-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 4 to Chapter B3

calculate the business value of a sample facility, on both a baseline - i.e., before imposition of compliance costs -
and post-compliance basis.  Using this, or a closely related, measure in the analysis of financial performance at
the time of the facility survey would therefore support a direct test of whether and how the survey financial data -
to  be subsequently used in the facility impact analysis - might reflect cyclically favorable conditions or differ
from the longer term trend of financial performance in an analysis. If either or both of these conditions were
found, the data would also readily support development of a necessary adjustment to offset these potential biases
in  the survey data.

EPA recognized that the after-tax, pre-interest cash flow measure used in the facility impact analysis would very
likely not be directly available from financial datasets that might be practically used in this analysis.  However,
reasonable surrogates for this measure that would likely be available include: after-tax cash flow from operations
(net income plus depreciation and amortization); earnings before interest, taxes, depreciation and amortization
(EBITDA); net income; and earnings before interest and taxes (EBIT).


B3A4-2.2 Selecting Appropriate Data

Other key requirements of the data to be used in the analysis include:

    *•   The financial data need to be a time series, preferably annual, over a sufficiently long period (and
        including the survey period) to allow testing of (1) whether survey period business conditions were
        cyclically favorable; and (2) whether financial performance in the industries exhibits a longer-term, non-
        neutral trend.

    *•   The data need to be at a sufficient level of industry resolution to account for variations in business
        conditions and performance not only across the five  manufacturing sectors but also within certain sectors,
        where there may be substantial variation in performance by important segments. Of particular importance
        is the ability to segment the chemicals sector into its segments such as basic chemicals and
        Pharmaceuticals,  and the primary metals sector into the ferrous and non-ferrous metals segments.

Based on these requirements, EPA selected the Value Line Investment Survey firm financial dataset as the data
source for this analysis. The Value Line dataset meets analysis requirements as follows:

    *•   The general company dataset of the Value Line Investment Survey (VL) reports summary financial
        information for nearly all publicly traded companies in the United States for a 12-year period, 1992-2003,
        which includes the 1996-1998 Phase III survey period.  The individual years in this  12-year period may
        be categorized  in three broad categories of economic performance: (1) six years of "normal"  economic
        performance - 1992-1996 and 2000; (2) three years of "subnormal" economic performance -  2001-2003;
        and (3) three years of years of "supra-normal" economic performance - 1997-1999.  The 12-year period
        thus captures reasonable diversity of business conditions before, after, and during the survey period. By
        including financial results for full-year 2003, the dataset also comes as close as possible to the present
        (2004) and thus would provide a basis for adjusting facility baseline financial data to essentially current
        conditions.

    *•   VL identifies and groups companies in a business content classification scheme that approximates 3-digit
        SIC or 4-digit NAICS classifications. These business classifications support identification of firms within
        the Phase III manufacturing industries at a level of sector detail sufficient for this analysis. Because (1)
        the dataset is by company instead of by aggregate groups and (2) the business classifications are defined
        by practical business content instead of in a rigid SIC or NAICS classification scheme, the VL dataset
                                                                                                   B3A4-5

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 4 to Chapter B3

        avoids the challenge confronted elsewhere in the Phase III analysis of the change in economic
        classification schemes and resulting inconsistency of aggregated data series over the year of the change1.

    *•   The VL dataset reports key accounting items that will readily support calculation of a financial metric,
        after-tax cash flow, that very nearly matches the principal financial metric (after-tax, pre-interest cash
        flow) underlying the Phase III facility impact analysis.

EPA recognizes that the VL dataset, by definition, excludes firms that are not publicly traded. The studied
industries include private, non-publicly traded firms, for which no comparable database of financial information is
available. As a result, use of the VL dataset in this analysis could yield findings that are not representative of the
overall industry, including the  non-publicly traded firms, to the extent that non-public firms in the studied
industries faced materially different business conditions or achieved materially different business performance
than publicly traded firms in the same industries. Overall, EPA expects that the business conditions faced by, and
performance achieved by, non-public firms in the studied industries are not likely to have been materially
different from those of the public firms. As a result, EPA judges that use of the VL dataset for this analysis is
appropriate and likely to yield  reasonably representative findings for to overall industries, including publicly
traded and non-traded firms.

In addition to the VL dataset, EPA considered a range of other data sources, including:

    *•   Economic and business performance data published by the Federal Reserve, in particular the Federal
        Reserve Economic Data (FRED IT) data series compiled by the Federal Reserve Bank of St.  Louis.

    *•   The Quarterly Financial Report for Manufacturing, Mining,  and Trade Corporations (QFR) published by
        the U.S.  Census Bureau.

    *•   Data series from the Bureau of Economic Analysis and data specifically available in The Survey of
        Current Business.

These data sources were each deficient for the analysis in some material way, including:

    *•   Data being too aggregate to provide the industry sector and sub-sector level of resolution needed to assess
        business conditions and trends within the Phase III manufacturing  sectors.

    *•   Data items being descriptive of general economic/financial conditions in an industry but not being
        sufficiently close to the financial performance concept needed for the analysis.

    *•   Data being reported in inconsistent economic classification frameworks over the desired analysis period.
        In addition to the problem of the SIC/NAICS break itself, data are sometimes reported at different levels
        of resolution before and after the SIC/NAICS break - e.g., at a 4-digit or finer level in the NAICS
        framework but only 2-digit level of resolution in the SIC framework.

    *•   Data not being readily available in an electronic format needed for efficient performance of the analysis.


B3A4-2.3 Selecting Industry Groups and Firms for Use in the Analysis

As discussed above, VL organizes firms by industry groups, which, in most instances, approximate 3-digit SIC or
4-digit NAICS classifications.  From review of the VL industry groups and the 316(b) Phase III  manufacturing
industries, EPA selected 10 VL industry groups and the firms within  these industry groups as candidates for this
    1 As described in the industry profiles, the change from SIC-based to NAICS-based reporting of economic data by federal
government and other data sources at around 1997/98 created difficulties in aligning and ensuring consistency of time series data that are
organized within these frameworks.

B3A4-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 4 to Chapter B3

analysis. Following review of the firms within these industry groups, EPA retained 6 firms for use in this
analysis. Key considerations in selecting the firms are as follows:

    *•   The selected VL industry groups are those that most closely correspond to the 316(b) Phase III
        manufacturing industries.

    *•   Within the industry groups, only those firms whose business operations reasonably match the profile of
        business activities of the 316(b) Phase III  manufacturing industries were considered candidates for the
        analysis. In some industry groups, a substantial number of firms included in the VL industry groups
        were excluded from the analysis:

        *•   VL includes Aluminum industry firms in its Metals and Mining industry group. However, most firms
           in this VL industry group are not involved in the Aluminum industry and thus were excluded from the
           analysis dataset.

        *•   EPA retained from the Paper and Forest Products group only those firms engaged in pulp mill, paper
           mill and/or paper and paperboard manufacturing operations. Firms engaged only in timber and
           lumber production were excluded from the analysis.

    *•   EPA retained only those firms that are based in the United States or Canada, and for which financial
        information is available in U.S. dollars.

    *•   After defining an initial set of firms according to these procedures and criteria, EPA retained only those
        firms for which a full 12 years of data were available.

    *•   Finally, EPA excluded firms that had undergone a significant restructuring - e.g., a merger or
        acquisition - which materially disrupted the continuity of financial reporting. Since the analysis to be
        performed would start from a time series of cash flow, measured in absolute dollars - as opposed, for
        example, to a time series of profit percentage values - including data from firms whose continuity of
        financial reporting had been affected by merger or acquisition activity would tend to bias the analysis.  In
        particular, firms engaging in mergers and  acquisitions that were accounted for on a purchase-accounting
        basis instead of a pooling-of-interests basis, would be likely to show sudden jumps in revenue, net
        income, and cash flow. These sudden jumps would bias the analysis by suggesting greater business
        growth than could be reasonably be achieved by the firm or facilities within the firm on a simple, organic
        growth basis.  Similarly, large contractions in business volume resulting from divestiture or termination of
        a line of business would bias the analysis  in the downward direction.  To apply this restriction, EPA
        examined the year-to-year revenue profiles for all firms over the 12-year analysis period.  EPA researched
        annual reports and other financial reporting for those firms showing large increases or decreases from
        year to year and excluded those firms where a material business event was found that would otherwise
        disrupt the continuity of financial reporting. EPA followed this rule with only two exceptions.  First, EPA
        kept firms in the analysis  when the only business event/disruption of financial reporting occurred in the
        last year of financial reporting - 2003.  EPA kept these firms in the analysis but excluded the final year of
        data from the analysis.  Second, in its research on one firm in the paper industry, EPA found that the firm
        had recorded an unusual, non-recurring stock gain transaction in 1995 that caused revenue and net
        income  to increase abnormally in that year.  Although the  VL net income item used in the analysis
        generally excluded income from unusual,  non-recurring events, the VL data series did not exclude income
       from this transaction.  Because EPA had already set aside a substantial number of firms from the paper
        industry, EPA decided to  keep this firm in the analysis but exclude the single year of unusual financial
       performance from the analysis dataset2. Applying this restriction substantially reduced the number of
    2 EPA considered removing the non-recurring item from the income statement but, because of uncertainty about the correct tax
adjustment, rejected this approach.
                                                                                                  B3A4-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 4 to Chapter B3
        firms that were included in the analysis dataset.  In particular, for the Aluminum industry, all of the firms
        in the initial VL dataset were found to have some significant discontinuity of financial reporting.3

EPA organized these 60 firms into six 316(b) Industry Groups for the analysis. Table B3A4.1, below, lists the
VL industry groups, the 316(b) Phase III manufacturing industries and/or industry segments (as discussed in the
industry profiles) to which the VL industry groups approximately correspond, the 316(b) Industry Groups for this
analysis, and the number of VL firms used in the analysis for each industry group.
                      Table B3A4.1: Value Line Industry Groups Selected for Analysis
Value Line Industry
Group
Metals and Mining
Paper and Forest
Products
Chemical (basic)
Chemical (diversified)
Chemical (specialty)
Biotechnology
Drug
Petroleum (integrated)
Steel (General)
Steel (Integrated)
316(b) Phase HI
Manufacturing
Industry
Aluminum
Pulp and Paper Mills
Chemicals Industry
Chemicals Industry
Chemicals Industry
Chemicals Industry
Chemicals Industry
Petroleum Refining
Steel
Steel
316(b) Industry Segment(s)
(as relevant)


Organic Chemicals
Inorganic Chemicals
Organic Chemicals
Inorganic Chemicals
Plastics Material and Resins
Pharmaceuticals
Pharmaceuticals



316(b) Phase HI
Industry Group for
Analysis
Aluminum
Pulp and Paper Mills
Industrial Chemicals

Plastics Material and
Resins
Pharmaceuticals

Petroleum Refining
Steel

Number of Firms
Used in Analysis
none
6
15

15
4

6
14

    Source:  Value Line Investment Survey and U.S. EPA analysis, 2004.
B3A4-2.4 Structuring the Analysis

The general objectives of this analysis were to:

     *•   Test, by 316(b) Industry Group, whether after-tax cash flow performance deviated, during the 316(b)
        survey data collection years, from normal performance over the 12-year analysis period.

     *•   Test, by 316(b) Industry Group, whether after-tax cash flow performance might be following a non-
        neutral trend over the 12-year analysis period.
    3 Because no Aluminum industry firms were able to be retained in the analysis, EPA was unable to develop an after-tax cash flow
adjustment factor for facilities in the Aluminum industry. EPA considered adjusting the pre-event financial statements for the Aluminum
industry firms - in effect, converting the purchase-accounting treatment of transactions to a pooling basis - but rejected this approach as
requiring too many judgments. However, EPA assessed the potential effect of applying a cash flow adjustment factor to facilities in this
industry by testing hypothetical factor values that substantially exceeded the adjustments - both for decrease and increase - estimated and
applied for the facilities in other industries. This analysis found that the facility impact analysis results for the Aluminum industry did not
change over this wide range of hypothesized cash flow adjustment factors.
B3A4-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

    *•  Given a finding that either or both of these conditions are true, to develop an adjustment to baseline after-
       tax cash flow to account for these effects, and, to yield after-tax cash flow values for the facility impact
       analysis that more closely reflect current financial performance in the 316(b) Phase III industries.

The overall approach to the  analysis was to analyze, for each industry group, the trend of financial performance
over the 12-year analysis period and to assess where the industry's financial performance lay relative to that trend
during the 316(b) survey data collection years of 1996-1998. For each industry group.  EPA used as analysis
observations, an index of constant dollar-adjusted after-tax cash flow for each of the firms in the industry group.
To analyze the trend, EPA calculated a simple regression of the index values against time. The estimated
regression relationship provided a direct measure of the real (i.e., inflation-adjusted) trend of financial
performance for each industry group.  The 1996-1998 average of index values for each industry group were then
compared with the trend values predicted from the estimated regression coefficients - both for the 1996-1998
years and for the end of the  analysis period - to determine the extent to which 1996-1998 survey values should be
adjusted to reflect (1) the deviation from trend at 1996-1998 and (2) the trend from 1996-1998 to the end of the
analysis period.

Specific steps in this analysis were as follows:

    *•  Calculate After-Tax Cash Flow (ATCF) as Net Profit plus Depreciation for each firm  by year.  As
       discussed above, EPA sought to analyze ATCF as a close approximation of the key financial metric -
       after-tax, pre-interest cash flow - used in the facility impact analysis. EPA calculated ATCF on a year-
       by-year basis for each firm in the analysis dataset as the sum of the VL data items: Net Profit and
       Depreciation.  In the VL data framework, Net Profit is defined as net income from continuing operations
       and excluding non-recurring items. Depreciation includes both non-cash items, depreciation and
       amortization.

    *•  Adjust ATCF to constant dollar values at mid-year 2003. using the GDP deflator. To  eliminate the effects
       of inflation in analyzing the trend of financial performance,  EPA deflated the ATCF values for all firms to
       mid-year 2003 using the GDP Deflator series published by the Department of Commerce, Bureau of
       Economic Analysis.

    *•  Calculate an index of each company's ATCF values by year using, as an index numerator, the average
       ATCF value for the company over the 12-year period.  As summarized above, the overall approach of the
       analysis involved a  regression analysis of the trend of ATCF values for the firms in an industry group
       over the 12-year analysis period.  To allow individual firms' ATCF values to be combined in a single
       regression requires eliminating the scale effect of the different sizes of firms. For this reason, the
       inflation-adjusted ATCF values for each firm were normalized to an index series by dividing the yearly
       values by the average of values for each firm over the 12-year period. EPA used the 12-year average of
       values for this index calculation instead of the value for a single year to prevent anomalously large swings
       in the index series when the ATCF value for the year selected as the base year for the  index calculation
       was very small relative to other values in the 12-year series. In addition, in calculating the index values
       for the 12-year series, EPA first removed any negative values from the series for each firm by adding to
       each value in the firm's 12-year series, the absolute value of the most negative value for the firm plus the
       absolute value of the smallest non-negative value in the series.  This adjustment has the effect of
       "vertically" shifting the ATCF values for a firm so that all values are positive while retaining the
       mathematical "shape" of the series for the trend analysis.  This adjustment was necessary to prevent the
       undesirable  inversion of the index trend that would occur if a negative index numerator is combined with
       a positive series values in calculating the index series.

    *•  Regress ATCF index values against year by industry group to calculate the time trend of constant dollar
       ATCF over the period 1992-2003. The preceding calculations yield a constant dollar  series of ATCF
       indexed to one and with an average value of one  over the 12-year analysis period. To calculate the trend
       indicated by these index ATCF values, EPA estimated a weighted linear regression of the index ATCF
       values against year by industry group. These regressions were performed on a revenue-weighted basis -


                                                                                                 B3A4-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

       i.e., each ATCF value was weighted by the firm's revenue value for the year - so that each firm's
       individual ATCF trend carries a weight in proportion to its revenue in estimating the trend relationship.
       As a result, the estimated trend relationship reflects a revenue-weighted average of the ATCF trends of
       the individual firms, instead of an arithmetic average, which would overweight the presence of smaller
       firms in estimating the trend relationship.  The estimated ATCF index coefficient from the regression for
       each industry indicates the trend in constant dollar ATCF over the analysis period: a negative coefficient
       indicates declining constant dollar ATCF over the analysis period; a positive coefficient indicates
       growing constant dollar ATCF over the analysis period.4

    *•  Calculate the predicted trend of ATCF index values for each industry group. Used together, the estimated
       ATCF index coefficient and regression intercept yield a predicted trend line of ATCF index values for the
       12-year period , for each industry group analyzed. The actual ATCF index values for an industry group
       can then be compared with predicted trend line to assess whether the ATCF values during the 1996-1998
       survey data collection period deviate from the trend. The predicted trend line also indicates where the
       ATCF index values would be at the end of the  analysis period if the ATCF index values followed the
       predicted trend.

    *•  Calculate the revenue-weighted average of actual ATCF index values by industry group for the 1996-
       1998 period. The revenue-weighted average of actual ATCF values for the 1996-1998 period is
       compared with the predicted trend values to assess the extent to which the actual ATCF index values
       deviate from trend and to provide a basis for estimating the adjustment needed to bring the ATCF values
       to the trend, or to the predicted trend value at the end of the analysis period. These values were calculated
       by, first, averaging the  1996, 1997, and 1998 ATCF index values for each firm, and, second, averaging
       these firm-average values over the firms in an industry group using, as weights, the 1996-1998 average
       revenue of each firm in the industry group.

B3A4-3  SUMMARY OF FINDINGS

Table B3A4.2, below, summarizes key results from the analyses outlined above. Items reported in the table are as
follows:

    »•  Estimated Trend: the revenue-weighted average of annual change in ATCF Index values for firms in the
       industry group over the analysis period, 1992-2003.  This value is the estimated coefficient of ATCF
       Index against time from the simple linear regression, as described above. Because the trend is estimated
       from an index series with an average value of one over the analysis period, the estimated trend may also
       be interpreted as equal approximately to the annual percent change in ATCF Index. A negative estimated
       trend value indicates that ATCF Index values decline, on average, over the analysis period; a positive
       estimated trend value indicates that ATCF Index values increase, on average, over the analysis period.

    *•  Average of ATCF Index Values at 1996-1998: the revenue-weighted average of actual ATCF Index
       values for firms in the industry analysis set over the 1996-1998 period. The values in this column are
       compared with values in the next two  columns, respectively, to assess (1) the extent to which financial
       performance during the 1996-1998 survey data period deviated from the analysis period trend at 1996-
       1998 and  (2) the overall change in financial performance from the 1996-1998 survey data period to the
       end of the analysis period resulting from the combination of deviation from analysis period trend and the
       trend, itself (see following paragraphs for further discussion).

    *•  Average of Predicted Trend Values at 1996-1998: the average of predicted ATCF Index values over the
       1996-1998 survey data period as predicted from the estimated regression terms. If ATCF performance
       for an individual firm or industry matched the industry trend over time, the actual ATCF Index values at
    4 In addition to testing a simple linear model of index ATCF against time, EPA also used a logarithm-adjusted series of the ATCF
values to test for an exponential trend in ATCF. The log model provided no improvement in the estimated regression relationships.  As a
result, EPA used the coefficients estimated from the linear model for its analysis of the ATCF trend.

B3A4-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 4 to Chapter B3
        1996-1998 would equal this value.  Material deviation of the actual ATCF Index values from this value
        suggests, for an industry, that ATCF performance during the 1996-1998 survey data period was: (1)
        abnormally favorable, if the actual ATCF Index values exceed the average of predicted values, or (2)
        abnormally unfavorable, if the actual ATCF Index values are less than the average of predicted values.

        Predicted Trend Value at 2003: the  ATCF Index value at the end of the analysis period as predicted from
        the estimated regression terms.  This value is the (statistically) expected value of ATCF Index at 2003 for
        a firm or for the industry, based on the estimated trend relationship. Material deviation of this value from
        the Average of Predicted Trend Values at 1996-1998 indicates a general trend going forward from the
        1996-1998 survey data period, which, apart from cyclical deviation, which would  further affect ATCF
        performance for firms in the industry group. For an industry, if this value is less than the Average of
        Predicted Trend Values at 1996-1998, then financial performance, as indicated by ATCF Index, generally
        deteriorated from 1996-1998 forward to 2003, the end of the analysis period. In addition to the cyclical
        deviation effect, this "trend" effect might also be taken into account in adjusting ATCF data calculated
        from the 316(b) survey responses. In this case,  comparison of the average of actual ATCF Index values
        over the 1996-1998 survey data period with the Predicted Trend Value at 2003, would  indicate the total
        potential adjustment, accounting for both the cyclical deviation and trend effects.
     Table B3A4.2: Key Results from Analysis of After-Tax Cash Flow Trends by 316(b) Industry for
                                               1992-2003
316(b) Phase HI Industry
Group
Aluminum
Pulp and Paper Mills
Industrial Chemicals
Plastics Material and Resins
Pharmaceuticals
Petroleum Refining
Steel
Estimated
Trend

-0.00040
0.00120
0.03180
0.05070
0.02300
-0.00420
Average of ATCF Average of Predicted
Index Values at 1996- Trend Values at 1996- Predicted Trend
1998 1998 Value at 2003
Analysis not undertaken
0.98953
1.10059
1.03865
0.98775
0.92346
1.25879
for the Aluminum industry
1.03058
1.00837
0.99332
0.99703
1.01441
1.03948

1.02880
1.01567
1.18383
1.30096
1.15248
1.01414
Source: U.S. EPA analysis, 2004.
The following page presents charts, by industry group, of the yearly ATCF Index Values and the estimated
predicted trend values over the analysis period.
                                                                                                B3A4-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 4 to Chapter B3
                                           Figure B3A4-4: ATCF Index vs Trend
                         Iron and Steel

                          Year
                                                                                            Industrial Chemicals
                                                                           0.60


                                                                           0.40


                                                                           0.20


                                                                           0.00
              -Time
                Trend
              -1ndex
                ATCF
                           Petroleum Refining
                                                                                            Pharmaceuticals
                                                                         1.60

                                                                         1.40

                                                                         1.20

                                                                       £ 1.00
                                                                       T3

                                                                       if 0.80

                                                                       < 0.60

                                                                         0.40

                                                                         0.20

                                                                         0.00
              -•-Time
                 Trend
              -•-Index
                 ATCF
                      Plastic Material and Resins
                                                                                           Pulp & Paper Mills




1
E
°r














/\ A-A
. . / . \ / \
//*-"*' "^ ^^^




^CtPc^Ct) Ct) Ct) Ct) Ct) C§)O~O/5'
Q) Ct)Ct)Ct)Ct)Ct) Ct)Ct)QCiQCi
B3A4-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

By industry, these results indicate the following:

    *•  Pulp and Paper Mills. The analysis indicates a very slight annual decline, approximately -0.04 percent, in
       constant dollar ATCF over the analysis period, meaning financial performance declined very modestly
       over this period. The analysis also indicates that the survey data collection years of 1996-1998 showed
       weaker performance than the predicted trend performance in those years.  Specifically, the average actual
       ATCF index value at 1996-98 is 4.0 percent below the predicted ACTF trend value for those years. With
       negative growth in ATCF over the analysis period, the predicted ATCF index value at the end of the
       analysis period, 2003, declines slightly from the 1996-1998 period.  As a result, the average actual ATCF
       index value at 1996-98 is approximately 3.8 percent below the predicted ACTF trend value in 2003.

    *•  Industrial Chemicals. The analysis for the Industrial Chemicals segment of the Chemicals industry
       indicates a very slight annual increase, approximately 0.12 percent, in constant dollar ATCF over the
       analysis period, meaning financial performance improved slightly over this period.  In contrast to the
       finding for the Paper and Allied Products industry, the analysis indicates that the Industry Chemicals
       segment achieved higher financial performance during the survey data collection years of 1996-1998 than
       the predicted trend performance in those years. Specifically, the average actual ATCF  index value at
       1996-98 is 9.1 percent above the predicted ACTF trend value for those years.  With slight positive growth
       in ATCF over the analysis period, the predicted ATCF index value at the end of the analysis period,  2003,
       increase slightly from the 1996-1998 period. As a result, the average actual ATCF index value at 1996-
       98 is approximately 8.4 percent above the predicted ACTF trend value in 2003.

    *•  Plastics Material and Resins. This segment of the  Chemicals industry shows a moderate increase, 3.2
       percent annually, in constant dollar ATCF over the analysis period.  From this analysis, the Plastic
       Material and Resins segment, like the Industrial Chemicals segment, also achieved higher financial
       performance during the survey data collection years of 1996-1998 than the predicted trend performance in
       those years. Specifically, the average actual ATCF index value at 1996-98 is 4.6 percent above the
       predicted ACTF trend value for those years. However, with relatively strong positive growth in ATCF,
       the predicted ATCF index value at the end of the analysis period, 2003, increases sufficiently to reverse
       this relationship. As a result, by 2003, the average actual ATCF index value at 1996-98 is 12.3 percent
       below the predicted ACTF trend value in 2003.

    *•  Pharmaceuticals. This third segment of the Chemicals industry also shows a strong increase, 5.1 percent
       annually, in constant dollar ATCF over the analysis period. Financial performance during the survey data
       collection years very nearly equaled the predicted ATCF index value: the average ATCF index value at
       1996-98 is 0.9 percent below the predicted ACTF trend value for those years.  With strong growth in
       ATCF over the analysis period, by 2003, the predicted ATCF value is substantially higher than the
       average ATCF index value at 1996-98: the average ATCF index value at 1996-1998 is 24.1 percent below
       the predicted trend value at 2003.

    *•  Petroleum Refining.  The analysis indicates a moderate increase, 2.3 percent annually, in constant dollar
       ATCF over the analysis period. The analysis also  indicates that the Petroleum Refining industry
       achieved, on average, weaker financial performance during the survey data collection years than the
       predicted trend performance in those years: the average ATCF index value for 1996-1998 is 9.0 percent
       below the predicted trend value during those years. However, the individual yearly values during 1996-
       1998 show considerable volatility relative to the trend, suggesting weak confidence in this finding. Like
       Pharmaceuticals, with relatively strong growth in ATCF over the analysis period, by 2003, the predicted
       ATCF value is substantially higher than the average ATCF index value at 1996-98: the average ATCF
       index value at 1996-1998 is 19.9 percent below the predicted trend value at 2003.

    *•  Steel.  The analysis indicates declining performance, approximately -0.4 percent annually, in constant
       dollar ATCF over the analysis period. The analysis also indicates that financial performance during  the
       survey data collection years substantially exceeded, by 21.1 percent, trend-based predicted performance
       during those years. With declining trend-based performance through the end of the analysis period, by


                                                                                                B3A4-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

       2003, the gap between the average ATCF value at 1996-1998 and the predicted trend value at 2003
       widens to 24.1 percent.

Table B3A4.3, below, summarizes these findings.
        Table B3A4.3: Estimated Relationship Between Actual ATCF at Survey Period and Trend
                     Predicted Values at Survey Period and End of Analysis Period
316(b) Phase III
Industry Group
Aluminum
Pulp and Paper Mills
Industrial Chemicals
Plastics Material and
Resins
Pharmaceuticals
Petroleum Refining
Steel
Percentage Difference in Actual and
Predicted ATCF Index Values at 1996-
1998
Analysis not undertaken
-4.0%
9.1%
4.6%
-0.9%
-9.0%
21.1%
Percentage Difference in Actual
Index Values at 1996-1998 and
Predicted Value at 2003
for the Aluminum industry
-3.8%
8.4%
-12.3%
-24.1%
-19.9%
24.1%
ATCF
Trend







        Source:  U.S. EPA analysis, 2004.
From these results, the industries and/or segments where financial performance during the 1996-1998 survey data
collection period exceeds trend-predicted performance and thus for which survey data may overstate the
industry's ability to withstand compliance burdens in comparison to the predicted trend values at 1996-1998 are:

    *•  Pulp and Paper Mills industry,
    *•  Industrial Chemicals segment of the Chemicals industry,
    *•  Plastics Material and Resins segment of the Chemicals industry , and
    *•  Steel industry.

Looking to the end of the analysis period, 2003, the industries and/or segments where financial performance
during the 1996-1998 survey data collection period exceeds trend-predicted performance at 2003, and thus for
which survey data may overstate the industry's ability to withstand compliance burdens at a time closer to the
point of regulatory implementation are:

    *•  Industrial Chemicals segment of the Chemicals industry, and
    *•  Steel industry.
B3A4-4  DEVELOPING AN ADJUSTMENT CONCEPT

On the basis of these findings, EPA considered whether and how to adjust after-tax cash flow, as derived from the
facility survey responses for use in the facility impact analysis. Given that several of the industries, or segments
within industries, were found to have financial performance during the survey data collection period that
exceeded the predicted trend financial performance for that period or that exceeded the predicted trend financial
performance at the end of the analysis period, EPA concluded that development and application of an adjustment
to baseline after-tax cash flow was warranted.
B3A4-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

In deciding how to adjust cash flow, EPA considered three primary adjustment concepts:

1.  Adjust baseline cash flow to account for deviation from predicted trend at the time of the survey data
    collection.

2.  Adjust baseline cash flow to account for deviation from predicted trend at the end of the analysis period.

3.  Adjust baseline cash flow to a future estimated period of compliance based on the estimated trend of change
    in constant dollar after-tax cash flow over time.

EPA decided to apply the ATCF adjustment according to the second of these three adjustment concepts: Adjust
baseline cash flow to account for deviation from predicted trend at the end of the analysis period. This adjustment
concept addresses both concerns that (1) business performance during the survey data collection period diverged
from the predicted trend performance during the survey data collection period, and (2) business performance from
the time of survey data collection period followed a non-neutral trend to the present.  EPA considered extending
the trend projection to the estimated time of compliance (concept 3) but rejected this approach since it was
deemed speculative in attempting to forecast business performance  into the future. In addition, the greater the
number of years over which ATCF results are projected based on historical trend, the less likely that the predicted
changes in ATCF reflect the performance of a static set of facilities and instead reflect capital additions, new
facilities, facility closures, etc.  For these reasons, EPA decided to restrict the adjustment to the end of the ATCF
analysis period.

EPA also considered whether to apply the indicated adjustment factors asymmetrically - i.e., only to reduce the
ATCF values as calculated from facility survey responses - or symmetrically - i.e., both to increase or to reduce
the ATCF values as calculated from facility survey responses.  In the case of asymmetric adjustment, the
adjustment would correct for business performance during the survey data collection period that exceeded the
predicted trend value - whether for the survey period or some future period - and would thus attempt to avoid
overstating the a facility's ability to bear the costs of regulation compliance without material  financial impact. In
the case of a symmetric adjustment, the adjustment would additionally address the potential that business
performance during the survey data collection period fell short of the predicted trend value and would thus
attempt to avoid understating the ability of an industry or facility to bear the costs of regulatory compliance
without material financial impact.

On this question, EPA decided to apply the ATCF adjustment on a symmetric basis, potentially reducing or
increasing facility cash flow on the basis of the  estimated adjustment factor.  EPA based its decision on the
principle of avoiding both overstatement and understatement of the ability of facilities in an industry to bear the
costs of regulatory compliance without material financial impact.

Based on these decisions, EPA calculated the adjustment factors by dividing the Predicted Trend Value at 2003
by the Average of ATCF Index Values at 1996-1998, as reported in Table B3A4-2, above. In the facility closure
analysis, as described in Chapter B3: Economic Impact Analysis for Manufacturers, facility after-tax cash flow is
simply multiplied by the appropriate adjustment factor based on the industry or industry segment to which a
facility is assigned. The resulting adjusted ATCF is carried forward in the baseline and post-compliance closure
analyses. Where the  Predicted Trend Value at 2003 is less than Average of ATCF Index Values at 1996-1998, the
resulting adjustment factor value is less than one and the effect of the ATCF adjustment is to  reduce the calculated
value of cash flow used in the facility impact analysis. Where the Predicted Trend Value at 2003 is greater than
Average of ATCF Index Values at 1996-1998, the resulting adjustment factor value is greater than one and the
effect of the ATCF adjustment is to increase the calculated value of cash flow used in the facility impact analysis.

EPA also used the adjustment factors to adjust the numerator values of the measures used in the facility moderate
impact analysis: pre-tax return on assets and interest coverage ratio. In both cases, the numerators of the measures
are closely related to cash flow, but are calculated on a pre-tax basis.  As a result, in this case, the ATCF-based
adjustment factor does  not match as closely in concept the financial measures to which it is applied as is the case
for the ATCF measure  used in the facility closure analysis.  Nevertheless, use of the adjustment for these


                                                                                                 B3A4-15

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 4 to Chapter B3
measures is appropriate because the pre-tax measures used in the facility moderate impact analysis will still move
closely with the after-tax cash flow measure on which the adjustment factor is based. In addition, it is important
that EPA recognize the potential effect of change in financial condition since the survey data collection period in
the facility moderate impact analysis as well as in the facility closure analysis.

Table B3A4.4, below, summarizes the adjustment factors implemented for each of the industries, and within the
chemical industry, for the industry segments. The table also reports the number of baseline and post-compliance
closures  (under the proposed regulatory option) estimated with and without application  of the ATCF adjustment
factor.
     Table B3A4.4: Using After-Tax Cash Flow Adjustment Factors in the Facility Closure Analysis

Aluminum
Pulp and Paper Mills
Chemicals Industry
Industrial Chemicals
Plastics Material and
Resins
Pharmaceuticals
Petroleum Refining
Steel
Total
Adjustment
Factor
1.0000
1.0397

0.9228
1.1398
1.3171
1.2480
0.8056

Number of
Facilities
Analyzed
21
230

138
34
6
36
68
532
Summary Results from Closure Analysis
Using
Adjustment Factors
Baseline Regulatory
Closures Closures
7
32

4
0
0
5
29
76
0
0

0
0
0
0
0
0
Not Using Factors
Baseline Regulatory
Closures Closures
7 0
32 0

4 0
0 0
0 0
5 1
25 0
73 1
    Adjustment factor not developed for Aluminum industry, so the results with use of adjustment factors are necessarily the same
    as those without use of the factors.

    All results are sample weighted.  The reported totals may differ from the apparent sums of individual data items due to
    rounding.

    Source:  U.S. EPA analysis, 2004.
As reported in Table B3A4.4, the adjustment factors for the Steel industry and Industrial Chemicals segment of
the Chemicals industry are less than one, at 0.8056 and 0.9228, respectively. For these industries, the effect of the
adjustment factor is to reduce the cash flow values calculated from facility survey responses. As described above,
EPA did not calculate an adjustment factor for the Aluminum industry due to data limitations; accordingly, this
industry's "adjustment factor" is simply 1.0000.  The adjustment factors for the remaining industries are greater
than one, ranging from a value of 1.0397 for the Pulp and Paper Mills industry to 1.3198 for the Pharmaceuticals
segment of the Chemicals industry.  For these industries, the effect of the adjustment factor is to increase the cash
flow values calculated from facility survey responses.

In terms of effect on analytic results, the use of the ATCF adjustment factors caused the number of baseline
closures to change in only one 316(b) industry group, the Steel industry.  For this industry, the reduction in cash
flow resulting from the adjustment causes an additional 4 facilities, on a sample weighted basis, to fail the
baseline closure analysis.
B3A4-16

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3

Under the 50 MGD All Option for existing manufacturing facilities, the use of the ATCF adjustment factors
eliminated one regulatory closure, in the Petroleum Refining industry. Because the calculated adjustment factor
for this industry is quite large, 1.248, EPA reviewed closely the effect of the adjustment factor on the facility
closure calculation. In particular, EPA was concerned that the regulatory closure was being eliminated by
application of a large ATCF adjustment. From this review, EPA determined that the single Petroleum  Refining
industry closure, without the ATCF adjustment, is a very marginal closure. Specifically, an ATCF adjustment
factor of 1.0195 (compared to the calculated 1.248) provides a sufficient increase in baseline cash flow to
eliminate the closure under the compliance requirements of the 50 MGD All Option. Another way of
understanding the 1.0195 adjustment factor is to calculate the annual trend factor (year-to-year change in
predicted trend ATCF Index) that would yield the 1.0195 value. In this case, the year-to-year change required to
generate the 1.0195 value is 0.0038, or an annual change factor that is very close to zero (approximately 0.38
percent annual average change). Given these findings, EPA concludes that the extent of improvement  in cash
flow needed to eliminate the regulatory closure in the Petroleum Refining industry is extremely small and is thus
quite plausible within the overall improving business performance trend exhibited by the Petroleum Refining
industry. Under the other two co-proposed options, the 200 MGD All Option and the 100 MGD SWB Option, the
use of the ATCF adjustment factors would have no closure effect.
                                                                                                 B3A4-17

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 4 to Chapter B3


REFERENCES

Board of Governors of the Federal Reserve System. Release G.I 7, Industrial Production and Capacity
Utilization: Capacity Utilization: Manufacturing (NAICS) and Industrial Production Index quarterly data series.
2004.

U.S. Department of Commerce. Bureau of Economic Analysis. Table 1.1.6. Real Gross Domestic Product,
Chained Dollars.  2004.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Information Collection Request for Cooling Water
Intake Structures, Phase IIExisting Facility Final Rule.  ICR Number 2060.02.  February 2004.

Value Line Investment Survey.  Value Line  Publishing, Inc. 220 East 42nd Street, New York, N.Y.  10017-589.
2003 and 2004.
B3A4-18

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                                                                           Appendix 5 to Chapter B3
                  Appendix 5  to Chapter B3:
       Estimating Capital  Outlays  for Section
      316(b)  Phase III  Manufacturing Sectors
              Discounted  Cash  Flow  Analyses
                                               APPENDIX CONTENTS
                                               B3 A5-1 Analytic Concepts Underlying Analysis of Capital
                                                      Outlays	B3A5-2
                                               B3A5-2 Specifying Variables for the Analysis . . . B3A5-4
                                               B3 A5-3 Selecting the Regression Analysis Dataset B3 A5-7
                                               B3A5-4 Specification of Models to be Tested	B3A5-9
                                               B3A5-5 Model Validation	B3A5-12
                                               Attachment B3 A5. A:  Bibliography of Literature
                                                                Reviewed for this
                                                                Analysis 	B3A5-17
                                               Attachment B3A5.B:  Historical Variables Contained in
                                                                the Value Line Investment Survey
                                                                Dataset 	B3A5-18
INTRODUCTION

The analysis of economic impacts to Phase III
manufacturing facilities associated with the proposed
Section 316(b) Regulation involves calculation of the
business value of sample facilities on the basis of a
discounted cash flow (DCF) analysis of operating
cash flow as reported in the detailed industry
questionnaires.1 Business value is calculated on a
pre- and post-compliance basis and the change in this
value serves as an important factor in estimating
regulatory impacts in terms of potential facility
closures. To be accurate in concept, the business
value calculation should recognize cash outlays for
capital acquisition as a component of cash flow. However, the Section 316(b) Detailed Industry Questionnaire
did not request information from surveyed facilities on their cash outlays for capital acquisition. Absent this data,
EPA developed an estimate of cash outlays for capital acquisition.  This appendix describes the methodology EPA
used to derive, for each sample facility, an estimate of cash outlays for capital acquisition.

EPA Office of Water (OW) previously identified that the omission of cash outlays for capital acquisition from
DCF analyses may lead to overstatement of the business value of sample facilities and, as a consequence,
understatement of regulatory impacts in terms of estimated facility closures (EPA, 2003). In response to this
omission, the Office of Management and Budget suggested the adoption of depreciation expense as a surrogate
for cash outlays for capital replacement and additions. However, for several reasons EPA believes depreciation is
a poor surrogate. First, depreciation is meant to capture the consumption/use of previously acquired assets, not
the cost of replacing, or adding to, the existing capital base. Therefore, depreciation is fundamentally the wrong
concept to use as a surrogate for capital outlays for capital replacement and additions.  Second, depreciation is
estimated based on the historical asset cost, which may understate or overstate the real replacement cost of assets.
Third, both book and tax depreciation schedules generally understate the assets' useful life.  Thus, reported
depreciation will overstate real depreciation value for recently acquired assets that are still in the depreciable asset
base, and conversely, understate the real depreciation value of assets that have expired from the depreciable asset
base but still remain in valuable use.  Finally, depreciation does not capture the important variations in capital
outlays that result from differences in revenue growth and financial performance among firms.  Businesses with
real growth in revenue will need to expand both their fixed and working capital assets to support business growth,
and all else being equal, growing businesses will have higher ongoing outlays for fixed and working capital
assets. Similarly, the ability of businesses to renew and expand their asset base depends on the financial
productivity of the deployed capital as indicated by measures  such as return on assets or return on invested
capital. As a result, businesses with "strong" asset productivity will attract capital for renewal and expansion of
their asset base, while businesses with "weak" asset productivity will have difficulty attracting the capital for
renewal and expansion of the business' asset base. All else being equal, businesses with strong asset productivity
     This analysis is limited to potentially affected facilities in primary SIC codes 26, 28, 29, and 33.
                                                                                       B3A5-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                  Appendix 5 to Chapter B3

will have higher ongoing outlays for capital assets; businesses with weak asset productivity will have lower
ongoing outlays for capital assets.

As an approach to addressing the absence of capital acquisition cash outlay data to support the Phase III DCF
analysis, EPA estimated a regression model of capital outlays using reported capital expenditures and relevant
explanatory financial and business environment information for public-reporting firms in the Phase III
manufacturing sectors.  The resulting estimated model is used to estimate capital outlays for facilities in the Phase
III sample dataset. The estimated capital outlay values were then used in the DCF analyses to calculate business
value of sample facilities and estimate regulatory impacts in terms of facility closures.

The approach and regression model described above are based largely on the approach and regression model
developed in support of the analysis of economic impacts for the Metal Products and Machinery Regulation
(MP&M), which provides a recent example of the need to address the omission of capital acquisition cash outlay
data from a DCF analysis.  EPA notes that the facilities/industry sectors examined in the Section 316(b) Phase III
analysis are similar to those analyzed in the MP&M analysis: both analyses estimate impacts to  facilities in
manufacturing industries only and facilities in SIC 33 are covered under both regulations. In addition, the Section
316(b) Detailed Industry Questionnaire and the MP&M survey  instruments are similar; therefore, similar data are
available for Phase III and MP&M survey facilities.  As such, EPA relied heavily on prior experience from the
MP&M final regulation in estimating the regression model used to estimate of capital outlays for facilities in the
Phase III sample dataset.

This appendix reports the results of the effort to estimate capital outlays for Phase III manufacturing facilities,
including: an overview of the analytic concepts underlying the analysis of capital outlays; specific variables
included in the regression analysis; summary of data selection and preparation; general specification of regression
models  to be tested; and the findings from the regression analyses.2


B3A5-1 ANALYTIC CONCEPTS UNDERLYING ANALYSIS OF  CAPITAL OUTLAYS

On the basis  of general economic and financial  concepts of investment behavior, EPA began its  analysis by
outlining a framework relating the level of a firm's capital outlays to explanatory factors that:

        *•  can be observed for public-reporting firms - either  as firm-specific information or general business
           environment information - and thus be included in  a regression analysis; and

        *•  for firm-specific information, are also available from the Phase III sample facility dataset.

To aid in identifying the explanatory concepts and variables that might be used in the analysis and as well in
specifying the models for analysis, EPA reviewed recent studies of the determinants of capital outlays.  EPA's
review of this literature generally confirmed the overall approach in seeking to estimate capital outlays and helped
to identify additional specific variables that other analysts found to contribute important information in the
analysis of capital outlays (e.g., the decision to test capacity utilization as an explanatory variable, see below,
resulted from the literature review). Articles reviewed are listed in Attachment B3A5A to this appendiB3A5

Table B3A5.1, beginning below and continuing on the subsequent page, summarizes the conceptual relationships
between a firm's capital outlays and explanatory factors that EPA sought to capture in this analysis. In the table,
EPA outlines the concept of influence on capital outlays, the general explanatory variable(s) that EPA identified
    2  Since the estimated regression model for the Phase III facilities is based on an earlier model developed for the MP&M final
regulation, much of the underlying research involved in the analytic development of the model had been previously completed and was not
required to be redone. Nonetheless, in order to present a lucid discussion of the analytic concepts underlying the model and the rationale
behind specifying variables for the analysis and specification of the regression model, a complete discussion of how the regression model
was developed is presented. During the course of the discussion, instances where prior experience gained during estimating the regression
model for the MP&M final regulation had a significant influence in the development of the current model are clearly highlighted.

B3A5-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                                                        Appendix 5 to Chapter B3
to capture the concept in a regression analysis, and the hypothesized mathematical relationship (sign of estimated
coefficients) between the concept and capital outlays. Table B3A52 identifies the specific variables included in
the analysis, including any needed manipulations and the correspondence of the variables to Phase III survey
information.
                         Table B3A5.1: Summary of Factors Influencing Capital Outlays
     Explanatory Factor/Concept To Be
            Captured in Analysis
       Translation of Concept to Explanatory Variable(s)
  Expected
 Relationship
 Availability of attractive opportunities for
 additional capital investment. A firm's
 owners, or management acting on behalf of
 owners, should expend cash for capital
 outlays only to the extent that the expected
 return on the capital outlays - whether for
 replacement of, or additions to, existing
 capital stock - are sufficient to compensate
 providers of capital for the expected return
 on alternative, competing investment
 opportunities,  taking into account the risk of
 investment opportunities.
Historical Return On Assets of establishment as a indicator of
investment opportunities and management effectiveness, and, hence,
of desirability to expand capital stock and ability to attract capital
investment. Use of a historical variable implicitly assumes past
performance is indicative of future expectations.
Positive
 Business growth and outlook as a
 determinant of need for capital expansion
 and attractiveness of investment
 opportunities. All else equal, a firm is more
 likely to have attractive investment
 opportunities and need to expand its capital
 base if the business is growing and the
 outlook for business performance is
 favorable.
Revenue Growth, from the prior time period(s) to the present,         Positive
provides a historical measure of business growth and is a potential
indicator of need for capital expansion. Use of a historical variable
implicitly assumes past performance is indicative of future
expectations.
Clearly, the theoretical preference is for a forward-looking indicator
of business growth and need for capital expansion. Options EPA
identified include Index of Leading Indicators and current Capacity
Utilization, by industry. Higher current Capacity Utilization may
presage need for capital expansion.
Positive
 Importance of capital in business
 production. All else equal, the more capital
 intensive the production activities of a
 business, the greater will be the need for
 capital outlay to replenish, and add to, the
 existing capital stock. More capital
 intensive businesses will spend more in
 capital outlays to sustain a given level of
 revenue over time.
The Capital Intensity of production as measured by the production
capital required to produce a dollar of revenue provides an indicator
of the level of capital outlay needed to sustain and grow production.

As an alternative to a firm-specific concept such as Capital Intensity
of production, differences in business characteristics might be
captured by an Industry Classification variable.
Positive
 Life of capital equipment in the business.
 All else equal, the shorter the useful life of
 the capital equipment in a business, the
 greater will be the need for capital outlay to
 replenish, and add to, the existing capital
 stock.
No information is available on the actual useful life of capital
equipment by business or industry classification. However, the
Capital Turnover Rate, as calculated by the ratio of book
depreciation to net capital assets, provides an indicator of the rate at
which capital is depleted, according to book accounting principles:
the higher the turnover rate, the shorter the life of the capital
equipment. However, the measure is imperfect for reasons of both
the inaccuracies of book reporting as a measure of useful life, and as
well the confounding effects of growth in the asset base due to
business expansion - which will tend to lower the indicated turnover
rate, all else equal, without a real reduction in life of capital equipment.

As above, an alternative to a firm-specific concept, differences in
business characteristics might be captured by an Industry
Classification variable.
Positive,
generally, but
with
recognition of
the potential
for counter-
trend effects
                                                                                                                     B3A5-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                                                    Appendix 5 to Chapter B3
                        Table B3A5.1: Summary of Factors Influencing Capital Outlays
     Explanatory Factor/Concept To Be
           Captured in Analysis
      Translation of Concept to Explanatory Variable(s)
  Expected
 Relationship
  The cost of financial capital. The cost at
  which capital - both debt and equity - is
  made available to a firm will determine
  which investment opportunities can be
  expected to generate sufficient return to
  warrant use of the financial capital for
  equipment purchases. All else equal, the
  higher the cost of financial capital, the fewer
  the investment/capital outlay opportunities
  that would be expected to be profitable and
  the lower the level of outlays for
  replacement of, or additions to, capital stock.
Preferably, measures of cost-of-capital would be developed           Negative
separately for debt and equity.

The Cost of Debt Capital, as measured by an appropriate benchmark
interest rate, provides an indication of the terms of debt availability
and how those terms are changing over time. Preferably, the debt
cost/terms would reflect the credit condition of the firm, which
could be based on a credit safety rating (e.g., S&P Debt Rating).
The cost of equity capital is more problematic than the cost of debt
capital since it is not directly observable for either public-reporting
firms or, in particular, private firms in the Phase III dataset.
However, a readily available surrogate such as Market-to-Book
Ratio provides insight into the terms at which capital markets are
providing equity capital to public-reporting firms: the higher the
Market-to-Book Ratio, the more favorable the terms of equity
availability.
Negative
  The price of capital equipment. The price
  of capital equipment - in particular, how
  capital equipment prices are changing over
  time - will influence the expected return
  from capital outlays. All else equal, when
  capital equipment prices are increasing, the
  expected return from incremental capital
  outlays will decline and vice versa.
  However, although the generally expected
  effect of higher capital equipment prices is
  to remove certain investment opportunities
  from consideration, the potential effect on
  total capital outlay may be mixed. If
  expected returns are such that the demand to
  invest in capital projects is relatively
  inelastic, the effect of higher prices  for
  capital equipment may be to raise, instead of
  lower, the total capital outlay for a firm.
Index provides an indicator of the change in capital equipment
prices.
Negative,
generally, but
with
recognition of
the potential
for counter-
trend effects
 Source:  U.S. EPA analysis, 2004.
B3A5-2  SPECIFYING VARIABLES FOR THE ANALYSIS

Working from the general concepts of explanatory variables outlined above, EPA defined the specific explanatory
variables to be included in the analysis. A key requirement of the regression analysis is that the firm-specific
explanatory variables included in the regression analysis later be able to be used as the basis for estimating capital
expenditures for facilities in the Phase III dataset. As a result, in defining the firm-specific variables, it was
necessary to ensure that the definition of variables selected for the regression analysis using data on public-
reporting firms be consistent with the data items available for facilities in the Phase III dataset.

Also, EPA's  selection of firm-specific variables was further constrained by the decision to use the Value Line
Investment Survey (VL) as the source of firm-specific information for the regression analysis. The decision to
use VL as the source of firm-specific data for the analysis was driven by several considerations:

         *•   Reasonable breadth of public-reporting firm coverage.  The VL dataset includes  8,500 firms.

         *•   Reasonable breadth of temporal coverage.  VL provides data for the most recent 11 years - i.e.,
             1992-2002. Although ideally EPA would have preferred a longer time  series to include more years
B3A5-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                                                                         Appendix 5 to Chapter B3
            not in the "boom" business investment period of the mid- to late-1990s.

        *•   Reasonable coverage of concepts/data needed for analysis. The VL data includes a wide range of
            financial data that are applicable to the analysis (VL provides 37 data items over the  11 reporting
            years; see Attachment DB). However, because of the pre-packaged nature of the VL data, it was not
            possible to customize any data items to support more precise definition of variables in the analysis.
            In particular, EPA found that certain balance sheet items were not reported to the level of specificity
            preferred for the analysis. Overall, though, EPA expects the consequence of using more aggregate,
            less-refined concepts should be minor.

The decision to use VL data for the analysis constrained, in some instances, EPA's choice of variables for the
analysis.

Table B3A5.2 reports the specific definitions of variables included in the analysis (both the dependent variable
and explanatory variables), including any needed manipulations, the data source, the Phase III estimation analysis
equivalent (either the corresponding variable(s) in the Section 316(b) Phase III Detailed Industry Questionnaire or
other source outside the questionnaire), and any issues in variable definition.
                   Table B3A5.2: Variables For Capital Expenditure Modeling Analysis
Variables for Regression Analysis
Variable
Source
Calculation
Phase III Analysis
Equivalent
Comment / Issue
                                              Dependent Variable
Gross
expenditures
on fixed
assets:
CAPEX,
includes
outlays to
replace, and
add to,
existing
capital stock
Value Line




Obtained from VL as Capital
Spending per Share.
CAPEX calculated by
multiplying by Average
Shares Outstanding.



None: to be estimated
based on estimated
coefficients.




This value and all other dollar values in
the regression analysis were deflated to
2002 using 2-digit SIC PPI values.




Explanatory Variables
                                             Firm-Specific Variables
 Return On
 Assets: ROA
Value Line
ROA = Operating Income /
Total Assets.  Both
Operating Income, defined
as Revenue less Operating
Expenses (CoGS+SG&A),
and Total Assets were
obtained directly from VL.
From Survey: Revenue
less Total Operating
Expenses (Material &
Product Costs +
Production Labor +
Cost of Contract
Work + Fixed
Overhead + R&D +
Other Costs &
Expenses)
Would have preferred an after-tax
concept in numerator and a deployed
production capital concept in
denominator. However, VL provides
no tax value per se and would require
calculation of tax using an estimated tax
rate, which could introduce error. Also
neither VL nor Phase III survey data
provide sufficient information to get at
deployed production capital.
                                                                                                       B3A5-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 5 to Chapter B3
                   Table B3A5.2: Variables For Capital Expenditure Modeling Analysis
Variables for Regression Analysis
Variable
Revenue:
REV




Capital
Turnover
Rate: CAPT


Capital
Intensity:
CAPI

Market-to-
Book Ratio:
MV/B



Source
Value Line




Value Line


Value Line

Value Line



Calculation
REV = Revenues. Revenues
directly available from VL.




CAPT = Depreciation /
Total Assets. Depreciation
and Total Assets directly
available from VL.


CAPI = Total Assets /
Revenue. Total Assets and
Revenue directly available
fromVL
MV/B = average market price
of common equity (Price)
divided by book value of
common equity (Book Value
per Share). Price and Book
Value per Share directly
available from VL.



Phase III Analysis
Equivalent
From Survey: Revenue




From Survey:
Depreciation / Total
Assets


From Survey:
Total Assets / Revenue

N/A (see
Comment/Issue)



Comment / Issue
In the log-linear formulation this
variable captures percent
change/growth in revenues. However,
the use of the log-linear formulation,
eliminates the potential to set the
growth term to zero in estimating
baseline capital outlays for Phase III
facilities.
During the specification of the
regression model for the MP&M final
regulation, Total Assets was also tested
as a scale variable. Since it provided a
good, but not as strong, an explanation,
as REV it was not included in the final
specification. Based on this previous
finding, Total Assets was not
considered while specifying the Phase
III regression model.
Would have preferred denominator of
net fixed assets instead of total assets.
However, VL provides detailed balance
sheet information for only the four most
recent years. Not possible to separate
current assets and intangibles from total
assets.
As above, would have preferred net
fixed assets instead of total assets, but
needed data are not available from VL
for the full analysis period.
During specification of the MP&M
regression model, MV/B was found to
highly correlated with other, more
important explanatory variables, which
makes sense, given that equity terms
would be derived from more
fundamental factors, such as ROA.
Thus, MV/B was omitted from the
MP&M regression model. As a result,
MV/B was not considered during the
specification of the Phase III regression
model which eliminated the need to
define an approach to use this variable
with Phase III survey data.
B3A5-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 5 to Chapter B3
                  Table B3A5.2: Variables For Capital Expenditure Modeling Analysis
Variables for Regression Analysis
Variable
Source
Calculation
Phase III Analysis
Equivalent
Comment / Issue
                                    General Business Environment Variables
Interest on
10-year, A-
rated
industrial
debt:
DEBTCST
Index of
Leading
Indicators:
ILI




Capacity
Utilization
by Industry:
CAPUTIL


Producer
Price Index
series for
capital
equipment:
CAPPRC
Moody 's
Investor
Services



Conference
Board






Federal
Reserve
Board
(Dallas
Federal
Reserve)
Bureau of
Labor
Statistics
(BLS)


DEBTCST = annual average
of rates for each data year




Monthly index series
available from Conference
Board. ILI = geometric mean
of current year values.




Monthly index series
available from Federal
Reserve CAPUTIL =
current year average value.


Annual average values
available from BLS.
CAPPRC = current year
average value as reported by
BLS.

Use average of
DEBTCST rates at time
of Phase III survey.



Use average of ILI
values at time of Phase
III survey.





Use average of
CAPUTIL values at
time of Phase III survey.



Use average of
CAPPRC values at time
of Phase III survey.



10-year maturity, industry debt selected
as reasonable benchmark for industry
debt costs. 10 years became "standard"
maturity for industrial debt during
1990s.

During specification of the MP&M
regression model, EPA found that ILI
and the CAPPRC (see below) are
highly correlated. Thus, ILI was
omitted from the MP&M regression
model. As a result, ILI was not
considered during the specification of
the Phase III regression model.






BLS reports PPI series for capital
equipment based on "consumption
bundles" defined for manufacturing and
non-manufacturing industries. For this
analysis, EPA used the PPI series based
on the manufacturing industry bundle.
 Source:  U.S. EPA analysis, 2004.
B3A5-3  SELECTING THE REGRESSION ANALYSIS DATASET

In addition to specifying the variables to be used in the regression analysis, EPA also needed to select the public
firm dataset on which the analysis would be performed.

As noted above, EPA used the Value Line Investment Survey as the source for public firm data.  VL includes
over 8,500 publicly traded firms and identifies firms' principal business both by a broad industry classification
(e.g., Paper/Forest) and by an SIC code assignment. Value Line's SIC code definitions do not match the U.S.
Census Bureau's SIC code definitions; however, in most instances a Value Line SIC code can be reasonably
matched to one or several U.S. Census Bureau defined SIC codes. To build the public firm dataset corresponding
to the Phase III sectors (SIC 26: Paper and allied products, SIC 28: Chemicals and allied products, SIC 29:
Petroleum and coal products, and SIC 33 Primary metal industries), EPA initially selected all firms included in
the Value Line SIC code families:

       *•   2600: Paper/forest products,
       »•   2640: Packaging and container,
       *•   2810: Chemical (basic),
       *•   2813: Chemical (diversified),
       *•   2820: Chemical (speciality),
       *•   2830: Biotechnology,
                                                                                                B3A5-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 5 to Chapter B3

        •>  2834: Drug,
        *•  2840: Household products,
        *•  2844: Toiletries/cosmetics,
        *•  2900: Petroleum (integrated),
        *•  3311: Steel (general), and
        >  3312: Steel (integrated).

In order to derive a dataset of firms whose business activities closely match the activities of firms included in the
Phase III sample survey EPA made or attempted to make the following revisions to the initial dataset:

        *•  EPA found that the VL SIC code definition does not include categories which match SIC 331 and
           SIC 335 (combined together to form the aluminum sector in the Phase III analysis).  Since U.S.
           aluminum companies are generally vertically integrated (S&P, 2001), most aluminum companies own
           large bauxite reserves and mine bauxite ore. As such, these firms are classified in VL under SIC
           1000: Metals and mining. EPA reviewed the business activities of firms listed in SIC 1000: Metals
           and mining, and included only those firms described as aluminum companies in the regression
           analysis dataset.

        *•  EPA reviewed the business activities of firms listed in SIC 3400: Metal fabricating, however, no
           firms whose activities matched those described within the profiles of the Phase III Manufacturing
           Sectors were found.3

        *•  EPA reviewed the business activities of firms listed in SIC 2840: Household products and SIC 2844:
           Toiletries/cosmetics, and retained only those firms in the dataset whose activities matched those
           described within the profiles of the Phase III Manufacturing Sectors (see footnote 4).

        *•  EPA deleted firms within SIC 2600: Paper/forest products whose business  activities are solely limited
           to timber/lumber production. These facilities are unlikely to use cooling water intake structures and
           therefore fall outside the Phase III  Manufacturing Sectors.

        *•  EPA reviewed the business activities of firms listed in SIC 2830: Biotechnology and SIC 2834: Drug
           in order to exclude firms that are exclusively research and development (R&D) firms and are unlikely
           to use cooling water intake structures. However, based on the information provided by Value Line
           EPA was unable to segregate R&D firms from the rest of the firms listed in these SIC codes.

        *•  EPA only retained firms in the VL dataset if they are situated in the U.S. or Canada, and for whom
           financial information is available in U.S. dollars.

On inspection, EPA found that a substantial number of firms did not have data for the full  11 years of the analysis
period.  The general reason for the omission of some years of data is that the firms did not become publicly listed
in their current operating structure - whether through an initial public offering, spin-off, divestiture of business
assets, or other significant corporate restructuring that renders earlier year data inconsistent with more recent
data - until after the beginning of the 11-year data period.4 As a result, the omission of observation years for a
firm always starts at the beginning of the data analysis period.  This systematic front-end truncation of firm
observations in the dataset could be expected to bias the analysis in favor of the capital expenditure behavior
nearer the end of the 1990s decade.  To avoid this problem, EPA removed all firm observations that have fewer
than 11 years of data. As a result, the dataset used in the analysis has a total of 2,244 yearly data observations and
represents 204 firms.
    3 The profiles only focus on 4-digit SIC categories represented in the sample of facilities which received the Section 316(b) detailed
industry questionnaire.

    4 When VL adds a firm to its dataset, it fills in the public-reported data history for the firm for the lesser of 11 years or the length of
time that the firm has been publicly listed and thus subject to SEC public reporting requirements.

B3A5-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                                                                Appendix 5 to Chapter B3
Table B3A5.3 presents the number of firms by industry classifications.
                        Table B3A5.3: Number of Firms by Industry Classifications
                    SIC Industry Classification
                                              Number of Firms
                    26: Paper and allied products

                    28: Chemicals and allied products

                    29: Petroleum and coal products

                    33: Primary metal industries
                                                    24

                                                    136

                                                    20

                                                    24
B3A5-4 SPECIFICATION OF MODELS TO BE TESTED

On the basis of the variables listed above and their hypothesized relationship to capital outlays, EPA specified a
time-series, cross sectional model to be tested in the regression analysis. EPA's dataset consisted of 204 cross
sections observed at 11 years (1992 through 2002). The general structure of this model was as follows:
Where:
CAPEXU
t
i
j
CAPT,.,
CAPLj
DEBTCST,
CAPPRQ
CAPUTIL,,
               CAPEXU =/(ROAu, REVU, CAPTU, CAPI, ft DEBTCST, „ CAPPRQ, CAPUTIL
capital expenditures of firm /', in time period t;5
year (year =1992,.  .  . ,2002);
firm /(/ = !,. •  •  , 204);
industry classification j
return on total assets for firm /' in year t;
revenue ($ millions) for firm /' in year t;
capital turnover rate for firm /' in year t;
capital intensity for firm / in year t;
financial cost of capital in year t;
price of capital goods in year t;
the Federal Reserve Board's Index of Capacity utilization for a given industry/ in year t.
EPA only tested log-linear model specifications for this analysis.6 The main advantage of the log-linear model is
that it incorporates directly the concept of percent change in the explanatory variables. Specifying the key
regression variables as logarithms permitted EPA to estimate directly as the coefficients of the model, the
elasticities of capital expenditures with respect to firm financial characteristics and general business environment
factors. The following paragraphs briefly discuss testing of the log-linear forms of the model. Parameter
estimates are presented for the final log-linear model only.

EPA specified a log-linear model, as follows:

                              ln(CAPEXu) = a
    5 All dollar values were deflated to 2002 using 2-digit SIC PPI values.

    6 While specifying the MP&M regression model, EPA tested both linear and log-linear model specifications. The pattern of
coefficient significance was found to be better in the log-linear model. In addition, the log-linear model offered advantages in terms of
retention of early time period observations (by eliminating the need to use percent change variables) and variable specifications, and
helped to reduce outlier effects in the model. As a result, EPA selected a log-linear specification as the final regression model for the
MP&M final regulation. Based on these reasons and the similarity of industry sectors analyzed for the two regulations, EPA decided to
test only log-linear model specifications for the Phase III regression model.
                                                                                                     B3A5-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 5 to Chapter B3

Where:
CAPEXU       =      capital expenditures of firm /', year t;
PJ.              =      elasticity of capital expenditures with respect to firm characteristic X;
Xu,             =      a vector of financial characteristics of firm /', year t;
Yy              =      elasticity of capital expenditures with respect to economic indicator Y;
Y,              =      a vector of economic indicators, year t; for CAPUTIL, Y is also differentiated by industry
                       classification
e               =      an error term; and
ln(r)            =      natural log of x

Based on this model, the elasticity of capital expenditures with respect to an explanatory variable, for example,
return on assets is calculated as follows:
                            EiCATEX}- d^(CAPEX"> - d(CAPEX}/CAPEX
                              ^         '     d\n(ROA)         d (ROA)/ROA
Since logarithmic transformation is not feasible for negative and zero values, such values in the VL public firm
dataset required linear transformation to be included in the analysis.  The following variables in the sample
required transformation:

        »•   CAPEX: Eighteen firms  in the sample reported zero capital expenditures at least in one time period.
            EPA set these expenditures to $ 1.

        *•   REVENUE: Seven firms reported negative revenues in at least one time period. Because these are
            likely due to accounting  adjustments from prior period reporting, EPA set negative revenues for these
            firms to $ 1.

        *•   ROA: the values for return on assets in the public firm sample range from -2.9 to 0.7.  Approximately
            34 percent of the firms in the dataset reported negative ROAs in at least one year. To address this
            issue while reducing potential effects of data transformation on the modeling results, EPA used the
            following data transformation approach:7

            n   EPA excluded 27 firms with any annual ROA values below the 95th percentile of the ROA
                distribution (i.e., ROA < - 0.51).

            n   EPA used an additive data transformation to ensure that remaining negative ROA values were
                positive in the logarithm transformation.  The additive transformation was performed by adding
                0.51 to all ROA values.

As a result of the data transformation procedures outlined above, the VL public firm dataset on which the
regression model is based was reduced to 177 firms (204  - 27 firms) and 1,947 yearly data observations.

The analysis tested several specifications of a log-linear model, including models with the intercept and slope
dummies for different industrial sectors and models with the intercept suppressed.8  Slope dummies were used to
    7 While specifying the MP&M regression model EPA conducted a sensitivity analysis to examine the degree to which the estimated
model was affected by this data transformation. Results of this analysis showed that the data transformation produces results that are
compatible with a model considering only positive ROA values and a model considering all ROA values. As a result, the Phase III
regression model utilized the same data transformation procedure.

    8 While specifying the MP&M regression model, EPA also tested specifications that included the following structural modifications:
(1) testing contemporary vs. lagged specification of certain explanatory variables: e.g., using prior, instead of current period revenue, REV,
as an explanatory variable; (2) testing scale-normalized specification of the dependent variable: e.g., using CAPEX/REV as the dependent
variable instead of simple CAPEX; (3) testing flexible functional forms that included quadratic terms; and (4) testing additional
explanatory variables including the index of 10 leading economic indicators (ILI) and market-to-book ratio (MV/B). Because EPA found

B3A5-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 5 to Chapter B3

test the influence of industry classification on the elasticity of capital expenditures with respect to an explanatory
variable: e.g., using the product of an industry classification dummy variable and CAPPRC to test whether certain
industries responded differently to change in price of capital equipment over time. Following review of the
different models tested, EPA concluded that the estimated coefficients did not vary, significantly, by industry and
thus selected the simple log -linear model, with the intercept and no slope dummies as the basis for the 3 16(b)
Phase III capital expenditures analysis. The results for this model are summarized below.

Cross-sectional, time-series datasets typically exhibit both autocorrelation and group-wise heteroscedasticity
characteristics. Autocorrelation is frequently present in economic time series data as the data display a "memory"
with the variation not being independent from one period to the next. Heteroscedasticity usually occurs in cross-
sectional data where the scale of the dependent variable and the explanatory power of the model vary across
observations. Not surprisingly, the dataset used in this analysis had both characteristics. Therefore, EPA
estimated the specified model using the generalized least squares procedure.  This procedure involves the
following two steps:

        *•  First, EPA estimated the model using simple OLS, ignoring  autocorrelation for the purpose of
           obtaining a consistent estimator of the autocorrelation coefficient (p);

        *•  Second, EPA used the generalized least squares procedure, where the analysis  is applied to
           transformed data.  The resulting autocorrelation adjustment is as follows:
where Za is either dependent or independent variables.

EPA was unable to correct the estimated model for group-wise heteroscedasticity due to computational
difficulties.  The statistical software used in the analysis (LIMDEP) failed to correct the covariance matrix due to
the very large number of groups (i.e., 177 firms) included in the dataset. Application of other techniques to
correct for group-wise heteroscedasticity was not feasible due to time constraints.  The estimated coefficients
remain unbiased; however, they are not minimum variance estimators.  Regression results reveal strong
systematic elements influencing capital expenditures: the analysis finds both statistically significant and intuitive
patterns that influence firm's investment behavior.  We find a strong systematic element of capital expenditures
variation which allows forecasting of capital expenditures based on firm and business environment characteristics.

Table B3A5.4 presents model results. The model has a fairly good fit, with adjusted R2 of 0.81. All coefficients
have the expected sign and all but one variable (cost of debt capital) are significantly different from zero at the
95thpercentile.
that these structural modifications either did not improve the fit of the MP&M regression model or resulted in the introduction of
multicollinearity among variables, these structural modifications were not tested while specifying the Phase III regression model.
                                                                                                   B3A5-11

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 5 to Chapter B3
                           Table B3A5.4: Time Series, Cross-Sectional Model
                                                 Results
Variable
Constant
Ln(ROA)
Ln(REV)
Ln(CAPT)
Ln(CAPI)
Ln(DEBTCST)
Ln(CAPPRC)
Ln(CAPUTIL)
Coefficient
21.880
0.526
1.129
0.687
1.078
-0.789
-5.957
1.716
t-Statistics
2.618
3.964
58.450
11.085
18.491
-1.605
-4.369
2.842
Autocorrelation Coefficient
                                                      0.385                 18.402
The empirical results show that among the firm-specific variables, the output variable (REV) is a dominant
determinant of firms' investment spending. A positive coefficient on this variable means that larger firms invest
more, all else equal, which is clearly a simple expected result. In addition, as expected, firms with higher
financial performance and better investment opportunities (ROA) invest more, all else equal: for each one percent
increase in ROA, a firm is expected to increase its capital outlays by 0.53 percent.  Other firm-specific
characteristics were also found important and will aid in differentiating the expected capital outlay for Phase III
facilities according to firm-specific characteristics. Firms that require more capital to produce a given level of
business activity (i.e., firms that have high capital intensity, CAPI) tend to invest more: a one percent increase in
capital intensity leads to a 1.08 percent increase in capital spending.  Higher capital turnover/shorter capital life
(CAPT) also has a positive effect on investment decisions: a one percent increase in capital turnover rate
translates to a 0.69 percent increase in capital outlays.

The model also shows that current business environment conditions play an important role in firms' decision to
invest. Negative signs on the capital price (CAPPRC) and debt cost (DEBTCST) variables match expectations,
indicating that falling (either relatively or absolutely) capital equipment prices and less costly credit are likely to
have a positive effect on firms' capital expenditures. The  most influential factor is capital equipment prices for
manufacturing facilities.  A one percent increase in the capital price index (CAPPRC) leads to a 5.96 percent
decrease in capital investment. Capacity utilization is also an influential  factor: a one percent increase in the
Federal Reserve Index of Capacity Utilization for the relevant industrial sector (CAPUTIL) leads to a 1.7 percent
increase in capital investments.  The fact that these systematic variables are significant in the regression analysis
means that EPA will be able to control for economy- and  industry-wide conditions in estimating capital outlays
for Phase III facilities.
B3A5-5 MODEL VALIDATION

To validate the results of the regression analysis, EPA used the estimated regression equation to calculate capital
expenditures and then compared the resulting estimate of capital expenditures with actual data. EPA used two
methods to validate its results:

        *•  EPA used median values for explanatory variables from the Value Line data as inputs to estimate
           capital expenditures and then compared the estimated value to the median reported capital
           expenditures, and
B3A5-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 5 to Chapter B3
        *•   EPA used Phase III survey data to estimate capital expenditures and then compared the estimated
           values to depreciation reported in the survey.

First, EPA estimated capital expenditures for a hypothetical firm based on the median values of the four
dependent variables from the Value Line data and the relevant values of the three economic indicators. The
estimated  capital expenditures for this hypothetical firm are $43 million.  EPA then compared this estimate to the
median value of capital expenditures from the Value Line data.  The median capital expenditure value in the
dataset is $36 million, which provides a close match to the estimated value. This is not surprising since the same
dataset was used to estimate the regression model and to calculate the median values used in this analysis.

EPA also used Phase III survey data to confirm that the estimated capital  expenditures seem reasonable. Because
the Phase  III survey does not provide information on capital expenditures, EPA compared the capital expenditure
estimates to the depreciation values reported in the survey.  Depreciation  had been proposed as a possible
surrogate for cash outlays for capital replacements and additions.  However, depreciation does not capture
important variations in capital outlays that result from differences in firms' financial performance.

For this analysis, EPA chose a representative facility from each of the four Phase III primary manufacturing
sectors for model validation.  The selected facility for each sector corresponds as closely as possible to the
hypothetical median facility in the sector based on the distribution of facility revenues and facility return on
assets. For each of the four facilities, EPA estimated capital expenditures using the estimated regression equation
and facility financial data. Table B3A55 shows the estimated regression coefficients, financial averages for the
four Phase III sectors, estimated facility capital expenditures, reported facility depreciation, and the comparison of
capital expenditures and depreciation.

As shown in Table B3A5.5, the estimated model provides reasonable estimates of capital expenditures.
  Table B3A5.5: Estimation of Capital Outlays for Phase III Sample Facilities: Median Facilities Selected
                                    by Revenue and ROA Percentiles


Sectors


Coefficient
Intercept
(21.88)
Paper and
allied
products
Chemicals
and allied
products
Petroleum
and coal
products
Primary
metals
industries

Pre-Tax
Return
on
Assets
(ROA)


0.53


0.16


0.22


0.15


0.11



Revenue Capital _ ., ,
($2003, Turnover TCfplta'
•••• \ T. ^ Intensity
millions) Rate J



1.13 0.69 1.08


$244 0.09 0.89


$237 0.06 1.14


$1,470 0.05 0.58


$444 0.06 0.52


Estimated
Cost Price of _ ., Capital
, .-,.., Capacity _ *,.,
of Capital TT, ... , . Expenditures
T» u^ /-i j Utilization ff-tnni
Debt Goods ($2003,
millions)


-0.79 -5.96 1.72


7.71 137.60 86.24 $18.94


7.71 137.60 79.36 $15.25


7.71 137.60 91.88 $45.58


7.71 137.60 88.77 $15.58

Difference
between
Depreciation Depreciation
($2003, and Capital
millions) Expenditures
($2003,
millions)




$16.16 ($2.78)


$13.66 $1.59


$62.95 $17.37


$18.55 $2.97

Source: U.S. EPA analysis, 2004.
                                                                                                  B3A5-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                 Appendix 5 to Chapter B3

One of the possible implications of the hypothesized relationships and estimated coefficient values from the prior
analysis is that a facility's predicted capital expenditures might be expected to increase relative to the facility's
actual depreciation as the facility's ROA increases.  An extension and somewhat version of this hypothesis is that,
at lower ROA values, predicted capital expenditures would be less than the depreciation but, that at higher ROA
values, predicted capital expenditures exceed depreciation. These hypotheses are consistent with the expectation
that businesses with higher financial performance will have relatively more attractive investment opportunities
and are more likely to attract the capital  to undertake those investments. EPA examined whether these
relationships occur in the 316(b) sample facilities.  Specifically, EPA calculated the predicted capital expenditure
for each facility and compared these values to the facilities' reported depreciation values. To remove the scale
effect of revenue, EPA normalized both  the predicted capital expenditure and reported depreciation values by
dividing by the three-year average of revenue for each facility. EPA then estimated the simple linear relationship
of the resulting revenue-normalized capital expenditure and deprecation values against facility ROA.  The four
graphs on the following pages present, for each of the four two-digit SIC code sectors, the normalized capital
expenditure and  deprecation values, and the estimated trend lines for each sector's depreciation and capital
expenditures with respect to ROA.4 The graphs indicate the following:

        *•    The  Paper and Allied Products (SIC 26) graph shows depreciation exceeding predicted capital
            expenditure at low ROA values but this relationship reverses with predicted capital expenditure
            exceeding depreciation as ROA increases. Thus, the calculations for these facilities match the
            hypothesized relationship.

        *•    The  Chemicals and Allied Products (SIC 28) graph also shows depreciation exceeding predicted
            capital expenditure at low ROA values, but again the relationship reverses with predicted capital
            expenditure exceeding depreciation as ROA increases. This predicted relationship is observed more
            strongly for facilities in the Chemicals and Allied Products industry than in the Paper and Allied
            Products industry.

        *•    The  Petroleum and Coal  Products (SIC  29) graph shows predicted capital expenditures exceeding
            depreciation over the ROA range analyzed.  However, the extent of difference does not materially
            change as ROA increases.

        *•    The  Primary Metal Industries (SIC 33) graph also shows predicted capital expenditures exceeding
            depreciation over the ROA range analyzed.  However, unlike for the Petroleum and Coal Products
            facilities, the amount by which predicted capital  expenditures exceeds depreciation increases as ROA
            increases, thus matching the hypothesized relationship.

In summary, with the exception of facilities in the Petroleum and Coal Products industry, the estimated model
produces capital expenditure values that increase relative to reported depreciation with increasing ROA, which
matches the hypothesized relationship.
    4 For presentation purposes, two outlier facilities were excluded from the graph for SIC 28: Chemicals and allied products, and one
outlier facility was excluded from the graph for SIC 26: Paper and allied products.

B3A5-14

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 5 to Chapter B3
     Figure B3A5.1:  Comparison of Estimated Capital Outlays to Reported Depreciation for Phase III
                         Survey Facilities in the Paper and Allied Products Sector
                                         CAPEX 	Linear (DEPR) 	 	 Linear (CAPEX)
 Source:  U.S. EPA analysis, 2004.
     Figure B3A5.2:  Comparison of Estimated Capital Outlays to Reported Depreciation for Phase III
                      Survey Facilities in the Chemicals and Allied Products Sector
                                     0.40
                                               0.60       0.80

                                               Re tu rn on Assets
                                                                                       1.40
                                                                                                 1 .60
                              DEPR
                                         CAPEX
                                                     -Linear (DEPR)
                                                                       Linear (CAPEX)
 Source: U.S. EPA analysis, 2004.
                                                                                                  B3A5-15

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 5 to Chapter B3

Figure B3A5.3: Comparison of Estimated Capital Outlays to Reported Depreciation for Phase III
Survey Facilities in the Petroleum and Coal Products Sector
A 1 /;
3
a
1
«
1
_£>
1
es
s
o
fc
H
1
a.
0
H
=8
I
3
O
"s
'a.
C!
U
0.14 - •
•
0.12 -
•
0.10 -

•
0.08 -



0.06 -
II

0.04 - — 	 -•- 	 	 I_ 	 _^
	 " ^ • " — — — — — _^, . _
~ ^^ 	 ••— ^ ~~ ~~
o* • ^ « ~ ^^"^^^^~^^^^^^^^^^™^^^^^^^_^^^ 	
0.02 - !*••** * ^ J •
. •

* *





















-0.10 0.00 0.10 0.20 0.30 0.40 0.50 0.60
Return on Assets

• DEPP pAp-pi^ ^^^^^^^^ L in L 3,r ( D E P F ) ^^^ Lin 3r('~'ArE1M



Source: U.S. EPA analysis, 2004.
Figure B3A5.4: Comparison of Estimated Capital Outlays to Reported Depreciation for Phase III
Survey Facilities in the Primary Metal Industries Sector


1
|
1
£
•B
.1
1
O
Z
c.
£

1
1
«8
i?l
0
1
'a.
R
U
<• 0.09 -
0.08 -
" 0.07 - T •
•
0.06 -
*
• •
0.05 - "• *
— ,_ 	 	 * •

m mmm^mm-—^^^_ *^ ^^— — ^
0-04 - ^ " ~^~~ *^* ^^ ^J _^ m
• * ^» * 	 ~' ~" ~ 	 __ __
• . •
•0.02 - *
« ^
0.01 -
n nn

















-0.10 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70
Return on Assets

• DEPR • CAPEX 	 Linear (DEPR) 	 	 Linear (CAP EX)


 Source: U.S. EPA analysis, 2004.
B3A5-16

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities               Appendix 5 to Chapter B3

ATTACHMENT B3A5.A: BIBLIOGRAPHY OF LITERATURE REVIEWED FOR THIS ANALYSIS

As noted above, EPA relied on previous studies of investment behavior to select critical determinants of firms'
capital expenditures. Empirical results from these studies suggest that investment is most sensitive to quantity
variables (output or sales), return-over-cost, and capital utilization (R.  Chirinko). Empirical results from more
recent studies further found that increasing depreciation rates and capital equipment prices were of first-order
importance in the equipment investment behavior in the 1990 (T. Tevlin, K. Whelan).  Specifically, declining
prices of micro-processor based equipment played a crucial role in the investment boom in the 1990.

Chirinko, Robert S.  1993. "Business Fixed Investment Spending: A Critical Survey of Modeling Strategies,
Empirical Results and Policy Implications." Journal of Economic Literature 31, no. 4: 1875-1911.

Goolsbee, Austan. 1997. "The Business Cycle, Financial Performance, and the Retirement of Capital Goods."
University of Chicago, Graduate School of Business Working Paper.

Greenspan, Alan. 2001. "Economic Developments." Remarks before the Economic Club of New York, New
York, May 24.

Kiyotaki, Nobuhiro and Kenneth D. West. 1996. "Business Fixed Investment And The Recent Business Cycle
In Japan." National Bureau of Economic Research Working Paper 5546.

McCarthy, Jonathan. 2001. "Equipment Expenditures since 1995: The Boom  and the Bust." Current Issues In
Economics And Finance 7, no. 9: 1-6.

Opler, Tim and Lee Pinkowitz, Rene Stulz and Rohan Williamson.  1997.  "The Determinants and Implications of
Corporate Cash Holdings." Working paper, Ohio State University College of Business.

Tevlin, Stacey and Karl Whelan. 2000. "Explaining the Investment Boom of the 1990s." Board of Governors of
the Federal Reserve System Finance and Economics Discussion Paper no. 2000-11

Uchitelle, Louis. 2001.  "Wary Spending by Companies Cools Economy." New York Times, May 14, p.  Al.
                                                                                             B3A5-17

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 5 to Chapter B3

ATTACHMENT B3A5.B:  HISTORICAL VARIABLES CONTAINED IN THE VALUE LINE
INVESTMENT SURVEY DATASET

All variables are provided for 10 years (except where a firm has been publicly listed for less than 10 years):

       *•   Price  of Common Stock
       *•   Revenues
       *•   Operating Income
       *•   Operating Margin
       *•   Net Profit Margin
       *•   Depreciation
       *•   Working Capital
       *•   Cash  Flow per share
       *•   Dividends Declared per share
       *•   Capital Spending per share
       *•   Revenues per share
       *•   Average Annual Price-Earnings Ratio
       *•   Relative Price-Earnings Ratio
       *•   Average Annual Dividend
       *•   Return Total Capital
       *•   Return Shareholders Equity
       *•   Retained To Common Equity
       *   All Dividends To Net Worth
       *•   Employees
       *   Net Profit
       *•   Income Tax Rate
       *•   Earnings Before Extras
       *•   Earnings per share
       *•   Long Term Debt
       *•   Total Loans
       *•   Total Assets
       *•   Preferred Dividends
       *•   Common Dividends
       *•   Book Value
       *•   Book Value per share
       *•   Shareholder Equity
       *•   Preferred Equity
       *•   Common Shares Outstanding
       *•   Average Shares Outstanding
       +   Beta
       *•   Alpha
       *•   Standard Deviation
B3A5-18

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities               Appendix 6 to Chapter B3

                   Appendix 6  to  Chapter B3:
     Summary of Moderate  Impact Threshold
                           Values  by Industry
INTRODUCTION                              APPENDIX CONTENTS
                                             B3 A6-1 Developing Threshold Values for Pre-Tax Return on
                                                    Assets	 B3A6-2
                                             B3 A6-2 Developing Threshold Values for Interest Coverage
                                                    Ratio	 B3A6-2
                                             B3A6-3 Summary of Results	 B3A6-4
                                             References 	 B3A6-5
Facilities subject to moderate impacts from the
proposed regulation are expected to experience
financial stress short of closure. This analysis uses
two financial indicators: (1) Pre-Tax Return on
Assets (PTRA) and (2) Interest Coverage Ratio
(ICR). These threshold values were calculated at
the industry-level and compared to pre- and post-
compliance PTRA and ICR values for sample facilities to determine if facilities choosing to remain in business
after promulgation of effluent guidelines would experience moderate impacts on their ability to attract and finance
new capital. The six industries considered in this analysis are: Paper, Chemicals, Petroleum, Steel, Aluminum
(the "Primary Manufacturing Industries"), and Other Industries. The remainder of this appendix describes the
sources and methodology used to derive industry-specific moderate impact threshold values.

EPA calculated the thresholds using income and financial structure information by 4-digit SIC code from the Risk
Management Association (RMA) Annual Statement Studies for eight years 1994-2001 (RMA, 2001; RMA 1998).
This source provides quartile values derived from statements of commercial bank borrowers and loan applicants
for firms having less than $250 million in total assets.  These criteria may introduce bias, since firms with
particularly poor financial statements might be less likely to apply to banks for loans, and some types of firms
may be more likely to use bank financing than others.  However, the RMA data offers the advantage of being
available by 4-digit SIC codes and for quartile ranges.

RMA did not provide data for all 4-digit SIC codes associated with an in-scope Section 316(b) facility.  Out of 26
SIC codes associated with facilities in the Primary Manufacturing Industries and 14 SIC codes associated with
facilities in Other Industries, 10 SIC codes associated with facilities in the Primary Manufacturing Industries (38
percent) and 7 SIC codes associated with facilities in Other Industries (50 percent), had no years of data available.
In addition, no data were available for the Aluminum industry, so EPA applied a combined Steel/Aluminum
industry value to facilities in those industries.

The 4-digit SIC code data were consolidated into weighted industry averages, weighted by 1997 value of
shipments from the Economic Censuses (U.S. DOC, 1997). For each industry and impact measure, a separate
threshold was calculated. The use of the RMA data for calculating the threshold values for pre-tax return on assets
and interest coverage ratio is outlined below.
                                                                                        B3A6-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities               Appendix 6 to Chapter B3


B3A6.1 DEVELOPING THRESHOLD VALUES FOR PRE-TAX RETURN ON ASSETS (PTRA)

Pre-tax return on total assets measures management's effectiveness in employing the capital resources of the
business to produce income. A low ratio may indicate that a borrower would have difficulty financing treatment
investments and continuing to attract investment.

The following data from Risk Management Association Annual Statement Studies were used to calculate PTRA:

       ••   % Profit Before Taxes / Total Assets 25th      Ratio of profit before taxes divided by total assets and
                                                  multiplied by 100 for the lowest quartile of values in
                                                  each 4-digit SIC code.

       *•   Operating Profit                         Gross profit minus operating expenses.

       *•   Profit Before Taxes                      Operating profit minus all other expenses (net).

RMA provides a measure of pre-tax return on assets that approximates the measure that EPA defined for the
moderate impact analysis.  As defined by RMA, this measure is the ratio of pre-tax income to assets, designated
        = Pre-Tax Income (EBT) / ASSETS2
                                        5th
However, as defined by EPA for its analysis, the numerator of the PTRA measure requires the use of earnings
before interest and taxes (EBIT) instead of pre-tax income (EBT). Defined as EBIT, the PTRA numerator will
capture all return from assets, whether going to debt or equity. To derive a pre-tax, total return value, EPA
adjusted RMA's measure of PTRA using the median percentage values of EBIT and EBT available from RMA.
This adjustment yields the PTRA measure that EPA used in the moderate impact analysis, designated ROA316(b):

ROA316(b) = ROA   * EBIT / EBT
Negative values are included in the weighted-industry PTRA averages but a different method is used to adjust the
ROA values reported in RMA to the value used in the moderate impact analysis. Specifically, using only those
observations (i.e., 4-digit SIC code and year combinations) with positive values for % Profit Before Taxes / Total
Assets, Operating Profit, and Profit Before Taxes, EPA calculated an adjustment factor by subtracting the
difference between ROA316(b) and ROA^^ as follows:
ROA316(b)-ROARMA = adjustment factor.

Those values were consolidated into industry-specific adjustment factors, weighted by 1997 value of shipments
from the Economic Censuses (U.S. DOC, 1997). Each negative PTRA observation from RMA was adjusted by
its industry specific adjustment factor to approximate the measure used in the moderate impact analysis:

ROAju^ + industry specific adjustment factor = ROA316(b)

The industry specific adjustment factors average 0.40 and range from 0.12 for Paper to 0.55 for the combined
Steel/Aluminum industry.


B3A6-2 DEVELOPING THRESHOLD VALUES FOR INTEREST COVERAGE RATIO (ICR)

Interest coverage ratio measures a business' ability to meet current interest payments and, on a pro-forma basis,
to meet the additional interest payments under a new loan. A high ratio may indicate that a borrower would have
little difficulty in meeting the interest obligations of a loan. This ratio serves as an indicator of a firm's capacity to
take on additional debt.
B3A6-2

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 6 to Chapter B3

The following data from Risk Management Association Annual Statement Studies were used to calculate ICR:

        ••   EBIT/Interest25th                  Ratio of earnings (profit) before annual interest expense and
                                            taxes (EBIT) divided by annual interest expense for the lowest
                                            quartile  of values in each 4-digit SIC code.

        *•   % Depr., Dep., Amort. /Sales med     Median  ratio of annual depreciation, amortization and depletion
                                            expenses divided by net sales and multiplied by 100.

        *•   Operating Profit                  Gross profit minus operating expenses.

RMA provides a measure of interest coverage that approximates the measure that EPA defined for the moderate
impact analysis.  As defined by RMA, this measure is the ratio of earnings before interest and taxes to interest,
designated ICR^^:

ICR^ = EBIT / INTEREST25&

However,  as defined by EPA for its analysis, the numerator of the ICR measure requires the use of earnings
before interest, taxes, depreciation, and amortization (EBITDA) instead of earnings before interest and taxes
(EBIT). Defined this way, the ICR numerator will include all operating cash flow that could be used for interest
payments. To derive the desired ICR value (designated ICR316(b)), EPA adjusted the RMA value as outlined
below:

ICR316(b) = EBITDA / INTEREST
Therefore, ICR316(b) = ICR^ * (EBIT + DA) / EBIT
or ICR316(b) = ICRj^ * { 1+ [(DA / SALES) / (EBIT / SALES)]}

For consistency of calculation, EPA used the median values available from RMA for the adjusting both the
numerator (DA / SALES) and denominator (EBIT / SALES) terms.1

EPA used the same method as described above to adjust the negative ICR values reported in RMA to the value
used in the moderate impact analysis.  Including only those observations with positive values for EBIT/Interest, %
Depr., Dep., Amort./Sales, and Operating Profit, an adjustment factor was calculated by subtracting the difference
between ICR316(b) and tCR^^as follows:

ICR316(b)-ICRRMA = adjustment factor.

An industry  specific adjustment factor was calculated for ICR values similar to the PTRA. Each negative ICR
observation from RMA was adjusted by its industry  specific adjustment factor to approximate the measure used in
the moderate impact analysis:
         industry specific adjustment factor = ICR
                                              •316(b)
The industry specific adjustment factors average 0.65 and range from 0.55 for Petroleum to 0.70 for Paper and the
combined Steel/Aluminum industry.
        1 Numerator (% Depr., Dep., Amort./Sales) is available for quartile values; denominator (Operating Profit) only for median
        values.	
                                                                                                 B3A6-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
Appendix 6 to Chapter B3
B3A6-3 SUMMARY OF RESULTS

Table B3A6.1 reports the resulting threshold values for PTRA and ICR by industry. The PTRA values range
from 1.8 percent for Other Industries to 2.9 percent for Chemicals. The ICR values range from 2.0 for Other
Industries to 2.4 for Chemicals.
                 Table B3A6.1: Summary of Moderate Impact Thresholds by Industry
                      based on 25th percentile value of firms reporting data to RMA
Industry
Paper
Chemicals
Petroleum
Steel/Aluminum
Other Industries
Pre-Tax Return on Assets
(PTRA)
2.1%
2.9%
2.1%
2.0%
1.8%
Source: RMA, 2001; RMA, 1998; U.S. Economics Census,
Interest Coverage Ratio
(ICR)
2.2
2.4
2.2
2.1
2
1997; U.S. EPA Analysis, 2004.
B3A6-4

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 6 to Chapter B3


REFERENCES

U.S. Department of Commerce. 1997. Bureau of the Census. Census of Manufacturers, Census of
Transportation, Census of Wholesale Trade, Census of Retail Trade, Census of Service Industries.

Risk Management Association (RMA). 1997-1998. Annual Statement Studies.

Risk Management Association (RMA). 2000-2001. Annual Statement Studies.
                                                                                                B3A6-5

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities               Appendix 6 to Chapter B3
                           THIS PAGE INTENTIONALLY LEFT BLANK
B3A6-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
                           Appendix 7 to Chapter B3
                  Appendix 7 to Chapter B3:
           Analysis  of Baseline Closure Rates
INTRODUCTION

This appendix presents information on the annual entry
and closure of establishments in the Primary
Manufacturing Industries.
APPENDIX CONTENTS
B3A7-1 Annual Establishment Closures
References 	
B3A7-1
B3A7-2
B3A7-1 ANNUAL ESTABLISHMENT CLOSURES

EPA used the dynamic data from the Statistics of U.S. Businesses (SUSB) to estimate the rate at which facilities
in these industries leave the industry each year. The SUSB data report numbers of establishments starting up,
closing, expanding employment and contracting employment each year from 1989 through 2001 (the latest year
currently available).

EPA compared the percent of facilities predicted to close in the baseline closure analysis to typical closure rates in
the five primary industries. The SUSB data are organized by 3-digit SIC code for years 1990 through  1998, and
4-digit NAICS code for years 1999 through 2001. As a result, it is not possible to compile a series of data
consistently aligned with the industries profiled. Nevertheless, EPA believes the SUSB data can provide a
general measure of establishment closures for comparison for the broad industry segments.

Table B3A7.1 shows the percentage of facilities assessed as closures in the baseline analysis, and the range and
average of closure rates for each of the five Primary Manufacturing  Industries.  As reported in the table, between
1.4 percent and 12.5 percent of all facilities in these industries close annually. The estimated baseline closure
rates for facilities in the Steel and Aluminum industries are higher than the observed closure  rates in these
industries, as  reported in SUSB data. However, EPA's baseline closure rates are estimated from sample survey
data and are thus subject to the statistical uncertainty of the sample survey. EPA believes the individual sample
facility analyses accurately represent the baseline financial condition of the facilities, based on the data provided
in the facility questionnaires.
            Table B3A7.1: Predicted Baseline Closures and Annual Percentage of Closures
                        for Primary Manufacturing Industries (1990-2001)
Sector
Paper
Chemicals
Petroleum
Steel
Aluminum
Total
Percent of 316(b)
Facilities Assessed as
Baseline Closures
13.6%
2.2%
13.9%
36.8%
33.3%
13.6%
Percent of Establishments
Range
1.4% -9. 8%
2.3% -9.2%
3. 3% -10.6%
4.6% -10.0%
2.3% -12. 5%
1.4% -12.5%
Closing
Average
5.0%
6.4%
6.6%
6.5%
6.2%
6.1%
          Source: Small Business Administration, Statistics of U.S. Businesses.
                                                                                        B3A7-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part B: Economic Analysis for Existing Facilities                Appendix 7 to Chapter B3


REFERENCES

Small Business Administration.  Statistics of U.S. Businesses.
Available at: http://www.sba.gov/ADVO/stats/data.html.

U.S. Department of Commerce (U.S. DOC). 1997. Bureau of the Census. 1997 Economic Census Bridge Between
NAICSandSIC.
B3A7-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

     Chapter  B4: Profile of the  Electric Power
                                       Industry
                                                  CHAPTER CONTENTS
                                                  B4-1 Industry Overview	
                                                      B4-1.1 Industry Sectors  	
                                                      B4-1.2 Prime Movers	
                                                      B4-1.3 Ownership	
                                                  B4-2 Domestic Production	
                                                      B4-2.1 Generating Capacity	
                                                      B4-2.2 Electricity Generation	
                                                      B4-2.3 Geographic Distribution	
                                                  B4-3 Power Plants Potentially Subject to Phase III
                                                      Regulation	
                                                      B4-3.1 Ownership Type	
                                                      B4-3.2 Ownership Size	
                                                      B4-3.3 Plant Size 	
                                                      B4-3.4 Geographic Distribution	
                                                      B4-3.5 Cooling Water Characteristics  	
                                                  B4-4 Industry Outlook	
                                                      B4-4.1 Current Status of Industry Deregulation
                                                      B4-4.2 Energy Market Model Forecasts	
                                                  Glossary	
                                                  References 	
. B4-2
. B4-2
. B4-2
. B4-5
. B4-8
. B4-8
. B4-9
B4-10

B4-13
B4-14
B4-15
B4-17
B4-18
B4-19
B4-21
B4-21
B4-22
B4-24
B4-27
INTRODUCTION

This profile compiles and analyzes economic and
operational data for the electric power generating
industry.  It provides information on the structure and
overall performance of the industry and explains
important trends that may influence the nature and
magnitude of economic impacts that could result
from regulation of facilities in Phase III. Based on
the proposed design intake flow threshold-based
options in today's proposed rule, Electric Generators
would not be subject to national categorical
requirements under the proposed Phase III rule.
However, in developing the proposed rule, EPA
analyzed other flow threshold options that would
have subjected Electric Generators to national
requirements. This chapter provides a profile of this
industry, while Chapter B5 provides the economic
impact analysis for this industry, based on the other
threshold options considered - but not proposed - by
EPA.

The electric power industry is one of the most extensively studied industries. The Energy Information
Administration (EIA), among others, publishes a multitude of reports, documents, and studies on an annual basis.
This profile is not intended to duplicate those efforts. Rather, this profile compiles, summarizes, and presents
those industry data that are important in the context of the proposed rule for Phase III existing facilities. For more
information on general concepts, trends, and developments in the electric power industry, the last section of this
profile, "References," presents a select list of other publications on the industry.

The remainder of this profile is organized as follows:

    *•   Section B4-1 provides a brief overview of the industry, including descriptions of major industry sectors,
       types of generating facilities, and the entities that own generating facilities.

    *•   Section B4-2 provides data on  industry production, capacity, and geographic distribution.

    *•   Section B4-3 focuses on electric generating facilities potentially subject to Phase III regulation. This
       section provides  information on the physical, geographic, and ownership characteristics of the potential
       Phase III generators.

    *•   Section B4-4 provides a brief discussion of factors affecting the future of the electric power industry,
       including the status of restructuring, and summarizes forecasts of market conditions through the year
       2025.
                                                                                              B4-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

B4-1   INDUSTRY OVERVIEW

This section provides a brief overview of the electric power industry, including descriptions of major industry
sectors, types of generating facilities, and the entities that own generating facilities.


B4-1.1  Industry Sectors

The electricity business is made up of three major functional service components or sectors: generation,
transmission, and distribution. These terms are defined as follows (Beamon, 1998; Joskow, 1997; U.S. DOE,
2004):!

    *•   The generation sector includes the power plants that produce, or "generate," electricity.2 Electric power
        is usually produced by a mechanically driven rotary generator called a turbine.  Generator drivers, also
        called prime movers, include gas or diesel internal combustion machines, as well as streams of moving
        fluid such as wind, water from a hydroelectric dam, or steam from a boiler. Most boilers are heated by
        direct combustion of fossil or biomass-derived fuels or waste heat from the exhaust of a gas turbine or
        diesel engine, but heat from nuclear, solar, and geothermal sources is also used.  Electric power may also
        be produced without a generator by using electrochemical, thermoelectric, or photovoltaic (solar)
        technologies.

    *•   The transmission sector can be thought of as the interstate highway system of the business - the large,
        high-voltage power lines that deliver electricity from power plants to local areas. Electricity transmission
        involves the "transportation" of electricity from power plants to distribution centers using a complex
        system.  Transmission requires: interconnecting and integrating a number of generating facilities into a
        stable, synchronized, alternating current (AC) network; scheduling and dispatching all connected plants to
        balance the demand and supply of electricity in real time; and managing the system for equipment
        failures, network constraints, and interaction with other transmission networks.

    »•   The distribution sector can be thought of as the local delivery system - the relatively low-voltage power
        lines that bring power to homes and businesses.  Electricity distribution relies on a system of wires and
        transformers along streets and underground to provide electricity to residential, commercial, and
        industrial consumers. The distribution system involves both the provision of the hardware (e.g., lines,
        poles, transformers) and a set of retailing functions, such as metering, billing, and various demand
        management services.

Of the three industry sectors, only electricity generation uses cooling water and is subject to section 316(b)
regulation. The remainder of this profile will focus on the generation sector of the industry.
B4-1.2  Prime Movers

Electric power plants use a variety of prime movers to generate electricity. The type of prime mover used at a
given plant is determined based on the type of load the plant is designed to serve, the availability of fuels, and
energy requirements. Most prime movers use fossil fuels (coal, oil, and natural gas) as an energy source and
employ some type of turbine to produce electricity.  According to the Department of Energy, the most common
prime movers are (U.S. DOE, 2004):
    'Terms highlighted in bold and italic font are defined in the glossary at the end of this chapter.

    2The terms "plant" and "facility" are used interchangeably throughout this profile.

B4-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities     B4: Electric Generator Profile

    *•   Steam Turbine: "Most of the electricity in the United States is produced in steam turbines. In a
        fossil-fueled steam turbine, the fuel is burned in a boiler to produce steam. The resulting steam then turns
        the turbine blades that turn the shaft of the generator to produce electricity. In a nuclear-powered steam
        turbine, the boiler is replaced by a reactor containing a core of nuclear fuel (primarily enriched uranium).
        Heat produced in the reactor by fission of the uranium is used to make steam.  The steam is then passed
        through the turbine generator to produce electricity, as in the fossil-fueled steam turbine. Steam-turbine
        generating units are used primarily to serve the base load of electric utilities.  Fossil-fueled
        steam-turbine  generating units range in size  (nameplate capacity) from 1 megawatt (MW) to more
        than 1,000 megawatts.  The size of nuclear-powered steam-turbine generating units in operation today
        ranges from 75 megawatts to more than 1,400 megawatts."

    *•   Gas Turbine: "In a gas turbine (combustion-turbine) unit, hot gases produced from the combustion of
        natural gas and distillate oil in a high-pressure combustion chamber are passed directly through the
        turbine, which spins the generator to produce electricity. Gas turbines are commonly used to serve the
        peak loads of the electric utility. Gas-turbine units can be installed at a variety of site locations,
        because their size is generally less than 100  megawatts. Gas-turbine units also have a quick startup time,
        compared with steam-turbine units. As a result, gas-turbine units are suitable for peakload, emergency,
        and reserve-power requirements. The gas turbine, as is typical with peaking units, has a lower efficiency
        than the steam turbine used for baseload power."

    *•   Combined-Cycle Unit: "The efficiency of the gas turbine is increased when coupled with a steam
        turbine in a combined-cycle operation. In this operation, hot gases  (which have already been used to spin
        one turbine generator) are moved to a waste-heat recovery steam boiler where the water is heated to
        produce steam that, in turn, produces electricity by running a second steam-turbine generator.  In this
        way, two generators produce electricity from one initial fuel input.  All or part of the heat required to
        produce steam may come from the exhaust of the gas turbine. Thus, the steam-turbine generator may be
        supplementarily fired in addition to the waste heat.  Combined-cycle generating units generally serve
        intermediate loads"

    *•   Internal Combustion Engine: "These prime movers have one or more cylinders in which the
        combustion of fuel takes place.  The engine, which is connected to the shaft of the generator, provides the
        mechanical energy to drive the generator to  produce electricity.  Internal-combustion (or diesel)
        generators can be easily transported, can be  installed upon short notice, and can begin producing
        electricity nearly at the moment they start. Thus,  like gas turbines, they are usually operated during
        periods of high demand for electricity. They are generally about 5 megawatts in size."

    »•   Hydroelectric Generating Unit: "Hydroelectric power is the result of a process in which flowing
        water is used to spin a turbine connected to a generator.  The two basic types of hydroelectric systems are
        those based on falling water and natural river current. In the first system, water accumulates in reservoirs
        created by the use of dams. This water then falls through conduits (penstocks) and applies pressure
        against the turbine blades to drive  the generator to produce electricity. In the second system, called a
        run-of-the-river system, the force of the river current (rather than falling water) applies pressure to the
        turbine blades to produce electricity.  Since  run-of-the-river systems do not usually have reservoirs and
        cannot store substantial quantities  of water, power production from this type of system depends on
        seasonal changes and stream flow. These conventional hydroelectric generating units range in size from
        less than 1 megawatt to 700 megawatts. Because of their ability to  start quickly and make rapid changes
        in power output, hydroelectric generating units are suitable for serving peak  loads and providing spinning
        reserve power, as well as serving baseload requirements. Another kind of hydroelectric power generation
        is the pumped storage hydroelectric system.  Pumped storage hydroelectric plants use the same principle
        for generation of power as the conventional  hydroelectric operations based on falling water and river
        current. However, in a pumped storage operation, low-cost off-peak energy  is used to pump water to an
        upper reservoir where it is stored as potential energy. The water is then released to flow back down
        through the turbine generator to produce electricity during periods of high demand for electricity."
In addition, there are a number of other prime movers:


                                                                                                   B4-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

    *•   Other Prime Movers: "Other methods of electric power generation, which presently contribute only
        small amounts to total power production, have potential for expansion.  These include geothermal, solar,
        wind, and biomass (wood, municipal solid waste, agricultural waste, etc.).  Geothermal power comes
        from heat energy buried beneath the surface of the earth. Although most of this heat is at depths beyond
        current drilling methods, in some areas of the country, magma - the molten matter under the earth's crust
        from which igneous rock is formed by cooling - flows close enough to the surface of the earth to produce
        steam. That steam can then be harnessed for use in conventional steam-turbine plants.  Solar power is
        derived from the energy (both light and heat) of the sun. Photovoltaic conversion generates electric
        power directly from the light of the sun; whereas, solar-thermal electric generators use the heat from the
        sun to produce  steam to drive turbines. Wind power is derived from the conversion of the energy
        contained in wind into  electricity. A wind turbine is similar to a typical wind mill. However, because of
        the intermittent nature of sunlight and wind, high capacity utilization factors cannot be achieved for these
        plants.  Several electric utilities have incorporated wood and waste (for example, municipal waste, corn
        cobs, and oats)  as energy sources for producing electricity at their power plants. These sources replace
        fossil fuels in the boiler. The combustion of wood and waste creates steam that is typically used in
        conventional steam-electric plants."

Section 316(b) regulation is only relevant for electric generators that use cooling water.  However, not all prime
movers require cooling water.  Only prime movers with a steam electric generating cycle use large enough
amounts of cooling water to fall under the scope of the options evaluated for this proposed rule.  This profile will,
therefore, differentiate between steam electric and other prime movers. EPA identified steam electric prime
movers using data collected by the EIA (U.S. DOE, 2001a).3 For this profile, the following prime movers,
including both steam turbines and combined-cycle technologies, are classified as steam electric:

    *•   Steam Turbine, including nuclear, geothermal, and solar steam (not including combined cycle),
    *•   Combined Cycle Steam Part,
    *•   Combined Cycle Combustion Turbine Part,
    *•   Combined Cycle Single Shaft (combustion turbine and steam turbine share a single generator), and
    *•   Combined Cycle Total Unit (used only for plants/generators that are in the planning stage).

Table B4-1 provides data on the number of existing power plants, by prime mover and regulatory status.  This
table includes all plants that have at least one non-retired unit and that submitted Form EIA-860 (Annual Electric
Generator Report) in 2001.  For the purpose of this analysis, plants were classified as "steam turbine" or
"combined-cycle" if they have  at least one generating unit of that type. Plants that do not have any steam electric
units were classified under the prime mover type that accounts for  the largest share of the plant's total generating
capacity.
    3Form EIA-860 (Annual Electric Generator Report) collects data used to create an annual inventory of all
units, plants, and utilities. The data collected includes: type of prime mover; nameplate rating; energy source;
year of initial commercial operation; operating status; cooling water source, and NERC region.
B4-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile


           Table B4-1: Number of Existing Utility and Nonutility Plants by Prime Mover in 2001

"D ' HT

Steam Turbine
Combined-Cycle
Gas Turbine
Internal Combustion
Hydroelectric
Other
Total
Number of Plants
Utility3
635
59
308
557
900
22
2,481
Nonutility3
903
239
426
346
490
134
2,538
Total
1,538
298
734
903
1,390
156
5,019
         a   See definition of utility and nonutility in Section B4-1.3.

         Source:  U.S. DOE, 2001a.
B4-1.3  Ownership

The U.S. electric power industry consists of two broad categories of firms that own and operate electric
generating plants: traditional electric utilities and nontraditional participants.  Generally, they can be defined as
follows (adapted from U.S. DOE, 2003a):

»»»  Traditional electric utilities
Traditional electric utilities are regulated and traditionally vertically integrated entities. They all have distribution
facilities for delivery of electric energy for use primarily by the public, but they may or may not generate
electricity. "Transmission utility" refers to the regulated owner/operator of the transmission system only.
"Distribution utility" refers to the regulated owner/operator of the distribution system serving retail customers.
Electric utilities can be further divided into four major ownership categories: investor-owned utilities, publicly-
owned utilities, rural electric cooperatives, and Federal utilities.  Each category is discussed below (U.S. DOE,
2004).

    *•   Investor-owned utilities (lOUs) are privately owned entities.  Like all private businesses, investor-
        owned electric utilities have the fundamental objective of producing a return for their investors.  These
        utilities  either distribute profits to stockholders as dividends or reinvest the profits.  Investor-owned
        electric utilities are granted service monopolies in certain geographic  areas and are  obliged to serve all
        consumers. As franchised monopolies, these utilities are regulated and required to charge reasonable
        prices, to charge comparable prices to similar classifications of consumers, and to give consumers access
        to services under similar conditions. Most investor-owned electric utilities are operating companies that
        provide  basic services for the generation, transmission, and distribution of electricity. The majority of
        investor-owned utilities perform all three functions. In 2001, lOUs operated 1,148  facilities, which
        accounted for approximately 44% of all U.S. electric generation capacity (U.S. DOE, 2001a).

    *•   Publicly-owned utilities are nonprofit local government agencies established to provide service to their
        communities and nearby consumers at cost. Publicly owned electric utilities include municipalities, State
        authorities, and political subdivisions (e.g., public power districts, irrigation projects, and other State
        agencies established to serve their local municipalities or nearby communities).  Excess funds or "profits"
        from the operation of these utilities are put toward reducing rates, increasing facility efficiency and
        capacity, and funding community programs and local government budgets.  Most municipal utilities are
        nongenerators engaging solely in the purchase of wholesale electricity for resale and distribution. The
        larger municipal utilities, however, generate and transmit electricity as well.  In general, publicly-owned
        utilities  have access to tax-free financing and do not pay certain taxes or dividends, giving them some
        cost advantages over lOUs. In 2001, municipalities operated 785 facilities (4.9% of U.S. capacity), States

                                                                                                       B4-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

        operated 85 facilities (2.1% of U.S. capacity), and political subdivisions operated 103 facilities (2.0% of
        U.S. capacity) (U.S. DOE, 200la).

    *•   Cooperative utilities (or "coops") are member-owned entities created to provide electricity to those
        members.  These utilities, established under the Rural Electrification Act of 1936, operate in rural areas
        with low concentrations of consumers because these areas historically have been viewed as uneconomical
        operations for lOUs. The National Rural Utilities Cooperative Finance Corporation, the Federal
        Financing Bank, and the Bank of Cooperatives are important sources of financing for these utilities.
        Cooperatives operate in 47 States and are incorporated under State laws.  In 2001, rural electric
        cooperatives operated 166 generating facilities and accounted for approximately 3.2% of all U.S. electric
        generation capacity (U.S.  DOE, 2001a).

    *•   Federal electric utilities are part of several agencies in the U.S. Government: the Army Corps of
        Engineers (Department of Defense), the Bureau of Indian Affairs and the Bureau of Reclamation
        (Department of the Interior), the International Boundary and Water Commission (Department of State),
        the Power Marketing Administrations (Department of Energy), and the Tennessee Valley Authority
        (TVA). Three Federal agencies operate generating facilities: TVA, the largest Federal producer; the U.S.
        Army Corps of Engineers; and the U.S. Bureau of Reclamation. In 2001, the ten Federal electric utilities
        operated 194 facilities, accounting for 7.6% of total U.S. electric generation capacity (U.S. DOE, 200 la).

Traditional electric utilities are hereafter referred to as "utilities".

»»»  Nontraditionalparticipants
Nontraditional participants are unregulated entities and include energy service providers, power marketers,
independent power producers (IPPs), and combined heat and power plants (CHPs, formerly referred to as
cogenerators). IPPs own or operate facilities whose primary business is to produce electricity for use by the
public; they are not aligned with distribution facilities. CHPs are plants designed to produce both heat and
electricity from a single  heat source. CHPs can be independent power producers, or industrial or commercial
establishments. In 2001, nontraditional participants operated 2,538 facilities, accounting for 36.1% of total U.S.
electric generation capacity (U.S. DOE, 200la).

Nontraditional participants in the electric power industry are hereafter referred to as "n on utilities".
B4-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
Figure B4-1 presents the number of generating facilities and their capacity in 2001, by type of ownership. The
horizontal axis also presents the percentage of the U.S. total that each type represents. This figure is based on
data for all plants that have at least one non-retired unit and that submitted Form EIA-860 in 2001.  The graphic
shows that nonutilities account for the largest percentage of facilities (2,538, or approximately 51%), but only
represent 36% of total U.S. generating capacity.  Investor-owned utilities operate the second largest number of
facilities, 1,147, and account for 44.1% of total U.S. capacity.
               Figure B4-1: Distribution of Facilities and Capacity by Ownership Type in 2001
/
/
Investor-Owned
Municipality
State
Political Subdivision
Cooperative
Federal
Nonutility



i i i i
	 J 404
l> 1 1/18
^ — •* 44^895 MW
G
£
£
E

/
0.0%
|19,098I\
.
118,012 IV
P 103
]• 29,010
iJ 166
Q69
^ 194
L> '"•'
IW
1W
MW
,402 MW

	 .329
550 MW
	 ^^^^^^^e^^=^^=pi
0
158MW
2,538
/ / ^ / / /


• Capacity
(MW)
DNunberof
Plants


10.0% 20.0% 30.0% 40.0% 50.0% 60.0%
         Source: U.S. DOE, 2001a.
                                                                                                       B4-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
                                  B4: Electric Generator Profile
B4-2   DOMESTIC PRODUCTION

This section presents an overview of U.S. generating capacity and electricity generation. Section B4-2.1 provides
data on capacity, and Section B4-2.2 provides data on generation.  Section B4-2.3 presents an overview of the
geographic distribution of generation plants and capacity.
B4-2.1  Generating Capacity
Utilities own and operate the majority of the
generating capacity (65%) in the United States.
Nonutilities owned only 35% of total capacity
in 2001. Nonutility capacity has increased
substantially in the past few years, as a result of
both new plant construction by independent
power producers and plant divestitures by
investor-owned utilities. Nonutility capacity
has increased 537% between 1991 and 2001,
compared with a decrease in utility capacity of
21% over the same time period (U.S. DOE,
2003a).

Figure B4-2 shows the growth in utility and
nonutility capacity from 1991 to 2001. The
growth  in nonutility capacity, combined with a
decrease in utility capacity, has resulted in a
modest growth in total generating capacity.  The
significant increase in nonutility capacity and
decrease in utility capacity since 1997 is mainly
attributable to utility plants being sold to
nonutilities.
CAPACITY/CAPABILITY

The rating of a generating unit is a measure of its ability to
produce electricity.  Generator ratings are expressed in
megawatts (MW). Capacity and capability are the two common
measures:

Nameplate capacity is the full-load continuous output rating
of the generating unit under specified conditions, as designated
by the manufacturer.

Net capability is the steady hourly output that the generating
unit is expected to supply to the system load, as demonstrated by
test procedures. The capability of the generating unit in the
summer is generally less than in the winter due to high
ambient-air and cooling-water temperatures, which cause
generating units to be less efficient.  The nameplate capacity of a
generating unit is generally greater than its net capability.

                                          U.S. DOE, 2004
Figure B4-2: Net Summer Capacity, 1991 to 2001 (MW)


900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000



	



—


—
s—
__


—



^
_


—


—
^


—


—
=


—


—
<=
_


—

—
^


—

—
<=


—

—
^
_


—

—







—

—
f=2

—





—

—
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001


n Nonutility
• Utility

           Source:  U.S. DOE, 2003a.
B4-,

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
                                    B4: Electric Generator Profile
B4-2.2  Electricity Generation

In 2001, total net electricity generation in the
U.S. was 3,737 million MWh. Utility-owned
plants accounted for 70% of this amount.
Total net generation has increased by 22%
over the 11 year period from  1991 to 2001.
During this period, nonutilities increased
their electricity generation by 345%. In
comparison, generation by utilities decreased
by 7% (U.S. DOE, 2003a).  This trend is
expected to continue with deregulation in the
coming  years, as more facilities are
purchased and built by nonutility power
producers.

Table B4-2 shows the change in net
generation between 1991 and 2001 by energy
source and ownership type.
MEASURES OF GENERATION

The production of electricity is referred to as generation and is
measured in kilowatthours (kWh). Generation can be measured
as:

Gross generation: The total amount of power produced by an
electric power plant.

Net generation: Power available to the transmission system
beyond that needed to operate plant equipment.  For example,
around 7% of electricity generated by steam electric units is used to
operate equipment.

Electricity available to consumers: Power available for sale to
customers. Approximately 8% to 9% of net generation is lost during
the transmission and distribution process.

                                            U.S. DOE, 2004
   Table B4-2: Net Generation by Energy
                        Source and Ownership Type, 1991 to 2001 (million MWh)
Energy
Source
Coal
Nuclear
Natural Gas
Hydropower
Oil
Renewablesa
Other Gases
Otherb
Total
Utilities
1991
1,551
613
264
276
111
10
-
-
2,825
2001
1,560
534
264
190
79
2
-
-
2,630
% Change
0.6%
-12.8%
0.1%
-31.0%
-29.2%
-78.8%
-
-
-6.9%
Nonutilities
1991
39
-
117
9
8
59
11
5
249
2001
344
235
375
18
46
76
9
5
1,107
% Change
771.4%
n/a
219.2%
101.9%
454.7%
29.3%
-20.3%
-1.1%
344.9%
Total
1991
1,591
613
382
284
120
69
11
5
3,074
2001
1,904
769
639
208
125
78
9
5
3,737
% Change
19.7%
25.5%
67.5%
-26.8%
4.3%
13.4%
-20.3%
-1.0%
21.6%
  a   Renewables include solar, wind, wood, biomass, and geothermal energy sources.
  b   Other includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies

  Source:  U.S. DOE, 2003a.
As shown in Table B4-2, natural gas generation grew the fastest among the fuel source categories, increasing by
68% between 1991 and 2001. Nuclear generation increased by 26%, while coal generation increased by 20%.
Generation from renewable energy sources increased 13%. Hydropower, however, experienced a decline of 27%.
For utilities, generation using natural gas and coal as fuel sources was relatively constant.  Generation using other
sources fell, mostly because of sales to nonutilities.  Nonutility generation grew quickly between 1991 and 2001
with the passage of legislation aimed at increasing competition in the industry. Coal generation was the fastest
growing nonutility energy source, increasing 771% between 1991 and 2001. Generation from oil-fired facilities
also increased substantially, by 455%.
                                                                                                     B4-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
Figure B4-3 shows total net generation for the U.S. by primary fuel source, for utilities and nonutilities.
Electricity generation from coal-fired plants accounted for 51% of total 2001 generation. Electric utilities
generated 82% (1,560 billion kWh) of the 1,904 billion kWh of electricity generated by coal-fired plants. This
represents approximately 59% of total utility generation. The remaining 18% (344 billion kWh) of coal-fired
generation were provided by nonutilities, accounting for 31% of total nonutility generation. The second largest
source of electricity generation was nuclear power plants, accounting for 20% total utility generation and 21% of
nonutility generation. Another significant source of electricity generation were gas-fired power plants, which
accounted for 34% of nonutility generation and 17% of total generation.
             Figure B4-3: Percentage of Electricity Generation by Primary Fuel Source in 2001
         Source:  U.S. DOE, 2003a.
The options evaluated for this proposed rule would affect facilities differently based on the fuel sources and prime
movers used to generate electricity. As described in Section B4-1.2 above, only prime movers with a steam
electric generating cycle use substantial amounts of cooling water and are potentially subject to Phase III
regulation.
B4-2.3  Geographic Distribution

Electricity is a commodity that cannot be stored or easily transported over long distances. As a result, the
geographic distribution of power plants is of primary importance to ensure a reliable supply of electricity to all
customers. The U.S. bulk power system is composed of three major networks, or power grids:

    *•   the Eastern Interconnected System, consisting of one third of the U.S., from the East Coast to East of the
        Missouri River;

    *•   the Western Interconnected System, West of the Missouri River, including the Southwest and areas West
        of the Rocky Mountains; and

    *•   the Texas Interconnected System, the smallest of the three, consisting of the majority of Texas.
B4-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

The Texas system is not connected with the other two systems, but the other two have limited interconnection to
each other.  The Eastern and Western systems are integrated with or have links to the Canadian grid system.  The
Western and Texas systems have links with Mexico.

These major networks contain extra-high voltage connections that allow for power transactions from one part of
the network to another.  Wholesale transactions can take place within these networks to reduce power costs,
increase supply options, and ensure system reliability. Reliability refers to the ability of power systems to meet
the demands of consumers at any given time.  Efforts to enhance reliability reduce the chances of power outages.

The North American Electric Reliability Council (NERC) is responsible for the overall reliability, planning, and
coordination of the power grids. This voluntary organization was formed in 1968 by electric utilities, following a
1965 blackout in the Northeast. NERC is organized into ten regional councils that cover the 48 contiguous States,
and affiliated councils that cover Hawaii, part of Alaska, and portions of Canada and Mexico.  These regional
councils are responsible for the overall coordination of bulk power policies that affect their regions' reliability and
quality of service. Each NERC region deals with electricity reliability issues in its region, based on available
capacity and transmission constraints. The councils also aid in the exchange of information among member
utilities in each region and among regions. Service areas of the member utilities determine the boundaries of the
NERC regions. Though limited by the larger bulk power grids described above, NERC regions do not necessarily
follow any  State boundaries.  Historically, almost all wholesale trade was within the NERC regions, but utilities
are expanding wholesale trade beyond those traditional boundaries (U.S. DOE, 2004).

Figure B4-4 below provides a map of the NERC regions, which include:

    *•  ECAR - East Central Area Reliability Coordination Agreement
    *•  ERCOT - Electric Reliability Council of Texas, Inc.
    *•  FRCC - Florida Reliability Coordinating Council
    *•  MAAC - Mid-Atlantic Area Council
    *•  MAIN - Mid-America Interconnected Network, Inc.
    *•  MAPP - Mid-Continent Area Power Pool
    *•  NPCC - Northeast Power Coordinating Council
    *•  SERC - Southeastern Electric Reliability Council
    *•  SPP - Southwest Power Pool, Inc.
    *•  WECC - Western Electricity Coordinating Council (formerly the Western Systems Coordinating
       Council)

Alaska and Hawaii are not shown in Figure  B4-4.  Part of Alaska is covered by the Alaska Systems Coordinating
Council (ASCC), an affiliate NERC member.  The State of Hawaii also has its own reliability authority (HICC).
                                                                                                  B4-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile
                    Figure B4-4: North American Electric Reliability Council (NERC)
                                                 Regions
                                                                        FRCC
                Source:  NERC, 2004.
The options evaluated for Phase III existing facilities may affect plants located in different NERC regions
differently.  Economic characteristics of existing facilities affected by the analyzed options are likely to vary
across regions by fuel mix, and the costs of fuel, transportation, labor, and construction.  Baseline differences in
economic characteristics across regions may influence the impact of an option on profitability, electricity prices,
and other impact measures. However, as discussed in the appendix to Chapter B5: Economic Impact Analysis for
Electric Generators, the three proposed options are estimated to have no impact on electricity prices in each
region since none of the three options requires any power plants to comply with the national categorical
requirements of the proposed rule.

Table B4-3 shows the distribution of all existing plants and capacity by NERC region. The table shows that 1,306
plants, equal to 26% of all facilities in the U.S., are located in the  Western Electric Coordinating Council
(WECC). However, these plants account for only 17% of total national capacity.  Conversely, only 13% of
generating plants are located in the Southeastern Electric Reliability Council (SERC), yet these plants account for
22% of total national capacity.
B4-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
            Table B4-3: Distribution of Existing Plants and Capacity by NERC Region in 2001

NERC Region

ASCC
ECAR
ERCOT
FRCC
fflCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
Total


Number
124
448
215
128
34
246
412
445
718
661
282
1,306
5,019
Plants

% of Total
2.5%
8.9%
4.3%
2.6%
0.7%
4.9%
8.2%
8.9%
14.3%
13.2%
5.6%
26.0%
100%
Capacity

Total MW
2,261
128,301
80,523
45,505
2,452
63,676
70,568
37,410
69,861
204,538
51,743
157,287
914,124


% of Total
0.2%
14.0%
8.8%
5.0%
0.3%
7.0%
7.7%
4.1%
7.6%
22.4%
5.7%
17.2%
100%
 Source:  U.S. DOE, 2001a.
B4-3  POWER PLANTS POTENTIALLY SUBJECT TO PHASE III REGULATION

Section 316(b) of the Clean Water Act applies to point source facilities which use or propose to use a cooling
water intake structure that withdraws cooling water directly from a surface waterbody of the United States.
Among power plants, only those facilities employing a steam electric generating technology require cooling water
and are therefore of interest to this analysis.

The following sections describe power plants that are potentially subject to Phase III regulation. These are
existing, steam electric power generating facilities that meet all of the following conditions:4

    *•  They use a cooling water intake structure or structures, or obtain cooling water by any sort of contract or
       arrangement with an independent supplier who has a cooling water intake structure; or their cooling water
       intake structure(s)  withdraw(s) cooling water from waters of the U.S., and at least twenty-five (25)
       percent of the water withdrawn is used for contact or non-contact cooling purposes;

    »•  they have a National Pollutant Discharge Elimination System (NPDES) permit or are required to obtain
       one; and

    *•  they have a design intake flow (DIP) of 2 million gallons per day (MGD) or greater but were  not covered
       by the final Phase II rule (i.e., their DIP is at least 2 MGD but less than 50 MGD).
    4Existing manufacturing facilities as well as new offshore oil and gas extraction facilities are also potentially
subject to Phase III regulation.  See chapters Al, B2, and C2 for more information on these industries.
                                                                                                  B4-13

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
                              B4: Electric Generator Profile
Phase III regulation also covers substantial additions
or modifications to operations undertaken at such
facilities.  While all electric generators that meet
these criteria are potentially subject to Phase III
regulation, this Economic Analysis (EA) focuses on
113 steam electric power generating facilities
identified in EPA's 2000 Section 316(b) Industry
Survey. These 113 facilities represent 117 facilities
nation-wide.5 The remainder of this chapter will
refer to these potentially regulated facilities as
"potential Phase III Electric Generators."

The following sections present a variety of physical,
geographic, and ownership information about the
potential Phase III Electric Generators.  Topics
discussed include:

    *•   Ownership type: Section B4-3.1 discusses
        potential Phase III Electric Generators with
        respect to the electric utility entities that
        own them (referred to as  "owner-utilities").

    *•   Ownership size: Section  B4-3.2 presents
        information on the size of the ultimate
        parent entities of potential Phase III Electric
        Generators.

    *•  Plant size: Section B4-3.3 discusses the size
        distribution of potential Phase III Electric
        Generators by generation capacity.
WATER USE BY STEAM ELECTRIC POWER
PLANTS

Steam electric generating plants are the single largest
industrial users of water in the United States. In 2000:

   *•  steam electric plants withdrew an estimated 195
      billion gallons per day, accounting for 48% of total
      water withdrawals and 60% of total surface water
      withdrawals in the U.S.;
   >•  steam electric plants accounted for 96% of all saline
      withdrawals in the U.S.;
   *•  steam electric water withdrawals have increased by
      3% between 1995 and 2000;
   *•  surface water accounted for more than 99% of steam
      electric water withdrawals;
   >•  approximately 69% of water intake by the electric
      power industry was from freshwater sources, 31%
      was from saline sources;
   *•  91% of water withdrawal by power plants was used
      in once-through cooling systems; 9% was used in
      closed-loop cooling systems;
   *•  Illinois, Texas, and Tennessee combined accounted
      for 22% of steam electric freshwater withdrawals;
      California and Florida combined accounted for 41%
      of steam electric saline withdrawals;
   >•  the average amount of water used to produce one
      kilowatthour (kWh) decreased from 63 gallons in
      1950 to 21 gallons in 2000.
                                          USGS, 2004
        Geographic distribution: Section B4-3.4
        discusses the distribution of potential Phase III Electric Generators by NERC region.

        Cooling Water Characteristics: Section B4-3.5 presents information on the type of waterbody from
        which potential Phase III Electric Generators draw their cooling water, the type of cooling system they
        operate, and the design intake flow of their cooling water intake structures.
B4-3.1  Ownership Type

The owners and operators of power plants can be divided into two broad ownership categories: traditional utilities
and nonutilities. Utilities can further be classified as investor-owned utilities, publicly-owned utilities
(municipalities, State authorities, and political subdivisions), cooperatives, and Federal electric utilities (see also
Section B4-1.3 above).  This classification is important because EPA has separately considered impacts on
governments in its regulatory development (see Chapter D2: UMRA Analysis for the analysis of government
impacts of the proposed rule).
    5EPA applied sample weights to the 113 facilities to account for non-sampled facilities and facilities that did
not respond to the survey.  For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to
the Information Collection Request (U.S. EPA, 2000).
B4-14

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
Table B4-4 shows the number of owner-utilities,6 plants, and capacity by ownership type. Numbers are presented
for the industry as a whole and the portion of the industry potentially subject to Phase III regulation.  Overall,
2.9% of all owner-utilities, 2.3% of all plants, and 7.5% of all capacity is potentially subject to Phase III
regulation.  The table further shows that most potential Phase III Electric Generators (55) are owned by investor-
owned utilities. An additional 34 potential Phase III Generators are owned by nonutilities. For all ownership
types, less than 6% of all power plants are potentially subject to Phase III regulation. However, the percentage of
capacity potentially subject to Phase III regulation is higher for State-owned power plants and cooperatives (26%
and 20%, respectively) compared to the other ownership types.
                   Table B4-4: Utilities, Plants, and Capacity by Ownership Type in 2001"
Ownership
Type
Investor-Owned
Federal
State
Municipal
Political
Subdivision
Cooperative
Total Utility
Nonutility6
Total
Owner-Utilities"
Total0
467
8
20
532
46
85
858
2,127
2,985
With
Potential
Phase HI
Plants
37
1
3
12
0
8
61
26
87
%With
Potential
Phase HI
Plants
7.9%
12.5%
15.0%
2.3%
0.0%
9.4%
7.1%
1.2%
2.9%
Plants
Total0
1,148
194
85
785
103
166
2,481
2,538
5,019
Potential
Phase
md
55
1
4
13
0
9
83
34
117
%
Potential
Phase HI
4.8%
0.5%
4.7%
1.7%
0.0%
5.4%
3.3%
1.4%
2.3%
Capacity (MW)
Total0
404,158
69,402
19,098
44,895
18,012
29,010
584,574
329,550
914,124
Potential
Phase
md
41,681
2,409
4,946
688
0
5,812
55,537
12,961
68,498
%
Potential
Phase IE
10.3%
3.5%
25.9%
1.5%
0.0%
20.0%
9.5%
3.9%
7.5%
 a   Numbers may not add up to totals due to independent rounding.
 b   Owner-utilities are the direct owners of generating plants. They are not necessarily the ultimate parents of the plants. Numbers
     exclude utilities that engage solely in transmission and distribution.
 c   Information on the total number of owner-utilities is based on data from Form EIA-861 (U.S. DOE, 2001b). Information on plants
     and capacity is based on data from Form EIA-860 (U.S. DOE, 2001a). These two data sources report information for non-
     corresponding sets of power producers.  Therefore, the total number of owner-utilities is not directly comparable to the
     information on total plants or total capacity.
 d   The number of potential Phase III Electric Generators and capacity was sample weighted to account for survey non-respondents.
 e   Total nonutilities from Form EIA-860; Form EIA-861 does not provide information for nonutilities.

 Source:   U.S. DOE, 2001a; U.S. DOE, 2001b; U.S. EPA, 2000; U.S. EPA Analysis, 2004.
B4-3.2 Ownership Size

In developing the proposed rule, EPA conducted an analysis of small entity impacts. The small entity analysis is
conducted at the ultimate parent firm level which, for investor-owned utilities and nonutilities, is often different
from the owner-utility level.  EPA estimates that the 87 owner-utilities with plants potentially subject to Phase III
regulation, presented in Table B4-4 above, are owned by 73 ultimate parent firms.  Of these 73 entities, EPA
    6Owner-utilities are the direct owners of generating plants. They are not necessarily the ultimate parents of
the plants.
                                                                                                          B4-15

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
estimates that 13, or 17.8%, are small.7 The size distribution varies considerably by ownership type: none of the
potential Phase III investor-owned entities are small, compared to 75% of potential Phase III municipalities, 25%
of potential Phase III cooperatives, and 9.5% of potential Phase III nonutilities.  By definition, States and the
Federal government are considered large parent entities.  In general, traditional utility entities that own potential
Phase III Electric Generators are larger than other entities in the industry.  Of the 817 traditional utility parent
entities in the industry, 412 entities, or 50.4%, are small.  In contrast, only 21.2% of potential Phase III traditional
utility entities are small. Overall, EPA estimates that 2.7% of all small utility parent entities own plants that are
potentially subject to Phase III regulation. For nonutilities, the industry-wide number of small entities is not
available.

For a detailed discussion of the identification and size determination of parent entities, see Chapter Dl:
Regulatory Flexibility Analysis.  The chapter also documents how EPA considered the economic impacts on small
entities when developing this regulation.
                 Table B4-5: Existing Parent Entities by Ownership Type and Size in 2001"

Ownership
Type


Investor-Owned
Federal
State
Municipal
Political
Subdivision
Cooperative
Total Utility
Nonutility0
Total
Total



Small
6
-
-
302
37
67
412
n/a
n/a
Number of Parent Entities'



Large
120
8
20
230
9
18
405
n/a
n/a



Total
126
8
20
532
46
85
817
1,718
2,535



% Small
4.8%
0.0%
0.0%
56.8%
80.4%
78.8%
50.4%
n/a
n/a
Total Number of Parent Entities That Own
Potential Phase III ElectricGenerators



Small
-
-
-
9
-
2
11
2
13



Large
28
1
3
34
-
6
41
19
60



Total
28
1
3
12
-
8
52
21
73



% Small
0.0%
0.0%
0.0%
75.0%
0.0%
25.0%
21.2%
9.5%
17.8%
% of Small
Entities That
Own
Potential
Phase HI
Electric
0.0%
0.0%
0.0%
3.0%
0.0%
3.0%
2.7%
n/a
n/a
 a   Numbers may not add up to totals due to independent rounding.
 b   The total number of parent entities that own generation utilities is based on data from Form EIA-861 (U.S. DOE, 2001b). Most of
     the other industry-wide information in this profile is based on data from Form EIA-860 (U.S. DOE, 200la). Since these two forms
     report data for differing sets of facilities, the information in this table is not directly comparable to the other information presented
     in this profile.
 c   Total nonutilities from Form EIA-860; Form EIA-861 does not provide data on nonutilities.

 Source:  U.S. DOE, 2001a; U.S. DOE, 2001b; U.S. EPA Analysis, 2004.



Table B4-6 presents the sample-weighted number of potential  Phase III Electric Generators that are owned by
small entities. The table shows that 14 of the 117 potential Phase III Electric Generators, or 12.2%, are owned by
    7Small entities are defined as: (1) a small business according to the Small Business Administration (SBA) size
standards; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or
special district with a population of less than 50,000; or (3) a small organization that is a not-for-profit enterprise
that is independently owned and operated and is not dominant in its field.
B4-16

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
small entities. Ten of the 14 potential Phase III Generators owned by small entities are municipalities, two are
nonutilities, and two are rural electric cooperatives. There are no potential Phase III investor-owned utilities that
are owned by a small entity. By definition, States and the Federal government are considered large parent
entities.
             Table B4-6: Potential Phase III Power Plants by Ownership Type and Size in 2001

Ownership Type

Investor-Owned
Federal
State
Municipal
Cooperative
Total Utility
Nonutility
Total
Number of Potential Phase III Facilties3

Small
0
0
0
10
2
12
2
14

Large
55
1
4
3
7
71
32
103

Total
55
1
4
13
9
83
34
117

% Small
0.0%
0.0%
0.0%
76.9%
21.2%
14.5%
6.4%
12.2%
      a   The number of potential Phase III Electric Generators was sample weighted to account for survey non-respondents.
          Numbers may not add up to totals due to independent rounding.

      Source: U.S. EPA analysis, 2004.
B4-3.3  Plant Size

EPA also analyzed the potential Phase III Electric Generators with respect to their generating capacity.  The size
of a Generator is important because it partly determines its need for cooling water and its importance in meeting
electricity demand and reliability needs.  Figure B4-5 shows that most potential Phase III Electric Generators have
small generating capacities. Of the 117 potential Phase III facilities, 69 facilities (59%) have a capacity of less
than 500 MW; 23 facilities (20%) have a capacity between 500 MW and 1,000 MW. Only five facilities have a
capacity of greater than 2,000 MW, one of which has capacity of 2,500MW or greater. Of the 69 facilities with
capacities less than 500 MW, 37 have a capacity of less than 100 MW, 17 have a capacity  between 100 and 250
MW, and 15 have a capacity between 250 and 500 MW.
                                                                                                      B4-17

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile
        Figure B4-5: Number of Potential Phase III Electric Generators by Plant Size in 2001a (MW)
                80

                70

                60

                50

                40

                30

                20

                10
                23
                            11
<500
                                 500-1,000     1,000-1,500    1,500-2,000    2,000-2,500     >=2,500
       a   The number of plants was sample weighted to account for survey non-respondents.

       Source:  U.S. DOE, 2001a; U.S. EPA, 2000.


B4-3.4  Geographic Distribution

The geographic distribution of facilities is important because a high concentration of facilities with regulatory
compliance costs could lead to impacts on a regional level.  Everything else being equal, the higher the share of
plants with costs in any one region, the higher the likelihood that there may be economic and/or system reliability
impacts as a result of the regulation.

Table B4-7 shows the distribution of potential Phase III Electric Generators by NERC region. The table shows
that there are only moderate differences between the regions both in terms of the number of potential Phase III
Electric Generators and the percentage of all plants that they represent.  Excluding Alaska and Hawaii, which
have no generators potentially subject to Phase III regulation, the percentage of potential Phase III Electric
Generators in each region ranges from 1% in the Western Electric Coordinating Council (WECC) and Northeast
Power Coordinating Council  (NPCC)  to 5% in the East Central Area Reliability Coordination Agreement
(ECAR).  ECAR also has the highest absolute number of potential Phase III power plants with 22 facilities,
followed by WECC with 18 facilities.
B4-18

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
                           Table B4-7: Existing Plants by NERC Region in 2001
NERC Region
ASCC
ECAR
ERCOT
FRCC
fflCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
Total
Total Number of
Facilities
124
448
215
128
34
246
412
445
718
661
282
1,306
5,019
Potential Phase HI Electric Generators3
Number
-
22
8
4
-
10
6
10
11
17
11
18
117
% of Total in Region
0%
5%
4%
3%
0%
4%
2%
2%
1%
3%
4%
1%
2%
       a   The number of potential Phase III facilities was sample weighted to account for survey non-respondents. Numbers
           may not add up to totals due to independent rounding.

       Source:  U.S. DOE, 2001a; U.S. EPA, 2000.
B4-3.5  Cooling Water Characteristics

The main determinants of the compliance actions potentially required of Phase III Electric Generators include (1)
the waterbody type from which they withdraw cooling water, (2) the type of cooling system they have in place in
the baseline, and (3) the design intake flow of their cooling water intake structure.  Table B4-8 shows that most of
the potential Phase III Electric Generators draw water from a freshwater river or stream (87 plants or 75%).  The
next most frequent waterbody types are lakes or reservoirs (19 plants or 16%) and the Great Lakes (seven plants
or 5%). The table also shows that most of the potential Phase III Electric Generators (86 plants or 74%) employ a
recirculating cooling system.8  Of the four plants that withdraw from an estuary, the most sensitive type of
waterbody, two use a recirculating system. Plants with once-through cooling water systems withdraw between
70% and 98% more water than those with recirculating systems.
    8Once-through cooling systems withdraw water from the water body, run the water through condensers, and
discharge the water after a single use.  Recirculating systems, on the other hand, reuse water withdrawn from the
source.  These systems take new water into the system only to replenish losses from evaporation or other
processes.  Recirculating systems use cooling towers or ponds to cool water before passing it through condensers
again.
                                                                                                     B4-19

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities
B4: Electric Generator Profile
                       Table B4-8: Number of Potential Phase III Electric Generators
                              by Water Body Type and Cooling System Type"

Waterbody Type

Estuary/ Tidal River
Ocean
Lake/ Reservoir
Freshwater River/Stream
Great Lake
Total
Cooling System Type

No.
2
-
14
69
1
86
Recirculating
% of Total
1.8%
0.0%
12.4%
58.9%
0.9%
73.9%

Once-Through
No. % of Total
2
-
4
14
6
26
1.7%
0.0%
3.7%
11.6%
4.8%
21.8%
Combination/Other
No. % of Total
0.0%
0.0%
0.0%
5 4.3%
0.0%
5 4.3%

Total

4
-
19
87
7
117
 a   The number of potential Phase III facilities was sample weighted to account for survey non-respondents. Numbers may not add
     up to totals due to independent rounding.

 Source:  U.S. DOE, 2001a; U.S. EPA, 2000.
Table B4-9 presents the distribution of Electric Generators potentially subject to Phase III regulation by water
body type and design intake flow (DIP) category. Many of the options evaluated by EPA differentiate
compliance requirements based on the facility's DIP.  Table B4-9 shows that more than half of the potential Phase
III Electric Generators (66) have a DIP of less than 20 million gallons per day (MGD).  Fifty-one, or 44%, of the
facilities have a design intake flow of between 20 and 50 million MGD.  None of the potential Phase III Electric
Generators have a flow of 50 MGD or greater because those plants were regulated under the final Phase II rule
(promulgated in July of 2004).
                       Table B4-9: Number of Potential Phase III Electric Generators
                          by Water Body Type and Design Intake Flow Category"

Waterbody Type

Estuary/ Tidal River
Ocean
Lake/ Reservoir
Freshwater River/Stream
Great Lake
Total

Design
< 20 MGD
No.
4
-
12
47
2
66
% of Total
3.5%
0.0%
10.7%
39.9%
2.1%
56.2%
20-
No.
-
-
6
41
4
51
Intake Flow"
50 MGD
% of Total
0.0%
0.0%
5.4%
34.9%
3.5%
43.8%
50+ MGD
No. % of Total
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Total

4
-
19
87
7
117
 a   The number of potential Phase III Electric Generators was sample weighted to account for survey non-respondents. Numbers may
     not add up to totals due to independent rounding.
 b   The three design intake flow (DIF) categories are defined as follows: "< 20 MGD" includes facilities that with a DIF of at least 2
     MGD but less than 20 MGD; "20 - 50 MGD" includes facilities with a DIF of at least 20 MGD but less than 50 MGD; "50+
     MGD" includes facilities with a DIF of at least 50 MGD.

 Source:  U.S. DOE, 2001a; U.S. EPA, 2000.
B4-20

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

B4-4   INDUSTRY OUTLOOK

This section discusses industry trends that are currently affecting the structure of the electric power industry and
may therefore affect the magnitude of impacts from the Proposed Section 316(b) Rule for Phase III Facilities.
The most important change in the electric power industry is deregulation - the transition from a highly regulated
monopolistic industry to a less regulated, more competitive industry.  Section B4-4.1 discusses the current status
of deregulation.  Section B4-4.2 presents a summary of forecasts from the Annual Energy Outlook 2003.


B4-4.1  Current Status of Industry Deregulation

The electric power industry is evolving from a highly regulated, monopolistic industry with traditionally-
structured electric utilities  to a less  regulated, more competitive industry.9 The industry has traditionally been
regulated based on the premise that the supply of electricity is a natural monopoly, where a single supplier could
provide electric services at a lower  total cost than could be provided by several competing suppliers.  Today, the
relationship between electricity consumers and suppliers is undergoing substantial change.  Some States have
implemented plans that will change the procurement and pricing of electricity significantly, and many more plan
to do so during the first few years of the 21st century (Beamon, 1998).

a.   Key changes in the industry's structure
Industry deregulation already has changed  and continues to fundamentally change the structure of the electric
power industry.  Some of the key changes include:

    *•  Provision of services: Under the traditional regulatory system, the generation, transmission, and
        distribution of electric power were handled by vertically-integrated utilities. Since the mid-1990s,
        Federal and State policies have led to increased competition in the generation sector of the industry.
        Increased competition has resulted in a separation of power generation, transmission, and retail
        distribution services. Utilities that provide transmission and distribution services will continue to be
        regulated and will be required to divest of their generation assets. Entities that generate electricity will no
        longer be subject to geographic or rate regulation.

    *•  Relationship between electricity providers and consumers: Under traditional regulation, utilities were
        granted a geographic franchise area and provided electric service to all customers in that  area at a rate
        approved by the regulatory commission. A consumer's electric supply choice was  limited to the utility
        franchised to serve their area.  Similarly, electricity suppliers were not free to pursue customers outside
        their designated service territories. Although most consumers will continue to receive power through their
        local distribution company (LDC), retail competition will allow them to select the company that generates
        the electricity they purchase.

    *•   Electricity prices: Under the traditional system, State and Federal authorities regulated all aspects of
        utilities' business operations, including their prices.  Electricity prices were determined administratively
        for each utility, based on the average cost of producing and delivering power to customers and a
        reasonable rate of return. As a result of deregulation, competitive market forces will set generation prices.
        Buyers and sellers of power will negotiate through power pools or one-on-one to set the price of
        electricity. As in all competitive markets,  prices will reflect the interaction of supply and demand for
        electricity. During most time periods, the  price of electricity will be  set by the generating unit with the
    9Several key pieces of Federal legislation have made the changes in the industry's structure possible.  The
Public Utility Regulatory Policies Act (PURPA) of 1978 opened up competition in the generation market
by creating a class of nonutility electricity-generating companies referred to as "qualifying facilities." The
Energy Policy Act (EPACT) of 1992 removed constraints on ownership of electric generation facilities, and
encouraged increased competition in the wholesale electric power business (Beamon, 1998).
                                                                                                    B4-21

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

       highest operating costs needed to meet spot market generation demand (i.e., the "marginal cost" of
       production) (Beamon, 1998).

b.   New industry participants
The Energy Policy Act of 1992 (EPACT) provides for open access to transmission systems, to allow nonutility
generators to enter the wholesale market more easily. In response to these requirements, utilities are proposing to
form Independent System Operators (ISOs) to operate the transmission grid, regional transmission groups, and
open access same-time information systems (OASIS) to inform competitors of available capacity on their
transmission systems.  The advent of open transmission access has fostered the development of power
marketers and power brokers as new participants in the electric power industry.  Power marketers buy and
sell wholesale electricity and fall under the jurisdiction of the Federal Energy Regulatory Commission (FERC),
since they take ownership of electricity and are engaged in interstate trade. Power marketers generally do not
own generation or transmission facilities or sell power to retail customers. A growing number of power marketers
have filed with the FERC and have had rates approved. Power brokers, on the other hand, arrange the sale and
purchase of electric energy, transmission, and other services between buyers and sellers, but do not take title to
any of the power sold.

c.   State activities
Many States have taken steps to promote competition in their electricity markets.  The status of these efforts
varies across States. Some States are just beginning to study what a competitive electricity market might mean;
others are beginning pilot programs; still others have designed restructured electricity markets and passed
enabling legislation. However, the difficult transition to a competitive electricity market in California,
characterized by price spikes and rolling black-outs in 2000, has affected restructuring in that State and several
others. Since those difficulties, five States (Arkansas, Montana, Nevada, New Mexico, and Oklahoma) have
delayed the restructuring process pending further review of the issues while California has suspended direct retail
access. As of February 2003, eighteen States had operating competitive retail electricity markets.  Oregon did not
have customers participating in the retail program, but nonresidential customers were allowed access (U.S. DOE,
2003b).

Even in States where consumer choice is available, important aspects of implementation may still be undecided.
Key aspects of implementing restructuring include treatment of Stranded costs, pricing  of transmission and
distribution services, and the design market structures required to ensure that the benefits of competition flow to
all consumers (Beamon, 1998).
B4-4.2 Energy Market Model Forecasts

This section discusses forecasts of electric energy supply, demand, and prices based on data and modeling by the
Energy Information Administration (EIA) and presented in the Annual Energy Outlook 2003 (U.S. DOE, 2003c).
The EIA models future market conditions through the year 2025, based on a range of assumptions regarding
overall economic growth, global fuel prices, and legislation and regulations affecting energy markets. The
projections are based on the results from EIA's National Energy Modeling System (NEMS) using assumptions
reflecting economic conditions as of November 2002. EPA used ICF Consulting's Integrated Planning Model
(IPM®), an integrated energy market model, to conduct the economic analyses supporting the Phase III
rulemaking effort (see appendix to Chapter B5: Economic Impact Analysis for Electric Generators}. The IPM
generates baseline and post compliance estimates of each of the measures discussed below.  For purposes of
comparison, this section presents a discussion of EIA's reference case results.

a.  Electricity demand
The AEO2003 projects electricity demand to grow by approximately 1.8% annually between 2000 and 2025.
This growth is driven by an  estimated 2.2% annual increase in the demand for electricity from the commercial
sector associated with a projected annual  growth in commercial floor space of 1.6%. EIA expects electricity
demand from the industrial sector to increase by 1.7% annually, largely in response to an increase in industrial
B4-22

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

output of 2.6% per year. Residential demand is expected to increase by 1.6% annually over the same forecast
period, due mostly to an increase in the number of U.S. households of 1.0% per year between 2000 and 2025.

b.   Capacity retirements
The AEO2003 projects total fossil fuel-fired generation capacity to decline due to retirements. EIA forecasts that
total fossil-steam capacity will decrease by an estimated 12% (or 78 gigawatts) between 2000 and 2025, including
56 gigawatts of oil and natural gas fired steam capacity.  EIA estimates total nuclear capacity to decline by an
estimated 3% (or 3 gigawatts) between 2000 and 2025 due to nuclear power plant retirement. These closures are
primarily assumed to be the result of the high costs of maintaining the performance of nuclear units compared
with the cost of constructing the least cost alternative.

c.   Capacity additions
Additional generation capacity will be needed to meet the estimated growth in electricity demand and offset the
retirement of existing capacity. EIA expects utilities to employ other options such as life extensions and
repowering, power imports from Canada and Mexico, and purchases from cogenerators before building new
capacity. EIA forecasts that utilities will choose technologies for new generation capacity that seek to minimize
cost while meeting environmental and emission constraints.  Of the new capacity forecasted to come on-line
between 2000 and 2025, approximately 80% is projected to be combined-cycle technology or combustion turbine
technology, including distributed generation capacity. This additional capacity is expected to be fueled by natural
gas and to supply primarily peak and intermediate capacity.  Approximately 17% of the additional capacity
forecasted to come on line between 2000 and 2025 is expected to be provided by new coal-fired plants, while the
remaining 3% is forecasted to come from renewable technologies.

d.   Electricity generation
The AEO2003 projects increased electricity generation from both natural gas and coal-fired plants to meet
growing demand and to offset lost capacity due to plant retirements.  The forecast projects that coal-fired plants
will remain the largest source of generation throughout the forecast period. Although coal-fired generation is
predicted to increase steadily between 2000 and 2025, its share of total generation is expected to decrease from
53% to an estimated 50%.  This decrease in the share of coal generation is in favor of less capital-intensive and
more efficient natural gas generation technologies. The share of total generation associated with gas-fired
technologies is projected to increase from approximately 14% in 2000 to an estimated 27% in 2025,  replacing
nuclear power as the second largest source  of electricity generation.  Generation from oil-fired plants is expected
to remain fairly small throughout the forecast period.

e.   Electricity prices
EIA expects the average real price of electricity, as well as the price paid by customers in each sector (residential,
commercial, and industrial), to decrease between 2000 and 2008 as a result of competition among electricity
suppliers, excess generating capacity, and a decline in coal prices.  However, by 2025, EIA predicts that the
average real price of electricity will return to 2000 levels as a result of rising natural gas costs and electricity
demand growth.
                                                                                                   B4-23

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

GLOSSARY

Definitions are adapted from the following sources:

U.S. Department of Energy's Electric Power Industry Overview.
At: http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html

U.S. Department of Energy's International Energy Annual 2002 - Glossary.
At: http://www.eia.doe.gov/emeu/iea/glossary.html#W

U.S. Department of Energy's Electric Power Annual Volume I - Glossary of Electricity Terms.
At: http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html

Base Load: A baseload generating unit is normally used to satisfy all or part of the minimum or base load of the
system and, as a consequence, produces electricity at an essentially constant rate and runs continuously.  Baseload
units are generally the newest, largest, and most efficient of the three types of units (i.e., base load, intermediate
load, and peak load units).

Combined-Cycle Unit: An electric generating technology in which electricity is produced from otherwise lost
waste heat exiting from one or more gas (combustion) turbines.  The exiting heat is routed to a conventional
boiler or to heat recovery steam generator for utilization by a steam turbine in the production of electricity. This
process increases the efficiency of the electric generating unit.

Distribution: The delivery of electricity to retail customers (including homes, businesses, etc.).

Electricity Available to Consumers: Power available for sale to customers. Approximately 8% to 9% of net
generation is lost during the transmission and distribution process.

Energy Policy Act (EPACT): In 1992 the EPACT removed constraints on ownership of electric generation
facilities and encouraged increased competition in the wholesale electric power business.

Gas Turbine: A gas turbine typically consisting of an axial-flow air compressor and one or more combustion
chambers, where liquid or gaseous fuel is burned and the hot gases are passed to the turbine.  The hot gases
expand to drive the generator and are then used to run the compressor.

Generation: The process of producing electric energy by transforming other forms of energy. Generation is
also the amount of electric energy produced, expressed in watthours (Wh).

Gross Generation: The total amount of electric energy  produced by the generating units at a generating station
or stations, measured at the generator terminals.

Hydroelectric Generating Unit: A unit in which the turbine generator is driven by falling water or natural
river current.

Intermediate load: Intermediate-load generating units meet system requirements that are greater than base load
but less than peak load. Intermediate-load units are used during the transition between base load and peak load
requirements.

Internal Combustion  Engine: An internal combustion engine has one or more cylinders in which the process
of combustion takes place, converting energy released from the rapid burning of a fuel-air mixture into
mechanical energy.  Diesel or gas-fired engines are the principal fuel types used in these generators.

Kilowatthours (kWh): One thousand watthours (Wh)
B4-24

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

Megawatt (MW): One million watts.

Nameplate Capacity: The amount of electric power delivered or required for which a generator, turbine,
transformer, transmission circuit, station, or system is rated by the manufacturer. Nameplate capacity is expressed
in watts or megawatts (MW).

Net Capability: The steady hourly output that the generating unit is expected to supply to the system load, as
demonstrated by test procedures. The capability of the generating unit in the summer is generally less than in the
winter due to high ambient-air and cooling water temperatures, which cause generating units to be  less efficient.
The nameplate capacity of a generating unit is generally greater than its net capability.

Net Generation: Gross generation minus plant use from all plants owned by the same utility.

Nonutility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns electric
generating capacity and is not an electric utility. Nonutility power producers include qualifying cogenerators,
qualifying small power producers, and other nonutility generators (including independent power producers)
without a designated franchised service area that do not file forms listed in the Code of Federal Regulations, Title
18, Part 141.

Other Prime Movers: Methods of power generation other than steam turbines, combined-cycle units,
gas combustion turbines, internal combustion engines, and hydroelectric generating units  Other
prime movers include: geothermal, solar, wind, and biomass.

Peak load: A peakload generating unit, normally the least efficient of the three unit types (i.e., base load,
intermediate load, and peak load units), is used to meet requirements during the periods of greatest, or peak, load
on the system.

Power Marketers: Business entities engaged in buying, selling, and marketing electricity. Power marketers do
not usually own generating or transmission facilities.  Power marketers, as opposed to brokers, take ownership of
the electricity and are involved in interstate trade. These entities file with the Federal Energy Regulatory
Commission for status as a power marketer.

Power Brokers: An entity that arranges the sale and purchase of electric energy, transmission, and other
services between buyers and sellers, but does not take title to any of the power sold.

Prime Movers: The engine, turbine, water wheel, or similar machine that drives an electric generator. Also, for
reporting purposes, a device that directly converts energy to electricity, e.g., photovoltaic, solar, and fuel cell(s).

Public Utility Regulatory Policies Act (PURPA): In 1978 PURPA opened up competition in the electricity
generation market by creating a class of nonutility electricity-generating companies referred to as "qualifying
facilities."

Reliability: Electric system reliability has two components: adequacy and security. Adequacy is the ability of
the electric system to supply customers at all times, taking into account scheduled and unscheduled outages of
system facilities. Security is the ability of the electric system to withstand sudden disturbances, such as electric
short circuits or unanticipated loss of system facilities.

Steam Turbine: A generating unit in which the prime mover is a steam turbine. The turbines convert thermal
energy (steam or hot water) produced by generators or boilers to mechanical energy or shaft torque. This
mechanical energy is used to power electric generators, including combined-cycle electric generating units, that
convert the mechanical energy to electricity.

Stranded Costs: Prudent costs incurred by  a utility that may not be recoverable under market based retail
competition. Examples are undepreciated generating facilities, deferred costs, and long-term contract costs.


                                                                                                 B4-25

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile

Transmission: The movement or transfer of electric energy over an interconnected group of lines and
associated equipment between points of supply and points at which it is transformed for delivery to consumers, or
is delivered to other electric systems. Transmission is considered to end when the energy is transformed for
distribution to the consumer.

Utility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or
operates facilities within the United States, its territories, or Puerto Rico for the generation, transmission,
distribution, or sale of electric energy primarily for use by the public and files forms listed in the Code of Federal
Regulations, Title 18, Part 141.  Facilities that qualify as cogenerators or small power producers under the Public
Utility Regulatory Policies Act (PURPA) are not considered electric utilities.

Watt: The electrical unit of power. The rate of energy transfer equivalent to one ampere flowing under the
pressure of one volt at unity power factor.

Watthour (Wh): An electrical energy unit of measure equal to one watt of power supplied to, or taken from, an
electric circuit steadily for one hour.
B4-26

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities     B4: Electric Generator Profile

REFERENCES

Beamon, J. Alan.  1998.  Competitive Electricity Prices: An Update.
At: http://www.eia.doe.gov/oiaf/archive/issues98/cep.html.

Joskow, Paul L.  1997. "Restructuring, Competition and Regulatory Reform in the U.S. Electricity Sector,"
Journal of Economic Perspectives, Volume 11, Number 3  - Summer 1997 - Pages 119-138.

North American Electric Reliability Council (NERC). At: http://www.nerc.com/regional/. Accessed May 20,
2004.

U.S. Department of Energy (U.S. DOE). 2004. Energy Information Administration (EIA). Electric Power
Industry Overview. At: http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html. Accessed March 30,
2004.

U.S. Department of Energy (U.S. DOE). 2003a. Energy Information Administration (EIA). Electric Power
Annual 2002.  At: http://www.eia.doe.gov/cneaf/electricity/epa/epa.pdf

U.S. Department of Energy (U.S. DOE). 2003b. Energy Information Administration (EIA). Status of State
Electric Industry Restructuring Activity as of February 2003.
At: http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html.

U.S. Department of Energy (U.S. DOE). 2003c. Energy Information Administration (EIA). Annual Energy
Outlook2003.  At: http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2003).pdf

U.S. Department of Energy (U.S. DOE). 2001a. Energy Information Administration (EIA). Form EIA-860
(2001).  Annual Electric  Generator Report.

U.S. Department of Energy (U.S. DOE). 200 Ib. Energy Information Administration (EIA). Form EIA-861
(2001).  Annual Electric  Utility Data.

U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II  Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II
Cooling Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener
Questionnaire: Phase I Cooling  Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).

U.S. Geological Survey (USGS). 2004.  Estimated Use of Water in the United States in 2000.
At: http://water.usgs.gov/watuse/. Accessed March 31, 2004.
                                                                                                 B4-27

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Phase III Existing Facilities      B4: Electric Generator Profile
                            THIS PAGE INTENTIONALLY LEFT BLANK
B4-28

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities         B5: Impact Analysis for Generators

  Chapter B5:  Economic Impact  Analysis for
                            Electric Generators
INTRODUCTION                                  „          „
                                                  CHAPTER CONTENTS
rr,  ,   •   -.in   /TATT-\   i-  i  -1-j- .ti   i  u      B5-1 Estimation of Private Compliance Costs	B5-1
The design intake flow (DIP) applicability thresholds                             F
for national categorical requirements for the three
proposed options for existing facilities are 50 MOD,
100 MOD, and 200 MOD, respectively.  Since
Electric Generators with a DIP of 50 MGD or greater
were covered by the final Phase II rule, no Electric
Generator would be subject to the national categorical
requirements under any of the three proposed options;
                                                      B5-1.1 Methodology	B5-1
                                                      B5-1.2 Summary Cost Statistics	B5-4
                                                  B5-2 Summary of Electricity Market Model
                                                         Analysis	B5-7
                                                  B5-3 Additional Impact Analyses  	B5-7
                                                      B5-3.1 Cost-to-Revenue Analysis  	B5-8
                                                      B5-3.2 Cost per Household Analysis  	B5-9
                                                      B5-3.3 Electricity Price Analysis	B5-11
                                                  B5-4 Uncertainties and Limitations	B5-13
                                                  References 	B5-15
                                                  Appendix 1 to Chapter B5 	 B5A-1
therefore there would be no compliance costs and no
direct impacts on any Electric Generators, nor any        References  	B5-15
indirect impacts on the Electric Generating Industry
as a result of the proposed rule.  However, Electric
Generators would be regulated and incur compliance
costs under several other options that were analyzed but ultimately not proposed by EPA.  This chapter assesses
the expected economic effect on Electric Generators of these other options.  This chapter (1) describes the
methodology used to estimate the private cost to Electric Generators potentially subject to Phase III regulation
and presents summary cost statistics; (2) summarizes EPA's electricity market model analysis for Electric
Generators potentially subject to Phase III regulation and the electric power industry as a whole; and (3) presents
an additional assessment of the magnitude of compliance costs to Electric Generators, including a cost-to-revenue
analysis at the facility and firm levels, an analysis of compliance costs per household at the North American
Electric Reliability Council (NERC) level, and an analysis of compliance costs relative to  electricity price
projections, also at the NERC level. The appendix to this chapter presents the detailed methodology and results
of EPA's electricity market model analysis.
B5-1  ESTIMATION OF PRIVATE COMPLIANCE COSTS

This section summarizes EPA's analysis of private compliance costs that would be incurred by Electric
Generators under various regulatory options that were considered but not proposed by EPA.  The first subsection
presents methodological components of estimating private costs that are unique to Electric Generators. For
information on cost categories and cost methodologies that are common to all industry segments analyzed in
developing the proposed requirements for Phase III existing facilities, please see Chapter Bl: Summary of Cost
Categories and Key Analysis Elements for Existing Facilities.  The second subsection presents  summary cost
statistics for each analyzed option, including facility counts and compliance costs by cost category.

B5-1.1 Methodology

a.   Development of Present Value and Annualized Costs
The estimation of compliance costs incurred by Electric Generators potentially subject to Phase III regulation
starts with facility-level compliance cost estimates for each model facility developed in EPA's  engineering
analysis.  EPA included the following compliance cost categories in this analysis: capital cost, annual operating
and maintenance cost, administrative cost, and the loss of business income from potential shutdown of facilities
during installation of compliance equipment. Of these cost categories, only operating and maintenance costs and
certain administrative costs recur annually. The remaining costs occur only once at the beginning of compliance
or in multi-year intervals over the period of the compliance analysis. Some  of the impact analyses require
                                                                                             B5-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities          B5: Impact Analysis for Generators

combining the annually recurring and non-recurring costs into a single, annual equivalent value. For combining
the annually recurring and non-recurring costs in this analysis, EPA calculated the annual equivalent cost of the
non-recurring cost categories and added these annualized costs to the annually recurring operating and
maintenance cost.

To derive the constant annual value of the non-annual costs, EPA calculated the present value as of the first year
of compliance of each facility (for this analysis, assumed to be 2010 to 2014) and then annualized it, using a 7.0%
pre-tax discount rate in both steps. The costs of compliance equipment were annualized over 10 years; initial
permitting cost and the income loss from installation shutdown were annualized over 30 years; and repermitting
costs were annualized over 5 years. EPA then added these annualized costs to annual O&M and administrative
costs to derive each facility's total annual pre-tax cost of complying with each evaluated option.

For more information on the compliance cost components developed for this analysis and EPA's methodology of
discounting, see Chapter B1 and the Technical Development Document for the Proposed Section 316(b) Rule for
Phase III Facilities (TDD; U.S. EPA, 2004b).

b.  Consideration of taxes
For understanding the economic impact of a regulation on facilities, the costs incurred by complying facilities are
adjusted for taxes and calculated on an after-tax basis.  The tax treatment of compliance outlays and income
effects shifts part of these costs to the tax-paying public and reduces the actual cost to private, tax-paying
businesses. For this reason, the after-tax costs of compliance are a more meaningful measure of the financial
burden on complying facilities than the pre-tax costs.  In analyzing and reporting the impact of compliance costs
on private facilities, annualized costs are therefore calculated on an after-tax basis.

EPA used combined Federal and State tax rates, specific to the State of each facility, to estimate the annual after-
tax cost of compliance.  The total effective tax rate was calculated as follows:

          Total Tax Rate  =  State Tax Rate +  Federal Tax Rate  - (State Tax Rate *  Federal Tax  Rate)

The amount by which a facility's annual tax liability would be reduced is the annualized compliance cost of the
rule multiplied by the total tax rate.1  A reduction in tax liability was only applied to privately-owned facilities
subject to income taxes, i.e., costs incurred by government-owned facilities and cooperatives are not adjusted for
taxes, since these facilities are not subject to income taxes.

c.  Monetary valuation of installation downtime
Installation of some of the compliance technologies considered for potential Phase III Electric Generators would
require a one-time, temporary downtime of the  facility's cooling water intake system. During the downtime
period, the facility's cooling-water dependent operations would most likely be halted, with a potential loss of
revenue and income from those operations. Accordingly, a key element of the cost to facilities in complying with
the proposed standards for Phase III existing facilities is the loss in income from installation downtime.  In the
facility impact analyses for Electric Generators, this loss in income is accounted for as a loss in revenue offset by
a reduction in variable costs in the affected business operations.

For the Electric Generating industry, EPA estimated facility-specific baseline revenue losses using 2008 revenue
projections from the Integrated Planning Model (IPM®; U.S. EPA, 2002; U.S. EPA, 2003). IPM® revenues
consist of energy revenues and capacity revenues (see discussion of the  IPM® in the appendix to this chapter).
One-time losses due to installation downtime were calculated by dividing each facility's annual revenue
    1 This calculation is a conservative approximation of the actual tax effect of the compliance costs. For capital costs, it assumes that
the total annualized cost, which includes imputed interest and principal charge components, is subject to a tax benefit.  In effect, the
schedule of principal charges over time in the annualized cost value is treated, for tax purposes, as though it were the depreciation schedule
over time.  In fact, the actual tax depreciation schedule that would be available to a company would be accelerated in comparison to the
principal charge schedule embedded in the annualized cost calculation. As a result, explicit accounting for the deprecation schedule would
yield a slightly higher present value of tax benefits than is reflected in the analysis presented here.
B5-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities          B5: Impact Analysis for Generators

projections by 52 weeks and multiplying this value by the estimated average downtime (in weeks) of the facility's
compliance technology.

EPA also used IPM® estimates to calculate avoided variable production costs during the downtime, again using
facility-specific 2008 projections from the IPM®. Variable production costs include both fuel and other variable
operating and maintenance costs. Similar to revenues, each  facility's annual variable production costs were
divided by 52 weeks and multiplied by the facility's estimated average downtime (in weeks).

The average cost of the technology installation downtime is  the revenue loss during the downtime less the
variable expenses that would normally be incurred during that period. The following formulas were used to
calculate the net loss due to downtime for electric generators:

                Cost of Installation Downtime  =  Revenue Loss  -  Variable Production Costs

where

               Variable Production Cost  =  Fuel Cost +   Variable Operating/Maintenance Cost

This approach may overstate the cost of the installation  downtime because it is based on average annual revenues
and average variable production costs. If downtime is scheduled during off-peak times, the loss in revenues could
be smaller as a result of lower electricity sales and electricity prices.

d.   Converting monetary values to current year dollar values
The various economic information used in the cost and impact analyses for potential Phase III Electric Generators
were initially estimated in dollars of different years. To ensure consistent analyses and to present the estimated
cost of regulatory compliance in approximately current  values, EPA adjusted all dollar values to constant dollars
of the year 2003 (average or mid-year, depending on availability) using an appropriate inflation adjustment index.
For adjusting compliance costs, EPA used the Construction Cost Index fCCI) published by the Engineering
News-Record (ENR, 2004; see Chapter Bl for index values  used in this analysis).

The economic analysis for Electric Generators also uses revenue, cost, and electricity price data from the IPM®
and electricity price data from the Annual Energy Outlook 2003 (U.S. DOE, 2003) and the Energy Information
Administration's Form EIA-861 (U.S. DOE, 2001).  These values were adjusted to year 2003 values using the
Commodity Producer Price Index (PPI) for Industrial Electric Power (U.S. DOL, 2004).  Table B5-1 below
presents the PPI values used in this analysis.
Table B5-1: PPI
Year
1997
1998
1999
2000
2001
2002
2003
Series for Industrial
Value
130.8
130.0
128.9
131.5
141.1
139.9
145.8
Electric Power
% Change

-0.6%
-0.8%
2.0%
7.3%
-0.9%
4.2%
Source: U.S. DOL, 2004.
                                                                                                   B5-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
B5-1.2 Summary Cost Statistics

a.  Number of facilities with regulatory requirements
In conducting the economic impact analyses for Electric Generators, EPA first eliminated from the analysis those
facilities estimated to be in severe financial distress independent of Phase III regulation. EPA judges these
facilities, which are referred to as "baseline closures," to be at substantial risk of financial failure regardless of any
additional financial burden that might result from the proposed rule or any of the other evaluated options. EPA
identified three of the  117 potentially regulated Electric Generators as baseline closures.  The identification of
baseline closures is based on EPA's IPM® analyses.  The IPM® considers a generator as a closure if the net
present value of future operation is negative (see the appendix to this chapter).

After setting aside baseline closures, EPA determined which facilities would be subject to the national categorical
requirements under each evaluated option.  Facilities that do not meet the design intake flow (DIF)/source
waterbody threshold for an option would be subject to permitting based on best professional judgment (BPJ).
These facilities do not incur incremental costs under this rule and are therefore excluded from EPA's cost and
economic impact analyses.

Table B5-2 below presents, for each evaluated option, the DIP applicability threshold, the number of Electric
Generators potentially subject to Phase III regulation, the number of baseline closures, the number of Electric
Generators subject to best professional judgment, and, by DIP Category, the number of Electric Generators
subject to the national requirements.

                   Table B5-2: Phase III Electric Generator Counts for Evaluated Options

50 MGD All
(proposed)
200 MGD All
(proposed)
100 MGD Cert.
(proposed)3
Option 3
Option 4b
Option 2
Option 1
Option 6
DIP
Applicability
Threshold
50 MGD
200 MGD
100 MGD (C)
BPJ (0)
20 MGD
20 MGD (C)
50 MGD (O)
20 MGD
20 MGD
2 MGD
Potentially
Subject to
Regulation
117
117
117
117
117
117
117
117
Baseline
Closures
3
3
3
3
3
3
3
3
Subject to
Best
Professional
Judgment
114
114
114
63
110
63
63
-
Subject to National Requirements
DIP Category
2-20 MGD 20-50 MGD 50+ MGD
-
-
-
51 - 51
4 - 4
51 - 51
51 - 51
114 63 51
 a   The applicability threshold for the "100 MGD for Certain Waterbodies" option is 100 MGD for facilities withdrawing from certain
     waterbodies (estuaries/tidal rivers and oceans) and the Great Lakes. Facilities withdrawing from other waterbodies (freshwater
     rivers, and lakes/reservoirs) are subject to best professional judgment.
 b   The applicability threshold for Option 4 is 20 MGD for facilities withdrawing from certain waterbodies (estuaries/tidal rivers and
     oceans) and the Great Lakes and 50 MGD for facilities withdrawing from other waterbodies (freshwater rivers, and
     lakes/reservoirs).

 Source:  U.S. EPA, 2000.
B5-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
b.  Distribution of Electric Generators by NERC region and compliance year
Table B5-3 presents the distribution of the existing Electric Generators potentially subject to Phase III regulation
(excluding baseline closures) by North American Electric Reliability Council (NERC) region and compliance
year.2 The NERC regions presented in the table are:

    •>  ASCC - Alaska
    *•  ECAR - East Central Area Reliability Coordination Agreement
    *•  ERCOT - Electric Reliability  Council of Texas
    *•  FRCC - Florida Reliability Coordinating Council
    *•  HI - Hawaii
    *•  MAAC - Mid-Atlantic Area Council
    *•  MAIN - Mid-America Interconnect Network
    *•  MAPP - Mid-Continent Area  Power Pool
    *•  NPCC - Northeast Power Coordinating Council
    *•  SERC - Southeastern Electric Reliability Council
    *•  SPP - Southwest Power Pool
    *•  WECC - Western Electricity Coordinating Council

                 Table B5-3: Weighted Number of Phase III Electric Generating Facilities
                                 by NERC Region and Compliance Year"
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
Total
2010
-
4
2
4
-
3
-
1
3
10
1
6
35
2011
-
2
-
-
-
4
1
1
1
2
2
2
15
2012
-
4
2
-
-
1
1
4
1
-
4
4
22
2013
-
4
3
-
-
-
3
3
2
-
3
3
21
2014
-
7
1
-
-
1
1
1
3
3
1
1
20
Total
-
22
8
4
-
10
6
10
11
16
11
16
114
    a   Note that compliance years were estimated for this analysis. Actual compliance years might be different than stated in this
        table. Numbers only include facilities estimated to operate in the baseline.

    Source:  U.S. EPA Analysis, 2004.
c.   Summary of compliance requirements
Table B5-4 shows estimated compliance requirements for each evaluated option, based on the performance
standard each Electric Generator would need to meet (depending on each Generator's waterbody type, design
intake flow, capacity utilization, and annual intake flow as a percent of source waterbody mean annual flow) and
its baseline technologies in-place.
    2 For a detailed discussion of the NERC regions, see the appendix to this chapter. For a description of how EPA determined
compliance years, see Chapter Bl, Section B 1-2.1 (Compliance Schedule).
                                                                                                     B5-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
                  Table B5-4: Number of Electric Generators by Compliance Requirement
Facility Compliance Requirement
Total Generators Potentially Subject to
Regulation (excluding baseline closures)
Facilities Subject to Best Professional Judgment
Facilities Subject to National Categorical
Requirements
No compliance requirement1
Impingement controls only
Impingement and entrainment controls
Proposed
Options
114
114
-
-
-
-
Option 3
114
63
51
39
n
-
Option 4
114
110
4
2
-
2
Option 2
114
63
51
38
n
2
Option 1
114
63
51
36
10
5
Option 6
114
-
114
94
14
6
a   These facilities meet compliance requirements in the baseline and thus would require no action to comply with the regulation.

Source:  U.S. EPA Analysis, 2004.
d.  Summary of estimated private compliance costs
Table B5-5 below presents, for each evaluated option, the annualized pre-tax and after-tax compliance costs
estimated to be incurred by Electric Generators subject to the national categorical requirements.

         Table B5-5: Private Compliance Costs for Electric Generators by Cost (annualized, 2003$)

Number of
Facilities
Subject to
National
Require-
ments
One-Time Costs
Capital Down-
Technology time
Initial Permit Pilot
Application Study
Recurring Costs
Monitoring,
«-voT»,r Record Permit
O&M ,, . „ _ ,
Keeping & Renewal
Reporting
Total
Annualized
Costs
                                           Pre-Tax Compliance Costs
Proposed
Options
Option 3
Option 4
Option 2
Option 1
Option 6
-
51
4
51
51
114
SO
$503,000
$168,000
$552,000
$608,000
$687,000
SO
$0
$72,000
$72,000
$134,000
$151,000
SO
$479,000
$250,000
$609,000
$625,000
$994,000
SO
$0
$0
$0
$0
$0
so
$318,000
$70,000
$354,000
$419,000
$459,000
SO
$328,000
$229,000
$492,000
$625,000
$872,000
SO
$397,000
$183,000
$483,000
$490,000
$801,000
SO
$2,025,000
$972,000
$2,562,000
$2,901,000
$3,963,000
                                          After-Tax Compliance Costs
Proposed
Options
Option 3
Option 4
Option 2
Option 1
Option 6
-
51
4
51
51
114
SO
$393,000
$168,000
$443,000
$497,000
$558,000
SO
$0
$72,000
$72,000
$120,000
$136,000
SO
$411,000
$219,000
$510,000
$521,000
$791,000
SO
$0
$0
$0
$0
$0
so
$247,000
$70,000
$282,000
$328,000
$358,000
SO
$283,000
$203,000
$420,000
$519,000
$696,000
SO
$338,000
$156,000
$399,000
$403,000
$630,000
SO
$1,673,000
$888,000
$2,127,000
$2,388,000
$3,169,000
 Source:  U.S. EPA Analysis, 2004.
B5-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities         B5: Impact Analysis for Generators

B5-2   SUMMARY OF ELECTRICITY MARKET MODEL ANALYSIS

EPA used an electricity market model, the IPM®, to assess potential economic and operational impacts of this
proposal.  As noted above, the three proposed options would not apply national requirements to any facilities in
the Electric Generators segment; thus, the three proposed options have no effects to be considered in an IPM®
analysis. Since conducting electricity market model analyses is time- and resource-intensive,  EPA only analyzed
one of the other options evaluated for this proposal.  EPA chose to conduct an IPM® analysis of the most inclusive
and most costly option, Option 6, to identify the upper bound of potential effects under any of the evaluated
options.

EPA conducted impact analyses at the market level (by NERC region) and for facilities subject to the national
requirements under Option 6.  Analyzed characteristics include changes in electricity prices, capacity, generation,
revenue, cost of generation, and income. These changes were identified by comparing outcomes in the post-
compliance scenario ("Policy Case") with outcomes in the base case. Because of the interrelationships between
the final Phase II rule (promulgated in July 2004) and Phase III regulation, EPA developed two base cases for this
analysis:

    *•   The first base case (referred to as "Base Case 1") models operational characteristics of the electricity
        market in the absence of any section 316(b) regulation (i.e., pre-Phase II regulation);
    *•   The second base case (referred to as "Base Case 2") models operational characteristics of the electricity
        market including compliance costs of the final Phase  II rule (but pre-Phase III regulation).

For the market-level analysis, EPA compared the Policy Case (after the implementation of Phase III compliance
requirements) with Base Case 2 (including Phase II compliance costs).  This comparison allows EPA to identify
the incremental market-level effects of Phase III regulation, beyond the effects of Phase II regulation. In contrast,
for the analysis of facilities subject to Phase III regulation, EPA compared the Policy Case with Base Case  1
(excluding Phase II compliance costs). This comparison was  done to determine the "true" effect of Phase III
regulation, net of any temporary effects that might be introduced as the result of the staggering of Phases II and
III. Because Phase II facilities have to comply before Phase III facilities are projected to comply (on average by
two years), Phase III facilities may experience a short-term competitive advantage during the time when Phase II
facilities incur the new incremental section 316(b) compliance costs while Phase III facilities do not. The post-
compliance economic performance of Phase III facilities should not be compared to this potential short-term
improvement in operating characteristics but to their steady-state,  pre-section 316(b) regulation economic
condition.

EPA used the most current version of the IPM®, V.2.1.6 released in 2003, for the analysis in developing this
proposal.3 The 2003 version of the IPM® has been updated to include, among other things, compliance costs of
the State Multi-Pollutant regulations and the New  Source Review  settlements, and updated costs for existing
facilities, such as life extension costs.

A detailed discussion of the IPM®, the methodology used in this analysis, and the analysis results for Option 6 is
presented  in the appendix to this chapter.


B5-3   ADDITIONAL IMPACT ANALYSES

This section presents an additional assessment of the magnitude of Electric Generator compliance costs associated
with the options evaluated for Phase III existing facilities. The analyses presented in this section include a cost-
to-revenue analysis at the facility and firm levels, an analysis  of compliance costs per household at the North
American Electric Reliability Council (NERC) level, and an analysis of compliance costs relative to electricity
price projections, also at the NERC level.
      The analysis of the final Phase II rule used a predecessor version, V.2.1.


                                                                                                   B5-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
B5-3.1 Cost-to-Revenue Analysis

The cost-to-revenue ratio is used to assess the magnitude of compliance costs relative to revenues. The cost-to-
revenue ratio is a useful test because it compares the cost of reducing adverse environmental impact from the
operation of the facility's cooling water intake structure (CWIS) with the economic value (i.e., revenue) of the
facility's economic activities. EPA conducted this test at the facility and firm levels. This analysis uses impact
thresholds of 0.5%, 1% and 3%.

a.  Facility-level analysis
EPA received survey data for 113 Electric Generators potentially subject to Phase III regulation.  EPA estimates
that three of these 113 Electric Generators are baseline closures; these facilities are excluded from this analysis.
For the remaining 110 facilities, EPA compared each facility's annualized after-tax compliance costs under each
evaluated option to the facility's annual revenues. EPA used facility-specific baseline revenue projections from
the IPM® for 2008 for this analysis.  The IPM® did not provide revenues for two facilities because they are not
included in the model.  In  addition, the  IPM® projects that nine facilities will have zero revenues in the baseline.
For the 11 facilities without IPM® revenues, EPA researched facility-specific electricity generation and firm-
specific wholesale prices,  as reported to the Energy Information Administration (EIA), to calculate the cost-to-
revenue ratio.  This research yielded information for nine of the  11 facilities; for the remaining two facilities, EIA
revenues are either zero or negative. EPA then applied sample weights to the 110 facilities to account for non-
sampled facilities and facilities that did not  respond to the survey. The sample-weighted facility count, excluding
baseline closures, is 114.

Table B5-6 below presents the results of the facility-level cost-to-revenue analysis for each evaluated option. The
table presents (1) the total number of facilities subject to the national categorical requirements; (2) the number of
facilities with a cost-to-revenue ratio of less than 0.5%, at least 0.5% but less than 1%, at least 1% but less than
3%, and at least 3%; and (3) the minimum and maximum ratios.

As previously noted, no Electric Generators are subject to the national requirements nor incur compliance costs
under the three  proposed options. Under the other evaluated  options, between four and 114 Electric Generators
are subject to the national  requirements; the remaining facilities are subject to best professional judgment
requirements and are excluded from this analysis.  Table B5-6 shows that under most options, the majority of
facilities would have a cost-to-revenue  ratio of less than 0.5%. Under Option 6, the most inclusive and costly of
the evaluated options, 10 facilities are estimated to have a ratio of between  1% and 3%, and 13 facilities are
estimated to have a ratio of greater than 3%. The maximum ratio under Option 6 is 430%; the maximum ratios
under the other evaluated options are 8.7% for Option 4 and 75.6% for Options 1, 2, and 3.

                 Table B5-6: Facility-Level Cost-to-Revenue Measure By Ownership Type
Option
Proposed
Options
Option 3
Option 4
Option 2
Option 1
Option 6
Total
Number of
Facilities3
-
51
4
51
51
114
< 0.5%
Number of Facilities with
0.5 to <1% 1 to <3%
a Ratio of
>=3%
No Rev.
-
35
1
34
33
88
3
-
3
1
1
3
1
4
7
10
9
1
9
9
13
1
-
1
1
2
Minimum
Ratio
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Maximum
Ratio
0.0%
75.6%
8.7%
75.6%
75.6%
430.4%
 a   Individual numbers may not add up due to independent rounding.

 Source:  IPM® analysis, V.2.1.6: model run for Section 316(b) base case, 2008, AEO electricity demand assumptions; U.S. EPA
         Analysis, 2004.
B5-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
b.  Firm-level analysis
The facility-level analysis presented above showed that compliance costs are generally low compared to facility-
level revenues. However, impacts experienced at the firm-level may be more significant for firms that own
multiple facilities subject to Phase III regulation. EPA therefore also analyzed the firm-level cost-to-revenue
ratios of the evaluated options.

EPA first identified the domestic parent entity of each of the 110 surveyed, non-baseline closure Electric
Generators potentially subject to Phase III regulation (for a detailed description of this analysis, see Chapter Dl:
Regulatory Flexibility Analysis).  EPA determined that 72 unique domestic parent entities own these 110
facilities.  EPA identified 18 entities that own more than one Electric Generator potentially subject to Phase III
regulation. EPA obtained the  sales revenues for each of the domestic parent entities from publicly available data
sources (the 1999, 2000, and 2001 Forms EIA-861; the Dun and Bradstreet database; company  10-K filings; and
entities' websites).  The firm-level analysis is based on the ratio of each parent entity's aggregated after-tax
compliance costs (summed over each facility owned by the parent entity and subject to the national requirements)
to its total sales revenue.

Table B5-7 below presents the results of the firm-level cost-to-revenue measure.  The table presents (1) the
sample-weighted number of facilities owned; (2) the total number of firms; (3) the number of firms with a cost-to-
revenue ratio of less than 0.5%, at least 0.5% but less than 1%, at least 1% but less than 3%, and at least 3%; and
(4) the minimum and maximum ratios.

No  Electric Generators are subject to the national requirements under the three proposed options.  Under the other
evaluated options, between four and 72 entities own Electric Generators subject to the national requirements; the
remaining entities own facilities subject to best professional judgment requirements and are excluded from this
analysis.  EPA estimates that Phase III compliance costs would comprise a low percentage of firm-level revenues.
Under all of the evaluated options, no more than one entity would experience a cost-to-revenue  ratio of greater
than 3%.  Depending on the option, between one and five entities would have a ratio between 1% and 3%. The
highest estimated cost-to-revenue ratio under any of the evaluated options is 3.39%.
                    Table B5-7: Firm-Level Cost-to-Revenue Measure by Entity Type
Option
Proposed Options
Option 3
Option 4
Option 2
Option 1
Option 6
Total
Number
of
Facilities
Total
Number
of
Entities
-
51
4
51
51
114
42
4
42
42
72
Number of Entities with a Ratio of
<0.5% 0.5to=3%
-
38
2
38
37
66
1 3
1 1
3 1
4 1
5 1
Minimum
Ratio
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
Maximum
Ratio
0.00%
2.65%
3.39%
3.39%
3.39%
3.39%
 Source:  U.S. EPA Analysis, 2004.
B5.3-2 Cost Per Household Analysis

EPA also conducted an analysis that evaluates the potential cost per household, if Phase III facilities were able to
pass compliance costs on to their customers. This analysis estimates the average compliance cost per household
                                                                                                   B5-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
for each North American Electric Reliability Council (NERC) region, using data on residential consumers from
the2001FormEIA-861.4

EPA calculated the average annual cost per household for each evaluated option by dividing the total pre-tax
compliance cost of all regulated facilities in a NERC region by the total number of households in that region.
This analysis assumes that Electric Generators pass costs on to consumers, on a dollar-to-dollar basis, and that
there will be no reduction in electricity consumption by the consumers in response to price increases. EPA also
used the conservative assumption that residential consumers bear the full burden of compliance costs; no other
customer groups (e.g., commercial or industrial consumers) are assumed to bear any of the compliance costs.

Table B5-8 presents the annualized pre-tax compliance costs, by NERC region, for each evaluated option. Table
B5-9 shows the number of households in each NERC region,  and the estimated annual compliance cost per
household. No Electric Generators would incur compliance costs under the three proposed options.  The highest
estimated annual cost per household, under any option and  in any region, is $0.12 in the Mid-Continent Area
Power Pool (MAPP) under Options 1 and 6. Under all other options and in all other regions, the estimated annual
cost per household is lower.

                Table B5-8: Annualized Pre-Tax Compliance Cost by NERC Region (2003$)
NERC
Region3
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
U.S.
Proposed
Options
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
SO
Option 3
$0
$256,000
$7,000
$2,000
$0
$8,000
$400,000
$540,000
$417,000
$14,000
$275,000
$107,000
$2,025,000
Option 4
$0
$387,000
$0
$0
$0
$0
$376,000
$0
$209,000
$0
$0
$0
$972,000
Option 2
$0
$504,000
$7,000
$2,000
$0
$8,000
$482,000
$540,000
$623,000
$14,000
$275,000
$107,000
$2,562,000
Option 1
$0
$642,000
$7,000
$2,000
$0
$8,000
$482,000
$603,000
$623,000
$14,000
$275,000
$246,000
$2,901,000
Option 6
$0
$917,000
$18,000
$10,000
$0
$22,000
$687,000
$612,000
$1,109,000
$36,000
$289,000
$262,000
$3,963,000
 a   Key to NERC regions: ASCC - Alaska Systems Coordinating Council; ECAR - East Central Area Reliability Coordination
     Agreement; ERCOT - Electric Reliability Council of Texas; FRCC - Florida Reliability Coordinating Council; HI - Hawaii;
     MAAC - Mid-Atlantic Area Council; MAIN - Mid-America Interconnect Network; MAPP - Mid-Continent Area Power Pool;
     NPCC - Northeast Power Coordinating Council; SERC - Southeastern Electric Reliability Council; SPP - Southwest Power Pool;
     WECC - Western Electricity Coordinating Council.

 Source:  U.S. DOE, 2001; U.S. EPA Analysis, 2004.
    4 The number of residential consumers reported in Form EIA-861 is based on the number of utility meters. This is a proxy for the
number of households but can differ slightly due to bulk metering in some multi-family housing.
B5-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
         Table B5-9: Annual Compliance Cost per Residential Consumer by NERC Region (2001)
NERC
Region3
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
U.S.
Number of
Households
(2001)
234,646
15,698,205
7,309,073
6,885,280
351,229
8,921,106
8,366,132
4,933,221
12,676,283
20,550,922
5,002,020
23,085,962
114,014,079
Annual Compliance Cost/ Residential Consumer (2003 S)
Proposed
Options
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
Option 3
$0.00
$0.02
$0.00
$0.00
$0.00
$0.00
$0.05
$0.11
$0.03
$0.00
$0.06
$0.00
$0.02
Option 4
$0.00
$0.02
$0.00
$0.00
$0.00
$0.00
$0.04
$0.00
$0.02
$0.00
$0.00
$0.00
$0.01
Option 2
$0.00
$0.03
$0.00
$0.00
$0.00
$0.00
$0.06
$0.11
$0.05
$0.00
$0.06
$0.00
$0.02
Option 1
$0.00
$0.04
$0.00
$0.00
$0.00
$0.00
$0.06
$0.12
$0.05
$0.00
$0.06
$0.01
$0.03
Option 6
$0.00
$0.06
$0.00
$0.00
$0.00
$0.00
$0.08
$0.12
$0.09
$0.00
$0.06
$0.01
$0.03
 a   Key to NERC regions: ASCC - Alaska Systems Coordinating Council; ECAR - East Central Area Reliability Coordination
     Agreement; ERCOT - Electric Reliability Council of Texas; FRCC - Florida Reliability Coordinating Council; HI - Hawaii;
     MAAC - Mid-Atlantic Area Council; MAIN - Mid-America Interconnect Network; MAPP - Mid-Continent Area Power Pool;
     NPCC - Northeast Power Coordinating Council; SERC - Southeastern Electric Reliability Council; SPP - Southwest Power Pool;
     WECC - Western Electricity Coordinating Council.

 Source:  U.S. DOE, 2001; U.S. EPA Analysis, 2004.
B5-3.3 Electricity Price Analysis

EPA also considered potential effects of Phase III regulation on electricity prices. EPA used three data inputs in
this analysis: (1) total pre-tax compliance cost incurred by facilities subject to the national requirements; (2) total
electricity sales projected for 2007 (the year the proposed rule would take effect), based on the Annual Energy
Outlook (AEO) 2003; and (3) projected prices for 2007 by consumer type (residential, commercial, industrial, and
transportation), also from the AEO 2003. All three data elements were calculated by NERC region.

Table B5-10 shows total projected electricity sales (in MWh) for 2007 and the average compliance cost per
kilowatt hour (KWh) for each evaluated option, by NERC region.  The average cost per kilowatt hour for each
option was estimated by dividing the annualized pre-tax compliance costs for each NERC region (presented in
Table B5-8 above) by the region's total electricity  sales. No Electric Generating facilities would incur
compliance costs under the three proposed options. For all other evaluated options, the average cost ranges from
no additional cost per KWh sales to a maximum of 0.0004 cents per KWh sales.  The U.S. average is estimated to
be 0.0001 additional cents per KWh sales or less under all options.
                                                                                                      B5-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
                     Table B5-10: Compliance Cost per KWh of Sales by NERC Region
NERC
Region3
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
U.S.
Total Electricity
Sales (MWh;
2001)
—
570,807,007
297,949,799
208,035,233
—
280,251,282
255,762,939
172,704,269
282,686,981
853,386,597
191,778,000
259,401,428
3,845,085,938
Annualized
Proposed
Options
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
Option 3
00.0000
00.0000
00.0000
00.0000
00.0000
00.0000
40.0002
40.0003
40.0001
00.0000
40.0001
00.0000
to.oooi
Pre-Tax Compliance
Option 4
00.0000
4 0.0001
00.0000
00.0000
00.0000
00.0000
40.0001
00.0000
40.0001
00.0000
00.0000
00.0000
00.0000
Cost (Cents / KWh Sales)
Option 2
00.0000
40.0001
00.0000
00.0000
00.0000
00.0000
40.0002
40.0003
40.0002
00.0000
40.0001
00.0000
to.oooi
Option 1
00.0000
4 0.0001
00.0000
00.0000
00.0000
00.0000
40.0002
40.0003
40.0002
00.0000
40.0001
40.0001
$0.0001
Option 6
00.0000
40.0002
00.0000
00.0000
00.0000
00.0000
40.0003
40.0004
40.0004
00.0000
40.0002
40.0001
to.oooi
 a   Key to NERC regions: ASCC - Alaska Systems Coordinating Council; ECAR - East Central Area Reliability Coordination
     Agreement; ERCOT - Electric Reliability Council of Texas; FRCC - Florida Reliability Coordinating Council; HI - Hawaii;
     MAAC - Mid-Atlantic Area Council; MAIN - Mid-America Interconnect Network; MAPP - Mid-Continent Area Power Pool;
     NPCC - Northeast Power Coordinating Council; SERC - Southeastern Electric Reliability Council; SPP - Southwest Power Pool;
     WECC - Western Electricity Coordinating Council.
     The Annual Energy Outlook does not include ASCC and HI.

 Source:  U.S. DOE, 2003; U.S. EPA Analysis, 2004.
To determine potential effects on electricity prices as a result of compliance with the evaluated options, EPA
compared the compliance cost per KWh of sales, presented in Table B5-10 above, to projected baseline electricity
prices for different consumer types (projections for 2007).

Table B5-11 below presents the estimated percentage changes in baseline electricity prices for Option 6, the most
inclusive and most costly of the evaluated options.  These results therefore represent the upper bound of potential
electricity price effects under any of the evaluated options. Rounded to the nearest 100th of a percent, the largest
estimated percentage increases for any consumer type and in any region under Option 6 is 0.01%. For all other
options, the resulting percentage increases in electricity prices would be less than, or equal to, those estimated for
Option 6. Overall, EPA concludes that the compliance costs for none of the evaluated options would have an
effect on electricity prices.

This analysis assumes that Electric Generators fully recover compliance costs from consumers and that each
sector (i.e., residential, commercial, industrial, and transportation) bears an equal burden of compliance costs per
MWh of purchased electricity.
B5-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities
B5: Impact Analysis for Generators
    Table B5-11: Estimated Price Increase as a Percentage of 2007 Prices by Consumer Type and NERC
                 Region - Option 6 (All costs and prices in cents per kilowatt hour; 2003$)


Region
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
U.S.
Annualized
Pre-Tax
Compliance
Cost (Cents /
KWh Sales)
Opt. 6
0.0002
0.0000
0.0000
0.0000
0.0003
0.0004
0.0004
0.0000
0.0002
0.0001
0.0001


Residential
Price _,
Change
6.72 0.00%
8.30 0.00%
8.37 0.00%
7.48 0.00%
7.60 0.00%
6.91 0.01%
10.64 0.00%
7.42 0.00%
7.18 0.00%
6.55 0.00%
7.86 0.00%


Commercial
Price _,
Change
5.95 0.00%
7.74 0.00%
7.16 0.00%
5.88 0.00%
6.10 0.00%
5.80 0.01%
7.85 0.01%
6.55 0.00%
6.03 0.00%
5.90 0.00%
6.87 0.00%


Industrial
Price _,
Change
4.15 0.00%
5.08 0.00%
5.33 0.00%
5.35 0.00%
4.18 0.01%
3.99 0.01%
5.47 0.01%
4.16 0.00%
4.06 0.00%
3.38 0.00%
4.43 0.00%


Transportation
Price _,
Change
5.65 0.00%
6.94 0.00%
7.32 0.00%
6.16 0.00%
6.12 0.00%
5.74 0.01%
8.40 0.00%
6.29 0.00%
5.76 0.00%
5.67 0.00%
6.71 0.00%


All Sectors Average
Price % Change
5.51 0.00%
7.22 0.00%
7.65 0.00%
6.34 0.00%
6.01 0.00%
5.53 0.01%
8.37 0.00%
6.16 0.00%
5.91 0.00%
5.22 0.00%
6.54 0.00%
 Source:  U.S. EPA Analysis, 2004.
B5-4   UNCERTAINTIES AND LIMITATIONS

»»»  Estimation of Private Compliance Costs
EPA's estimates of the compliance costs associated with the options evaluated in developing the proposed rule are
subject to limitations because of uncertainties about the number and characteristics of Electric Generators that
would potentially be subject to Phase III regulation under each option. Projecting the number of facilities that
meet the design intake flow applicability thresholds is subject to uncertainties associated with the quality of data
reported by the facilities in their Detailed Questionnaire (DQ) and Short Technical Questionnaire (STQ) surveys,
and with the accuracy of the design flow estimates for the STQ facilities.  Characterizing the cooling systems and
intake technologies in use at existing facilities is also subject to uncertainties associated with the quality of data
reported by the facilities in their surveys and with the projected technologies for the STQ facilities. The estimated
total compliance costs for the Electric Generating industry may be over- or understated if the projected number of
Phase III existing facilities subject to the national categorical requirements is incorrect or if the characteristics of
the facilities are different from those assumed in the analysis.

Limitations in EPA's ability to consider a full range of compliance responses may result in an overestimate of
facility compliance costs. The Agency was not able to consider certain compliance responses, including the costs
of using alternative sources of cooling water, the costs of some methods of changing the cooling system design,
and the costs of restoration. Costs would be overstated if these excluded compliance responses are less expensive
than the projected compliance response for some facilities.

Alternative less stringent requirements based on both costs and benefits are allowed under the evaluated options.
There is some uncertainty in predicting compliance responses because the number of facilities requesting
alternative less stringent requirements based on costs and benefits is unknown.
                                                                                                   B5-13

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities         B5: Impact Analysis for Generators

There is also uncertainty associated with the estimates of facility revenues. Facility revenues are projected
revenues from the IPM®.  The IPM® is a forward looking model that simulates generator dispatch based on
numerous assumptions about future conditions, including future fuel prices, electricity demand, new capacity
additions, heat rates, etc.  Changing these assumptions might affect the projected facility revenues and the
estimated cost of installation downtime for Electric Generators.

»»»  Electricity Market Model An alysis
Uncertainties and limitations associated with EPA's IPM® analysis are documented in the appendix to this
chapter.

»»»  Additional Impact Analyses
There is uncertainty associated with EPA's estimates of potential cost per household and electricity price changes.
As noted in the sections above, EPA's analyses are based on the assumption that Electric Generators would be
able to pass on 100% of their compliance costs to their customers.  For the cost per household analysis, EPA
assumed that all costs would be passed on to all residential customers in the region. The results of this analysis
might differ if less than 100% of compliance costs could be passed on, or if only a subset of residential consumers
in a region bore the passed-on costs. For the electricity price analysis, EPA assumed that all costs would be
spread evenly  among all customers.  Again, the results of this analysis might differ if less than 100% of
compliance costs could be passed on, or if the  different customer groups bore different shares of compliance
costs. However, in both analyses, the two uncertainty factors would change results in opposite directions; it is
therefore unclear whether EPA's analyses might overstate  or understate actual impacts.  In addition, the impacts
of both analyses  are very minor; therefore, it is unlikely that EPA's findings would change, even if one or more of
EPA's assumptions were incorrect.
B5-14

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities          B5: Impact Analysis for Generators

REFERENCES

Engineering News-Record (ENR). 2004.  Construction Cost Index.  Available at:
http://enr.construction.com/features/conEco/costIndexes/constIndexHist.asp.

U.S. Department of Energy (U.S. DOE). 2003.  Energy Information Administration (EIA). Annual Energy
Outlook 2003 With Projections to 2025. DOE/EIA-0383(2003).  January 2003.

U.S. Department of Energy (U.S. DOE). 2001.  FormEIA-861. Annual Electric Utility Report for the Reporting
Period 2001.

U.S. Department of Labor (U.S. DOL).  2004. Bureau of Labor Statistics (BLS). Producer Price Index-
Commodities.  Series ID: WPU0543.  Not Seasonally Adjusted.  Group: Fuels and related products and power.
Item: Industrial electric power.  Available at: http://www.bls.gov/ppi/. Accessed on July 23, 2004.

U.S. Environmental Protection Agency (U.S. EPA).  2004a.  Economics and Benefits Analysis for the Final
Section 316(b) Phase IIExisting Facilities Rule.  EPA-821-R-04-005.  February 2004.

U.S. Environmental Protection Agency (U.S. EPA).  2004b.  Technical Development Document for the Proposed
Section 316(b) Rule for Phase III Facilities.  EPA-821 -R-04-015. November 2004.

U.S. Environmental Protection Agency (U.S. EPA).  2003. Documentation Supplement for EPA Modeling
Applications (V. 2.1.6) Using the Integrated Planning Model.  EPA 430/R-03-007. July 2003.

U.S. Environmental Protection Agency (U.S. EPA).  2002. Documentation of EPA Modeling Applications (V.2.1)
Using the Integrated Planning Model. EPA  430/R-02-004. March 2002.

U.S. Environmental Protection Agency (U.S. EPA).  2000.  Section 316(b) Industry Survey. Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II
Cooling Water Intake Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener
Questionnaire: Phase I Cooling Water Intake Structures, January, 1999 (OMB Control Number 2040-0203).
                                                                                                B5-15

-------
§ 316(b) Proposed Rule: Phase III-EA, PartB: Economic Analysis for Existing Facilities         B5: Impact Analysis for Generators
                           THIS PAGE INTENTIONALLY LEFT BLANK
B5-16

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                              Appendix 1 to Chapter B5
                    Appendix  1  to  Chapter  B5:
            Electricity  Market Model Analysis
                                                         B5A-1.2

                                                         B5A-1.3
                                                         B5A-1.4
                                                  B5A-2
APPENDIX CONTENTS
B5A-1  Integrated Planning Model Overview ...
       B5A-1.1  Modeling Methodology	
                Specifications for the Section
                316(b) Analysis  	
                Model Inputs  	
                Model Outputs	
       Economic Impact Analysis Methodology
       B5 A-2.1  Market-level Impact Measures
       B5A-2.2  Facility-level Impact Measures
                (Potential Phase III Facilities
                Only) 	
       Analysis Results for Option 6  	
       B5A-3.1  Market Analysis for 2013	
       B5 A-3.2  Analysis of Potential Phase III
                Facilities for 2013  	
       Summary of IPM V.2.1.6 Updates	
       Uncertainties and Limitations  	
                                                  B5A-3
                                                  B5A-4
                                                  B5A-5
 B5A-2
 B5A-2

 B5A-5
 B5A-6
 B5A-7
 B5A-8
 B5A-8
B5A-10
B5A-11
B5A-12

B5A-18
B5A-24
B5A-30
INTRODUCTION

This appendix presents EPA's analysis of impacts on
Electric Generators potentially subject to Phase III
regulation and to the Electric Generating Industry as
a whole. While only a subset of facilities in the
electric power generation industry would be subject
to Phase III regulation under any option evaluated for
this proposal, interdependencies within the electric
power market, might result in indirect impacts
throughout the industry.  Direct impacts on plants
subject to an evaluated option may include changes
in capacity utilization, generation, and profitability.
Potential indirect impacts on the electric power
industry may include changes to the generation and
revenue of facilities and firms not subject to Phase III
regulation, changes to  bulk system reliability, and
regional and national impacts such as changes in the
price of electricity and the construction of new
generating capacity.

Under the proposed options, the minimum applicability threshold for national categorical requirements is 50
MGD or greater.  Since Electric Generators with design intake flows of 50 MGD or greater were covered by
Phase II regulation, no Phase III Generator would be subject to the national categorical requirements under any of
the proposed options; therefore there would be no direct impacts on any Electric Generators nor any indirect
impacts on the Electric Generating Industry as a result of the proposed rule.  However, some of the other options
evaluated by EPA would impose compliance costs on Electric Generators. This chapter presents an analysis of
the potential effects of Option 6, the most costly option considered by EPA, and the option with the highest
potential impacts. Option 6 would impose national categorical requirements on all facilities with a DIP of 2 MGD
or greater.

EPA used ICF Consulting's Integrated Planning Model (IPM®), an integrated energy market model, to conduct
the economic analyses supporting this rule.1 The model addresses the interdependencies within the electric power
market and accounts for both direct and indirect impacts of regulatory actions. EPA used the model to analyze
two potential effects of Option 6: (1) potential energy effects at the national  and regional levels, as required by
Executive Order 13211 ("Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution,
or Use");2 and (2) potential economic impacts on facilities potentially subject to Phase III regulation.

Option 6 was evaluated under the unadjusted  electricity demand from the Annual Energy Outlook (AEO) 2003.
Section B5A-3 presents the results of the IPM® analysis for Option 6.
    1 The IPM® was also used for the Phase II Rule. At the time of the Phase II proposal EPA evaluated several models suitable for
analysis of environmental policies that affect the electric power industry. For a full discussion of the various models EPA considered, refer
to section B3-1 and Appendix B in Chapter B3 of the Economics and Benefits Analysis for the Final Section 316(b) Phase II Existing
Facilities Rule (U.S. EPA, 2004a).

    2 Please refer to Chapter D3: Other Administrative Requirements for a discussion of this analysis.
                                                                                              B5A-1

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5
B5A-1     INTEGRATED PLANNING MODEL OVERVIEW

This section presents a general overview of the capabilities of the IPM®, including a discussion of the modeling
methodology, the specification of the model for the section 316(b) analysis, and model inputs and outputs.  When
the analyses in support of the Phase II Rule were developed, the latest EPA specification of the U.S. power
market, "EPA Base Case 2000," was based on IPM® Version 2.1 (U.S. EPA, 2002). In July 2003, a new version
of the model, Version 2.1.6, was released (U.S. EPA, 2003).  The Phase III proposal analyses utilize the
specifications for the new "EPA Base Case 2003".  A summary table of model updates is presented in section
B5A-4.

B5A-1.1    Modeling Methodology

a.  General framework
The IPM® is an engineering-economic optimization model of the electric power industry, which generates least-
cost resource dispatch decisions based on user-specified constraints such as environmental, demand, and other
operational  constraints. The model can be  used to analyze a wide range of electric power market issues at the
plant, regional, and national levels. In the past, applications of the IPM® have included capacity planning,
environmental policy analysis and compliance planning, wholesale price forecasting, and asset valuation.

The IPM® uses a long-term dynamic linear programming framework that simulates the dispatch of generating
capacity to achieve a demand-supply equilibrium on a seasonal basis and by region. The model seeks the optimal
solution to an "objective function," which is a linear equation equal to the present value of the sum of all capital
costs, fixed  and variable operation and maintenance (O&M) costs, and fuel costs. The objective function is
minimized subject to a series of user-defined supply and demand, or system operating, constraints.  Supply-side
constraints include capacity constraints, availability of generation resources, plant minimum operating constraints,
transmission constraints, and environmental constraints.  Demand-side constraints include reserve margin
constraints and minimum system-wide load requirements. The optimal solution to the objective function is the
least-cost mix of resources required to satisfy system wide electricity demand on a seasonal basis by region. In
addition to existing capacity, the model also considers new resource investment options, including capacity
expansion or repowering at existing plants  as well as investment in new plants. The model selects new
investments while considering interactions with fuel markets, capacity markets, power plant cost and performance
characteristics, forecasts of electricity demand, reliability criteria, and other constraints. The resulting system
dispatch is optimized given the resource mix, unit operating characteristics, and fuel and other costs, to achieve
the most efficient use of existing and new resources available to meet demand.  The model is dynamic in that it is
capable of using forecasts of future conditions to make decisions for the present.3

b.  Model plants
The model is supported by a database of boilers and electric generation units which includes all existing utility-
owned generation units as well as those located at plants owned by independent power producers and
cogeneration facilities that contribute capacity to the electric transmission grid. Individual generators are
aggregated into model plants with similar O&M costs and specific operating characteristics including seasonal
capacities, heat rates, maintenance schedules, outage rates, fuels, and transmission and distribution loss
characteristics.
    3 EPA used the IPM® to forecast operational changes, including changes in capacity, generation, revenues, electricity prices, and
plant closures, resulting from the rule. In other policy analyses, the IPM® is generally also used to determine the compliance response for
each model facility. This process involves selecting the optimal response from a menu of compliance options that will result in the least-
cost system dispatch and new resource investment decision. Compliance options specified by IPM® may include fuel switching,
repowering, pollution control retrofit, co-firing multiple fuels, dispatch adjustments, and economic retirement.  EPA did not use this
capability to choose the compliance responses of the facilities subject to section 316(b) rulemaking. Rather EPA exogenously estimated a
compliance response using the costs of technologies capable of meeting the percentage reductions in impingement and entrainment
required under the regulation. In the post-compliance analysis, these compliance costs were added as model inputs to the base case
operating and capital costs.

B5A-2

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5
The number and aggregation scheme of model plants can be adjusted to meet the specific needs of each analysis.
The EPA Base Case 2003 contains 1,703 model plants.

c.   IPM® regions
The IPM® divides the U.S. electric power market into 26 regions in the contiguous U.S.  It does not include
generators located in Alaska or Hawaii. The 26 regions map into North American Reliability Council (NERC)
regions and sub-regions.  The IPM® models electric demand, generation, transmission, and distribution within
each region and across the transmission grid that connects regions. For the analyses presented in this chapter,
IPM® regions were aggregated back into NERC regions. Figure B5A-1 provides a map of the regions included in
the IPM®. Table  B5A-1 presents the crosswalk between NERC regions and IPM® regions.
            Figure B5A-1: Regional Representation of U.S. Power System as Modeled in IPM"
                                                                                  NENG
                                                           WUMS           DSNYU
                                                                   MECS
 Source:  U.S. EPA, 2002.
                                                                                                B5A-3

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5
                    Table B5A-1: Crosswalk between NERC Regions and IPM® Regions
NERC Region
ASCC - Alaska
ECAR - East Central Area Reliability Coordination Agreement
ERCOT - Electric Reliability Council of Texas
FRCC - Florida Reliability Coordinating Council
HI - Hawaii
MACC - Mid Atlantic Area Council
MAIN - Mid- America Interconnect Network
MAPP - Mid-Continent Area Power Pool
NPCC - Northeast Power Coordination Council
SERC - Southeastern Electricity Reliability Council
SPP - Southwest Power Pool
WECC - Western Electricity Coordinating Council
IPM® Regions
Not Included
ECAO, MECS
ERCT
FRCC
Not Included
MACE, MACS, MACW
MANO, WUMS
MAPP
DSNY, LILC, NENG, NYC, UPNY
ENTG, SOU, TVA, VACA
SPPN, SPPS
AZNM, CALI, NWPE, PNW, RMPA
Source: U.S. EPA, 2002.
d.  Model run years
The IPM® models the electric power market over the 26-year period 2005 to 2030.  Due to the data-intensive
processing procedures, the model is run for a limited number of years only. Run years are selected based on
analytical requirements and the necessity to maintain a balanced choice of run years throughout the modeled time
horizon. EPA selected the following run years for the Phase II analysis: 2008, 2010, and 2013, and has chosen to
retain them for the Phase III analysis.4'5

The model assumes that capital investment decisions are only implemented during run years. Each model run
year is mapped to several calendar years such that changes in variable costs, available capacity, and demand for
electricity in the years between the run years are partially captured in the results for each model run year. Table
B5A-2 below identifies the model run years specified for the analysis of Phase III options and the calendar years
mapped to each.
    4 The IPM® developed output for a total of five model run years 2008, 2010, 2013, 2020, and 2026.  Model run years 2020 and 2026
were specified for model balance, while run years 2008, 2010, and 2013 were selected to provide output across the compliance period.
Output for 2026 was not used in this analysis. For a discussion explaining the reasons for the selected model run years refer to section B3-
2.\dofthe Economics and Benefits Analysis for the Final Section 316(b) Phase II Existing Facilities Rule (U.S. EPA, 2004a).

    5 EPA estimates that Phase III facilities would comply between 2010 and 2014. For the analyses using the IPM® only, EPA modified
this assumption and used compliance years of 2008 through 2012 by subtracting two years from the estimated compliance year of each
facility. This modification allowed EPA to analyze the output for 2013 as the year when all facilities are in compliance.
B5A-4

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5
                              Table B5A-2: Model Run Year Mapping
Run Year
2008
2010
2013
2020
2026
Mapped Years
2005-2009
2010-2012
2013-2015
2016-2022
2023-2030
Source: IPtvf model specification for the Section 316(b) Base Case.
B5A-1.2   Specifications for the Section 316(b) Analysis

The analysis for section 316(b) rulemaking required changes in the original specification of the IPM®.
Specifically, the base case configuration of the model plants and model run years were revised according to the
requirements of this analysis.  Both modifications to the existing model specifications are discussed below.

    *•   Changes in the Aggregation of Model Plants: As noted above, the IPM® aggregates individual boilers
        and generators with similar cost and operational characteristics into model plants. Since the IPM® model
        plants were initially created to support air policy analyses, the original configuration was not appropriate
        for the section 316(b) analysis. As a result, the steam and non-steam electric generators at facilities
        subject to the Phase II and Phase III rules were disaggregated from the existing IPM® model plants and
        "run" as individual facilities along with the other existing model plants.  This change increased the total
        number of model plants from  1,703 to 2,342.

    *•   Use of Different Model Run Years: The original specification of the IPM®'s EPA Base Case 2003 uses
        five model run years chosen based on the requirements of various air policy analyses: 2005, 2010, 2015,
        2020, and 2026. As explained above, EPA was interested in analyzing different years for the section
        316(b) rulemaking effort.  Therefore, EPA changed the run years for the section 316(b) analysis in order
        to obtain model output throughout the compliance period (see discussion of run year selection in section
        B5A-1.1 .d above). The change in run years and run year mappings are summarized below.
                                Table B5A-3: Modification of Model Run Years
EPA Base
Run Year
2005
2010
2015
2020
2026
Case 2003 Specification
Run Year Mapping
2005-2007
2008-2012
2013-2017
2018-2022
2023-2030
Section 316(b) Base Case
Run Year Run
2008
2010
2013
2020
2026
Specification
Year Mapping
2005-2009
2010-2012
2013-2015
2016-2022
2023-2030
Source: IPM® model specifications for the EPA Base Case 2003 and the Section 316(b) Base Case.
EPA compared the base case results generated from the two different specifications of the IPM® model.  The base
case results could only be compared for those run years that are common to both base cases, 2010 and 2020. This
comparison identified little or no difference in the base case results:

    »•   Base case total production costs (capital, O&M, and fuel) using the revised section 316(b) specifications
       are lower by 0.1% in 2010 and 2020.


                                                                                                   B5A-5

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5

    *•   Early retirements of base case oil and gas steam capacity and coal capacity under the section 316(b)
        specifications are higher by 3,192 megawatt (MW) and 383 MW in 2010 and 2020, respectively.
    *•   The change in model specifications resulted in virtually no change in base case coal and gas use in 2010
        and 2020.

B5A-1.3    Model Inputs

Compliance costs and compliance-related capacity reductions are the primary model inputs in the analysis of
section 316(b) rulemaking.  EPA determined compliance costs for each of the 113 facilities potentially subject to
Phase III regulation and 534 facilities subject to the Phase II regulation and modeled by the IPM®.6 For each
facility, compliance costs consist of capital costs (including costs for new screens or fish barrier nets, intake
relocation, and intake piping modification), fixed O&M costs, variable O&M costs, permitting costs, and capacity
reductions (for information  on the costing methodology, see the Technical Development Document for the
Proposed Section 316(b) Rule for Phase III Facilities; U.S. EPA, 2004b).

    *•   Capital cost inputs  into the IPM® are expressed as a fixed O&M cost, in dollars per kilowatt (KW) of
        capacity per year. The capital costs of compliance reflect the up-front cost of construction, equipment,
        and capital associated with the installation of required compliance technologies. The IPM® uses two up-
        front cost values as  model inputs (one each for technologies with a useful life of 10 and 30 years,
        respectively) and translates these values into a series of annual after-tax payments using a discount rate of
        5.34% for medium risk investments and 6.74%for high risk investments, and a capital charge rate of 12%
        for medium risk investments and  13.4% for high risk investments for the duration of the book life of the
        investment (assumed to be 30 years for initial permitting  costs and 10 years for the various compliance
        technologies) or the years remaining in the modeling horizon, whichever is shorter. High risk
        investments include Integrated Gasification Combined Cycle (IGCC) and repowerings-to- IGCC.7

    *•   Fixed O&M cost inputs into the IPM® are expressed in terms of dollars per KW of capacity per year.

    *•   Variable O&M cost inputs are expressed in dollars per megawatt hour (MWh)  of generation.

    *•   Permitting costs consist of initial permitting costs, annual monitoring costs, repermitting costs (occurring
        every five years after issuance of the initial permit), and,  for some facilities, pilot study costs.  Permitting
        cost inputs are expressed as follows: initial permitting and pilot study activities are necessary for the on-
        going operation of the plant and are therefore added to the capital costs for technologies with a 30-year
        useful life; annual monitoring and annualized repermitting costs are added to the fixed O&M costs.

    *•   Capacity reductions consist of a one-time generator downtime.  Generator downtime estimates reflect the
        amount of time generators are off-line while compliance technologies are constructed and/or installed and
        are expressed in weeks. The generator downtime is a one-time event that affects several of the
        compliance technologies evaluated by EPA.  Generator downtime is estimated to occur during the year
        when a facility  complies with the policy option. Since the years that are mapped into a run year are
        assumed  to have the same characteristics as the run year itself, generator downtimes were applied as an
    6  Two of the 113 facilities potentially subject to Phase III regulation and nine of the 543 facilities subject to the Phase II rule are
either not modeled in the IPM® or do not have steam-electric generators: one Phase III facility is out-of-service; one Phase II facility is
retired; five facilities, one Phase III and four Phase II, are on-site generators that do not provide electricity to the grid; three Phase II
facilities are in Hawaii and one Phase II facility is in Alaska, neither of which is represented in the IPM®.

    7  The capital charge rate is a function of capital structure (debt/equity shares of an investment), pre-tax debt rate (or interest cost),
debt life, after-tax return on equity, corporate income tax, depreciation schedule, book life of the investment, and other costs including
property tax and insurance. The discount rate is a function of capital structure, pre-tax debt rate, and after-tax return on equity.

B5A-6

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5

        average over the years that are mapped into each model run year.8 Estimated generator downtimes due to
        construction and/or installation range from two to eleven weeks (see also Chapter Bl: Summary of Cost
        Categories and Key Analysis Elements for Existing Facilities).

The IPM® operates at the boiler level. It was therefore necessary to distribute facility-level costs across affected
boilers. EPA used the following  methodology:

    *•   Steam electric generators operating at each of the 645 modeled section 316(b) Phase II and Phase III
        facilities were identified using data from the IPM®.

    *•   Generator-specific design intake flows were obtained from Form EIA-767 (1998 and 2000).9

    *•   Facility-level compliance costs were distributed across each facility's steam generators.  For facilities
        with available design intake flow data, this distribution was based on each generator's proportion of total
        design intake volume; for facilities without available design intake flow, this distribution was based on
        each generator's proportion of total steam electric capacity.

    *•   Generator-level compliance costs were aggregated to the boiler level based on the EPA's Base Case 2003
        cross-walk between boilers and generators.

B5A-1.4    Model Outputs

The IPM® generates a series of outputs on different levels of aggregation  (boiler, model plant, region, and nation).
The economic analysis for Option 6 used a subset of the available IPM® output.  For each model run and for each
model run year (2008, 2010, 2013, and 2020) the following model outputs were generated:

    *•   Capacity - Capacity is a measure of the ability to generate electricity.  This output measure reflects the
        summer net dependable capacity of all generating units at the plant.  The model differentiates between
        existing capacity, new capacity additions, and existing capacity that has been repowered.10

    *•   Early Retirements -  The IPM® models economic closures as a result of negative net present value of
        future operation.11  Under the Phase II analysis, all power plants that retired after the compliance year
        continued to carry the compliance costs after retirement.  This modeling assumption has been changed for
        the Phase III analysis such that power plants with a compliance year in the 2005, 2006, or 2007 model run
        years, if endogenously retired by the model in the 2008 run year, will not carry the cost of the compliance
        decision over their retired life.
    8  For example, a facility with a downtime in 2008 was modeled as if l/5th of its downtime occurred in each year between 2005 and
2009.  A potential drawback of this approach of averaging downtimes over the mapped years is that the snapshot of the effect of
downtimes during the model run year is the average effect; this approach does not model potential worst case effects of above-average
amounts of capacity being down in any one NERC region during any one year.

    9  This information is provided in Schedule IV - Generator Information, Question 3.A (Design flow rate for the condenser at 100%
load).  Design intake flow data at the generator level is not available for nonutilities nor for those utility owned plants with a steam
generating capacity less than 100 MW. Generator-level design intake flow data were not available for 41 of 111 Phase III modeled
facilities and 60 of the 534 Phase II modeled facilities.

    10 Repowering in the IPM® consists of converting oil/gas or coal capacity to combined-cycle capacity. The modeling assumption is
that each one MW of existing capacity is replaced by two MW of repowered capacity.

    11 Under the Phase II analysis nuclear plants were evaluated for economic viability at the end of their license term. Nuclear units that,
at age  30, did not make a major maintenance investment, were provided with a 10-year life extension, if they  were economically viable.
These  same units could subsequently undertake a 20-year re-licensing option at age 40.  Nuclear units that already had made a
maintenance investment were provided with a 20-year re-licensing option at age 40, if they were economically viable. All nuclear units
were ultimately retired at age 60.  Nuclear power plant retirements are no longer endogenous in the 2003 IPM®, and are now consistent
with AEO2003. All other nuclear plants are assumed to remain operating over the modeling time horizon.

                                                                                                          B5A-7

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5
       Energy Price - The average annual price received for the sale of electricity.

       Capacity Price -  The premium over energy prices received by facilities operating in peak hours during
       which system load approaches available capacity.  The capacity price is the premium required to stimulate
       new market entrants to construct additional capacity, cover costs, and earn a return on their investment.
       This price manifests as short term price spikes during peak hours and, in long-run equilibrium, need be
       only so large as is  required to justify investment in new capacity.

       Generation - The amount of electricity produced by each plant that is available for dispatch to the
       transmission grid ("net generation").

       Energy Revenue -  Revenues from the sale of electricity to the grid.

       Capacity Revenue - Revenues received by facilities operating in hours where the price of energy
       exceeds the variable production cost of generation for the next unit to be dispatched at that price in order
       to maintain reliable energy supply in the short run. At these peak hours, the price of energy includes a
       premium which reflects the cost of the required reserve margin and serves to stimulate investment in the
       additional capacity required to maintain  a long run equilibrium in the supply and demand for capacity.

       Fuel Costs  - The cost of fuel consumed in the generation of electricity.

       Variable Operation and Maintenance Costs - Non-fuel O&M costs that vary with the level of
       generation,  e.g., cost of consumables, including water, lubricants, and electricity.

       Fixed Operation and Maintenance Costs  - O&M costs that do not vary with the level of generation,
       e.g., labor costs and capital expenditures for maintenance.  In post-compliance scenarios, fixed O&M
       costs also include annualized capital costs of compliance and permitting costs.

       Capital Costs - The cost of construction,  equipment, and capital. Capital costs are associated with
       investment in new equipment, e.g., the replacement of a boiler or condenser, installation of technologies
       to meet the requirements of air regulations, or the repowering of a plant.
B5A-2    ECONOMIC IMPACT ANALYSIS METHODOLOGY

The outputs presented in the previous section were used to identify changes to economic and operational
characteristics such as capacity, generation, revenue, cost of generation, and electricity prices associated with
Option 6.  EPA developed impact measures at two analytic levels: (1) the market as a whole, including all
facilities and (2) the subset of facilities potentially subject to Phase III regulation. Both analyses were conducted
by NERC region.  The following subsections describe the impact measures used for the two levels of analysis.

B5A-2.1   Market-level Impact Measures

The market-level analysis evaluates regional changes as a result of Option 6.  Seven main measures are  analyzed:

    *•   (1) Changes in available capacity: This measure analyzes changes in the capacity available to generate
        electricity. A long-term reduction in availability may be the result of partial or full closures of plants
        subject to Phase III regulation.  In the short term, temporary plant shut-downs for the installation of Phase
        III compliance technologies may lead to reductions in available capacity.12 When analyzing changes in
    12 Such short-term capacity reductions would not be expressed as changes in available capacity but might affect electricity
generation, production costs, and/or prices.

B5A-8

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5

        available capacity, EPA distinguished between existing capacity, new capacity additions, and
        repowering additions. Under this measure, EPA also analyzed capacity closures.  Only capacity that is
        projected to remain operational in the base case but is closed in the post-compliance case is considered a
        closure as the result of the analyzed option. An option may result in partial (i.e., unit) or full plant
        closures. An option may also result in avoided closures if a facility's compliance costs are low relative to
        other affected facilities. An avoided closure is a unit or plant that would close in the base case but
        operates in the post-compliance case.

    *•   (2) Changes in the price of electricity: This measure considers changes in regional prices as a result of
        Phase III regulation. In the long term, electricity prices may change as a result of increased production
        costs of the potential Phase III facilities. In the short-term, price increases may be higher if large power
        plants have to temporarily shut down to construct and/or install Phase III compliance technologies. This
        analysis  considers changes in both energy prices and capacity prices.

    *•   (3) Changes in generation: This measure considers the amount of electricity generated. At a regional
        level, long-term changes in generation may be the result of plant closures or a change in the amount of
        electricity traded between regions. In the short term, temporary plant shut-downs to install Phase III
        compliance technologies may lead to reductions in generation.  At the national level, the demand for
        electricity does not change between the base case and the analyzed policy options (generation within the
        regions is allowed to vary).  However, demand for electricity does vary across the modeling horizon
        according to the model's underlying electricity demand growth assumptions.

    *•   (4) Changes in revenues: This measure considers the revenues realized by all facilities in the market and
        includes both  energy revenues and capacity revenues (see definition in section B5A-1.4 above). A
        change in revenues could be the result of a change in generation and/or the price of electricity.

    *•   (5) Changes in costs: This measure considers changes in the overall cost of generating electricity,
        including fuel costs, variable and fixed O&M costs, and capital costs. Fuel costs and variable O&M
        costs are production costs that vary with the level of generation. Fuel costs generally account for the
        single largest  share of production costs.  Fixed O&M costs and capital costs do not vary with generation.
        They are fixed in the short-term and therefore do not affect the dispatch decision of a unit (given
        sufficient demand, a unit will dispatch as long as the price of electricity is at least equal to its per MWh
        production costs). However, in the long-run, these costs need to be recovered for a unit to remain
        economically  viable.

    *•   (6) Changes in pre-tax income: Pre-tax income is defined as total revenues minus total costs and is an
        indicator of profitability. Pre-tax income may decrease as a result of reductions in revenues and/or
        increases in costs.

    *•   (7) Changes in variable production costs per MWh: This measure considers the regional change in
        average variable production cost per MWh. Variable production costs include fuel costs and other
        variable  O&M costs but exclude fixed O&M costs and capital costs. Production cost per MWh is a
        primary  determinant of how often a power plant's units are dispatched.  This measure presents similar
        information to total fuel and variable O&M costs under measure (5) above, but normalized for changes in
        generation.

B5A-2.2   Facility-level Impact Measures (Potential Phase III Facilities Only)

EPA used the IPM® results to analyze impacts on potential Phase III facilities at two levels: (1) changes in the
economic and operational characteristics of the potential Phase III facilities as a group and (2) changes to
individual facilities within the group of potential Phase III facilities.

a.   Potential Phase III facilities as a group
                                                                                                    B5A-9

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5

The analysis of the potential Phase III facilities as a group is largely similar to the market-level analysis described
in Section B5A-2.1 above, except that the base case and policy option totals only include the economic activities
of the 111 potentially regulated Phase III facilities represented by the model. In addition, a few measures differ:
(1) new capacity additions and prices are not relevant at the facility level, (2) the number of potential Phase III
facilities that experience closure of all their steam electric capacity is presented, and (3) repowering changes are
not explicitly analyzed at the facility level. Following are the measures evaluated for the group of potential Phase
III facilities:

    *•   (1) Changes in available capacity: This measure considers the capacity available at the  111 potentially
        regulated Phase III facilities.  A long-term reduction in availability may be the result of partial or full
        plant closures, a change in the decision to repower, or a change in the choice of air pollution control
        technologies. In the short term, temporary plant shut-downs for the installation of Phase III compliance
        technologies may lead to reductions in available capacity.13 Under this measure, EPA also analyzed
        regulatory closures.  Only capacity that is projected to remain operational  in the base case but is closed
        in the post-compliance case is considered a closure as the result of the rule.  An option may result in
        partial (i.e., unit) or full plant closures. An option may also result in avoided closures if a facility's
        compliance costs are low relative to other affected facilities. An avoided closure is a unit or plant that
        would close in the base case but operates in the post-compliance case.  At the facility-level, both the
        number of full regulatory closure facilities and closure capacity are analyzed.

    *•   (2) Changes in generation: This measure considers the generation at the 111 potential Phase III facilities.
        Long-term changes in generation may be the result of a reduction in available capacity (see discussion
        above) or the less frequent dispatch of a plant due to higher production cost as a result of the policy
        option.  In the short term, temporary plant shut-downs may lead to reductions in generation at some of the
        111 potential Phase III facilities. For some 316(b) facilities, Phase III regulation may  lead to an increase
        in generation if their compliance costs are low relative to other affected facilities.

    *•   (3) Changes in revenues: This  measure considers the revenues realized by the 111 potential Phase III
        facilities and includes both energy revenues and capacity revenues (see definition in section B5A-1.4
        above). A change in revenues could be the result of a change in generation and/or the price of electricity.
        For some 316(b) facilities, Phase III regulation may lead to an increase in revenues if their generation
        increases as a result of the rule,  or if the rule leads to an increase in electricity prices.

    *•   (4) Changes in costs: This measure considers changes in the overall cost of generating electricity for the
        111 Phase III facilities, including fuel costs, variable and fixed O&M costs, and capital costs.  Fuel costs
        and variable  O&M costs are production costs that vary with the level of generation. Fuel costs generally
        account for the single largest share of production costs. Fixed O&M costs and capital costs do not vary
        with generation. They are fixed in the short-term and therefore do not affect the dispatch decision of a
        unit (given sufficient demand, a unit will dispatch as long as the price of electricity is at least equal to its
        per MWh production costs). However, in the long-run, these costs need to be recovered for a unit to
        remain economically viable.

    *•   (5) Changes in pre-tax income: Pre-tax income is defined as total revenues minus total costs and is an
        indicator of profitability. Pre-tax income may decrease as a result of reductions in revenues and/or
        increases in costs.

    *•   (6) Changes in variable production costs per MWh: This measure considers the plant-level change in the
        average annual variable production cost per MWh. Variable production costs include  fuel costs and other
        variable O&M costs but exclude fixed O&M costs and capital costs.

b.  Individual Phase III facilities
    13 Such short-term capacity reductions would not be expressed as changes in available capacity but might affect electricity
generation, production costs, and/or prices.

B5A-10

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5

To assess potential distributional impacts among individual Phase III facilities, EPA analyzed facility-specific
changes to a number of key measures.  For each measure, EPA determined the number of potential Phase III
facilities that experience an increase or a reduction, respectively, within three ranges: 1% or less, 1 to  3%, and
more than 3%. EPA conducted this analysis for the following measures:

    *•   (1) Changes in capacity utilization: Capacity utilization is defined as a unit's actual generation divided
        by its potential generation, if it ran 100% of the time (i.e., generation / (capacity * 365 days *  24 hours)).
        This measure indicates how frequently a unit is dispatched and earns energy revenues for its owner.

    *•   (2) Changes in generation: See explanation in subsection a. above.

    *•   (3) Changes in revenues: See explanation in subsection a. above.

    *•   (4) Changes in variable production costs per MWh: See explanation in subsection a. above.

    *•   (5) Changes in fuel costs per MWh: See explanation in subsection a. above.

    *•   (6) Changes in pre-tax income: See explanation in subsection a. above.


B5A-3    ANALYSIS RESULTS FOR OPTION 6

The remainder of this section presents the  results of the economic impact analysis of Option 6 for the ten NERC
regions modeled by the IPM®.  Analyzed characteristics include changes in electricity prices, capacity, generation,
revenue, cost of generation, and income. These changes were identified by comparing outcomes in the post-
compliance scenario with outcomes in the  base case.  Because of the interrelationships between the final Phase II
rule (promulgated in July 2004) and regulation of potential Phase III facilities, EPA developed two base cases for
this analysis: the first base case (referred to as Base Case 1) models operational  characteristics of the electricity
market in the absence of any section 316(b) rulemaking (i.e., pre-Phase II regulation); the second base case
(referred to as Base Case 2) models operational characteristics of the electricity  market including compliance
costs of the final Phase II rule (but pre-Phase III regulation).  Results are presented at the market level and the
Phase III facility level.

For the market-level analysis of Option 6,  EPA compared the post-compliance scenario (after the implementation
of Phase III compliance requirements) with Base Case 2 (including Phase II compliance  costs).  This comparison
allows EPA to identify the incremental market-level effects of Phase III requirements, beyond the effects of Phase
II regulation. In contrast, for the analysis of facilities subject to Phase III regulation, EPA compared the post-
compliance scenario with Base Case 1 (excluding Phase II compliance costs). This comparison was done to
determine the "true" effect of Phase III regulation, net of any temporary effects that might be introduced as the
result of the staggering of the three section 316(b) phases.  Because Phase II facilities have to comply  before
Phase III facilities (on average by two years), Phase III facilities may experience a short-term competitive
advantage during the time when Phase II facilities incur section 316(b) compliance costs while Phase III facilities
do not.  The post-compliance economic performance of Phase III facilities should not be compared to  this
potential short-term improvement in operating characteristics but to their steady-state, pre-section 316(b)
rulemaking economic condition.

The following subsections present the market-level analysis (including all facilities, by NERC region) and the
facility-level analysis (including analyses of the in-scope Phase III facilities as a group and of individual Phase III
facilities). The results are presented using data from model run year 2013.  It should be noted that the results
presented in this section are based on Option 6; EPA did not conduct an IPM® analysis for the other options
considered for this proposal. Since Option 6 is the most inclusive and costly of any of the considered options, the
results represent the upper bound estimate of potential economic impacts as a result of proposed Phase III
regulation.  And, as noted above, none of the three proposed options would apply national categorical
                                                                                                  B5A-11

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5
requirements to any electric generating facilities; thus the proposed options have no effects to be considered in an
IPM® analysis.

B5A-3.1   Market Analysis for 2013

This section presents the results of the IPM® analysis for all facilities modeled by the IPM®.  The market-level
analysis includes results for all generators located in each NERC region including facilities that are potentially
subject to Phase III regulation and facilities that are not subject to Phase III regulation.

Table B5A-4 presents the market-level impact measures discussed in section B5A-2.1 above: (1) capacity
changes, including changes in existing capacity, new additions, repowering additions, and closures; (2) electricity
price changes, including changes in energy prices and capacity prices; (3) generation changes; (4) revenue
changes; (5) cost changes, including changes in fuel costs, variable O&M costs, fixed O&M costs, and capital
costs; (6) changes in pre-tax income; and (7) changes in variable production costs per MWh of generation.  For
each measure, the table presents the results for Base Case 2 and Option 6, the absolute difference between the two
cases, and the percentage difference.
Table B5A-4: Market-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
Base Case 2
Option 6 Difference % Change
National Totals
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
992,564
944,254
38,766
9,544
23,213
n/a
n/a
4,592,198
$181,098
$112,839
$64,060
$8,393
$35,689
$4,696
$68,259
$15.78
992,549
944,168
39,008
9,373
23,386
n/a
n/a
4,592,191
$181,026
$112,863
$64,075
$8,394
$35,692
$4,702
$68,164
$15.78
(15)
(86)
241
(171)
173
n/a
n/a
(7)
($72)
$23
$14
$1
$3
$5
($95)
$0.00
0.0%
0.0%
0.6%
(1.8)%
0.7%
n/a
n/a
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
(0.1)%
0.0%
East Central Area Reliability Coordination Agreement (ECAR)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
129,375
127,266
2,109
0
1,699
$28.81
$59.50
711,535
$28,304
129,381
127,264
2,117
0
1,703
$28.81
$59.55
711,438
$28,313
6
(3)
8
0
4
$0.01
$0.05
(97)
$9
0.0%
0.0%
0.4%
0.0%
0.2%
0.0%
0.1%
0.0%
0.0%
B5A-12

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-4: Market-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
Base Case 2
$15,091
$8,423
$1,703
$4,471
$494
$13,213
$14.23
Electric Reliability Council of Texas
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
88,456
80,603
6,622
1,231
178
$39.84
$14.69
343,397
$14,972
$10,490
$6,834
$698
$2,309
$649
$4,481
$21.93
Option 6 Difference
$15,086
$8,423
$1,702
$4,471
$491
$13,226
$14.23
(ERCOT)
88,456
80,722
6,966
768
291
$41.91
$5.48
343,397
$14,873
$10,504
$6,844
$700
$2,311
$650
$4,369
$21.97
($4)
$0
($1)
$0
($3)
$14
$0.00

0
119
345
(463)
113
$2.07
($9.21)
0
($98)
$14
$10
$2
$2
$1
($112)
$0.03
% Change
0.0%
0.0%
(0.1)%
0.0%
(0.6)%
0.1%
0.0%

0.0%
0.1%
5.2%
(37.6)%
63.4%
5.2%
(62.7)%
0.0%
(0.7)%
0.1%
0.1%
0.2%
0.1%
0.1%
(2.5)%
0.2%
Florida Reliability Coordinating Council (FRCC)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
56,655
52,822
1,463
2,370
145
$34.46
$50.55
231,180
$10,831
$7,173
$4,633
$432
$1,870
$238
$3,658
56,655
52,676
1,316
2,662
145
$34.43
$50.82
231,180
$10,838
$7,177
$4,634
$432
$1,868
$243
$3,661
0
(146)
(146)
292
0
($0.04)
$0.28
0
$7
$4
$1
$0
($1)
$5
$3
0.0%
(0.3)%
(10.0)%
12.3%
0.0%
(0.1)%
0.5%
0.0%
0.1%
0.1%
0.0%
0.0%
(0.1)%
2.1%
0.1%
                                                                                                                B5A-13

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-4: Market-Level Impacts of Option 6 (by
Economic Measures
(7) Variable Production Costs ($/MWh)
NERC Region; 2013)
Base Case 2 Option 6 Difference % Change
$21.91
$21.91
$0.00
0.0%
Mid-Atlantic Area Council (MAAC)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
70,973
68,977
1,997
0
949
$31.55
$44.06
314,261
$13,039
$8,131
$3,744
$537
$3,619
$230
$4,908
$13.62
70,973
68,977
1,997
0
949
$31.56
$44.06
314,253
$13,044
$8,131
$3,744
$537
$3,619
$230
$4,913
$13.62
0
0
0
0
0
$0.01
$0.01
(8)
$5
$0
$0
$0
$0
$0
$5
$0.00
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
Mid-America Interconnected Network (MAIN)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
69,770
67,013
2,757
0
0
$27.09
$51.01
332,292
$12,556
$7,690
$3,405
$544
$3,424
$317
$4,866
$11.88
69,770
67,013
2,757
0
0
$27.09
$51.05
332,359
$12,561
$7,692
$3,406
$544
$3,425
$317
$4,870
$11.88
0
0
0
0
0
$0.00
$0.04
68
$5
$2
$1
$0
$1
$0
$3
$0.00
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
Mid-Continent Area Power Pool (MAPP)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
37,368
37,336
32
0
37,368
37,336
32
0
0
0
0
0
0.0%
0.0%
0.0%
0.0%
B5A-14

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-4: Market-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
(Id) Closures
(2a) Energy Prices ($2003MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
Base Case 2
0
$25.58
$40.39
190,058
$6,404
$3,884
$1,968
$370
$1,541
$5
$2,520
$12.30
Northeast Power Coordinating Council
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
77,994
74,198
3,586
210
3,531
$34.95
$30.21
306,579
$13,053
$9,535
$5,248
$439
$3,426
$422
$3,518
$18.55
Option 6 Difference % Change
0
$25.58
$40.42
190,058
$6,406
$3,885
$1,968
$370
$1,542
$5
$2,521
$12.30
(NPCC)
77,982
74,151
3,621
209
3,578
$34.95
$30.21
306,608
$13,054
$9,538
$5,248
$439
$3,426
$424
$3,516
$18.55
0
$0.00
$0.03
0
$2
$1
$0
$0
$1
$0
$1
$0.00

(12)
(47)
35
0
47
$0.00
$0.00
30
$1
$3
$0
$0
$0
$3
($2)
$0.00
0.0%
0.0%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

0.0%
(0.1)%
1.0%
(0.1)%
1.3%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.6%
0.0%
0.0%
Southeastern Electric Reliability Council (SERC)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (Gwh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
218,915
207,416
11,499
0
8,824
$30.48
$47.76
1,065,456
$42,915
$25,995
218,915
207,416
11,499
0
8,824
$30.47
$47.77
1,065,456
$42,912
$25,997
0
0
0
0
0
$0.00
$0.01
0
($3)
$2
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
                                                                                                                B5A-15

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-4: Market-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
Base Case 2 Option 6 Difference % Change
$14,586
$1,839
$8,468
$1,102
$16,921
$15.42
$14,588
$1,839
$8,468
$1,102
$16,915
$15.42
$2
$0
$0
$0
($6)
$0.00
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Southwest Power Pool (SPP)
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/Mwh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
57,806
57,806
0
0
179
$28.05
$13.96
239,392
$7,520
$5,505
$3,582
$472
$1,444
$8
$2,015
$16.93
Western Electricity Coordinating Council
(1) Total Domestic Capacity (MW)
(la) Existing
( Ib) New Additions
(Ic) Repowering Additions
(Id) Closures
(2a) Energy Prices ($2003/MWh)
(2b) Capacity Prices ($2003/KW/yr)
(3) Generation (GWh)
(4) Revenues (Millions; $2003)
(5) Costs (Millions; $2003)
(5a) Fuel Cost
(5b) Variable O&M
(5c) Fixed O&M
(5d) Capital Cost
(6) Pre-Tax Income (Millions; $2003)
(7) Variable Production Costs ($/MWh)
185,252
170,817
8,702
5,733
7,708
$32.62
$20.37
858,050
$31,504
$19,346
$11,638
$1,360
$5,116
$1,232
$12,158
$15.15
57,797
57,797
0
0
188
$28.05
$13.97
239,392
$7,521
$5,506
$3,583
$472
$1,443
$8
$2,015
$16.94
(WECC)
185,252
170,817
8,702
5,733
7,708
$32.62
$20.37
858,050
$31,504
$19,347
$11,638
$1,360
$5,117
$1,232
$12,157
$15.15
(9)
(9)
0
0
9
$0.00
$0.01
0
$1
$1
$1
$0
$0
$0
$0
$0.00

0
0
0
0
0
$0.00
$0.00
0
$0
$1
$0
$0
$1
$0
($1)
$0.00
0.0%
0.0%
0.0%
0.0%
5.0%
0.0%
0.1%
0.0%
0.0%
0.0%
0.0%
(0.1)%
0.0%
(1.9)%
0.0%
0.0%

0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

B5A-16

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5

                Table B5A-4: Market-Level Impacts of Option 6 (by NERC Region; 2013)
               Economic Measures                  Base Case 2       Option 6      Difference       % Change
 Source:  IPM® Analysis: Model runs for Section 316(b) Base Case 2 and Option 6.


Summary of Market Results at the National Level.
The results presented in Table B5A-4 show that capacity closures are estimated to increase by 173 MW, which
represents 0.7% of total baseline capacity. Repowering additions are estimated to experience a net decrease of
171 MW or 1.8%. However, an estimated increase of 241 MW in new additions would offset the lost capacity.
Total costs of electricity generation would not change, but capital costs are estimated to rise  by 0.1%. All other
measures are  estimated to change by less than 1%.

Summary of Market Results at the Regional Level. At the regional level, Option 6 is estimated to result in the
following changes:

    *•  ERCOT is estimated to experience the most notable changes in electricity prices, repowering additions,
       new capacity, and closures among the ten NERC regions. Energy prices increase by $2.07/MWh, which
       represents a 5.2% increase. Capacity prices decrease by $9.21/KW/year, or approximately 63%. This is
       partially due to the increase in energy prices, which allows facilities to bid their undispatched capacity at
       a lower price. This may also be, in part, due to an increase of 345 MW of new additions.  The increased
       new additions are offset by a large decrease in repowering additions (463 MW, or 37.6%). Capacity
       closures increase by  113 MW.  However, these closures occur in facilities that do not fall under Phase III
       regulation. While not subject to regulation these generators retire because there is a decrease in the
       capacity price they are able to receive for existing capacity. As a result of lower capacity prices, pre-tax
       income is also estimated to decrease in ERCOT (2.5%).  All other measures are predicted to change by
       less than 1%.

    >  FRCC is the only region estimated to experience a reduction in new additions (146 MW, or  10%).  It is
       also estimated to lose 146  MW of existing capacity. A projected 292  MW increase in repowering,
       however, would completely offset these reductions. FRCC is estimated to have an increase in capacity
       prices and a decrease in energy prices. However, both changes are less than 1%. All other measures are
       also estimated to change by less than 1%.

    »•  SPP and NPCC are the only regions that are estimated to experience an increase in post-compliance
       capacity closures.  In SPP, the 9 MW increase in closures (5% of Base Case 2 capacity) is due to the
       partial retirement of a potential Phase III facility. In NPCC, the 47 MW increase in closures  (1.3% of
       Base  Case 2 capacity) is the result of combination of partial facility closures and an avoided partial
       facility closure. Specifically, three facilities (two potential Phase III and one Phase II) retire  73 MW of
       capacity while one potential  Phase III facility opts to keep 26 MW of capacity on-line which was retired
       under the baseline. The net result of these changes is a 47 MW increase in closures. There are no
       additional changes in capacity in SPP. However, NPCC is estimated to have an additional 35 MW of new
       additions. The changes in all other measures are less than 1%.

    *•  ECAR is estimated to have the largest decrease in generation (97 GWh).  However, this decrease is
       negligible in comparison to total base case generation  (less than 0.1%). Overall capacity (6 MW),  new
       additions (8 MW), and closures (4 MW, all of which is potential Phase III capacity) increase slightly.
       Capacity prices also increase slightly (0.1%), as does pre-tax income (0.1%). All other measures do not
       change.

    »•  MAAC, MAIN, MAPP, SERC, and, WECC are not estimated to have any significant impacts for any
       of the measures analyzed.  There are no changes in capacity for each region; there is no new  or repowered
       capacity, and there are no additional closures as a result of Option 6.  MAAC is estimated to  have a slight
       increase in energy prices.  Energy prices remain constant in each of the other regions. Each region except
                                                                                                  B5A-17

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5

        WECC experiences a slight increase in capacity prices (on average 0.1%). Generation, revenue, and costs
        are not expected to significantly change for any region. MAAC and MAIN are estimated to have a 0.1%
        increase in pre-tax income.

B5A-3.2   Analysis of Potential Phase III Facilities for 2013

This section presents the results of the IPM® analysis for facilities that are potentially subject to Phase III
regulation and that are modeled by the IPM®. Four of the 111 potential Phase III facilities are closures in Base
Case 1, and five facilities are closures under Option 6.  These facilities are not represented in the results  described
in this section.

EPA used the IPM® results from model run year 2013 to analyze impacts on potential Phase III facilities at two
levels: (1) changes in the economic and operational characteristics of the potential Phase III facilities as  a group
and (2)  changes to individual facilities within the group of potential Phase III facilities.

a.  Potential Phase III facilities as a group
This section presents the analysis of the impacts of Option 6 on the potential Phase III facilities as a group. This
analysis is similar to the market-level analysis described above but is limited to facilities subject to the national
requirements of Option  6. Table B5A-5 presents the  impact measures for the group of potential Phase III
facilities discussed in section B5A-3.2 above: (1) capacity changes, including changes in the number and capacity
of closure facilities; (2)  generation changes; (3) revenue changes; (4) cost changes, including changes in fuel
costs, variable O&M costs, fixed O&M costs, and capital costs; (5) changes in pre-tax income; and (6) changes in
variable production costs per MWh of generation, where variable production cost is defined as the sum of fuel
cost and variable O&M  cost.  For each measure, the table presents the results for the Base Case 1  and Option 6,
the absolute difference between the two cases, and the percentage difference.

Two points should be kept in mind when interpreting these results:

*•   The percentage changes are calculated relative to baseline values of potential Phase III  facilities in each
    region. In some regions, very few facilities are potentially subject to Phase III regulation.  If these percentage
    changes were calculated relative to the total for all electric  power facilities in each region, the observed
    percentage changes  would be much smaller.
*•   The post-compliance scenario reflects compliance costs of both Phase II and Phase III regulation, while the
    base case reflects conditions before either Phase II or Phase III regulation. While Phase II compliance costs
    do not directly affect the analyzed measures for potential Phase III facilities, they do have an indirect effect
    on all facilities within the NERC region, through potential  increases in electricity prices and changes in fuel
    demand.  As a result, measures such as  changes in variable production cost/MWh and pre-tax income might
    be influenced by Phase II compliance costs, rather than Phase III regulation.
B5A-18

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-5: Facility-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
Base Case 1
Option 6
Difference
% Change
National Totals
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
62,075
3
1,047
409,687
$14,165
$8,500
$4,798
$1,129
$2,406
$168
$5,664
$14.47
62,157
4
964
408,609
$14,104
$8,468
$4,761
$1,127
$2,412
$168
$5,637
$14.41
0
1
(82)
(1,078)
($60)
($33)
($37)
($2)
$6
$0
($28)
($0.06)
0.1%
33.3%
(7.8)%
(0.3)%
(0.4)%
(0.4)%
(0.8)%
(0.2)%
0.2%
0.2%
(0.5)%
(0.4)%
East Central Area Reliability Coordination Agreement (ECAR)
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
11,536
0
0
83,922
$3,042
$1,601
$907
$233
$386
$74
$1,441
$13.59
Electric Reliability Council of Texas
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
3,900
0
0
16,418
$684
$445
$246
$65
$123
$11
$239
$18.94
11,532
0
4
83,922
$3,039
$1,601
$907
$233
$387
$74
$1,438
$13.59
(ERCOT)
3,900
0
0
16,482
$657
$448
$249
$65
$123
$11
$209
$19.04
(4)
0
4
0
($3)
$1
$0
$0
$1
$0
($4)
$0.00

0
0
0
64
($27)
$3
$3
$0
$0
$0
($30)
$0.10
0.0%
0.0%
n/a
0.0%
(0.1)%
0.0%
0.0%
0.0%
0.2%
0.0%
(0.3)%
0.0%

0.0%
0.0%
0.0%
0.4%
(3.9)%
0.7%
1.0%
0.5%
0.1%
3.1%
(12.7)%
0.5%
Florida Reliability Coordinating Council (FRCC)

                                                                                                                B5A-19

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-5: Facility-Level Impacts of Option 6 (by
Economic Measures
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
NERC Region; 2013)
Base Case 1 Option 6 Difference % Change
2,447
0
0
13,227
$577
$317
$200
$36
$81
$0
$260
$17.85
2,447
0
0
12,714
$555
$300
$183
$36
$81
$0
$255
$17.21
0
0
0
(513)
($22)
($17)
($17)
($1)
$0
$0
($5)
($0.65)
0.0%
0.0%
0.0%
(3.9)%
(3.8)%
(5.5)%
(8.4)%
(1.7)%
0.0%
0.0%
(1.8)%
(3.6)%
Mid-Atlantic Area Council (MAAC)
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
6,420
0
0
41,996
$1,515
$813
$439
$118
$232
$24
$702
$13.27
6,420
0
0
41,996
$1,529
$812
$438
$118
$232
$24
$717
$13.25
0
0
0
0
$14
($1)
($1)
$0
$0
$0
$15
($0.02)
0.0%
0.0%
0.0%
0.0%
0.9%
(0.1)%
(0.2)%
0.0%
0.0%
0.0%
2.1%
(0.2)%
Mid-America Interconnected Network (MAIN)
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
3,234
0
0
22,247
$778
$443
$267
$56
$95
$25
$335
$14.54
3,234
0
0
22,247
$777
$444
$267
$56
$96
$25
$333
$14.54
0
0
0
0
($1)
$1
$0
$0
$1
$0
($2)
$0.00
0.0%
0.0%
0.0%
0.0%
(0.1)%
0.2%
0.0%
0.0%
0.8%
0.0%
(0.6)%
0.0%
Mid-Continent Area Power Pool (MAPP)
(1) Total Domestic Capacity (MW)
4,379
4,379
0
0.0%
B5A-20

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5

Table B5A-5: Facility-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
Base Case 1
0
0
30,897
$955
$687
$342
$83
$263
$0
$268
$13.73
Northeast Power Coordinating Council
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
845
0
112
791
$62
$40
$17
$2
$21
$0
$21
$24.53
Option 6
0
0
30,897
$953
$687
$341
$83
$263
$0
$265
$13.73
(NPCC)
940
1
16
647
$54
$39
$13
$2
$24
$0
$15
$22.77
Difference
0
0
0
($2)
$1
$0
$0
$1
$0
($3)
$0.00

95
1
(95)
(144)
($8)
($1)
($4)
$0
$3
$0
($6)
($1.75)
% Change
0.0%
0.0%
0.0%
(0.2)%
0.1%
0.0%
0.1%
0.3%
0.0%
(1.0)%
0.0%

11.3%
n/a
(85.6)%
(18.2)%
(12.7)%
(3.5)%
(24.8)%
(18.1)%
15.8%
0.0%
(30.3)%
(7.2)%
Southeastern Electric Reliability Council (SERC)
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
11,967
1
207
88,265
$3,104
$1,859
$1,211
$210
$403
$34
$1,245
$16.10
11,967
1
207
88,265
$3,106
$1,857
$1,209
$210
$403
$34
$1,249
$16.08
0
0
0
0
$2
($2)
($2)
$0
$0
$0
$4
($0.02)
0.0%
0.0%
0.0%
0.0%
0.1%
(0.1)%
(0.2)%
0.0%
0.0%
0.2%
0.3%
(0.1)%
Southwest Power Pool (SPP)
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
4,391
0
4,382
0
(9)
0
(0.2)%
0.0%
                                                                                                                B5A-21

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1
to Chapter B 5

Table B5A-5: Facility-Level Impacts of Option 6 (by NERC Region; 2013)
Economic Measures
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
Base Case 1 Option 6 Difference % Change
0
14,995
$457
$381
$211
$41
$129
$0
$76
$16.81
Western Electricity Coordinating Council
(1) Total Domestic Capacity (MW)
(la) Closures - Number of Facilities
(Ib) Closures - Capacity (MW)
(2) Generation (GWh)
(3) Revenues (Millions; $2003)
(4) Costs (Millions; $2003)
(4a) Fuel Cost
(4b) Variable O&M
(4c) Fixed O&M
(4d) Capital Cost
(5) Pre-Tax Income (Millions; $2003)
(6) Variable Production Costs ($2003/MWh)
12,956
2
728
96,928
$2,992
$1,916
$957
$284
$674
$0
$1,077
$12.81
9
14,510
$441
$364
$196
$40
$129
$0
$77
$16.22
(WECC)
12,956
2
728
96,928
$2,995
$1,916
$957
$284
$675
$0
$1,079
$12.81
9
(485)
($15)
($17)
($15)
($1)
$0
$0
$1
($0.59)

0
0
0
0
$2
$0
$0
$0
$0
$0
$2
$0.00
n/a
(3.2)%
(3.4)%
(4.4)%
(7.2)%
(3.4)%
(0.1)%
0.0%
1.7%
(3.5)%

0.0%
0.0%
0.0%
0.0%
0.1%
0.0%
0.0%
0.0%
0.0%
0.0%
0.2%
0.0%
Source: IPM® analysis: Model runs for Section 316(b) Base Case 1 and Option 6.
Summary of Potential Phase III Facility Results at the National Level. The results presented in Table B5 A-5
show that Option 6 would lead to one facility closure, and 82 MW (0.1% of Base Case 1 capacity) of avoided
capacity closures. This outcome is the net result of two avoided partial facility closures (potential Phase III
facilities with relatively low compliance costs that become more competitive relative to facilities with which they
compete), one full policy closure, and two partial policy closures.  It should be  noted that all four facilities
estimated to experience partial or full closures under Option 6 did not generate  any electricity under Base Case 1.
All four facilities are oil and gas-fueled facilities that served only reliability purposes.  In addition, generation,
revenues, and overall costs would all decrease under Option 6 but by less than 1%.  Fixed O&M costs, which
include the capital cost of compliance, are projected to increase by 0.2%. Pre-tax income for the group of
potential Phase III facilities would decrease by 0.5%.

Summary of Potential Phase III Facility Results at the Regional Level.  Results vary somewhat by region. For
many regions, impacts follow the general pattern described in the comparison to the market level above:
generation, revenues, and pre-tax income decrease.  Overall costs decrease in many regions due to lower levels of
generation but increase in other regions where the additional compliance costs outweigh the reduction in
generation.  In addition to these general patterns, EPA estimates that Option 6 would result in the following
changes:

    *•   NPCC is the only region estimated to experience an increase in total capacity, gaining 95 MW (11.3% of
        Base Case  1  capacity) under Option 6. This outcome is the net result of two avoided partial facility
B5A-22

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5

        closures, and one full policy closure. Potential Phase III facilities in NPCC are estimated to experience
        the largest relative reductions in generation and revenues of any NERC region (18.2% and 12.7%,
        respectively).  The reduction in generation is attributable to two facilities that are projected to experience
        an increase in variable production costs. All potential Phase III facilities in NPCC are estimated to
        experience at least some reduction in revenues due to the estimated decrease in capacity prices (see Table
        B5A-4). Potential Phase III facilities in NPCC are also estimated to experience the largest relative
        reduction in pre-tax income (30.3%) of any region. Though the aforementioned changes are significant
        on percentage basis, they are relatively minor in absolute terms and consistent with the changes seen in
        the other regions. The only measure for which NPCC experiences the largest change on both a
        percentage basis and in absolute value is variable production costs.

    *•   ECAR and SPP are the only regions projected to experience a net reduction in capacity due to Option 6.
        In ECAR 4 MW are estimated to retire, or less than 0.1% of ECAR's Base Case 1 capacity. In SPP 9
        MW are estimated to retire, or 0.2% of SPP's Base Case 1 capacity. Neither region experiences changes
        in generation as a result of these partial closures. In addition, none of the 13 MW of retired capacity were
        dispatched under the Base Case 1.

    *•   ERCOT is the only region projected to experience an increase in Phase III generation under Option 6,
        gaining 64 GWh, or 0.4%.  However, potential Phase III facilities in ERCOT are also estimated to see the
        largest reductions in revenues ($27 million) and pre-tax incomes ($30 million). Revenues decrease even
        though generation in the region increases due to the large drop in capacity prices (see Table B5A-4).
        Specifically, the projected $93 million increase in energy revenues are offset by the projected $120
        million decrease in capacity revenues.

    *•   Potential Phase III facilities in FRCC are estimated to experience a 513 GWh reduction in generation
        (3.9%) due to Option 6. As a result, revenues decrease  in by 3.8%, fuel costs decrease by 8.4%, and
        variable O&M costs decrease 1.7%.

    >   MAAC, MAIN, and MAPP, SERC and WECC are  estimated to experience relatively small changes in
        pre-tax income (between -1.0% and 2.1%).  The changes in all other measures are less than 1% in these
        regions.

b.   Individual facilities potentially subject to Phase III regulation
In addition to the effects of Option  6 on potential Phase III facilities as a group, there may be shifts in economic
performance among individual facilities potentially subject to Phase III regulation.  To assess such potential
shifts, EPA analyzed facility-specific changes in (1) capacity utilization (defined as generation divided by
capacity multiplied by the number of hours per year - 8,760); (2) generation; (3) revenues; (4) variable production
costs per MWh of generation (defined as variable O&M cost plus fuel cost divided by generation); (5) fuel cost
per MWh of generation; and (6) pre-tax income. For each measure, EPA determined the number of potential
Phase III facilities that experience no changes, or an increase or a reduction within three ranges: 1% or less, 1 to
3%, and more than 3%.

Table B5A-6 presents the total number of potential Phase III facilities  with different estimated degrees of change
due to Option 6.  This table excludes four facilities with estimated significant status changes in 2013: three
facilities are baseline closures, and  one facility  is a full closure as a result of Option 6. These facilities are either
not operating at all in either Base Case 1 or the  post-compliance case, or they experience fundamental changes in
the type of units they operate; therefore, the measures presented in Table B5A-6 would not be meaningful for
these facilities. In addition, the change in variable production cost per MWh of generation could not be
developed for six  facilities with zero generation in either Base Case 1 or the post-compliance scenario.  For these
facilities, the change in variable production cost per MWh is indicated as "n/a."
                                                                                                   B5A-23

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
Appendix 1 to Chapter B5
          Table B5A-6: Number of Potential Phase III Facilities with Operational Changes (2013)



(1) Change in Capacity Utilization
(2) Change in Generation
(3) Change in Revenues
(4) Change in Variable Production
Costs/MWh
(5) Change in Fuel Costs/MWh
(6) Change in Pre-Tax Income
Reduction
3%
8
8
15
1

1
32
Increase
3%
4
4
4
1

1
1
No

Change
95
95
31
66

70
14

N/A

0
0
0
6

6
0
 a   For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 1 Oth of a percent.
 b   The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post-
     compliance case.  For all other measures, the change is expressed as the percentage change between the base case and post-
     compliance values.
 Source: Model runs for Section 316(b) Base Case 1 and Option 6.


Table B5A-6 indicates that the majority of potential Phase III facilities would not experience changes in capacity
utilization, generation, fuel costs per MWh, or variable production costs per MWh due to compliance with Option
6.  Of those facilities with changes in post-compliance capacity utilization, generation, fuel costs per MWh, and
variable production costs per MWh, most would experience decreases in these measures. Changes in revenues at
most potential Phase III facilities would also not exceed 1.0%.  The largest effect of Option 6 would be on
facilities' pre-tax income: about 64% of facilities would experience a reduction in pre-tax income, with 30%
experiencing a reduction  of 3% or greater. These reductions are due to a combination of reduced revenues and
increased compliance costs.


B5A-4    SUMMARY IPM®V.2.1.6 UPDATES

Table B5AA-1 below presents a summary of the series of updates that were incorporated in EPA modeling
applications using the Integrated Planning Model (IPM®) in the Spring of 2003.  Designated Version 2.1.6, the
latest available data were used to update key model parameters in the EPA Base Case and associated policy cases
in preparation for performing analyses in conjunction with Congressional consideration of the Administration's
Clear Skies Initiative.

This table and its accompanying report, Documentation Supplement for EPA Modeling Applications (V.2.1.6)
Using the Integrated Planning Model (U.S. EPA, 2003), is a supplement to the comprehensive documentation of
EPA's applications of IPM® as reported m Documentation of EPA Modeling Applications (V.2.1) Using the
Integrated Planning Model (U.S. EPA, 2002). The supplementary report  consists of the summary table presented
below and a series of attachments providing details of specific updates.  To help readers track the parameters that
were updated, Table B5AA-1 contains cross references to the earlier documentation report. Parameters not
included in Table B5AA-1 remained unchanged.  Both the supplemental and comprehensive documentation is
available for viewing and downloading at www.epa.gov/airmarkets/epa-ipm.
B5A-24

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                                                                               Appendix 1 to Chapter B5
                             Table B5AA-1 Summary Table of IPM® V.2.1.6 Updates
   ID
Feature
Description
Doc. Report
  Section1
 Power System Operations Assumptions
  1       Revised aggregation scheme

         ("Documentation for v.2.1"
         refers to the report
         Documentation of EPA
         Modeling Applications (V.2.1)
         Using the Integrated Planning
         Model, EPA 430/R-02-004
         (March 2002), which is
         available for viewing and
         downloading at
         www.epa.gov/airmarkets/epa-
         ipm.
                   The aggregation scheme was revised to enable modeling emission         3.1
                   scenarios in geographical areas most likely to be of future interest. Table   4.2.6
                   A-1 in Attachment A updates the crosswalk between actual and model      Appendix A4.1
                   plants that was previously presented as Table 4.7 in the documentation
                   for v.2.1. Table A-2 and the accompanying map provides details on the
                   geographical aggregation scheme used in the v.2.1.6.
         Electricity Demand Growth:
         @ 1.55% indexed on AEO
         2003 electricity sales
         projections.

         (AEO 2003 refers to Annual
         Energy Outlook 2003 with
         Projections to 2025,
         DOE/EIA-0383(2003),
         released by the U.S.
         Department of Energy's
         Energy Information
         Administration on January 9,
         2003.)
                   1. As was done in EPA's previous applications of IPM®, calculations
                   were performed to account for efficiency improvements not factored into
                   AEO 2003's projections of electricity sales. This resulted in a 2000-2020
                   adjusted electricity growth rate of 1.55% per year.

                   Attachment B provides details.
                                        3.2.1
                                        3.2.2
                                        Appendix A3.1
3
4
5
6
State Multi-Pollutant
Regulations
New Source Review (NSR)
Settlements
State Renewable Energy
Programs
State Renewable Portfolio
Standards (RPS)
Attachment C lists the state multipollutant programs incorporated in
v.2.1.6.
Attachment D shows the settlements under New Source Review
provisions of the Clean Air Act that were included in v. 2. 1 .6.
V. 2. 1 .6 incorporates the capacity shown in Table 76 in the AEO 2003
assumptions document. Entitled "Planned 2002+ U.S. Central Station
Generating Capacity Using Renewable Resources," the table captures the
effects of state renewable energy programs in its projection of both
existing and forecasted renewable capacity. Table 76 appears on pp. 131-
133 of the document "Assumptions for the Annual Energy Outlook
2003," which can be found on the Web at
www.eia.doe.gov/oiaf/aeo/assumption/pdf/0554(2003).pdf
V. 2. 1 .6 does not endogenously model RPS beyond the capacity already
implicit in Table 76 "Planned 2002+ U.S. Central Station Generating
Capacity Using Renewable Resources." (See previous item for
information on locating this table.)
3.9
3.9.3
3.9.4
(Not covered)
3.9.4
(Not covered)
         Emission and removal rate
         assumptions for potential
         units.
                   The emission and removal rates are the same as in AEO 2003, i.e.,
                                                     NOx Rates       SO2 Rates
                   Conventional Pulverized Coal (CPC)  0.11 Ib/mmBtu    95% Removal
                   Integrated Gasification Combined Cycle
                   (IGCC)                           0.021b/mmBtu    99% Removal
                   Combined Cycle (CC)               0.02 Ib/mmBtu    —
                   Combustion Turbine (CT)           0.08 Ib/mmBtu    —

                   These differ from the removal rates in v. 2.1 (also called EPA Base Case
                   2000).  See  Attachment E for a detailed breakdown of the differences.
                                        3.9.5
                                                                                                                 B5A-25

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                                                                                          Appendix 1 to Chapter B5
Table B5AA-1 Summary Table of IPM® V.2.1.6 Updates
ID
Feature Description
Doc. Report
Section1
Generating Resources

National Electric
Energy Data System (NEEDS) Changes
4.1
4.2
         The following changes were made to NEEDS, the database that serves as the source of all currently
         operating and planned/committed units represented in v.2.1.6.
  8a
AES Deepwater Unit
The AES Deepwater generating unit in Texas (ID #10670_G_GEN1) was
identified as combusting fossil waste in NEEDS 2000 (used for the EPA
Base Case 2000, v2.1) but as combusting oil in EPA's Emissions and
Generation Resource Integrated Database (EGRID).  Further investigation
revealed that this unit burned petroleum coke and some oil. To give a
more accurate representation of its mercury emissions, in v. 2.1.6 the unit
was designated as combusting petroleum coke and assigned a
corresponding mercury emission rate of 23.18 Ib/TBtu (dry).
  8b     Mercury Emission Rates for
         Existing Geothermal Units
                             Based on recent information obtained by EPA, mercury emission rates
                             were updated to 2.97 Ibs/TBtu for existing geothermal units in California
                             and 3.65 Ibs/TBtu for existing geothermal units in the IPM® model region
                             NWPE. In addition, 29 MW of existing geothermal capacity was
                             identified in the AZNM model region and 8 MW in the PNW model
                             region and assigned an emission rate of 3.70 Ibs/TBtu, the same emission
                             rate as assigned to new potential geothermal units in v.2.1.6. (See item
                             #10 below.)
  8c
  8d
Hawthorn Unit 5
This 550 MW coal unit was added to NEEDS, v. 2.1.6.
Updated information on unit
closures
Units that were shown as retired or out of service in 2000 EIA 860a were    4.2
removed from the NEEDS database as part of the v.2.1.6 update.  Based
on supplemental information, Ashtabula units 8, 10 and 11, Arapahoe
units 1 and 2, Arkwright units 1-4, 5A, 5B,and Mitchell units 1 and 2
were also removed from the NEEDS population, either because they were
retired or out of service.
  8e


  8f
Life Extension Costs
A life extension cost of $5/kW-yr is added to every fossil plant that
reaches an age of 30 years. This assumption is based on AEO 2003.
4.2.4 and 4.3.4
SO2, NO^, and Particulate
Controls
The inventory of SO2, NOX, and particulate controls in v.2.1.6 was
derived from U.S. EPA's Emission Tracking System, 2002, Quarter 2,
supplemented by corroborated information obtained from utilities, control
technology vendors, state and regional regulatory agencies, and trade
publications and announcements.
4.2.5
                                      Attachment F shows the inventory of emission controls on existing
                                      generating units that are included in v.2.1.6.
         Updated planned/committed
         capacity
                             Existing and planned/committed units in NEEDS 2.1.6 were derived from
                             the following data sources:
                             Period            Source
                             1998 and earlier   NEEDS 2000
                                                                    4.3
                                      All planned/committed capacity after 1998 in NEEDS 2000 was removed
                                      and replaced with the following data.
                                      1999-2000        EIA 860, as released in year 2000. EIA 860 shows
                                                        operating units for these years.
                                      2001              RDI. (Updated through the July 2002 release of the
                                                        RDI database.)
                                      2002-2005        AEO 2003 or RDI. AEO 2003 was used for
                                                        renewable (biomass, geothermal, landfill gas, hydro,
                                                        pumped storage, solar, and wind) and non-
                                                        conventional generating  units (fuel cells) due to the
                                                        Energy Information Administration's (EIA) extensive
B5A-26

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                                                                                 Appendix 1 to Chapter B5
                             Table B5AA-1  Summary Table of IPM® V.2.1.6 Updates
   ID
Feature
Description
Doc. Report
  Section1
                                                        research in this area for AEO 2003.  The RDI
                                                        database (up through the July 2002 release) was used
                                                        for conventional generating units (coal steam,
                                                        combined cycle turbines, combustion turbines, fossil
                                                        and non-fossil waste) since it was more current than
                                                        AEO 2003.
                                       Attachment G lists the planned/committed units included in NEEDS 2.1.6
                                       and gives a detailed summary of the data sources used.
         Cost and Performance of
         Potential (New) Capacity
         from Conventional Generating
         Units
                    The cost and performance assumptions for new (potential) conventional
                    pulverized coal, integrated gasification combined cycle, combined cycle,
                    advanced combined cycle, and combustion turbine units were updated
                    based on AEO 2003. See Attachment H for details.
                                         4.4.2
  10      Mercury emissions for new
         (potential) geothermal units
                    Based on recent information obtained by EPA, the mercury emission rate
                    for new (potential) geothermal plants was updated to 3.70 Ibs/TBtu in
                    v.2.1.6, compared to 4.08 Ibs/TBtu in v.2.1. (See item 8b above for a
                    description of related updates  of the mercury emission rates for existing
                    geothermal plants.)
                                         4.4.3
                                         5.3.1
 Existing Nuclear Units
  11 a    Cost and performance
                    1.  To provide maximum granularity in forecasting the behavior of
                    nuclear units, 102 out of the 103 existing nuclear units in v.2.1.6 are
                    represented by separate model plants. (Note: All nuclear generating
                    units, except Browns Ferry units 1 and 2 are represented by a separate
                    model plant.  In the v.2.1.6 base case, Browns Ferry Unit 1, which is
                    projected to be brought out of mothballs, is represented by the same
                    model plant as Browns Ferry Unit 2. See item lie below for further
                    details.) In v.2.1, the 103 existing nuclear units were represented by 47
                    model plants.
                    2.  AEO 2003 cost and performance assumptions were implemented.
                    These include
                    (a) Variable operations and maintenance (VOM), fixed operations and
                    maintenance (FOM), and fuel cost assumptions as in AEO 2003.
                    Attachment I details the cost assumptions included in v. 2.1.6.
                    (b) AEO 2003 assumption of cost incurred from age 30, i.e., an addition
                    of $50/Kw/yr to annual FOM costs starting at age 30.
                    (c) Availability assumptions are expressed in terms of capacity factors,
                    which are based on AEO 2003. As in AEO 2003, v. 2.1.6 assumes two
                    vintages of existing nuclear units, based on whether a unit's start date
                    occurs before or after 1982. For the older vintage, the capacity factor
                    increases 0.5 percentage point per year through age 25, stays flat from 25-
                    40, and then declines by 0.5% point after 40. The capacity factor of a
                    newer vintage unit increases by 0.7 percentage point per year through age
                    30, is flat from 30-40, and declines by 0.5% point after age 40. The
                    maximum capacity factor is assumed to be 90%. Any plant starting with a
                    capacity factor above 90% just remains at  its current level, at least until it
                    is old enough to start declining.
                    3.  In v.2.1.6 existing nuclear units are constrained to retain the same
                    retirement pattern as in AEO 2003.
                                         4.5
                                         Appendix 4.4
  lib    Upratings
                    All the nuclear capacity uprating assumptions that are in AEO 2003 were    4.5
                    incorporated in NEEDS 2.1.6.                                          Appendix 4 4


                    A listing of all upratings appears in Attachment J.
  lie     Browns Ferry Unit 1
                    V. 2.1.6 uses the same assumptions about this TVA unit being brought
                    out of mothballs as in AEO 2003, i.e.,
                    1. The unit has a zero capacity factor (availability) until 2007. Starting
                                         4.5
                                         Appendix 4.4
                                                                                                                    B5A-27

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                                                                                         Appendix 1 to Chapter B5
                             Table B5AA-1 Summary Table of IPM® V.2.1.6 Updates
   ID
          Feature
                                                               Description
  Doc. Report
    Section1
                                      in 2007, it can operate up to a 75% capacity factor.
                                      2. Like other existing nuclear units its capacity factor grows by 0.7% per
                                      year until it reaches a maximum of 90%.
                                      3. Its costs were assumed to be the same as those for Browns Ferry Unit
                                      2.
 Emission Control Technologies
  12      Selective Non-Catalytic
         Reduction (SNCR) Control of
         NOx Emissions
                             In v. 2.1.6 SNCR is available as an emission control retrofit option for all
                             coal plants >25 MW and < 200 MW rather than to all plants > 25, as in
                             v.2.1. In both v.2.1 and v.2.1.6 SNCR is available to all oil/gas steam
                             units > 25 MW.
                                                                                                        5.2.2
  13      Gas Rebum Option for NOx
         Control at coal fired plants
                             To reduce model size, this option, which was provided in v 2.1, was not
                             offered in v2.1.6.
                                                                                                        5.2.2
  14      Mercury Emission
         Modification Factors (EMFs)
                             Mercury emission modification factors are multipliers that represent the
                             extent of mercury removal achieved by various configurations of NOX,
                             SO2 and particulate emission controls at coal fired generating units.
                             Based on additional information received on the performance of these
                             controls, mercury EMFs were updated. Attachment K shows the mercury
                             EMFs used in v. 2.1.6.
                                                                                                        5.3.2
                                                                                                        5.3.3
                                                                                                        Appendix A5.4
  15      Mercury Control Using
         Activated Carbon Injection
         (ACI)
                             Instead of modeling ACI with an 80% mercury removal rate, as was done
                             in v. 2.1, v.2.1.6 has the capability to provide two concurrent ACI options
                             of 60% and 90% mercury removal. The two options could be used for
                             special mercury analyses.  However, v. 2.1.6 will use an ACI mercury
                             removal rate of 90% for typical analyses. Due to constraints on model
                             size and run time, the 60% removal option is intended to be applied only
                             on selected sensitivity analysis runs.
                                                                                                        5.3.3
                                                                                                        Appendix A5.3
16     Mercury Control Costs Using
       ACI
                                      Based on information received from ACI vendors as an outgrowth of the
                                      Mercury MACT FACA process, the cost and injection rates for ACI were
                                      revised. ("Mercury MACT FACA process" refers to the advisory
                                      committee set up under the Federal Advisory Committee Act (FACA) to
                                      enable EPA to obtain input on proposed regulations governing maximum
                                      achievable control technology (MACT) for mercury removal from
                                      electric generating units.)
                                                                                                Appendix
                                                                                                A5.3.2
                                      (See Attachments LI and L2 for a complete development of the ACI cost
                                      equations used in v. 2.1.6.)
 Financial Assumptions
  17     Revised financial assumptions
         for Integrated Gasification
         Combined Cycle (IGCCs)
         plants.
                             With the following exceptions, the financial assumptions in v.2.1.6 are
                             the same as in EPA Base Case 2000 (v.2.1): IGCCs and Repowerings-to-
                             IGCCs are assigned the discount rate (DR) and capital charge rate (CCR)
                             associated with high (rather than medium) risk investments, i.e., DR =
                             6.74%, not 6.14%. CCR = 13.4%, not 12.9%
 Fuel Assumptions
  18
Coal Supply Curves
                                     To provide greater consistency between the v.2.1.6 and the AEO 2003
                                     coal supply curves, the regional coal supply curves in v.2.1.6 were
                                     adjusted to reflect the percentage change in labor productivity assumed
                                     in AEO 2003.  The coal transportation cost escalation rates in v.2.1.6
                                     were also made consistent with those assumed in AEO 2003.  See
                                     Attachment M for a presentation of the AEO 2003 labor productivity and
                                     transportation escalator assumptions.
  19
Natural Gas Supply Curves
                                    Updated gas supply curves were generated using ICF Consulting Inc.'s
                                    North American Natural Gas Analysis System (NANGAS) model. Key
                                    activities included:
                                    1. Gas supply curves were developed for the 2005-2025, modeling
8.2
Appendix 8.1
B5A-28

-------
§ 316(b) Proposed Rule: Phase III — EA, PartB: Economic Analysis for Existing Facilities
                                                                                         Appendix 1 to Chapter B5
                             Table B5AA-1 Summary Table of IPM® V.2.1.6 Updates
   ID
          Feature
                           Description
Doc. Report
  Section1
                                      horizon, rather than the 2005-2020 period used earlier.
                                      2. Earlier optimistic technology assumptions, developed for the
                                      Department of Energy's National Energy Technology Laboratory's
                                      (NETL), were reviewed and revised resulting in a somewhat less
                                      optimistic technology perspective.
                                      3.  The Gulf of Mexico East drilling moratorium was incorporated in
                                      NANGAS.
                                      4.  EIA success rates for Gulf of Mexico offshore were adopted.
                                      5.  Pipeline links were checked to ensure correct gas flow, e.g., making
                                      sure the Rockies-Southwest link shows gas flows from the Rockies to the
                                      Southwest rather than the reverse.
                                      6.  Seasonal transportation adders were updated.
                                      7.  Four initial NANGAS runs were performed to cover the range of
                                      anticipated electric demand growth rates. A separate NANGAS run was
                                      performed at electric demand annual growth rates of 1.1%, 1.55% (EPA's
                                      CCAP adjusted growth rate), 1.88% (approximating the AEO 2003
                                      Reference Case electricity sales growth rate), and 2.2%.
                                      8.  Outputs from the four runs were used to produce an initial set of
                                      natural gas supply curves for incorporation in IPM®.
                                      9.  A series of iterations was performed between NANGAS and IPM®
                                      until convergence was achieved in the IPM® and NANGAS electric sector
                                      results.  The gas supply curves generated by this process were
                                      incorporated in v.2.1.6.


                                      Attachments N contains the natural gas supply curves used in v. 2.1.6 for
                                      each model run year and the seasonal transportation adders.
 20      Oil prices consistent with
         AEO 2003
                             1.  V. 2.1.6 fuel prices for distillate oil and high and low sulfur residual
                             oil were based on the AEO 2003. The prices used in v.2.1.6 are shown in
                             Attachment O together with the AEO 2003 source data from which the
                             prices were derived.
                             2.  The sulfur content for these fuels were defined to be consistent with
                             AEO 2003, i.e.,
                                Fuel                        Sulfur Content
                                Distillate                   0.3
                                Residual: Low Sulfur        1.08
                                Residual: High Sulfur        2.69
 Miscellaneous Other Features
 21
SO, allowance bank
An SO2 allowance bank of 6.414 million tons (going into 2005) was
assumed.
 22      Feasibility constraint on the
         maximum amount of SO2
         scrubbers that can be built in
         2005 under the v.2.1.6 Clear
         Skies run
                             The maximum amount of SO2 scrubbers that could be built in 2005 was
                             limited to 5066 MW in the Clear Skies run.  This is consistent with recent
                             EPA assessments of the short-term feasibility of scrubber installations.
 1   This column indicates the most closely related sections in Documentation of EPA Modeling Applications (V. 2.1) Using the
     Integrated Planning Model (U.S. EPA, 2002).

 Source:    U.S. EPA, 2003.
                                                                                                                  B5A-29

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                Appendix 1 to Chapter B5

B5A-5  UNCERTAINTIES AND LIMITATIONS

There are uncertainties associated with EPA's electric power market and economic impacts analyses conducted in
developing the proposed rule:

Demand for electricity: The IPM® assumes that electricity demand at the national level would not change
between the base case and the policy case (generation within the regions is allowed to vary).  Under the base case
specifications, electricity demand is based on the AEO 2003 forecast.14  The IPM® model, as specified for this
analysis, does not capture changes in demand that may result from electricity price increases associated with
Option 6.  While this constraint may overestimate total demand in policy options that have high compliance cost
and that may therefore lead to significant price increases, EPA believes that it does not affect the results obtained
in developing the proposed rule. As described in Section B5A-3 above, the price increases associated with the
Option 6 in most NERC regions are relatively small. EPA therefore  concludes that the assumption of inelastic
demand-responses to changes in prices is reasonable.

   *•  International imports: The IPM® assumes that imports from Canada and Mexico would not change
      between the base case and the policy case.  Holding international imports fixed would provide a
      conservative estimate of production costs and electricity prices under Option 6, because imports are not
      subject to Phase III regulation and may therefore become more competitive relative to domestic capacity,
      displacing some of the more expensive domestic generating units. On the other hand, holding imports
      fixed may understate  effects on marginal domestic units, which may be displaced by increased imports.
      However, EPA concludes that fixed imports do not materially affect the results of the analyses. In 2013
      only four of the ten NERC regions import electricity (ECAR, MAPP, NPCC, and WECC) and the level of
      imports compared to domestic generation in each  of these regions is very small (from less than 0.01% in
      ECAR, to 2.75% in NPCC).

   >  Repowering: For the  section 316(b) analysis, EPA is not using the IPM® function that allows the model to
      pick among a set of compliance responses. As a result, there is no iterative process that would adjust the
      compliance response  (and as a result the cost of compliance) if a facility chooses to repower.  Repowering
      in the IPM® typically consists of the conversion of existing oil/gas or coal capacity to new combined-cycle
      capacity. The modeling assumption is that each one MW of existing capacity is replaced by two MW of
      repowered capacity.  This change in plant type and size might lead to a change in intake flow and
      potentially to different compliance requirements and costs.  Since combined-cycle facilities require
      substantially less cooling water than other oil/gas  or coal facilities, the effect of repowering is likely to be a
      reduction in cooling water requirements (even considering the doubling of the plant's capacity).  As a
      result, not allowing the model to adjust the compliance response or cost is likely to lead to a conservative
      estimate of compliance costs and potential economic impacts from Option 6.

   *•  Downtime associated with installation of compliance technologies: EPA estimates that the installation of
      several compliance technologies would require the steam electric generators of facilities that are projected
      to install such technologies to be off-line. Downtimes under Option 6 are estimated to be either 2 or 9
      weeks, depending  on  the technology. Generator downtime is estimated to occur during the year when a
      facility complies with Option 6. Since the years that are mapped into a run year are assumed to have the
      same characteristics as the run year itself, generator downtimes were applied as an average over the years
      that are mapped into each model run year. For example, years 2010 to 2012 are all mapped into 2010.
      Therefore, a facility with a downtime in 2011 was modeled as if 1/3rd of its downtime  occurred in each
      year between 2010 and 2012. A potential drawback of this approach of averaging downtimes over the
      mapped years is that the snapshot of the effect of downtimes during the model run year is the average
    14 EPA also considered conducting an analysis under a third base case adjusted to account for demand reductions resulting from
implementation of the Climate Change Action Plan (CCAP) as was done for the Phase II analysis.

B5A-30

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities                 Appendix 1 to Chapter B5

      effect; this approach does not model potential worst case effects of above-average amounts of capacity
      being down in any one NERC region during any one year.
                                                                                                     B5A-31

-------
§ 316(b) Proposed Rule: Phase III — EA, Part B: Economic Analysis for Existing Facilities               Appendix 1 to Chapter B5
                           THIS PAGE INTENTIONALLY LEFT BLANK
B5A-32

-------
§ 316(b) Proposed Rule: Phase III-EA, Part C: Economic Analysis for Phase III New OOGE Facilities
                              Cl: Summary of Costs
    Chapter  Cl:  Summary of Cost  Categories
and Key Analysis  Elements for New  Offshore
             Oil and Gas Extraction  Facilities
INTRODUCTION

This chapter presents an overview of the cost
categories and certain elements of the analytic
framework that are common to the economic analyses
of the two major industry segments covered by the
proposed standards for new Offshore Oil and Gas
Extraction facilities: mobile offshore drilling units
(MODUs) and oil and gas production platforms or
structures.
CHAPTER CONTENTS
Cl-l Cost Categories	Cl-1
    C1 -1.1 Cost of Installing and Operating
         Compliance Technology	Cl-1
    Cl-1.2 Administrative Costs for Complying
         Facilities	Cl-3
Cl-2 Key Elements of the Economic Analysis for New
    Offshore Oil and Gas Extraction Facilities  .... Cl-7
    Cl-2.1 Compliance Schedule	Cl-7
    Cl-2.2 Adjusting Monetary Values to a
         Common Time Period of Analysis  .... Cl-8
    Cl-2.3 Discounting and Annualization -
         Costs to Society or Societal Costs	Cl-9
    Cl-2.4 Discounting and Annualization -
         Costs to Complying Facilities	Cl-11
                                               References 	Cl-13
Cl-1  COST CATEGORIES

In its analyses of the costs and economic impacts of
the proposed rule on new oil and gas extraction
facilities, EPA considered three categories of costs:

    *•   costs of installing and operating compliance technology,
    *•   administrative costs incurred by complying facilities, and
    *•   administrative costs incurred by permitting authorities.

In contrast to the analysis conducted for the Manufacturing and Electric Generating industry segments (see also
Chapter Bl), EPA assumed that no downtime would be associated with installing or maintaining CWIS
technologies for new offshore oil and gas extraction facilities, for two reasons.  First, new facilities do not have to
retrofit equipment; the equipment is built to specification and installed before the facility begins operations.
Second, even the maintenance of CWISs should not result in downtime in the oil and gas industry, since MODUs
are hauled out on a regular basis for other types of maintenance activities, and production platforms are shut in
one to two times per year for other maintenance, making incremental downtime due to CWIS maintenance
unlikely (see the Technical Development Document for the Proposed Section 316(b) Phase III Rule (hereafter
referred to as the "Phase III Technical Development Document"; U.S. EPA, 2004b).

Subsection Cl-1.1 provides an overview of the three cost categories included in the analysis for new offshore oil
and gas extraction facilities, addressing those aspects of each category that are relevant to the oil and gas industry.
Table Cl-1 summarizes the type of new offshore oil and gas extraction facility  assumed to be subject to  Phase III
regulation and the compliance technologies considered for each facility type. Subsection Cl-1.2 presents
information on administrative costs incurred by new oil and gas facilities. Additional detail on the costs of
installing and operating compliance technology is provided in the Phase III Technical Development Document.

Cl-1.1 Cost of Installing and Operating Compliance Technology

Oil and gas drilling and production facilities would need to implement technologies to reduce impingement
mortality and/or entrainment.  The choice of technology varies depending on CWIS diameter and flow rate or
diameter, or type of CWIS (e.g., sea chest or simple pipe). Note that for new MODUs, which EPA assumes will
                                                                                        Cl-1

-------
§ 316(b) Proposed Rule: Phase III-EA, Part C: Economic Analysis for Phase III New OOGE Facilities
Cl: Summary of Costs
use sea chests, only impingement requirements would apply. EPA determined that entrainment controls on sea
chests are not technically practicable (U.S. EPA, 2004b).
      Table Cl-1: Technologies for Implementing 316(b) Requirements for New Offshore Oil and Gas
                                           Extraction Facilities
Category
Platform
Platform
Platform
Platform
Platform
Jackup
Jackup
Jackup3
Jackup3
Jackup
Submersibles, Semi-
Submersibles and Drill Ships3
Submersibles, Semi-
submersibles and Drill Ships3
Drill Barges
Drill Barges
CWIS Type
Simple Pipe or Caisson
Simple Pipe or Caisson
Simple Pipe or Caisson
Simple Pipe or Caisson
Simple Pipe or Caisson
Simple Pipe or Caisson
Simple Pipe or Caisson
Sea Chest
Sea Chest
Submersible Pumps
Sea Chests
Sea Chests
Simple Pipes
Simple Pipes
Technology Description
Stainless steel wedge wire screen - no air sparge cleaning
Stainless steel wedge wire screen - with air sparge
cleaning
CuNi wedge wire screen - no air sparge cleaning
CuNi wedge wire screen - with air sparge cleaning
Stainless steel and CuNi velocity caps
Cylindrical wedge wire screen over tower inlet
Horizontal Flow Modifier
Flat panel wedge wire screen over sea chest opening
Horizontal Flow Diverter for Side Sea Chests
Cylindrical wedge wire screen over suction pipe inlet
Flat panel wedge wire screen over sea chest
Horizontal flow diverter over side sea chest
Cylindrical wedge wire screen over simple pipes
Velocity Cap on the CWIS
 3   All semi-submersibles and drill ships and most jackups in EPA's technical database use sea chests. EPA determined that
     entrainment controls on sea chests are not technically practicable. New MODUs, which are represented by typical existing
     MODUs, are assumed to use sea chests (see U.S. EPA, 2004b).

 Source: U.S. EPA, 2004b.
EPA developed technology cost estimates for the proposed rule based on the impingement mortality and
entrainment reduction technologies (as appropriate) projected for each new oil and gas facility. Technology costs
include capital costs and operating and maintenance (O&M) costs.  The technology costs developed for the
proposed rule analysis are engineering cost estimates, expressed in July 2002 dollars. These costs were converted
to mid-year 2003 values (see Section Cl-2.2 below for a discussion of adjusting monetary values to a common
time period of analysis).

More detailed information on the compliance technologies considered by EPA, on technology costs, and on
EPA's characterization of baseline technologies already in-place at new offshore oil and gas extraction facilities,
is available in the Phase III Technical Development Document. In addition, Chapter C3: Economic Impact
Analysis for the Offshore Oil and Gas Extraction Industry provides more detail on the engineering costs assumed
for each of the different types of oil and gas facilities analyzed in this report.
Cl-2

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs


Cl-1.2 Administrative Costs for Complying Facilities

Compliance with the standards of the proposed rule requires new offshore oil and gas extraction facilities to carry
out certain administrative functions. For Phase III existing facilities, these administrative functions, which help
them determine their compliance requirements and provide the documentation needed for issuance of their new
National Pollution Discharge Elimination System (NPDES) permits, fall on each facility individually.  For oil and
gas facilities, however, General Permits apply.

There are three General Permits  (GPs) that would apply to new offshore oil and gas extraction facilities subject to
Phase III regulation. The Region 6 General Permit applies to the relatively active Western Gulf of Mexico
(GOM) region; the Region 4 General Permit applies to the currently relatively inactive Eastern GOM region, and
the Region 10  General Permit (Cook Inlet permit) applies to Cook Inlet, Alaska. The GPs are expected to be
rewritten to accommodate the requirements of section 316(b) following promulgation of the final rule and as each
GP comes up for renewal at the end of its 5-year cycle.

The current Region 6 permit was effective as of 2002, expired in 2003, and is planned for renewal in 2004.  Study
of produced water will reopen in 2007.  The likely beginning rounds of the post-promulgation schedule of this
permit is thus 2007 and 2012. The Region 4 permit expired in 2003. It is likely to be renewed in 2004.  The
probable post-promulgation GP renewal schedule is considered to be 2009 and 2014. The planned renewal date
of the general permit for Cook Inlet is January 2005 but the permit expires in 2004. The likely post-promulgation
renewal schedule  is thus 2009 and 2014.

The rule is scheduled to be promulgated in 2006, with the effective date assumed to be the beginning of 2007.
Three years of environmental studies are assumed to be required prior to permitting under the section 316(b) rule.
Thus, the first possible compliance date after the 2007 effective date would be 2010. However, the general
permits may not be able to incorporate section 316(b) requirements during the 2007-2009 repermitting cycles.
Therefore, EPA assumed that the oil and gas industries would be required to comply starting in 2012 (or 2014 in
the case of Region 4 and 10 permits).

Because the rule becomes effective in 2007, however, EPA is assuming, for both simplicity and to be
conservative, that starting in 2007, new offshore oil and gas extraction facilities would have installed and would
be operating relevant CWIS controls, since they would be relatively inexpensive to install during construction.
The pre-permitting studies are assumed to start in 2007 (for both Region 6 and Region  4), but other permitting
tasks would not begin until the year prior to when the GPs renewals are finalized (2012 or 2014), or the year prior
to  when the facility is assumed to come on line or be launched, whichever is later.  Monitoring would only begin
in  the year the  renewals are finalized or the year in which the facility comes on line or is launched, again,
whichever is later. The timing assumptions for Region 6 and Region 4 permits may overstate costs, since costs
are moved several years earlier in the analysis time frame than they would be if EPA assumed only those facilities
constructed in  2012 or later incur compliance costs.  The costs of compliance in this industry, however, are
relatively small overall, so the numerical significance of any overestimation would be small. More specific
details of the timing assumptions of costs incurred are provided in a memorandum to the Rulemaking record
(ERG, 2004).

Because new offshore oil and gas extraction facilities would be subject to Phase III regulation under these GPs,
EPA assumes that certain administrative functions can be shared among new facilities.  All MODUs and
platforms expected to be built in the first five years before the revised  Region 6 General Permit is issued (2012)
are expected to share the initial costs of certain biological characterization studies that would be required by
section 316(b) under the Region 6 GP.  They are also assumed to share the cost of monitoring studies, which must
be performed at a minimum for the first two years of the permit and then at least once per year for each
repermitting cycle. Only MODUs are assumed to share the costs of permitting studies  under the Region 4 GP.
Permitting costs for platforms are assumed to be those incurred under the Region 6 permit.  Should platforms be
constructed in  Region 4 locations, permitting costs would be similar to Region 6 permitting costs. Since it is not
known which MODUs may operate in the Eastern GOM, all MODUs constructed in 2007 and beyond are


                                                                                                   Cl-3

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities          Cl: Summary of Costs


assumed to incur permitting costs under a Region 4 GP. This roughly doubles the permitting costs assigned to
MODUs.  The assumption may overstate total costs, since not all MODUs may operate in the Eastern Gulf, and
there may be significant costs savings once a Region 6 permit application is completed, since much of the
information required for both permits would most likely be identical.

Only one Alaska project is anticipated, at most, over the period of analysis (see Chapter C2: Profile of the
Offshore Oil and Gas Extraction Industry), so this project is expected to incur the entire cost of facility
permitting.  This project is assumed to go on  line in the year the Region 10 permit is finalized (2014).  For this
project, EPA assumes that the 3-year studies are performed in the three years prior to start-up (2011-2013).

The administrative functions associated with  incorporating the 316(b) requirements into the applicable General
Permits are either one-time requirements (compilation of information for the initial post-promulgation General
Permits) or recurring requirements (compilation of information for subsequent General Permit renewals; and
monitoring, record keeping, and reporting). More detailed information on the derivation of permitting activities
and costs can be seen in U.S. EPA (2004a).

a.   Initial post-promulgation General Permit application
EPA assumes that the proposed rule would encourage firms to pool their resources.  Therefore, those firms that
are planning to construct new platforms or MODUs to operate in the GOM within the first 5 years before the
applicable General Permit is reissued with 316(b) requirements in place are assumed to share certain pre-
permitting costs.  EPA expects that these firms will hire a consultant to perform the  more general information
gathering tasks required of industry before facilities can be permitted under a GP and also to perform the two
years of monitoring studies required in the first two years of the permit (monitoring costs are assumed shared by
the number facilities  permitted in the first or second year of the first permit cycle). Other activities are specific to
each facility and it is assumed each facility will incur the cost of these activities individually. Some of the
permitting activities,  however, may not be incremental to existing requirements. Minerals Management Service
(MMS) will be finalizing a rule (possibly mid-August, 2004)  that will require some of the same information (U.S.
EPA, 2004a).  The MMS rule is, however, not applicable to Cook Inlet. All information submitted would be
consistent with Phase I, Track 1 requirements. Activities and costs associated with the initial permit renewal
application include:

    *•    Start-up activities: reading and understanding the rule; mobilizing and planning; and training staff. This
        is a facility-specific activity.

    *•    Permit application activities: identifying source water physical data, velocity information, and cooling
        water intake  structure data, including description of CWIS operations, flow distribution and water balance
        diagram, and drawings and maps to support CWIS descriptions, and maintaining copies of these records.
        These activities are assumed facility-specific, but several of the activities duplicate activities required by
        MMS. There are no incremental costs associated with duplicate activities.

    *•    Source waterbody flow and CWIS velocity flow information: Information used to demonstrate that the
        facility's  CWIS meets the proportional flow requirements.  The CWIS velocity flow information and
        demonstration is assumed to be facility-specific, but none of these activities is incremental to MMS
        requirements. The waterbody flow calculation activities are only those associated with compiling site-
        specific information. Other waterbody characterization activities that can be shared are included in the
        biologic characterization study activities.

    *•    Design and construction technology plan: delineation of the hydrologic zone of influence for the CWIS,
        description of technologies to be implemented; the basis for technology selection; expected performance
        of the technology; and design calculations, drawings and estimates to support the technology description
        and performance.  These activities are assumed facility-specific. Development of the narrative
        description of technologies is considered an MMS requirement, so no costs are assumed incurred for this
        activity.


Cl-4

-------
§ 316(b) Proposed Rule: Phase III-EA, Part C: Economic Analysis for Phase III New OOGE Facilities
Cl: Summary of Costs
    *•   Source water baseline biological characterization data: characterization of the biological community in
        the region and operation of CWISs; list of species in region; identification and evaluation of primary
        period of reproduction, larval recruitment, and period of peak meroplankton abundance for relevant taxa;
        and description of the likely impact of CWISs on the biological community due to impingement and
        entrainment. This is considered a regional study to be conducted over a 3-year period by a contractor;
        costs are assumed to be shared among affected facilities, since the entire monitoring program is assumed
        to apply region-wide.

Table Cl-2 below lists the estimated costs per facility of each of the initial post-promulgation General Permit
activities described above (permit costs for MODUs in the Eastern GOM are lower in some cases, since MODUs
are assume to use sea chests and are not required to  meet entrainment requirements, eliminating any costs
associated with entrainment studies).
        Table Cl-2: Cost of Initial Post-Promulgation NPDES General Permit Application Activities
                                           (Per Facility, 2003$)
Activity
Start-up activities3
Permit application activities'1
Source waterbody flow information3
CWIS velocity flow information5
Design and construction technology planb
Biological characterization studyc>e
Total Initial Post-Promulgation NPDES General
Permit Application Cost11
Region 6
$2,171
$925
$1,416
$0
$1,282
$63,942
$69,737
Region 4
$2,171
$925
$1,416
$0
$1,141
$39,871
$45,524
Region 10
$2,171
$925
$1,416
$0
$1,282
$296,564
$302,358
 a   The costs for these activities are incurred in 2007 for facilities built in 2007 to 2011 in both Eastern and Western Gulf. For
     Alaska, they occur in 2011.
 b   The costs for these activities are incurred in 2011 for facilities built in 2007 to 2012 for both Eastern and Western Gulf. For
     Alaska, they occur in 2013.
 c   The costs for these activities are incurred during 2007-2009 in the Eastern and Western Gulf and are shared costs. For Alaska,
     these costs are incurred during 2011-2013.
 d   Individual numbers may not add to total due to independent rounding.
 e   Shared study costs.
 f   Measured as incremental to MMS requirements.

 Source:  U.S. EPA, 2004a. See also ERG, 2004.
b.  Subsequent NPDES General Permit Renewals
Subsequent General Permit renewals would require collecting and submitting the same type of information
required for the initial permit renewal application. EPA expects that both the facility and the contractor can use
some of the information from the initial studies.  Building upon existing information is expected to require less
effort than developing the data the first time, especially in situations where conditions have not changed.  The
shared recurring permit costs are assumed to be shared by all new offshore oil and gas extraction facilities built in
the first 5-year cycle plus all new facilities built in the next 5-year cycle, etc., so as time goes on, shared costs are
shared by more and more facilities (except Alaska, where only one project is assumed during the time frame of
the analysis).  As facilities  go offline or are retired (after 30 years), fewer projects share in these studies.
Table Cl-3 lists the estimated costs of each of the NPDES General Permit renewal activities subsequent to the
first round. Since these numbers change slightly as facilities come on or offline, the costs shown are for the first
repermitting cycle following the initial GP renewal.
                                                                                                       Cl-5

-------
§ 316(b) Proposed Rule: Phase III-EA, Part C: Economic Analysis for Phase III New OOGE Facilities
Cl: Summary of Costs
               Table Cl-3: Cost of Subsequent NPDES General Permit Application Activities
                                              (Per Facility, 2003$)
Activity
Start-up activities2
Permit application activities3
Source waterbody flow information3
CWIS velocity flow information3
Design and construction technology plan3
Biologic characterization study3
Total Recurring NPDES Permit Application Cost"
Region 6
$692
$190
$401
$0
$802
$12,005
$14,090
Region 4
$692
$190
$401
$0
$694
$7,455
$9,432
Region 10
$692
$190
$401
$0
$802
$194,932
$197,017
 3   The costs for these activities are incurred during the year of the General Permit renewal.  Shared costs shown are for the first
     permit renewal period after the initial permit (e.g., 2017); these costs change as the number of permitted facilities change. For
     simplicity, all costs for repermitting are assumed to be incurred in one year, rather than spread over several years as was assumed
     for the initial round of permitting.

 Source:  U.S. EPA, 2004a. See also ERG, 2004.
c.  Annual monitoring, record keeping, and reporting
Annual monitoring, record keeping, and reporting activities and costs include:

    *•   Biologic monitoring for impingement
    *•   Biologic monitoring for entrainment
    *•   Velocity monitoring
    »•   Preparing and maintaining a yearly status report

Table Cl-4 on the following page outlines the associated costs of these activities.
                        Table Cl-4: Cost of Monitoring Activities (Per Facility, 2003$)
Activity
Biologic monitoring for impingement
Biologic monitoring for entrainment
Velocity monitoring3
Preparing and maintaining yearly status report
Total Monitoring Cost
Region 6
$4,350
$2,710
$1,004
$1,775
$9,839
Region 4
$1,963
$0
$453
$801
$3,217
Region 10
$0
$46,078
$6,192
$10,945
$63,215
 3   The costs for these activities are incurred during the first two years of the initial General Permit renewal (i.e., 2012 or 2014) and
     are shared. These costs are incurred for one year in each subsequent permit renewal cycle.  Shared costs shown are for the first
     permit cycle only (2012 or 2014); these costs change as the number of permitted facilities change over time.

 Source:  U.S. EPA, 2004a. See also ERG 2004.
Cl-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs


d.  Administrative Costs for Permitting Authorities
In addition, permitting authorities have to review the information provided by new offshore oil and gas extraction
facilities and have to issue new general permits that reflect the requirements of the proposed rule. These activities
impose costs on the responsible governmental units. For more details on the specific costs and timing
assumptions for federal administration of new offshore oil and gas extraction facilities, see Chapter D2:  UMRA
Analysis. These costs and assumptions are summarized briefly below.

The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination
System (NPDES) permit program. In the case of the oil and gas industry, NPDES permitting  is consolidated
under several General Permits,  which are administered at the EPA regional level. Unlike the Phase III existing
facilities discussed in Chapter Bl: Summary of Cost Categories and Key Analysis Elements for Existing
Facilities, no states are involved in these permitting activities. Thus, three Regions (Region 6, Region 4, and
Region 10) are expected to be the only entities responsible for permitting. Because states are  not involved in
permitting, there are no costs associated with Federal oversight as there are for state-administered NPDES
permits. The three Regions would incur three types of costs associated with implementing the requirements of the
proposed rule on a per-facility basis, i.e., for each facility permitted under a GP: (1) start-up activities (considered
not incremental to existing activities; $0 cost), (2) activities associated with the initial General Permit containing
the new section 316(b) requirements ($12,309 in each  region) and subsequent permit renewals ($5,018 in each
region), and (3) annual activities ($1,428 in each region).1

The start up activities apply only once to each Region, but the remaining activities are incurred on a per-facility
basis.

For a detailed discussion of administrative costs for permitting authorities, see Chapter D2: UMRA Analysis,
section D2-1.2.
Cl-2   KEY ELEMENTS OF THE ECONOMIC ANALYSIS FOR NEW OFFSHORE OIL AND GAS
        EXTRACTION FACILITIES

The economic analysis of regulation of new offshore oil and gas extraction facilities addresses the cost to, and
impact on, the affected industry segments and society generally. Although these analyses differ in important
respects for the individual industry segments - particularly in terms of the analytic models and methods for
assessing the economic/financial impact of the proposed rule on complying parties within the segments - several
elements of the analysis have features common to all new offshore oil and gas extraction facilities. This section
reviews the following key common elements:

    *•   Compliance Schedule
    »•   Adjusting Monetary Values to a Common Time Period of Analysis
    *•   Discounting and Annualization: Costs to Society or Social Costs
    »•   Discounting and Annualization: Costs to Complying Facilities

Cl-2.1  Compliance Schedule

For its analysis of the cost and impacts of the proposed rule, EPA developed a profile of the expected compliance
year (year in which the new MODU or platform is launched or comes on line) for each of the types of facilities
considered in the economic analysis. Unlike the analysis for the Phase III existing facilities, the compliance year
is not necessarily the same year as the year in which the facility must comply with the General Permit, since EPA
is assuming that CWIS controls are installed and are operating in new MODUs and platforms starting in 2007,
    1 The costs associated with implementing the requirements for new offshore oil and gas extraction facilities are documented in EPA's
Information Collection Request (U.S. EPA, 2004a).

                                                                                                   Cl-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs


even though the first General Permit is assumed to be reissued with 316(b) requirements in 2012. Developing an
explicit profile of compliance years for new offshore oil and gas extraction facilities is important because the
schedule of compliance years determines the timing of outlays by facilities and society in complying with the
regulation, both for the initial outlays and for the ongoing profile of outlays in maintaining compliance with the
regulation. This information is important in properly assessing the present value of the regulation's costs to
society.

For the analysis, EPA initially assumed that firms planning to build facilities  in the first permit cycle (Region 6
General Permit) (2012-2016) would contract to perform the studies necessary for these facilities to be permitted
starting in 2007.  The Region 4 permit is assumed not to incorporate 316(b) requirements until 2014, but studies
are started in 2007 as well.  Starting in 2014, any new MODUs are assumed to incur the  costs of the Region 4
permit as well as the Region 6 permit. No platforms/structures are assumed to incur costs of the Region 4 permit
(they will incur the costs of one permit only, assumed to be issued under the Region 6 General Permit).  The next
group of facilities to be launched or come on line in the next permit cycle (2017 or 2019) would need to be
involved only in repermitting activities for the shared studies, and thus, for the shared costs, would share
repermitting costs with each other as well as with operations begun in the first 5-year cycle. These new
operations would, however, incur initial permitting costs among those activities that are facility specific.  The
years in which facilities are expected to be completed are specifically spelled out, given the number of facilities
expected to be completed in each year (see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry).
More information on specific timing assumptions can be seen in ERG (2004) and the 316(b) Oil and Gas
Compliance Cost Model (DCN 7-4018).

Cl-2.2 Adjusting Monetary Values to a Common Time Period of Analysis

The various economic information used in the cost and impact analyses were initially provided or estimated in
dollars of different years. For example, facility financial data obtained in the 316(b) survey for the oil and gas
industry are for the years 2000, 2001, and 2002, while the technology costs of regulatory compliance were
estimated in dollars of the year 2002. To support a consistent analysis using these data that were initially
developed in dollars of different years, EPA needed to bring the dollar values to a common analysis year.  For this
analysis, EPA adjusted all dollar values to constant dollars of the year 2003 (average or mid-year, depending on
availability) using an appropriate inflation adjustment index. For adjusting compliance costs, EPA used the
Construction Cost Index (CCI) published by the Engineering News-Record.

a.   CCI
EPA used the CCI to adjust compliance cost estimates from July 2002 to mid-year 2003.  EPA judges the CCI as
generally reflective of the cost of installing and operating process and treatment equipment such as would be
required for compliance with Phase III regulation.  Table Cl-5, following page, shows CCI values for July, 2002
and June, 2003.
Table Cl-5:
Year
My 2002
June 2003
Construction
Value
6605
6694
Cost Index
% Change
1.3%
Source: ENR, 2004.
b.  GDP Deflator
EPA used the GDP Deflator to adjust 316(b) survey financial data from 2000, 2001, and 2002 to 2003. The GDP
Deflator is a quarterly series that measures the implicit change in prices, overtime, of the bundle of goods and
services comprising gross domestic product. Table Cl-6 shows GDP Deflator values from 2000 to 2003.  From
2000 to 2003, the total change in the deflator series was 5.7% (105.7/100.0).

Cl-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs
                                    Table Cl-6: GDP Deflator Series
Year
2000
2001
2002
2003
Source: U.S.
Value
100.0
102.4
103.9
105.7
BEA, 2004.
% Change

2.4%
1.5%
1.7%

Cl-2.3  Discounting and Annualization - Costs to Society or Social Costs

Discounting refers to the economic conversion of future costs (and benefits) to their present values, accounting for
the fact that society tends to value future costs or benefits less than comparable near-term costs or benefits.
Discounting is important when the values of costs or benefits occur over a multiple year period and may vary
from year to year. Discounting is also important when the time profiles of costs and benefits are not the same -
which is the case for the regulatory analysis of new oil and facilities.  Discounting enables the accumulation of the
cost and benefit values from multiple years at a specified point in time, accounting for the difference in how
society values those costs and benefits depending on the year in which the values  are estimated to occur.

For its analysis of the costs to society, or the social costs, of the proposed rule for new offshore oil and gas
extraction facilities, EPA first developed a profile of the costs expected to be incurred as a result of the regulation
over the period of analysis. EPA defined the analysis  period as follows. The analysis period begins in 2007 (5
years  before the first of the General Permits is reissued with 316(b) requirements) and includes facilities
constructed over the next 20 years - i.e., to 2026 -plus a period of 30 years in which each newly constructed
facility is assumed to continue compliance. Thus, for  the social cost analysis for Phase III new offshore oil and
gas extraction facilities, the analysis period extends to 2055 (see the 316(b) Oil and Gas Compliance Cost Model,
DCN  7-4018). In developing the time profile of costs, EPA assigned costs according to the following schedule:

a. Direct Costs  of Regulatory Compliance

    *•    Capital Costs of Compliance Technology: This cost is first incurred in the year that the facility begins
        operation. However, the equipment for complying with the regulation is expected to have a useful life of
        10 years,  or a period shorter than the 30 years of compliance. Accordingly, following the first
        installation, facilities are assumed to reinstall, and  re-incur the cost of, the compliance equipment at year
        11  and year 21 of the  facility-specific compliance period.

    >    Compliance Technology Operation and Maintenance: This  cost is assumed to occur in each year of a
        facility's  30-year compliance year period.

b. Administrative Costs Incurred by Complying Facilities

    *•    Biological Characterization Study: This is a three-year study required for all facilities, which is assumed
        to be shared by the affected facilities. The cost of this study is incurred over the years immediately
        following the effective date of the proposed rule or the years preceding the first post-promulgation GP
        (2007-2009 for Eastern and Western Gulf, and 2011-2013 for Alaska).

    *•    Initial Permitting Cost. In addition to incurring a share of the cost of characterization studies, complying
        facilities would also incur an initial permitting cost, which is  assigned to the year preceding the first year
        of a facility's 30-year compliance period, or in 2007 for facilities launched or coming on line in 2007
        through 2011.

                                                                                                    Cl-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs
    *•  Repermitting Costs: As explained above, General Permits are renewed each five years during the period
       of compliance. Repermitting costs, both shared and facility-specific, are assumed to recur at years 5,10,
       15, 20, and 25 of the General Permit cycles.  For new offshore oil and gas extraction facilities, EPA
       assumes that 30 years is the reasonable maximum lifetime of these facilities; thus, no repermitting cost is
       incurred in the 30th year of facility operation.

    *•  Annual Monitoring, Record Keeping, and Reporting Activities: These costs are assumed to occur in the
       first two years of the initial permit and in each year of the permit renewal year.  These costs begin in 2012
       or 2014, depending on permit.

c.   Administrative Costs Incurred by Permitting Authorities

    *•  One-time Start-up Costs: These costs are assumed to be nonincremental to  existing costs of permitting in
       the three regions.

    *•  Permit Processing Costs: These costs are assigned to the years in which facilities apply for initial permits
       or renewal permits during the compliance period.

    *•  Annual Permit Administration Activities: The cost of these activities is assumed to occur in parallel with
       the annual permit-related activities by complying facilities and thus occurs in each year of a facility's
       compliance period.

EPA assigned costs by facility and governmental unit according to this framework and then summed these costs
on a year-by-year basis over the total time period of analysis.  For the social cost analysis, these costs were tallied
on a pre-tax basis, which differs from the treatment of costs for the facility impact analysis as described below.
These profiles of costs by year were then discounted to the assumed date the final rule would take effect,
beginning of year 2007, at two values of the social discount rate, 3% and 7%.  These discount rate values  reflect
guidance from the Office of Management and Budget regulatory analysis guidance document, Circular A-4
(OMB, 2003).2

For more detailed information see ERG (2004) and the 316 (b) Oil and Gas Compliance Cost Model (DCN 7-
4018).

EPA used the following formula to calculate the present value of the time stream of costs as of the beginning of
2007:3

                                                          Cost
                                      Present Value =
                                                       (1 +  r)'-2007
where:
        Costt   =   Costs in year t
        r       =   Social discount rate (3% and 7%)
        t       =   Year in which cost is incurred (2007 to 2055)

After calculating the present value of these cost streams, EPA calculated their constant annual equivalent value
(annualized value) using the annualization formula presented below, again using the two values of the social
discount rate, 3% and 7%. Although the analysis period extends from 2007 through 2055, a period of 49 years,
    2 See Chapter El: Summary of Social Costs, for further discussion of the framework for analyzing the social costs of the 316(b)
Phase III regulation.

    3 Calculation of the present value assumes that the cost is incurred at the beginning of the year.
Cl-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl : Summary of Costs


inclusive, EPA annualized costs over 30 years, since 30 years is the assumed period of compliance. This same
annualization concept and period of annualization were also followed in the analysis of benefits, although for
benefits the time horizon of analysis for calculating the present value is longer than for costs.  Using a 30-year
annualization period for both social costs and benefits allows comparison of constant annual equivalent values of
costs and benefits that have been calculated on a mathematically consistent basis. The annualization formula is as
follows:

                                                            r x n +  r)(»-V
                              Annualized Cost = PV of Cost x -         '
                                                                + r)n -  \

where:

       r       =   Social discount rate (3% and 7%)
       n       =   Annualization period, 30 years for the social cost analysis

Cl-2.4 Discounting and Annualization - Costs to Complying Facilities

In general, EPA followed similar concepts and procedures in the discounting and annualization required for the
analysis of costs to, and impacts on, complying facilities as those followed for the analysis of social costs.
However,  the analysis of costs to complying facilities differs from that for costs to society in several important
ways, which are described below.

    *•  Consideration of taxes. For understanding the impact of the regulation on complying facilities, the costs
       incurred by complying facilities are adjusted for taxes, as relevant, and  calculated on an after-tax basis.
       The tax treatment of compliance outlays and income effects (e.g., from  installation) shifts part of these
       costs to the tax-paying public and reduces the actual cost to private, tax-paying businesses. For this
       reason, the after-tax costs of compliance are a more meaningful measure than the pre-tax costs of the
       financial burden on complying facilities. In analyzing and reporting the impact of compliance costs on
       private facilities, annualized costs are therefore calculated on an after-tax basis.  Since most companies
       that operate MODUs or platforms are headquartered in states without corporate income taxes, EPA
       assumes a state tax rate of 0%. On the Federal level, EPA assumes that the highest marginal corporate tax
       rate applies.  This rate is 35% (IRS, 2002), so post-tax costs will be  65% of the pre-tax costs. EPA does
       this because all platform and MODU owners that are likely to operate in Alaska or the Gulf of Mexico are
       large corporations by  SBA  standards and/or all have earnings in most years that place them in the highest
       corporate tax bracket.

    *•  Calculation of present value and annualization of costs at the year of compliance.  In the social cost
       analysis, costs were summed on a present value basis at the beginning of 2007, the assumed date the final
       regulation would take effect.  For the analysis of costs to complying facilities, costs were calculated on a
       present value basis and annualized at the first year of compliance for each facility (assumed to be the year
       the facility is brought on  line or launched). The calculation of annualized costs at the first year of
       compliance provides more accurate and meaningful insight for assessing financial impact in relation to
       the baseline financial  performance and conditions of the complying  facility than would be achieved if, for
       example, costs were further discounted - and reduced numerically - by bringing them to the year the rule
       would take effect.  The aggregates of annualized cost over facilities  for purposes of reporting total cost to
       complying facilities and total financial burden are likewise the sum  of costs at the initial year of
       compliance for each facility, even though those years differ across facilities.  These costs are annualized
       and used to report the aggregate costs to industry.  The costs used to determine impacts are derived
       somewhat differently  and the method used to incorporate them into the  impact analysis varies by type of
       facility (MODU or platform) as explained in Chapter C3: Economic Impact Analysis for the Offshore Oil
       and Gas Extraction Industry.
                                                                                                   Cl-11

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs

    *•   Use of discount rates in present value and annualization calculations. The discounting and
        annualization calculations for the complying facility cost calculations use the same formulas as used for
        the social cost calculations. However, the discount rate used in the facility cost calculations generally has
        a different interpretation than the rate used for the social cost calculation (even though the numerical
        value of the rate may be the same). Instead of being a social discount rate, the discount rate used for the
        present value and annualization calculations for complying facility costs represents a cost of capital to the
        individual complying facility, which may reasonably differ from the concept of the social discount rate.
        The social discount rate may be derived on several bases, including as an opportunity cost of capital to
        society or as a societal inter-temporal preference or indifference rate - i.e., the required rate of change
        over time in a value of consumption or outlay at which society would be indifferent to the time period in
        which the consumption or outlay occurs. The social discount rates based on these society-level concepts
        may reasonably differ from the cost of capital used for assessing costs and financial impacts to the
        complying firm.
Cl-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs


REFERENCES

Engineering News-Record (ENR). 2004. Construction Cost Index. Available at:
http://enr.construction.com/features/conEco/costIndexes/constIndexHist.asp.

ERG. 2004. Cost Timing and Cost Sharing Assumptions for Industry Compliance Costs. Memorandum to the
316(b) Phase III Rulemaking Record. October 15, 2004.

Office of Management and Budget (OMB). 2003. Executive Office of the President.  Circular A-4, To the Heads
of Executive Agencies and Establishments; Subject: Regulatory Analysis.  September 17, 2003.

U.S. Bureau of Economic Analysis (U.S. BEA). 2004. Gross Domestic Product. Table 1.1.9: Implicit Price
Deflators for Gross Domestic Product (GDP).  Last Revised on February 27, 2004.
Available at: http://www.bea.doc.gov/bea/dn/nipaweb/TableView.asp#Mid.

U.S. Department of the Treasury. 2002. Internal Revenue Service (IRS). 2002 Instructions for Forms 1120 &
1120-A, page 17 (Federal tax rates).

U.S. Environmental Protection Agency (U.S. EPA). 2004a. Information Collection Request (ICR)for Cooling
Water Intake Structures Phase III Proposed Rule.  ICR Number 2169.01.  October 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2004b. Technical Development Document for the Proposed
Section 316(b) Phase III Facilities.  EPA-821-R-04-015. November 2004.
                                                                                               Cl-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities         Cl: Summary of Costs
                          THIS PAGE INTENTIONALLY LEFT BLANK
Cl-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities   C2: Profile ofOOGE Industry

  Chapter C2:  Profile of the  Offshore  Oil  and
                      Gas  Extraction  Industry
                                                  CHAPTER CONTENTS
                                                  C2-1 Mobile Offshore Drilling Units (MODUs) .... C2-2
                                                      C2-1.1 Overview  	C2-2
                                                      C2-1.2 Existing MODUs and Their Associated
                                                            Firms	C2-3
                                                      C2-1.3 Existing MODUs with Intake Rates
                                                            Meeting Proposed Rule Criteria	C2-9
                                                  C2-2 Oil and Gas Production Platforms	C2-10
                                                      C2-2.1 Overview  	C2-10
                                                      C2-2.2 Existing Platforms and Their Associated
                                                            Firms	C2-11
                                                      C2-2.3 Existing Platforms with Intake
                                                            Rates Meeting Proposed Rule Criteria C2-25
                                                  C2-3 Total New Oil and Gas Operations	C2-30
                                                  References 	C2-31
INTRODUCTION

EPA's proposed 316(b) cooling water intake
rulemaking would affect new construction among
offshore components of the oil and gas industry. The
proposal would affect new offshore oil and gas
extraction facilities only, because EPA has decided
not to regulate existing oil and gas facilities. This
profile compiles and analyzes economic and financial
data for several sectors of the offshore oil and gas
extraction industry that may be affected by certain of
the Phase I 316(b) requirements for new facilities that
are being proposed for new offshore oil and gas
extraction facilities under Phase III. The profile
characterizes the firms and facilities that currently
exist to provide information on the characteristics of
facilities that might be constructed in the future and
the firms that are most likely to construct such facilities. The review of existing facilities that would be subject to
Phase III regulation, if they were newly constructed, is also informative in showing the relatively small number of
facilities that EPA has excluded from coverage by not including existing oil and gas facilities in this proposal.

Two key industry sectors are primarily associated with offshore oil and gas drilling and production, both of which
might intake ambient cooling water from the surrounding oceans or navigable waterways for a wide variety of
cooling needs. EPA also investigated the  liquid natural gas (LNG) re-gasification industry, but determined that
all but one new LNG facility currently planned would meet the 316(b) requirement that 25% or more of total
intake flow be used for cooling water purposes (U.S. EPA, 2004). EPA proposes to apply Best Professional
Judgment (BPJ) to this industry. This industry, therefore,  is not discussed further.

The two major offshore oil and gas extraction industry users of CWIS are:

    *•  mobile offshore drilling units (MODUs)
    *•  offshore oil and gas production platforms

The following sections provide a profile for MODUs and production platforms (Sections C2-1 and C2-2). Within
each profile, a brief overview of the industry is provided, including a look at existing facilities and their
associated firms, and the financial conditions of those firms (where firm financial data are publicly available).
The existing facilities are then discussed in more detail to provide information for the financial modeling of new
facilities. Also discussed are factors affecting the future of each of these two groups of CWIS users.  Finally,
EPA projects the numbers of new MODUs or platforms that might be constructed with CWIS flow rates greater
than 2 MGD, greater than 20 MGD, and greater than 50 MGD during the construction portion of the time frame
of this economic analysis (construction spans the years 2007 to 2026). As discussed in Section Cl, EPA decided
to apply a similar regulatory structure to new offshore oil and gas extraction facilities as had been applied to new
facilities for the 316(b) Phase I regulation: impingement and entrainment (I&E) controls are required on all new
offshore oil and gas extraction facilities that have a total CWIS intake flow rate of 2 MGD or more (except for
MODUs using sea chests, which are subject to impingement controls only).
                                                                                             C2-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

Section C2-3 concludes this chapter with a summary of the estimated total number of new facilities in the offshore
oil and gas extraction industry with at least 2 MGD intake rates by MGD flow rate category.


C2-1  MOBILE OFFSHORE DRILLING UNITS (MODUs)

C2-1.1 Overview

Offshore drilling operations often use MODUs, which are vessels or other sea-going rigs that are used to transport
drilling equipment to the offshore site and from which drilling operations can be undertaken.  The MODUs of
interest are active primarily in the State offshore waters of the Gulf of Mexico (GOM). MODUs operating close
to shore in State waters tend to be small barges and submersibles that do not use cooling water at the rates of
concern (significantly less than 2 MGD) (U.S. EPA, 2004).

MODUs provide nearly all of the exploration and delineation drilling in the offshore development of oil and gas
resources. MODUs also provide developmental drilling services. In exploratory drilling, drilling is undertaken to
determine whether oil and gas resources are available near existing fields or in areas where no resources have
been previously found (wildcats). Once an exploratory well has identified the presence of potentially recoverable
oil and gas resources, delineation drilling is undertaken. Delineation entails the drilling of additional wells to
determine the extent and nature of the new field.  These two types of drilling often occur at a distance from
existing platforms and thus are usually conducted from a mobile rig.

Drilling of development wells can be done from either a platform or a MODU.  The same types of mobile rigs
used to drill  exploratory and delineation wells can also be used to drill developmental wells.  Once a field has
been delineated and a decision is made to develop the field, a platform is typically constructed and  developmental
drilling is initiated to construct wells for producing the field.  A discussion of platform-based drilling is presented
below in Section C2-2.

MODUs encompass a variety of vessel or rig types. The two basic groups of MODUs are bottom-supported units
and floating  units. Bottom-supported units include submersibles and jackups. Floating units include inland
barge rigs, drill ships, ship-shaped barges, and semi-submersibles.

Bottom-supported drilling units are typically used when drilling occurs in shallow waters. Types of bottom-
supported units include:

    *•  Submersibles-barge-mounted drilling rigs that are towed to the drill site and sunk to the bottom. These
       rigs  may be either posted barge or bottle type. A posted barge rig consists of a barge hull that rests on the
       bottom, with steel posts that rise from the top of the hull and a deck built on top of the posts well above
       the water line. These are used in water depths no  more than 30 to 35 feet. A bottle type submersible
       consists of several steel cylinders or bottles. When the bottles are flooded, the rig submerges and sinks to
       the bottom, and when water is removed, they rise to the surface. These rigs can be used in water depths
       up to 100 feet.

    *•  Jackup rigs-barge-mounted rigs with extendable legs that are retracted during transport. At the drill site,
       the legs are extended to the seafloor. As the legs continue to extend, the barge hull is lifted above the
       water. Jackup rigs, which can be used in waters up to 300 feet deep, can be categorized by their leg type:
       columnar leg and open-truss leg.

Floating drilling units are typically used when drilling occurs in deep waters and  at locations far from shore.
Types of floating units include:

        *•      Semi-submersible-a type of floating drill  unit that can withstand rough seas with minimal rolling
              and pitching tendencies, thus they are used for drilling projects in ultra-deep water Gulf regions.
              They are hull-mounted and float on the surface of the  water when empty. At the drilling site, the


C2-2

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

               hulls are flooded and sunk to a certain depth below the surface of the water. When the hulls are
               fully submerged, the unit is stable and not susceptible to wave motion due to its low center of
               gravity. The unit is moored with anchors to the seafloor.  The two types of semi-submersible rigs
               are bottle-type (similar in concept to the bottle-type submersible) and column-stabilized.

        *•       Drill ships and ship-shaped barges-vessels that float on the surface of the water equipped with
               drilling rigs. These vessels maintain position above the drill site by anchors on the seafloor or the
               use of propellers mounted fore, aft, and on both sides of the vessel (dynamic positioning). Drill
               ships are the other major drilling rig used in ultra-deep Gulf waters. In these locations, drill ships
               typically operate using dynamic positioning.  Drill  ships and ship-shaped barges are susceptible
               to wave motion since they float on the surface of the water, and thus are not suitable for use in
               heavy seas.

Of the five basic types of MODUS  (submersibles, jackups, semi-submersibles, drill ships, and drill barges), the
drill ships, semi-submersibles, and jackups are the three types that typically intake over 2 MOD of cooling water,
with drill ships having the highest intake rates. Among drill ships with known intake rates above 2 MGD, all
intake more than 50 MGD.  Jackups and semi-submersibles do not generally appear to intake more than 20 MGD,
but many intake more than 2 MGD. Submersibles and drill barges generally have cooling water intake below the
2 MGD cutoff. Drilling operations  use cooling water for purposes such as cooling  engines, compressors,
winches, and pumps (U.S. EPA 2004).

C2-1.2  Existing MODUs and Their Associated Firms

Table C2-1 presents a listing of the  existing MODUs' owners and the number of rigs they are currently operating
in the GOM (as of 2002). These include MODUs that may have CWIS intake rates that do not exceed 2 MGD.
Most  MODUs are held by just a few firms. GlobalSantaFe, Transocean, Rowan Companies, Noble Corp. Parker
Drilling, Pride International, ENSCO International, and Diamond Offshore operate 326 MODUs, 85% of the
total.1 The firms that own MODUs generally work as contractors to the oil and gas exploration and production
industry. The  provision of drilling  and related services to U.S. and/or foreign offshore regions  is the major focus
of their business.
    1 This count includes 53 MODUs currently operating outside of U.S. waters, which EPA is treating as not regulated by the
rulemaking.
                                                                                                    C2-3

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                        Table C2-1: Number of Existing MODUs and Parent Firms
Company
Atwood Oceanics
Blake Drilling & Workover
Blue Dolphin
BSI Drilling
Caspian Drilling Company
Cyprus Company
Diamond Offshore
Energy Equipment Resources
ENSCO International Inc
Global Santa Fe
Nabors Industries
Newfield Exploration Company
Noble Corp.
NR Marine
Ocean Rig Asa
Parker Drilling
Pride International
Rowan Companies Inc
Tetra Technologies
Transoceanlnc.
Workships BV
Total Number of Rigs
Number of Rigs
3
19
1
3
2
1
29
1
30
56
15
1
22
1
2
37
29
24
7
99
2
384
                      Source:  ERG, 2004d; Table C2-2.
Table C2-2 presents the operating companies associated with the parent companies listed in Table C2-1.  The total
number of potentially affected parent firms is 21.  These affiliations were determined primarily on the basis of
Security and Exchange Commission (SEC) data. SEC maintains an online database (the Edgar Database), on
which all filings of publicly held firms are available. The 10K annual reports and 8K reports are used the most to
collect this information.  The 10K annual reports to SEC generally list significant subsidiaries and are the source
of income statement and balance sheet information for characterizing financial conditions at a firm. Subsidiary
lists are used to confirm ownership relationships.  The 8-K forms, in which significant changes to the firm must
be announced, are often the source of information on mergers and acquisitions.
C2-4

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                      Table C2-2:  Owners of MODUs Currently Operating in COM and
                                                 Parent Company
                               Listed Owner
            Parent Company
                  Atwood Deep Seas

                  Atwood Oceanics

                  Blake Workover & Drilling

                  BSI Drilling

                  Caspian Drilling Company

                  Chiles Offshore

                  Diamond Offshore

                  Drillmar

                  Energy Equipment Resources

                  ENSCO

                  ENSCO Offshore Company

                  Enserch Exploration

                  Falcon Drilling Company

                  Global Marine Deepwater

                  Global Marine Drilling Co.

                  Global Marine North Sea Inc

                  GlobalSantaFe

                  Global Santa Fe/Glomar

                  Glomar

                  Hercules Offshore

                  Mallard Bay Drilling

                  Marine Drilling Companies

                  Nabors

                  Nabors Offshore

                  Noble

                  Noble Drilling Corp

                  Noble Drilling US

                  Noble International

                  Noble Mexico

                  NR Marine

                  Ocean Rig Asa

                  Parker Drilling
Atwood Oceanics

Atwood Oceanics

Blake Workover & Drilling

BSI Drilling

Caspian Drilling Company

ENSCO International, Inc.

Diamond Offshore

Blue Dolphin

Energy Equipment Resources

ENSCO International, Inc.

ENSCO International ,Inc.

Newfield Exploration

Transocean, Inc.

GlobalSantaFe

GlobalSantaFe

GlobalSantaFe

GlobalSantaFe

GlobalSantaFe

GlobalSantaFe

Parker Drilling

Parker Drilling

Pride International

Nabors Industries

Nabors Industries

Noble Corp.

Noble Corp.

Noble Corp.

Noble Corp.

Noble Corp.

NR Marine

Ocean Rig Asa

Parker Drilling
                                                                                                                C2-5

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                   Table C2-2: Owners of MODUs Currently Operating in COM and
                                           Parent Company
Listed Owner
Pride International
Pride Offshore
R&B Falcon
Rowan
Rowan Companies, Inc
Rowan/Rowan Companies, Inc.
Rowan/Rowan Drill, Inc.
Rowan/Rowan International Inc.
Seatanker's Management
Tetra Applied Technology
Transocean
Transocean Sedco Forex
Transocean/Deepwater Drilling LLC
Workships BV
Parent Company
Pride International
Pride International
Transocean, Inc.
Rowan Companies
Rowan Companies
Rowan Companies
Rowan Companies
Rowan Companies
Cyprus Company
Tetra Technologies
Transocean, Inc
Transocean, Inc
Transocean, Inc
Workships BV
Source: ERG, 2004d; SEC, 2003.
The identification of corporate parent is critical to determining which firms should be defined as small under SBA
standards. SBA defines the size of the firm to be that of the firm at the highest level of organization. Generally,
EPA characterized a firm at the higher level of organization if it was majority owned by the larger entity. This
approach is consistent with SBA's definition of affiliation. Small firms that are affiliated (e.g., 51% owned) by
firms defined as large by SBA's standards (13CFR Part 121) are not considered small for the purposes of
regulatory flexibility analysis (see Section Dl for more details). Affiliated firms can also be firms owned by the
same owners or that have the same corporate officers as another firm.

Another key piece of information needed for classifying firms as small or large is what industry the  firm belongs
to. SBA defines small businesses differently for different types of industry and currently uses NAICS to classify
industries. SEC still requires companies to report their SIC code, not the NAICS code. Crosswalks between
NAICS and SIC, however, are available from Bureau of the Census (2004).

Once the parent firms were identified as above and the proper NAICS identified based on the reported SIC code
in the 10K reports and the NAICS crosswalk information, the revenue and employment (or other criteria, as
appropriate) for these parent firms were determined and compared to the SBA definition of small based on their
NAICS classification. Table C2-3 shows the SBA definitions for the industries identified.

It is assumed that all domestic firms that could not be identified as large are  small businesses. Also, for the
purposes of this analysis, MODU operators owned by foreign firms are assumed to be  large, even when data on
employment could not be found, because SBA defines a small business as one "with a place of business in the
United States, and which operates primarily in the United States or which makes a significant contribution to the
economy" (13 CFR Part 121).  Only large businesses in this industry would  meet the latter criteria, and few, if
any,  foreign firms operate primarily in the United States.
C2-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities     C2: Profile ofOOGE Industry

Table C2-3 presents the number of MODU parent companies by NAICS and SIC code, where that information is
available. For the most part, those identified as small may not actually be small but are apparently privately
owned and no information was available to support defining them as large. Eight firms are foreign-owned and
presumed large.  Industrial classification data are unavailable for foreign firms. Only two firms are positively
identified as small, out of the 21 total firms operating existing MODUs, but four companies believed to be
domestic could not be identified as small or large, so are presumed to be small. These firms (along with foreign-
owned firms) are not counted in the number of firms shown in Table C2-3, because their NAICS classifications
are also unknown.
                     Table C2-3: NAICS Classification of MODU Parent Companies
SIC code
1311
1381
1389
2819
NAICS code
211111
213111
213112
211112
NAICS Description
Crude Petroleum and Natural
Gas Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and
Gas Operations
Natural Gas Liquid Extraction
SBA Definition of Small
500 employees
500 employees
$7.5 million in revenues
500 employees
Total Number of
Firms3
Small Large
2 0
0 6
0 1
0 1
 a       Does not include seven foreign firms and four unknown firms for which NAICS or SIC codes could not be located in publicly
         available data.

 Source:  SEC, 2003; 13 CFR Part 121.
Table C2-4 presents the financial conditions at the parent firms listed in Table C2-2. A number of parent
companies are privately held or are foreign and do not have financial information available on the SEC database,
so information is not presented for these firms.  The financial data shown are from 2002, the base year for the new
offshore oil and gas extraction facility analysis. The total assets of the MODU parent companies range from $8
million to $12.7 billion. The revenues range from $3 million to $2.7 billion.  The three financial ratios calculated
in the table are the return on assets, return on equity, and the profit margin. Each of these ratios calculates the net
income as a ratio over the total assets, stockholder's equity, and total revenues respectively, and are commonly
used measures of financial health in the oil and gas industry. The return on assets percentages range from -29.5%
to 6.8%, and the profit margin ranges from -139% to 21%.
                                                                                                     C2-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry
                                        Table C2-4: Financial Condition of MODU Parent Companies (2002)
Firms
Atwood Oceanics
Blake Drilling & Workover
Blue Dolphin
BSI Drilling
Caspian Drilling Company
Diamond Offshore
Energy Equipment
Resources
ENSCO International, Inc
GlobalSantaFe
Nabors Industries
Newfield Exploration
Company
Noble Corp.
NR Marine
Ocean Rig Asa
Parker Drilling
Pride International
Rowan Companies Inc
Cyprus Company
Tetra Technologies
Transocean Inc.
Workships BV
Size
Large
Small*
Small
Small*
Large**
Large
Small*
Large
Large
Large
Small
Large
Small*
Large**
Large
Large
Large
Large**
Large
Large
Large**
Type
Other
Other
Other
Other
Foreign
Independent
Other
Other
Foreign
Foreign
Independent
Independent
Other
Foreign
Other
Other
Other
Foreign
Other
Foreign
Foreign
No. of
Employees
800

11


3,766

4,300
8,800
15,261
488
3,747


2,898
10,100
5,237

1,391
13,200

Assets
($000)
$445,238

$7,775


$3,258,765

$3,061,500
$5,808,200

$2,315,753
$3,065,714


$953,325
$4,324,995
$2,054,504

$308,817
$12,665,000

Equity
($000)
$276,133

$5,765


$1,335

$1,967,000
$4,234,200

$1,009,231
$1,989,210


$300,626
$1,699,705
$1,131,777

$184,152
$7,141,000

Revenues
($000)
$149,157

$2,910


$752,561

$698,100
$2,017,700

$661,750
$986,356


$389,946
$1,269,774
$617,258

$242,606
$2,674,000

Net Income
($000)
$28,285




$62,520

$59,300
$277,900

$73,847
$209,503


($114,054)
($8,947)
$86,278

$8,899
($3,732,000)

Return on
Assets
6.35%




1.92%

1.94%
4.78%

3.19%
6.83%


-11.96%
-0.21%
4.20%

2.88%
-29.47%

Return on
Equity
10.24%




4683.15%

3.01%
6.56%

7.32%
10.53%


-37.94%
-0.53%
7.62%

4.83%
-52.26%

Profit
Margin
18.96%




8.31%

8.49%
13.77%

11.16%
21.24%


-29.25%
-0.70%
13.98%

3.67%
-139.57%

 * Presumed small due to lack of data.
 "Presumed large-foreign-owned.

 Source:  Table C2-2; SEC, 2003, U.S. EPA 2000.
C2-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

C2-1.3 Existing MODUs with Intake Rates Meeting Proposed Rule Criteria

a.  Overview of Existing MODUs as Models for New MODUs
To provide information on whether new MODUs might be subject to Phase III regulation, EPA investigated
information obtained from a survey of MODUs undertaken for the Phase III rulemaking decision. Not all of the
MODUs owned by the firms listed above meet the applicability standard (at least 2 MOD design intake flow) and
other criteria of the proposed rule. EPA used a multi-step process to estimate the total number of existing MODUs
that would be regulated under the proposed rule  if they were newly constructed (i.e., CWISs with total design
flow of at least 2 MOD or more or less than 25% of intake volume used for cooling water purposes).2 The
sampling frame used 384 MODUs  as shown in Table C2-1).  Among these 384 MODUs in this universe, EPA
sampled 30 MODUs in the survey. The survey weights for all MODUs is thus 384 divided by 30, or 12.8.

The following is the status of the economic survey respondents:

       *•       23 respondents returned surveys

       *•       8 respondents were determined to have CWISs that meet proposed rule criteria.

       *•       15 respondents were determined to have CWISs that do not meet proposed rule criteria or were
               not operating in U.S. waters

       *•       4 surveys were not returned from among a group of MODUs whose CWIS intake rates were
               known (based on voluntary data submitted during the 316(b) Phase I rulemaking)

       *•       3 surveys were not returned among a group of MODUs whose CWIS intake rates were unknown.

Based on the ratio of respondents whose intake rates meet proposed rule criteria to total respondents (8/23), EPA
assumes that among the three MODUs with unknown intake rates, one will have intake rates meeting the
proposed rule's criteria and two will have intake rates not meeting these criteria. Thus, the total number of
MODUs in the economic survey sample whose intake rates are assumed to meet proposed rule criteria is
estimated to be 13. Multiplying this number by the  survey weight of 12.8 yields an estimate of a total of 166
MODUs with intake rates meeting  proposed rule criteria. Another six MODUs, originally thought to have intake
rates of less than 2 MOD were determined to have intake rates greater than 2 MOD, and these are added to the
estimate of MODUs with CWISs meeting proposed rule criteria, for a total of 172 MODUs meeting the proposed
rule's criteria - roughly half of the existing MODUs operating in U.S. waters (331 MODUs or about 52 %). EPA
therefore assumes that approximately half of new MODUs built might meet proposed rule criteria. Of the 172
MODUs meeting proposed rule criteria, EPA estimates that all new semi-submersibles and jackups will have
CWIS flow rates below 20 MGD, based on all surveyed semi-submersibles and jackups having rates below 20
MOD. EPA also estimates that all  new drill ships will have rates above 50 MGD, based on all surveyed drill
ships having intake rates of this size.  For more information on the estimate of existing MODUs that might meet
proposed rule criteria, see ERG, 2004a.

b.  Current Drilling Activity and Trends
In 2002, 62 wells were drilled offshore  in the Gulf of Mexico on Federal offshore leases. Offshore drilling rigs
are extremely capital intensive.  Therefore, once a company has invested in a rig, it is in their best interest to keep
the rig in operation. Currently, the utilization of all rigs worldwide stands at 72%, which is down significantly
from 85% in 1998 (Drilling Contractor, 2003a).  Trends seem to indicate increased utilization in certain regions
however, such as in the Gulf of Mexico. The jackup market, in particular, has  shown pricing improvement in the
GOM. The Bureau of Land Management's Minerals Management Service (MMS) projects that oil production in
the Gulf of Mexico should be between 1.5 and 2.0 million barrels per day (bpd) by the end of 2005 and gas
production should be between 11 and 17 billion cubic feet per day (bcfd) by the same time period.  Deepwater
    2 For simplicity, the text refers to operations that meet either of these criteria as not meeting proposed rule criteria, even though the
proposed rule does not apply to existing facilities..
                                                                                                   C2-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

exploration and deep exploration in the shallow waters of the GOM are expected to continue to grow. Deepwater
exploration in the Gulf of Mexico is projected to be a significant source of new oil and gas supplies in future
years (Drilling Contractor, Nov/Dec 2001).

c. Estimates of New MODUs To Be Constructed
The progress report published by Offshore magazine shows that the majority of offshore production investment in
2003 is in the refurbishment of old rigs, however some new rigs are being built. In 2003, the majority of new
offshore construction comprised jackup rigs. Surveys indicate that 14 jackups were completed in 2003, and that
eight additional jackups are to be completed by 2005. Of the eight jackups to be completed, three are being built
with a new Rowan  Companies design specifically introduced for deep shelf drilling in the shallow water of the
Gulf of Mexico (Offshore, July 2003). The outlook of the offshore industry shows increased growth in deepwater
drilling. Three companies are reported as having deepwater semi-submersibles completed by 2004. The
projections predict  that up to 67% of oil production and 27% of gas production will come from deepwater drilling
by 2005. (Drilling  Contractor, Nov/Dec 2001).

Since jackups and semi-submersibles are among the most frequent MODUs to have CWIS intake rates that would
meet proposed rule criteria, EPA focuses on these as an indication of how many MODUs might be built with
CWIS intake rates of concern. Given that 22 jackups are expected to be completed over the time period of 2003-
2005 (three years) (Drilling Contractor, 2003b), EPA assumes seven jackups might be built each year during the
time frame of the economic analysis; of this group (based on the assumption that half of all new MODUs would
meet proposed rule criteria, discussed above) EPA assumes four of these would be affected by  the 316(b)
requirements. It is  further assumed that about one  semi-submersible will be built per year. To be conservative,
EPA assumes each  of these semi-submersibles would meet proposed rule criteria.  Drill ships may also be
constructed during  the time frame of the analysis, but there are currently very few drill ships operating in the
GOM. Only 12 out of a total 384 MODUs operating in the GOM (3%) are drill ships.  EPA conservatively
assumes three drill  ships might be constructed over the entire 20-year time frame of the analysis, all of which are
assumed to meet proposed rule criteria.

The other two types of MODUs (submersibles and barges) are seldom associated with CWIS intake rates meeting
proposed rule criteria (U.S. EPA, 2004). EPA assumes no submersibles or barges with total design intake rates
meeting proposed rule criteria will be built during the time frame of the analysis. EPA assumes that half the
jackups and  semi-submersibles will be built with proposed technologies in place to control intake of aquatic
species under a two MGD cutoff. The drill ships are assumed to be  built with 50 MGD or greater intake rates, and
the jackups and semi-submersibles are assumed to  be built with intakes having a total intake rate of less than 20
MGD, based on the intake rates of existing MODUs of these types in the survey.
C2-2   OIL AND GAS PRODUCTION PLATFORMS

C2-2.1  Overview

Oil and gas production operations generally take place on platforms or other structures.  The primary areas of
offshore oil and gas production activity are the GOM, California, and Alaska. In shallow offshore waters,
platforms are the typical structure used to support the resource extraction activities. These activities may involve
drilling wells, producing oil and gas from wells, separating production streams, gathering and compressing gas,
and working over older wells to increase production. Platforms often support buildings for crews, including in
some cases, long-term living quarters.

There are several different types of platforms, and non-platform structures used in the GOM.  Seven major types
of production systems are used in offshore oil and gas production.

        *•       The fixed platform is the most commonly used for shallow-water drilling. It is anchored directly
               into the seabed with a deck to support living quarters etc.  While it is primarily used for shallow
               water drilling, it is economically feasible for depths up to 1,650 ft.


C2-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
        *•       The compliant tower is a flexible tower and piled foundation with a conventional deck. The
               compliant tower differs from the fixed platform in that it can withstand large lateral forces.
               Therefore, it is effective at greater depths and is typically used in water depths between 1,500 and
               3,000 ft.

        *•       The Seastar platform is a floating  mini-tension leg platform used for smaller deepwater reserves.
               It is used in water depths from 600 to 3,500 ft.

        *•       A floating production system (FPS) is a semi-submersible with drilling and production
               equipment.  The FPS can be dynamically positioned using rotating thrusters. The FPS is used at
               depths from 600 to 6,000 ft.

        *•       Another type of offshore platform is the Tension Leg platform (TLP).  It is connected to he sea
               floor with tension tendons. TLPs  are used up to depths of 6,000 ft.

        *•       The Spar platform consists of a large diameter cylinder supporting a deck and is used in water
               depths up to 3,000 ft.

        *•       The Subsea system can produce single or multiple wells using manifold pipeline systems.  The
               Subsea system is used for production at depths greater than 7,000 ft. (U.S. EPA, 2000). In this
               system, all well completions are at the seafloor level, with piping leading to production platforms
               in shallower water or nearby deepwater structures.

C2-2.2  Existing Platforms and Their Associated Firms

EPA's primary sources of data on platforms in most of the regions of concern (GOM and California)  are from the
Department of the Interior, Minerals  Management Service (MMS).  MMS collects data on platforms, drilling, and
production from all of the platforms located in Federal waters (3 miles offshore in most locations, but 10 miles
beyond the Texas shoreline). Early investigations by EPA (U.S. EPA, 2004) indicated that water intakes for
cooling waters in near-shore regions  of the Gulf (both in the coastal regions and in offshore State waters) appear
to be well below 2 MGD. Thus, EPA has focused only on the operations in Federal waters in the GOM.
Operations in the coastal subcategory and in State  offshore waters of the GOM are therefore considered unlikely
to be affected by the rulemaking and are not discussed further.

a. Platforms in the GOM
Early in the process of identifying existing platforms where cooling water intake rates might be in the size range
of concern, EPA determined that the  largest platforms and those in deepwater locations (1,000 feet of water depth
or greater) appeared the likeliest to have CWISs with at least 2 MGD of total flow (ERG, 2003). This finding was
based on voluntary data submissions from industry on a number of platforms operating in the GOM (ERG, 2004a,
DCN 7-3505). Based on this analysis, EPA divided the analysis in the GOM into  several groups-platforms in
deep water (in depths of a 1,000 feet of water or more), shallow water platforms (< 1,000 feet) with 20 or more
slots available for wells (considered large platforms), and shallow water platforms with fewer than  20 slots (small
platforms). These groupings were used to stratify  EPA's survey of platforms conducted for the proposed 316(b)
Phase III rulemaking.

Using a database compiled by MMS  as of June 2003, EPA created a list of platforms located in the Gulf of
Mexico. The database was downloaded and counts of structures were noted. Abandoned platforms and platforms
without production equipment were eliminated from the platform count. The platforms were then categorized by
deepwater and shallow water, and 20+ wells and <20 wells. The counts are presented in Table C2-5.  As the table
shows, the about 90% of platforms in the GOM are small platforms  operating in shallow water.  Only a very few
structures  (generally not the typical fixed platforms) are found in the deepwater regions of the GOM.  Currently
(2003 data) only 26 are considered built and operational in the MMS database.
                                                                                                   C2-11

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                                   Table C2-5: COM Platform Count
                                    Category
              Total Number of Platforms

              Removed Platforms

              Abandoned Platforms

              Platforms without Production Equipment

Producing Platforms


Deep

Shallow

Deepwater
>=20 slots

<20 slots
Total Producing Platforms
26
209

2,194
2,429
Count
6,226

2,229

 21

1,587
              Source:  MMS, 2003a.
These platforms are operated by a number of firms of different sizes and types.  The potentially affected firms can
be divided into two basic categories. The first category consists of the major integrated oil companies, which are
characterized by a high degree of vertical integration (i.e., their activities encompass both "upstream"
activities—oil exploration, development, and production—and "downstream" activities—transportation, refining,
and marketing). The second category of affected firms consists of independents engaged primarily in exploration,
development, and production of oil and gas and not typically involved in downstream activities. Some
independents are strictly producers  of oil and gas, while others maintain some service operations, such as contract
drilling and well servicing.

The major integrated oil companies are generally larger than the independents.  As a group, the majors typically
produce more oil and gas, earn significantly more revenue and income, and have considerably more assets and
greater financial resources than most independents.  Furthermore, majors tend to be relatively homogeneous in
terms of size and corporate structure.  All majors are considered large firms under the Regulatory Flexibility Act
(RFA) guidelines  and generally are C corporations (i.e., the corporation pays income taxes). Independents can
vary greatly by size and corporate structure. Larger independents tend to be C corporations; small firms might
also pay corporate taxes, but they also  can be organized as S corporations (which elect to be taxed at the
shareholder level rather than the corporate level under subchapter S of the Internal Revenue Code). Small firms
also might be organized as limited partnerships, sole proprietorships, etc., whose owners, not the firms, pay taxes.

The proportions of majors and independents operating in the State offshore in the GOM has been changing over
the last dozen or more years. Except for the deepwater GOM, majors have generally been disinvesting in the
Gulf, selling their platforms to independents. Independents, because of their different cost structures and risk
profiles can often  operate marginal  platforms far longer than majors.  Independents often have lower overheads.
Furthermore, many independents who  operate platforms purchased from majors do not engage as extensively in
exploration, thus they may be tolerant of lower returns, since their risks are lower.

Table C2-6 summarizes the information developed using the MMS databases, listing the firms operating in the
Federal GOM.  To identify parent companies and/or recent changes in ownership, EPA again used SEC's Edgar
database. Note that EPA's analysis is based primarily on the status of the industry as of year end 2002, reported
C2-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry


in March 2003 (the date by which most firms must submit their 10K reports). Mergers and acquisitions continue
to occur among this group of firms.3
                       Table C2-6: Operators and Parent Companies of GOM Platforms
                         Operator Company
                Parent Company
      AEDC USA Inc

      AGIP Petroleum Co Inc

      AGIP Petroleum Exploration Co Inc

      Amerada Hess Corporation

      Anadarko E&P Company LP

      Anadarko Petroleum Corporation

      Apache Corporation

      Apex Oil & Gas Inc

      Arena Offshore LLC

      ATP Oil & Gas Corporation

      B T Operating Co

      Barrett Resources Corporation

      BHP Billiton Petroleum (Americas) Inc

      Bois D'arc Offshore Ltd

      BP America Production Company

      BP Exploration & Production Inc

      Burlington Resources Offshore Inc

      Caim Energy USA Inc

      Gallon Petroleum Operating Company

      Calpine Natural Gas Company

      Century Exploration Company

      Chevron USA Inc

      CNG Pipeline Company

      Cockrell Oil Corporation

      Comstock  Offshore LLC

      Conn Energy Inc

      ConocoPhillips Company

      Contour Energy E&P LLC
AOC Energy Development Company Ltd.

AGIP Petroleum Co Inc

AGIP Petroleum Co Inc

Amerada Hess Corporation

Anadarko Petroleum Corporation

Anadarko Petroleum Corporation

Apache Corporation

Apex Oil & Gas Inc

Arena Resources

ATP Oil & Gas Corporation

B T Operating Co

Williams Companies Inc

BHP Billiton Petroleum (Americas) Inc

Bois D'arc Offshore Ltd

BPPLC

BPPLC

Burlington Resources Inc

Caim Energy USA Inc

Gallon Petroleum Co

Calpine Corp

Century Exploration Company

ChevronTexaco

Dominion Resources Inc

Cockrell Oil Corporation

Comstock Resources

Conn Energy Inc

ConocoPhillips Company

Contour Energy Co
    3 Note that all corporate ties could not be identified.  Corporate parents are not obliged to list all subsidiaries, only
significant subsidiaries.  Where no corporate ties could be identified, EPA assumed the operator listed was at the highest level
of corporate organization.
                                                                                                             C2-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities     C2: Profile ofOOGE Industry
                       Table C2-6: Operators and Parent Companies of GOM Platforms
                         Operator Company
                Parent Company
      Delos Offshore Company LLC



      Denbury Offshore Inc



      Devon Energy Production Company LP



      Devon SFS Operating Inc



      Dominion Exploration & Production Inc



      Duke Energy Field Services LP



      Dunhill Resources Inc



      Dynegy Midstream Services Limited Partnership



      EEX Corporation



      El Paso Production Company



      El Paso Production Gom Inc



      El Paso Production Oil & Gas Company



      Energy Partners Ltd



      Energy Resource Technology  Inc



      EOG Resources Inc



      Equilon Pipeline Company LLC



      ExxonMobil Corporation



      Fairways Specialty Sales & Service Inc



      Flextrend Development Company LLC



      Forest Oil Corporation



      Freeport McMoran Sulphur LLC



      Garden Banks Gas Pipeline LLC



      GOM Shelf LLC



      Gryphon Exploration Company



      Hall-Houston Oil Company



      HC Resources LLC



      Houston Exploration Company



      Hunt Oil Company



      Hunt Petroleum (AEC) Inc



      J M Huber Corporation



      J Ray McDermott Technology Inc



      Juniper Energy LP



      Kerr-McGee Corporation



      Kerr-McGee Oil & Gas Corporation
El Paso Corp.



Denbury Resources



Ocean Energy Inc



Ocean Energy Inc



Dominion Resources Inc



Duke Energy Co



Dunhill Resources Inc



Dynagy Inc



Newfield Exploration Company



El Paso Corp.



El Paso Corp.



El Paso Corp.



Energy Partners Ltd



Energy Resource Technology Inc



EOG Resources Inc



Equilon Enterprises LLCa



Exxon Mobil Corporation



Fairways Specialty Sales & Service Inc



El Paso Corp.



Forest Oil Corporation



McMoran Exploration Co



Garden Banks Gas Pipeline LLC



GOM Shelf LLC



Gryphon Exploration Company



Hall-Houston Oil Company



HC Resources LLC



Houston Exploration Company



Hunt Oil Company



Hunt Petroleum (AEC) Inc



J M Huber Corporation



McDermott International Inc.



Juniper Energy LP



Kerr-McGee Corporation



Kerr-McGee Corporation
C2-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                       Table C2-6: Operators and Parent Companies of GOM Platforms
                         Operator Company
                Parent Company
       Linder Oil Company, a Partnership



       LLOG Exploration Offshore Inc



       Louis Dreyfus Natural Gas Corp



       Magnum Hunter Production Inc



       Manta Ray Offshore Gathering Company LLC



       Marathon Oil Company



       Maritech Resources, Inc



       Matrix Oil & Gas, Inc



       McMoRan Oil & Gas LLC



       Merit Energy Company



       Millennium Offshore Group Inc



       Mission Resources Corporation



       Mobil Oil Exploration & Production



       Murphy Exploration & Production



       Murphy Exploration & Production Company - USA



       NCX Company LLC



       Newfield Exploration Company



       Nexen Petroleum USA Inc



       Nippon Oil Exploration USA



       Ocean Energy Inc



       Offshore Energy I LLC



       Panaco Inc



       Petro Ventures Inc



       Petrobras America Inc



       Petroquest Energy LLC



       Pioneer Natural Resources USA Inc



       Pogo Producing Company



       PRS Offshore LP



       Remington Oil and Gas Corporation



       Samedan Oil Corporation



       Scana Petroleum Resources Inc



       Seagull EnergyE&P Inc



       Seneca Resources Corporation



       Shell Frontier Oil & Gas Inc
Linder Oil Company, a Partnership



Amerada Hess Corporation



Dominion Resources Inc



Magnum Hunter Production Inc



El Paso Corp.



Marathon Oil Corp



Maritech Resources, Inc



Matrix Oil & Gas, Inc



McMoRan Exploration Co



Merit Energy Company



Millennium Offshore Group Inc



Mission Resources Corporation



ExxonMobil Corporation



Murphy Oil Corporation



Murphy Oil Corporation



NCX Company LLC



Newfield Exploration Company



Nexen Petroleum USA Inc



Nippon Oil Exploration USA



Ocean Energy Inc



Offshore Energy I LLC



Panaco Inc



Petro Ventures Inc



Petrobras America Inc



Petroquest Energy LLC



Pioneer Natural Resources Co



Pogo Producing Company



PRS Offshore LP



Remington Oil and Gas Corporation



Noble Energy Inc



Scana Petroleum Resources Inc



Ocean Energy Inc



National Fuel Gas Company



Royal Dutch/Shell Group
                                                                                                              C2-15

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities     C2: Profile ofOOGE Industry
                       Table C2-6: Operators and Parent Companies of GOM Platforms
                         Operator Company
                Parent Company
       Shell Offshore Inc

       Shell Oil Company

       Spinnaker Exploration Company LLC

       St Mary Energy Company

       Stone Energy Corporation

       Tarpon Offshore LP

       Taylor Energy Company

       TDC Energy Corporation

       TDC Energy LLC

       Texaco Exploration and Prod

       The Louisiana Land and Exploration Company

       Torch Energy Services Inc

       TotalFinaElf E&P USA Inc

       Transcontinental Gas Pipe Line Corporation

       Transworld Exploration and Production Inc

       Tri-Union Development Corporation

       UMC Pipeline Corporation

       Union Oil Company of California

       Unocal Pipeline Company

       Vastar Resources Inc.

       Vintage Petroleum Inc

       W & T Offshore Inc

       Walter Oil & Gas Corporation

       Westport Oil and Gas Company LP

       Westport Resources Corporation

       WFS - Offshore Gathering Company

       William G Helis Company LLC

       Williams Field Services - Gulf Coast Company LP

       Williams Production RMT Company
Royal Dutch/Shell Group

Royal Dutch/Shell Group

Spinnaker Exploration Company LLC

St Mary Land & Exploration Co

Stone Energy Corporation

Tarpon Offshore LP

Taylor Energy Company

TDC Energy LLC

TDC Energy LLC

ChevronTexaco

Burlington Resources Inc

Torch Offshore

TotalFinaElf E&P USA Inc

Transcontinental Gas Pipe Line Corporation

Transworld Exploration and Production Inc

Tri-Union Development Corporation

UMC Pipeline Corporation

Unocal Corp.

Unocal Corp.

BPPLC

Vintage Petroleum Inc

W & T Offshore Inc

Walter Oil & Gas Corporation

Westport Oil and Gas Company LP

Westport Resources Corporation

Williams Companies Inc

William G Helis Company LLC

Williams Companies Inc

Williams Companies Inc
       a        Joint venture between Royal Dutch/Shell Group and Texaco currently operating as Shell Oil Products U.S. Shell
               bought Texaco's interests in 2002 (Alexander's Oil and Gas Connections, 2002).

       Source:  MMS,  2003a; SEC, 2003.
C2-16

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry


It is important to note that companies may share ownership of a platform.  In general, the company listed as the
operator in the MMS databases is the owner or largest share holder of the platform, but this is not always the case.
The economic analyses in this report, however, make the simplifying assumption that only one firm owns a
platform.  In reality, the impacts from regulatory costs to a platform might be shared by several firms.

The same methodology used to identify small firms in the MODU profile (Section C2-1) is used for this profile.
Table C2-7 lists the numbers of firms in the GOM by their NAICS definition.4 Also listed is the SIC code, which
is the identifier used in the  10K reports. In the table, NAICS and SICs are mapped in the key industry sectors
represented by firms operating in the GOM.
                           Table C2-7: Count of Firms by SIC and NAICS Code
   SIC code      NAICS code
                    NAICS Title
                                SBA Size Standard
                                                                                            GOM
                                                                                        Number of Firms
                                                                                       Small
                                                                                Large
     1311


     1389

     2911

     3443

     4911


     4922

     4924
211111


213112

324110



221112


486210

221210
Crude Petroleum and Natural
Gas Extraction

Support Activities for Oil and
Gas Operations

Petroleum Refineries

Several industries

Fossil Fuel Electric Power
Generation

Pipeline Transportation of
Natural Gas

Natural Gas Distribution
     500 employees            19


 $7.5 million in revenues         1

    1,500 employees            0

     750 employees3            0

4.0 million megawatt hours        0


 $6.0 million in revenues         1

     500 employees             0
12
 a       Highest number of employees defining small among the group of industries that 3443 has been split into.
 Note:    Does not include 37 firms considered domestic and 10 foreign firms for which NAICS or SIC codes could not be located in
         publicly available data.

 Source:  SEC, 2003, 13 CFR Part 121.
As Table C2-7 shows, the predominant firm types operating in the GOM are those in the oil and gas extraction
NAICS and the refineries NAICS. A total of 21 firms were identified as small.  Another 37 non-foreign firms
could not be identified as small or large thus are considered small for purposes of analysis. As was done for
MODU firms, all foreign firms were assumed to be large.  Once EPA accounted for these relationships and
transactions, EPA's count of potentially affected firms in the Gulf of Mexico becomes 96 firms, of which 10 are
listed as majors, and 10 firms are identified as foreign owned (not including  Shell Oil, a major that is affiliated
with Royal Dutch/Shell Group, but which reports to SEC). Non-foreign non-majors total 76 firms, including
those not previously identified as majors or independents (U.S. EPA, 2000).

Table C2-8 shows the firms considered potentially affected firms operating in the Federal GOM and their
relevant financial data.  These data include number of employees, assets, liabilities, and revenues,  along with
several ratios that provide a general indication of financial health. Note that blank lines in Table C2-8 indicate
firms that are likely to be privately held or are foreign and for which no public data have been located.
    4 The North American Industry Classification System (NAICS) supercedes the Standard Industrial Classification (SIC)
codes, however, the transition to the new system is still in progress.
                                                                                                      C2-17

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

The ratios used to establish company financial status are profitability ratios, namely: return on assets, return on
equity, and profit margin. As described earlier, these three financial indicators are calculated as the ratio of the
net income to the total assets, stockholders' equity, and net sales respectively.  While individually these ratios
only tell a part of the financial stability of a company, when analyzed together, they give a much clearer picture of
a company's financial health.

Of these operators in the Gulf, EPA has identified 58 (60%) that either meet the SBA's definition of a small
business (which for the oil and gas extraction industry is defined as a business entity with 500 or fewer employees
or for the oil field service industry as a business entity with $5 million or less in annual revenues) or that cannot
be identified as large because their employment or revenue figures are not known. These latter firms might be
privately owned, or they do  not file with the SEC as an independent firm but their parent company could not be
identified.  Most of these firms, however, are not likely to be involved in constructing new oil and gas platforms
that would be subject to Phase III regulation, as  discussed below. Small firms that might be affected by the rule
are discussed in more detail in Chapter Dl: Regulatory Flexibility Analysis.

Table C2-8 also presents summary financial ratios for the  large and small firms.  Among publicly held firms,
median return on assets for the group is 2.65%, median return on equity is 4.89%, and median profit margin (net
income/revenues) is 5.71%, according to 2002 financial data. Among these publicly held firms, 35 out of 48
firms, or 73%, reported positive net income for 2002.

b.  California Platforms
California has a total of 33 platforms; 9 located in State waters and 24 in State waters. Six companies operate
platforms in State water off the California shore: Aera Energy LLC, Arguello, Inc., ExxonMobil, Nuevo Energy,
Pacific Operators Offshore,  and Venoco Inc.  Two deepwater (>1,000 ft.) platforms operate in CA State waters,
both of which are owned by ExxonMobil.  Financial information for these companies is presented in Table C2-9
Aera Energy LLC, ExxonMobil, Nuevo Energy, and Venoco Inc. also operate platforms in State waters along
with two additional companies (Occidental Petroleum Co. and Rincon Island Limited Partnership). The
maximum depth  of platform drilling in State waters is 211 ft.  The maximum depth in State waters is  1,198 ft.
ExxonMobil and Shell (owning the majority of the joint venture  company, Aera Energy) are the only majors
operating in California State waters.  The other companies are all unidentified. Nuevo Energy Company and
Arguello (a subsidiary of Plains Exploration and Production) are the only companies specifically identified as a
small  business, with 412 employees and 354 employees (at the parent companies), respectively. Venoco Pacific
Operators, and Rincon Island, LP, are assumed small for lack of data. One of the firms in California is classified
as  NAICS 324110 (SIC 2911), Petroleum Refineries, one  firm is classified as NAICS 422720 (SIC 5172),
Petroleum and Petroleum Products Wholesale, and two additional firms are listed as NAICS 211111 (SIC 1311),
Crude Petroleum and Natural Gas Extraction. The NAICS classification of the remaining firms is undetermined.
C2-18

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry

Table C2-8:
Company Name
AOC Energy Development
Corp.
AGIP Petroleum Co Inc
Amerada Hess Corporation
Anadarko Petroleum Corp.
Apache Corporation
Apex Oil & Gas Inc
Arena Resources
ATP Oil & Gas
Corporation
B T Operating Co
BHP Billiton Petroleum
(Americas) Inc
Bois D'arc Offshore Ltd
BPPLC
Burlington Resources
Offshore Inc
Cairn Energy USA Inc
Gallon Petroleum
Operating Company
Calpine Corporation
Century Exploration Co.
ChevronTexaco
Cockrell Oil Corporation
Comstock Resources
Conn Energy Inc
ConocoPhillips Company
Contour Energy E & P
Size
Large**
Large**
Large
Large
Large
Small*
Small
Small
Small*
Large**
Small*
Large
Large
Large**
Small
Large
Small*
Large
Small*
Small
Small*
Large
Small
Type
Foreign
Foreign
Major
Independent
Independent
Other
Independent
Independent
Other
Foreign
Other
Major
Independent
Foreign
Independent
Other
Independent
Major
Independent
Independent
Other
Major
Independent
Number of
Employees


11,662
3,800
1,958

5
53



73,350
2,003
19
100
3,353

53,014

62

>10,000
47
Financial Conditions Among GOM Firms
Assets ($000) Equity Revenues
($000) ($000)


$2,455,425 $1,608,133
$1,280,000 $3,860,000
$9,459,851 $544,000 $2,559,873

$6,050 $5,125 $1,657
$182,055 $38,547 $94,423

$2,865,000 $2,815,000

$164,090,000 $178,721,000
$10,645,000 $3,832,000 $2,964,000
$696,100 $70,000
$410,613 $140,960 $67,108
$23,266,992 $7,457,899

$77,359,000 $31,604,000 $99,049,000

$683,071 $215,662

$76,836,000 $56,748,000

Net Income Return on Return on
($000) Assets Equity



$825,000 64.45%
$554,329 5.86% 101.90%

$403 6.66% 7.86%
($4,700) -2.58% -12.19%

$718,000 25.06%

$10,422,000 6.35%
$454,000 4.26% 11.85%
$29,100 4.18%
($1,671) -0.41% -1.19%
$118,618 0.51%

$1,132,000 1.46% 3.58%



($295,000) -0.38%

Profit
Margin



21.37%
21.65%

24.32%
-4.98%

25.51%

5.83%
15.32%
41.57%
-2.49%
1.59%

1.14%



-0.52%

                                                                                                                                                             C2-19

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry

Table C2-8: Financial Conditions Among GOM Firms
Company Name
LLC
Denbury Resources Inc
Dominion Resources
Duke Energy Co.
Dunhill Resources Inc
Dynegy Inc.
El Paso Corp.
Energy Partners Ltd
Energy Resource
Technology Inc
EOG Resources Inc
Equilon Enterprises
ExxonMobil Corporation
Fairways Specialty Sales &
Service Inc
Forest Oil Corporation
Garden Banks Gas Pipeline
LLC
GOM Shelf LLC
Gryphon Exploration
Company
Hall-Houston Oil Company
HC Resources LLC
Houston Exploration
Company
Hunt Oil Company
Hunt Petroleum (Aec) Inc
J M Huber Corporation
Size

Small
Large
Large
Small*
Large
Large
Small
Small*
Large
Large
Large
Small*
Small
Small*
Small*
Small*
Small*
Small*
Large
Small*
Small*
Small*
_ Number of Assets ($000) Equity Revenues Net Income Return on Return on
ype Employees ($000) ($000) ($000) Assets Equity

Independent 356 $895,292 $366,797 $285,152 $46,795 5.23% 12.76%
Other 17,000 $37,909,000 $10,218,000 $1,362,000 3.59%
Other 22,000 $60,966,000 $15,663,000 $1,034,000 1.70%
Other
Other 1,524 $20,030,000 $2,087,000 $5,553,000 ($1,955,000) -9.76% -93.68%
Other 11,885 $46,224,000 $8,377,000 $12,194,000
Independent 132 $384,220 $191,922 $134,031 ($8,799) -2.29% -4.58%
Independent
Major 1,000 $3,814,006 $1,672,395 $1,095,036 $87,173 2.29% 5.21%
Major
Major 92,500 $153,000,000 $74,597,000 $205,000,000 $11,460,000 7.49% 15.36%
Other
Independent 493 $1,924,681 $921,211 $475,694
Other
Other
Independent
Independent
Other
Independent 145 $1,138,816 $592,789 $345,381 $70,494 6.19% 11.89%
Independent
Independent
Independent
Profit
Margin

16.41%
13.33%
6.60%

-35.21%

-6.56%

7.96%

5.59%







20.41%



C2-20

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry

Table C2-8: Financial Conditions Among GOM Firms
Company Name
Juniper Energy LP
Kerr-McGee Corporation
Linder Oil Company, a
Partnership
Magnum Hunter
Production Inc
Marathon Oil Company
Maritech Resources Inc
Matrix Oil and Gas
McDermott International
Inc
McMoRan Exploration Co.
Merit Energy Company
Millennium Offshore
Group Inc
Mission Resources Corp.
Murphy Oil Company
National Fuel Gas
Company
NCX Company LLC
Newfield Exploration
Company
Nexen Petroleum USA Inc
Nippon Oil Exploration U
SA
Noble Corp.
Ocean Energy Inc
Offshore Energy I LLC
Panaco Inc
Size
Small*
Large
Small*
Small
Large
Small*
Small*
Large
Small
Large**
Large**
Small
Large
Large
Small*
Small
Large**
Large**
Large
Large
Small*
Small
Number of Assets ($000) Equity
ype Employees ($000)
Other
Independent 4,470 $9,909,000 $2,536,000
Other
Independent 221 $251,069 $72,152
Major 28,166 $4,479,000 $5,082,000
Other
Other
Other $128,171 ($416,757)
Independent 18 $72,448 ($64,431)
Foreign
Foreign
Independent 90 $342,404 $65,377
Major $3,885,775 $1,593,553
Other
Independent
Independent 488 $2,315,753 $1,009,231
Foreign 1,767 $41,548,000
Foreign $11,076,000
Independent 624 $3,065,714 $1,989,210
Independent 948 $131,613 ($825)
Independent
Independent 21
Revenues
($000)

$2,540,000

$48,834
$31,720,000


$1,748,681
$43,768


$105,464
$3,966,516


$661,750
$1,971,300
$34,894,000
$986,356
$47,483


Net Income Return on Return on
($000) Assets Equity

($485,000) -4.89% -19.12%

($3,512) -1.40% -4.87%
$516,000 11.52% 10.15%


($776,394) -605.75% 186.29%
$17,041 23.52% -26.45%


($38,484) -11.24% -58.86%
$111,508 2.87% 7.00%


$73,847 3.19% 7.32%
$287,200 0.69%
$269,000 2.43%
$209,503 6.83% 10.53%
$2,227 1.69% -269.94%


Profit
Margin

-19.09%

-7.19%
1.63%


-44.40%
38.93%


-36.49%
2.81%


11.16%
14.57%
0.77%
21.24%
4.69%


                                                                                                                                                             C2-21

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry


Company Name
Petro Ventures Inc
Petrobras America Inc
Petroquest Energy LLC
Pioneer Natural Resources
USA Inc
Pogo Producing Company
PRS Offshore LP
Remington Oil and Gas
Corporation
Royal Dutch/Shell Group
Scana Petroleum Resources
Inc
Spinnaker Exploration
Company LLC
St Mary Energy Company
Stone Energy Corporation
Tarpon Offshore LP
Taylor Energy Company
TDC Energy Corporation
LLC
Torch Offshore Inc.
TotalFinaElf E&P USA Inc
Transcontinental Gas Pipe
Line Corporation
Transworld Exploration
and Production Inc
Tri-Union Development
Corporation
UMC Pipeline Corporation

Size
Small*
Large**
Small
Large
Small
Small*
Small
Large
Small*
Small
Small
Small
Small*
Small*
Small*
Small
Large**
Large
Small*
Small*
Small*
Table C2-8:
Number of
Employees
Other
Foreign
Independent 57
Independent 979
Independent 219
Independent
Independent 29
J^J01 111,000
Foreign
Other
Independent 65
Independent 185
Independent 210
Other
Independent
Independent
Other 362
Foreign
Other 1,261
Other
Independent
Independent
Financial Conditions Among GOM Firms
Assets ($000) Equity Revenues Net Income Return on Return on
($000) ($000) ($000) Assets Equity


$132,063 $97,770 $48,141 $2,307 1.75% 2.36%
$3,455,100 $1,374,900 $717,400 $26,700 0.77% 1.94%
$2,426,608 $824,885 $605,500 $87,954 3.62% 10.66%

$288,993 $193,660 $104,186 $11,332 3.92% 5.85%
$152,691,000 $235,598,000 $9,419,000 6.17%

$842,715 $692,977 $188,326 $31,579 3.75% 4.56%
$537,139 $299,513 $196,394 $27,560 5.13% 9.20%
$1,179,371 $577,488 $377,495 $85,229 7.23% 14.76%



$101,904 $79,867 $67,990 $395 0.39% 0.49%

$4,969,532 $2,476,513 $1,276,282 $163,041 3.28% 6.58%
$12,665,000 $7,141,000 $2,674,000 ($3,732,000) -29.47% -52.26%



Profit
Margin


4.79%
3.72%
14.53%

10.88%
4.00%

16.77%
14.03%
22.58%



0.58%

12.77%
-139.57%


C2-22

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities
C2: Profile of OOGE Industry


Company Name
Unocal
Vintage Petroleum Inc
W & T Offshore Inc
Walter Oil & Gas
Corporation
Westport Oil and Gas
Company LP
Westport Resources
Corporation
William G Helis Company
LLC
Williams Company

Size
Large
Large
Small*
Small*
Small*
Small
Small*
Large

Type
Independent
Independent
Independent
Independent
Other
Independent
Independent
Other
Table C2-8:
Number of
Employees
6,615
690



333

7,300
Financial Conditions Among GOM Firms
Assets ($000) Equity
($000)
$10,760,000 $3,298,000
$1,775,804 $570,992



$2,233,451 $1,132,006

$34,988,500 $5,049,000
Revenues Net Income
($000) ($000)
$5,297,000 $331,000
$664,263 ($143,664)



$400,398 ($28,566)

$5,608,400 ($754,700)
Return on Return on Profit
Assets Equity Margin
3.08% 10.04% 6.25%
-8.09% -25.16% -21.63%



-1.28% -2.52% -7.13%

-2.16% -14.95% -13.46%
 Note: Other is used if no designation for major or independent is provided in U.S. EPA, 2000.
 * Presumed small due to lack of data.
 ** Presumed large - Foreign-owned.
 Source:  Table C2-6; SEC, 2003; U.S. EPA, 2000.
                                                                                                                                                             C2-23

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
    Table C2-9: Financial Information for Companies Operating Platforms in California Waters ($000)
Company Name
Royal/Dutch Shell
(Aera Energy)
Plains Exploration and
Production (Arguello)
ExxonMobil
Nuevo Energy
Company
Pacific Operators
Offshore
Venoco, Inc.
Rincon Island Limited
Partnership
Occidental Petroleum
Corp.
Size
Large
Small
Large
Small
Small3
Small"
Small3
Large
Type Employees Total Assets
Major 111,000 $152,691,000
Other 354 $550,880
Major 92,500 $153,000,000
Independent 412 $855,171
Other
Independent
Other
Major 7,244 $16,548,000
Equity Revenues
$235,598,000
$173,820 $178,038
$74,597,000 $205,000,000
$174,276 $323,056



$6,318,000 $7,491,000
Net Income
$9,419,000
$26,237
$11,460,000
$12,275



$989,000
 a       Presumed small due to lack of data.

 Source: ERG, 2004c; SEC, 2003; U.S. EPA, 2000.
c.  Alaska Operations
There are two major regions of oil and gas production in Alaska. The first, the North Slope region, operates
generally from onshore locations or on gravel islands.  Platforms are not used here.

The second region, Cook Inlet, Alaska, is divided into two regions: Upper Cook Inlet, which is in State waters
and is governed by the Coastal Oil and Gas effluent guidelines; and Lower Cook Inlet, which is considered
Federal OCS waters and is governed by the Offshore Oil and Gas Effluent Guidelines.  This section refers
primarily to  Upper Cook Inlet.

There are 16 platforms and 3 onshore production facilities in Cook Inlet, Alaska, of which two platforms have
ceased operation and two platforms have suspended operation.  The platforms are owned by five companies:
Forest Oil Corporation, Marathon Oil  Corp., ConocoPhillips, XTO Energy, and Unocal Corp. Marathon owns the
two out-of-operation platforms and is not considered a potentially affected firm in Alaska. Unocal  Corp. operates
the majority of platforms in the Cook Inlet region, with 10 platforms and 2 onshore treatment facilities. Only one
company operating in  Cook Inlet waters, Forest Oil, is an independent and considered a small business. XTO is
also an independent, but is a large business.  The remaining operators are all listed as majors, as is the operator
(BP) of the Duck Island structure in the Beaufort Sea (North Slope). Two of the firms in Alaska are listed under
NAICS 324110 (SIC 2911), Petroleum Refineries, and the three additional firms are  listed as NAICS 211111
(SIC 1311),  Crude Petroleum and Natural Gas Extraction. Financial data for these firms are presented in Table
C2-10

The Department of Fish and Game in Alaska developed a  standard lease requirement for all water intake pumps to
be fitted with a screened enclosure.  The requirement further States that the water intake at the surface of the
screen enclosure should not exceed 0.1 feet per second. For the purposes of the regulatory analysis, therefore, any
new platforms in the Cook Inlet or the North Slope regions are considered to be potentially affected by the 316(b)
requirements for entrainment, but not impingement, since the Alaska requirement meets or exceeds proposed
316(b) impingement standards.
C2-24

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
        Table C2-10: Financial Information for Companies Operating Platforms in Alaska ($000)
   Company Name     Size
Type
Employees     Tot. Assets
Equity
Revenues
Net Income
Forest Oil
BP
ConocoPhillips
XTO Energy
Unocal
Small
Large
Large
Large
Large
Independent
Major
Major
Independent
Major
493
73,350
>10,000
867
6,615
$1,924,681
$164,090,000
$76,836,000
$2,648,193
$10,760,000
$921,211


$907,786
$3,298,000
$475,694
$178,721,000
$56,748,000
$810,163
$5,297,000
$21,276
$10,422,000
($295,000)
$186,100
$331,000
 Source: ERG, 2004c; SEC, 2003; U.S. EPA, 2000.
C2-2.3 Existing Platforms with Intake Rates Meeting Proposed Rule Criteria

a. Overview of Existing Platforms as Model for New Platforms Subject to Phase III Regulation
Very few existing platforms appear to have CWISs with intake rates that meet the proposed rule's criteria. Most
of the existing platforms with CWISs of this size are located in the deepwaters of GOM and in California and
Alaska waters (Cook Inlet). Using the same approach as outlined for determining existing MODUs with CWIS
intake rates meeting proposed rule  criteria, EPA makes the following estimates, using the  survey conducted for
the oil and gas sectors to support this rulemaking and voluntary data submitted by industry.  See also ERG
(2004b).

EPA stratified the survey in the GOM into three strata: deepwater, shallow large (20+ slot platforms), and shallow
small (fewer than 20 slots).

The survey universe of deepwater structures was 24 (two structures were removed from the universe prior to the
survey because their CWIS intake rates were known to be less than 2 MGD).  For the survey, EPA sampled four
facilities. There were no non-respondents. Only one of the four reported data showing them to have CWIS intake
rates meeting proposed rule criteria. Thus EPA estimated that six deepwater structures would have CWIS intake
rates meeting proposed rule criteria (24 divided by 4 is a weight of 6; with one respondent reporting an intake rate
of 2 MGD or more, this produces an estimate of six total new structures meeting proposed rule criteria).
However, earlier data (see ERG, 2004a) indicate that eight structures in the deepwater have CWIS  intake  rates
meeting proposed rule criteria.  EPA used the higher number of structures to estimate the proportion of existing
structures with CWISs meeting the proposed rule criteria to total structures in the deepwater.  Given eight
structures meeting proposed rule criteria and 24 total structures, EPA believes that about 1/3 of deepwater
structures to be built will be equipped with intakes meeting the proposed rule's criteria. Only one existing
deepwater structure has a total intake rate of over 20 MGD, and none have a total rate of over 50 MGD. All firms
currently operating multi-well structures in the deepwater GOM with CWIS rates that meet criteria are large.

For shallow water large platforms,  EPA determined that existing 206 exluding platforms were either known to
have CWISs with intake rates meeting proposed rule criteria or their intake rates were unknown (an additional 3
platforms were known to have CWIS intake rates less than 2 MGD and were dropped from the sampling frame).
EPA sampled 33 platforms among the large platform group.  Three of these were nonrespondents.  No additional
platforms with intake rates meeting proposed rule criteria were detected using the survey.  The nonrespondents
were thus assumed also to have CWIS intake rates not meeting proposed rule criteria. Four platforms, however,
were known to have CWISs meeting proposed rule criteria based on earlier data (see ERG, 2004a). None of these
were sampled. EPA therefore assumes only these four platforms have intake rates meeting proposed rule criteria.
These platforms are  owned by large firms (ExxonMobil and Marathon). Thus EPA assumes that if any large
platforms with CWIS intake rates meeting proposed rule criteria were to be built, they would be built by large
firms.
                                                                                                  C2-25

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

For shallow small platforms, EPA determined that 2,194 platforms were in the universe of platforms in the
Federal GOM. The vast majority of these platforms have unknown CWIS intake rates. Four such platforms were
identified prior to EPA's Phase III Survey as having CWIS intake rates exceeding 2 MOD (ERG, 2004a). None
of these was sampled.  A total of 18 platforms with unknown CWIS intake rates were sampled (all responded),
but EPA determined that none of the sampled platforms had total design flow rates meeting proposed rule criteria.
Although this is a very small sample, this finding is bolstered by EPA's observations that platforms in State
waters are unlikely to have CWIS with intake rates totaling 2 MOD or more (ERG, 2004a). Platforms in State
waters and small platforms in Federal waters are generally similar structures.  EPA therefore assumes that only
four small platforms located in the shallow water GOM have CWIS intakes meeting proposed rule criteria. These
four platforms are owned by ExxonMobil and BP, thus no small firms are estimated likely to build platforms with
greater than 2 MGD intake rates  in shallow water.

In the GOM, therefore, EPA estimates that a total of 16 existing platforms have CWIS intake rates meeting
proposed rule criteria.  All are owned by large firms, and most operate in the deepwater regions.

In California, EPA determined that 20 platforms either have CWIS intake rates totaling 2 MGD or more or their
CWIS intake rates were unknown (13  platforms with known intake rates were eliminated from the sampling
frame because their total intake was less than 2 MGD). EPA sampled 3 of these 20 platforms.  Only one was
found to have an intake rate meeting proposed rule criteria.  EPA thus assumes seven existing platforms in
California have total intake rates meeting proposed rule criteria (20 divided by 3 is a weight of 6.7, which yields 7
platforms weighted). A total of six platforms are known from earlier data (see ERG, 2004a) to  have intakes rates
meeting proposed rule criteria, including the surveyed platform. Three have intake rates greater than 20 MGD but
less than 50 MGD. Of the six platforms with flow data showing rates meeting proposed rule criteria, three of
these are owned by a small business (Plains Exploration and Production/Arguello). The remainder are owned by
large businesses (Aera Energy, a joint venture between Shell and ExxonMobil, and ExxonMobil).

In Alaska, EPA determined that 19 platforms/production facilities are in the survey universe (one platform was
known to have a total CWIS intake rate of less than 2 MGD and was dropped from the sampling  frame).  EPA
sampled two platforms, but only  one was determined to have a CWIS intake rate meeting proposed rule criteria.
EPA therefore estimates that there are 10 platforms in Alaska with intakes that meet proposed rule criteria (19/2 is
a weight of 9.5). Five of these (all located in Cook Inlet) have CWIS data showing them to have CWISs meeting
proposed rule criteria (ERG, 2004a).  Of these structures with known CWISs of this size, all are platforms owned
by Unocal. Based on this, EPA might assume no small businesses currently operating would be affected in
Alaska. However, the most recently built platform in Cook Inlet, Osprey, was constructed by a small firm
(Osprey's CWIS intake rates are  unknown). To be conservative, EPA assumes that a small firm, much like Forest
Oil (Osprey's owner), might be the type of firm to build a new structure in Alaska and such a structure might have
CWIS intake rates meeting proposed rule criteria. However, it is also entirely likely that no such structures will
be built within the time frame of the analysis.

In summary, there are 16 platforms in the GOM, seven platforms in California, and 10 platforms in Alaska, for  a
total of 33 existing platforms that meet proposed rule criteria.  Of these, three platforms or structures (one in the
deepwater and two in California) have CWIS intake rates greater than 20 MGD, and  one platform (California) has
an intake rate greater than 30 MGD. No platforms have CWIS intake rates exceeding 50 MGD.

b.  Current Oil and Gas Production Levels and Trends
In 2002, 555 million bbls of oil and 4.5 million MMcf of gas were produced in the GOM. Fifty nine% of all oil
production in the GOM now comes from deepwater wells (MMS, 2003b). MMS has been using  incentives such
as royalty relief to promote drilling of deep gas wells in GOM over the past few years. In recent years, the
drilling of such wells has increased and trends show a continuation of deep gas drilling and exploration in GOM.
As technology advances and more deep gas wells are drilled, reserve estimates are being revised  as more gas is
presumed recoverable. Deep gas wells in the GOM consist of deepwater drilling and deep shelf drilling in
shallow waters. Deep shelf gas production increased by 137 Bcf from 2000 to 2002.  Approximately 20% of all
GOM exploration drilling was at greater than 15,000 ft. at the end of 2003. As the industry gains more
experience in deep gas drilling, and the technology continues to advance, experts predict that this trend will


C2-26

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

continue to be a substantial percentage of gas exploration and production in GOM (Drilling Contractor, Jan./Feb.
2004).

Standard & Poor's annual Report Card of the Oil and Gas industry in 2003 predicted that oil prices would average
approximately $19 per barrel, and that natural gas prices would average $3 per million Btu (MMBtu) (S&P,
2003). These price estimates were conservative, especially in light of the potential volatility in the market caused
by the war in Iraq.  S&P stated factors such as rising non-OPEC production, slow economic growth, and the
resumption of Venezuelan operations as potential factors in lowering oil prices. In 2000, OPEC developed a price
band mechanism which would adjust production to keep price baskets within the range of $22/bbl to $28/bbl.
OPEC has rarely used the mechanism and prices have fluctuated outside of the determined range a number of
times since the band's inception. OPEC has, however, maintained a stable price of $20-$22 per barrel in recent
years, (Drilling Contractor, Nov/Dec 2003a).  Currently, U.S. crude prices for the benchmark Texas Upper Gulf
Coast crude is $27.25 per bbl (OGJ, February 16, 2004). The economic analysis employs long run wellhead oil
and gas prices used by 316(b) survey respondents to project future platform fmancials.

S&P also noted that natural gas in North America (onshore and offshore) has shown a 5% annual decline in
production. In 2002, production began well over 20% greater than the 5 year average, but the year ended with
production 15% lower than that same mark (S&P, 2003). Similar production trends in Canada, the most
important source of natural gas imports for the U.S., create speculation of rising natural gas prices.  Recently
(February 4, 2004), the Henry Hub gas price (a leading gas benchmark) was $5.20/MMBtu
(http://www.wtrg.com/daily/oilandgasspot.html). Despite  the current price level, Drilling Contractor predicts that
prices will decline over the next two  years, falling to a range of $3.50 to $4.50 /MMbtu from 2004 to 2006.
(Drilling Contractor, Nov/Dec 2003a).  U.S. oil  demand is predicted to increase by 1.5% each year while existing
fields should deplete at the same rate. The demand for natural gas is predicted to increase as well, albeit at a
slower rate (1%).

c.  Estimate of Platforms To Be Built That May Be Affected by the Proposal
In the deepwater region, EPA determined,  based on MMS  data, that approximately 2 to 4 structures are built each
year (see Figure C2-1 and Table C2-11). EPA assumes that an average of three such deepwater structures are
completed each year. EPA notes that out of 24 total structures in the deepwater as of 2003, 8 are estimated to
meet proposed rule criteria, or about  a third of the total. EPA thus assumes that one structure per year out of the
three installed annually might have intakes meeting proposed rule criteria. Because only one structure currently
has a CWIS intake rate of greater than 20 MGD (and none have a CWIS intake rate of more than 30 MGD), EPA
assumes that only one structure out of 10 would be built having a CWIS intake  rate of 20 MGD or more.  This
would mean that EPA estimates two  structures would  be built with these intake rates over the 20-year
construction time frame.

All of these structures are assumed to be constructed by large firms. Only large firms have built structures in the
deepwater GOM, except for a few subsea completions, which have not been identified as associated with intake
rates meeting proposed rule  criteria.  This scenario is likely to continue, given the resources required to construct
deepsea structures, which sometime exceed $1 billion dollars (U.S. EPA, 2000).
                                                                                                  C2-27

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry


Year
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Note: 2003 is a partial year only.
Source: MMS, 2003b.
Table C2-11: Count
Deepwater Platforms
0
2
0
2
1
4
3
2
4
2
0


of Platform Installations
Platforms in Shallow Water with
Greater than or Equal to 20 Wells
1
4
0
1
0
2
0
0
0
0
0



Platforms in Shallow Water
with Less than 20 Wells
26
57
42
63
55
60
36
55
60
66
15


Among large (20+ slot) platforms, EPA determined that few, if any, such platforms might be built during the time
frame of the analysis (see Table C2-11). As the table shows, no platforms of this size have been built over the past
5 years. Given that so few of the existing platforms appear to resemble a new regulated project, EPA assumes no
new platforms of this size and with CWIS meeting proposed rule criteria would be constructed.

Among smaller platforms, EPA determined that although they are installed at a rate of about 50-60 per year (see
Table C2-11), they are unlikely to install CWIS of the size considered to meet proposed rule criteria. EPA
therefore assumes no new smaller platforms constructed in shallow water would be affected by the proposal.
C2-28

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry
                               Figure C2-1: Platform Installation by Year
fin
zr\
brms
i. <_
berofPlat
/J 4
D C
E
z
90
i n
n -






•
-




,
-




















rk
,-,












0











[i











n
-






n
PI










n











n
PI











PI

                                                                               DDeepwater Platforms
                                                                               • Platforms in Shallow
                                                                                 Water with Greater than
                                                                                 or Equal to 20 Wells

                                                                               DPlatforms in Shallow
                                                                                 Water with Less than 20
                                                                                 Wells
            1993  1994  1995  1996  1997  1998   1999  2000  2001  2002  2003

                                   Year of Installation
 Note: 2003 is a partial year only.

 Source: MMS, 2003b.
The Federal offshore waters off the coast of California have been subject to a moratorium on lease sales since
1990. No platforms have been constructed since 1994, and no exploration has been undertaken since 1989.
Currently the moratorium extends to 2012. President Bush has dropped opposition to the moratorium and
currently has no apparent plans to end the moratorium (Environmental News Network, 2003).  The State has
indicated to the President that it wishes the moratorium to remain in place, and Governor Schwartzenegger has
been pushing for a "permanent ban on all oil drilling in coastal waters." (MSNBC, 2003). There are, however, 40
leases off San Luis Obispo and Santa Barbara Counties that are not subject to the moratorium, and a consortium
of oil companies including Aera Energy have announced plans for exploratory drilling.  Aera Energy plans to drill
in 2004.  Political opposition to these plans is enormous, however (Sneed, 2004). Even if exploratory drilling is
allowed to take place, any platform construction would occur many years later. Given this  strong level of
antipathy towards offshore oil and gas development in California, EPA believes that the construction of new
platforms, or any new drilling, in either State or Federal California offshore regions is unlikely in the time frame
of the analysis.

In Cook Inlet, Alaska, only one new platform has been constructed in recent years.  Most new exploration and
development in this region takes place from existing infrastructure or from onshore locations using directional
drilling, in which wells are drilled both vertically and horizontally to reach potential reserves, sometimes
thousands of feet from the top-hole locations. No definitive plans appear to be in place for any new platforms in
State waters. In Federal waters, lower Cook Inlet is a source of potential activity, since MMS completed a lease
                                                                                                    C2-29

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

bid in April, 2004.  However, given the long lead times between lease bid to operation, it may be relatively
unlikely that this lease bid will result in new platforms during the time frame of the analysis in either location. To
be conservative, however, EPA assumes one such platform might be constructed in Upper Cook Inlet (State
waters) and begin operation during the time frame of analysis.  In other Federal areas in the Alaska region, little
new activity is underway. BP has dropped plans for its Liberty project in the Beaufort Sea area (Federal Register,
Vol. 67, No. 99 pp. 36020-36022). Although some leases are actively registered in the Beaufort Sea, the time
frame for development, if any is undertaken, could be beyond the time frame of this analysis.
C2-3  TOTAL NEW OIL AND GAS OPERATIONS

Table C2-12 summarizes the number of existing MODUs and platforms that are estimated to meet the proposed
rule's criteria, had EPA decided to regulate existing oil and gas facilities, as well as new MODUs and platforms
expected to be built over the 20-year analytical period that might be required to install control technologies. Also
presented is an assessment of the number of firms involved that might be small businesses.
   Table C2-12  Number of Existing and Future Offshore Oil and Gas Extraction Facilities Estimated or
             Assumed To Meet Proposed Rule Criteria over a 20-Year Analysis Time Frame
Type of Oil and
Gas Facility
MODUs
Deepwater
Platforms (GOM)
20+ Slot
Platforms (GOM)
Other GOM
Platforms
California
Platforms
Alaska Platforms
Total
Existing Facilities
No. with
>2MGD
flows
172
8

4

4

7
10
205
No. with
>20 MGD
flows
12
1

0

0

3
0
16
No. with
>50
MGD
flows
12
0

0

0

0
0
12
No. of
Small
Firms
Potentially
Involved3
6
0

0

0

1
1
8
New Facilities
No. Built
in 20- Year
Period >2
MGD
103
20

0

0

0
1
124
No. Built
in 20- Year
Period
>20 MGD
3
2

0

0

0
0
5
No. Built
in 20- Year
Period
>50 MGD
3
0

0

0

0
0
3
No. of
Small
Firms
Potentially
Involved3
0
0

0

0

0
1
1
 a      No small firms are involved if the cutoff is 20 MGD or greater

 Source: U.S. EPA Analysis, 2004. See the 316(b) Oil and Gas Compliance Cost Model, DCN 7-4018 and ERG, 2004b.
C2-30

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry


REFERENCES

Alexanders Oil and Gas Connections. 2002. Shell Oil board elects Philip Watts and Rob Routs. Volume 7, issue
#10 Thursday, May 16, 2002.

Bureau of Census  2004.  1997 NAICS United States Structure, Including Relationship to 1987 U.S. SIC
http://www.census.gov/epcd/www/naicstab.htm

Drilling Contractor. 2003a. Deepwater success results in higher drilling activity. November/December

Drilling Contractor. 2003b. Large jackups are most notable of new built rigs.  November/December.

Drilling Contractor. 2004. Gulf deep shelf gas drilling expected to increase. January/February 2004.

Drilling Contractor. 2001. MMS: GOMdeepwater activity, production to grow. November/December

Environmental News Network. 2003. Bush won't challenge ban on new California offshore oil drilling. April 1.
http://www.een.com/news/2003-04-01/s_3613.asp. Downloaded April 26, 2004.

ERG. 2003.  Assessment of Platforms in the Gulf of Mexico That Are Likely To Be In Scope. Memorandum to
George Denning, EPA, from ERG. August 21, 2003.

ERG. 2004a. Non-CBI In-Scope Facility Database.  Spreadsheet Submitted to the 316(b) Phase III Rulemaking
Record. DCN 7-3505.

ERG  2004b. Calculation of Weights for Engineering Cost Estimates. Memorandum to the 316(b) Phase III
Rulemaking Record. September 24, 2004.

ERG. 2004c. Expanded Universe of MODUs and Platforms.  Spreadsheet Submitted to the  316(b) Phase III
Rulemaking Record. DCN 7-4022.

ERG. 2004d. Final MODU List. SpreadsheetFinalMODUlist.xls.  Submitted to the 316(b) Phase III
Rulemaking Record. DCN 7-4029.

MMS. 2003a. MMS Platforms Master Database. U.S. Department of the Interior. Minerals Management
Service. Downloaded 6/10/2003.  DCN 7-4025.

MMS. 2003b. Deepwater production summary by year, www.gomr.mms.gov/homepg/offshore/
deepwatr/summary.asp downloaded 10/10/2003.

MSNBC. 2003. Will Gov. Schwarzenegger be green?  December 12. http://msnbc.msn.com/id/3475222
Downloaded April 26, 2004.

Oil and Gas Journal. 2004. Statistics: US Crude Prices. 67.  February 16, 2004.

Offshore. 2003. Upgrades target deep gas and deepwater. Offshore Magazine. July 2003.

SEC.  2003.  Security and Exchange Commission Edgar Database of Corporate Filings.
http: //www .sec .gov/edgar. shtml

S&P (Standard and Poors).  2003. Industry Report Card: Oil and Gas. January, 17, 2003.

Sneed, David. 2004. Oil drilling planned offSLO County in 2007.  San Luis Obispo Tribune. April 27, 2004
                                                                                               C2-31

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis of Phase III New OOGE Facilities    C2: Profile ofOOGE Industry

U.S. Environmental Protection Agency (U.S. EPA) 2000. Economic Analysis of Final Effluent Limitations
Guidelines and Standards for Synthetic-Based Drilling Fluids and Other Non-Aqueous Drilling Fluids in the Oil
and Gas Extraction Point Source Category.  EPA-821-B-98-020.  December 2000.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Technical Development Document for the Proposed
Section 316(b) Phase III Rule.  EPA-821-R-04-015. November 2004.
C2-32

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

  Chapter  C3: Economic  Impact Analysis  for
         the Offshore  Oil and Gas Extraction
                                      Industry
                                                C3-2
CHAPTER CONTENTS
C3-1 MODU Analyses	C3-2
     C3-1.1 Aggregate National After-tax Compliance
           Cost Analysis  	C3-2
     C3-1.2 Vessel-Level Compliance Costs	C3-3
     C3-1.3 Impact Analysis 	C3-5
     Economic Impact Analysis for Oil and Gas
     Production Platforms	C3-8
     C3-2.1 Aggregate National After-tax Compliance
           Costs	C3-9
     C3-2.2 Platform-Level Compliance Costs  . . C3-10
     C3-2.3 Impact Analysis	C3-12
     Total Costs and Impacts Among All Affected
     Oil and Gas Industry Entities	C3-14
     Total Costs to Government Entities and Social
     Costs of the 316(b) Phase III Rulemaking . . . C3-15
     C3-4.1 Total Costs to Government Entities  . C3-15
     C3-4.2 Total Social Costs	C3-15
References  	C3-17
                                                C3-3
                                                C3-4
INTRODUCTION

The Proposed Section 316(b) Rule for Phase III
Facilities would potentially affect any new MODUs
and oil and gas production structures that use CWISs
with daily design combined intakes totaling at least 2
MOD (and at least 25% of water used for cooling
water purposes).  This regulatory structure is the
similar to that applied to new electric generating and
other industrial facilities under the Section 316(b)
Phase I, Track 1 regulation.

This economic impact analysis is divided into four
sections. Section C3-1 presents the analysis of the
316(b) rulemaking on MODUs, Section C3-2 presents
the analysis of offshore oil and gas production
platforms, Section C3-3 summarizes the costs and
impacst on both MODUs and platforms and provides
totals for the combined industry subgroups, and
Section C3-4 presents costs to the Federal government
and total social costs.  The first two sections each discuss the aggregate national after-tax compliance cost
estimates for new MODUs and platforms (as well as briefly summarize what these costs would be had existing
MODUs and platforms been covered by the proposed rule). These sections also present vessel-level or platform-
level pre- and after-tax compliance costs, and discuss impacts, both at the vessel/platform level and at the firm
level.  The vessel/platform level impacts are assessed using two approaches. The first approach uses the existing
facilities that might represent new facilities and applies a cash-flow/net income-based analysis. The second
approach is a standard barrier-to-entry analysis that investigates the present value of initial permitting costs
(discounted to the assumed year of compliance) plus initial one-time capital/installation costs as a percentage of
the cost to construct a new MODU or platform. The firm-level analysis uses firm revenues at firms that are the
likeliest to construct new facilities. EPA applies a pre-tax and after-tax annualized cost of compliance
(incorporating permitting, monitoring, capital/installation, and O&M costs) for each MODU/platform the firm is
expected to build over the period of analysis.  For simplicity and to be conservative, all new MODUs or
platforms/structures a firm is expected to construct during this time frame are assumed to be launched or to come
on line in one year for comparison to one year's revenues at the potentially affected firms. The ratio of these
costs to revenues is then calculated and assessed as to whether this ratio might indicate the potential for firm-level
impacts.

The methodologies used in each analysis are presented  first in each section, followed by a discussion of the
analytic results.
                                                                                          C3-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

C3-1  MODU ANALYSES

C3-1.1 Aggregate National After-tax Compliance Cost Analysis

A number of costs must be considered in calculating the aggregate national after-tax compliance costs, each with
distinct timing considerations. Permitting costs are incurred by facilities, but these costs are incurred by facilities
to come under one of three General Permits.  EPA assumes costs of studies needed to incorporate permit
requirements under the General Permits can be shared. EPA further assumes that all permitting costs would be
grouped into three general permit regions. These regions are Eastern Gulf of Mexico, Western Gulf of Mexico,
and Alaska.  Other permit activities are facility-specific and would fall on each facility affected. The timing of
permitting costs is complex and was discussed in Chapter Cl: Summary of Cost Categories and Key Analysis
Elements for New Offshore Oil and Gas Extraction Facilities. More information can also be found in U.S. EPA
(2004a) and ERG (2004a).

EPA assumes that four jackups and 1 semi-submersible will be built each year over the time frame of the analysis.
EPA also assumes that three drill ships will be built, launched in 2012, 2017, and 2022 for a total of 103 MODUs
over the 20-year period of construction. Permitting costs, therefore, apply to 80 jackups, 20 semi-submersibles
and 3 drill ships. See Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry.

Pre-tax costs of installing and operating control technologies and for various permitting activities are input to a
spreadsheet in the year in which they are assumed to be incurred. Capital costs are assumed to be incurred every
10 years, and repermitting costs occur every 5 years. Each MODU is assumed to operate over a 30-year
compliance period. Costs are discounted to the year of compliance, assumed to be the year the MODU  is
launched, and summed to produce the present value of costs in the year of compliance.  These costs are  then
annualized over 30 years. See Chapter Cl: Summary of Cost Categories and Key Analysis Elements for New
Offshore Oil and Gas Extraction Facilities for more details on the cost discounting methodology.

To create after-tax costs, EPA assumes that the highest marginal corporate tax rate applies. This rate is  35% (IRS,
2002),  so after-tax costs would be 65% of the pre-tax costs. EPA does this because all MODU owners that are
likely to build MODUs are large corporations by SBA standards and all have earnings in most years that place
them in the highest corporate tax bracket.

Table C3-1 summarizes the national aggregate after-tax compliance costs for MODUs.  As the table shows, these
costs are $1.8 million per year over the time frame of the  analysis. See ERG (2004a) for a detailed description of
how these costs were calculated. See also the 316(b) Oil  and Gas Compliance Cost Model, DCN 7-4018
(hereinafter,  Compliance Cost Model.

Had existing MODUs been covered by the proposed rule, the total national cost of the rule would have included
an additional $3.6 million per year (ERG, 2004b).
C3-2

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities


              Table C3-1: Total Aggregate National After-tax Compliance Costs for MODUs
                                                 (2003$)
Type of Cost
Permitting (a)
C apital/Installation
Semi-submersibles
Jackups
Drill ships
Total
Monitoring
O&M
Total
Present Value
(year of compliance)
$7,111,190

$597,347
$14,373,374
$765,049
$15,735,770
$1,357,609
$0
$24,204,569
Annualized Cost of
Compliance
$535,575

$44,989
$1,082,522
$57,619
$1,185,130
$102,247
$0
$1,822,952
             Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
C3-1.2  Vessel-Level Compliance Costs

This section addresses costs to each of the three types of new vessels. Again, permitting and monitoring costs are
from U.S. EPA (2004a), and capital/installation costs are from U.S. EPA (2004b). Weighted average costs
reported in the TDD (U.S. EPA, 2004b) and derived for existing facilities are calculated and applied to new
facilities as presented in a spreadsheet located in the rulemaking record (DCN 7-4030) and in the Compliance
Cost Model, DCN 7-4018. Pre-tax costs per vessel are used in the firm-level analysis. After-tax per facility costs
are also presented. After-tax costs are used for comparison to pre-tax costs and in the firm-level analysis, but are
not used directly in the vessel impact analysis.1 Additional details on how these costs are calculated are presented
in ERG (2004a).

a.  Pre-Tax Cost of Compliance for Representative Vessels
The costs  shown in Table  C3-2 reflect the costs assigned to each vessel, by type of vessel. The representative
vessels are those launched in 2007 (jackups and semi-submersibles) and 2012 (drill ship)  for the purposes of
timing assumptions. All costs are discounted to the year of compliance, which is the same as the assumed year of
launching. This date may be prior to the date actual compliance is required for some vessels. Those constructed in
2007-2012 or 2014 (depending on location) are assumed to install and operate compliance equipment
immediately when they are constructed, even though permit requirements may not be in place at that time (see
Chapter Cl: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas Extraction
Facilities  for more details). The present value  costs are calculated by inputting each cost into the year that it is
assumed to be incurred, which includes additional capital costs in years  11 and 21 after initial construction,
repermitting costs every 5 years, and monitoring costs in the appropriate years. The costs are taken out over 30
years, discounted to the year of compliance at the recommended OMB discount rate of 7%, and then summed.
The present value cost is then annualized using a 30-year time frame assumption and 7% discount rate.  Chapter
Cl: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas Extraction Facilities
also discusses this process, as does ERG (2004a).
    1 In the impact analysis, after-tax costs are applied to existing MODUs, but these are calculated in a more exact way, since the
existing MODUs have known marginal tax rates, and a depreciation schedule is used to more precisely calculate the after-tax cost impact
on cash flow; see Section C3-1 below and ERG, 2004c).
                                                                                                     C3-3

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

Table C3-2 presents the costs of compliance on an annual basis for the three types of MODUs.  As the table
shows, these costs range from $14,938 to $37,638 per year depending on type of vessel. These costs are small in
comparison to revenues associated with drilling even one exploration well in the deepwater GOM. The
construction of these types of wells cost oil and gas production companies about $25 million to $30 million per
well (U.S. EPA, 2000). The major portion of this outlay is paid to the operator of the MODU that drills the well.
These costs are also small in comparison to typical MODU day rates, which can range from $150,000 to $250,000
per day (Hatton, et al., 2002).
                Table C3-2: Per-Vessel Annualized Pre-Tax Cost of Compliance (2003$)
Type of Cost
Permitting (a)
Semi-submersibles
Jackups
Drill ships
Capital/Installation
Semi-submersibles
Jackups
Drill ships
Monitoring
Semi-submersibles
Jackups
Drill ships
O&M
Total
Semi-submersibles
Jackups
Drill ships
Present Value
(year of compliance)

$128,206
$128,206
$66,191

$45,950
$276,411
$392,333

$24,189
$24,189
$33,742
$0

$198,345
$428,806
$492,266
Annualized Cost of
Compliance

$9,656
$9,656
$4,985

$3,461
$20,818
$29,548

$1,822
$1,822
$2,541
$0

$14,938
$32,295
$37,075
           Source: U.S. EPA Analysis, 2004.  See the Compliance Cost Model, DCN 7-4018.
b.  After-tax Costs
After-tax costs are presented here for comparison purposes. After-tax costs are assumed to be lower than the pre-
tax costs by the top marginal corporate tax rate of 35%. Thus the costs calculated are 65% of the pre-tax costs in
Table C3-2 above.

The annual after-tax, annualized, per-vessel compliance costs are $9,710 for semi-submersibles, $20,922 for
jackups, and $24,099 for drill ships, based on the pre-tax costs shown above in Table C3-2.
C3-4

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

C3-1.3  Impact Analysis

The impact analysis is conducted at two levels: vessel-level and firm-level.  Although the financial condition of
new vessels cannot be known, the financial conditions of a few, representative existing vessels are reflected in
EPA's 316(b) survey of MODUs. EPA received eight economic surveys from three semi-submersibles, three
jackups, and two drill ships.  The financial information from these representative vessels is used for a general
assessment of how well these vessels would do financially if costs of the preferred option applied. The
representative vessels are thus a proxy for new sources subject to Phase III regulation.  This analysis provides an
alternative assessment of the potential for barrier to entry.

The second vessel-level analysis is a more typical barrier-to-entry analysis conducted by EPA for new entities,
which looks at the present value of the initial permitting costs (including those associated with start-up activities,
pre-permitting studies and initial permit application activities), discounted to the applicable compliance year, plus
the initial one-time capital/installation costs of required control equipment and compares these costs to the
baseline construction costs for each type of MODU. EPA uses an initial permit cost stream represented by
MODUs expected to be constructed in 2007 (jackups and semi-submersibles) or 2012 (drill ships).  See the
Compliance Cost Model (DCN 7-4018).

The firm-level analysis is a revenue test, comparing the revenues of firms likely to construct MODUs with the
annualized compliance costs for representative new vessels, assuming each firm identified as potentially affected
builds a share of the new MODUs expected to be constructed over the time frame of the analysis.  For simplicity
and to be conservative, each firm is assumed to launch all their new MODUs in one year for comparison to one
year's revenues. EPA uses the annualized cost stream for MODUs constructed in 2007  (or the cost stream for a
drill ship constructed in 2012, the first year post-compliance in which a drill ship is assumed to be constructed) to
represent the annualized costs to each potentially affected firm. EPA uses both the pre-tax and after-tax
compliance costs for comparison with revenues.

a.  Vessel Impact Analysis Using Survey Vessels
To calculate the impact of the today's proposal on new MODUs, EPA used two models - a cash flow/net income
model, which computes the estimated present value of after tax cash flow/net income for representative MODUs
(based on survey data) over a 30-year operating period for each new facility, and a post-tax cost calculation
model, which estimates the present value after-tax costs of compliance using engineering and permitting cost
inputs.  These two models are used to analyze the effect of after-tax costs on after-tax vessel  cash flow or net
income. For additional details on these models, see ERG (2004c) and DCN 7-4020.

Using data provided by surveyed MODU operators, EPA used both the reported after-tax net income and a
calculated cash flow figure for each survey MODU.  EPA calculated cash flow using after-tax net income and
adding depreciation, depletion, and amortization (DD&A) back into net income, since DD&A are not cash
expenses. EPA used cash flow as an upper bound estimate of available cash and after-tax net income as a lower
bound estimate. EPA was  only able to undertake financial analysis for those MODUs with a positive net income
or cash flow for the three years of financial information provided in the survey.  EPA assumes that any MODU
whose cash flow or net income is negative over the three years of financial data availability is unlikely to be a
viable operation in the baseline and cannot be analyzed with respect to compliance costs.

EPA used the cash flow/net income over the three years of data collected to create a moving  cycle of cash
flow/net income over the period of analysis. The years of data collected were 2000, 2001, and 2002, with 2002
generally being a poorer year for the industry as a whole. In this way, EPA was able to represent industry
financials in both good and bad years. The 3-year cycle provides a means for projecting the  volatile oil and gas
business over each facility's 30-year operating period, which is expected to include major swings in the prices of
oil and gas, the driving force behind the level of operations, pricing, and thus the financial performance of newly
constructed vessels. EPA assumed that cash flow/net income will be flat on average over the 30 years of analysis
and thus does not apply any factors to increase  or decrease cash flow or net income over the  years of analysis
within those cyclical movements. The cash flow/net income figures from the survey, therefore, repeat every three
                                                                                                   C3-5

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

years for 30 years. EPA then computes the present value of that stream of cash flow/net income figures and
compares it to the present value of after-tax compliance costs for the preferred option.

EPA used the capital, O&M, and permitting costs to calculate the present value of the after-tax annualized cost of
compliance with the proposed requirements. Each cost is accounted for in the year in which it is assumed to be
incurred. EPA made the simplifying assumption that the existing MODUs would represent new MODUs that are
launched in 2007. Since EPA assumes MODUs launched in this year install and operate compliance equipment at
that time (even though they do not become permitted for compliance with 316(b) requirements until the date of
the first applicable General Permit renewal), EPA considers the date of launching the "compliance year."

The first costs to be incurred are the Region 6 and Region 4 pre-permitting costs (the shared study costs) and the
capital costs of installation and incremental O&M costs (O&M costs are estimated to be $0 for all MODUs).
Costs for permit application activities occur in 2011 for the Region 6 permit and in 2013 for the Region 4 permit.
Only MODUs are assumed to be permitted under the Region  4 permit, since relatively little production activity is
currently underway in the Eastern Gulf2 Monitoring costs begin to be incurred in 2012. Repermitting costs enter
in 2017, and every 5 years thereafter. EPA estimated capital  costs for each MODU for which a financial survey
response was received (with one exception), as well as many  other MODUs for which financial data were not
obtained (all were used to calculate the average costs of compliance for new facilities). In this analysis, however,
only the costs for the eight MODUs with economic survey information were used for developing the costs for this
impact analysis.

EPA's post-tax compliance cost model determined the  marginal tax rate of the owner company based on the
firm's average taxable earnings over the three years of survey data (which were put on  a mid-year 2003 basis to
match the engineering costs, which were also  set to 2003 dollars) and used the modified accelerated cost recovery
system (MACRS) to calculate depreciation on the capital outlay. Depreciation was then used to compute a "tax
shield" on the investment (for more information on EPA's post-tax cost calculation model, see ERG [2004c] and
DCN 7-4020). The post-tax cost calculation model calculates the present value of after-tax compliance costs.

The present value output from the post-tax cost calculation model is then input to the cash flow/net income model
and used to compare with the present value of cash flow/net income of the vessel as discussed above.  If the
present value of baseline after-tax cash flow or net income minus the present value of after-tax compliance costs
is greater than $0, EPA assumes that the MODU would be able to continue to operate post-compliance. If the
cash flow value becomes negative, EPA assumes the MODU would no longer continue to operate.  If the net
income value becomes negative, EPA assumes the longer term viability of the vessel is potentially jeopardized. In
either case, such a MODU would be counted as a potential "regulatory closure." This analysis is considered an
alternative  assessment of the potential for barrier to entry.

Although many of EPA's analyses investigate whether costs of compliance  can be passed through to customers,
this analysis makes an assumption that costs cannot be passed through.  Because existing MODUs would not have
to meet the requirements of the proposal, and  new MODUs must compete with these existing MODUs, it is
unlikely that new MODUs would be able to pass through any compliance costs.  Assuming zero cost pass-through
provides a realistic estimate of potential economic impacts to new MODUs.

Due to confidential business information (CBI) constraints, EPA is not able to provide  detailed impact results on a
MODU-specific level. Detailed results are provided in the CBI portion of the Rulemaking Record (ERG, 2004c,
CBI version, and DCN 7-4020). The general  findings of the closure analysis are that no new MODUs would be
regulatory closures, based on an assumption that finances for new MODUs might look  like those for existing
MODUs, as a result of the incremental  costs of compliance with the preferred option using either a cash flow or
net income approach.
b.  Barrier to Entry Analysis (Vessel-Level)
    2 Permitting costs to platforms are assumed to be associated with the Western Gulf Permit; use of this assumption avoids potentially
understating the magnitude of shared costs to MODUs in Region 4.

C3-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

EPA used the incremental capital/installation costs and the net present value of permitting costs of compliance for
MODUs, as discussed above, using the cost streams associated with vessels launched in 2007 (jackups and semi-
submersibles) and 2012 (drill ships), discounted to the compliance year. The sum of these costs (capital and
permitting) were then compared to the costs of constructing new MODUs. If these compliance costs comprised a
small fraction of construction costs, EPA assumed that compliance costs would not have a major impact on future
MODUs and would not have an effect on a decision to build additional MODUs.

EPA estimated the incremental capital costs to install CWISs that meet the requirements of 316(b) Phase I, Track
1. These costs are $26,008 for semi-submersibles, $156,450 for jackups, and  $222,062 for drill ships. The present
value of a share of the permit costs is $101,192 for each vessel except those for drill ships, which are $24,521
(because they are assumed not be involved in the initial study cost sharing due to their much later assumed launch
dates). The total incremental initial investment costs, therefore, are $127,200 for semi-submersibles, $257,642 for
jackups, and $246,583 for drill ships). According to Drilling Contractor Magazine (2003), the cost of new
MODUs planned to be built in the next few years average $250 million for semi-submersibles and $125 million
for jackups. A drill ship completed in 1998 (R&B Falcon's Pathfinder3) cost approximately $275 million.
Incremental present value of permitting costs plus capital/installation costs are therefore estimated to range from
0.05% to 0.21% of construction costs, regardless of type of MODU. Because this is only a tiny fraction of total
costs of construction (and a tiny fraction of contingency, which typically ranges from  10% to 20% of
capital/installation costs), EPA believes that these costs would not have a material effect on decisions to build new
MODUs.

c.  Firm-Level Analysis
To determine the impact of the proposed rule on firms, EPA uses a revenue test, which compares the annualized
pre-tax and after-tax costs of compliance (calculated as discussed for each representative MODU as discussed
above), with 2002 revenues reported by all firms determined likely to build new MODUs meeting the proposed
rule's criteria. Because nearly all of these firms (other than foreign-owned) are publicly owned, EPA relied on the
revenue data reported in Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry, which was
compiled from corporate 10K reports downloaded from SEC's Edgar Database. EPA determined the number of
MODUs likely to be built by each firm under the proposed rule.  Only those firms that were identified as currently
owning jackups,  semi-submersibles, and drill ships that would meet the proposed rule's criteria if newly
constructed are considered likely to construct the estimated 103 new MODUs that would be affected by the
proposal. These same firms also generally comprise the firms that are currently building new MODUs (see also
Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry). EPA then assigned a number of potentially
in-scope MODUs to be built by each of the firms and used the  average per-MODU compliance costs multiplied
by the number of these potentially in-scope MODUs to calculate the total compliance costs that might be faced by
these firms.

To calculate costs to revenues, EPA uses the pre-tax and after-tax costs shown in Table C3-2 for the firms
identified  as likely to construct new MODUs meeting the proposed rule's criteria. Each firm is assumed to build
12 jackups or semi-submersibles over the time frame of the analysis (a little over one every other year), except for
GlobalSantaFe and Transocean, which are assumed to build 20 jackups and one drill ship or two drillships,
respectively. For simplicity and to be conservative, EPA assumes that all MODUs estimated to be constructed by
these firms are launched in one year for comparison with one year's revenues at those firms. EPA uses the higher
cost of a jackup rig to represent the cost of compliance for both jackups and semi-submersibles for simplicity.

Table C3-3 shows all of the MODU owners that are considered likely to build an in-scope MODU. As the table
shows, annualized pre-tax costs per firm range from $0.4 to $0.7 million. The ratio of pre-tax costs to revenues
ranges from 0.03% to 0.06% and after-tax costs to revenue range from 0.02% to 0.04%.  Given that the highest
ratio seen  is 0.06 percent, EPA concludes that firm-level impacts would be minimal. Furthermore, even if these
costs applied to other firms (among those that own jackups or semi-submersibles with unknown CWIS intake
     R&B Falcon was acquired by Transocean, Inc. (see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry).

                                                                                                   C3-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities     C3: EIAfor OOGE Facilities

rates that are considered unlikely to build new MODUs subject to Phase III regulation), impacts on any firm
would still be estimated to be much less than  1 percent.4

These costs reflect the assumption that all new jackups would be built with sea chests and, therefore, these vessels
would not be required to meet entrainment controls. However, jackups on rare occasions use straight pipes. If
jackups are not built with sea chests, the costs to comply with both impingement and entrainment contros would
result in the annualized per-vessel compliance costs to rise from $32,295 to $39,063. Under this scenario, the
costs to revenue ratios shown in Table C3-3 would be at most 0.08 percent (see DCN 7-4030 and DCN 7-4018).


                                Table C3-3: Revenue Test for MODU Owners
Name
Diamond Offshore
ENSCO
GlobalSantaFe
Noble
Pride
Rowan
Transocean
Total/A vg.
No. of Likely In-
scope Rigs >2
MGD Built in One
Year
12
12
21
12
12
12
22
103
Revenues
(Smillions)
$753
$698
$2,018
$986
$1,270
$617
$2,674
$9,406
Annualized
Pre-Tax Costs
per Firm
(Smillions)
$0.4
$0.4
$0.7
$0.4
$0.4
$0.4
$0.7
$3.3
Costs to
Revenues
(%)
0.05%
0.06%
0.03%
0.04%
0.03%
0.06%
0.03%
0.04%
Annual-ized
After-tax
Costs per
Firm
(Smillions)
$0.3
$0.3
$0.4
$0.3
$0.3
$0.3
$0.5
$2.2
Costs to
Revenues
(%)
0.03%
0.04%
0.02%
0.03%
0.02%
0.04%
0.02%
0.02%
 Source: SEC, 2003; U.S. EPA Analysis, 2004. See Compliance Cost Model, DCN 7-4018.
C3-2  ECONOMIC IMPACT ANALYSIS FOR OIL AND GAS PRODUCTION PLATFORMS

This section presents the aggregate national after-tax compliance costs for new oil and gas production platforms
that will be built in scope. It also presents platform-level compliance costs (in after-tax and pre-tax terms).
Impacts on platforms are then presented in two sections. The first section uses a model of a new platform to
determine the potential for any effect on production. The second section uses an approach for identifying barriers
to entry for all platforms likely to be built in scope and for assessing  impacts on those platforms for which
information was not sufficient to create a detailed economic model. As discussed in Chapter C2: Profile of the
Offshore Oil and Gas Extraction Industry, only 20 in-scope deepwater platforms and one in-scope Alaska
platform are expected to be constructed over the 20  year construction time frame of the analysis under the
proposed rule.
    4 There are several firms owning jackups or semi-submersibles that did not submit voluntary technical data, so EPA is not able to
determine whether they own MODUs that might meet the proposed rule's criteria were they to be newly constructed. These firms are
Atwood Oceanics, Caspian Drilling Co., Energy Equipment Resources, Nabors Industries, Newfield Exploration, Ocean Rig ASA, Parker
Drilling, Tetra Technologies, and Workships BV.  Most of these firms, however, own only one or two such MODUs and are considered far
more likely to purchase MODUs from the firms included in this analysis than to build their own (several of these MODUs have clearly
been purchased from GlobalSantaFe, for example). Had these firms been included in the analysis, however, EPA's findings would not
have changed. The firm with the lowest revenues in this group among those with publicly available data (Atwood Oceanics, Parker
Drilling, and Newfield Exploration; see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry) reported 2002 revenues as
$149 million. Applying the same methodology that EPA used for the firms considered likely to build MODUs, EPA would predict that the
cost-to-revenue ratio among these firms considered unlikely to  build MODUs would be at most 0.3 percent.
C3-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

C3-2.1 Aggregate National After-tax Compliance Costs

The methodology for calculating the aggregate national after-tax compliance costs are identical to that used for
calculating these same costs for MODUs, although the costs incurred are different. Costs are input in each year in
which they occur over the 30-year time frame of the analysis, including recurring capital replacement costs,
repermitting costs, and O&M.  The costs in each year are discounted to the compliance year (assumed the year the
platform comes on line) and summed to calculate the present value of the cost stream. These present value costs
are then annualized. For more details on timing assumptions and annualized and present value cost calculations,
see Chapter Cl: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas
Extraction Facilities and ERG (2004a).

To create after-tax costs, EPA assumes that the highest marginal corporate tax rate applies.  This rate is 35 percent
(IRS, 2004), so after-tax costs will be 65 percent of the pre-tax costs.  EPA does this because all platform owners
that are likely to build in-scope platforms are large corporations by SBA standards and/or have earnings that place
them in the highest corporate tax bracket (including the one small  corporation considered likely to build an Alaska
platform).

Table C3-4 summarizes the national aggregate after-tax compliance costs for production platforms.  As the table
shows, these costs are $1.2 million per year over the time frame of the analysis.  See ERG (2004a) for a detailed
description of how these costs were calculated. Also see DCN 7-4018.

Had  existing platforms been covered by the proposed rule, the total national cost of the rule would have included
an additional $4.5 million per year (ERG, 2004b).
                                                                                                     C3-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities


             Table C3-4: Total National Aggregate After-tax Compliance Costs for Platforms
                                                  (2003$)
Type of Cost
Permitting (a)
Deepwater
Alaska
Total
Capital/Installation
Deepwater
Alaska
Total
Monitoring
Deepwater
Alaska
Total
O&M
Deepwater
Alaska
Total
Total Compliance Costs
Deepwater
Alaska
Total National Compliance Costs
Present Value
(to year of compliance)
$842,324
$481,371
$1,323,695
$5,227,966
$390,008
$5,617,974
$187,012
$190,138
$377,150
$7,703,465
$1,371,845
$9,075,310
$13,960,768
$2,433,362
$16,394,129
Annualized Cost of
Compliance
$63,439
$36,254
$99,693
$393,741
$29,373
$423,114
$14,085
$14,320
$28,405
$580,182
$103,320
$683,502
$1,051,447
$183,267
$1,234,714
             Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
C3-2.2  Platform-Level Compliance Costs

This section addresses costs to each of the two types of platforms (deepwater and Alaska). Again, permitting and
monitoring costs are from U.S. EPA (2004a), and capital/installation and O&M costs are from U.S. EPA (2004b),
with the weighted average of the capital and O&M costs applied to new platforms/structures as calculated in DCN
7-4030. Pre-tax costs per platform are used in the firm-level analysis, along with after-tax costs.  After-tax costs
are used for comparison to pre-tax costs but are not used directly in the platform impact analysis.5 See ERG
(2004a) for more detail on how these costs were calculated. Also see DCN 7-4018.
    5 In the impact analysis, costs are input in the year in which they are assumed to be incurred, and the financial model
internally calculates the tax shield on these costs given depreciation schedules; see Section C3-2.3a below and ERG [2004d]).
C3-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

a.   Pre-Tax Cost of Compliance for Representative Platforms
The costs shown in Table C3-5 reflect the estimated costs incurred by each platform, by type of platform. Costs
are derived as above for computing national aggregate costs, but these costs are for a representative deepwater
platform that comes on line in 2007 (year of compliance assumed 2007) and the representative Cook Inlet
platform coming on line in 2014 (year of compliance). Costs (which are incurred over the full time frame of the
analysis, including recurring capital replacement and repermitting costs) are discounted to the applicable year of
compliance and annualized over 30 years at 7 percent.

Table C3-5 presents the costs of compliance on an annual basis for the two types of platforms. As the table
shows, these costs are $82,338 or $281,949 depending on type of platform.
                Table C3-5: Per-Platform Annualized Pre-Tax Cost of Compliance (2003$)
Type of Cost
Permitting share
Deepwater
Alaska
Capital/Installation
Deepwater
Alaska
Monitoring share
Deepwater
Alaska
O&M
Deepwater
Alaska
Total
Deepwater
Alaska
Present Value
(Year of Compliance)

$80,513
$740,570

$402,151
$600,012

$18,021
$292,520

$592,574
$2,110,532

$1,093,259
$3,743,633
Annualized Cost of
Compliance

$6,064
$55,776

$30,288
$45,190

$1,357
$22,031

$44,629
$158,953

$82,338
$281,949
            Source:  U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
b.  After-tax Costs for Representative Platforms
After-tax costs are presented here for comparison purposes.  After-tax costs are assumed to be lower than the pre-
tax costs by the top marginal corporate tax rate of 35 percent (IRS, 2002). Thus the costs calculated are 65 percent
of the pre tax costs in Table C3-5 above.

The annual after-tax per-platform compliance costs are $53,520 for deepwater platforms and $183,267 for the
Alaska platform, based on the pre-tax costs shown above in Table C3-5.
                                                                                                   C3-11

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

C3-2.3 Impact Analysis

The impact analysis for oil and gas production platforms is divided into two types: platform-level and firm-level.
The platform-level analyses include two approaches to determining the potential for impacts. Although the
financial condition of new platforms cannot be known, the financial conditions of a few, representative existing
platforms are reflected in EPA's 316(b) survey of production platforms. EPA received economic surveys from
one deepwater platform and one Alaska platform with CWIS intake rates meeting the proposed rule's
requirements.  The financial information from the deepwater platform is used for a general assessment of how
well new deepwater platforms would do financially if the proposed rule's costs applied. The Alaska platform that
was surveyed, however, is a very old structure and  is at the end of its productive life, thus has a production profile
completely different from what would be expected  of a new operation. Furthermore, new platforms constructed
in Cook Inlet are far likelier to look like the Osprey platform, which is a departure from the older technology
represented by the other Cook Inlet platforms. The Osprey platform was designed to operate as a MODU until a
productive reservoir was located, at which point the MODU was designed to convert to a stationary production
platform. This design allowed Osprey to be built at a significantly lower cost than the traditional fixed platforms
located in the inlet.  EPA does not have sufficient financial information at this time to model an Osprey-type
platform. For these reasons, the potential for impact on a new Alaska platform is assessed only in the second
platform-level analysis, described below.

The second platform-level analysis is a more typical barrier-to-entry analysis used for new entities.  It uses the
present value of initial permitting costs (discounted to the year of compliance) plus the capital/installation costs
and compares these costs to the construction costs for each type of platform. This is a typical barrier-to-entry
analysis, which assesses incremental start-up costs  associated with compliance to baseline start-up costs.

The firm-level analysis is a revenue test, comparing the revenues of firms likely to construct platforms whose
CWISs meet the proposed rule's criteria with the annualized compliance costs for each platform, assuming each
firm considered likely to build a regulated platform in the deepwater builds four platforms/structures over the time
frame of the analysis. For simplicity and to be conservative, EPA assumes the firms bring all platforms on line in
one year for comparison to one year's revenues. One small firm is assumed the likeliest to build one platform in
Alaska during the time frame of the analysis, and this firm is assigned the cost of the one Alaska platform
assumed to be constructed during the analysis period.

a.   Platform Impact Analysis Using Survey Platforms
Oil and gas production platforms are modeled somewhat differently than most other Phase III entities.  Because
the surveyed deepwater platform was a relatively new structure in 2002 (the first year of survey data provided),
the model is built using survey data to represent new, later-built structures.

Generally, the model can show production extending as far out as 30 years. Calculations, such as the after-tax
costs of compliance that are computed outside of the model platform framework (presented earlier in this
Chapter), use a 5 or 10-year time frame over which to annualize costs.  The platform model operates somewhat
differently.  Pre-tax costs are input into the model in the year in which they occur (including costs incurred in pre-
production years). The model calculates after-tax costs, which are then annualized over the modeled production
life, which could be shorter than 30 years. For this reason, repermitting costs are input into the model every five
years and capital costs for CWISs are input every 10 years, until the model shows the platform is uneconomical to
operate.

EPA has developed a model deepwater oil and gas  production platform based on information obtained from
EPA's survey and from other sources of publicly available information, such as that from MMS. ERG (2004d;
non-CBI version) contains additional details on the methodology, non-CBI data, and assumptions on which the
model is based and how the model was constructed. EPA has used the same basic approach a number of times for
analyzing impacts of effluent guidelines on oil and  gas facilities (see, for example, U.S. EPA, 2000). Usually, the
only differences are the input variables, such as production rates, that are used to model individual platforms. For
specific details on the values of variables defined by survey information and the detailed impact results, see ERG
(2004d;CBI version).

C3-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

The model is based on both a cash flow and net income approach. The projected net revenues are compared to
operating costs at each year for each model project. Net revenues (after subtracting royalties and severance,
which are payments to the lease owner and a State, if relevant) are based on an assumed price of oil, current and
projected production of oil and gas, well production decline rates, and severance and royalty rates.  Operating
costs are based on a calculated cost per barrel of oil equivalent (BOB) produced. The model runs for 30 years or
is assumed to shut in when operating costs exceed revenues.  That is, the economic model can calculate differing
lifetimes according to project characteristics.  The model then calculates the lifetime of the project,  total
production and the net present value of the operation (net income of the operation over the life of the project in
terms of today's dollars), which includes the net operating earnings, taxes, expenditures on drilling, other capital
expenditures, etc. A positive net present value means that the project is a good investment. In this case the return
is greater than the discount rate, which represents the opportunity cost of capital. If the net present  value is
negative, it means that money would have been better invested elsewhere.

The model is run twice-with and without the change due to the 316(b) Phase  III requirements. The  incremental
cost to retrofit I&E equipment is input into a capital expenditure line (which is used in both the cash flow and net
income calculations), and additional O&M and permitting costs are input to the cash flow section of the model.
The post-compliance results (including production, project life, and net present value of income) are compared to
those  calculated under baseline assumptions.

There are two  ways the increased costs can have an impact on a platform. First, any increase in operating costs
might raise total operating costs enough to cause the operating costs to exceed net revenues earlier than in the
baseline. If the platform life is reduced, there will be a concomitant loss of production. Second, any increase in
costs, whether operating, capital or permitting, could also drive the net present value of a marginal operation
negative.  The decision in this case would be to not develop the project rather than build the project with I&E
controls in place,  since the project would not be considered a good investment.  If the platform has  a positive net
present value under baseline conditions but a negative net present value in the post-compliance scenario, EPA
notes  an impact on the platform and estimates the production lost as a result.

Due to issues with CBI, the detailed results of the platform-specific impacts are not reported  here. See ERG
(2004d; CBI version) in the CBI portion of the Rulemaking Record for detailed information on impacts.
However, EPA determined that there would be no impacts on deepwater oil and gas development or production
due to the proposed rule's costs based on model results.  Impacts on net present value of projects is  expected to be
very small.

b.  Barrier to Entry Analysis  (Platform Level)
EPA uses the incremental capital costs and present value of initial permitting  costs for compliance for new
deepwater and Alaska platforms to compare to the costs of construction of new platforms, identical to the
approach used to measure impacts on MODU owners. If the initial investment costs of compliance are a small
fraction of baseline construction costs, EPA assumes that compliance costs would not have a major impact on
future platforms and would  not have an effect on a decision to build additional oil and gas production platforms.

Costs for constructing deepwater platforms are estimated to range from $114  million to $2.3  billion (see U.S.
EPA,  2000). Forest Oil (Forest Oil, 2004) reports that the 2002 capital outlay for the Osprey platform in Cook
Inlet was $120 million (which does not include exploration, delineation, or additional costs to continue to develop
the platform).  For deepwater platforms, EPA estimates that a platform coming on line in 2007 would incur costs
of $291,253 (deepwater) and $685,161 (Alaska) in capital/installation costs plus the present value cost of the
initial round of permitting costs. The ratio of incremental compliance costs to construction costs ranges from 0.01
percent to 0.3 percent for deepwater projects and 0.6 percent for an Alaska project.  This is a small  fraction of
contingency on these projects.

c.  Firm Level Impacts
The firms that are considered affected are  those identified as currently having platforms or structures in the
deepwater that meet the proposed rule's criteria. In Alaska, Forest Oil is selected as the likeliest type of firm to
build  an Alaska platform during the time frame of the  analysis. All the firms  considered likely to build a new

                                                                                                    C3-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

platform/structure subject to the proposed rule have publicly available data on 2002 revenues. Each firm is
expected to bring on line four affected platforms over the period of analysis.  For simplicity and to be
conservative, EPA assumes all four platforms are brought on line in the same year for comparison to one year's
revenues. The costs of compliance are calculated as the cost stream over the compliance lifetime of a
representative deepwater platform constructed in 2007 and an Alaska platform constructed in 2014, discounted to
the year of compliance and annualized (the same approach used for judging impacts on MODU owners). These
costs are then compared to firm-level revenues in a revenue test. Both pre-tax costs, reported in Table C3-5 above,
and after-tax costs are used to compare to revenues.

Table C3-6 presents the affected firms in both regions of concern (deepwater and Alaska), their annual revenues,
their annualized pre-tax costs of compliance applied to all potentially affected structures they might construct, and
the ratio of their compliance costs to revenues. As the table shows, costs to revenues are 0.012 percent or less for
all affected firms.
                            Table C3-6: Revenue Test for Platform Owners
Name
Amerada Hess
BP
ChevronTexaco
ExxonMobil
Forest Oil
Royal Dutch/Shell
Total
No. of
Platforms
4
4
4
4
1
4
21
Revenues
(Smillions)
$3,783
$178,721
$56,748
$205,000
$2,450
$235,598
$682,300
Pre-Tax PV
Costs
(Smillions)
$0.3
$0.3
$0.3
$0.3
$0.3
$0.3
$1.90
Pre-Tax
Costs to
Revenues
0.009%
<0.001%
0.001%
0.001%
0.012%
<0.001%
<0.001%
After-tax
Initial
Investment
Costs
$0.2
$0.2
$0.2
$0.2
$0.2
$0.2
$1.3
After-tax
Costs to
Revenues
0.006%
<0.001%
<0.001%
0.001%
0.007%
0.001%
O.001%
 Source: SEC, 2003; U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
C3-3  TOTAL COSTS AND IMPACTS AMONG ALL AFFECTED OIL AND GAS INDUSTRY
       ENTITIES

Table C3-7 on the following page summarizes the total costs and impacts associated with the 316(b) Phase III
Rulemaking on the oil and gas industry.

As the table shows, impacts on new MODUs and platforms and their associated firms are expected to be minimal,
Aggregate national after-tax compliance costs are also shown in the table.  These costs total $1.8 million per year
for MODUs and $1.2 million per year for platforms, which is $3.1 million per year over all affected new oil and
gas operations estimated to be  constructed over the period of the analysis.
C3-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities


        Table C3-7: Total National Aggregate Annualized After-tax Compliance Costs and Impacts
                                  for the Oil and Gas Industry (2003$)
O&G Facility
MODUs
Platforms
Total"
Annualized After-tax Compliance Costs
(in Sm i II ions, discounted to year of compliance)
$1.8
$1.2
$3.1
Facility Impacts
0
0
0
Firm Impacts
0
0
0
 a   Totals may not sum due to independent rounding.

 Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
C3-4   TOTAL COSTS TO GOVERNMENT ENTITIES AND SOCIAL COSTS OF THE 316(B) PHASE III RULEMAKING

C3-4.1  Total Costs to Government Entities

The costs in Table C3-8 reflect those costs to Region 6, Region 4 and Region 10 to administer the costs of the
three General Permits as well as to maintain these permits overtime as the number of permittees increases or
decreases. The details of individual cost items and timing assumptions can be seen in Chapter D2: UMRA
Analysis. Costs are arrayed over the time frame of the analysis and discounted at either 3% or 7% to 2007.
Table C3-8: Total Costs to Government Entities (2003$)
Government Entity
Present Value Cost (2007)
Annualized Cost
                                             3% Discount Rate
EPA Region 6
EPA Region 4
EPA Region 10
Total government cost
$4,670,139
$3,792,250
$40,778
$8,503,168
$231,327
$187,843
$2,020
$421,190
                                             7% Discount Rate
EPA Region 6
EPA Region 4
EPA Region 10
Total government cost
$2,394,817
$1,888,682
$22,602
$4,306,101
$180,364
$142,245
$1,702
$324,311
           Source: U.S. EPA 2004a; U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
C3-4.2  Total Social Costs

The total costs to government entities, plus the total pre-tax cost to industry are used as an approximation of total
social cost. There is no lost production of oil and gas calculated and no closures or firm failures are estimated.
Thus no social costs associated with employment dislocations are incurred.  A small  deadweight loss would occur,
                                                                                                   C3-15

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

but this is not calculated. Consumer and producer surplus losses are also not calculated, but they are captured in
the total pre-tax cost to industry.

Table C3-9 presents the total social costs associated with the 316(b) requirements under the proposed rule.  The
annualized social costs of the rule associated with the affected oil and gas industries under the proposed rule is
approximately $3.7 million using the 3 percent social discount rate suggested by OMB and $3.0 million per year
using OMB's 7 percent discount rate.
           Table C3-9: Total Social Costs of the Proposed Rulemaking for Oil and Gas Industries
                                             (in millions, 2003$)
                   Cost Item
Present Value Cost (2007)
                                               3 % Discount Rate
                                               7 % Discount Rate
        Note: Totals may not add due to independent rounding.

        Source: EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
Annualized Costs
MODU compliance costs
Platform compliance costs
Total pre-tax compliance costs
Government cost
Total social costs
$37.5
$28.0
$65.4
$8.5
$73.9
$1.9
$1.4
$3.2
$0.4
$3.7
MODU compliance costs
Platform compliance costs
Total pre-tax compliance costs
Government costs
Total social costs
$21.4
$14.6
$36.0
$4.3
$40.3
$1.6
$1.1
$2.7
$0.3
$3.0
C3-16

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities

REFERENCES

Drilling Contractor. 2003. Large jackups are most notable of new built rigs. November/December.

ERG. 2004a.  Cost Timing and Cost Sharing Assumptions for Industry Compliance Costs. Memorandum to the
316(b) Phase III Rulemaking Record.  September 24, 2004.

ERG. 2004b. Costs for Existing Oil and Gas Facilities Had These Been Regulated Under 316(b) Phase III.
Memorandum to the 316(b) Phase III Rulemaking Record. September 24, 2004.

ERG. 2004c. MODU Cost and Impact Calculations. Memorandum to the 316(b) Phase III Rulemaking Record
(Non-CBI version) and CBI Rulemaking Record (CBI version). September 24, 2004.

ERG. 2004d. Detailed Methodology and Results for Oil and Gas Production Platforms.  Memorandum to the
316(b) Phase III Rulemaking Record (Non-CBI version) and CBI Rulemaking Record (CBI version). October 7,
2004.

Forest Oil.  2002. Presentation on Forest Oil Corporation given at Bane of America Securities Energy and Power
Conference. June 2002  Available athttp://www.forestoil.com/downloads/presentation_bancofamerica_
jun_2002.pdf

Hatton, S., H. Howells, and M. Hudson. 2002. Reducing Drilling Costs: A High Pressure Small Bore Drilling
Riser System. 2H Offshore Engineering Ltd. Available at http://www.2hoffshore.com/papers/docs/new/
Paper61.pdf

SEC. 2003. Security and Exchange Commission Edgar Database of Corporate Filings.
http: //www .sec .gov/edgar. shtml

U.S. Department of the Treasury. 2002. Internal Revenue Service (IRS). 2002 Instructions for Forms 1120 &
1120-A, page 17 (Federal tax rates).

U.S. Environmental Protection Agency (U.S. EPA). 2004a.  Information Collection Request for Cooling Water
Intake Structures Phase III Proposed Rule.  ICR Number 2169.01. October 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2004b.  Technical Development Document for the Proposed
Section 316(b) Phase III Facilities.  EPA-821-R-04-015. November 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2000.  Economic Analysis of Final Effluent Limitations
Guidelines and Standards for Synthetic-Based Drilling Fluids and Other Non-Aqueous Drilling Fluids  in the Oil
and Gas Extraction Point Source Category. EPA-821-B-00-012. December 2000.
                                                                                               C3-17

-------
§ 316(b) Proposed Rule: Phase III - EA, Part C: Economic Analysis for Phase III New OOGE Facilities    C3: EIAfor OOGE Facilities
                           THIS PAGE INTENTIONALLY LEFT BLANK
C3-18

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA
  Chapter  Dl:  Regulatory  Flexibility  Analysis
                                               Dl-2
                                               Dl-3
 Dl-2
 Dl-2
 Dl-7
 Dl-7
 Dl-7
 Dl-8
Dl-10
Dl-11
CHAPTER CONTENTS
Dl-l Analysis of Manufacturers	
     Dl-1.1   Small Entity Determination	
     Dl-1.2   Percentage of Small Entities Regulated
     Dl-l.3   Sales Test for Small Entities	
     Analysis of Electric Generating Facilities	
     D 1-2.1   Small Entity Determination	
     D 1-2.2   Percentage of Small Entities Regulated
     Dl-2.3   Sales Test for Small Entities	
     Analysis of New Offshore Oil and Gas Extraction
     Facilities 	Dl-12
     Dl-3.1   Small Entity Determination	Dl-12
     Dl-3.2   Percentage of Small Entities Regulated . Dl-14
     Dl-3.3   Sales Test for Small Entities	Dl-14
     Summary of Regulatory Flexibility Analysis  . . . Dl-14
References 	Dl-16
Appendix 1 to Chapter Dl	D1A1-1
Appendix 2 to Chapter Dl	D1A2-1
                                               Dl-4
INTRODUCTION

The Regulatory Flexibility Act (RFA) requires
EPA to consider the economic impact a proposed
rule would have on small entities. The RFA
requires an agency to prepare a regulatory
flexibility analysis for any notice-and-comment
rule it promulgates, unless the Agency certifies
that the rule "will not, if promulgated, have a
significant economic impact on a substantial
number of small entities" (The Regulatory
Flexibility Act, 5 U.S.C. § 605(b)).

Small entities include small businesses, small
organizations, and small governmental
jurisdictions. For assessing the impacts of the
proposed regulation proposal on  small entities, a
small entity is defined as: (1) a small business as
defined by the Small Business Administration's
(SBA) regulations at 13 CFR 121.201; (2) a small
governmental jurisdiction that is  a government of a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.

The SBA small business size standards changed from a SIC code-based system to a NAICS code-based system on
October 1, 2000. Since EPA conducted its data collection effort for existing facilities before this change, EPA
performed the small entity analysis for existing facilities based on SIC codes. EPA then conducted a subsequent
analysis to determine whether use of NAICS codes-based size standards would yield different results. This
analysis showed, for the three proposed options as  well as for all other evaluated options, that the small entity
determinations and assessments of small entity impacts are the same under both SIC-based and NAICS-based size
standards. Appendix 2 to this chapter presents the  findings for the comparison of the SIC-based analysis and the
NAICS-based analysis.

To evaluate the potential impact of this rule on small entities, EPA identified the domestic parent entity of each
facility potentially subject to Phase III regulation, and determined its size. EPA then used a "sales test" to assess
the potential severity of economic impact on small entities. The test compares annualized compliance cost to total
entity sales revenues.  This analysis uses three cost-to-revenue ranges to report the estimated number and
percentage of small entities incurring compliance costs: less than 1%; at least 1% but less than 3%; and at least
3%.  EPA assumed that small entities with costs of 3% of revenues or more might be significantly impacted as a
result of the proposed rule.

EPA is proposing three options that define which existing facilities would be subject to the national categorical
requirements under the proposed rule: the "50 MOD for All Waterbodies" option (the "50 MOD All" option); the
"200 MOD for All Waterbodies" option (the "200  MOD All" option); and the "100 MOD for Certain
Waterbodies" option (the "100 MOD CWB" option).  These options all require the same reduction in
impingement and entrainment (I&E), and differ only by design intake flow (DIP) applicability threshold and
waterbody type. As a result, the  number of facilities that would be required to meet the national categorical
requirements varies among the three options: the 50 MGD All option, the proposed option with the broadest
applicability, would apply national categorical requirements to 136 facilities. The 200 MGD All option would
apply national categorical requirements to 25 facilities, while the 100 MGD CWB option would apply national
                                                                                              Dl-l

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities              Dl: RFA

categorical requirements to 19 facilities. In addition to the analyses for the three proposed options, the appendix
to this chapter presents analyses for five other options evaluated but not proposed for existing facilities (Option 1,
Option 2, Option 3, Option 4, and Option 6).

EPA is also proposing section 316(b) requirements for new offshore oil and gas extraction facilities (also
abbreviated as "new OOGE facilities") in Phase III. These proposed requirements are based on a 2 MOD DIP
applicability threshold and would apply to an estimated 124 new offshore oil and gas extraction facilities.

EPA's analysis found that this proposed rule would not have a significant economic impact on a substantial
number of small entities.  This determination is based on the finding that this rule would apply national
categorical requirements to only one small entity (entities that operate facilities subject to permit specifications
based on best professional judgment, BPJ, would not incur incremental compliance costs under this rule  and are
excluded from this analysis).  In the Manufacturers and Electric Generators industry segments, no small  entity is
expected to meet the lowest proposed flow threshold of 50 MOD and therefore, no small entity in these segments
would be subject to the national requirements. In the new offshore oil and gas extraction industry segment, EPA
estimates that the proposed rule would apply national requirements to only one small entity. EPA estimates that
this entity would incur annualized after-tax compliance costs of less than 0.1% of annual sales revenues.
Dl-1   ANALYSIS OF MANUFACTURERS

EPA's 2000 Section 316(b) Detailed Industry Questionnaire (U.S. EPA, 2000) identified 199 facilities in the five
Primary Manufacturing Industries - Paper, Chemicals, Petroleum, Aluminum, and Steel - assessed as potentially
subject to the options considered for Phase III existing facilities. As described in Chapter B3: Economic Impact
Analysis for Manufacturers, these 199 facilities represent 532 facilities in those industries.1 In addition, this
section also considers the effect of the regulation on facilities in Other Industries that are also expected to be
affected by the regulation. The analysis of facilities in Other Industries is restricted to a sample of 22 facilities for
which  EPA received surveys but which are not part of the statistically valid sample.  EPA estimates that 30 of the
199 sampled facilities in the five Primary Manufacturing Industries, representing 76 facilities industry-wide, and
four of the 22 known facilities in Other Industries are baseline closures; these facilities are excluded from this
analysis (see Chapter B3: Economic Impact Analysis for Manufacturers for more information). The remainder of
the small entity analysis for Manufacturers therefore discusses research done for the 169 sample facilities in
Primary Manufacturing Industries, representing 456 facilities that are open in the baseline, and an additional 18
known facilities in Other Industries that are open in the baseline.

Although EPA's sample-based data for the Primary Manufacturing Industries support specific estimates of the
number of small entity-owned facilities, these data do not support a specific estimate of the number of small
entities that own these facilities.  As a result,  EPA estimated the number of small entities owning facilities in the
Primary Manufacturing Industries as a range, based on alternative assumptions about the ownership of regulated
manufacturing facilities by small entities.

Dl-1.1 Small Entity Determination

The small entity determination for Manufacturers facilities was conducted in two steps:

    *•   Identify the domestic parent entity of the 169 sample facilities in the Primary Manufacturing Industries
        and the 18 additional known facilities in Other Industries.

    *•   Determine the size of the entities owning the  169 sample facilities in the Primary Manufacturing
        Industries and the 18  additional known facilities in Other Industries.
    1 EPA applied sample weights to the 199 facilities to account for non-sampled facilities and facilities that did not respond to the
survey.  For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA, 1999a).

Dl-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA
a.  Identification of Domestic Parent Entities
The RFA analysis is conducted at the highest level of domestic ownership, referred to as the "domestic parent
entity" or "domestic parent firm." EPA gathered information on the domestic parent firm in the Detailed Industry
Questionnaire.  In instances where a response was not provided, EPA used several other data sources to determine
the domestic parent firm including the Screener Questionnaire,  corporate websites, and Dun & Bradstreet data
(D&B, 2003). EPA determined that 100 unique entities own the 169 facilities in the Primary Manufacturing
Industries.  One known facility in the Other Industries was also  found to be owned by a firm that owns facilities in
the Primary Manufacturing Industries. Therefore, the 100 unique entities own 170 sample facilities.  The
remaining 17 facilities in Other Industries were found to be owned by 14 unique entities.

b.  Size Determination of Domestic Parent Entities
EPA identified the size of each entity owning a potentially regulated Manufacturers facility using Small Business
Administration (SBA) size threshold guidelines.2 These thresholds define the minimum firm-level employment or
revenue size, by industry (four-digit SIC codes), below which a business qualifies as a small business under SBA
guidelines.3 To determine the entity size, EPA used data from the Detailed Industry Questionnaire, as well as the
Screener Questionnaire, corporate websites, the U.S. Securities and Exchange Commision's (SEC) FreeEdgar
database, corporate websites, and Dun & Bradstreet data (SEC,  2004; D&B, 2003).

Table Dl-1 presents the unique firm-level 4-digit SIC codes and corresponding SBA size standards used to
determine the size of entities that own Manufacturers facilities potentially subject to Phase III regulation.
Table Dl-1:
SIC Code
0133
1011
1311
2011
2046
2061
2062
2063
2075
2211
2421
2611
2621
2631
2653
2673
Unique 4-Digit Firm-Level SIC Codes and
SIC Description
Sugarcane and Sugar Beets
Iron Ores
Crude Petroleum and Natural Gas
Meat Packing Plants
Wet Com Milling
Cane Sugar, Except Refining
Cane Sugar Refining
Beet Sugar
Soybean Oil Mills
Broadwoven Fabric Mills, Cotton
Sawmills and Planing Mills, General
Pulp Mills
Paper Mills
Paperboard Mills
Corrugated and Solid Fiber Boxes
Plastics, Foil, and Coated Paper Bags
SBA Size Standards for Manufacturers a
SBA Size Standard
$0.5 Million
500 Employees
500 Employees
500 Employees
750 Employees
500 Employees
750 Employees
750 Employees
500 Employees
1,000 Employees
500 Employees
750 Employees
750 Employees
750 Employees
500 Employees
500 Employees
    2 The SBA website provides the most recent size thresholds at http://www.sba.gov/regulations/siccodes.

    3 For a comparison of the small entity determination using SIC codes and NAICS codes, respectively, see Appendix 2 to this chapter.
                                                                                                    Dl-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA

Table Dl-1:
SIC Code
2679
2711
2812
2813
2819
2821
2824
2833
2834
2851
2869
2873
2874
2891
2899
2911
3312
3313
3315
3316
3317
3334
3353
3421
3714
3728
3999
5153
5171
6141
6719
Unique 4-Digit Firm-Level SIC Codes and SBA Size Standards
SIC Description
Converted Paper and Paperboard Products, NEC
Newspapers: Publishing, or Publishing and Printing
Alkalies and Chlorine
Industrial Gases
Industrial Inorganic Chemicals, NEC
Plastics Material and Synthetic Resins, and Nonvulcanizable Elastomers
Manmade Organic Fibers, Except Cellulosic
Medicinal Chemicals and Botanical Products
Pharmaceutical Preparations
Paints, Varnishes, Lacquers, Enamels, and Allied Products
Industrial Organic Chemicals, NEC
Nitrogenous Fertilizers
Phosphatic Fertilizers
Adhesives and Sealants
Chemicals and Chemical Preparations, NEC
Petroleum Refining
Steel Works, Blast Furnaces (Including Coke Ovens), and Rolling Mills
Electrometallurgical Products, Except Steel
Steel Wiredrawing and Steel Nails and Spikes
Cold-Rolled Steel Sheet, Strip, and Bars
Steel Pipe and Tubes
Primary Production of Aluminum
Aluminum Sheet, Plate, and Foil
Cutlery
Motor Vehicle Parts and Accessories
Aircraft Parts and Auxiliary Equipment, NEC
Manufacturing Industries, NEC
Grain and Field Beans
Petroleum Bulk Stations and Terminals
Personal Credit Institutions
Offices of Holding Companies, NEC
for Manufacturers a
SBA Size Standard
500 Employees
500 Employees
1,000 Employees
1,000 Employees
1,000 Employees
750 Employees
1 ,000 Employees
750 Employees
750 Employees
500 Employees
1 ,000 Employees
1,000 Employees
500 Employees
500 Employees
500 Employees
1,500 Employees
1,000 Employees
750 Employees
1,000 Employees
1,000 Employees
1,000 Employees
1 ,000 Employees
750 Employees
500 Employees
750 Employees
1 ,000 Employees
500 Employees
100 Employees
100 Employees
$5.0 Million
$5.0 Million
Source: U.S. SBA, 2000.
As discussed earlier, EPA estimated the number of small entities owning facilities in the manufacturing industries
as a range, based on alternative assumptions about the possible ownership of potentially regulated manufacturing
facilities by small entities. EPA considered two cases based on the sample weights developed from the facility
survey. These cases provide a range of estimates for (1) the number of firms incurring compliance costs and (2)
Dl-4

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities             Dl: RFA

the costs incurred by any firm owning a regulated facility. Chapter B3: Economic Impact Analysis for
Manufacturers provides a more detailed description of these cases.

Case 1: Upper bound estimate of number of firms owning facilities that face requirements under the
regulation; lower bound estimate of total compliance costs that a firm may incur.

For this case, EPA assumed (1) that a firm owns only the regulated sample facility(ies) that it is known to own
from the sample analysis and (2) that this pattern of ownership, observed for sampled facilities and their owning
firms, extends over the facility population represented by the sample facilities. This case minimizes the
possibility of multi-facility ownership by a single firm and thus maximizes the count of affected firms, but also
minimizes the potential cost burden to any single firm.

Case 2: Lower bound estimate of number affirms owning facilities that face requirements under the
regulation; upper bound estimate of total compliance costs that a firm may incur.

For this case, EPA inverted the prior assumption and assumed that any firm owning a regulated sample
facility(ies) owns the known sample facility(ies) and all of the sample weight associated with the sample
facility(ies). This case minimizes the count of affected firms, while tending to maximize the potential cost burden
to any single firm.

Data in the rest of this section are presented by the industry sector of the firm. EPA determined firm sector based
on the sample facilities owned by the firm.  If all of the sampled facilities owned by the firm are in the same
industry sector, then that industry sector was assigned to the firm. If sample facilities owned by the firm are in
more than one industry sector, then the firm was assigned to the "multiple industries" firm sector. As discussed
earlier, one known facility in the Other Industries group was found to be owned by a firm that owns facilities in
the Primary Manufacturing Industries.  This firm is included in the data reported for multiple industries.  The
remaining 14 entities that were found to own 17 facilities in Other Industries are presented separately.

The number of entities in Primary Manufacturing Industries that would be required to meet the national
categorical requirements set by the proposed options varies by option based on the DIP applicability threshold and
waterbody type specified in the option. Under the 50 MGD All option, between 46 (Case 2 estimate) and 105
(Case 1 estimate) firms would potentially be subject to Phase III regulation.  Under the 200 MGD All option, the
number of firms potentially regulated is between 14 (Case 2) and 21 (Case 1). Finally, the  100 MGD CWB
option would potentially regulate between 12 (Case 2) and 21 (Case 1) entities.  EPA determined that no firms
owning regulated 316(b) manufacturing facilities would be small.

Table D1-2 on the following page presents the total number of firms with facilities subject to the national
categorical requirements, as well as the number and percentage of those firms determined to be small.  The data
are shown for the two ownership cases for the three proposed options.
                                                                                                  Dl-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA

Table Dl-2: Number of Firms by Firm Sector and Size (assuming two different ownership cases)
Firm Sector
Case 1: Upper bound estimate of number
of firms owning facilities that face
requirements under the regulation
Total Number of Percentage
Number of Small of Firms that
Firms Firms are Small
Case 2: Lower bound estimate of number
of firms owning facilities that face
requirements under the regulation
Total Number of Percentage
Number of Small of Firms that
Firms Firms are Small
                                                   50 MOD All Option
Paper
Chemicals
Petroleum
Steel
Aluminum
Multiple Industries
Firms that own facilities in Primary
Manufacturing Industriesa>b
Additional firms that own known
facilities in Other Industries"
26
42
11
15
3
8
105
4
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
13
12
9
7
1
4
46
4
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
                                                  200 MGD All Option
Paper
Chemicals
Petroleum
Steel
Aluminum
Multiple Industries
Firms that own facilities in Primary
Manufacturing Industries3'1"
Additional firms that own known
facilities in Other Industries'1
3
4
3
7
0
5
21
1
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
2
3
3
2
0
4
14
1
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
                                                 100 MGD CWB Option
Paper
Chemicals
Petroleum
Steel
Aluminum
Multiple Industries
Firms that own facilities in Primary
Manufacturing Industries3'1"
Additional firms that own known
facilities in Other Industries'1
2
7
5
3
0
4
21
1
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
1
3
4
1
0
3
12
1
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
  a    Excludes firms whose only sample facilities close in the baseline.
  b    Individual numbers may not add up to totals due to independent rounding.

  Source:  U.S. EPA Analysis, 2004.
Dl-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities              Dl: RFA

Dl-1.2  Percentage of Small Entities Regulated

As part of its assessment of the small entity impact of the proposed rule on Manufacturers, EPA estimated the
percentage of all small entities in the Primary Manufacturing Industries that would be expected to be subject to
the national requirements for each of the three proposed options. Because the analysis of facilities in Other
Industries is not based on a statistically valid sample, EPA could not estimate the number of entities in Other
Industries that would be subject to the regulatory requirements of the proposed options, nor the percentage that
are small entities. From its prior analysis of the use of cooling water in industries other than the electric power
industry, EPA judges the overall effect and coverage of Phase III regulation in the Other Industries to be minor in
relation to the effect and coverage in the five Primary Manufacturing Industries.

EPA used the Statistics of U.S. Businesses (SUSB) published by the Small Business Administration to estimate
the total number of manufacturing establishments owned by small firms in each of the five Primary
Manufacturing Industries.  EPA included all of the SIC industry groups with a sample facility in the five Primary
Manufacturing Industries.  Based on the SUSB reporting framework, EPA considered all establishments owned
by a firm with 500 or fewer employees to be a small entity-owned establishment.  This assumption will tend to
underestimate the number of small entity-owned establishments in these industry groups because the SBA small
entity size criterion is greater than 500 employees for some SIC codes.  Underestimating the total number of small
entities would result in an overestimate of the percentage of small entities in these industries that subject to Phase
III regulation.

EPA estimated that 5,113 entities within the five Primary Manufacturing Industries are small. However, since no
small entity is expected to be subject to national requirements under the three proposed options, the percentage of
all small entities subject to Phase III regulation is zero.

Dl-1.3  Sales Test for Small Entities

In addition to considering the fraction of small  entities in each of the affected Manufacturers  industries that would
be subject to Phase III regulation, EPA also assessed the extent of economic/financial impact on small entities by
comparing estimated compliance  costs to estimated entity revenue (also referred to as the "sales test").  The
analysis is based on the ratio of estimated annualized after-tax compliance costs to annual revenue  of the entity.
For this analysis, EPA judges that entities for which annualized compliance costs equal or exceed 3% of revenue,
might experience a significant economic/financial impact as a result of the regulatory requirements under the three
proposed options.

EPA included the following compliance cost categories in this  analysis: pilot study capital  costs; one-time
technology costs of complying with the regulatory requirements; one-time costs of installation downtime; annual
operating  and maintenance costs; and permitting costs (initial permit costs, annual monitoring costs, and permit
reissuance costs). A detailed summary of how  these costs were developed is presented in Chapter Bl: Summary
of Cost Categories and Key Analysis Elements for Existing Facilities and Chapter B3: Economic Impact Analysis
for Manufacturers. EPA collected revenue data for the small entities in EPA's Detailed Industry Questionnaire.

In the Manufacturers segment, EPA determined that no small entities would face regulatory requirements under
the three proposed options; therefore, no small  entities would incur compliance costs or significant economic
impact under these options.


D1 -2   ANALYSIS OF ELECTRIC GENERATING FACILITIES

EPA's 2000 Section 316(b) Detailed Industry Questionnaire (U.S. EPA, 2000) identified 113 Electric Generating
facilities potentially subject to Phase III regulation. EPA estimates that three of the 113 sample facilities are
baseline closures; these facilities are excluded from this analysis (see Chapter B5: Economic Impact Analysis for
Electric Generators for more information). The remaining 110 sample facilities represent  114 facilities in the
                                                                                                  Dl-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities              Dl: RFA

industry.4 It is impossible, however, to determine the parent entities of extrapolated facilities. The remainder of
the small entity analysis for Electric Generators therefore discusses research done for the 110 sample facilities
only.

Dl-2.1  Small Entity Determination

Similar to the analysis for Manufacturers, the small entity determination for Electric Generators was conducted in
two steps:

    *•   Identify the domestic parent entity of the 110 sample facilities.
    *•   Determine the size of the entities owning the 110 sample facilities.

a.  Identification of Domestic Parent Entities
As previously described for Manufacturers, the RFA analysis is conducted at the highest level of domestic
ownership, referred to as the "domestic parent entity." EPA first identified the immediate owner of the 110
sample  Phase III Generators using the 2001 Form EIA-860 (U.S. DOE, 2001a). The immediate owners of power
plants can be classified into one of the following seven categories: investor-owned utility (IOU), nonutility,
Federal utility, State authority, municipality, political subdivision, or rural electric cooperative. lOUs and
nonutilities are private businesses; Federal utilities, State authorities, municipalities, and political subdivisions are
public sector entities;  and rural electric cooperatives are  not-for-profit  enterprises.5  EPA conducted research to
determine changes in  facility- and entity-level ownership in order to identify the correct domestic parent entity of
each potential Phase III Electric Generator. EPA incorporated known  ownership changes through the 2002
calendar year, but did not incorporate changes in facility/entity ownership that occurred after 2002 to maintain
consistency in its analyses.

Public sector entities and electric cooperatives are generally not owned by other entities. EPA therefore assumed
that these entities are the domestic parents of the facilities that they own.  lOUs and nonutilities, on the other
hand, are often owned by holding companies.  A holding company is defined by the U.S. Census Bureau as being
"primarily engaged in holding the securities of (or equity interests in) companies and enterprises for the purpose
of owning a controlling interest or influencing the management decisions of these firms" (Census, 2002). To
determine the domestic parent entity for potential Phase  III Generators owned by an IOU or a nonutility, EPA
used several publicly  available data sources, including data from the Department of Energy's (DOE) Energy
Information Administration, 2001 Form EIA-860; 10-K  filings available through the U.S. Securities and
Exchange Commission's (SEC) FreeEdgar database; corporate websites; and Dun and Bradstreet data (U.S.
DOE, 200la; SEC, 2004; D&B, 2003).

EPA determined that 72 unique domestic parent entities  own the 110 sample Electric Generators.

b.  Size Determination  of Domestic Parent Entities
Different size thresholds  apply to different types of entity (i.e., private businesses, public sector entities, and not-
for-profit enterprises). Therefore, EPA used multiple data sources to determine the sizes of the Phase III domestic
parent entities:
    4 EPA applied sample weights to the 113 facilities to account for non-sampled facilities and facilities that did not respond to the
survey.  For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.
EPA, 1999a).

    5 No political subdivisions were found to be subject to the national categorical requirements under any of the evaluated options.
Political subdivisions are therefore not discussed in this chapter.

Dl-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA
    *•  For private businesses (including lOUs and nonutilities), the small entity size is defined based on the
       parent entity's SIC code and the related size standard set by the Small Business Administration (SBA).6
       The SBA standards are based on employment, sales revenue, or total electric output (in megawatt hours,
       MWh), by 4-digit SIC code. EPA used Dun and Bradstreet data, as well as the following publicly
       available data sources, to obtain the information necessary to determine the entity size for private
       businesses: 10-K filings available through the U.S. Securities and Exchange Commission's (SEC)
       FreeEdgar database, 1999 - 2001 EIA Form-860, U.S. Census Data, and company websites (D&B, 2003;
       SEC, 2004; U.S. DOE, 2001a; Census, 2003). Table Dl-5 presents the unique firm-level SIC codes and
       the corresponding SBA size standards for Electric Generators that were used to determine the size of
       privately-owned entities.

    *•  All Federal and State governments are considered large for the purpose of the RFA analysis (U.S. EPA,
       1999b).

    *•  Municipalities are considered public sector entities. Public sector entities are defined as small if they
       serve a population of less than 50,000.  Population data for these entities were obtained from the U.S.
       Census Bureau (Census, 2003).

    *•  The SBA threshold for SIC 4911 (4 million MWh of total electric output) was used for the size
       determination of rural electric cooperatives.  The size determination was based on data from the 1999 -
       2001 Form EIA-861 (U.S. DOE, 2001b).

Table Dl-3 presents the unique firm-level 4-digit SIC codes and corresponding SBA size standards that were used
to determine the size of the entities that own Electric Generating facilities potentially subject to Phase III
regulation
              Table Dl-3: Unique 4-Digit Firm-Level SIC Codes and SBA Size Standards for
                                          Electric Generators
SIC Code
1311
1542
2621
4911
4924
4925
4932
4953
6211
9111
Source: U.S.
SIC Description
Crude Petroleum and Natural Gas
General Contractors - Nonresidential Buildings, Other than Industrial Buildings
and Warehouses
Paper Mills
Electric Services
Natural Gas Distribution
Mixed, Manufactured, or Liquefied Petroleum Gas Production and/or
Distribution
Gas and Other Services Combined
Refuse Systems
Security Brokers, Dealers and Flotation Companies
Executive Offices
SBA, 2000.
SBA Size Standard
500 Employees
$27.5 Million
750 Employees
4 million MWh
500 Employees
$5.0 Million
$5.0 Million
$10.0 Million
$5.0 Million
50,000 Population

     For a comparison of the small entity determination using SIC codes and NAICS codes, respectively, see Appendix 2 to this chapter.
                                                                                                    Dl-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities             Dl: RFA

Based on these size thresholds, EPA determined that 13 out of the 72 parent entities owning the 110 sample
facilities are small entities. Nine of the 13 small entities are municipalities, two are nonutilities, and two are rural
cooperatives.

Under the proposed options, the minimum applicability threshold for national categorical requirements is 50
MGD or greater.  Since Electric Generators with a DIP of 50 MGD or greater were covered by Phase II
regulation, no Phase III Generator would be subject to the national categorical requirements under any of the
proposed options.

Dl-2.2  Percentage of Small Entities  Regulated

As part of its assessment of the small entity impact of the proposed rule on Electric Generators, EPA compared
the number of small entities potentially subject to  Phase III regulation to the number of small entities in the entire
industry. While no small entities would be subject to the national categorical requirements under any of the
proposed options, some of the other evaluated options would regulate small entities. This analytical step is
therefore relevant to the other evaluated options only.

EPA estimated the total number of small entities in the United States using information collected by the Energy
Information Administration (EIA). Based on Form EIA-861,  858 unique lOUs, Federal utilities, State authorities,
municipalities, and rural electric cooperatives operated electric power plants in the United States in 2001. In
addition, there were 2,127 nonutilities  in 2001 (U.S. DOE, 2001a). EPA determined the entity sizes for rural
electric cooperatives based on their total electricity sales for 2001, as reported in Form EIA-861. All Federal
utilities and State authorities are assumed to be large.  As described above, EPA researched holding company
information for Phase III lOUs and nonutilities, and population data for Phase III municipalities. It was not
feasible to conduct the same research for all those types of entities in the entire industry.  EPA therefore used a
combination of methods to estimate the number of small lOUs, nonutilities, and municipalities operating in the
Electric Generating industry:

    *•   Investor-owned entities: EPA  determined which lOUs would be considered small based on the electric
        output threshold of 4 million MWh, using the 2001 Form EIA-861.  However, EPA's analysis of the
        domestic parent entity size of Section 316(b) lOUs (both for Phases II and III) showed that the small
        entity determination based on the 4 million MWh threshold is not always the same as that based on the
        holding company's SIC code.  EPA identified seven lOU-owned Phase II and Phase III Generators that
        would qualify as small entities based on the 4 million MWh total electric output threshold.7 However,
        EPA's holding company research showed that only one of these seven lOUs, or 14%, would also be
        considered small at the holding company level. EPA  therefore estimates that industry-wide only 14% of
        private entities that are small at the IOU level would also be small at the holding company level.
        Accordingly, EPA reduced the industry-wide number of privately-owned small utilities (based on Form
        EIA-861) by a factor of 86%.  Using this method, EPA estimates that six investor-owned entities in the
        Electric Generating industry are small.

    *•   Municipalities: EPA determined which municipalities would be considered small based on the electric
        output threshold of 4 million MWh, using the 2001 Form EIA-861 data. As with lOUs, EPA's analysis
        of Section 316(b) municipalities (both for Phases II and III) showed that the small entity determination
        based on the 4 million MWh threshold is not always the same as that based on population.  EPA's
        research of municipalities owning facilities potentially subject to Phase III regulation, showed that 44
        municipalities would be small  based on the 4 million  MWh size standard.8 Of these 44 entities, 26, or
        59%, would also be considered small when using the  population threshold. EPA therefore  estimates,
    7 EPA used information on small lOUs from both Phase II (five) and Phase III (two) to adjust the number of small lOUs in the
Electric Generating industry.

    8 EPA used information on small in-scope municipalities from both Phase II (30) and Phase III (14) to adjust the number of small
municipalities in the Electric Generating industry.

Dl-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities              Dl: RFA

        industry-wide, that only 59% of small municipalities, based on electric output, would also be small based
        on population size. Accordingly, EPA reduced the industry-wide number of small municipalities (based
        on Form EIA-861) by a factor of 41%. Using this method, EPA estimates that 302 municipalities in the
        Electric Generating industry are small.

The adjustments made to IOU and municipality size determinations are based on the assumption that Section
316(b) lOUs and municipalities are representative of the EIA universe of electric utilities (for lOUs in terms of
their respective sizes at the utility level and the holding company level; for municipalities in terms of their
respective sizes based on electric output and population). If this is not the case, the industry-wide estimate of
small lOUs and municipalities may be over- or underestimated.

    *•   Nonutilities: Electric output data or other information to determine the entity sizes of nonutilities are not
        available from the EIA or other public data sources. As a result, EPA estimated a range of the number of
        small nonutilities based on two methods: (1) EPA assumed that the proportion of small nonutilities in the
        industry as a whole is the same as the proportion of small nonutilities potentially subject to Phase III
        regulation (i.e., two out of 26, or 7.7%);9 and (2) EPA assumed that the proportion of small nonutilities in
        the industry as a whole is the same as the proportion of total lOUs,  municipalities, political subdivisions,
        and rural electric cooperatives estimated to  be small based on electric output (i.e., 412 of 817, or 50.4%).
        Using these two methods, EPA estimates that between 132 and 866 nonutilities within the entire Electric
        Generating industry are small.

EPA estimates that the total number of small entities in the  Electric Generating industry is between 544  and 1,278.
However, since no small entities would be subject to the national categorical requirements under any of the
proposed options, the percentage of all small entities subject to Phase III regulation is zero.

Dl-2.3  Sales Test for Small Entities

As previously described for Manufacturers, the final step in the RFA analysis consists of analyzing the cost-to-
revenue ratio of each small entity subject to Phase III regulation (also referred to as the "sales test").  The analysis
is based on the ratio of each parent entity's aggregated after-tax compliance costs (summed over each facility
owned by the parent entity and subject to the national categorical requirements) to its total sales revenue. EPA
used a threshold of 3% to determine entities that might experience a significant economic impact as a result of
Phase III regulation.

The estimated annualized after-tax compliance costs include all direct costs incurred by facilities: pilot study
capital costs; one-time technology costs of complying with the Phase III regulation; one-time costs of installation
downtime; annual operating and maintenance costs; and permitting costs (initial permit costs, annual monitoring
costs, and permit reissuance costs). A detailed summary of how these costs were developed is presented in
Chapter Bl: Summary of Cost Categories and Key Analysis Elements for Existing Facilities and Chapter B5:
Economic Impact Analysis for Electric Generators. None of the small entities that own facilities  potentially
subject regulation owns more than one Electric Generating  facility.  Therefore, no small entity would be expected
to incur compliance costs for more than one facility under any of the evaluated options.

EPA collected revenue data for the small entities with potentially regulated Phase III Electric Generators from one
of several sources, listed in order of preference: (1)  Dun and Bradstreet, (2) average utility revenue (1999-2001)
from Form EIA-861, and (3) other sources such as company annual reports or websites (D&B, 2003; U.S. DOE,
2001b).

As previously noted, Electric Generating facilities with a DIP of 50 MGD or greater, the minimum DIP
applicability threshold of the three proposed options, were covered under the final Section 316(b) Phase II rule.
Therefore, no Electric Generators are regulated or incur compliance costs under any of the proposed options.
    9 The 26 nonutilities are the immediate owners of the 31 Phase III nonutility facilities. These 26 nonutilities are owned by the 21
entities presented in Table Dl-6.
                                                                                                    Dl-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA
Dl-3  ANALYSIS OF NEW OFFSHORE OIL AND GAS EXTRACTION FACILITIES

This section discusses EPA's analysis of potential small entity impacts of the proposed rule on the new offshore
oil and gas extraction industry segment.  The proposed Phase III regulation for new offshore oil and gas extraction
facilities is based on a 2 MOD DIP applicability threshold and would regulate an estimated 124 new offshore oil
and gas extraction facilities.

Dl-3.1 Small Entity Determination

EPA used the information on existing small entities in the offshore oil and gas extraction industry to estimate the
number of small entities associated with new facilities. EPA identified 24 small entities currently operating
mobile offshore drilling units or platforms that could potentially be regulated by the proposed option for new
facilities, should they construct new MODUs or platforms similar to those currently in operation.

a.  Mobile Offshore Drilling Units (MODUs)
EPA first identified the operating companies of existing MODUs operating in the Gulf of Mexico and the number
of rigs owned by each company. EPA then linked these operating companies to their domestic parent companies.
EPA identified 21 parent firms potentially affected by the proposed rule for new facilities (see Table C2-2 in
Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry).  These affiliations were determined
primarily on the basis of Security and Exchange Commission (SEC) data using the FreeEdgar database, on which
all filings of publicly held firms are available (SEC, 2004).  The 10-K and 8-K reports were the primary sources
used to collect this information.  The 10-K annual reports generally list significant subsidiaries of the parent
company and are the source of income statement and balance sheet information used for characterizing financial
conditions at a firm. The subsidiary lists were used to confirm ownership relationships. The 8-K forms, in which
significant changes to the firm must be announced, are often the source of information on mergers and
acquisitions.

EPA identified the NAICS code for each of the domestic parent companies currently operating a MODU in the
Gulf of Mexico and the SB A size standard for each code. Table Dl-4 shows that of the 21 parent entities
operating MODUs in the Gulf of Mexico, only two entities could be identified as small. These companies own
approximately 0.5% of all MODUs operating in the Gulf of Mexico.
   Table Dl-4: Unique 4-Digit Firm-Level SIC Codes, NAICS Classification, and SBA Size Standards for
                                     Mobile Offshore Drilling Units
SIC Code
1311
1381
1389
2819
NAICS Code
211111
213111
213112
211112
NAICS Title
Crude Petroleum and Natural
Gas Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and
Gas Operations
Natural Gas Liquid Extraction
SBA Size Standard
500 employees
500 employees
$7.5 million in revenues
500 employees
Total Number of
Firms3
Small
2
-
-
-
Large
-
6
1
1
 a   Does not include seven foreign firms and four unknown firms for which NAICS or SIC codes could not be located in publicly
     available data.

 Source: SEC Edgar Database; 10K filings; 13 CFRPart 121.
Dl-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities              Dl: RFA

EPA estimates that 80 jack-up MODUs, 20 semi-submersible MODU, and three drillships will be built during the
entire 20-year period of analysis, for a total of 103 new sources (see Chapter C2: Profile of the Offshore Oil and
Gas Extraction Industry for a detailed discussion of the estimated number of new MODUs). Given that large
companies currently operate approximately 99.5% of the existing facilities, EPA estimates that no small entities
will be building new MODUs potentially subject to Phase III regulation.

b.   Platforms

»»»  Gulf of Mexico
EPA determined, based on data from the Bureau of Land Management's Minerals Management Service (MMS),
that, on average, one potentially regulated structure is built per year in the deepwater portion of the Gulf of
Mexico. EPA therefore estimates that 20 structures will be constructed over the time frame of the analysis. With
the exception of a few subsea completions, which do not operate potentially regulated CWIS, only large firms
have built structures in the deepwater Gulf of Mexico. This trend is likely to continue, given the resources
required to construct deepsea structures, which sometimes exceed $1 billion dollars (EPA 821-B-00-012).
Therefore, all of these structures are assumed to be constructed by large firms.

»»»  California
EPA does not project any platforms off the California coast to be constructed during the time period of evaluation.
Therefore, no small entities owning platforms in this area would be affected by this rule.

»»»  Alaska
In Cook Inlet, Alaska, only one new platform has been constructed in the last 16 years.  Most new exploration and
development in this region takes place from existing infrastructure or from onshore locations.  No definitive plans
appear to be in place for any new platforms in State waters.  In Federal waters, lower Cook Inlet is a source of
potential activity,  since MMS completed a lease bid in April, 2004. However, given the long lead times between
lease bid to operation, it may be unlikely that this lease bid will result in new platforms during the time frame of
the analysis. To be conservative, however, EPA assumes that one such platform might be constructed in either
Federal or State waters and begin operation in 2014. In other Federal areas in the Alaska region, little new
activity is underway. BP has dropped plans for its Liberty project in the Beaufort Sea area.  Although some leases
are actively registered in the Beaufort Sea, the time frame for development, if any is undertaken, is likely to be
beyond the time frame of this analysis. Because the most recently installed platform in Cook Inlet was built by a
small entity, EPA projects that one small entity in Alaska would potentially be affected by the rule.  This  platform
is estimated to have a DIP of greater than 2 MGD.

In summary, EPA projects that 20 new deepwater platforms in the Gulf of Mexico and one new platform  in Cook
Inlet would be potentially regulated under the proposed rule. All new platforms expected to be built in the Gulf
of Mexico are assumed to be owned by large entities. The one new platform expected to be built in Cook Inlet is
assumed to be owned by a small entity.  For more information on oil and gas platforms, including profiles and
projections for the number and type of new facilities estimated to begin operation, see Chapter C2: Profile of the
Offshore Oil and Gas Extraction Industry.

Dl-3.2 Percentage of Small Entities Regulated

Due to the capital requirements for constructing a new MODU or platform with a DIP of 2 MGD or more, very
few small businesses are expected to be affected by the proposed rule.  For existing offshore oil and gas extraction
facilities, EPA identified two small  businesses operating MODUs, 21 small businesses operating platforms in the
Federal Gulf of Mexico waters, and one small business operating a platform in Cook Inlet, Alaska for a total of 24
small businesses (four MODU owners and 37 platform owners could not be identified as small or large, since no
financial data on these firms were publicly available).  EPA estimates one small entity would potentially be
subject to  the proposed rule for new offshore oil and gas extraction facilities.  Therefore, one of 24 identified
small entities in the offshore oil and gas extraction industry (4%) is estimated to be subject to Phase III regulation.

Dl-3.3 Sales Test for Small Entities


                                                                                                   Dl-13

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses for Existing and New Facilities
DLRFA
There are no small entities projected to build new MODUs or deepwater platforms in the Gulf of Mexico that are
potentially subject to the proposed rule. In Alaska, Forest Oil is considered the likeliest type of firm to build an
Alaska platform during the time frame of the analysis.  In 2002, Forest Oil reported revenues of $2,450 million.
The annualized pre-tax costs of compliance applied to all known affected or potentially affected structures owned
by Forest Oil are $0.28 million and the annualized after-tax costs are $0.21 million.  The cost-to-revenue ratio for
the one small entity projected to be in scope of the proposed rule is therefore approximately 0.012% pre-tax or
0.008% after-tax.
Dl-4   SUMMARY OF REGULATORY FLEXIBILITY ANALYSIS

The RFA analysis, conducted in developing this proposed rule, is summarized in Table Dl-5 on the following
page. No small entity would be subject to the national categorical requirements for existing facilities under any of
the three proposed options.  Only one small entity would be subject to the national categorical requirements for
new offshore oil and gas extraction facilities under the proposed rule. This small entity is estimated to incur
compliance costs of less than 0.1% of annual revenues. As a result of this analysis, EPA concluded that the
proposed rule would not have a significant economic impact on a substantial number of small entities
                  Table Dl-5: Summary of Small Entity Impact Ratio Ranges by Sector
Industry
Total Number of
Small Entities
Number of Small
Entities Owning
Facilities
Potentially Subject
to Regulation
Percentage of
Small Entities
Subject to
Regulation
Compliance Cost/Annual
Revenues
0-1%
1-3% >3%
                   Proposed Options for Existing Facilities / 2 MGD Option for New OOGE Facilities
Manufacturers
Electric Generators
New OOGE Facilities
Total
5,113
543 - 1,295
24 1
5,680 - 6,432 1
0.0%
0.0%
4.2%
0.0%
1
1
0 0
 Source:  U.S. EPA Analysis, 2004.
Dl-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities             Dl: RFA


REFERENCES

Dun and Bradstreet (D&B). 2003.  Data extracted from D&B Webspectrum over 2002 and 2003.

Regulatory Flexibility Act. Pub. L. 96-354, Sept. 19, 1980, 94 Stat. 1164 (Title 5, Sec. 601 et seq.).

U.S. Census Bureau, Population Division (Census).  2003. National Population Dataset.  Accessed September
2003. Available at: http://eire.census.gov/popest/estimates_dataset.php

U.S. Census Bureau (Census).  2002.  1997 NAICS Definitions: 551 Management of Companies and Enterprises.
Available at: http://www.census.gov/epcd/naics/NDEF551.HTM

U.S. Department of Energy (U.S. DOE).  2001a.  FormEIA-860. Annual Electric Generator Report.

U.S. Department of Energy (U.S. DOE).  2001b.  FormEIA-861. Annual Electric Power Industry Report.

U.S. Environmental Protection Agency (U.S. EPA).  2004.  Technical Development Document for the Proposed
Section 316(b) Rule for Phase III Facilities. EPA-821 -R-04-015. November 2004.

U.S. Environmental Protection Agency (U.S. EPA).  2000.  Detailed Industry Questionnaire: Phase II Cooling
Water Intake Structures.

U.S. Environmental Protection Agency (U.S. EPA).  1999a.  Information Collection Request (ICR), Detailed
Industry Questionnaires: Phase II Cooling Water Intake Structures & Watershed Case Study Short
Questionnaire. August 1999.

U.S. Environmental Protection Agency (U.S. EPA).  1999b. Revised Interim Guidance for EPA Rulewriters:
Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act. March 29,
1999.

U.S. Securities and Exchange Commission (SEC). 2004. FreeEdgar Database. Accessed between 1999 and
2004. Available at: www.freeedgar.com.

U.S. Small Business Administration (U.S. SBA). 2000. Small Business Size Standards.  13  CFR §121.201.
                                                                                                Dl-15

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 1 to Chapter Dl
                  Appendix 1 to Chapter Dl:
 Summary of Results  for Alternative  Options
This appendix presents the results of the RFA analysis for the other options for existing facilities which were
evaluated in developing the proposed rule.  For all options, facility counts and other results only include those
Phase III existing facilities that are (1) non-baseline closures and (2) subject to national categorical requirements
under the option. See Chapter B3: Economic Impact Analysis for Manufacturers and Chapter B5'.Economic
Impact Analysis for Electric Generators for more information on baseline closures and counts of facilities subject
to national categorical requirements under each option.  See the main body of this chapter for a description of data
sources and methodologies used in these analyses.

In Table D1A-1 below, the other evaluated options for existing facilities are presented in order of increasing
stringency and/or applicability (e.g., the largest number of facilities would be subject to the national requirements
under Option 6, compared to any of the other evaluated options). As discussed in the main chapter, the estimates
of the total number of regulated small entities and the percentage of all small entities subject to  Phase III
regulation exclude consideration of entities in Other Industries within the Manufacturers segment (see section Dl-
1.2). However, the estimated number of small entities incurring costs in the three cost-to-revenue ranges include
the known number of small entities owning known facilities in Other Industries.
      Table D1A-1: Summary of Small Entity Impact Ratio Ranges for Existing Facilities by Sector
Industry
Number of Small
Entities Owning
Total Number of Facilities
Small Entities Potentially
Subject to
Regulation
Percentage of
Small Entities
Subject to
Regulation
Compliance Cost/ Annual
Revenues
0-1% 1-3% >3%
                                          Option 3
Manufacturers3'1'
Electric Generators
Total0
5,113
543-1,295
5,656 - 6,408
3
9
12
0.1%
0.7% -1.7%
0.2%
4
6
10
-
3
3
-
-
-
Option 4
Manufacturers3-11
Electric Generators
Total0
5,113
543-1,295
5,656 - 6,408
1
2
3
0.0%
0.2% - 0.4%
0.0%-0.1%
1
-
1
-
1
1
-
1
1
Option 2
Manufacturers3'1'
Electric Generators
Total0
5,113
543-1,295
5,656 - 6,408
3
9
12
0.1%
0.7% -1.7%
0.2%
4
5
9
-
3
3
-
1
1
Option 1
Manufacturers3'1'
Electric Generators
Total0
5,113
543-1,295
5,656 - 6,408
3
9
12
0.1%
0.7% -1.7%
0.2%
4
4
8
-
4
4
-
1
1
                                                                                     D1A1-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 1 to Chapter Dl
        Table D1A-1: Summary of Small Entity Impact Ratio Ranges for Existing Facilities by Sector
Industry
Number of Small
Entities Owning
Total Number of Facilities
Small Entities Potentially
Subject to
Regulation
Percentage of
Small Entities
Subject to
Regulation
Compliance Cost/ Annual
Revenues
0-1% 1-3% >3%
                                                        Option 6
Manufacturers3-1'
Electric Generators
Total0
5,113
543-1,295
5,656 - 6,408
10
13
23
0.2%
1.0% -2. 4%
0.4%
12
7
19
1
5
6
1
1
  a    For Manufacturers, the more conservative cost analysis (Case 2 estimate) is presented, which is likely to overstate the compliance
      costs that would be incurred by any single small entity but may understate the number of small entities incurring compliance costs.
  b    For Manufacturers, the "Total Number of Small Entities" and the "Number of Small Entities Owning Facilities Potentially Subject
      to Regulation" exclude entities in Other Industries; the numbers presented in the cost-to-revenue ranges include known entities in
      Other Industries.
  c    Individual numbers may not sum to reported totals due to independent rounding.

  Source:  U.S. EPA Analysis, 2004.
D1A1-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
                                                                   Appendix 2 to Chapter Dl
                  Appendix 2  to  Chapter  Dl:
     Small  Business Determinations Based on
                                NAICS  Codes
INTRODUCTION

As discussed in Chapter Dl, the SBA small business
size standards changed from a SIC code-based system
to a NAICS code-based system on October 1, 2000.
Because EPA conducted its data collection effort for
existing facilities before this change, EPA performed
the small entity analysis for existing facilities based on
SIC codes.  This appendix presents an analysis to
determine whether use of NAICS code-based size standards would affect the results of the small entity analysis.
                                         CHAPTER CONTENTS
                                         D1A2-1 Identifying NAICS Codes and
                                                Thresholds	D1A2-1
                                         D1A2-2 Differences in NAICS-Based and
                                                SIC-Based Size Thresholds	D1A2-7
                                         D1A2-3 Results	D1A2-9
                                         References 	D1A2-10
D1A2-1   IDENTIFYING NAICS CODES AND THRESHOLDS

EPA started with the unique firm-level 4-digit SIC codes for firms that own existing facilities potentially subject
to Phase III regulation (see Tables Dl-1 and Dl-3). EPA used information from the Economic Census, 7997
Economic Census: Bridge Between NAICS and SIC, to determine 1997 NAICS Codes classifications for these
firms.1  EPA also used an additional Economic Census publication/dataset, 1997 NAICS Matched to 2002 NAICS,
to bring the data forward to NAICS 2002 so that the most current small business thresholds could be used
(Census, 2003).  Table D1A2-1 presents firm-level SIC codes, SIC code descriptions, SIC code-based small
business thresholds, as well as the corresponding NAICS codes, NAICS code descriptions, and NAICS code-
based small business thresholds. For ease of reference, gray shading is used to highlight SIC codes with
corresponding NAICS code that have a different size standard.
           Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code
0133
1011
SIC Code Description
Sugarcane and Sugar
Beets
Iron Ores
SIC Size Standards
(employees/ Smillions)
$0.5
500
NAICS
Code
111991
111930
212210
NAICS Code Description
Sugar Beet Farming
Sugarcane Farming
Iron Ore Mining
NAICS Size Standards
(employees/ Smillions)
$0.75
$0.75
500
 1311
 1542
Crude Petroleum and
Natural Gas.

General Contractors -
Nonresidential
Buildings, Other than
Industrial Buildings and
Warehouses
 500
$27.5
211111
236220
Crude Petroleum and Natural
Gas Extraction
Commercial and Institutional
Building Construction
 500
$28.50
 2011   Meat Packing Plants
                         500
            311611  Animal (except Poultry)
                                    500
   1  Two different bridges are available from Census. One provides a bridge based on the processes/activities performed and the other
bridge is based on establishment classifications. This analysis uses the bridge based on establishment classifications (Census, 2000).
                                                                                      D1A2-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code
_,T_ .-,,-,» ... SIC Size Standards
SIC Code Description , , ,«,.„. ..
(employees/ Simmons)

2046
2061
2062
2063
2075
2211
2421
2611
2621
2631
2653
2673
2679
2711
2812
2813
Wet Corn Milling 750
Cane Sugar, Except _m
T-. ,- . jUU
Refining
Cane Sugar Refining 750
Beet Sugar 750
Soybean Oil Mills 500
Broadwoven Fabric . mn
Mills, Cotton 1;UUU
Sawmills and Planing ,__
Mills, General
Pulp Mills 750
750
Paper Mills
750
Paperboard Mills 750
Corrugated and Solid
Fiber Boxes
Plastics, Foil, and
Coated Paper Bags
Converted Paper and
Paperboard Products, 500
N.E.C.
Newspapers: Publishing,
or Publishing and 500
Printing
Alkalies and Chlorine 1 ,000
Industrial Gases 1,000
NAICS
Code
»,-. „-,„,-, ... NAICS Size Standards
NAICS Code Descnption , , ,„ .... .
(employees/ Smilhons)
Slaughtering
311221
311311
311312
311313
311222
311225
313210
321113
321912
321918
321999
322110
322121
322122
322130
322211
322223
326111
322222
322231
322299
516110
325181
325120
Wet Com Milling
Sugarcane Mills
Cane Sugar Refining
Beet Sugar Manufacturing
Soybean Processing
Fats and Oils Refining and
Blending
Broadwoven Fabric Mills
Sawmills
Cut Stock, Resawing Lumber,
and Planing
Other Millwork(including
Flooring)
All Other Miscellaneous
Wood Product Manufacturing
Pulp Mills
Paper (except
Newsprint)Mills
Newsprint Mills
Paperboard Mills
Corrugated and Solid Fiber
Box Manufacturing
Plastics, Foil, and Coated
Paper Bag Manufacturing
Unsupported Plastics Bag
Manufacturing
Coated and Laminated Paper
Manufacturing
Die-Cut Paper and
Paperboard Office Supplies
Manufacturing
All Other Converted Paper
Product Manufacturing
Internet Publishing and
Broadcasting
Alkalis and Chlorine
Manufacturing
Industrial Gas Manufacturing
750
500
750
750
500
1,000
1,000
500
500
500
500
750
750
750
750
500
500
500
500
500
500
500
1,000
1,000

D1A2-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code
2819
2821
2824
2833
2834
2851
2869
2873
2874
2891
2899
2911
3312
CT/- /- j T, • <,• SIC Size Standards
SIC Code Description , , . „ .„. ,
(employees/ Simmons)
Industrial Inorganic , „„„
Chemicals, N.E.C. '
Plastics Materials,
Synthetic Resins, and „_„
Nonvulcanizable
Elastomers
Manmade Organic
Fibers, Except 1,000
Cellulosic
Medicinal Chemicals „_„
and Botanical Products
Pharmaceutical „_„
750
Preparations
Paints, Varnishes,
Lacquers, Enamels, and 500
Allied Products
Industrial Organic , „„„
Chemicals, N.E.C. '
Nitrogenous Fertilizers 1 ,000
Phosphatic Fertilizers 500
Adhesives and Sealants 500
Chemicals and Chemical -„„
Preparations, N.E.C.
Petroleum Refining 1,500
Steel Works, Blast
Furnaces (Including , „„„
r^ 1 t~\ \ J 1,UUU
Coke Ovens), and
Rolling Mills
NAICS
Code
325131
325188
325998
331311
325211
325222
325411
325412
325510
325110
325120
325188
325193
325199
325311
325312
325520
311942
325199
325510
325998
324110
324199
331111
NAICS Code Description
Inorganic Dye and Pigment
Manufacturing
All Other Basic Inorganic
Chemical Manufacturing
All Other Miscellaneous
Chemical Product and
Preparation Manufacturing
Alumina Refining
Plastics Material and Resin
Manufacturing
Noncellulosic Organic Fiber
Manufacturing
Medicinal and Botanical
Manufacturing
Pharmaceutical Preparation
Manufacturing
Paint and Coating
Manufacturing
Petrochemical Manufacturing
Industrial Gas Manufacturing
All Other Basic Inorganic
Chemical Manufacturing
Ethyl Alcohol Manufacturing
All Other Basic Organic
Chemical Manufacturing
Nitrogenous Fertilizer
Manufacturing
Phosphatic Fertilizer
Manufacturing
Adhesive Manufacturing
Spice and Extract
Manufacturing
All Other Basic Organic
Chemical Manufacturing
Paint and Coating
Manufacturing
All Other Miscellaneous
Chemical Product and
Preparation Manufacturing
Petroleum Refineries
All Other Petroleum and Coal
Products Manufacturing
Iron and Steel Mills
NAICS Size Standards
(employees/ Smillions)
1,000
1,000
500
1,000
750
1,000
750
750
500
1,000
1,000
1,000
1,000
1,000
1,000
500
500
500
1,000
500
500
l,500a
500
1,000

                                                                                                            D1A2-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code
3313
3315
3316
3317
3334
3339
3353
3421



3714



CT/- /- j T, • <,• SIC Slze Standards
SIC Code Description , , . „ .„. ,
1 (employees/ Smilhons)
Electrometallurgical
Products, Except Steel
Steel Wiredrawing and
Steel Nails and Spikes '
Cold-Rolled Steel Sheet,
Strip, and Bars '
Steel Pipe and Tubes 1 ,000
Primary Production of
Aluminum '
Primary Smelting and
Refining of Nonferrous
metals, Except Copper
and Aluminum
Aluminum Sheet, Plate,
and Foil
Cutlery 500



Motor Vehicle Parts and
Accessories



NAICS
Code
331112
331492
331222
332618
331221
331210
331312
331419
331315
332996
332211
336211
336312
336322
336330
336340
336350
336399
NAICS Code Description
Electrometallurgical
Ferroalloy Product
Manufacturing
Secondary Smelting,
Refining, and Alloying of
Nonferrous Metal (except
Copper and Aluminum)
Steel Wire Drawing
Other Fabricated Wire
Product Manufacturing
Cold-Rolled Steel Shape
Manufacturing
Iron and Steel Pipe and Tube
Manufacturing from
Purchased Steel
Primary Aluminum
Production
Primary Smelting and
Refining of Nonferrous Metal
(except Copper and
Aluminum)
Aluminum Sheet, Plate and
Foil Manufacturing
Fabricated Pipe and Pipe
Fitting Manufacturing
Cutlery and Flatware (except
Precious) Manufacturing
Motor Vehicle Body
Manufacturing
Gasoline Engine and Engine
Parts Manufacturing
Other Motor Vehicle
Electrical and Electronic
Equipment Manufacturing
Motor Vehicle Steering and
Suspension Components
(except Spring)
Manufacturing
Motor Vehicle Brake System
Manufacturing
Motor Vehicle Transmission
and Power Train Parts
Manufacturing
All Other Motor Vehicle
Parts Manufacturing
NAICS Size Standards
(employees/ Smilhons)
750
750
1,000
500
1,000
1,000
1,000
750
750
500
500
1,000
750
750
750
750
750
750
D1A2-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS
SIC «,„,„,„ ... SIC Size Standards
_ , SIC Code Description , , . „ .„. ,
Code l (employees/ Smilhons)

Aircraft Parts and
3728 Auxiliary Equipment, 1,000
N.E.C.

3861 Photographic Equipment 50Q
and Supplies








3999 Manufacturing 50Q
Industries, N.E.C.






NAICS
Code
332912
333995
333996
336413
325992
333315
314999
316110
321999
322299
323110
323111
323112
323113
323119
325998
326199
332212
332999
335121
337127
339999
Codes
,.T.T^_^ , _ ... NAICS Size Standards
NAICS Code Descnption , , ,„ .... .
(employees/ Smilhons)
Fluid Power Valve and Hose
Fitting Manufacturing
Fluid Power Cylinder and
Actuator Manufacturing
Fluid Power Pump and Motor
Manufacturing
Other Aircraft Part and
Auxiliary Equipment
Manufacturing
Photographic Film, Paper,
Plate and Chemical
Manufacturing
Photographic and
Photocopying Equipment
Manufacturing
All Other Miscellaneous
Textile Product Mills
Leather and Hide Tanning
and Finishing
All Other Miscellaneous
Wood Product Manufacturing
All Other Converted Paper
Product Manufacturing
Commercial Lithographic
Printing
Commercial Gravure Printing
Commercial Flexographic
Printing
Commercial Screen Printing
Other Commercial Printing
All Other Miscellaneous
Chemical Product and
Preparation Manufacturing
All Other Plastics Product
Manufacturing
Hand and Edge Tool
Manufacturing
All Other Miscellaneous
Fabricated Metal Product
Manufacturing
Residential Electric Lighting
Fixture Manufacturing
Institutional Furniture
Manufacturing
All Other Miscellaneous
Manufacturing
500
500
500
l,000b
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500
500

                                                                                                            D1A2-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code


4911



4924

4925

4932


4953



5153

5171


6141

_,T_ ,-, , TV ... SIC Size Standards
SIC Code Description , , ,«,.„. ..
(employees/ Simmons)


Electric Services





4 million megawatt hrs.



Natural Gas Distribution 500
Mixed, Manufactured
, or
Liquefied Petroleum Gas ,., .
Production and/or
Distribution

Gas and Other Services ,., .
Combined


Refuse Systems





$10



Grain and Field Beans 100


Petroleum Bulk Stations . . _
and Terminals


Personal Credit
Institutions



$5

NAICS
Code
221111
221112
221113
221119
221121
221122
221210

221210

221210
562920
562211
562212
562213
562219
425120
424510
425110
424710
454311
454312
522120
522210
522220
522291
NAICS Code Description
Hydroelectric Power
Generation 1
Fossil Fuel Power
Generation 1
Nuclear Electric Power
Generation 1
Other Electric Power
Generation 1
Electric Bulk Power
Transmission and Control
Electric Power Distribution
Natural Gas Distribution

Natural Gas Distribution

Natural Gas Distribution
Materials Recovery Facilities
Hazardous Waste Treatment
and Disposal
Solid Waste Landfill
Solid Waste Combustors and
Incinerators
Other Nonhazardous Waste
Treatment and Disposal
Wholesale Trade Agents and
Brokers
Grain and Field Bean
Merchant Wholesalers
Business to Business
Electronic Markets
Petroleum Bulk Stations and
Terminals
Heating Oil Dealers
Liquefied Petroleum Gas
(Bottled Gas) Dealers
Savings Institutions
Credit Card Issuing
Sales Financing
Consumer Lending
NAICS Size Standards
(employees/ Smillions)
4 million megawatt hrs.c
4 million megawatt hrs.c
4 million megawatt hrs.c
4 million megawatt hrs.c
4 million megawatt hrs.c
4 million megawatt hrs.c
500

500

500
$10.50
$10.50
$10.50
$10.50
$10.50
100
100
100
100
$10.50
$6.00
















$150 million in assets4
$150 million in assets*
$6.00
$6.00


D1A2-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes
SIC
Code

6211

6719
9111
SIC Code Description

Security Brokers,
Dealers and Flotation
Companies

Offices of Holding
Companies, N.E.C.
Executive Offices
SIC Size Standards
(employees/ Smillions)

$5

$5
50,000 Population
NAICS
Code
523110
523120
523910
523999
551112
921110
NAICS Code Description
Investment Banking and
Securities Dealing
Securities Brokerage
Miscellaneous Intermediation
Miscellaneous Financial
Investment Activities
Offices of Other Holding
Companies
Executive Offices
NAICS Size Standards
(employees/ Smillions)
$6.00
$6.00
$6.00
$6.00
$6.00
50,000 Population
 Notes (from source SBA publications):

 a   For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor
     more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned
     or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or a
     throughput.  The total product to be delivered under the contract must be at least 90 percent refined by the successful bidder from
     either crude oil or bona fide feedstocks.

 b   Contracts for the rebuilding or overhaul of aircraft ground support equipment on a contract basis are classified under NAICS code
     336413.

 c   A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of electric
     energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours.

 d   A financial institution's assets are determined by averaging the assets reported on its four quarterly financial statements for the
     preceding year. "Assets" for the purposes of this size standard means the assets defined according to the Federal Financial
     Institutions Examination Council 034 call report form.

 Source: U.S. SBA, 2000; U.S. SBA, 2002.
D1A2-2   DIFFERENCES IN NAICS-BASED AND SIC-BASED SIZE THRESHOLDS

As a second step, EPA identified all potential Phase III firms whose SIC code-based small business threshold
differs from the NAICS code-based one.  There are two possible cases:

    (1)     the NAICS threshold is greater than the SIC threshold, which could lead to additional firms being
            classified as small businesses, and

    (2)     the NAICS threshold is less than the SIC threshold, which could lead to fewer firms being classified
            as small businesses.

For each such firm, EPA examined whether the firm's initial business size classification, based on the SIC code-
based criteria, would change under the NAICS code-based criteria.

Table D1A2-2 lists SIC codes for which the NAICS threshold exceeds the SIC threshold and therefore could
potentially lead to additional facilities being classified as small. The table shows that there are 13 potentially
affected firms, in 11 SIC codes, that fall into that category. Table D1A2-3 lists SIC codes for which the NAICS
threshold is less than the SIC threshold and therefore could potentially lead to  fewer facilities being classified as
small.  The table shows that there are 17 potentially affected firms, in six SIC codes, that fall into that category.
                                                                                                         D1A2-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
Appendix 2 to Chapter Dl
                       Table D1A2-2: NAICS Thresholds Exceed SIC Thresholds
                             Additional Firms May Be Classified as Small
SIC Code
0133
1542
2075
2899
3714
4925
4932
4953
6141
6211
6719
SIC Code Threshold
$0.5 million
$27.5 million
500 Employees
500 Employees
750 Employees
$5.0 million
$5.0 million
$10.0 million
$5.0 million
$5.0 million
$5.0 million
Total
NAICS Code(s)
111991; 111930
236220
311225
325199
336211
221210
221210
562920; 562211;
562212; 562213;
562219
522220; 522291
522120; 522210
5231 10; 523120;
523910; 523999
551112
NAICS Code Threshold
$0.75 million
$28.5 million
1,000 Employees
1,000 Employees
1,000 Employees
500 Employees
500 Employees
$10.5 million
$6.0 million
$150 million in assets
$6.0 million
$6.0 million

Number of
Potentially Affected
Firms
1
1
1
1
1
1
2
2
1
1
1
13
        Source: U.S. EPA Analysis, 2004.
                    Table D1A2-3: NAICS thresholds Are Less than SIC Thresholds
                               Fewer Firms May Be Classified as Small
SIC Code
2819
3312
3315
3353
3728
5171
SIC Code Threshold
1,000 Employees
1,000 Employees
1,000 Employees
750 Employees
1,000 Employees
100 Employees
Total
NAICS Code(s)
325998
324199
332618
332996
332912; 333995;
333996
454311
454312
NAICS Code Threshold
500 Employees
500 Employees
500 Employees
500 Employees
500 Employees
$10.5 million
$6.0 million

Number of
Potentially Affected
Firms
1
11
1
1
1
2
17
        Source: U.S. EPA Analysis, 2004.
D1A2-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses                        Appendix 2 to Chapter Dl


D1A2-3   RESULTS

During the final step of this comparison, EPA analyzed firms for which the SIC code-based business size
threshold differs from the NAICS code-based threshold.  For all but one firm, this analysis found that the SIC-
based and NAICS-based business size determinations were unambiguously the same: based on the firm's
employment, revenue, or electric output, no previously determined small business is large, and no previously
determined large businesses is small, under the NAICS-based threshold. However, for one firm, in SIC Code
3312, EPA's initial finding of potential change in business size classification was ambiguous because the SIC
Code in which the firm is classified, mapped to more than one NAICS code, and the NAICS code-based size
thresholds were not the same: for one of the corresponding NAICS codes (324199), the firm's business size
determination would change while for the other NAICS code (331111), the determination would not change (see
also Table D1A2-1). For this firm, EPA used information from the Dun and Bradstreet business database to
identify the firm's NAICS code as 331111, which has the same small business threshold of 1,000 employees as
SIC code 3312. Therefore, this analysis found no difference in small entity determinations, and therefore no
change in small entity impacts, as a result of using NAICS-based size standards instead of SIC-based size
standards, for the small business determination.
                                                                                               D1A2-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses                       Appendix 2 to Chapter Dl

REFERENCES

U.S. Census Bureau (Census). 2000. 1997 Economic Census: Bridge Between NAICS and SIC.  June 2000.
Available at: http://www.census.gov/epcd/ec97brdg/ (Table 2).

U.S. Census Bureau (Census). 2003. 1997 NAICS Matched to 2002 NAICS. May 2003.
Available at: http://www.census.gov/epcd/naics02/NAICS97toNAICS02.xls.

U.S. Small Business Administration (U.S. SBA).  2000. Effective until September 30, 2000.  Small Business Size
Standards.  Available at: http://www.sba.gov/regulations/siccodes/.

U.S. Small Business Administration (U.S. SBA).  2002. Effective October 1, 2002.  Small Business Size
Standards.  Available at: http://www.sba.gov/size/indextableofsize.html.
D1A2-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities    D2: UMRA Analysis

                  Chapter  D2:  UMRA  Analysis
INTRODUCTION

Title II of the Unfunded Mandates Reform Act of
1995, Pub. L. 104-4, establishes requirements for
Federal agencies to assess the effects of their
regulatory actions on State, local, and Tribal
governments and the private sector.  Under UMRA
section 202, EPA generally must prepare a written
statement, including a cost-benefit analysis, for
proposed and final rules with "Federal mandates"
that might result in expenditures by State, local, and
Tribal governments, in the aggregate, or by the
private sector, of $100 million or more in any one
year.
CHAPTER CONTENTS
D2-1   Analysis of Impacts on Government Entities . . D2-2
    D2-1.1 Compliance Costs for Government-Owned
           Facilities	D2-2
    D2-1.2 Administrative Costs for Existing
           Facilities	D2-3
    D2-1.3 Administrative Costs for New Offshore
           Oil and Gas Extraction Facilities  	D2-8
    D2-1.4 Impacts on Small Governments  	D2-11
D2-2   Compliance Costs for the Private Sector	D2-11
D2-3   Summary of UMRA Analysis  	D2-12
References 	D2-14
Appendix to Chapter D2 	  D2A-1
Before promulgating a regulation for which a written statement is needed, UMRA section 205 generally requires
EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most
cost-effective, or least burdensome alternative that achieves the objectives of the rule. The provisions of section
205 do not apply when they are inconsistent with applicable law.  Moreover, section 205 allows EPA to adopt an
alternative other than the least costly, most cost-effective, or least burdensome alternative if the Administrator
publishes with the rule an explanation why that alternative was not adopted. Before EPA establishes any
regulatory requirements that might significantly or uniquely affect small governments, including Tribal
governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan
must provide for notifying potentially affected small governments, enabling officials of affected small
governments to have meaningful and timely input in the development of EPA regulatory proposals with
significant intergovernmental mandates, and informing, educating, and advising small governments on
compliance with regulatory requirements.

EPA is proposing three options that define which existing facilities would be subject to the national categorical
requirements under the proposed rule: the "50 MGD for All Waterbodies" option (the "50 MGD All"option);  the
"200 MGD for All Waterbodies" option (the "200 MGD All" option); and the "100 MGD for Certain
Waterbodies" option (the "100 MGD CWB" option). These options all require the same reduction in
impingement and entrainment (I&E), and differ only by applicability criteria defined on the basis of design intake
flow (DIP) and waterbody type. As a result, the number of facilities that would be required to meet the national
categorical requirements varies among the three options. EPA is also proposing section 316(b) requirements for
new offshore oil and gas extraction facilities (also abbreviated as "new OOGE facilities") in Phase III.  These
proposed requirements are based on a 2 MGD DIP applicability threshold and would apply to an estimated 124
new offshore oil and gas extraction facilities.

    *•  50 MGD for All Waterbodies option for existing facilities and proposed option for new offshore oil and
       gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance  for this option
       to be $44.8 million (2003$). All of these direct facility costs are incurred by the private sector (including
       136 manufacturing facilities and 124 new offshore oil and gas extraction facilities). No facility owned by
       State and local governments would be subject to the national categorical requirements under this proposed
       option.  Additionally, State and local permitting authorities are estimated to incur $0.5  million  annually to
       administer this option, including labor costs to write permits and to conduct compliance monitoring and
       enforcement activities.  EPA estimates that the highest undiscounted after-tax cost incurred by  the private
       sector in any one year is approximately $280 million in 2011.
                                                                                                  D2-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

    *•  200 MGDforAll Waterbodies option for existing facilities and proposed option for new offshore oil
       and gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance for this
       option to be $21.4 million (2003$). All of these direct facility costs are incurred by the private sector
       (including 25 manufacturing facilities and 124 new offshore oil and gas extraction facilities).  No facility
       owned by State and local governments would be subject to the national categorical requirements under
       this proposed option. Additionally, State and local permitting authorities are estimated to incur $0.1
       million annually to administer this option, including labor costs to write permits and to conduct
       compliance monitoring and enforcement activities. EPA estimates that the highest undiscounted after-tax
       cost incurred by the private sector in any one year is approximately $91 million in 2010.

    *•  100 MGDfor Certain Waterbodies option for existing facilities and proposed option for new offshore
       oil and gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance  for this
       option to be $17.4 million (2003$). All of these direct facility costs are incurred by the private sector
       (including 19 manufacturing facilities and 124 new offshore oil and gas extraction facilities).  No facility
       owned by State and local governments would be subject to the national categorical requirements under
       this proposed option. Additionally, State and local permitting authorities are estimated to incur $0.2
       million annually to administer this option, including labor costs to write permits and to conduct
       compliance monitoring and enforcement activities. EPA estimates that the highest undiscounted after-tax
       cost incurred by the private sector in any one year is approximately $236 million in 2011.

Given these findings, EPA has determined that this rule contains a Federal mandate that may result in
expenditures of $100 million or more in any one year, for State, local, and Tribal governments, in the  aggregate,
or the private sector. Accordingly, under §202 of the UMRA, EPA has prepared a written statement, presented in
the preamble to the proposed rule, that includes (1) a cost-benefit analysis; (2) an analysis of macroeconomic
effects; (3) a summary of State, local, and Tribal input; (4) a discussion related to the least burdensome option
requirement; and (5) an analysis of small  government burden. This chapter contains additional information to
support that statement, including information on compliance and administrative costs, and on impacts on small
governments. In addition, the appendix to this chapter presents summary results for five other options evaluated
for existing facilities (Option 1, Option 2, Option 3, Option 4, and Option 6).
D2-1  ANALYSIS OF IMPACTS ON GOVERNMENT ENTITIES

Governments may incur two types of costs as a result of this proposed rule:

    *•  direct costs to comply with the rule for facilities owned by government entities, and
    *•  administrative costs to implement the rule.

Both types of costs are discussed on the following pages.

D2-1.1 Compliance Costs for Government-Owned Facilities

The Electric Generating Industry is the only industry segment potentially subject to Phase III regulation with
government-owned facilities.  No facilities in the Manufacturers or new offshore oil and gas extraction facility
segment are owned by a government. EPA has determined that no government-owned facility has a DIP that
exceeds 50 MGD (the minimum applicability threshold of the proposed options). Therefore, no government-
owned facility would incur compliance costs under any of the proposed options.
D2-2

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

D2-1.2  Administrative Costs for Existing Facilities

The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination
System (NPDES) permit program. Forty-five States and one Territory currently have NPDES permitting
authority under section 402(c) of the Clean Water Act (CWA).  EPA estimates that States and Territories would
incur three types of costs associated with implementing the requirements of the proposed rule: (1) start-up
activities, (2) permitting activities associated with the initial NPDES permit containing the new section 316(b)
requirements and subsequent permit renewals, and (3) annual activities.1  EPA estimates that the total costs for
these activities under the three proposed options would be between $0.1 million and $0.5 million, annualized over
30 years at a 7% discount rate. Table D2-1 presents the estimated annualized costs of the three major
administrative activities for each of the proposed options.
              Table D2-1: Annualized Government Administrative Costs (in millions, 2003$)
Activity
Start-Up Activities
Permitting Activities
Annual Activities
Total
50 MGD All Option
$0.01
$0.39
$0.15
$0.55
200 MGD All Option
$0.01
$0.08
$0.03
$0.12
100 MGD CWB Option
$0.01
$0.11
$0.03
$0.15
       Source:  U.S. EPA Analysis, 2004.
Based on the specific permitting requirements of each facility (see Chapter Bl: Summary of Cost Categories and
Key Analysis Elements for Existing Facilities), EPA calculated total government costs of implementing the
proposed rule by adding the cost of start-up activities to the aggregate costs for each facility's first post-
promulgation permit, repermitting activities, and annual activities. The maximum one-year undiscounted
implementation cost incurred by governments under the three proposed options is approximately $2.0 million in
2011 (50 MGD All option).  EPA notes that the  annualized cost of administrative activities depends on when they
are incurred. If facilities reach compliance later than assumed in this analysis, permitting authorities'
administrative activities would also occur in later years. As a result, the annualized costs of the rule to permitting
authorities would be lower because administrative costs incurred in  later years have lower present values.

a.  Start-Up Activities
Forty-five States and one Territory with NPDES permitting authority are expected to undertake start-up activities
to prepare for administering the proposed rule. Start-up activities include reading and understanding the rule,
mobilization and planning of the resources required to address the rule's requirements, and training technical staff
on how to review materials submitted by facilities and make determinations on the proposed Phase III
requirements for each facility's NPDES permit.  In addition, permitting authorities are expected to incur other
direct costs, e.g., for purchasing supplies and copying.  Table D2-2 shows the total start-up costs EPA estimated
permitting authorities to incur. Each permitting  authority is estimated to incur start-up costs of $4,000 as a result
of the proposed rule. EPA assumes that the initial start-up activities would be incurred by all permitting
authorities at the beginning of 2007, the year the Phase III requirements would take effect.
    1 The costs associated with implementing Phase III requirements are documented in EPA's Information Collection Request (U.S.
EPA, 2003).
                                                                                                     D2-3

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis


                           Table D2-2: Government Costs of Start-Up Activities
                                     (per Permitting Authority; 2003$)
Start-Up Activity
Read and Understand Rule
Mobilization/Planning
Training
Other Direct Costs
Total
Start-Up Costs
$977
$1,698
$1,219
$50
$3,944
                  Source:  U.S. EPA, 2004.
b.  Initial Post-Promulgation Permitting and Repermitting Activities
The permitting authorities would be required to implement the proposed Phase III requirements by adding
compliance requirements to each facility's NPDES permit. Permitting activities include incorporating section
316(b) requirements into the first post-promulgation permit and making modifications, if necessary, to each
subsequent permit. For this analysis, EPA assumed that each complying facility's first permit containing the new
section 316(b) requirements would be issued between 2010 and 2014.2  Repermitting activities would take place
every five years after initial permitting.

The proposed rule requires facilities to submit the same type of information for their initial post-promulgation
permit and for each permit renewal application. Therefore, the type of administrative activities required by the
initial post-promulgation and each subsequent permit are similar.  EPA identified the following major activities
associated with State permitting activities: reviewing submitted documents and supporting materials, verifying
data sources, consulting  with facilities and the interested public, determining specific permit requirements, and
issuing the permit.  Table D2-3 presents the State permitting activities and associated costs, on a per permit basis.
The permitting costs do not vary by type of facility to be permitted (however, the costs associated with permitting
facilities with (a) a recirculating system or a wedgewire screen in the baseline or (b) a facility installing a new
wedgewire screen are less). The burden of repermitting is expected to be smaller than the burden of initial
permitting because the permitting authority is already familiar with the  facility's case and the type of information
the facility would provide.

Two of the permitting activities presented within Table D2-3 pertain only to facilities opting for a site-specific
determination of best technology available (BTA). An authorized State is able to permit a facility to opt for a site-
specific determination if it can demonstrate that the proposed technology would result in environmental
performance within a watershed that is comparable to the reductions in impingement and entrainment mortality
that would otherwise be  achieved under the proposed rule.  EPA estimates that under the proposed rule, 50
facilities would apply for a site-specific determination.3
    2 For an explanation of how the compliance years were assigned to facilities subject to Phase III regulation, see Chapter Bl.

    3 EPA is not including this site-specific determination as a direct cost for complying facilities because this is an optional activity that
the facility would choose only in cases where the cost of the alternative technology plus the cost of the site-specific determination is less
than the cost of the technology otherwise required by the proposed rule.  However, the site-specific determination costs for permitting
authorities are not optional, and thus are included in EPA's estimates of total cost.

D2-4

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis
                       Table D2-3: Government Permitting Costs (per Permit; 2003$)
Activity
Review Source Water Physical Data
Review CWIS Data
Review CWS Operation Narrative
Review Proposal for Collection of Information for Comprehensive
Demonstration Study
Review Source Water Body Flow Information
Review Design and Construction Technology Plan
Review Impingement Mortality Monitoring Results
Review Entrainment Characterization Monitoring Results
Review Baseline Characterization Monitoring Results and Study Findings
Review Pilot Study for New Impingement & Entrainment Technology
Review Restoration Measures3
Review Technology Installation and Operation Plan & Verification
Monitoring Plan
Determine Monitoring Frequency
Determine Record Keeping and Reporting Frequency
Considering Public Comments
Issuing Permit
Permit Record Keeping
Other Direct Costs
Total Cost (without site specific determination)b
Review Information to Support Site-Specific Determination of BTA
Establish Requirements for Site-Specific Technology
Site-Specific Costs0
Total Cost (with site specific determination)b
First Post-Promulgation
Permit
$290
$871
$871
$1,302
$290
$1,443
$4,279
$4,279
$12,678
$1,302
$2,299
$1,047
$290
$290
$1,302
$265
$130
$310
$33,541
$45,980
$1,162
$47,142
$80,683
Repermitting
$113
$259
$259
$407
$113
$410
$1,284
$1,284
$3,819
$407
$690
$311
$113
$113
$407
$64
$24
$310
$10,387
$13,794
$322
$14,116
$24,503
     Assumed to apply to only 10% of facilities.  Only 10% of the per permit costs of $22,990 and $6,897 is accounted for in this
     framework.
 b   Individual numbers may not add up to total due to independent rounding.
 c   Cost incurred only for permits of facilities conducting site-specific demonstrations.

 Source:  U.S. EPA, 2004.
As shown in Table D2-3, initial post-promulgation permits that do not require a site-specific determination of
BTA are expected to impose an average per permit cost of $34,000 on the issuing permitting authority.  For initial
post-promulgation permits that include a site-specific determination, the State administrative costs associated with
the site-specific determination are estimated to increase by $47,000, resulting in total per permit costs of
approximately $81,000.
                                                                                                          D2-5

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

The State administrative cost for a permit renewal that does not include a site-specific determination is $10,000.
For facilities that conduct a site-specific determination, the cost per permit imposed on the permitting authority
increases by $14,000, resulting in an average repermitting cost of almost $25,000.

Permitting authorities also incur costs associated with review of verification studies conducted at facilities. In
addition to reviewing the studies, permitting authorities must modify permits in case of unfavorable study results.
In total, verification study review is expected to cost permitting authorities $800 per permit. Table D2-4 lists the
components of verification study review.
                       Table D2-4: Government Costs of Verification Study Review
                                           (per Permit; 2003$)
Activity
Review of Verification Studies
Permit Modification Due to Unfavorable Results
Recordkeeping
Other Direct Costs
Total
Post-Promulgation Permit Costs
$227
$517
$24
$10
$778
                 Source:  U.S. EPA, 2004.
Finally, State governments may incur costs associated with alternative regulatory requirements.  States may adopt
in their NPDES programs, alternative regulatory requirements to reduce impingement mortality and entrainment
within a watershed. If these States demonstrate to the Administrator that the reductions are comparable to what
would otherwise be achieved under rule, the Administrator would approve these alternative regulatory
requirements.  For the final Phase II rule, EPA estimated that 10 regulatory permitting authorities would incur
costs associated with alternative regulatory requirements. For this analysis, EPA assumed that those States
interested in adopting alternative regulatory requirements would have done so under the Phase II rule.  As a result,
EPA assumes that these States would incur no additional costs for establishing alternative regulatory requirements
under this proposed rule. Table D2-5 reports the cost of each component of establishing alternative regulatory
requirements.
D2-6

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis


                 Table D2-5: Government Costs of Alternative Regulatory Requirements
                                    (per Permitting Authority; 2003$)
Activity
Document Alternative Regulatory Requirements
Document Environmental Conditions within Watershed
Include Supporting Historical Studies, Calculations, and Analyses
Submit Documentation
Recordkeeping
Other Direct Costs
Total3
Post-Promulgation Permit Costs
$1,360
$1,813
$3,542
$97
$138
$100
$7,049
            a    Individual numbers may not add up to total due to independent rounding.

            Source:  U.S. EPA, 2004.
c.   Annual activities
In addition to the start-up and permitting activities discussed above, permitting authorities would have to perform
certain annual activities to ensure the continued implementation of the requirements of the proposed rule.  These
annual activities include reviewing biannual status reports, tracking compliance, making determinations on
monitoring frequency reduction, and record keeping.

Table D2-6 outlines the annual activities necessary for each permit, along with their estimated costs.  These costs
begin with the issuance of the first permit following promulgation of the rule.  A total cost of approximately
$1,500 is estimated for each permit per year.
                          Table D2-6: Government Costs for Annual Activities
                                           (per Permit; 2003$)
Annual Activity
Review of Biannual Status Report3
Compliance Tracking
Determination of Monitoring Frequency Reduction
Record Keeping
Other Direct Costs
Total"
Annual Costs
$340
$581
$453
$138
$30
$1,541
          a    This is a cost that is incurred once every two years. Therefore, only half of the total review cost of
              is accounted for in this annual framework.
          b    Individual numbers may not sum to total due to independent rounding.

          Source:   U.S. EPA, 2004.
                                                                                                       D2-7

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

The Federal government is likely to incur costs for reviewing and validating proper implementation of the section
316(b) elements of States' NPDES permits that are issued after promulgation of the rule.  Table D2-7 outlines the
annual activities associated with reviewing a permit issued after promulgation of the rule, along with the
estimated cost of each activity.  EPA estimates a cost of approximately $2,300 per permit for post-promulgation
review. Costs incurred by the Federal government are not part of the UMRA analysis but are part of the social
cost analysis presented in Chapter El of this EA.
        Table D2-7: Federal Government Permit Program Oversight Activities (per Permit; 2003$)
Annual Activity
Review Source Water Physical Data
Review CWIS Data
Review CWS Operation Narrative
Review Proposal for Collection of Information for Comprehensive Demonstration Study
Review Source Water Body Flow Information
Review Design and Construction Technology Plan
Review Impingement Mortality Study and/or Entrainment Characterization Study
Review Pilot Study for New Impingement & Entrainment Technology
Review Restoration Measures3
Review Technology Installation and Operation Plan & Verification Monitoring Plan
Review the Monitoring Frequency
Permit Record Keeping
Other Direct Costs
Total Cost (without site specific determination)1"
Review Information to Support Site-Specific Determination of BTA
Review the Established Requirements for Site-Specific Technology
Site-Specific Costs0
Total Cost (with site specific determination)1"
Post-Promulgation Permit Costs
$145
$113
$113
$113
$113
$145
$340
$113
$34
$145
$113
$130
$50
$1,699
$680
$145
$825
$2,494
 a   Assumed to apply to only 10% of facilities. Only 10% of the per permit cost of $340 is accounted for in this framework.
 b   Applies only to certain facilities, according to site specific determination of BTA Compliance Schedule.
 c   Individual numbers may not add up to total due to independent rounding.

 Source:  U.S. EPA, 2004.
D2-1.3  Administrative Costs for New Offshore Oil and Gas Extraction Facilities

For new facilities in the offshore oil and gas extraction industry, NPDES permitting is consolidated under General
Permits, which are administered by EPA Regional offices. No States are involved in these permitting activities.
Thus, unlike for existing facilities, States would incur no costs for new facility permitting. Three EPA Regions
(Region 6, Region 4, and Region  10) are expected to be the only entities responsible for permitting.  Because
States are not involved in the section 316(b) permitting for new offshore oil and gas extraction facilities, the
Federal government would incur no costs for State oversight, which again differs from the existing facilities case.
The affected EPA Regions would incur three types of costs for implementing the proposed rule: (1) start-up
D2-8

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

activities, (2) activities associated with the initial General Permit containing the new section 316(b) requirements
and subsequent permit renewals, and (3) annual activities. These  activities and their timing assumptions are
discussed below.  The timing of these costs and how they are discounted and annualized are documented in the
Oil and Gas 316(b) Compliance Cost Model (see DCN 7-4018). For more information on the methods used for
discounting and cost annualization, see Chapter Cl: Summary of Cost Categories and Key Analysis Elements for
New Offshore Oil and Gas Extraction Facilities.

It should be noted that costs incurred by the Federal government are not part of the UMRA analysis, but are part
of the social cost analysis presented in Chapter El: Summary of Social Costs and Chapter C3: Economic Impact
Analysis for the Offshore Oil and Gas Extraction Industry of this  EA.

a.  Start-Up Activities
Start-up activities are not considered incremental to existing Regional permitting activities (U.S. EPA, 2004).

b.  Initial Post-Promulgation Permitting and Repermitting Activities
Initial permitting and repermitting activities relate to the review of data collected for the  regional studies and the
individual data submitted by facilities that plan to be permitted (or re-permitted) under the General Permits in the
three EPA Regions.  Tables D2-8 and D2-9 present the individual activities and their costs for Regions 4, 6, and
10. These costs are on a per facility basis, i.e., the regions incur these costs for each facility that is permitted
under their general permits (see DCN 7-4018, which illustrates how these costs are aggregated and assigned to the
regions).

Table D2-8 presents the permit issuance activities and their related costs. The per facility initial permitting cost of
approximately $12,000 would be incurred in 2012 for facilities brought on-line or launched between 2007 and
2012 (Region 6) and in 2014 for facilities brought on-line or launched between 2007 and 2014 (Region 4 and 10).
In later years, these costs are assumed to be incurred in the year of compliance of each new facility. The burden
of repermitting is expected to be smaller than the burden of initial permitting, approximately $3,200 per facility,
because the permitting authority is already familiar with the facility's case and the type of information the facility
would provide. Repermitting costs are incurred in 5-year intervals after the initial post-promulgation permit.
                                                                                                     D2-9

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis


                   Table D2-8: Federal Government Costs for Permit Issuance Activities
                          (Per Facility Permitted under General Permits; 2003$)
Activity
Review Source Water Physical Data
Review CWIS Data
Review Source Water Body Flow Information
Review CWIS Velocity Information
Review Design and Construction Technology Plan
Review Regional Monitoring Study Design and Sampling Plans
Review Regional Monitoring Study
Review Source Water Baseline Biological Characterization Study
Determine Monitoring Frequency
Determine Record Keeping and Reporting Frequency
Consider Public Comments
Issue Permit
Permit Record Keeping
ODCs Lump Sum
Total3
First Post-
Promulgation Permit
$290
$871
$290
$1,302
$1,443
$1,443
$2,778
$1,302
$290
$290
$1,302
$265
$130
$310
$12,309
Repermitting
$113
$259
$113
$407
$410
n/a
n/a
$849
$113
$113
$407
$64
$24
$310
$3,183
 a   Individual numbers may not add up to total due to independent rounding.

 Source: U.S. EPA, 2004.
c.  Annual activities
Annual costs are associated with the activities that must be undertaken by the regions each year for each active
facility operating under the applicable General Permit.  These activities also include a one-time cost for
determining monitoring frequency reduction. This cost is assigned only to facilities operating at the time the
decision about monitoring frequency reduction is made (assumed to occur at the end of the initial two years of
monitoring, which is 2013 for the Region 6 permit and 2015 for the Region 4 and Region 10 permits). Table D2-
9 outlines these activities and their associated costs.
D2-10

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis


                      Table D2-9: Federal Government Costs for Annual Activities
                         (Per Facility Permitted under General Permits; 2003$)
Activity
Review of Yearly Status Report
Compliance Tracking
Determination on Monitoring Frequency Reduction3
Record Keeping
ODCs Lump Sum
Total"
Annual Costs
$680
$581
$0
$138
$30
$1,428
               a   One-time cost of $453 incurred only by those facilities operating in 2013 (Region 6) or
                   2014 (Regions 4 and 10).
               b   Individual numbers may not sum to total due to independent rounding.

               Source: U.S. EPA, 2004.
D2-1.4  Impacts on Small Governments

EPA's analysis also considered whether the proposed rule may significantly or uniquely affect small governments
(i.e., governments with a population of less than 50,000).  As described earlier, the Electric Generating Industry is
the only industry segment with government-owned facilities; governments own no facilities in either the
Manufacturers or new offshore oil and gas extraction facility segments. No government-owned facility exceeds
the 50 MGD DIP applicability threshold (the smallest DIP applicability threshold of the three proposed options).
Therefore, no government-owned facility would incur compliance costs under any of the three proposed options.
As no facilities owned by small governments are subject to national requirements under the proposed options,
EPA has determined that the three proposed options would contain no regulatory requirements that might
significantly or uniquely affect small governments.
D2-2   COMPLIANCE COSTS FOR THE PRIVATE SECTOR

The only compliance costs incurred by the private sector result from facilities complying with the proposed
options. These options all require the same reduction in impingement and entrainment (I&E), and differ only by
applicability threshold, which is based on the facilities' design intake flow and waterbody type. These direct
facility costs already include the cost to facilities of obtaining their NPDES permits. The methodology for
determining compliance costs for Phase III existing facilities is presented in Chapter Bl: Summary of Cost
Categories and Key Analysis Elements for Existing Facilities of this EA; the methodology for Phase III new
offshore oil and gas extraction facilities is presented in Chapter C1: Summary of Cost Categories and Key
Analysis Elements for New Offshore Oil and Gas Extraction Facilities. EPA identified all facilities subject to
national categorical requirements under the three proposed options to be owned by a private entity.

Private sector costs for the proposed option for Phase III new facilities and for the three proposed options for
Phase III existing facilities are as follows (discounted at a 7% rate):

    *•   Under the 50 MGD for All Waterbodies option for existing facilities and the proposed option for new
        offshore oil and gas extraction facilities, 260 facilities are estimated to  incur annualized compliance
        costs of $44.8 million and a maximum one year cost of $280.3 million in 2011.
                                                                                                  D2-11

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

    *•  Under the 200 MGDfor All Waterbodies option for existing facilities and the proposed option for new
       offshore oil and gas extraction facilities, 149 privately-owned facilities are estimated to incur annualized
       compliance costs of $21.4 million and a maximum one year cost, in 2010, of $90.8 million.

    *•  Under the 100 MGDfor Certain Waterbodies option for existing facilities and the proposed option for
       new offshore oil and gas extraction facilities, 143 privately-owned facilities are estimated to incur
       annualized compliance costs of $17.4 million and a maximum one year cost, in 2011, of $235.6 million.
D2-3   SUMMARY OF UMRA ANALYSIS

EPA estimates that the proposed rule would result in expenditures of $ 100 million or greater for State and local
governments, in the aggregate, or for the private sector in any one year.  Table D2-10 summarizes the after-tax
compliance costs for facilities, and the costs to implement the rule for permitting authorities, under the proposed
options.
                       Table D2-10: Summary of UMRA Costs (in millions, 2003$)
Sector
Total Annualized Cost
Facility Government
Compliance Implementation Total
Costs Costs
Maximum One- Year Cost
Facility
Compliance
Costs
Government
Implementation
Costs
Total
            50 MGDfor All Waterbodies Option for Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$0.0
$44.8
200 MGDfor All Waterbodies
Government Sector
(excl. Federal)
Private Sector
$0.0
$21.4
$0.5
n/a
$0.5
$44.8
$0.0
$280.3
$2.0
n/a
$2.0
$280.3
Option for Existing Facilities /Proposed Option for New OOGE Facilities
$0.1
n/a
$0.1
$21.4
$0.0
$90.8
100 MGDfor Certain Waterbodies Option for Existing Facilities /Proposed Option for New
Government Sector
(excl. Federal)
Private Sector
$0.0
$17.4
$0.2
n/a
$0.2
$17.4
$0.0
$235.6
$0.4
n/a
OOGE Facilities
$0.8
n/a
$0.4
$90.8

$0.8
$235.6
Source: U.S. EPA Analysis, 2004.
Costs for new offshore oil and gas extraction facilities and the three proposed options for Phase III existing
facilities are as follows:

    *•   The 50 MGDfor All Waterbodies option for existing facilities and the proposed option for new offshore
        oil and gas extraction facilities would impose annual costs of $0.5 million on State and local
        governments (in implementation costs only), and $44.8 million on the private sector.  Maximum one year
        costs under this option are estimated to be approximately $2.0 million for government entities, and $280.3
        million for the private sector. Both of these maximum annual cost values are estimated to occur in 2011.

    *•   The 200 MGDfor All Waterbodies option for existing facilities and the proposed option for new
        offshore oil and gas extraction facilities would impose annual costs of $0.1 million on State and local
D2-12

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities     D2: UMRA Analysis

       governments (in implementation costs only), and $21.4 million on the private sector. Maximum one year
       costs under this option are approximately $0.4 million for government entities in 2011, and $90.8 million
       for the private sector in 2010.

    *•  The 100 MGDfor Certain Waterbodies option for existing facilities and the proposed option for new
       offshore oil and gas extraction facilities would impose annual costs of $0.2 million on State and local
       governments (in implementation costs only), and $17.4 million on the private sector. Maximum one year
       costs under this option are approximately $0.8 million for government entities and $235.6 million for the
       private sector, both of which are estimated to occur in  2011.
                                                                                                    D2-13

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities    D2: UMRA Analysis

REFERENCES

U.S. Environmental Protection Agency (U.S. EPA). 2004. Information Collection Request (ICR)for Cooling
Water Intake Structures Phase III Proposed Rule. ICR Number 2169.01. October 2004.
D2-14

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities Appendix to Chapter D2


                      Appendix  to Chapter D2


This appendix presents the results of the UMRA analysis for the other five options considered for Phase III
existing facilities, combined with the proposed option for new offshore oil and gas extraction facilities. For all
options, results only include those Phase III existing facilities that are (1) non-baseline closures and (2) subject to
national categorical requirements under the option.  See the main body of this chapter for a description of data
sources and methodologies used in these analyses.

In Table D2A-1 below, the other evaluated options for Phase III existing facilities, combined with the proposed
option for new offshore oil and gas extraction facilities, are presented in order of increasing stringency and/or
applicability (e.g., the largest number of facilities would be subject to the national requirements under Option 6,
compared to any of the other evaluated options).
        Table D2A-1: Summary of UMRA Costs for Other Evaluated Options (in millions, 2003$)
Sector
Total Annualized Cost
Facility Government
Compliance Implementation Total
Costs Costs
Maximum One- Year Cost
Facility
Compliance
Costs
Government
Implementation
Costs
Total
                      Option 3 for Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$1.0 $0.9
$61.9 n/a
$1.9
$61.9
$1.8 $4.5
$712.2 n/a
$6.3
$712.2
Option 4 for Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$0.8 $0.8
$66.0 n/a
$1.6
$66.0
$1.7 $4.6
$722.9 n/a
$6.4
$722.9
Option 2 for Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$1.4 $1.0
$70.5 n/a
$2.4
$70.5
$2.4 $5.6
$730.7 n/a
$7.9
$730.7
Option Ifor Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$1.5 $1.1
$72.3 n/a
$2.6
$72.3
$2.4 $5.6
$737.2 n/a
$8.1
$737.2
Option 6 for Existing Facilities /Proposed Option for New OOGE Facilities
Government Sector
(excl. Federal)
Private Sector
$1.8 $1.7
$91.7 n/a
$3.5
$91.7
$2.8 $7.6
$922.3 n/a
$10.5
$922.3
Source: U.S. EPA Analysis, 2004.
                                                                                             D2A-1

-------
§ 316(b) Proposed Rule: Phase III - EA, Part D: Additional Economic Analyses for Existing and New Facilities  Appendix to Chapter D2
                           THIS PAGE INTENTIONALLY LEFT BLANK

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses
                       D3: Other Administrative Requirements
           Chapter  D3:  Other Administrative
                                 Requirements
INTRODUCTION

This chapter presents several other analyses
conducted in developing this proposed rule.
These analyses address the requirements of
Executive Orders and Acts applicable to Phase
III regulation.
D3-1  EXECUTIVE ORDER 12866:
       REGULATORY PLANNING AND
       REVIEW

Under Executive Order 12866 (58 FR 51735,
October 4, 1993), the Agency must determine
whether the regulatory action is "significant" and
therefore subject to OMB review and the
requirements of the Executive Order. The order
defines a "significant regulatory action" as one
that is likely to result in a rule that may:
D3-2
D3-3
D3-4

D3-5
CHAPTER CONTENTS
D3-1 E.G. 12866: Regulatory Planning and Review  	D3-1
     Paperwork Reduction Act of 1995	D3-1
     E.G. 13132: Federalism	D3-2
     E.G. 13175: Consultation and Coordination with
     Indian Tribal Governments  	D3-4
     E.G. 13045: Protection of Children from Environmental
     Health Risks and Safety Risks	D3-4
D3-6 E.G. 13211: Actions Concerning Regulations That
     Significantly Affect Energy Supply, Distribution,
     or Use 	D3-5
     D3-6.1  Existing Electric Generators 	D3-6
     D3-6.2  New Offshore Oil and Gas Extraction
            Facilities  	D3-7
D3-7 National Technology Transfer and Advancement
     Act of 1995 	D3-7
D3-8 E.G. 12898: Federal Actions to Address Environmental
     Justice in Minority Populations and Low-Income
     Populations 	D3-7
D3-9 E.G. 13158: Marine Protected Areas	D3-8
References  	D3-9
    *•   have an annual effect on the economy of $ 100 million or more or adversely affect in a material way the
       economy, a sector of the economy, productivity, competition, jobs, the environment, public health or
       safety, or State, local, or Tribal governments or communities; or

    »•   create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; or

    »•   materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and
       obligations of recipients thereof; or

    *•   raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles
       set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, EPA determined that this proposed rule is a "significant
regulatory action." As such, this action was submitted to OMB for review. Changes made in response to OMB
suggestions or recommendations are documented in the public record.
D3-2  PAPERWORK REDUCTION ACTOF1995

The Paperwork Reduction Act of 1995 (PRA) (superseding the PRA of 1980) is implemented by the Office of
Management and Budget (OMB) and requires that agencies submit a supporting statement to OMB for any
information collection that solicits the same data from more than nine parties. The PRA seeks to ensure that
Federal agencies balance their need to collect information with the paperwork burden imposed on the public by
the collection.
                                                                                           D3-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

The definition of "information collection" includes activities required by regulations, such as permit development,
monitoring, record keeping, and reporting.  The term "burden" refers to the "time, effort, or financial resources"
the public expends to provide information to or for a Federal agency, or to otherwise fulfill statutory or regulatory
requirements.  PRA paperwork burden is measured in terms of annual time and financial resources the public
devotes to meet one-time and recurring information requests (44 U.S.C. 3502(2); 5 C.F.R. 1320.3(b)).

Information collection activities may include:

    *•   reviewing instructions;
    *•   using technology to collect, process, and disclose information;
    *•   adjusting existing practices to comply with requirements;
    *•   searching data sources;
    *•   completing and reviewing the response; and
    *•   transmitting or disclosing information.

Agencies must provide information to OMB on the parties affected, the annual reporting burden, the annualized
cost of responding to the information collection, and whether the request significantly impacts a substantial
number of small entities. An agency may not conduct or sponsor, and a person is not required to respond to, an
information collection unless it displays a currently valid OMB control number.

EPA's estimate of the information collection requirements imposed by the proposed Phase III regulation are
documented in the Information Collection Request (ICR) which accompanies this regulation (U.S. EPA, 2004).
D3-3   EXECUTIVE ORDER 13132: FEDERALISM

Executive Order 13132 (64 FR 43255, August 10, 1999) requires EPA to develop an accountable process to
ensure "meaningful and timely input by State and local officials in the development of regulatory policies that
have federalism implications." Policies that have federalism implications are defined in the Executive Order to
include regulations that have "substantial direct effects on the States, on the relationship between the national
government and the States, or on the distribution of power and responsibilities among the various levels of
government."

Under section 6 of Executive Order 13132, EPA may not issue a regulation that has federalism implications, that
imposes substantial direct compliance costs, and that is not required by statute unless the Federal government
provides the funds necessary to pay the direct compliance costs incurred by State and local governments or unless
EPA consults with State and local officials early in the process of developing the regulation.  EPA also may not
issue a regulation that has federalism implications and that preempts State law, unless the Agency consults with
State and local officials early in the process of developing the regulation.

This proposed rule does not have federalism implications. It would not have substantial direct effects on the
States, on the relationship between the national government and the States, or on the distribution of power and
responsibilities among the  various levels of government, as specified in  Executive Order 13132.  Rather, this
proposed rule would result in minimal administrative costs on States that have an authorized NPDES program.
EPA expects the following annual burden for States to collectively administer one of the three proposed options:

    *    50 MOD for All Waterbodies option: 16,972 hours with a cost of $754,804 ($747,981 in labor costs and
        $6,823 in non-labor costs);
    >    200 MOD for All Waterbodies option: 4,677 hours with a cost of $201,092 ($198,932 in labor costs and
        $2,160 in non-labor costs);
    >    100 MOD for Certain Waterbodies option: 6,528 hours with a cost of $286,597 ($284,624 in labor costs
        and $1,973 in non-labor costs).
It is noted that States do not incur any burden hours and costs to administer the proposed rule for the new offshore
oil and gas extraction facilities because the EPA Regions administer their permits; these facilities are therefore


D3-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

outside the jurisdiction of the States. In addition, EPA has identified zero Phase III existing facilities that are
owned by Federal, State or local government entities therefore the annual impacts on these facilities is zero.

The proposed national cooling water intake structure requirements would be implemented through permits issued
under the NPDES program. Forty-five States and one territory are currently authorized pursuant to section 402(b)
of the CWA to implement the NPDES program. In States not authorized to implement the NPDES program, EPA
issues NPDES permits. Under the CWA, States are not required to become authorized to administer the NPDES
program.  Rather, such authorization is available to States if they operate their programs in a manner consistent
with section 402(b) and applicable regulations.  Generally, these provisions require that State NPDES programs
include requirements that are as stringent as Federal program requirements. States retain the ability to implement
requirements that are broader in scope or more  stringent than Federal requirements. (See section 510 of the
CWA.)

EPA does not expect this proposed rule to have substantial direct effects on either authorized or nonauthorized
States or on local governments because it would not change how EPA and the States and local governments
interact or their respective authority or responsibilities for implementing the NPDES program.  This rule
establishes national requirements for Phase III facilities with cooling water intake structures. NPDES-authorized
States that currently do not comply with the proposed regulations based on this  rule might need to  amend their
regulations or statutes to ensure that their NPDES programs are consistent with Federal section 316(b)
requirements.  (See 40 CFR 123.62(e).)  For purposes of this rule, the relationship and distribution of power and
responsibilities between the Federal government and the State and local governments are established under the
CWA (e.g., sections 402(b) and 510); nothing in this rule alters that. Thus, the  requirements of section 6 of the
Executive Order do not apply to this rule.

Although  section 6 of Executive Order 13132 does not apply to this rule, EPA did consult with State governments
and representatives of local governments in developing definitions and concepts relevant to the section 316(b)
rulemaking and this proposed rule:

    *•  During the development of the proposed section 316(b) rule for new facilities (Phase I), EPA conducted
       several outreach activities through which State and local officials were  informed about the section 316(b)
       rulemaking effort. These officials then provided information and comments to the Agency. The outreach
       activities were intended to provide EPA with feedback on issues such as adverse environmental impact,
       BTA, and the potential cost associated  with various regulatory alternatives.

    *•  EPA has made presentations on the section 316(b) rulemaking effort in general at eleven professional and
       industry  association meetings.  EPA also conducted two public meetings in June and September of 1998
       to discuss issues related to the section 316(b) rulemaking effort.  In September 1998 and April 1999, EPA
       staff participated in technical workshops sponsored by the Electric Power Research Institute on issues
       relating to the  definition and assessment of adverse environmental  impact. EPA staff have worked with
       numerous States such as New York, New Jersey, California, Rhode Island, and Massachusetts and regions
       such as Region 1 and Region 9. EPA further organized a meeting of technical experts (May 23, 2001)
       and a Symposium on Technologies for Protecting Aquatic Organisms from Cooling Water Intake
       Structures (BTA symposium, May 6-7, 2003).

    *•  EPA met with the Association of State  and Interstate Water Pollution Control Administrators
       (ASIWPCA) and, with the assistance of ASIWPCA, conducted a conference call in which representatives
       from 17  States or interstate organizations participated.

    *•  EPA met with OMB and utility representatives and other Federal agencies (the Department of Energy, the
       Small Business Administration, the Tennessee  Valley Authority, the National Oceanic  and Atmospheric
       Administration's National Marine Fisheries Service and the Department of Interior's U.S.  Fish and
       Wildlife  Service).
                                                                                                   D3-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

    *•   EPA received more than 130 comments on the Phase I proposed rule and Notice of Data Availability
       (NODA). State and local government representatives from the following States submitted comments:
       Alaska, California, Florida, Louisiana, Maryland, Michigan, Nebraska, New Hampshire, New Jersey,
       New York, North Carolina, North Dakota, Ohio, Pennsylvania, and Texas.  In addition, EPA received
       more than 170 comments on the Phase II proposed rule and NODA, including comments from State and
       local government representatives from Arkansas, Alabama, Indiana, Tennessee, and Rhode Island. In
       some cases these comments have informed the development of the Phase III rulemaking effort.

    *•   On May 23, 2001, EPA held a day-long forum to  discuss specific issues associated with the development
       of regulations under section 316(b).  At the meeting, 17 experts from industry, public interest groups,
       States, and academia reviewed and discussed the Agency's preliminary data on cooling water intake
       structure technologies that are in place at existing facilities and the costs associated with the use of
       available technologies for reducing impingement and entrainment. Over 120 people attended the
       meeting.

In the spirit of this Executive Order and consistent with EPA policy to promote communications between EPA
and State and local governments, the preamble to this proposed rule specifically solicits comment from  State and
local officials.
D3-4  EXECUTIVE ORDER 13175: CONSULTATION AND COORDINATION WITH INDIAN TRIBAL
       GOVERNMENTS

Executive Order 13175 (65 FR 67249, November 6, 2000) requires EPA to develop an accountable process to
ensure "meaningful and timely input by tribal officials in the development of regulatory policies that have tribal
implications." "Policies that have tribal implications" is defined in the Executive Order to include regulations that
have "substantial direct effects on one or more Indian Tribes, on the relationship between the Federal government
and the Indian Tribes, or on the distribution of power and responsibilities between the Federal government and
Indian Tribes." This proposed rule does not have tribal implications. It would not have substantial direct effects
on tribal governments, on the relationship between the Federal government and Indian Tribes, or on the
distribution of power and responsibilities between the Federal government and Indian Tribes, as specified in
Executive Order 13175. EPA's analyses show that no facility subject to Phase III regulation is owned by tribal
governments.  This proposed rule does not affect Tribes in any way in the foreseeable future. Accordingly, the
requirements of Executive Order 13175  do not apply to this rule.
D3-5  EXECUTIVE ORDER 13045: PROTECTION OF CHILDREN FROM ENVIRONMENTAL
       HEALTH RISKS AND SAFETY RISKS

Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be
"economically significant" as defined under Executive Order 12866 and (2) concerns an environmental health or
safety risk that EPA has reason to believe might have a disproportionate effect on children.  If the regulatory
action meets both criteria, the Agency must evaluate the environmental health and safety effects of the planned
rule on children and explain why the planned regulation is preferable to other potentially effective and reasonably
feasible alternatives considered by the Agency.  This proposed rule is a significant rule as defined under
Executive Order 12866. However, it does not concern an environmental health or safety risk that would have a
disproportionate effect on children. Therefore, it is not subject to Executive Order 13045.
D3-6  EXECUTIVE ORDER 13211: ACTIONS CONCERNING REGULATIONS THAT
       SIGNIFICANTLY AFFECT ENERGY SUPPLY, DISTRIBUTION, OR USE
D3-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

Executive Order 13211, ("Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution,
or Use" (66 FR 28355, May 22, 2001)) requires EPA to prepare a Statement of Energy Effects when undertaking
regulatory actions identified as "significant energy actions." For the purposes of Executive Order 13211,
"significant energy action" means:

           "any action by an agency (normally published in the Federal Register) that promulgates or
           is expected to lead to the promulgation of a proposed rule or regulation, including notices of
           inquiry,  advance notices of proposed rulemaking, and notices of proposed rulemaking:
              (1) (i) that is a significant regulatory action under Executive Order 12866 or any
                  successor order, and
                  (ii) is likely to have a significant adverse effect on the supply, distribution, or use of
                  energy; or
              (2) that is designated by the Administrator of the Office of Information and Regulatory
                  Affairs (OIRA) as a significant energy action."

For those regulatory actions identified as "significant energy actions," a Statement of Energy Effects must include
a detailed statement relating to (1) any adverse effects on energy supply, distribution, or use (including a shortfall
in  supply, price increases, and increased use of foreign supplies) and (2) reasonable alternatives to the action with
adverse energy effects and the expected effects of such alternatives on energy supply, distribution, and use.

This rule is not a "significant energy action" as defined in Executive Order 13211 because it is not likely to have a
significant adverse effect on the supply, distribution, or use of energy.  The proposed rule does not contain any
compliance requirements that would:

    *•   reduce crude oil supply in excess of 10,000 barrels per day;
    *•   reduce fuel production in excess of 4,000 barrels per day;
    *•   reduce coal production in excess of 5 million tons per day;
    *•   reduce electricity production in excess of 1 billion kilowatt hours per day or in excess of 500 megawatts
        of installed capacity;
    *•   increase energy prices in excess of 10 percent;
    *•   increase the cost of energy distribution in excess of 10 percent;
    *•   significantly increase dependence on foreign supplies  of energy; or
    *•   have other similar adverse outcomes, particularly unintended ones.

Of the potential significant adverse effects on the supply, distribution, or use of energy (listed above) only a few
apply to this proposed rule. Regulation of Electric Generators, through increases in the cost of generating
electricity and shifts in the types of generators employed, might affect (1) the production of coal, (2) the
production of electricity, (3) the amount of installed capacity, (4) energy prices, and (5) the dependence on
foreign supplies  of energy.  Regulation of new offshore oil and gas facilities might affect (1) the production of oil
and gas, (2) energy prices, and (3) the dependence on foreign supplies of energy.  While facilities in the
Manufacturing industry segments generate electricity, their contribution to the overall supply of electricity is
insignificant (less than 0.02%); therefore, compliance with the 316(b) Phase III regulation by this industry
segment would not perceptibly affect the supply, distribution, or use of energy.

Potential energy effects associated with the regulation of existing Electric Generators and new offshore oil and
gas extraction facilities are described in the following two subsections.

D3-6.1  Existing Electric Generators

The three proposed options for Electric Generators have design intake flow (DIP) applicability thresholds for
national categorical requirements of 50 MGD or greater, 100 MGD or greater, and 200 MGD or greater. Since
Electric Generators with a DIP of 50 MGD or greater were covered by the final Phase II rule, no Phase III
                                                                                                     D3-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

Generator would be subject to the national requirements under the three proposed options; therefore there would
be no impacts on any measures of energy supply, distribution, or use under the proposed rule.

To assess potential energy effect of alternative evaluated options for Electric Generators, EPA used the results
from its electricity market model analysis (see the Appendix to Chapter B5: Economic Impact Analysis for
Electric Generators).  EPA compared the post-compliance scenario (after the implementation of Phase III
compliance requirements) with Base Case 2 (including Phase II compliance costs but excluding Phase III
compliance costs). This comparison allows EPA to identify the incremental market-level effects of Phase III
regulation, beyond the effects of Phase II regulation.  It should be noted that this analysis was only conducted for
Option 6, the most inclusive option with the highest regulatory costs and potential for energy effects.  Therefore,
the potential energy effects of all other options evaluated by EPA would be lower.

»»» Production of coal
EPA estimates that Option 6 would decrease the annual use of coal for electricity generation by 53.8 trillion Btu
(TBtu), or 0.25%. This reduction converts to 2.66 million tons of coal per year or 7,286 tons of coal per day.1
Assuming that a reduction in the use of coal for electricity generation results in a similar reduction in coal
production, EPA concludes that Option 6 would not have a significant impact on the national production of coal
as defined by the thresholds listed above.

»»» Production of electricity
EPA's electricity market analysis did not allow for an explicit consideration of the changes in the production of
electricity. However, based on the small effects on installed capacity and electricity prices,  EPA concludes that
Option 6 would not reduce electricity production in excess of 1 billion kilowatt hours per day.

»»» Installed capacity
None of the evaluated options contain requirements that would permanently reduce installed capacity, for
example through parasitic losses or auxiliary power requirements.  However,  the rule does contain requirements
that may lead to one-time temporary downtimes of up to nine weeks of steam electric generators subject to Phase
III regulation. EPA estimates that under Option 6 approximately four facilities, accounting  for 145 megawatts
(MW) of generating capacity, would experience such downtimes. However, EPA's analyses indicate that these
downtimes would not have a significant adverse effect on the supply, distribution, or use of energy (see the
Appendix to Chapter B5: Economic Impact Analysis for Electric Generators). In addition, EPA estimates that
Option 6 would lead to only 173 MW in incremental permanent capacity closures, well below the 500 MW
impact threshold.

»»» Energy prices
Option 6 would not significantly affect energy prices in either the long run or the short run.  EPA estimates that,
in the long run, energy prices would rise by less than 1% in all but one North American Electric Reliability
Council (NERC) regions. The Electric Reliability Council of Texas (ERCOT) is estimated to have the largest
increase in electricity prices with 1.1% in 2010 and 5.2% in 2013.  No other region would experience energy price
increases of more than 0.2% as a result of Phase III regulation.

»»» Dependence on foreign supplies of energy
EPA's electricity market analysis did not allow for an explicit consideration of effects on foreign imports of
energy. However, Electric Generators which are generally not subject to significant foreign competition. (Only
Canada and Mexico are connected to the U.S. electricity grid, and transmission losses are substantial when
electricity is transmitted over long distances.) In addition, the effects on installed capacity and electricity prices,
are estimated to be small. EPA therefore concludes that Option 6 would not significantly increase dependence on
foreign supplies of energy.
     This conversion assumes an average energy content of 10,115 Btu per pound of coal (U.S. DOE, 2000).
D3-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

D3-6.2 New Offshore Oil and Gas Extraction Facilities

This rule applies only to new offshore oil and gas extraction facilities and not existing ones. Hence the rule
would have no impact on existing production of oil and gas, energy prices, installed capacity, nor would it
significantly increase dependence on foreign supplies of energy. EPA's analysis identified no barriers to entry or
energy effects. EPA therefore concludes that the proposed rule would not significantly affect new offshore oil
and gas production, energy prices, or dependence on foreign supplies of energy.

Based on these analyses for potentially regulated existing and new facilities, EPA concludes that this proposed
rule would have minimal energy effects at a national and regional level. As a result, EPA did not prepare  a
Statement of Energy Effects.
D3-7  NATIONAL TECHNOLOGY TRANSFER AND ADVANCEMENT ACT OF 1995

Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995, Pub L. No. 104-
113, Sec. 12(d) directs EPA to use voluntary consensus standards in its regulatory activities unless doing so
would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are
developed or adopted by voluntary consensus standard bodies.  The NTTAA directs EPA to provide Congress,
through the Office of Management and Budget (OMB), explanations when the Agency decides not to use
available and applicable voluntary consensus standards.

This proposed rule does not involve such technical standards. Therefore, EPA is not considering the use of any
voluntary consensus standards.
D3-8  EXECUTIVE ORDER 12898: FEDERAL ACTIONS TO ADDRESS ENVIRONMENTAL JUSTICE
       IN MINORITY POPULATIONS AND LOW-INCOME POPULATIONS

Executive Order 12898 (59 FR 7629, February 11, 1994) requires that, to the greatest extent practicable and
permitted by law, each Federal agency must make achieving environmental justice part of its mission.  E.O.
12898 provides that each Federal agency must conduct its programs, policies, and activities that substantially
affect human health or the environment in a manner that ensures such programs, policies, and activities do not
have the effect of (1) excluding persons (including populations) from participation in, or (2) denying persons
(including populations) the benefits of, or (3) subjecting persons (including populations) to discrimination under
such programs, policies, and activities because of their race, color, or national origin.

Today's proposed rule requires that the location, design, construction, and capacity of cooling water intake
structures (CWIS) at Phase III facilities reflect the best technology available for minimizing adverse
environmental impact. For several reasons, EPA does not expect that this proposed rule would have an
exclusionary effect, deny persons the benefits of the participation in a program, or subject persons to
discrimination because of their race, color, or national origin. In fact, because EPA expects that this proposed
rule would help to preserve the health of aquatic ecosystems located in reasonable proximity to Phase III facilities,
it believes that all populations, including minority and low-income populations, would benefit from improved
environmental conditions as a result of this rule.
D3-9  EXECUTIVE ORDER 13158: MARINE PROTECTED AREAS

Executive Order 13158 (65 FR 34909, May 31, 2000) requires EPA to "expeditiously propose new science-based
regulations, as necessary, to ensure appropriate levels of protection for the marine environment." EPA may take
action to enhance or expand protection of existing marine protected areas and to establish or recommend, as
                                                                                                D3-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses              D3: Other Administrative Requirements

appropriate, new marine protected areas. The purpose of the Executive Order is to protect the significant natural
and cultural resources within the marine environment, which means "those areas of coastal and ocean waters, the
Great Lakes and their connecting waters, and submerged lands thereunder, over which the United States exercises
jurisdiction, consistent with international law."  EPA expects that the Proposed Section 316(b) Rule for Phase III
Facilities would advance the objective of Executive Order 13158.

Marine protected areas (MPAs) include designated areas with varying levels of protection, from fishery closure
areas, to aquatic National Parks, Marine Sanctuaries, and Wildlife Refuges (NOAA, 2002). The Departments of
Commerce and the Interior are developing an inventory of MPAs in the U.S. that are protected and managed
under Federal, State, Territorial, Tribal, or local laws. This list has not been completed, but it currently includes
32 Federal sites in the New England region, 31 in the Middle Atlantic region, 43 in the South Atlantic region, 45
in the Gulf of Mexico region, 12 in the Caribbean region, 15 in the Great Lakes region, and 46 in the U.S. West
Coast region. Examples of marine protected areas include the Great Bay National Wildlife Refuge in New
Hampshire, the Cape Cod Bay Northern Right Whale Critical Habitat in Massachusetts, the Narragansett Bay
National Estuarine Research Reserve in Rhode Island, Everglades National Park and the Tortugas Shrimp
Sanctuary in Florida, and the Point Reyes National Seashore in California.

Marine protected areas can help address problems related to the depletion of marine resources by prohibiting, or
severely curtailing, activities that are permitted or regulated by law outside of marine protected areas. Such
activities include oil exploration, dredging, dumping, fishing, certain types of vessel traffic, and the focus of
section 316(b) rulemaking, the impingement and entrainment of aquatic organisms by cooling water intake
structures.

Impingement and entrainment affects many kinds of aquatic organisms, including fish, shrimp, crabs, birds, sea
turtles, and marine mammals. Aquatic environments are harmed both directly and indirectly by impingement and
entrainment of these organisms. In addition to the harm that results from the direct removal of organisms by
impingement and entrainment, there are the indirect effects on aquatic food webs that result from the impingement
and entrainment of organisms that serve as prey for predator species. There are also cumulative impacts that
result from multiple intake structures operating in the same local area, or when multiple intakes affect individuals
within the same population over a broad geographic range.

Decreased numbers of aquatic organisms resulting from the direct and indirect effects of impingement and
entrainment can have a number of consequences for marine resources, including impairment of food webs,
disruption of nutrient cycling and energy transfer within aquatic ecosystems, loss of native species, and reduction
of biodiversity. By reducing the impingement and entrainment of aquatic organisms, this proposed rule would not
only help protect individual species but also the overall marine environment, thereby advancing the objective of
Executive Order 13158 to protect marine areas.
D3-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses             D3: Other Administrative Requirements

REFERENCES

Executive Office of the President. 2001.  Executive Order 13211. "Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use." 66 FR 28355. May 22, 2001.

Executive Office of the President. 2000a. Executive Order 13175.  "Consultation and Coordination with Indian
Tribal Governments." 65 FR 67249, November 6, 2000.

Executive Office of the President. 2000b. Executive Order 13158.  "Marine Protected Areas." 65 FR 34909,
May 31,2000.

Executive Office of the President. 1999.  Executive Order 13132. "Federalism." 64 FR 43255. August 10,
1999.

Executive Office of the President. 1997.  Executive Order 13045. "Protection of Children from Environmental
Health Risks and Safety Risks." 62 FR 19885, April 23, 1997.

Executive Office of the President. 1994.  Executive Order 12898. "Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations." 59 FR 7629, February 11, 1994.

Executive Office of the President. 1993.  Executive Order 12866. "Regulatory Planning and Review." 58 FR
51735. October 4, 1993.

National Oceanic and Atmospheric (NOAA) and U.S. Department of Commerce. 2002.  Marine Protected Areas
of the United States, http://mpa.gov/welcome.html. Accessed 2/22/02.

Paperwork Reduction Act (PRA).  44 U.S.C. 3501 et seq.

U.S. Department of Commerce (U.S. DOC), Bureau of the Census.  2000.  2000 Census  of Population and
Housing.

U.S. Department of Commerce (U.S. DOC), Bureau of the Census.  1998.  1998 Small Area Income and Poverty
Estimates.

U.S. Department of Energy (U.S. DOE), Energy Information Administration (EIA). 2000. Coal Industry Annual
2000 Data Tables, Table 106 Average Quality of Coal Received at Electric Utilities by Census Division and State,
1991, 1996-2000.  Table data from Federal Energy Regulatory Commission, FERC Form 423, Monthly Report of
Cost and Quality of Fuels for Electric Plants. Accessed 11/24/03.

U.S. Department of the Interior (U.S. DOI), Fish and Wildlife Service, and U.S. Department of Commerce,
Bureau of the Census.  1997. 1996 National Survey of Fishing, Hunting, and Wildlife-Associated Recreation.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Information Collection Request (ICR)for Cooling
Water Intake Structures Phase III Proposed Rule.  ICR Number 2169.01. October 2004.
                                                                                                D3-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartD: Additional Economic Analyses             D3: Other Administrative Requirements
                           THIS PAGE INTENTIONALLY LEFT BLANK
D3-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis        El: Summary of Social Costs

        Chapter El:  Summary  of Social Costs
INTRODUCTION                                  CHAPTER CONTENTS
                                                  El-l Costs of Compliance by Regulated Industry
                                                       Segments	El-l
                                                  El-2 State and Federal Administrative Costs	El-4
                                                  El-3 Total Social Cost	El-4
                                                  El-4 Limitations and Uncertainties  	El-12
                                                  Glossary	El-13
                                                  References 	El-14
                                                  Appendix to Chapter El	  E1A-1
This chapter presents EPA's estimates of the costs to
society associated with the options evaluated for the
proposed rule for Phase III facilities.  The social
costs of regulatory actions are the opportunity
costs to society of employing scarce resources to
reduce environmental damages. The social costs of
regulation include both monetary and non-monetary
outlays made by society. Monetary outlays include
the resource costs of compliance, government
administrative costs, and other adjustment costs, such as the cost of relocating displaced workers. Non-monetary
outlays, some of which can be assigned monetary values, include losses in consumers' and producers' surplus in
affected product markets, the adverse effects of involuntary unemployment, possible loss of time (e.g., delays in
investment decisions), and possible adverse impacts on the rate of innovation.

EPA's estimates of social costs for the evaluated section 316(b) Phase III options include three components:

    1.  direct costs of complying with the regulation within each regulated industry segment,
    2.  cost to State governments in administering the regulation, and
    3.  cost to the Federal government in administering the regulation.

This chapter presents the social cost analysis for the three proposed options for existing facilities: the "50 MGD
for All Waterbodies" option ("50 MGD All"), the "200 MGD for All Waterbodies" option ("200 MGD All"), and
the "100 MGD for Certain Waterbodies" Option ("100 MGD CWB"). These options differ with regard to (1)
their design intake flow (DIP) applicability thresholds: 50,  100, and 200 MGD, respectively; and (2) the type of
waterbodies to which they would apply: the options with the 50 and 200 MGD applicability thresholds would
apply to all waterbody types while the option with the 100  MGD applicability threshold would apply only to
facilities withdrawing cooling water from certain waterbody types (i.e., an ocean, estuary, tidal river/stream or one
of the Great Lakes). Facilities meeting these applicability criteria would be required to meet similar performance
standards to those required in the final 316(b) Phase II rule, including a 80-95% reduction in impingement
mortality and a 60-90% reduction in entrainment. Facilities not meeting these applicability criteria would
continue to be subject to permit requirements based on the  Director's Best Professional Judgment (BPJ). As a
result, the number of facilities that would be required to meet the national requirements would vary among the
three proposed options. Of the three options presented here, the 100 MGD for Certain Waterbodies Option would
apply national categorical requirements to the smallest number of facilities, with the 200 MGD for All
Waterbodies Option and 50 MGD for All Waterbodies Option applying to successively larger numbers of
facilities.

This chapter also presents social costs for new offshore oil  and gas extraction facilities (also abbreviated as "new
OOGE facilities"). The proposed requirements for this industry segment are based on a 2 MGD DIP applicability
threshold and would apply to an estimated 124 new offshore oil and gas extraction facilities.
El-l  COSTS OF COMPLIANCE BY REGULATED INDUSTRY SEGMENT

The compliance costs used to estimate total social costs differ in their consideration of taxes from those in Part B:
Economic Analysis for Phase III Existing Facilities, and Part C: Economic Analysis for Phase III New Offshore
Oil and Gas Extraction Facilities, which were calculated for the purpose of estimating the private costs and
                                                                                              El-l

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis         El: Summary of Social Costs

impacts of the evaluated options. For the impact analyses, compliance costs are measured according to their
effect on the financial performance of the regulated facilities and firms. The analyses therefore explicitly consider
the tax deducibility of compliance outlays.1  In the analysis of costs to society, however, these compliance costs
are considered on a pre-tax basis.  The costs to  society are the full value of the resources used, whether they are
paid for by the regulated facilities or by all taxpayers in the form of lost tax revenues.

EPA included no costs for facilities that were assessed as baseline closures or that are subject to permit
specifications based on best professional judgement (BPJ), instead of the proposed rule's national categorical
requirements. However, EPA's estimates do include compliance costs for facilities estimated to close because of
the rule.2  This approach may overstate the social costs of compliance, to the extent that the net economic loss to
society in facility closures is less than the estimated cost to society of compliance.3

To assess the cost to society of complying with Phase III regulation, EPA estimated the costs to facilities for the
labor, equipment, materials, and other economic resources needed to comply with each evaluated option. In this
analysis, EPA assumed that the market prices for labor, equipment, materials, and other compliance resources
represent the opportunity costs to society for use of those resources in regulatory compliance.

For the analysis of installation downtime in the Electric Generators and Manufacturers segment, EPA assumed
that the cost of society is equal to the increase in production cost for providing the electricity or other replacement
goods and services not provided by the facilities that incur downtime in reaching compliance with the 316(b)
Phase III regulation. For both Electric Generators and Manufacturers, this cost is approximated as the lost
revenue from installation downtime less the variable cost of producing the electricity or other goods and services
not produced due to the installation downtime.  Implicit in this assumption is that the variable production cost of
replacing the electricity or other lost goods and services is essentially the same  as the price received for the sale of
the electricity or other goods and services not produced by the facilities incurring the installation downtime.  For
electricity, this assumption is consistent with the electricity market concept that the variable production cost of the
last generating unit to be dispatched is approximately the same as the price received for the last unit of
production.  For the goods and services not produced by affected Manufacturers facilities, the assumption is
likewise consistent with a competitive market model of increasing marginal production cost, such that the
production cost of the "last" or highest cost goods and services produced and sold in any period is approximately
equal to the price received for those goods and  services in the market.  For Manufacturers -  which do not
necessarily produce and sell goods in as orderly markets as electric generators and where, as a result, the cost of
producing replacement goods and services may be less than selling  price - this  assumption may overstate the cost
to society of installation downtime. Absent specific knowledge  of the overall production  cost structure of the
affected industries, EPA adopted this conservative assumption for its analysis of the social cost of Phase III
regulation.

EPA estimates that the offshore oil and gas extraction industry segment would not incur cost from installation
downtime because only new  offshore oil and gas extraction facilities would be regulated under this proposed rule.
The potential disruption in ongoing business operation estimated for existing Manufacturers and Electric
Generators is not relevant for new facilities.

Finally, EPA assumes in its social cost analysis that none of the  evaluated options would affect the aggregate
quantity of goods and services sold to consumers by producers in the affected industry segments. The resource
costs of compliance therefore manifest only as  a reduction in the total of producers' surplus and consumers'
    1 Because government facilities and cooperatives are not subject to income taxes, their costs are not adjusted for taxes.

    2 To the extent such impacts occur under any of the options analyzed.

    3 Including costs for regulatory closures yields an estimate of social costs assuming that all facilities, except those assessed as
baseline closures, would incur the costs of regulatory compliance and continue to operate post-regulation. Calculating costs as if all
facilities continue operating will overstate social costs  if the social cost of compliance is greater than the net economic loss to society from
facility closure. Whether this result will hold depends, in part, on the difference between social and private discount rates, and the
marginal cost to society to replace the lost production of goods and services in closing facilities.

El-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
surplus, with no change in the quantity of goods and services produced and consumed.  In the impact analyses,
specific assumptions are made about the distribution of this effect between producers and consumers (i.e., the
impact analyses of all analyzed section 316(b) Phase III industry segments - Manufacturers, Electric Generators,
and new offshore oil and gas extraction facilities - assume that all compliance costs are absorbed by complying
businesses with no increase in prices to consumers). However, for the social cost analysis, the distribution of this
effect between producers and consumers is irrelevant.  Given the very small impact of the options on total costs
within the industry segments, EPA believes the assumption of no effect on total quantity of goods and services
produced and consumed is reasonable.

Table El-1 below summarizes total direct facility costs for the proposed rule new offshore oil and gas extraction
facilities combined with the three proposed options for existing facilities.  As described in Chapter Bl: Summary
of Cost Categories and Key Analysis Elements for Existing Facilities and Chapter Cl: Summary of Cost
Categories and Key Analysis Elements for New Offshore Oil and Gas Extraction Facilities, costs were first tallied
on an as-incurred, year-by-year basis over the total time period of analysis, considering the latest year in which
any affected facility is assumed to reach compliance (2014 for existing facilities, 2026 for new offshore oil and
gas extraction facilities) and for a period of 30 years in which facilities are assumed to continue compliance, for
the purposes of the social cost analysis. Thus, for the social cost analysis, the analysis period extends to 2055 for
new facilities and to 2043 for existing facilities.4 These profiles of costs by year were then discounted to the
assumed year when this proposed rule would take effect, beginning of year 2007, at two values of the discount
rate, 3% and 7%. These discount rate values reflect guidance from the Office of Management and Budget (OMB)
regulatory analysis guidance document, Circular A-4 (OMB, 2003). After calculating the present value of these
cost streams, EPA calculated their constant annual equivalent value (annualized value) using the annualization
formula presented in Chapter Bl, again using the two values of the discount rate, 3% and 7%.
            Table El-1: Summary of Annualized Direct Costs by Regulated Industry Segments
                                           (in millions, 2003 $)


Existing Manufacturing Facilities
Primary Manufacturing Industries
Other Industries
Existing Electric Generators
Total Existing Facilities3
New Oil & Gas Facilities
Total Direct Facility Costs"
50 MGD All (Existing) /
2 MGD All (New)
3% 7%

$42.7 $45.1
$4.1 $4.4
$0.0 $0.0
$46.8 $49.5
$3.2 $2.7
$50.0 $52.2
200 MGD All (Existing) /
2 MGD All (New)
3% 7%

$21.7 $23.1
$1.0 $0.9
$0.0 $0.0
$22.6 $24.0
$3.2 $2.7
$25.9 $26.7
100 MGD CWB (Existing) /
2 MGD All (New)
3% 7%

$16.7
$0.7
$0.0
$17.5
$3.2
$20.7

$17.4
$0.7
$0.0
$18.1
$2.7
$20.8
  a   Individual numbers may not add up to totals due to independent rounding.

  Source:  U.S. EPA Analysis, 2004.
    4 Tables El-4 through El-6 below present the time profiles of regulatory costs associated with each of the proposed options for
existing facilities, combined with the proposed option for new offshore oil and gas extraction facilities.
                                                                                                      El-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
El-2   STATE AND FEDERAL ADMINISTRATIVE COSTS

Social costs also include costs to State and Federal governments of administering the permitting and compliance
monitoring activities under the proposed regulation.  State and Federal permitting authorities incur costs to
administer the rule, including labor costs to write permits and to conduct compliance monitoring and enforcement
activities. Chapter D2: UMRA Analysis presents more information on State and Federal implementation costs.

EPA's estimate of State and Federal government cost for administering the proposed rule is comparatively minor
in relation to the estimated direct cost of regulatory compliance. At a 3% discount rate, EPA estimates
administrative costs of $0.98 million (50 MOD All Option), $0.54 million (200 MOD All Option), and $0.57
million (100 MOD CWB Option). At a 7% discount rate, these costs amount to $0.89 million (50 MOD All
Option), $0.45 million (200 MOD All Option), and $0.48 million (100 MOD CWB Option).
               Table El-2: Summary of Annualized Government Costs (in millions, 2003 $)

Existing Facilities:
State Admin. Costs
Federal Admin. Costs
Total Existing Facilities Admin. Costa
New OOGE Facilities:
State Admin. Costs
Federal Admin. Costs
Total New OOGE Facilities Admin. Cost
Total Gov. Admin. Costs3
50 MGD All (Existing) /
2 MGD All (New)
3% 7%

$0.55 $0.55
$0.01 $0.01
$0.56 $0.56

n/a n/a
$0.42 $0.32
$0.42 $0.32
$0.98 $0.89
200 MGD All (Existing) /
2 MGD All (New)
3%

$0.12
<$0.01
$0.12

n/a
$0.42
$0.42
$0.54
7%

$0.12
<$0.01
$0.13

n/a
$0.32
$0.32
$0.45
100 MGD CWB (Existing) /
2 MGD All (New)
3% 7%

$0.15
<$0.01 <
$0.15

n/a
$0.42
$0.42
$0.57

$0.16
$0.01
$0.16

n/a
$0.32
$0.32
$0.48
 a   Individual numbers may not add up to totals due to independent rounding.

 Source:  U.S. EPA Analysis, 2004.
El-3   TOTAL SOCIAL COST

Table El-3 combines the information presented above by industry segment and major cost category - direct
facility costs and administrative costs - and reports the total social costs of the three proposal options, discounted
at a 3% and 7% rate.  At a 3% discount rate the estimated total annualized social costs are $51.0 million for the 50
MGD All Option, $26.4 million forthe 200 MGD All Option, and $21.3 million forthe 100 MGD CWB Option.
At a 7% discount rate the estimated total annualized social costs are $53.1 million for the 50  MGD All Option,
$27.2 million forthe 200 MGD All Option, and $21.3 million forthe 100 MGD CWB Option (all values in
2003$).

As shown in Table El-3, existing facilities account for the substantial majority of total social cost under all three
proposal options.  Since no Electric Generators would be subject to the national requirements under any of the
three proposed options, Manufacturers account for all costs in the existing facilities segment. At a 3% discount
rate, annualized pre-tax costs per facility in the Manufacturers segment amount to $349,000 for the 50 MGD All
option, $920,000 forthe 200 MGD All option, and $929,000 forthe 100 MGD CWB option. At a 7% discount
El-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
rate, annualized pre-tax costs in the Manufacturers segment amount to $369,000 for the 50 MGD All option,
$974,000 for the 200 MGD All option, and $962,000 for the 100 MGD CWB option. Because the 200 MGD
option and the 100 MGD option  apply national categorical requirements to a smaller number of facilities than the
50 MGD option, they result in a  lower total national cost but a higher cost per regulated facility.  Facilities that
are subject to the national requirements of the 200 MGD option and the 100 MGD option incur the same
compliance costs as under the 50 MGD option; however, the average costs per regulated facility are higher under
the 200 MGD and  100 MGD options because only the higher flow, and therefore higher cost, facilities incur costs
under these options.  For facilities in the new offshore oil and gas extraction industry segment, per facility costs
under the proposed rule are approximately $30,000 at a 3% discount rate and $24,000 at a 7% discount rate.
                   Table El-3: Summary of Annualized Social Costs (in millions, 2003 $)


Existing Facilities:
Total Direct Facility Costs
Total Government Administrative Costs
Total Existing Facilities Social Cost
New OOGE Facilities:
Total Direct Facility Costs
Total Government Administrative Costs
Total New OOGE Facilities Social Cost
Total Social Cost
50 MGD All
(Existing) / 2 MGD
All (New)
3% 7%

$46.8 $49.5
$0.6 $0.6
$47.3 $50.1

$3.2 $2.7
$0.4 $0.3
$3.7 $3.0
$51.0 $53.1
200 MGD
All
(Existing) / 2 MGD
All (New)
3%

$22.6
$0.1
$22.8

$3.2
$0.4
$3.7
$26.4
7%

$24.0
$0.1
$24.1

$2.7
$0.3
$3.0
$27.2
100 MGD CWB
(Existing) / 2 MGD
All (New)
3%

$17.5
$0.2
$17.6

$3.2
$0.4
$3.7
$21.3
7%

$18.1
$0.2
$18.3

$2.7
$0.3
$3.0
$21.3
 a   Individual numbers may not add up to totals due to independent rounding.

 Source:  U.S. EPA Analysis, 2004.
Tables El-4 through El-6, starting on the following page, provide additional detail on the compliance cost
calculations.  The tables compile, for each of the three proposed options for existing facilities and the proposed
option for new offshore oil and gas extraction facilities, the time profiles of costs incurred by the regulated
industry segments, administrative costs, and total costs.  The tables also report the calculated present and
annualized values of costs at 3% and 7% discount rates.  Time profiles for other options evaluated for existing
facilities are presented in the appendix to this chapter.
                                                                                                      El-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
  Table El-4: Time Profile of Compliance Costs for the 50 MGD for All Waterbodies Option for Existing
             Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
Existing Facilities
Regulated Industry
Segments
Man.
$3.2
$10.2
$15.4
$171.6
$178.4
$73.4
$109.9
$21.9
$22.2
$17.8
$18.2
$14.9
$18.8
$44.1
$81.0
$28.8
$57.9
$21.9
$22.2
$17.8
$18.2
$14.9
$18.8
$44.1
$81.0
$28.8
$57.9
$21.9
$22.2
$17.8
Generators
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Administrative
Costs
$0.2
$0.0
$0.0
$1.1
$2.1
$1.1
$0.9
$0.3
$0.4
$0.7
$0.4
$0.4
$0.2
$0.4
$0.7
$0.4
$0.4
$0.2
$0.4
$0.7
$0.4
$0.4
$0.2
$0.4
$0.7
$0.4
$0.4
$0.2
$0.4
$0.7
Total
$3.3
$10.2
$15.4
$172.6
$180.5
$74.4
$110.8
$22.2
$22.7
$18.6
$18.6
$15.3
$19.0
$44.5
$81.7
$29.2
$58.2
$22.1
$22.7
$18.6
$18.6
$15.3
$19.0
$44.5
$81.7
$29.2
$58.2
$22.1
$22.7
$18.6
New
O&G
Facilities
$1.9
$1.7
$1.8
$1.1
$1.6
$1.9
$2.2
$2.1
$1.8
$1.6
$4.1
$2.7
$3.7
$2.8
$2.8
$4.8
$2.9
$4.4
$3.0
$2.9
$4.9
$2.8
$4.1
$2.8
$2.8
$5.1
$2.8
$4.6
$2.8
$2.8
OOGE Facilities
Administrative
Costs
$0.0
$0.0
$0.0
$0.0
$0.0
$0.5
$0.1
$0.7
$0.3
$0.3
$0.5
$0.3
$0.5
$0.3
$0.4
$0.7
$0.4
$0.7
$0.4
$0.4
$0.7
$0.3
$0.7
$0.3
$0.3
$0.7
$0.3
$0.7
$0.3
$0.3

Total
$1.9
$1.7
$1.8
$1.1
$1.6
$2.4
$2.4
$2.7
$2.0
$1.9
$4.6
$3.0
$4.2
$3.2
$3.2
$5.5
$3.3
$5.1
$3.4
$3.3
$5.6
$3.1
$4.7
$3.1
$3.1
$5.8
$3.1
$5.2
$3.1
$3.1
Total
$5.2
$12.0
$17.2
$173.7
$182.2
$76.8
$113.2
$24.9
$24.7
$20.5
$23.2
$18.2
$23.2
$47.7
$85.0
$34.7
$61.5
$27.2
$26.1
$21.9
$24.2
$18.4
$23.7
$47.7
$84.9
$35.0
$61.4
$27.3
$25.8
$21.7
El-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
  Table El-4: Time Profile of Compliance Costs for the 50 MGD for All Waterbodies Option for Existing
             Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Existing Facilities
Regulated Industry
Segments
Man. Generators
$18.2 $0.0
$14.9 $0.0
$14.2 $0.0
$12.0 $0.0
$6.2 $0.0
$4.1 $0.0
$0.5 $0.0












$944.6 $0.0
$46.8 $0.0
$657.5 $0.0
$49.5 $0.0
Administrative _ , ,
_ , Total
Costs
$0.4 $18.6
$0.4 $15.3
$0.2 $14.4
$0.1 $12.1
$0.1 $6.3
$0.0 $4.1
$0.0 $0.5












$11.2 $955.8
$0.6 $47.3
$7.5 $665.0
$0.6 $50.1
New
O&G
Facilities
$3.9
$1.8
$3.0
$1.7
$1.7
$3.6
$1.6
$2.4
$1.5
$1.5
$2.1
$0.5
$1.0
$0.3
$0.2
$1.5
$0.1
$0.6
$0.0
$65.4
$3.2
$36.0
$2.7
OOGE Facilities
Administrative
Costs
$0.7
$0.3
$0.6
$0.3
$0.2
$0.5
$0.2
$0.4
$0.2
$0.2
$0.3
$0.1
$0.2
$0.1
$0.1
$0.1
$0.0
$0.1
$0.0
$8.5
$0.4
$4.3
$0.3

Total
$4.6
$2.1
$3.6
$2.0
$1.9
$4.1
$1.8
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$74.0
$3.7
$40.3
$3.0
Total
$23.2
$17.4
$18.0
$14.1
$8.2
$8.3
$2.4
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$1,029.8
$51.0
$705.3
$53.1
 Source:  U.S. EPA Analysis, 2004.
                                                                                                      El-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
  Table El-5: Time Profile of Compliance Costs for the 200 MGD for All Waterbodies Option for Existing
             Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
Existing Facilities
Regulated Industry
Segments
Man. Generators
$0.0
$1.4
$2.1
$129.1
$83.4
$12.1
$45.4
$7.4
$8.5
$7.4
$8.9
$7.4
$7.2
$12.7
$39.8
$14.6
$45.7
$7.3
$8.5
$7.4
$8.9
$7.4
$7.2
$12.7
$39.8
$14.6
$45.7
$7.3
$8.5
$7.4
$8.9
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Administrative
Costs
$0.2
$0.0
$0.0
$0.0
$0.5
$0.1
$0.4
$0.1
$0.1
$0.2
$0.1
$0.1
$0.1
$0.0
$0.2
$0.1
$0.1
$0.1
$0.0
$0.2
$0.1
$0.1
$0.1
$0.0
$0.2
$0.1
$0.1
$0.1
$0.0
$0.2
$0.1
Total
$0.2
$1.4
$2.1
$129.1
$83.8
$12.3
$45.8
$7.5
$8.5
$7.5
$9.0
$7.5
$7.3
$12.7
$40.0
$14.6
$45.8
$7.4
$8.5
$7.5
$9.0
$7.5
$7.3
$12.7
$40.0
$14.6
$45.8
$7.4
$8.5
$7.5
$9.0
New
O&G
Facilities
$1.9
$1.7
$1.8
$1.1
$1.6
$1.9
$2.2
$2.1
$1.8
$1.6
$4.1
$2.7
$3.7
$2.8
$2.8
$4.8
$2.9
$4.4
$3.0
$2.9
$4.9
$2.8
$4.1
$2.8
$2.8
$5.1
$2.8
$4.6
$2.8
$2.8
$3.9
OOGE Facilities
Administrative
Costs
$0.0
$0.0
$0.0
$0.0
$0.0
$0.5
$0.1
$0.7
$0.3
$0.3
$0.5
$0.3
$0.5
$0.3
$0.4
$0.7
$0.4
$0.7
$0.4
$0.4
$0.7
$0.3
$0.7
$0.3
$0.3
$0.7
$0.3
$0.7
$0.3
$0.3
$0.7

Total
$1.9
$1.7
$1.8
$1.1
$1.6
$2.4
$2.4
$2.7
$2.0
$1.9
$4.6
$3.0
$4.2
$3.2
$3.2
$5.5
$3.3
$5.1
$3.4
$3.3
$5.6
$3.1
$4.7
$3.1
$3.1
$5.8
$3.1
$5.2
$3.1
$3.1
$4.6
Total
$2.1
$3.1
$3.9
$130.2
$85.4
$14.6
$48.1
$10.2
$10.6
$9.5
$13.5
$10.5
$11.5
$15.9
$43.2
$20.1
$49.1
$12.5
$11.9
$10.9
$14.6
$10.6
$12.0
$15.9
$43.1
$20.4
$48.9
$12.7
$11.6
$10.7
$13.6
El-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
  Table El-5: Time Profile of Compliance Costs for the 200 MGD for All Waterbodies Option for Existing
             Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Existing Facilities
Regulated Industry
Segments
Man. Generators
$7.4 $0.0
$7.0 $0.0
$6.7 $0.0
$3.9 $0.0
$3.0 $0.0
$0.4 $0.0












$457.2 $0.0
$22.6 $0.0
$318.7 $0.0
$24.0 $0.0
Administrative _ , ,
r, i Total
Costs
$0.1 $7.5
$0.1 $7.1
$0.0 $6.8
$0.0 $3.9
$0.0 $3.1
$0.0 $0.4












$2.5 $459.7
$0.1 $22.8
$1.7 $320.3
$0.1 $24.1
New
O&G
Facilities
$1.8
$3.0
$1.7
$1.7
$3.6
$1.6
$2.4
$1.5
$1.5
$2.1
$0.5
$1.0
$0.3
$0.2
$1.5
$0.1
$0.6
$0.0
$65.4
$3.2
$36.0
$2.7
OOGE Facilities
Administrative
Costs
$0.3
$0.6
$0.3
$0.2
$0.5
$0.2
$0.4
$0.2
$0.2
$0.3
$0.1
$0.2
$0.1
$0.1
$0.1
$0.0
$0.1
$0.0
$8.5
$0.4
$4.3
$0.3

Total
$2.1
$3.6
$2.0
$1.9
$4.1
$1.8
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$74.0
$3.7
$40.3
$3.0
Total
$9.6
$10.6
$8.8
$5.9
$7.2
$2.2
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$533.6
$26.4
$360.6
$27.2
 Source:  U.S. EPA Analysis, 2004.
                                                                                                      El-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
    Table El-6: Time Profile of Compliance Costs for the 100 MGD for Certain Waterbodies Option for
         Existing Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
Existing Facilities
Regulated Industry
Segments
Man. Generators
$0.4
$3.8
$3.9
$8.8
$138.9
$11.4
$34.9
$5.3
$8.2
$5.2
$6.5
$5.2
$5.2
$8.2
$41.1
$12.2
$35.3
$5.3
$8.2
$5.2
$6.5
$5.2
$5.2
$8.2
$41.1
$12.2
$35.3
$5.3
$8.2
$5.2
$6.5
$5.2
$4.8
$4.7
$2.2
$1.3
$0.4
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
$0.0
Administrative
Costs
$0.2
$0.0
$0.0
$0.2
$0.8
$0.1
$0.4
$0.0
$0.1
$0.3
$0.1
$0.1
$0.0
$0.1
$0.3
$0.1
$0.1
$0.0
$0.1
$0.3
$0.1
$0.1
$0.0
$0.1
$0.3
$0.1
$0.1
$0.0
$0.1
$0.3
$0.1
$0.1
$0.0
$0.0
$0.0
$0.0
$0.0
Total
$0.6
$3.8
$3.9
$9.0
$139.7
$11.5
$35.3
$5.4
$8.3
$5.4
$6.6
$5.3
$5.2
$8.3
$41.4
$12.2
$35.4
$5.4
$8.3
$5.4
$6.6
$5.3
$5.2
$8.3
$41.4
$12.2
$35.4
$5.4
$8.3
$5.4
$6.6
$5.3
$4.8
$4.7
$2.2
$1.3
$0.4
New
O&G
Facilities
$1.9
$1.7
$1.8
$1.1
$1.6
$1.9
$2.2
$2.1
$1.8
$1.6
$4.1
$2.7
$3.7
$2.8
$2.8
$4.8
$2.9
$4.4
$3.0
$2.9
$4.9
$2.8
$4.1
$2.8
$2.8
$5.1
$2.8
$4.6
$2.8
$2.8
$3.9
$1.8
$3.0
$1.7
$1.7
$3.6
$1.6
OOGE Facilities
Administrative
Costs
$0.0
$0.0
$0.0
$0.0
$0.0
$0.5
$0.1
$0.7
$0.3
$0.3
$0.5
$0.3
$0.5
$0.3
$0.4
$0.7
$0.4
$0.7
$0.4
$0.4
$0.7
$0.3
$0.7
$0.3
$0.3
$0.7
$0.3
$0.7
$0.3
$0.3
$0.7
$0.3
$0.6
$0.3
$0.2
$0.5
$0.2

Total
$1.9
$1.7
$1.8
$1.1
$1.6
$2.4
$2.4
$2.7
$2.0
$1.9
$4.6
$3.0
$4.2
$3.2
$3.2
$5.5
$3.3
$5.1
$3.4
$3.3
$5.6
$3.1
$4.7
$3.1
$3.1
$5.8
$3.1
$5.2
$3.1
$3.1
$4.6
$2.1
$3.6
$2.0
$1.9
$4.1
$1.8
Total
$2.5
$5.6
$5.7
$10.1
$141.4
$13.9
$37.7
$8.1
$10.4
$7.4
$11.2
$8.3
$9.5
$11.5
$44.6
$17.7
$38.7
$10.5
$11.7
$8.8
$12.2
$8.4
$10.0
$11.4
$44.5
$18.0
$38.6
$10.6
$11.4
$8.6
$11.2
$7.4
$8.4
$6.7
$4.1
$5.4
$2.2
El -10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
El: Summary of Social Costs
    Table El-6: Time Profile of Compliance Costs for the 100 MGD for Certain Waterbodies Option for
         Existing Facilities and the Proposed Option for New OOGE Facilities (in millions; 2003$)
Year
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Existing Facilities
Regulated Industry
Segments
Man. Generators












$352.8 $0.0
$17.5 $0.0
$240.4 $0.0
$18.1 $0.0
Administrative _ , ,
r, i Total
Costs












$3.1 $355.9
$0.2 $17.6
$2.1 $242.5
$0.2 $18.3
New
O&G
Facilities
$2.4
$1.5
$1.5
$2.1
$0.5
$1.0
$0.3
$0.2
$1.5
$0.1
$0.6
$0.0
$65.4
$3.2
$36.0
$2.7
OOGE Facilities
Administrative
Costs
$0.4
$0.2
$0.2
$0.3
$0.1
$0.2
$0.1
$0.1
$0.1
$0.0
$0.1
$0.0
$8.5
$0.4
$4.3
$0.3

Total
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$74.0
$3.7
$40.3
$3.0
Total
$2.8
$1.7
$1.6
$2.4
$0.6
$1.3
$0.4
$0.3
$1.6
$0.2
$0.7
$0.1
$429.9
$21.3
$282.8
$21.3
 Source:  U.S. EPA Analysis, 2004.
                                                                                                      El-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis        El: Summary of Social Costs

E1 -4  LIMITATIONS AND UNCERTAINTIES

EPA did not include in its estimate of social costs the cost associated with unemployment that may result from
facility closures. Potential unemployment-related costs would include the cost of administering unemployment
programs for workers who are projected to lose employment (but not the cost of unemployment benefits, which
are a transfer payment within society); and an estimate of the amount that workers would be willing to pay to
avoid involuntary unemployment.  However, from its facility impact analysis, EPA estimates that no facilities
would close as a result of the proposed rule. EPA also did not recognize any possible savings in unemployment-
related costs from jobs created by the rule as a negative cost (benefit) of the regulation. Accordingly, EPA
estimates a zero cost of unemployment for the proposed rule.

Another key uncertainty factor in the analysis of costs to society is EPA's estimate of the cost of installation
downtime in Manufacturers facilities. As described above, EPA adopted the conservative assumption that the
production cost for replacing the goods and services not provided by complying facilities due to installation
downtime would be approximately equal to the price received for those goods and services  in the market.  To the
extent that these replacement goods and services are produced at a cost less than selling price, this assumption
would lead to an overestimate of the cost to society of installation downtime.  The amount of potential
overestimation is not known.
El-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis         El: Summary of Social Costs

GLOSSARY

consumer surplus: The value that consumers derive from goods and services above the price they have to pay
to obtain the goods and services.

opportunity cost: The lost value of alternative uses of resources (capital, labor, and raw materials) used in
regulatory compliance.

producer surplus: The difference between what producers' earn on their output and the economic costs of
producing that output, including a normal return on capital.

social cost: The costs incurred by society as a whole as a result of the proposed rule. Social costs do not
include costs that are transfers among parties that do not represent a new cost overall.
                                                                                                  El-13

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis         El: Summary of Social Costs

REFERENCES

Office of Management and Budget (OMB). 2003.  Circular A-4, Regulatory Analysis.  September 17, 2003.
Available at http://www.whitehouse.gov/omb/circulars/a004/a-4.pdf
El-14

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                              Appendix to Chapter El
                      Appendix to  Chapter El
INTRODUCTION
                                                APPENDIX CONTENTS
                                                El A-l Costs of Compliance by Regulated Industry
                                                      Segment	  E1A-1
                                                E1A-2 State and Federal Administrative Costs ....  E1A-2
                                                E1A-3 Total Social Cost	  E1A-2
This appendix presents the social cost results for five
other options evaluated for potential Phase III
existing facilities. For all options, facility counts and
other results only include those potential Phase III
existing facilities that are (1) non-baseline closures
and (2) subject to national categorical requirements under the option.  See Chapter B3: Economic Impact Analysis
for Manufacturers and Chapter B5: Summary of Electric Generator Costs for more information on baseline
closures and counts of facilities subject to national categorical requirements under each option. See the main
body of this chapter for a description of data sources and methodologies used in these analyses.
E1A-1    COSTS OF COMPLIANCE BY REGULATED INDUSTRY SEGMENT

Table El A-l below summarizes total direct facility costs for the five other options evaluated for existing
facilities, at a 3% and a 7% discount rate. For a description of this analysis, see section El-1 above.
          Table El A-l: Summary of Annualized Direct Costs by Regulated Industry Segments
                               Existing Facilities (in millions, 2003$)

Option 3
Option 4
Option 2
Option 1
Option 6
3% Discount Rate
 Manufacturers

    Primary Manufacturing
    Industries
                                  $58.2
$62.1
$66.2
8.3
$85.9
Other Industries
Electric Generators
Total Direct Facility Costs"
$4.4
$1.5
$64.1
$4.3
$0.7
$67.1
$4.4
$1.9
$72.6
$4.4
$2.2
$75.0
$5.2
$2.9
$94.0
7% Discount Rate
Manufacturers
Primary Manufacturing
Industries
Other Industries
Electric Generators
Total Direct Facility Costs"

$62.5
$4.7
$1.5
$68.7
a Individual numbers may not add up to totals due to
Source: U.S. EPA Analysis, 2004.

$67.8
$4.6
$0.7
$73.0
independent rounding.


$71.7
$4.7
$1.8
$78.3



$73.8
$4.7
$2.1
$80.7



$92.5
$5.5
$2.8
$100.8


                                                                                          E1A-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
E1A-2    STATE AND FEDERAL ADMINISTRATIVE COSTS

Table E1A-2 presents annualized costs to State and Federal governments of administering the permitting and
compliance monitoring activities for the five other options evaluated for existing facilities, at a 3% and a 7%
discount rate. For a description of this analysis, see section El-2 above.
Table E1A-2: Summary of Annualized Government Costs for Existing Facilities (in millions, 2003$)

Option 3
Option 4
Option 2
Option 1
Option 6
3% Discount Rate
State Admin. Costs
Federal Admin. Costs
Total Gov. Admin. Costs3
$0.91
$0.02
$0.92
$0.81
$0.01
$0.83
$1.05
$0.02
$1.07
$1.08
$0.02
$1.10
$1.66
$0.03
$1.69
7% Discount Rale
State Admin. Costs
Federal Admin. Costs
Total Gov. Admin. Costs3
$0.90
$0.02
$0.92
a Individual numbers may not add up to totals due to
Source: U.S. EPA Analysis, 2004.
$0.81
$0.02
$0.83
independent rounding.
$1.05
$0.02
$1.07

$1.08
$0.02
$1.10

$1.65
$0.04
$1.69

E1A-3    TOTAL SOCIAL COST

Table E1A-3 presents the total social costs of the five other options evaluated for existing facilities, including
direct facility costs and government administrative costs, at a 3% and a 7% discount rate. Tables E1A-4 through
E1A-8 present the time profiles for the five other options.  For a description of these analyses, see section El-3
above.
Table E1A-3: Summary of Annualized Social Costs for Existing Facilities (in millions,

Option 3 Option 4
Option 2
Option 1
2003$)
Option 6
3% Discount Rate
Total Direct Facility Costs
Total Government Administrative Costs
Total Social Cost3
$64.1 $67.1
$0.9 $0.8
$65.0 $67.9
$72.6
$1.1
$73.7
$75.0
$1.1
$76.1
$94.0
$1.7
$95.7
7% Discount Rate
Total Direct Facility Costs
Total Government Administrative Costs
Total Social Cost3
$68.7 $73.0
$0.9 $0.8
$69.6 $73.9
$78.3
$1.1
$79.3
$80.7
$1.1
$81.8
$100.8
$1.7
$102.5
a Individual numbers may not add up to totals due to independent rounding.
Source: U.S. EPA Analysis, 2004.
E1A-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
    Table E1A-4: Time Profile of Compliance Costs for Existing Facilities - Option 3 (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Costs of Compliance by Regulated Industry
Segments
Manufacturers
$3.5
$14.0
$23.4
$184.6
$190.4
$277.3
$116.4
$28.1
$28.9
$26.7
$24.3
$18.6
$23.2
$52.9
$91.8
$36.8
$64.4
$28.0
$28.9
$26.7
$24.3
$18.6
$23.2
$52.9
$91.8
$36.8
$64.4
$28.0
$28.9
$26.7
$24.3
$18.6
$17.3
$14.6
$8.3
$5.1
$0.8
$1,263.6
$62.6
$892.1
$67.2
Generators
$0.2
$0.9
$1.4
$1.8
$3.0
$2.0
$1.0
$2.2
$1.0
$1.4
$0.7
$1.1
$1.4
$1.5
$2.8
$1.7
$1.1
$2.2
$1.0
$1.4
$0.7
$1.1
$1.4
$1.5
$2.8
$1.7
$1.1
$2.2
$1.0
$1.4
$0.7
$1.1
$0.6
$0.4
$0.3
$0.1
$0.1
$30.9
$1.5
$19.5
$1.5
Administrative Costs
$0.2
$0.0
$0.0
$1.6
$2.7
$2.3
$1.6
$0.8
$0.7
$1.0
$0.9
$0.7
$0.4
$0.7
$1.0
$0.9
$0.7
$0.4
$0.7
$1.0
$0.9
$0.7
$0.4
$0.7
$1.0
$0.9
$0.7
$0.4
$0.7
$1.0
$0.9
$0.7
$0.4
$0.2
$0.1
$0.1
$0.0
$18.7
$0.9
$12.2
$0.9
Total Cost
$3.9
$14.9
$24.8
$188.0
$196.1
$281.5
$119.0
$31.0
$30.6
$29.1
$25.9
$20.4
$25.0
$55.1
$95.6
$39.4
$66.1
$30.6
$30.6
$29.1
$25.9
$20.4
$25.0
$55.1
$95.6
$39.4
$66.1
$30.6
$30.6
$29.1
$25.9
$20.4
$18.3
$15.3
$8.8
$5.3
$1.0
$1,313.2
$65.0
$923.8
$69.6
 Source:  U.S. EPA Analysis, 2004.
                                                                                                        E1A-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
    Table E1A-5: Time Profile of Compliance Costs for Existing Facilities - Option 4 (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Costs of Compliance by Regulated Industry
Segments
Manufacturers
$3.2
$13.6
$22.4
$180.9
$291.4
$282.0
$115.6
$25.1
$28.8
$25.0
$23.7
$19.5
$22.0
$50.6
$89.8
$39.7
$64.0
$25.1
$28.8
$25.0
$23.7
$19.5
$22.0
$50.6
$89.8
$39.7
$64.0
$25.1
$28.8
$25.0
$23.7
$19.5
$17.4
$15.2
$8.4
$5.1
$0.8
$1,340.4
$66.4
$960.9
$72.4
Generators
$0.0
$0.3
$0.6
$0.6
$2.0
$0.5
$0.5
$1.3
$0.6
$0.7
$0.3
$0.6
$0.3
$0.6
$1.0
$0.3
$0.6
$1.2
$0.6
$0.7
$0.3
$0.6
$0.3
$0.6
$1.0
$0.3
$0.6
$1.2
$0.6
$0.7
$0.3
$0.6
$0.3
$0.3
$0.2
$0.1
$0.1
$14.1
$0.7
$8.9
$0.7
Administrative Costs
$0.2
$0.0
$0.0
$1.1
$3.0
$2.1
$1.5
$0.6
$0.5
$1.1
$0.8
$0.5
$0.3
$0.5
$1.1
$0.8
$0.5
$0.3
$0.5
$1.1
$0.8
$0.5
$0.3
$0.5
$1.1
$0.8
$0.5
$0.3
$0.5
$1.1
$0.8
$0.5
$0.3
$0.2
$0.1
$0.1
$0.0
$16.7
$0.8
$11.0
$0.8
Total Cost
$3.3
$13.9
$23.0
$182.6
$296.5
$284.6
$117.7
$27.0
$29.9
$26.8
$24.8
$20.7
$22.6
$51.8
$91.9
$40.8
$65.2
$26.6
$29.9
$26.8
$24.8
$20.7
$22.6
$51.8
$91.9
$40.8
$65.2
$26.6
$29.9
$26.8
$24.8
$20.7
$18.0
$15.7
$8.7
$5.2
$0.9
$1,371.2
$67.9
$980.8
$73.9
 Source:  U.S. EPA Analysis, 2004.
E1A-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
    Table E1A-6: Time Profile of Compliance Costs for Existing Facilities - Option 2 (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Costs of Compliance by Regulated
Segments
Industry
Manufacturers Generators
$3.5
$15.0
$25.6
$187.5
$298.4
$286.1
$120.9
$30.2
$31.7
$29.5
$26.9
$22.1
$25.3
$55.6
$96.0
$43.6
$69.4
$30.1
$31.7
$29.5
$26.9
$22.1
$25.3
$55.6
$96.0
$43.6
$69.4
$30.1
$31.7
$29.5
$26.9
$22.1
$19.4
$16.7
$9.7
$5.9
$1.1
$1,427.1
$70.7
$1,014.8
$76.4
$0.2
$1.0
$1.8
$2.2
$3.8
$2.2
$1.2
$3.3
$1.2
$1.9
$0.9
$1.4
$1.6
$1.8
$2.8
$1.9
$1.4
$3.3
$1.2
$1.9
$0.9
$1.4
$1.6
$1.8
$2.8
$1.9
$1.4
$3.3
$1.2
$1.9
$0.9
$1.4
$0.8
$0.6
$0.5
$0.2
$0.2
$38.6
$1.9
$24.3
$1.8
Administrative Costs
$0.2
$0.0
$0.0
$1.6
$3.3
$2.9
$2.0
$0.9
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.2
$0.2
$0.1
$0.0
$21.6
$1.1
$14.2
$1.1
Total Cost
$3.9
$16.0
$27.4
$191.4
$305.5
$291.2
$124.1
$34.4
$33.6
$32.7
$28.8
$24.2
$27.3
$58.2
$100.0
$46.6
$71.4
$33.9
$33.6
$32.7
$28.8
$24.2
$27.3
$58.2
$100.0
$46.6
$71.4
$33.9
$33.6
$32.7
$28.8
$24.2
$20.7
$17.6
$10.3
$6.2
$1.3
$1,487.3
$73.7
$1,053.3
$79.3
 Source:  U.S. EPA Analysis, 2004.
                                                                                                        E1A-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
    Table E1A-7: Time Profile of Compliance Costs for Existing Facilities - Option 1 (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Costs of Compliance by Regulated
Segments
Industry
Manufacturers Generators
$3.5
$15.1
$26.1
$201.3
$299.7
$290.1
$122.0
$31.3
$32.7
$31.1
$27.9
$23.1
$26.4
$58.6
$97.6
$47.7
$70.4
$31.2
$32.7
$31.1
$27.9
$23.1
$26.4
$58.6
$97.6
$47.7
$70.4
$31.2
$32.7
$31.1
$27.9
$23.1
$20.4
$17.6
$10.6
$5.9
$1.1
$1,469.5
$72.8
$1,043.3
$78.6
$0.2
$1.0
$1.8
$3.1
$4.0
$2.6
$1.4
$3.8
$1.4
$2.2
$1.1
$1.6
$1.8
$2.4
$3.0
$2.3
$1.6
$3.3
$1.4
$2.2
$1.1
$1.6
$1.8
$2.4
$3.0
$2.3
$1.6
$3.3
$1.4
$2.2
$1.1
$1.6
$1.0
$0.8
$0.6
$0.3
$0.3
$43.9
$2.2
$27.6
$2.1
Administrative Costs
$0.2
$0.0
$0.0
$1.7
$3.3
$3.1
$2.0
$1.0
$0.8
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.7
$1.2
$1.1
$0.7
$0.5
$0.2
$0.2
$0.1
$0.0
$22.3
1.1
$14.6
$1.1
Total Cost
$3.9
$16.1
$27.9
$206.0
$306.9
$295.9
$125.3
$36.1
$34.9
$34.5
$30.2
$25.4
$28.6
$61.7
$101.8
$51.2
$72.7
$35.0
$34.9
$34.5
$30.2
$25.4
$28.6
$61.7
$101.8
$51.2
$72.7
$35.0
$34.9
$34.5
$30.2
$25.4
$21.9
$18.6
$11.4
$6.2
$1.4
$1,535.7
$76.1
$1,085.6
$81.8
  Source:  U.S. EPA Analysis, 2004.
E1A-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter El
    Table E1A-8: Time Profile of Compliance Costs for Existing Facilities - Option 6 (in millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Costs of Compliance by Regulated
Segments
Industry
Manufacturers Generators
$5.5
$22.8
$36.7
$259.6
$400.0
$308.6
$131.9
$42.8
$43.7
$40.1
$37.6
$31.6
$36.5
$72.5
$124.3
$65.0
$80.3
$42.6
$43.7
$40.1
$37.6
$31.6
$36.5
$72.5
$124.3
$65.0
$80.3
$42.6
$43.7
$40.1
$37.6
$31.6
$26.5
$22.2
$13.0
$7.5
$1.7
$1,839.0
$91.1
$1,301.3
$98.0
$0.2
$1.0
$2.0
$3.5
$5.2
$4.0
$2.6
$4.9
$1.8
$2.5
$2.0
$2.8
$2.2
$2.7
$3.4
$3.2
$2.9
$4.2
$1.8
$2.5
$2.0
$2.8
$2.2
$2.7
$3.4
$3.2
$2.9
$4.2
$1.8
$2.5
$2.0
$2.8
$1.3
$1.1
$0.9
$0.5
$0.5
$58.8
$2.9
$36.6
$2.8
Administrative Costs
$0.2
$0.0
$0.0
$3.0
$5.0
$4.1
$3.1
$1.9
$1.3
$1.9
$1.5
$1.1
$0.8
$1.3
$1.8
$1.5
$1.1
$0.8
$1.3
$1.8
$1.5
$1.1
$0.8
$1.3
$1.8
$1.5
$1.1
$0.8
$1.3
$1.8
$1.5
$1.1
$0.8
$0.3
$0.2
$0.1
$0.0
$34.2
$1.7
$22.4
$1.7
Total Cost
$6.0
$23.8
$38.7
$266.2
$410.1
$316.7
$137.6
$49.6
$46.8
$44.5
$41.1
$35.5
$39.6
$76.5
$129.5
$69.7
$84.3
$47.7
$46.7
$44.5
$41.1
$35.5
$39.6
$76.5
$129.5
$69.7
$84.3
$47.7
$46.7
$44.5
$41.1
$35.5
$28.7
$23.6
$14.2
$8.1
$2.2
$1,932.0
$95.7
$1,360.3
$102.5
 Source:  U.S. EPA Analysis, 2004.
                                                                                                        E1A-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis            Appendix to Chapter El
                           THIS PAGE INTENTIONALLY LEFT BLANK
E1A-8

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis       E2: Summary of Benefits

            Chapter E2:  Summary  of Benefits
                                                 CHAPTER CONTENTS
                                                 E2-1  Calculating Losses and Benefits 	E2-1
                                                 E2-2  Summary of Baseline Losses and Expected
                                                       Reductions in I&E	E2-2
                                                 E2-3  Time Profile of Benefits	E2-4
                                                 E2-4  Total Annualized Monetary Value of Losses
                                                       and Benefits	E2-10
                                                 References 	E2-15
                                                 Appendix to Chapter E2	  E2A-1
INTRODUCTION

This chapter summarizes the EPA's benefits analysis
conducted in developing the Proposed Section
316(b) Rule for Phase III Facilities and presents the
total monetary value of regional and national
baseline losses and of benefits of the three proposed
options for Phase III existing facilities:

    •>   the "50 MOD for All Waterbodies" option
       ("50 MOD All"),
    *   the "200 MOD for All Waterbodies" option ("200 MOD All"), and
    >   the "100 MOD for Certain Waterbodies" option ("100 MOD CWB").

Benefits results for five other options evaluated by EPA, but not proposed, are presented in the appendix to this
chapter.

The Regional Benefits Assessment for the Proposed Section 316(b) Rule for Phase III Facilities (RBA) provides
greater detail on the methods and data used  in the regional analyses (U.S. EPA, 2004).  See Chapter Al for a
discussion of the methods used to estimate impingement and entrainment (I&E), and see Chapters A2 through A9
for discussion of the methods used to estimate the value of I&E losses and the benefits of the options evaluated
for the proposed rule. The results  of the regional analyses are presented in Parts B through G of the RBA.

EPA was unable to assess benefits of reducing I&E at new offshore oil and gas extraction facilities due to
significant data gaps at the time of proposal. Therefore, the benefits estimates presented in this section are
underestimates because they do not reflect benefits associated with reducing I&E at new offshore oil and gas
extraction facilities.
E2-1  CALCULATING LOSSES AND BENEFITS

EPA's analysis of national baseline losses and benefits under the evaluated options includes 603 sample-weighted
facilities in seven case study regions, excluding facilities that are expected to close in the baseline.  The Agency
calculated baseline losses by summing losses from all 603 facilities. EPA's estimates of benefits are based on
only those facilities that have requirements under each option.

Quantifying and monetizing reductions in I&E due to the evaluated options considered for the proposed rule is
challenging.  As described in Chapters A3 and A6 of the RBA, EPA has estimated non-use values only
qualitatively and, as a result, the estimated total benefits of the evaluated options reflect use values only.  The
RBA discusses specific limitations and uncertainties associated with estimation of commercial and recreational
benefits at the regional level. National benefit estimates, which are based on the regional estimates, are subject to
the same uncertainties. The overall effect of these uncertainties is of unknown magnitude and direction (i.e., the
estimates may over- or understate the anticipated national-level of use benefits); however, EPA has no data to
indicate that the results for any of the benefit categories are atypical or unreasonable.
                                                                                              E2-1

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits
E2-2   SUMMARY OF BASELINE LOSSES AND EXPECTED REDUCTIONS IN I&E

Based on the results of the regional analyses, EPA calculated total baseline I&E losses and the amount by which
these losses would be reduced under each of the evaluated options. Losses are presented using two measures of
I&E:

    1.   Age-one equivalent losses - the number of individual fish of different ages impinged and entrained by
        facility intakes, expressed as age-one equivalents; and

    2.   Foregone fishery yield - pounds of commercial harvest and numbers of recreational fish and shellfish that
        are not harvested due to I&E, including indirect losses of harvested species due to losses of forage
        species.

Table E2-1 presents baseline I&E losses for both measures. As reported in Table E2-1, EPA estimates total
national losses of age-one equivalents for all 603 facilities of 120 million fish. Nationwide, EPA estimates that
4.2 million pounds of fishery yield per year is foregone under current rates of I&E. Approximately 37% of all
age-one equivalent losses, or 44.2 million fish, occur in the Inland region. The Gulf of Mexico region has the
highest foregone fishery yields with approximately 2 million pounds, followed by the Mid-Atlantic region with
approximately 0.9 million pounds. More detailed discussions of the I&E losses in each region are provided in
Parts B through G of the RBA.
    Table E2-1: Total Annual Baseline I&E Losses for Potential Phase III Existing Facilities by Region
                                              (thousands)
Region
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland
National Total
Age-One Equivalents
1,310
2,340
23,200
1,520
12,700
34,400
44,200
120,000
Foregone Fishery Yield (Ibs)
96
45
920
123
1,990
489
495
4,160
 Source:  U.S. EPA Analysis, 2004.
To gauge the expected benefits of the proposed options, EPA estimated the extent to which these options would
reduce the estimated baseline losses.  These avoided losses are based on the expected reductions in I&E at each
facility from implementation of the required compliance technologies.  Table E2-2 reports, by region and option,
the expected percent reductions in I&E, and the estimated quantities of reduction in (1) losses in age-one
equivalents and (2) foregone fishery yield. At the national level, EPA estimates that the 50 MGD All option
would reduce age-one equivalent losses by 49.5 million fish and fishery yield loss by 2.2 million pounds. In
comparison, the 200 MGD All option and the 100 MGD CWB option apply to smaller numbers of facilities and
would result in slightly smaller reductions in I&E.  The 200 MGD All option would reduce age-one equivalent
losses by 34.0 million fish and fishery yield losses by 1.4 million pounds. The 100 MGD All option would
reduce age-one equivalent losses by 29.8 million fish and fishery yield losses by 1.9 million pounds.
E2-2

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis       E2: Summary of Benefits

The study regions show substantial variation in the estimated reductions in I&E losses and avoided losses in age-
one equivalents and foregone fishery yield.  As reported in Table E2-2, the largest percentage reductions in I&E
occur in the Gulf of Mexico for both the 50 MOD All and 100 MOD CWB options with 76% and 57%,
respectively.  The 200 MGD All option has the largest reductions in I&E in the Mid-Atlantic region with 65% and
49%, respectively.

Percentage reductions in entrainment are less substantial, overall, than the impingement reductions. However, the
Great Lakes region shows larger percentage reductions in entrainment than impingement for each of the three
proposed options, where entrainment reductions range from 37% to 43%, and impingement reductions are 21% to
33%.

In terms of avoided age-one equivalent losses,  the Inland region accounts for the largest reductions for the 50
MGD All option with approximately 30% of avoided losses. Under the 200  MGD All and the 100 MGD CWB
options, the Mid-Atlantic region accounts  for the largest reductions in total avoided age-one equivalent losses
with 35% and 40%,  respectively.

On the basis of avoided losses in fishery yield, the Gulf of Mexico generates the greatest benefits under each of
the three options, followed by the Mid-Atlantic region. Together, these two  regions account for 83%, 84%, and
92% of the avoided fishery yield losses achieved by the 50 MGD All, the 200 MGD All, and the 100 MGD CWB
options, respectively.

More detailed discussions of regional benefits  are provided in Parts B through G of the RBA.
                                                                                                    E2-3

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis E2: Summary of Benefits

Table E2-2: Expected Reduction in I&E for Phase III Existing Facilities by Option and Region
Region
Number of
Facilities
Installing
Technology
Impingement
Entrainment
Age-One
Equivalents
(thousands)
Foregone Fishery
Yield
(thousands; Ibs)
                                                  50 MGD All Option
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
1
4
3
0
7
19
69
103
39%
43%
73%
0%
76%
33%
37%
29%
40%
55%
0%
57%
43%
27%

383
930
13,400
0
8,380
11,600
14,800
49,493
28
18
600
0
1,250
169
157
2,222
                                                 200 MGD All Option
California*
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
0
1
2
0
2
5
12
22
0%
11%
65%
0%
41%
21%
22%
0%
8%
49%
0%
31%
37%
21%

0
198
11,900
0
4,580
7,710
9,650
34,038
0
4
534
0
682
116
107
1,443
                                                100 MGD CWB Option
California*
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland0
National Total
0
3
2
0
7
6
0
18
0%
43%
65%
0%
76%
24%
0%
0%
32%
49%
0%
57%
40%
0%

0
754
11,900
0
8,380
8,740
0
29,774
0
15
534
0
1,250
130
0
1,929
  3    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
      than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.
  b    No I&E reductions are expected in the California region because all potentially regulated facilities in this region withdraw less
      than 100 MGD and therefore would not be required to install technologies to comply with the 200 MGD All and the 100 MGD
      CWB options.
  c    The 100 MGD CWB option would not apply national categorical requirements to facilities located on freshwater rivers and
      lakes/reservoirs.  Thus, no I&E reductions are expected at the potentially regulated facilities in the Inland region.

  Source:  U.S. EPA Analysis, 2004.
E2-3   TIME PROFILE OF BENEFITS

To account for the difference in timing of benefits and costs, EPA developed a time profile of total benefits from
all Phase III facilities that reflects when benefits from each facility would be realized. For each study region,
E2-4

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis       E2: Summary of Benefits

EPA first calculated the undiscounted commercial and recreational fishing benefits from the expected annual I&E
reductions under the proposed options, based on the assumptions that all facilities in each region have achieved
compliance with the rule and that benefits are realized immediately following compliance. Then, since there are
regulatory and biological time lags between promulgation of the rule and the realization of benefits, EPA created
a time profile of benefits that takes into account the fact that benefits do not begin immediately.  The development
of the time profile of benefits is discussed in detail in Chapter A8: Discounting Benefits.

Table E2-3 below provides the time profile of the monetary value of baseline I&E losses, by region.  EPA
developed similar time profiles for monetary benefits for the three proposed options for Phase III existing
facilities (see Tables E2-4, E2-5, and E2-6).
                                                                                                     E2-5

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits

Table E2-3: Time Profile
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%b
Annualized 3%c
PV 7%b
Annualized 7%c
California
$0
$12
$23
$93
$105
$110
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$116
$105
$93
$23
$12
$6
$0
$0
$0
$0
$0
$0
$2,143
$109
$1,258
$101
of Mean Monetary Value of Total
North
Atlantic
$0
$20
$41
$163
$183
$194
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$204
$183
$163
$41
$20
$10
$0
$0
$0
$0
$0
$0
$3,761
$192
$2,207
$178
Mid-
Atlantic
$0
$111
$222
$889
$1,001
$1,056
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,112
$1,001
$889
$222
$111
$56
$0
$0
$0
$0
$0
$0
$20,519
$1,047
$12,042
$970
South
Atlantic
$0
$8
$16
$65
$73
$77
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$73
$65
$16
(TO
4>o
$4
$0
$0
$0
$0
$0
$0
$1,498
$76
$879
$71
Baseline
Gulf of
Mexico
$111
$222
$887
$998
$1,054
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$1,109
$998
$887
$222
$111
$55
$0
$0
$0
$0
$0
$0
$0
$21,088
$1,076
$12,857
$1,036
I&E Losses
Great Lakes
$118
$236
$945
$1,063
$1,122
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,181
$1,063
$945
$236
$118
$59
$0
$0
$0
$0
$0
$0
$0
$22,452
$1,146
$13,688
$1,103
(thousands;
Inland
$112
$224
$897
$1,009
$1,065
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,121
$1,009
$897
$224
$112
$56
$0
$0
$0
$0
$0
$0
$0
$21,306
$1,087
$12,990
$1,047
2003$)a
National
Total
$341
$833
$3,031
$4,280
$4,602
$4,848
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,924
$4,583
$4,090
$1,892
$644
$322
$76
$0
$0
$0
$0
$0
$0
$92,769
$4,733
$55,921
$4,506
 a   Because EPA estimated non-use benefits only qualitatively, the total monetary value of I&E losses includes only losses in use
     values.
 b   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 c   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 Source:  U.S. EPA Analysis, 2004.
E2-6

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits

Table E2-4: Time Profile
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
of Mean
„ ,.„ . North
California . ,,
Atlantic
$0
$0
$0
$0
$3
$7
$27
$31
$32
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$34
$31
$27
$7
$3
$2
$0
$0
$0
$577
$29
$302
$24
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Total Use
Mid-
Atlantic
$0
$0
$0
$0
$7
$14
$99
$164
$439
$571
$607
$636
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$643
$636
$629
$543
$479
$203
$71
$36
$7
$10,239
$522
$4,973
$401
Benefits - 50
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
MGD All
Gulf of
Mexico
$0
$0
$0
$0
$0
$76
$152
$608
$684
$722
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$684
$608
$152
$76
$38
$0
$0
$12,463
$636
$6,280
$506
Option (thousands; 2003$)a
Great Lakes
$0
$0
$0
$oe
$11
$26
$106
$160
$291
$371
$391
$406
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$410
$400
$384
$304
$250
$120
$39
$19
$5
$6,602
$337
$3,252
$262
Inland
$0
$0
$0
$7
$33
$96
$231
$275
$329
$349
$354
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$351
$324
$262
$127
$83
$28
$8
$4
$0e
$5,998
$306
$3,113
$251
National
Total
$0
$0
$0
$7
$54
$223
$625
$1,280
$1,826
$2,120
$2,225
$2,272
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,286
$2,279
$2,232
$2,063
$1,661
$1,006
$460
$166
$61
$14
$37,177
$1,897
$18,556
$1,495
 a   Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b   No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
     than 50 MGD and therefore would not be required to install technologies to comply with this option.
 c   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 e   Positive non-zero value less than $500.
 Source:  U.S. EPA Analysis, 2004.
                                                                                                                         E2-7

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits

Table E2-5: Time Profile
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
so
so
so
so
of Mean
North
Atlantic
$0
$0
$0
$0
$0
$0
$0
$2
$3
$14
$15
$16
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$17
$15
$14
$3
$2
$1
S266
S14
S124
S10
Total Use Benefits -
200
Mid- South
Atlantic Atlantic"
$0
$0
$0
$0
$0
$0
$43
$100
$372
$501
$537
$565
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$529
$472
$200
$71
$36
$7
$9,047
S462
$4,349
$350
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
MGD All
Gulf of
Mexico
$0
$0
$0
$0
$0
$42
$83
$332
$374
$394
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$415
$374
$332
$83
$42
$21
$0
$0
$6,810
$347
$3,431
$277
Option (thousands; 2003$)a
Great Lakes
$0
$0
$0
$0
$4
$8
$48
$77
$185
$251
$267
$279
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$283
$279
$275
$235
$207
$99
$32
$16
$4
$4,513
$230
$2,192
$177
Inland
$0
$0
$0
$3
$23
$58
$168
$191
$225
$238
$240
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$242
$239
$219
$184
$74
$51
$17
$4
$2
$0
$4,063
$207
$2,113
$170
National
Total
$0
$0
$0
$3
$27
$108
$343
$702
$1,159
$1,398
$1,474
$1,518
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,530
$1,527
$1,503
$1,422
$1,188
$828
$371
$132
$56
$12
$24,698
$1,260
$12,209
$984
 a   Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b   No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
     than 200 MGD and therefore would not be required to install technologies to comply with this option.
 c   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 Source:  U.S. EPA Analysis, 2004.
E2-8

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits

Table E2-6: Time Profile
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%d
Annualized 3%e
PV 7%d
Annualized 7%e
California"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
so
so
so
so
of Mean Total Use Benefits - 100
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$40
$47
$60
$64
$65
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$66
$61
$56
$25
$19
$6
$2
$1
$1,059
S54
S524
S42
Mid-
Atlantic
$0
$0
$0
$0
$0
$0
$43
$100
$372
$501
$537
$565
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$572
$529
$472
$200
$71
$36
$7
$9,047
$462
$4,349
$350
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
MGD CWB
Gulf of
Mexico
$0
$0
$0
$0
$0
$76
$152
$608
$684
$722
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$760
$684
$608
$152
$76
$38
$0
$0
$12,463
$636
$6,280
$506
Option (thousands;
Great
Lakes
$0
$0
$0
$0
$6
$12
$66
$98
$212
$284
$301
$314
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$318
$312
$306
$252
$220
$105
$34
$17
$4
$5,079
$259
$2,479
$200
Inland0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
2003$)a
National
Total
$0
$0
$0
$0
$6
$93
$270
$846
$1,316
$1,566
$1,661
$1,703
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,716
$1,710
$1,623
$1,445
$870
$400
$150
$55
$12
$27,647
$1,411
$13,632
$1,099
 a   Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b   No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
     than 100 MGD and therefore would not be required to install technologies to comply with this option.
 c   The 100 MGD CWB option would not apply national categorical requirements to facilities located on freshwater rivers and
     lakes/reservoirs. Thus, no I&E reductions are expected at the potentially regulated facilities in the Inland region.
 d   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 e   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 Source:  U.S. EPA Analysis, 2004.
                                                                                                                          E2-9

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis        E2: Summary of Benefits


E2-4   TOTAL ANNUALIZED MONETARY VALUE OF LOSSES AND BENEFITS

EPA used the profiles of benefits, by region, to calculate a total present value of benefits and then to calculate a
constant annual equivalent value (annualized value) of the present value.  EPA performed the calculations of
present value and annualized value using two discount rate values: a real rate of 3% and a real rate of 7%.
Although the total period for analysis of benefits extends from 2007 through 2048, a 42-year period, EPA
annualized the value of benefits over 30 years, which is the assumed length of each facility's compliance period
for the social cost analysis, as described in Chapter El: Summary of Social Costs. Using the same annualization
period as in the cost analysis is necessary to provide a conceptually and mathematically consistent comparison of
annualized benefit and cost values.

EPA estimated mean values, as well as lower and upper bound values reflecting uncertainty in the recreational
benefits estimates.  Table E2-7 presents the value of baseline I&E losses for each region and for the nation as a
whole. Tables E2-8 and E2-9 present I&E losses for each region and the nation under the 50 MGD All, 200
MGD All, and 100 MGD CWB options discounted at 3% and 7%, respectively. Because EPA did not estimate
non-use benefits quantitatively, the monetary value of national losses and benefits presented in these tables
reflects only use values.1 As described in Chapter A3  of the RBA, the Agency was not able to monetize benefits
for 96.7% of the age-one equivalent losses of all commercial, recreational, and forage species analyzed for the
evaluated options for existing facilities. This means that the estimates of losses and benefits presented in this
section represent the losses and benefits associated with less than 3.3% of the total age-one equivalents lost due to
I&E by cooling water intake structures, and should be interpreted with caution.

Table E2-7 reports the monetized value of baseline losses as outlined above. EPA estimates the national value of
these losses at $0.3 million in commercial fishing losses and  $4.4 million in recreational fishing losses (2003$,
discounted to 2007 at 3%).  The total use value of fishery resources lost is $4.7 million per year, with lower and
upper bounds of $2.4 million and $9.5 million, respectively (2003$, discounted at 3%).  At a 7% discount rate,
EPA estimates total annual national value of losses at $0.3 million in commercial fishing losses and $4.2 million
in recreational fishing losses (2003$). The total use value of fishery resources lost, discounted at 7%, is $4.5
million per year, with lower and upper bounds of $2.3 million and $9.0 million, respectively (2003$).  Total
monetized losses are greatest in the  Great Lakes region. More detailed discussions of the valuation of recreational
and commercial fishing losses under the baseline conditions in each region are provided in  Parts B through G  of
the RBA.
    1 See Chapter A6 of the RBA for a detailed description of the ecological benefits from reduced I&E.

E2-10

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits

Table E2-7: Summary of Monetary Values of Baseline I&E Losses (thousands; 2003$)a
Region
Annualized Use Value of Baseline I&E Losses
Commercial
Fishing
Recreational Fishing
Low Mean High
Total Use Value"
Low Mean
High
                                                  3% discount rate
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland0
National Total
$0 - $20
$0-$9
$0 - $47
$0
$0-$139
$0 - $70
n/a
SO - $284
$38
$84
$473
$34
$419
$534
$576
$2,159
$90
$183
$1,000
$76
$937
$1,076
$1,087
$4,449
$211
$401
$2,124
$171
$2,105
$2,109
$2,047
$9,168
$58
$93
$520
$34
$558
$604
$576
$2,443
$109
$192
$1,047
$76
$1,076
$1,146
$1,087
$4,733
$231
$409
$2,171
$171
$2,244
$2,179
$2,047
$9,452
                                                  7% discount rate
California
North Atlantic
Mid-Atlantic
South Atlantic
Gulf of Mexico
Great Lakes
Inland0
National Total
$0-$18
$0-$8
$0 - $44
$0
$0-$133
$0 - $67
n/a
$0 - $271
$35
$78
$438
$32
$404
$515
$555
$2,057
$83
$170
$927
$71
$903
$1,036
$1,047
$4,236
$196
$371
$1,969
$158
$2,028
$2,031
$1,971
$8,724
$54
$86
$482
$32
$537
$582
$555
$2,328
$101
$178
$970
$71
$1,036
$1,103
$1,047
$4,506
$214
$379
$2,012
$158
$2,161
$2,099
$1,971
$8,995
 a    All losses presented in this table are annualized.  These estimated annualized losses represent the value of all losses generated over
     the time frame of the analysis, discounted to 2007, and then annualized over a 30-year period.
 b    The total monetizable value of I&E reductions includes use benefits only.  EPA evaluated non-use benefits only qualitatively. A
     range of recreational fishing benefits is provided, based on the Krinsky and Robb technique to estimated the 95th and 5th percentile
     limits on the marginal value per fish predicted by EPA's meta-analysis (see chapter A5 of the RBA). Commercial fishing benefits
     are computed based on a range from 0% to 40% of the change in gross revenue (see Chapter A4 of the RBA). To calculate the total
     use value columns (low, mean, and high), the high end value for commercial fishing benefits is added to the low, mean, and high
     values for recreational fishing benefits, respectively.
 0    No significant commercial fishing takes place in the Inland region. Thus, this region is excluded from the commercial fishing
     analysis.

 Source:  U.S. EPA Analysis, 2004.
Tables E2-8 and E2-9 present EPA's estimates of the national and regional values of avoided I&E losses (all
values are in 2003$, discounted at 3% and 7% to beginning of year 2007, and annualized over a 30-year period).
National values of avoided I&E losses at a 3% discount rate are as follows:

    *•    For the 50 MGD All option, a mean value of $1.9 million per year, with lower and upper bounds of $1.0
         million and $3.8 million (see Table E2-8);

    »•    For the 200 MGD All option, a mean value of $ 1.3 million per year, with lower and upper bounds of $0.6
         million and $2.5 million (see Table E2-8); and

    *•    For the 100 MGD CWB option, a mean value of $ 1.4 million per year, with lower and upper bounds of
         $0.7 million and $2.9 million (see Table E2-8).
                                                                                                              E2-11

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis        E2: Summary of Benefits
The 7% discount rate calculations yield smaller values as follows:

    *•   For the 50 MGD All option, a mean value of $1.5 million per year, with lower and upper bounds of $0.8
        million and $3.0 million (see Table E2-9);

    *•   For the 200 MGD All option, a mean value of $ 1.0 million per year, with lower and upper bounds of $0.5
        million and $2.0 million (see Table E2-9); and

    *•   For the 100 MGD CWB option, a mean value of $ 1.1 million per year, with lower and upper bounds of
        $0.6 million and $2.3 million (see Table E2-9).

EPA also considered how benefits might increase if facilities that meet technology requirements in the baseline
optimize their operation and maintenance (O&M) procedures (e.g., by rotating screens more often to reduce
impingement mortality due to the proposed regulation).  For this analysis, EPA evaluated facilities that are
expected to (1)  install no new technology and (2) meet impingement standards with a 0.5 fps screen. If there was
a 5% increase in the efficacy of O&M at these facilities, the total annualized national benefits from the proposed
regulation would increase by approximately $19,000 for the 50 MGD All option, from $1.897 million to $1.916
million (using the 3% discount rate).  If there was a 15% increase in efficacy, the estimated annualized benefits
would increase  by over $58,000, to $1.955 million (using the 3% discount rate).  Using the 7% discount  rate, total
annualized national benefits from the proposed regulation would increase by approximately $18,000 and $55,000,
for the 5% and  15% increases in efficacy, respectively. Therefore,  optimization  of O&M procedures would result
in 1.0% to  3.5% increase in the estimated total use benefits of the proposed regulation, depending on the assumed
increase in efficacy and the discount rate being used.  Optimization of O&M procedures would result in similar
increases in the estimated use benefits under "200 MGD for All Waterbodies" and "100 MGD for Certain
Waterbodies" options.

The majority of the use benefit value is  attributable to benefits to recreational anglers  from improved catch rates.
As shown in Tables E2-8 and E2-9, use benefits are largest in the Gulf of Mexico for the 50 MGD All and 100
MGD CWB options and the Mid-Atlantic region under the 200 MGD All option. More detailed discussions of
regional benefits under each option are provided in  Parts B through G  of the RBA.
E2-12

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits
        Table E2-8: Summary of Monetized Benefits by Option (thousands; 2003$; discounted at 3%)a
Region
Annualized
Commercial
Fishing Benefits
Annualized Recreational Fishing
Benefits
Low
Mean High
Total Annualized Value of Monetized
Impingement and Entrainment
Reductions'"
Low Mean High
                                                     50 MGD All Option
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inlandd
National Total
*cn U - 4>J
(Tfl (f3
4>U - 4>J
$0 - $25
$0
$0 - $78
$0 - $20
n/a
SO - $132
$10
$29
$235
$0
$249
$157
$162
$843
$24
$63
$497
$0
$558
$316
$306
$1,765
$57
$138
$1,057
$0
$1,254
$621
$577
$3,704
$16
$32
$260
$0
$327
$178
$162
$975
$29
$66
$522
$0
$636
$337
$306
$1,897
$62
$141
$1,082
$0
$1,332
$641
$577
$3,836
                                                    200 MGD All Option
California6
North Atlantic
Mid-Atlantic
South Atlantic"
Gulf of Mexico
Great Lakes
Inland4
National Total
$0
$0-$1
$0 - $22
$0
$0 - $43
$0-$14
n/a
$0 - $79
$0
$6
$208
$0
$136
$108
$110
$567
$0
$13
$440
$0
$305
$216
$207
$1,181
$0
$28
$934
$0
$685
$425
$390
$2,463
$0
$7
$230
$0
$179
$122
$110
$647
$0
$14
$462
$0
$347
$230
$207
$1,260
$0
$29
$956
$0
$728
$439
$390
$2,542
                                                   100 MGD CWB Option
California6
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland45
National Total
$0
$0-$2
$0 - $22
$0
$0 - $78
$0-$16
n/a
$0-$118
$0
$24
$208
$0
$249
$121
$0
$602
$0
$52
$440
$0
$558
$243
$0
$1,292
$0
$113
$934
$0
$1,254
$478
$0
$2,779
$0
$26
$230
$0
$327
$137
$0
$720
$0
$54
$462
$0
$636
$259
$0
$1,411
$0
$115
$956
$0
$1,332
$494
$0
$2,897
  a    All benefits presented in this table are annualized. These annualized benefits represent the value of all losses generated over the
      time frame of the analysis, discounted to 2007, and then annualized over a 30-year period.
  b    The total monetizable value of I&E reductions includes use benefits only. EPA evaluated non-use benefits only qualitatively. A
      range of recreational fishing benefits is provided, based on the Krinsky and Robb technique to estimated the  95th and 5th
      percentile  limits on the marginal value per fish predicted by EPA's meta-analysis (see chapter A5 of the RBA).  Commercial
      fishing benefits are computed based on a range from 0% to 40% of the change in gross revenue (see Chapter A4 of the RBA). To
      calculate the total use value columns (low, mean, and high), the high end value for commercial fishing benefits is added to the low,
      mean, and high values for recreational fishing benefits, respectively.
  0    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
      than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.
  d    No significant commercial fishing takes place in the Inland region. Thus, this region is excluded from the commercial fishing
      analysis.
  °    No I&E reductions are expected in the California region because all potentially regulated facilities in this region withdraw less
      than 100 MGD and therefore would not be required to install technologies to comply with the 200 MGD All  and the 100 MGD
      CWB options.
  f    The 100 MGD CWB option would not apply national categorical requirements to facilities located on freshwater rivers and
      lakes/reservoirs. Thus, no I&E reductions are expected at the potentially regulated facilities in the Inland region.
  Source:  U.S. EPA Analysis, 2004.
                                                                                                                      E2-13

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E2: Summary of Benefits
        Table E2-9: Summary of Monetized Benefits by Option (thousands; 2003$;  discounted at 7%)a
Region
Annualized
Commercial
Fishing Benefits
Annualized Recreational Fishing
Benefits
Low
Mean High
Total Annualized Value of Monetized
Impingement and Entrainment
Reductions'"
Low Mean High
                                                     50 MGD All Option
California
North Atlantic
Mid-Atlantic
South Atlantic'
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$4
$0-$2
$0-$19
$0
$0 - $62
$0-$16
n/a
$0 - $104
$9
$22
$181
$0
$198
$122
$133
$665
$20
$49
$382
$0
$444
$246
$251
$1,391
$47
$107
$811
$0
$998
$483
$473
$2,919
$13
$25
$200
$0
$260
$138
$133
$769
$24
$51
$401
$0
$506
$262
$251
$1,495
$51
$109
$830
$0
$1,061
$499
$473
$3,023
                                                    200 MGD All Option
California6
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inlandd
National Total
$0
$0
$0 - $17
$0
$0 - $34
$0-$11
n/a
$0 - $62
$0
$4
$158
$0
$108
$83
$90
$443
$0
$10
$334
$0
$243
$166
$170
$922
$0
$21
$709
$0
$545
$326
$321
$1,922
$0
$5
$175
$0
$142
$93
$90
$505
$0
$10
$350
$0
$277
$177
$170
$984
$0
$21
$726
$0
$579
$337
$321
$1,984
                                                   100 MGD CWB Option
California6
North Atlantic
Mid-Atlantic
South Atlantic6
Gulf of Mexico
Great Lakes
Inland45
National Total
$0
$0-$2
$0 - $17
$0
$0 - $62
$0-$12
n/a
$0 - $93
$0
$19
$158
$0
$198
$93
$0
$468
$0
$40
$334
$0
$444
$188
$0
$1,006
$0
$88
$709
$0
$998
$368
$0
$2,164
$0
$20
$175
$0
$260
$105
$0
$561
$0
$42
$350
$0
$506
$200
$0
$1,099
$0
$90
$726
$0
$1,061
$381
$0
$2,257
  a    All benefits presented in this table are annualized.  These annualized benefits represent the value of all losses generated over the
      time frame of the analysis, discounted to 2007, and then annualized over a 30-year period.
  b    The total monetizable value of I&E reductions includes use benefits only.  EPA evaluated non-use benefits only qualitatively.  A
      range of recreational fishing benefits is provided, based on the Krinsky and Robb technique to estimated the 95th and 5th
      percentile  limits on the marginal value per fish predicted by EPA's meta-analysis (see chapter A5 of the RBA).  Commercial
      fishing benefits are computed based on a range from 0% to 40% of the change in gross revenue (see Chapter A4 of the RBA).  To
      calculate the total use value columns (low, mean, and high), the high end value for commercial fishing benefits is added to the low,
      mean, and high values for recreational fishing benefits, respectively.
  c    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
      than 50 MGD and therefore would not be required  to install technologies to comply with the proposed options.
  d    No significant commercial fishing takes place in the Inland region, and thus this region is excluded from the commercial fishing
      benefits analysis.
  e    No I&E reductions are expected in the California region because all potentially regulated facilities in this region withdraw less
      than 100 MGD and therefore would not be required to install technologies to comply with the 200 MGD All and the 100 MGD
      CWB options.
  f    The 100 MGD CWB option would not apply national categorical requirements to facilities located on freshwater rivers and
      lakes/reservoirs. Thus, no I&E reductions are expected at the potentially regulated facilities in the Inland region.
  Source:   U.S. EPA Analysis, 2004.
E2-14

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis        E2: Summary of Benefits


REFERENCES

U.S. Environmental Protection Agency (U.S. EPA). 2004.  The Regional Benefits Assessment for the Proposed
Section 316(b) Rule for Phase III Facilities. EPA-821 -R-04-017. November 2004.
                                                                                                 E2-15

-------
Section 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis       E2: Summary of Benefits
                           THIS PAGE INTENTIONALLY LEFT BLANK
E2-16

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                              Appendix to Chapter E2
                      Appendix to  Chapter E2
INTRODUCTION
                                                APPENDIX CONTENTS
                                                E2A-1  Summary of Expected Reductions in I&E . E2A-1
                                                E2A-2  Time Profile of Benefits	 E2A-3
                                                E2A-3  Total Annualized Monetary Value
                                                       of Benefits 	 E2A-9
This appendix supplements Chapter E2 by presenting
the results of the benefits analysis for five other
options evaluated for potential Phase III existing
facilities. For all options, facility counts and other
results only include those potential Phase III existing
facilities that are (1) non-baseline closures and (2)
subject to national categorical requirements under the option.  The options are presented in increasing order based
on design intake flow (DIP) applicability threshold and the stringency of compliance requirements. See the main
body of this chapter for a description of methodologies used in this analysis.
E2A-1    SUMMARY OF EXPECTED REDUCTIONS IN I&E

Table E2A-1 presents the number of facilities with technology requirements under the other options, by region,
and EPA's estimates of the percentage by which I&E would be reduced. The table also presents estimates of
regional and national reductions in I&E losses under each option, expressed as age-one equivalents lost and
foregone fishery yield.
Table E2A-1: Expected Reductions in I&E for Existing Phase III Facilities by Option
Region
Number of
Facilities Installing
Technology
Impingement
Entrainment
Age-One
Equivalents
(thousands)
Foregone
Fishery Yield
(thousands; Ibs)
                                            Option 3
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
4
4
4
0
11
38
130
190
78%
43%
74%
0%
80%
38%
43%
29%
40%
55%
0%
57%
43%
27%

391
930
13,400
0
8,650
13,200
16,600
53,171
28
18
606
0
1,270
190
171
2,283
                                            Option 4
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
4
4
4
0
11
38
69
130
78%
43%
74%
0%
80%
38%
37%
59%
40%
55%
0%
60%
46%
27%

771
930
13,600
0
8,860
13,300
14,800
52,261
56
18
610
0
1,320
192
157
2,353
                                            Option 2
                                                                                          E2A-1

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2
            Table E2A-1: Expected Reductions in I&E for Existing Phase III Facilities by Option
Region
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
Number of
Facilities Installing
Technology
4
4
4
0
11
38
69
130
Impingement
78%
43%
74%
0%
80%
38%
37%
Entrainment
59%
40%
55%
0%
60%
46%
27%

Age-One
Equivalents
(thousands)
771
930
13,600
0
8,860
13,300
14,800
52,261
Foregone
Fishery Yield
(thousands; Ibs)
56
18
610
0
1,320
192
157
2,353
                                                        Option 1
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
4
4
4
0
11
38
134
194
78%
43%
74%
0%
80%
38%
43%
59%
40%
55%
0%
60%
46%
29%

771
930
13,600
0
8,860
13,300
16,900
54,361
56
18
610
0
1,320
192
177
2,373
                                                        Option 6
California
North Atlantic
Mid-Atlantic
South Atlantic3
Gulf of Mexico
Great Lakes
Inland
National Total
4
4
5
0
11
61
203
288
78%
43%
75%
0%
80%
41%
45%
59%
40%
56%
0%
60%
48%
30%

771
930
13,700
0
8,860
14,300
17,600
56,161
56
18
615
0
1,320
206
183
2,398
  3    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with
      these options.

  Source:  U.S. EPA Analysis, 2004.

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis       Appendix to Chapter E2


E2A-2    TIME PROFILE OF BENEFITS

Tables E2A-2 through E2A-6 below provide the time profiles of regional benefits for Option 3, Option 4, Option
2, Option 1, and Option 6.
                                                                                                E2A-3

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-2: Time
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California
$0
$0
$0
$0
$2
$4
$14
$18
$20
$32
$34
$35
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$36
$34
$32
$21
$18
$15
$4
$2
$1
$574
$29
$285
$23
Profile of
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Mean Total
Mid-
Atlantic
$0
$0
$0
$0
$7
$15
$100
$170
$443
$574
$610
$638
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$645
$638
$630
$545
$475
$202
$71
$35
$7
$10,281
$525
$4,996
$403
Use Benefits - Option
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Gulf of
Mexico
$0
$0
$0
$0
$0
$79
$158
$631
$710
$750
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$789
$710
$631
$158
$79
$39
$0
$0
$12,945
$660
$6,523
$526
3 (thousands
Great
Lakes
$0
$0
$0
$oe
$12
$31
$121
$193
$331
$418
$440
$455
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$460
$448
$429
$339
$267
$129
$42
$20
$5
$7,416
$378
$3,661
$295
; 2003$)a
Inland
$0
$0
$0
$7
$34
$101
$238
$292
$354
$380
$387
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$391
$384
$357
$291
$153
$99
$37
$11
$5
$1
$6,542
$334
$3,384
$273

National
Total
$0
$0
$0
$8
$55
$234
$641
$1,346
$1,909
$2,226
$2,338
$2,387
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,403
$2,395
$2,348
$2,169
$1,762
$1,057
$493
$176
$65
$15
$39,056
$1,993
$19,484
$1,570
 a    Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
      option.
 c    The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d    Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
      annualized over a 30-year period.
 e    Positive non-zero value less than $500.
 Source:  U.S. EPA Analysis, 2004.
E2A-4

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-3: Time
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California
$0
$0
$0
$0
$3
$7
$27
$34
$39
$62
$65
$67
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$65
$62
$41
$35
$29
$7
$3
$2
$1,112
$57
$552
$44
Profile of
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Mean Total
Mid-
Atlantic
$0
$0
$0
$0
$7
$15
$101
$172
$449
$581
$617
$646
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$646
$638
$552
$481
$205
$72
$36
$7
$10,407
$531
$5,057
$408
Use Benefits - Option
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Gulf of
Mexico
$0
$0
$0
$0
$0
$80
$161
$642
$723
$763
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$723
$642
$161
$80
$40
$0
$0
$13,167
$672
$6,635
$535
4 (thousands
Great
Lakes
$0
$0
$0
$1
$12
$31
$122
$195
$334
$422
$445
$460
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$464
$453
$434
$343
$270
$131
$42
$20
$5
$7,494
$382
$3,699
$298
; 2003$)a
Inland
$0
$0
$0
$7
$33
$96
$231
$275
$329
$349
$354
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$351
$324
$262
$127
$83
$28
$8
$4
$0e
$5,998
$306
$3,113
$251

National
Total
$0
$0
$0
$7
$56
$234
$652
$1,360
$1,924
$2,250
$2,362
$2,413
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,421
$2,373
$2,195
$1,776
$1,068
$504
$179
$66
$16
$39,475
$2,014
$19,692
$1,587
 a   Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b   No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
     the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
     option.
 c   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 e   Positive non-zero value less than $500.
 Source:  U.S. EPA Analysis, 2004.
                                                                                                                        E2A-5

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-4: Time
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California
$0
$0
$0
$0
$3
$7
$27
$34
$39
$62
$65
$67
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$65
$62
$41
$35
$29
$7
$3
$2
$1,112
$57
$552
$44
Profile of
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Mean Total
Mid-
Atlantic
$0
$0
$0
$0
$7
$15
$101
$172
$449
$581
$617
$646
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$646
$638
$552
$481
$205
$72
$36
$7
$10,407
$531
$5,057
$408
Use Benefits
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
- Option
Gulf of
Mexico
$0
$0
$0
$0
$0
$80
$161
$642
$723
$763
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$723
$642
$161
$80
$40
$0
$0
$13,167
$672
$6,635
$535
2 (thousands;
Great Lakes
$0
$0
$0
$1
$12
$31
$122
$195
$334
$422
$445
$460
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$464
$453
$434
$343
$270
$131
$42
$20
$5
$7,494
$382
$3,699
$298
2003$)a
Inland
$0
$0
$0
$7
$33
$96
$231
$275
$329
$349
$354
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$358
$351
$324
$262
$127
$83
$28
$8
$4
$0e
$5,998
$306
$3,113
$251

National
Total
$0
$0
$0
$7
$56
$234
$652
$1,360
$1,924
$2,250
$2,362
$2,413
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,428
$2,421
$2,373
$2,195
$1,776
$1,068
$504
$179
$66
$16
$39,475
$2,014
$19,692
$1,587
 a    Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
      option.
 c    The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d    Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
      annualized over a 30-year period.
 e    Positive non-zero value less than $500.
 Source:  U.S. EPA Analysis, 2004.
E2A-6

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-5: Time
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California
$0
$0
$0
$0
$3
$7
$27
$34
$39
$62
$65
$67
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$65
$62
$41
$35
$29
$7
$3
$2
$1,112
$57
$552
$44
Profile of
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Mean Total
Mid-
Atlantic
$0
$0
$0
$0
$7
$15
$101
$172
$449
$581
$617
$646
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$653
$646
$638
$552
$481
$205
$72
$36
$7
$10,407
$531
$5,057
$408
Use Benefits - Option
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
Gulf of
Mexico
$0
$0
$0
$0
$0
$80
$161
$642
$723
$763
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$723
$642
$161
$80
$40
$0
$0
$13,167
$672
$6,635
$535
1 (thousands
Great
Lakes
$0
$0
$0
$1
$12
$31
$122
$195
$334
$422
$445
$460
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$465
$464
$453
$434
$343
$270
$131
$42
$20
$5
$7,494
$382
$3,699
$298
; 2003$)a
Inland
$0
$0
$0
$7
$35
$104
$245
$302
$366
$392
$399
$403
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$404
$396
$369
$300
$159
$102
$38
$12
$5
$1
$6,748
$344
$3,490
$281

National
Total
$0
$0
$0
$8
$57
$242
$666
$1,387
$1,961
$2,292
$2,407
$2,458
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,474
$2,467
$2,417
$2,232
$1,809
$1,087
$514
$182
$67
$16
$40,225
$2,052
$20,068
$1,617
 a   Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b   No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
     the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
     option.
 c   The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d   Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
     annualized over a 30-year period.
 Source:  U.S. EPA Analysis, 2004.
                                                                                                                        E2A-7

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-6: Time
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%c
Annualized 3%d
PV 7%c
Annualized 7%d
California
$0
$0
$0
$0
$3
$7
$27
$34
$39
$62
$65
$67
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$69
$65
$62
$41
$35
$29
$7
$3
$2
$1,112
$57
$552
$44
Profile of
North
Atlantic
$0
$0
$0
$0
$0
$5
$10
$42
$50
$72
$78
$79
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$81
$76
$71
$39
$31
$9
$3
$2
$1,298
$66
$635
$51
Mean Total
Mid-
Atlantic
$0
$0
$0
$0
$7
$15
$101
$172
$449
$582
$622
$651
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$659
$652
$644
$557
$487
$210
$77
$37
$8
$10,492
$535
$5,095
$411
Use Benefits
South
Atlantic"
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
- Option 6
Gulf of
Mexico
$0
$0
$0
$0
$0
$80
$161
$642
$723
$763
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$803
$723
$642
$161
$80
$40
$0
$0
$13,167
$672
$6,635
$535
(thousands;
Great
Lakes
$0
$0
$0
$1
$15
$41
$140
$216
$361
$455
$478
$494
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$499
$498
$484
$458
$359
$283
$138
$45
$21
$5
$8,063
$411
$3,990
$322
2003$)a
Inland
$0
$0
$0
$8
$36
$106
$251
$311
$377
$406
$413
$418
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$419
$411
$383
$312
$168
$107
$41
$13
$5
$1
$6,993
$357
$3,614
$291

National
Total
$0
$0
$0
$9
$61
$254
$690
$1,418
$1,999
$2,340
$2,460
$2,512
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,529
$2,520
$2,468
$2,275
$1,839
$1,112
$530
$190
$70
$17
$41,124
$2,098
$20,521
$1,654
 a    Because EPA estimated non-use benefits only qualitatively, the monetary value of benefits includes use values only.
 b    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
      option.
 c    The present value (PV) is estimated by discounting individual annual values to 2007, using the stated discount rate.
 d    Annualized benefits represent the value of all benefits generated over the time frame of the analysis, discounted to 2007, and then
      annualized over a 30-year period.
 Source:  U.S. EPA Analysis, 2004.
E2A-8

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2
E2A-3    TOTAL ANNUALIZED MONETARY VALUE OF BENEFITS

Tables E2A-7 and E2A-8 present EPA's estimates of the value of national and regional reductions in I&E under
the other options analyzed for the proposed rule, using 3% and 7% discount rates. The tables shows for all other
options, that benefits to recreational anglers account for the majority of use benefits. National use benefits are
largest in the Gulf of Mexico region under all five options. More detailed discussions of regional benefits under
each option are provided in Sections B through G of the RBA.
Table E2A-7: Summary of Monetized Benefits for Existing Phase
(thousands; 2003$; discounted at 3%)
Region
III Facilities3

Annualized Use Benefits of I&E Reductions
Annualized
Commercial
Fishing
Recreational Fishing
Low Mean High
Total Use Value"
Low
Mean
High
                                               Option 3
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$5
$0-$3
$0 - $25
$0
$0 - $80
$0 - $23
n/a
SO - $137
$10
$29
$236
$0
$259
$177
$176
$888
$24
$63
$499
$0
$580
$355
$334
$1,856
$57
$138
$1,061
$0
$1,305
$697
$630
$3,888
$15
$32
$261
$0
$339
$200
$176
$1,024
$29
$66
$525
$0
$660
$378
$334
$1,993
$62
$141
$1,086
$0
$1,385
$720
$630
$4,025
                                               Option 4
California
North Atlantic
Mid-Atlantic
South Atlantic"
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$10
$0-$3
$0 - $25
$0
$0 - $83
(Tfl *CO'3
4>U - 4>ZJ
n/a
$0 - $144
$20
$29
$239
$0
$263
$178
$162
$892
$47
$63
$506
$0
$589
$359
$306
$1,870
$110
$138
$1,074
$0
$1,325
$704
$577
$3,929
$30
$32
$265
$0
$346
$202
$162
$1,036
$57
$66
$531
$0
$672
$382
$306
$2,014
$120
$141
$1,100
$0
$1,408
$728
$577
$4,073
                                               Option 2
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$10
$0-$3
$0 - $25
$0
$0 - $83
$0 - $23
n/a
$0 - $144
$20
$29
$239
$0
$263
$178
$162
$892
$47
$63
$506
$0
$589
$359
$306
$1,870
$110
$138
$1,074
$0
$1,325
$704
$577
$3,929
$30
$32
$265
$0
$346
$202
$162
$1,036
$57
$66
$531
$0
$672
$382
$306
$2,014
$120
$141
$1,100
$0
$1,408
$728
$577
$4,073
                                                                                               E2A-9

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2
                 Table E2A-7: Summary of Monetized Benefits for Existing Phase III Facilities"
                                        (thousands; 2003$; discounted at 3%)
Region
Annualized Use Benefits of I&E Reductions
Annualized
Commercial
Fishing
Recreational Fishing
Low Mean High
Total Use Value"
Low Mean
High
                                                         Option 1
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$10
$0-$3
$0 - $25
$0
$0 - $83
*cn $.")t.
4>U - 4>ZJ
n/a
SO - $144
$20
$29
$239
$0
$263
$178
$182
$912
$47
$63
$506
$0
$589
$359
$344
$1,908
$110
$138
$1,074
$0
$1,325
$704
$649
$4,001
$30
$32
$265
$0
$346
$202
$182
$1,056
$57
$66
$531
$0
$672
$382
$344
$2,052
$120
$141
$1,100
$0
$1,408
$728
$649
$4,146
                                                         Option 6
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$10
$0-$3
$0 - $26
$0
$0 - $83
$0 - $25
n/a
$0 - $146
$20
$29
$241
$0
$263
$192
$189
$934
$47
$63
$510
$0
$589
$386
$357
$1,952
$110
$138
$1,083
$0
$1,325
$758
$673
$4,087
$30
$32
$267
$0
$346
$217
$189
$1,080
$57
$66
$535
$0
$672
$411
$357
$2,098
$120
$141
$1,109
$0
$1,408
$783
$673
$4,233
  a    All benefits presented in this table are annualized. These annualized benefits represent the value of all benefits generated over the
      time frame of the analysis, discounted to 2007, and then annualized over a 30-year period.
  b    The total monetizable value of I&E reductions includes use benefits only.  EPA evaluated non-use benefits only qualitatively.  A
      range of recreational fishing benefits is provided, based on the Krinsky and Robb technique to estimated the 95th and 5th
      percentile limits on the marginal value per fish predicted by EPA's meta-analysis (see chapter A5 of the RBA).  Commercial
      fishing benefits are computed based on a range from 0% to 40% of the change in gross revenue (see Chapter A4 of the RBA).  To
      calculate the total use value columns (low, mean, and high), the high end value for commercial fishing benefits is added to the low,
      mean, and high values for recreational fishing benefits, respectively.
  0    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with
      these options.
  d    No significant commercial fishing takes place in the Inland region, and thus this region is excluded from the commercial fishing
      benefits analysis.

  Source:  U.S. EPA Analysis, 2004.
E2A-10

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2

Table E2A-8: Summary of Monetized Benefits for Existing Phase III
(thousands; 2003$, discounted at 7%)
Region
Facilities"

Annualized Use Benefits of I&E Reductions
Annualized
Commercial
Fishing
Recreational Fishing
Low Mean High
Total Use Value"
Low
Mean
High
                                                       Option 3
California
North Atlantic
Mid-Atlantic
South Atlantic'
Gulf of Mexico
Great Lakes
Inlandd
National Total
$0-$4
$0-$2
$0-$19
$0
$0 - $64
$0-$18
n/a
SO - $107
$8
$22
$181
$0
$206
$138
$144
$700
$19
$49
$383
$0
$462
$277
$273
$1,463
$45
$107
$814
$0
$1,038
$543
$515
$3,063
$12
$25
$201
$0
$270
$156
$144
$807
$23
$51
$403
$0
$526
$295
$273
$1,570
$49
$109
$834
$0
$1,102
$561
$515
$3,170
                                                       Option 4
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
$0-$8
$0-$2
$0-$19
$0
$0 - $66
$0-$18
n/a
$0-$114
$16
$22
$184
$0
$209
$139
$133
$703
$37
$49
$388
$0
$469
$280
$251
$1,473
$86
$107
$825
$0
$1,055
$549
$473
$3,095
$24
$25
$203
$0
$275
$157
$133
$816
$44
$51
$408
$0
$535
$298
$251
$1,587
$94
$109
$844
$0
$1,120
$567
$473
$3,208
                                                       Option 2
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
*cn U - 4)0
$0-$2
$0-$19
$0
$0 - $66
$0-$18
n/a
$0-$114
$16
$22
$184
$0
$209
$139
$133
$703
$37
$49
$388
$0
$469
$280
$251
$1,473
$86
$107
$825
$0
$1,055
$549
$473
$3,095
$24
$25
$203
$0
$275
$157
$133
$816
$44
$51
$408
$0
$535
$298
$251
$1,587
$94
$109
$844
$0
$1,120
$567
$473
$3,208
                                                       Option 1
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
$0-$8
$0-$2
$0-$19
$0
$0 - $66
$0-$18
n/a
$16
$22
$184
$0
$209
$139
$149
$37
$49
$388
$0
$469
$280
$281
$86
$107
$825
$0
$1,055
$549
$531
$24
$25
$203
$0
$275
$157
$149
$44
$51
$408
$0
$535
$298
$281
$94
$109
$844
$0
$1,120
$567
$531
                                                                                                               E2A-11

-------
Section 316(b) Proposed Rule: Phase III -EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E2
                 Table E2A-8: Summary of Monetized Benefits for Existing Phase III Facilities"
                                        (thousands; 2003$, discounted at 7%)
                                                    Annualized Use Benefits of I&E Reductions
Region
National Total
Annualized
Commercial
Fishing
SO- $114
Recreational Fishing
Low
$719
Mean High
$1,504 $3,152
Total Use Value"
Low
$832
Mean
$1,617
High
$3,266
                                                         Option 6
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland4
National Total
*cn U - 4)0
$0-$2
$0 - $20
$0
$0 - $66
$0 - $20
n/a
$0-$115
$16
$22
$185
$0
$209
$150
$154
$736
$37
$49
$391
$0
$469
$302
$291
$1,539
$86
$107
$831
$0
$1,055
$592
$549
$3,220
$24
$25
$205
$0
$275
$170
$154
$852
$44
$51
$411
$0
$535
$322
$291
$1,654
$94
$109
$850
$0
$1,120
$612
$549
$3,335
  a    All benefits presented in this table are annualized. These annualized benefits represent the value of all benefits generated over the
      time frame of the analysis, discounted to 2007, and then annualized over a 30-year period.
  b    The total monetizable value of I&E reductions includes use benefits only.  EPA evaluated non-use benefits only qualitatively. A
      range of recreational fishing benefits is provided, based on the Krinsky and Robb technique to estimated the 95th and 5th
      percentile limits on the marginal value per fish predicted by EPA's meta-analysis (see chapter A5 of the RBA).  Commercial
      fishing benefits are computed based on a range from 0% to 40% of the change in gross revenue (see Chapter A4 of the RBA). To
      calculate the total use value columns (low, mean, and high), the high end value for commercial fishing benefits is added to the low,
      mean, and high values for recreational fishing benefits, respectively.
  c    No I&E reductions are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with
      these options.
  d    No significant commercial fishing takes place in the Inland region, and thus this region is excluded from the commercial fishing
      benefits analysis.

  Source:  U.S. EPA Analysis, 2004.
E2A-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                              E3: Benefit-Cost Analysis
     Chapter  E3: Comparison  of Benefits  and
                                    Social Costs
                                                CHAPTER CONTENTS
                                                E3-1 Comparison of Benefits and Social Costs by
                                                    Option	 E3-2
                                                E3-2 Incremental Analysis of Benefits and Social Costs E3-7
                                                E3-3 Break-Even Analysis of Potential Non-Use
                                                    Benefits	 E3-8
                                                Glossary	 E3-12
                                                References  	 E3-13
                                                Appendix to Chapter E3	E3A-1
INTRODUCTION

This chapter compares total monetized benefits to
total social costs for the options analyzed for the
Proposed Section 316(b) Rule for Phase III
Facilities. Benefits and costs are compared on two
bases: (1) for each of the options analyzed and (2)
incrementally across options.  For more information
on the analysis of social costs and benefits, see
Chapter El: Summary of Social Costs and Chapter
E2: Summary of Benefits.

EPA considered and analyzed three proposed options and five other options for Phase III existing facilities
(Manufacturers and Generators) in developing the proposed rule.  New offshore oil and gas extraction facilities
were excluded from the comparison of benefits and costs because EPA was unable to estimate benefits for this
industry segment.  This  chapter presents results for the three proposed options for existing facilities: the "50 MOD
for All Waterbodies" option ("50 MOD All"), the "200 MOD for All Waterbodies" option ("200 MOD All"), and
the "100 MOD for Certain Waterbodies" option ("100 MOD CWB"). Summary results for five other options
evaluated in regulation development are presented in the appendix to this chapter.

Table  E3-1 shows compliance action assumptions for the three proposed options based on the performance
standard each facility would need to meet (depending on each facility's waterbody type, design intake flow,
capacity utilization, and annual intake flow as a percent of source waterbody mean annual flow) and its baseline
technologies in-place.
               Table E3-1: Number of Existing Phase III Facilities by Compliance Action"
Facility Compliance Action
Total Facilities Potentially Subject to Regulation
(excluding baseline closures)
Facilities Subject to Best Professional Judgment
Facilities Subject to National Categorical Requirements
No compliance actionb
Impingement controls only
Impingement and entrainment controls
50 MGD All
603
468
136
32
37
66
200 MGD All
603
579
25
2
3
19
100 MGD CWB
603
584
19
1
0
18
 a   Alternative less stringent requirements based on site-specific assessments of costs, or costs and benefits are allowed. Estimation
     of compliance responses is uncertain because the number of facilities requesting alternative less stringent requirements based on
     these site-specific assessments is unknown.
 b   These facilities meet compliance requirements in the baseline and thus would require no action to comply with the regulation.

 Source:  U.S. EPA Analysis, 2004.
                                                                                             E3-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis            E3: Benefit-Cost Analysis

E3-1   COMPARISON OF BENEFITS AND SOCIAL COSTS BY OPTION

The preceding chapters, Chapter El: Summary of Social Costs and Chapter E2: Summary of Benefits, present
estimates of total social cost and benefit for the three proposed and five other options evaluated in developing the
316(b) Phase III regulation. Based on these values of estimated benefits and social costs, EPA calculated the net
monetized benefit to society of each option.

As documented in Chapter E2: Summary of Benefits, the monetized benefit values developed by EPA for the
316(b) Phase III regulation, and included in the net benefits calculation presented in this chapter, include only use
benefit values for commercial and recreational fishing. EPA was unable to estimate, at this time, a monetized
value of non-use benefits from reduced impingement and entrainment (I&E). As a result, the monetized benefit
value that is compared with the estimated value of total social cost in this benefit-cost comparison, is narrow in
conceptual  scope and omits a benefit category with potentially large monetary value. Specifically, the Agency
was unable to monetize benefits  for 96.7% of the age-one equivalent losses of all commercial, recreational, and
forage species considered for the options for Phase III existing facilities. As a result, the benefits estimates used
in this analysis represent the benefits associated with only about 3.3% of the total avoided loss in age-one
equivalents. Accordingly, the net benefit values presented in this chapter are based on comparison of a
substantially complete estimate of costs to society with a substantially incomplete estimate of benefits.

Table E3-2, below, presents EPA's estimates of use benefits and social  costs for the three proposed options for
existing facilities, at 3% and  7% discount rates.  At a 3% discount rate,  EPA estimates that social costs exceed use
benefits by $45.4 million under the 50 MOD All option, $21.5 million underthe 200 MOD All option, and $16.2
million underthe 100 MOD CWB option. At a 7% discount rate,  social costs exceed use benefits by $48.6
million underthe 50 MGD All option, $23.1 million underthe 200 MGD All option, and $17.2 million underthe
100 MGD CWB option.  These values are all in dollars as of mid-year 2003 and are based on the discounting of
costs and benefits to beginning of year 2007, the assumed date when  the proposed rule would take effect.
E3-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
          Table E3-2: Total Benefits, Social Costs, and Net Benefits for Existing Phase III Facilities
                                         by Option (millions; 2003$)
Option
Total Monetized Use Benefits3
Low
Mean High
Total Social
Costs
Net Benefits Based on
Use Benefits Only"
Low Mean High
                                                3% discount rate
50 MOD All
200 MOD All
100 MOD CWB
$1.0
$0.6
$0.7
$1.9
$1.3
$1.4
$3.8
$2.5
$2.9
$47.3
$22.8
$17.6
($46.4)
($22.1)
($16.9)
($45.4)
($21.5)
($16.2)
($43.5)
($20.2)
($14.7)
                                                7% discount rate
50 MOD All
200 MOD All
100 MOD CWB
$0.8
$0.5
$0.6
$1.5
$1.0
$1.1
$3.0
$2.0
$2.3
$50.1
$24.1
$18.3
($49.3)
($23.6)
($17.7)
($48.6)
($23.1)
($17.2)
($47.1)
($22.1)
($16.0)
 a   The total monetizable value of I&E reductions includes use benefits only. EPA evaluated non-use benefits only qualitatively.  The
     range (low, mean, and high) of annualized use values is computed by adding the high end value for commercial fishing benefits
     (based on assumed producer surplus of 40% of gross revenue) to the low, mean, and high values from recreational fishing benefits,
     respectively (see Chapter A4 of the RBA).
 b   Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.

 Source:   U.S. EPA Analysis, 2004.
This comparison of fairly complete costs and incomplete benefits provides an incomplete assessment of net
benefits to society. The proposed options are expected to provide benefits that were not accounted for in the
benefits analysis.  These benefits include reduced I&E losses offish, shellfish, and other aquatic organisms,
which, in turn, increase the numbers of individuals present, increase local and regional fishery populations (a
subset of which was accounted for in the benefits analysis), and ultimately contribute to the enhanced
environmental functioning of affected waterbodies (rivers, lakes,  estuaries, and oceans) and associated
ecosystems.  See Chapter A6 of the Regional Benefits Assessment for the Proposed Section 316(b) Rule for Phase
III Facilities (RBA) for a detailed description of the ecological benefits from reduced I&E (U.S. EPA, 2004).
Taking  into account these additional unquantified benefits of improved fisheries and aquatic ecosystem
functioning, the Agency believes that the total benefits to society of the proposed rule for Phase III existing
facilities could potentially exceed total social costs.

Tables E3-3 and E3-4 present total net benefits for existing Phase III facilities by option and region, discounted at
3% and 7%, respectively.  As reported in Tables E3-3 and E3-4, EPA estimates that costs are largest relative to
benefits in the Inland region for the 50 MGD All and 200 MGD All options, and in the  Gulf of Mexico region for
the 100 MGD CWB option.  Conversely, costs outweigh benefits by the least amount in the California region for
the 50 MGD All option, in the North Atlantic region for the 200 MGD All option, and in the Mid-Atlantic region
for the 100 MGD CWB option.
                                                                                                         E3-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
                         Table E3-3: Total Net Benefits for Existing Phase III Facilities
                            by Option and Region (millions; 2003$, discounted at 3%)
Option
Net Benefits Based on Use Benefits Only3
„ ,.„ . North
California . ,,
Atlantic
A,T-J A.H <,• South Gulf of Great T , ,
Mid-Atlantic . ,, ,. b ,„ . T , Inland
Atlantic Mexico Lakes
National
Total
                                                          Low
50 MOD All
200 MOD All
100 MOD CWB
($0.8)
$0.0
$0.0
($4.5)
($0.5)
($2.0)
($2.3)
($1.7)
($1.7)
$0.0
$0.0
$0.0
($8.7)
($3.6)
($8.7)
($9.9)
($3.9)
($4.3)
($19.5)
($12.2)
$0.0
($46.4)
($22.1)
($16.9)
                                                         Mean
50 MOD All
200 MOD All
100 MOD CWB
($0.8)
$0.0
$0.0
($4.5)
($0.5)
($1.9)
($2.0)
($1.5)
($1.5)
$0.0
$0.0
$0.0
($8.4)
($3.5)
($8.4)
($9.7)
($3.8)
($4.2)
($19.4)
($12.1)
$0.0
($45.4)
($21.5)
($16.2)
                                                          High
50 MOD All
200 MOD All
100 MOD CWB
($0.8)
$0.0
$0.0
($4.4)
($0.5)
($1.9)
($1.5)
($1.0)
($1.0)
$0.0
$0.0
$0.0
($7.7)
($3.1)
($7.7)
($9.4)
($3.6)
($4.0)
($19.1)
($11.9)
$0.0
($43.5)
($20.2)
($14.7)
 a    Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 b    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
     than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.

 Source:  U.S. EPA Analysis, 2004.
E3-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
                        Table E3-4: Total Net Benefits for Existing Phase III Facilities
                          by Option and Region (millions; 2003$, discounted at 7%)
Option
Net Benefits Based on Use Benefits Only3
„ ,.„ . North
California ...
Atlantic
Mid-Atlantic
South Gulf of „, ,T , T i j
... ,. b ,„ . Great Lakes Inland
Atlantic Mexico
National
Total
                                                       Low
50 MOD All
200 MOD All
100 MOD CWB
($1.0)
$0.0
$0.0
($5.0)
($0.5)
($2.0)
($2.2)
($1.6)
($1.6)
$0.0
$0.0
$0.0
($9.9)
($4.2)
($9.9)
($10.1)
($3.6)
($4.0)
($20.5)
($13.6)
$0.0
($49.3)
($23.6)
($17.7)
                                                       Mean
50 MOD All
200 MOD All
100 MOD CWB
($0.9)
$0.0
$0.0
($5.0)
($0.5)
($2.0)
($2.0)
($1.4)
($1.4)
$0.0
$0.0
$0.0
($9.7)
($4.1)
($9.7)
($9.9)
($3.5)
($3.9)
($20.4)
($13.5)
$0.0
($48.6)
($23.1)
($17.2)
                                                       High
50 MOD All
200 MOD All
100 MOD CWB
($0.9)
$0.0
$0.0
($4.9)
($0.4)
($1.9)
($1.6)
($1.1)
($1.1)
$0.0
$0.0
$0.0
($9.1)
($3.8)
($9.1)
($9.7)
($3.3)
($3.7)
($20.2)
($13.4)
$0.0
($47.1)
($22.1)
($16.0)
 a    Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 b    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw less
     than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.

 Source:  U.S. EPA Analysis, 2004.
Table E3-5, on the following page, provides additional detail on the net benefits calculation.  Table E3-5
compiles, for the three proposed options, the time profiles of benefits and costs as presented in the preceding
chapters. The table also reports the calculated present and annualized values of benefits and costs at 3% and 7%
discount rates.
                                                                                                              E3-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
            Table E3-5: Time Profile of Benefits and Social Costs for Existing Phase III Facilities
                                               (millions; 2003$)
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%
Annualized 3%
PV 7%
Annualized 7%
50 MGD All
Monetized
Benefits
$0.00
$0.00
$0.00
$0.01
$0.05
$0.22
$0.63
$1.28
$1.83
$2.12
$2.22
$2.27
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.29
$2.28
$2.23
$2.06
$1.66
$1.01
$0.46
$0.17
$0.06
$0.01
$37.18
$1.90
$18.56
$1.50
Total Cost
(excl. O&G)
$3.3
$10.2
$15.4
$172.6
$180.5
$74.4
$110.8
$22.2
$22.7
$18.6
$18.6
$15.3
$19.0
$44.5
$81.7
$29.2
$58.2
$22.1
$22.7
$18.6
$18.6
$15.3
$19.0
$44.5
$81.7
$29.2
$58.2
$22.1
$22.7
$18.6
$18.6
$15.3
$14.4
$12.1
$6.3
$4.1
$0.5
$0.0
$0.0
$0.0
$0.0
$0.0
$955.8
$47.3
$665.0
$50.1
200 MGD
Monetized
Benefits
$0.00
$0.00
$0.00
$0.00
$0.03
$0.11
$0.34
$0.70
$1.16
$1.40
$1.47
$1.52
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.50
$1.42
$1.19
$0.83
$0.37
$0.13
$0.06
$0.01
$24.70
$1.26
$12.21
$0.98
All
Total Cost
(excl. O&G)
$0.2
$1.4
$2.1
$129.1
$83.8
$12.3
$45.8
$7.5
$8.5
$7.5
$9.0
$7.5
$7.3
$12.7
$40.0
$14.6
$45.8
$7.4
$8.5
$7.5
$9.0
$7.5
$7.3
$12.7
$40.0
$14.6
$45.8
$7.4
$8.5
$7.5
$9.0
$7.5
$7.1
$6.8
$3.9
$3.1
$0.4
$0.0
$0.0
$0.0
$0.0
$0.0
$459.7
$22.8
$320.3
$24.1
100 MGD
Monetized
Benefits
$0.00
$0.00
$0.00
$0.00
$0.01
$0.09
$0.27
$0.85
$1.32
$1.57
$1.66
$1.70
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.72
$1.71
$1.62
$1.45
$0.87
$0.40
$0.15
$0.05
$0.01
$27.65
$1.41
$13.63
$1.10
CWB
Total Cost
(excl. O&G)
$0.6
$3.8
$3.9
$9.0
$139.7
$11.5
$35.3
$5.4
$8.3
$5.4
$6.6
$5.3
$5.2
$8.3
$41.4
$12.2
$35.4
$5.4
$8.3
$5.4
$6.6
$5.3
$5.2
$8.3
$41.4
$12.2
$35.4
$5.4
$8.3
$5.4
$6.6
$5.3
$4.8
$4.7
$2.2
$1.3
$0.4
$0.0
$0.0
$0.0
$0.0
$0.0
$355.9
$17.6
$242.5
$18.3
 Source: U.S. EPA Analysis, 2004.
E3-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
E3-2   INCREMENTAL ANALYSIS OF BENEFITS AND SOCIAL COSTS

In addition to comparing benefits and costs for each proposed option, as presented in the preceding section, EPA
also analyzed the benefits and costs of the three options on an incremental basis.  The comparison in the
preceding section addresses the simple quantitative relationship between estimated benefits and costs for each
option by itself: for a given option, which is greater - benefits or costs - and what is the amount of difference? In
contrast, incremental analysis looks at the differential relationship of benefits and costs across options and poses a
different question: as increasingly more costly options are considered, by what amount do benefits, costs, and net
benefits change from option to option? Incremental benefit-cost analysis provides insight into the net gain to
society from imposing increasingly more costly requirements and may aid regulatory decision-makers in choosing
among a set of regulatory proposals that otherwise have a similar quantitative relationship between benefits and
costs based on a one-option-at-a-time comparison.

The Agency conducted the incremental benefit-cost analysis by calculating, for each option, the change in net
benefits, from option to option, in moving from the least costly option to successively more costly options. As
described previously, the three proposed options - the 50 MOD All, 200 MOD All, and 100 MOD CWB
options - differ in terms of design intake  flow (DIP) applicability threshold and affected waterbodies. Thus the
difference in benefits and costs across the options derives from the number of facilities each option is expected to
cover and what types of waterbodies are affected. As reported in Table E3-6, at a 3% discount rate, the
incremental change in net benefits in moving  from the 100 MGD CWB option to  the 200 MGD All option is -$5.3
million, and from the 200 MGD All option to the 50 MGD All option, is -$23.9 million. Thus, for both
incremental steps, calculated net benefits become  increasingly more negative but the step from the 200 MGD All
option to the 50 MGD All option is more costly to society, on a net benefit basis,  than the  step from the 100 MGD
CWB option to the 200 MGD All option. The same pattern of change occurs for the calculations under a 7%
discount rate: the incremental change in net benefits in moving from the 100 MGD CWB option to the 200 MGD
All option is -$6.0 million, and from the 200 MGD All option to the 50 MGD All option, is -$25.4 million.
      Table E3-6: Incremental Benefit-Cost Analysis for Existing Phase III Facilities (millions; 2003$)
Option3
Net Benefits Based on
Use Benefits Only"
Low Mean High
Incremental Net Benefits0
Low Mean High
                                              3% discount rate
100 MGD CWB
200 MGD All
50 MGD All
($16.9)
($22.1)
($46.4)
($16.2)
($21.5)
($45.4)
($14.7)
($20.2)
($43.5)
n/a
($5.2)
($24.2)
n/a
($5.3)
($23.9)
n/a
($5.5)
($23.3)
                                               7% discount rate
100 MGD CWB
200 MGD All
50 MGD All
($17.7)
($23.6)
($49.3)
($17.2)
($23.1)
($48.6)
($16.0)
($22.1)
($47.1)
n/a
($5.9)
($25.7)
n/a
($6.0)
($25.4)
n/a
($6.1)
($24.9)
 a   Options are presented in order of increasing applicability, based on the number of facilities regulated.
 b   Net benefits are computed by subtracting total annualized costs from total annual use benefits.  The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 c   Incremental net benefits are equal to the difference between net benefits of a given option and the net benefits of the previous less
     stringent option.

 Source: U.S. EPA Analysis, 2004.
                                                                                                      E3-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis           E3: Benefit-Cost Analysis

E3-3   BREAK-EVEN ANALYSIS OF POTENTIAL NON-USE BENEFITS

As described in Section E3-1, above, EPA's monetized estimates of benefits for the 316(b) Phase III regulation
consider only the use benefit values for commercial and recreational fishing, and exclude non-use benefits.
Estimating non-use benefit values is a very challenging and uncertain exercise, particularly when primary
research using stated preference methods is not a feasible option (as is the case for the proposed rulemaking). In
Chapter A3 of the RBA, EPA described alternative approaches for developing non-use benefit estimates based on
benefits transfer and associated methods. Because of the uncertainty in estimating the non-use benefits of the
options evaluated for the proposed rule, the Agency assessed non-use benefits only qualitatively (see Chapter A6
of RBA for a qualitative assessment of non-use benefits). As a result, the comparison of costs and benefits
presented in Sections E3-1 and E3-2 involves a substantially more complete accounting of costs than of benefits.
On the basis of this limited, incomplete accounting of benefits and costs, EPA found that costs exceed use benefits
for each of the three proposed options.

Although EPA did not specifically estimate the non-use benefits of the 316(b) Phase III regulation, it is possible
to calculate the amount of non-use benefits that would be needed for the regulation's benefits to equal the
estimated total costs (the "break-even" non-use benefits value). Regulatory decision-makers may then judge the
reasonableness of these required values in assessing whether the regulation is likely, overall, to achieve total
benefits to society that exceed costs.

To perform this break-even analysis, EPA subtracted the estimated  commercial and recreational use benefits from
the estimated annual costs.  EPA then used this required residual to calculate the non-use benefit value, in terms
of annual willingness-to-pay (WTP), needed for total benefits to equal total costs. This calculation was done in
two different ways: (1) on a per household basis and (2) on a per age-1 equivalent basis. EPA performed this
analysis using the regional studies framework as described in the  RBA.  This approach assumes that all of the
facilities in the sample weight of a given sample facility are in the same benefits analysis region as the sample
facility.

For the WTP per household analysis, this approach also assumes that the size and other characteristics of potential
use and non-use  benefit populations, which are assessed for the sample facility, may be extended to the weight of
the sample facility. Although this assumption  embeds considerable uncertainty, it permits the estimation of a non-
use benefit population for each facility, which  may then be used to calculate the WTP value by household that
equates total benefits and total costs, on a sample-weighted basis, for each option. For this analysis, EPA
assumed that only anglers fishing in the region and households within a 25-mile radius of the facility hold non-use
values for the affected resources (BLS, 2000).:

At the national level, EPA estimated the following (see Table E3-7  below):

    *•   WTP per household.  Under the 50 MGD All option, non-use benefit values per household would have
        to be $1.99 (3% discount rate) and $2.13 (7% discount rate) for total annual benefits to equal total
        annualized costs. Under the 200 MGD All option, which applies to the next smaller set of facilities, these
        values decrease to $1.87 (3% discount rate) and $2.01 (7% discount rate). Under the 100 MGD CWB
        option, which applies to the smallest set of facilities of the three proposed options, these values decrease,
        to $1.43 (3% discount rate) and $1.52  (7% discount rate).

    *•   WTP per age-1 equivalent. Under the 50 MGD All option, non-use benefit values per age-1 equivalent
        would have to be $0.92 (3% discount rate) and $0.98 (7% discount rate) for total annual benefits to equal
        total annualized costs.  Under the 200 MGD All option, which applies to the next smaller set of facilities,
        these values decrease to $0.63  (3% discount rate) and $0.68 (7% discount rate).  Under the 100 MGD
        CWB option, which applies to the smallest set of facilities of the three proposed options, these values
        decrease, to $0.54 (3% discount rate) and $0.58 (7% discount rate).
    1 See chapter E2 for details on the estimation of age-1 equivalents.

E3-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
    Table E3-7: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
                    Costs for Existing Phase III Facilities - Break-Even Analysis (2003$)
Option
Total
Social
Costs
(millions)
Mean Value
of Use
Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
($)
Reduction of
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent
($)
                                              3% Discount Rate
50 MOD All
200 MOD All
100 MOD CWB
$47.3
$22.8
$17.6
$1.9
$1.3
$1.4
$45.4
$21.5
$16.2
22,784,450
11,524,368
11,328,241
$1.99
$1.87
$1.43
49,493,000
34,038,000
29,774,000
$0.92
$0.63
$0.54
                                               7% Discount Rate
50 MOD All
200 MOD All
100 MOD CWB
$50.1
$24.1
$18.3
$1.5
$1.0
$1.1
$48.6
$23.1
$17.2
22,784,450
11,524,368
11,328,241
$2.13
$2.01
$1.52
49,493,000
34,038,000
29,774,000
$0.98
$0.68
$0.58
 a   The non-use benefits category in this table may include some categories of use values that were not taken into account by the
     recreation and commercial fishing analyses.
 b   The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
     ecological services (e.g., population, health, sustainability, and overall ecosystem health).

 Source: U.S. EPA Analysis, 2004.
EPA also calculated the annual WTP needed on a per household basis and a per age-1 equivalent basis at the
regional level (see Tables E3-8 and E3-9 below).  EPA estimated the following:

    *•   WTP per household.  The Gulf of Mexico region has the highest estimated annual break-even WTP
        values per household with $6.38, $13.83, and $6.38 (3% discount rate) and $7.34, $16.31, and $7.34 (7%
        discount rate) under the 50 MOD All, the 200 MOD All, and the 100 MOD CWB options, respectively.
        The Mid-Atlantic region has the lowest estimated annual break-even WTP values per household with
        $0.35, $0.27, and $0.27 (3% discount rate) and $0.35, $0.25, and $0.25 (7% discount rate) under the 50
        MOD All, the 200 MOD All, and the 100 MOD CWB options, respectively.

    »•   WTP per age-1 equivalent.  The North Atlantic region has the highest estimated annual break-even
        WTP value per age-1 equivalent with $4.84, $2.51, and $2.56 (3% discount rate) and $5.37, $2.28, and
        $2.62 (7% discount rate) under the 50 MOD All, the 200 MOD All, and the 100 MOD CWB options,
        respectively. The Mid-Atlantic region has the lowest estimated annual break-even WTP values per age-1
        equivalent with $0.15,  $0.13, and $0.13 (3% discount rate) and $0.15, $0.12, and $0.12 (7% discount
        rate) under the 50 MOD All, the 200 MOD All, and the  100 MOD CWB options, respectively.
                                                                                                       E3-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
     Table E3-8: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
     Costs for Existing Phase III Facilities - Break-Even Analysis by Regions (2003$, discounted at 3%)
Option
Total Social
Costs
(millions)
Mean Value
of Use
Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
(S)
Reduction of
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent
(S)
                                                      50MGDAU
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$0.8
$4.6
$2.6
$0.0
$9.1
$10.1
$19.7
$47.3
$0.0d
$0.1
$0.5
$0.0
$0.6
$0.3
$0.3
$1.9
$0.8
$4.5
$2.0
$0.0
$8.4
$9.7
$19.4
$45.4
1,166,416
2,129,180
5,887,031
0
1,322,480
4,064,660
8,214,682
22,784,450
$0.70
$2.11
$0.35
$0.00
$6.38
$2.40
$2.36
$1.99
383,000
930,000
13,400,000
0
8,380,000
11,600,000
14,800,000
49,493,000
$2.14
$4.84
$0.15
$0.00
$1.01
$0.84
$1.31
$0.92
                                                     200 MOD All
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$0.0
$0.5
$2.0
$0.0
$3.8
$4.1
$12.3
$22.8
$0.0
$o.od
$0.5
$0.0
$0.3
$0.2
$0.2
$1.3
$0.0
$0.5
$1.5
$0.0
$3.5
$3.8
$12.1
$21.5
0
1,699,855
5,603,551
0
251,666
2,388,297
1,580,998
11,524,368
$0.00
$0.29
$0.27
$0.00
$13.83
$1.60
$7.65
$1.87
0
198,000
11,900,000
0
4,580,000
7,710,000
9,650,000
34,038,000
$0.00
$2.51
$0.13
$0.00
$0.76
$0.50
$1.25
$0.63
                                                    100MGDCWB
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$0.0
$2.0
$2.0
$0.0
$9.1
$4.5
$0.0
$17.6
$0.0
$0.1
$0.5
$0.0
$0.6
$0.3
$0.0
$1.4
$0.0
$1.9
$1.5
$0.0
$8.4
$4.2
$0.0
$16.2
0
1,989,096
5,603,551
0
1,322,480
2,413,114
0
11,328,241
$0.00
$0.97
$0.27
$0.00
$6.38
$1.74
$0.00
$1.43
0
754,000
11,900,000
0
8,380,000
8,740,000
0
29,774,000
$0.00
$2.56
$0.13
$0.00
$1.01
$0.48
$0.00
$0.54
 a    The non-use benefits category in this table may include some categories of use values that were not taken into account by the
      recreation and commercial fishing analyses.
 b    The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
      ecological services (e.g., population, health, sustainability, and overall ecosystem health).
 0    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw
      less than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.
 d    Positive non-zero value less than  $50,000.
 Source: U.S. EPA Analysis, 2004.
E3-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
E3: Benefit-Cost Analysis
     Table E3-9: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
     Costs for Existing Phase III Facilities - Break-Even Analysis by Regions (2003$, discounted at 7%)
Option
Total
Social
Costs
(millions)
Mean Value
of Use
Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
($)
Reduction of
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent1"
($)
                                                      50MGDAU
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland
National Total
$1.0
$5.0
$2.4
$0.0
$10.2
$10.2
$20.6
$50.1
$o.od
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.5
$0.9
$5.0
$2.0
$0.0
$9.7
$9.9
$20.4
$48.6
1,166,416
2,129,180
5,887,031
0
1,322,480
4,064,660
8,214,682
22,784,450
$0.81
$2.35
$0.35
$0.00
$7.34
$2.45
$2.48
$2.13
383,000
930,000
13,400,000
0
8,380,000
11,600,000
14,800,000
49,493,000
$2.48
$5.37
$0.15
$0.00
$1.16
$0.86
$1.38
$0.98
                                                     200MGDAII
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland
National Total
$0.0
$0.5
$1.8
$0.0
$4.4
$3.7
$13.7
$24.1
$0.0
$o.od
$0.4
$0.0
$0.3
$0.2
$0.2
$1.0
$0.0
$0.5
$1.4
$0.0
$4.1
$3.5
$13.5
$23.1
0
1,699,855
5,603,551
0
251,666
2,388,297
1,580,998
11,524,368
$0.00
$0.27
$0.25
$0.00
$16.31
$1.47
$8.56
$2.01
0
198,000
11,900,000
0
4,580,000
7,710,000
9,650,000
34,038,000
$0.00
$2.28
$0.12
$0.00
$0.90
$0.45
$1.40
$0.68
                                                    100MGDCWB
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of Mexico
Great Lakes
Inland
National Total
$0.0
$2.0
$1.8
$0.0
$10.2
$4.1
$0.0
$18.3
$0.0
$o.od
$0.4
$0.0
$0.5
$0.2
$0.0
$1.1
$0.0
$2.0
$1.4
$0.0
$9.7
$3.9
$0.0
$17.2
0
1,989,096
5,603,551
0
1,322,480
2,413,114
0
11,328,241
$0.00
$0.99
$0.25
$0.00
$7.34
$1.62
$0.00
$1.52
0
754,000
11,900,000
0
8,380,000
8,740,000
0
29,774,000
$0.00
$2.62
$0.12
$0.00
$1.16
$0.45
$0.00
$0.58
 a    The non-use benefits category in this table may include some categories of use values that were not taken into account by the
      recreation and commercial fishing analyses.
 b    The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
      ecological services (e.g., population, health, sustainability, and overall ecosystem health).
 0    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region withdraw
      less than 50 MGD and therefore would not be required to install technologies to comply with the proposed options.
 d    Positive non-zero value less than $50,000.

 Source: U.S. EPA Analysis, 2004.
                                                                                                                 E3-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis            E3: Benefit-Cost Analysis

GLOSSARY

opportunity cost: The lost value of alternative uses of resources (capital, labor, and raw materials) used in
regulatory compliance.

social cost:  The costs incurred by society as a whole as a result of the proposed rule. Social costs do not
include costs that are transfers among parties that do not represent a new cost overall.
E3-12

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis            E3: Benefit-Cost Analysis

REFERENCES

U.S. Department of Commerce, Bureau of the Census, Bureau of Labor Statistics (BLS).  2000.  "Summary File
1." Available at: http://www.census.gov/Press-Release/www/2001/sumfilel.html.

U.S. Environmental Protection Agency (U.S. EPA). 2004. The Regional Benefits Assessment for the Proposed
Section 316(b) Rule for Phase III Facilities.  EPA-821 -R-04-017. November 2004.
                                                                                                 E3-13

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis          E3: Benefit-Cost Analysis
                           THIS PAGE INTENTIONALLY LEFT BLANK
E3-14

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                                  Appendix to Chapter E3
                       Appendix  to Chapter  E3
INTRODUCTION
                                                  APPENDIX CONTENTS
                                                  E3A-1  Comparison of Benefits and Social Costs by
                                                         Option 	  E3A-1
                                                  E3A-2  Incremental Analysis of Benefits and Social
                                                         Costs 	  E3A-7
                                                  E3 A-3  Break-Even Analysis of Potential Non-Use
                                                         Benefits 	  E3A-7
This appendix presents results from EPA's analysis
of the benefits and costs of the 316(b) Phase III
regulation for five additional options evaluated for
Phase III existing facilities. Results are presented for
the comparison of benefits and costs and the
breakeven assessment of non-use benefits. As
discussed previously in Chapter E3, the benefit and
cost values presented in this appendix pertain only to
the Manufacturers and Electric Generators segments of the industries subject to Phase III regulation.

EPA estimated the compliance response for each facility under each of the other options (see Table E3A-1,
below).  In this table and the following tables, the options are listed in order of increasing cost, which reflects the
breadth of regulatory coverage based on design intake flow applicability threshold and the stringency of
compliance requirements.  For a description of this analysis, see section E3-1 above.
Table E3A-1: Number of Existing Phase III Facilities by Compliance Action"
Facility Compliance Action
Total Facilities Potentially Subject to Regulation
(excluding baseline closures)
Facilities Subject to Best Professional Judgment
Facilities Subject to National Categorical
Requirements
No compliance actionb
Impingement controls only
Impingement and entrainment controls
Option 3
603
235
368
202
100
66
Option 4
603
415
189
59
39
91
Option 2
603
235
368
184
93
91
Option 1
603
251
353
160
73
120
Option 6
603
0
603
317
114
172
 a   Alternative less stringent requirements based on a site-specific assessment of costs, or costs and benefits, are allowed.  The
     estimate of number of facilities meeting specific requirements is uncertain because the number of facilities requesting alternative
     less stringent requirements based on site-specific assessments is unknown.
 b   These facilities already meet compliance requirements.

 Source: U.S. EPA Analysis, 2004.
E3A-1    COMPARISON OF BENEFITS AND SOCIAL COSTS BY OPTION

Table E3A-2 on the following page reports benefits, costs, and net benefits for all five other options. For further
information on this analysis, see section E3-1, above.
                                                                                               E3A-1

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
          Table E3A-2: Total Benefits, Social Costs, and Net Benefits for Existing Phase III Facilities
                                            by Option (millions; 2003$)
Option
Total Monetized Use Benefits3
Low Mean High
Total Social Costs
Net Benefits Based on Use Benefits Onlyb
Low Mean High
                                                    3% Discount Rate
Option 3
Option 4
Option 2
Option 1
Option 6
$1.0
$1.0
$1.0
$1.1
$1.1
$2.0
$2.0
$2.0
$2.1
$2.1
$4.0
$4.1
$4.1
$4.1
$4.2
$65.0
$67.9
$73.7
$76.1
$95.7
($64.0)
($66.9)
($72.6)
($75.0)
($94.6)
($63.1)
($65.9)
($71.7)
($74.0)
($93.6)
($61.0)
($63.8)
($69.6)
($71.9)
($91.5)
                                                    7% Discount Rate
Option 3
Option 4
Option 2
Option 1
Option 6
$0.8
$0.8
$0.8
$0.8
$0.9
$1.6
$1.6
$1.6
$1.6
$1.7
$3.2
$3.2
$3.2
$3.3
$3.3
$69.6
$73.9
$79.3
$81.8
$102.5
($68.8)
($73.1)
($78.5)
($80.9)
($101.6)
($68.0)
($72.3)
($77.7)
($80.1)
($100.8)
($66.4)
($70.7)
($76.1)
($78.5)
($99.1)
 a    The total monetizable value of I&E reductions includes use benefits only. EPA evaluated non-use benefits only qualitatively.  The
     range (low, mean, and high) of annualized use values is computed by adding the high end value for commercial fishing benefits
     (based on assumed producer surplus of 40% of gross revenue) to the low, mean, and high values from recreational fishing benefits,
     respectively (see Chapter A4 of the RBA).
 b    Net benefits are computed by subtracting total annualized costs from total annual use benefits.  The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.

 Source:   U.S. EPA Analysis, 2004.
E3A-2

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
Tables E3A-3 and E3A-4, below and following page, report net benefits, by option and benefit study region for,
respectively, the 3% and 7% discount rate calculations. For further information on this analysis, see section E3-1,
above.
           Table E3A-3: Total Net Benefits for Existing Phase III Facilities by Option and Region
                                       (millions; 2003$, discounted at 3%)
Option

„ ,.„ . North
California . ,,
Atlantic
Net Benefits Based
,-.,.,, ,. South
Mid-Atlantic ... ,. b
Atlantic"
on Use Benefits Only3
Gulf of _ , T , T i j
,„ . Great Lakes Inland
Mexico
National
Total
                                                        Low
Option 3
Option 4
Option 2
Option 1
Option 6
($1.1)
($1.5)
($1.5)
($1.5)
($2.2)
($4.5)
($4.5)
($4.5)
($4.5)
($4.5)
($2.5)
($3.0)
($3.0)
($3.0)
($3.2)
$0.0
$0.0
$0.0
$0.0
$0.0
($9.2)
($14.2)
($14.2)
($14.2)
($14.2)
($20.4)
($22.6)
($22.6)
($22.6)
($28.4)
($25.0)
($19.5)
($25.0)
($27.4)
($39.8)
($64.0)
($66.9)
($72.6)
($75.0)
($94.6)
                                                       Mean
Option 3
Option 4
Option 2
Option 1
Option 6
($1.1)
($1.5)
($1.5)
($1.5)
($2.2)
($4.5)
($4.5)
($4.5)
($4.5)
($4.5)
($2.2)
($2.8)
($2.8)
($2.8)
($3.0)
$0.0
$0.0
$0.0
$0.0
$0.0
($8.9)
($13.8)
($13.8)
($13.8)
($13.8)
($20.2)
($22.5)
($22.5)
($22.5)
($28.2)
($24.8)
($19.4)
($24.9)
($27.2)
($39.6)
($63.1)
($65.9)
($71.7)
($74.0)
($93.6)
                                                        High
Option 3
Option 4
Option 2
Option 1
Option 6
($1.1)
($1.4)
($1.4)
($1.4)
($2.1)
($4.4)
($4.4)
($4.4)
($4.4)
($4.4)
($1.6)
($2.2)
($2.2)
($2.2)
($2.4)
$0.0
$0.0
$0.0
$0.0
$0.0
($8.1)
($13.1)
($13.1)
($13.1)
($13.1)
($19.9)
($22.1)
($22.1)
($22.1)
($27.8)
($24.5)
($19.1)
($24.6)
($26.9)
($39.3)
($61.0)
($63.8)
($69.6)
($71.9)
($91.5)
 a    Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 b    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
     the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
     option.

 Source:  U.S. EPA Analysis, 2004.
                                                                                                              E3A-3

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
           Table E3A-4: Total Net Benefits for Existing Phase III Facilities by Option and Region
                                       (millions; 2003$, discounted at 7%)
Option

„ ,.„ . North
California . ,.
Atlantic
Net
Mid-
Atlantic
Benefits Based on Use Benefits Only3
South
Atlantic"
Gulf of
Mexico
Great Lakes Inland
National
Total
                                                        Low
Option 3
Option 4
Option 2
Option 1
Option 6
($1.2)
($1.6)
($1.6)
($1.6)
($2.2)
($5.0)
($5.0)
($5.0)
($5.0)
($5.0)
($2.4)
($2.9)
($2.9)
($2.9)
($3.1)
$0.0
$0.0
$0.0
$0.0
$0.0
($10.4)
($16.7)
($16.7)
($16.7)
($16.7)
($22.7)
($24.8)
($24.8)
($24.8)
($30.7)
($25.7)
($20.5)
($25.7)
($28.1)
($41.6)
($68.8)
($73.1)
($78.5)
($80.9)
($101.6)
                                                       Mean
Option 3
Option 4
Option 2
Option 1
Option 6
($1.2)
($1.6)
($1.6)
($1.6)
($2.2)
($5.0)
($5.0)
($5.0)
($5.0)
($5.0)
($2.2)
($2.7)
($2.7)
($2.7)
($2.9)
$0.0
$0.0
$0.0
$0.0
$0.0
($10.1)
($16.5)
($16.5)
($16.5)
($16.5)
($22.6)
($24.7)
($24.7)
($24.7)
($30.5)
($25.6)
($20.4)
($25.6)
($28.0)
($41.4)
($68.0)
($72.3)
($77.7)
($80.1)
($100.8)
                                                        High
Option 3
Option 4
Option 2
Option 1
Option 6
($1.2)
($1.5)
($1.5)
($1.5)
($2.1)
($4.9)
($4.9)
($4.9)
($4.9)
($4.9)
($1.8)
($2.3)
($2.3)
($2.3)
($2.4)
$0.0
$0.0
$0.0
$0.0
$0.0
($9.6)
($15.9)
($15.9)
($15.9)
($15.9)
($22.3)
($24.4)
($24.4)
($24.4)
($30.2)
($25.4)
($20.2)
($25.4)
($27.7)
($41.2)
($66.4)
($70.7)
($76.1)
($78.5)
($99.1)
 a    Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 b    No benefits or costs are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
     the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
     option.

 Source:  U.S. EPA Analysis, 2004.
Tables E3A-5 and E3A-6 compile the time profiles of benefits and costs for the five other options. The tables
also report the calculated present and annualized values of benefits and costs at 3% and 7% discount rates.
E3A-4

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
              Table E3A-5: Time Profile of Benefits and Costs for Existing Phase III Facilities
                                  for Options 3, 4, and 2 (millions; 2003$)

Year

2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Option 3
Monetized Total Cost
Benefits
$0.00
$0.00
$0.00
$0.01
$0.05
$0.23
$0.64
$1.35
$1.91
$2.23
$2.34
$2.39
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.40
$2.39
$2.35
$2.17
$1.76
$1.06
$0.49
$0.18
$0.06
$0.02
$39.06
$1.99
$19.48
$1.57
(excl. O&G)
$3.9
$14.9
$24.8
$188.0
$196.1
$281.5
$119.0
$31.0
$30.6
$29.1
$25.9
$20.4
$25.0
$55.1
$95.6
$39.4
$66.1
$30.6
$30.6
$29.1
$25.9
$20.4
$25.0
$55.1
$95.6
$39.4
$66.1
$30.6
$30.6
$29.1
$25.9
$20.4
$18.3
$15.3
$8.8
$5.3
$1.0
$0.0
$0.0
$0.0
$0.0
$0.0
$1,313.2
$65.0
$923.8
$69.6
Option
Monetized
Benefits
$0.00
$0.00
$0.00
$0.01
$0.06
$0.23
$0.65
$1.36
$1.92
$2.25
$2.36
$2.41
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.42
$2.37
$2.19
$1.78
$1.07
$0.50
$0.18
$0.07
$0.02
$39.48
$2.01
$19.69
$1.59
4
Total Cost
(excl. O&G)
$3.3
$13.9
$23.0
$182.6
$296.5
$284.6
$117.7
$27.0
$29.9
$26.8
$24.8
$20.7
$22.6
$51.8
$91.9
$40.8
$65.2
$26.6
$29.9
$26.8
$24.8
$20.7
$22.6
$51.8
$91.9
$40.8
$65.2
$26.6
$29.9
$26.8
$24.8
$20.7
$18.0
$15.7
$8.7
$5.2
$0.9
$0.0
$0.0
$0.0
$0.0
$0.0
$1,371.2
$67.9
$980.8
$73.9
Option
Monetized
Benefits
$0.00
$0.00
$0.00
$0.01
$0.06
$0.23
$0.65
$1.36
$1.92
$2.25
$2.36
$2.41
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.43
$2.42
$2.37
$2.19
$1.78
$1.07
$0.50
$0.18
$0.07
$0.02
$39.48
$2.01
$19.69
$1.59
2
Total Cost
(excl. O&G)
$3.9
$16.0
$27.4
$191.4
$305.5
$291.2
$124.1
$34.4
$33.6
$32.7
$28.8
$24.2
$27.3
$58.2
$100.0
$46.6
$71.4
$33.9
$33.6
$32.7
$28.8
$24.2
$27.3
$58.2
$100.0
$46.6
$71.4
$33.9
$33.6
$32.7
$28.8
$24.2
$20.7
$17.6
$10.3
$6.2
$1.3
$0.0
$0.0
$0.0
$0.0
$0.0
$1,487.3
$73.7
$1,053.3
$79.3
 Source: U.S. EPA Analysis, 2004.
                                                                                                       E3A-5

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
              Table E3A-6: Time Profile of Benefits and Costs for Existing Phase III Facilities
                                    for Options 1 and 6 (millions; 2003$)

Year

2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
PV 3%
Annualized 3%
PV 7%
Annualized 7%
Option 1
Monetized Benefits

$0.00
$0.00
$0.00
$0.01
$0.06
$0.24
$0.67
$1.39
$1.96
$2.29
$2.41
$2.46
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.47
$2.42
$2.23
$1.81
$1.09
$0.51
$0.18
$0.07
$0.02
$40.23
$2.05
$20.07
$1.62
Total Cost
(excl. O&G)
$3.9
$16.1
$27.9
$206.0
$306.9
$295.9
$125.3
$36.1
$34.9
$34.5
$30.2
$25.4
$28.6
$61.7
$101.8
$51.2
$72.7
$35.0
$34.9
$34.5
$30.2
$25.4
$28.6
$61.7
$101.8
$51.2
$72.7
$35.0
$34.9
$34.5
$30.2
$25.4
$21.9
$18.6
$11.4
$6.2
$1.4
$0.0
$0.0
$0.0
$0.0
$0.0
$1,535.7
$76.1
$1,085.6
$81.8
Option 6
Monetized Benefits

$0.00
$0.00
$0.00
$0.01
$0.06
$0.25
$0.69
$1.42
$2.00
$2.34
$2.46
$2.51
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.53
$2.52
$2.47
$2.27
$1.84
$1.11
$0.53
$0.19
$0.07
$0.02
$41.12
$2.10
$20.52
$1.65
Total Cost
(excl. O&G)
$6.0
$23.8
$38.7
$266.2
$410.1
$316.7
$137.6
$49.6
$46.8
$44.5
$41.1
$35.5
$39.6
$76.5
$129.5
$69.7
$84.3
$47.7
$46.7
$44.5
$41.1
$35.5
$39.6
$76.5
$129.5
$69.7
$84.3
$47.7
$46.7
$44.5
$41.1
$35.5
$28.7
$23.6
$14.2
$8.1
$2.2
$0.0
$0.0
$0.0
$0.0
$0.0
$1,932.0
$95.7
$1,360.3
$102.5
 Source: U.S. EPA Analysis, 2004.
E3A-6

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
E3A-2    INCREMENTAL ANALYSIS OF BENEFITS AND SOCIAL COSTS

EPA conducted an incremental analysis of benefits and social costs to determine as increasingly more costly
options are considered, by what amount do benefits, costs, and net benefits change from option to option. Table
E3A-7, below, reports this analysis for the five other options evaluated. For a description of this analysis, see
section E3-2 above.
Table E3A-7: Incremental Benefit-Cost Analysis
Option3
for Existing Phase III Facilities (millions; 2003$)
Net Benefits Based on
Use Benefits Only"
Low Mean High
Incremental Net Benefits0
Low Mean High
                                              3% discount rate
Option 3
Option 4
Option 2
Option 1
Option 6
($64.0)
($66.9)
($72.6)
($75.0)
($94.6)
($63.1)
($65.9)
($71.7)
($74.0)
($93.6)
($61.0)
($63.8)
($69.6)
($71.9)
($91.5)
n/a
($2.9)
($5.8)
($2.4)
($19.6)
n/a
($2.9)
($5.8)
($2.4)
($19.6)
n/a
($2.8)
($5.8)
($2.6)
($19.5)
                                              7% discount rate
Option 3
Option 4
Option 2
Option 1
Option 6
($68.8)
($73.1)
($78.5)
($80.9)
($101.6)
($68.0)
($72.3)
($77.7)
($80.1)
($100.8)
($66.4)
($70.7)
($76.1)
($78.5)
($99.1)
n/a
($4.3)
($5.5)
($2.4)
($20.7)
n/a
($4.3)
($5.5)
($2.4)
($20.7)
n/a
($4.3)
($5.5)
($2.4)
($20.6)
 a   Options are presented in order of increasing applicability, based on the number of facilities regulated.
 b   Net benefits are computed by subtracting total annualized costs from total annual use benefits. The net benefits presented here are
     based on the comparison of a substantially complete measure of social costs with an incomplete measure of benefits and should be
     interpreted with caution.
 c   Incremental net benefits are equal to the difference between net benefits of a given option and the net benefits of the previous less
     stringent option.

 Source: U.S. EPA Analysis, 2004.
E3A-3    BREAK-EVEN ANALYSIS OF POTENTIAL NON-USE BENEFITS

EPA conducted a break-even analysis for each option to determine the per household value and per age-1
equivalent value of non-use benefits needed for total annual benefits to equal total annual costs. Table E3A-8
presents the results at the national level; Tables E3A-9 and E3A-10 present results at the regional level. For a
description of this analysis, see section E3-3 above.
                                                                                                    E3A-7

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
    Table E3A-8: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
                      Cost for Existing Phase III Facilities - Break-Even Analysis (2003$)
Option
Total Social
Costs
(millions)
Mean Value of
Use Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
($)
Reduction in
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent1"
($)
                                                  3% Discount Rate
Option 3
Option 4
Option 2
Option 1
Option 6
$65.0
$67.9
$73.7
$76.1
$95.7
$2.0
$2.0
$2.0
$2.1
$2.1
$63.1
$65.9
$71.7
$74.0
$93.6
31,890,286
26,772,975
26,772,975
32,298,995
38,143,532
$1.98
$2.46
$2.68
$2.29
$2.45
53,171,000
52,261,000
52,261,000
54,361,000
56,161,000
$1.19
$1.26
$1.37
$1.36
$1.67
                                                   7% Discount Rate
Option 3
Option 4
Option 2
Option 1
Option 6
$69.6
$73.9
$79.3
$81.8
$102.5
$1.6
$1.6
$1.6
$1.6
$1.7
$68.0
$72.3
$77.7
$80.1
$100.8
31,890,286
26,772,975
26,772,975
32,298,995
38,143,532
$2.13
$2.70
$2.90
$2.48
$2.64
53,171,000
52,261,000
52,261,000
54,361,000
56,161,000
$1.28
$1.38
$1.49
$1.47
$1.79
 a    The non-use benefits category in this table may include some categories of use values that were not taken into account by the
      recreation and commercial fishing analyses.
 b    The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
      ecological services (e.g., population, health, sustainability, and overall ecosystem health).

 Source:  U.S. EPA Analysis, 2004.
E3A-8

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                 Appendix to Chapter E3
   Table E3A-9: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
     Costs for Existing Phase III Facilities - Break-Even Analysis by Regions (2003$, discounted at 3%)
Option
Total Social
Costs
(millions)
Mean Value
of Use
Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
(S)
Reduction of
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent1"
(S)
                                                  Option 3
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.1
$4.6
$2.7
$0.0
$9.5
$20.6
$25.2
$65.0
$o.od
$0.1
$0.5
$0.0
$0.7
$0.4
$0.3
$2.0
$1.1
$4.5
$2.2
$0.0
$8.9
$20.2
$24.8
$63.1
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
13,329,383
31,890,286
$0.71
$2.11
$0.34
$0.00
$6.59
$2.86
$1.86
$1.98
391,000
930,000
13,400,000
0
8,650,000
13,200,000
16,600,000
53,171,000
$2.76
$4.84
$0.16
$0.00
$1.02
$1.53
$1.50
$1.19
                                                  Option 4
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.5
$4.6
$3.3
$0.0
$14.5
$22.8
$19.7
$67.9
$0.1
$0.1
$0.5
$0.0
$0.7
$0.4
$0.3
$2.0
$1.5
$4.5
$2.8
$0.0
$13.8
$22.5
$19.4
$65.9
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
8,212,072
26,772,975
$0.98
$2.11
$0.43
$0.00
$10.28
$3.17
$2.36
$2.46
771,000
930,000
13,600,000
0
8,860,000
13,300,000
14,800,000
52,261,000
$1.93
$4.84
$0.20
$0.00
$1.56
$1.69
$1.31
$1.26
                                                  Option 2
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.5
$4.6
$3.3
$0.0
$14.5
$22.8
$25.2
$73.7
$0.1
$0.1
$0.5
$0.0
$0.7
$0.4
$0.3
$2.0
$1.5
$4.5
$2.8
$0.0
$13.8
$22.5
$24.9
$71.7
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
8,212,072
26,772,975
$0.98
$2.11
$0.43
$0.00
$10.28
$3.17
$3.03
$2.68
771,000
930,000
13,600,000
0
8,860,000
13,300,000
14,800,000
52,261,000
$1.93
$4.84
$0.20
$0.00
$1.56
$1.69
$1.68
$1.37
 California
$1.5
$0.1
Option 1

  $1.5
1,518,773
3.98
771,000
$1.93
                                                                                                      E3A-9

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
    Table E3A-9: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
     Costs for Existing Phase III Facilities - Break-Even Analysis by Regions (2003$, discounted at 3%)
Option
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
Total Social
Costs
(millions)
$4.6
$3.3
$0.0
$14.5
$22.8
$27.5
$76.1
Mean Value
of Use
Benefits
(millions)
$0.1
$0.5
$0.0
$0.7
$0.4
$0.3
$2.1
Non-Use
Benefits
Necessary to
Break Even3
(millions)
$4.5
$2.8
$0.0
$13.8
$22.5
$27.2
$74.0
Number of
Households
2,129,180
6,491,544
0
1,344,996
7,076,410
13,738,093
32,298,995
Break-Even
WTP per
Household
($)
$2.11
$0.43
$0.00
$10.28
$3.17
$1.98
$2.29
Reduction of
I&E Losses
(Age-1
Equivalents)
930,000
13,600,000
0
8,860,000
13,300,000
16,900,000
54,361,000
Break-Even
Value per
Age-1
Equivalent1"
($)
$4.84
$0.20
$0.00
$1.56
$1.69
$1.61
$1.36
                                                        Option 6
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$2.2
$4.6
$3.5
$0.0
$14.5
$28.6
$40.0
$95.7
$0.1
$0.1
$0.5
$0.0
$0.7
$0.4
$0.4
$2.1
$2.2
$4.5
$3.0
$0.0
$13.8
$28.2
$39.6
$93.6
1,518,773
2,129,180
7,214,556
0
1,344,996
9,055,971
16,880,055
38,143,532
$1.43
$2.11
$0.41
$0.00
$10.28
$3.11
$2.35
$2.45
771,000
930,000
13,700,000
0
8,860,000
14,300,000
17,600,000
56,161,000
$2.82
$4.84
$0.22
$0.00
$1.56
$1.97
$2.25
$1.67
  a    The non-use benefits category in this table may include some categories of use values that were not taken into account by the
      recreation and commercial fishing analyses.
  b    The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
      ecological services (e.g., population, health, sustainability, and overall ecosystem health).
  c    No benefits or costs  are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
      option.
  d    Positive non-zero value less than $50,000.

  Source: U.S. EPA Analysis, 2004.
E3A-10

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
                                                                 Appendix to Chapter E3
   Table E3A-10: Estimated Value of Non
     Costs for Existing Phase III Facilities
                   Use Benefits Required for Total Benefits to Equal Total Social
                   - Break-Even Analysis by Regions (2003$, discounted at 7%)
Option
Total Social
Costs
(millions)
Mean Value
of Use
Benefits
(millions)
Non-Use
Benefits
Necessary to
Break Even3
(millions)
Number of
Households
Break-Even
WTP per
Household
(S)
Reduction of
I&E Losses
(Age-1
Equivalents)
Break-Even
Value per
Age-1
Equivalent1"
(S)
                                                  Option 3
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.2
$5.0
$2.6
$0.0
$10.7
$22.9
$25.9
$69.6
$0.0d
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.6
$1.2
$5.0
$2.2
$0.0
$10.1
$22.6
$25.6
$68.0
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
13,329,383
31,890,286
$0.79
$2.35
$0.34
$0.00
$7.54
$3.19
$1.92
$2.13
391,000
930,000
13,400,000
0
8,650,000
13,200,000
16,600,000
53,171,000
$3.07
$5.37
$0.16
$0.00
$1.17
$1.71
$1.54
$1.28
                                                  Option 4
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.6
$5.0
$3.1
$0.0
$17.0
$25.0
$20.6
$73.9
$0.0d
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.6
$1.6
$5.0
$2.7
$0.0
$16.5
$24.7
$20.4
$72.3
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
8,212,072
26,772,975
$1.03
$2.35
$0.42
$0.00
$12.25
$3.49
$2.48
$2.70
771,000
930,000
13,600,000
0
8,860,000
13,300,000
14,800,000
52,261,000
$2.03
$5.37
$0.20
$0.00
$1.86
$1.86
$1.38
$1.38
                                                  Option 2
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$1.6
$5.0
$3.1
$0.0
$17.0
$25.0
$25.9
$79.3
$0.0d
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.6
$1.6
$5.0
$2.7
$0.0
$16.5
$24.7
$25.6
$77.7
1,518,773
2,129,180
6,491,544
0
1,344,996
7,076,410
8,212,072
26,772,975
$1.03
$2.35
$0.42
$0.00
$12.25
$3.49
$3.12
$2.90
771,000
930,000
13,600,000
0
8,860,000
13,300,000
14,800,000
52,261,000
$2.03
$5.37
$0.20
$0.00
$1.86
$1.86
$1.73
$1.49
 California
$1.6
$0.0d
Option 1

  $1.6
1,518,773
$1.03
771,000
$2.03
                                                                                                     E3A-11

-------
§ 316(b) Proposed Rule: Phase III-EA, PartE: Social Costs, Benefits, and Benefit-Cost Analysis
Appendix to Chapter E3
   Table E3A-10: Estimated Value of Non-Use Benefits Required for Total Benefits to Equal Total Social
     Costs for Existing Phase III Facilities - Break-Even Analysis by Regions (2003$, discounted at 7%)
Option
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
Total Social
Costs
(millions)
$5.0
$3.1
$0.0
$17.0
$25.0
$28.3
$81.8
Mean Value
of Use
Benefits
(millions)
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.6
Non-Use
Benefits
Necessary to
Break Even3
(millions)
$5.0
$2.7
$0.0
$16.5
$24.7
$28.0
$80.1
Number of
Households
2,129,180
6,491,544
0
1,344,996
7,076,410
13,738,093
32,298,995
Break-Even
WTP per
Household
($)
$2.35
$0.42
$0.00
$12.25
$3.49
$2.04
$2.48
Reduction of
I&E Losses
(Age-1
Equivalents)
930,000
13,600,000
0
8,860,000
13,300,000
16,900,000
54,361,000
Break-Even
Value per
Age-1
Equivalent1"
($)
$5.37
$0.20
$0.00
$1.86
$1.86
$1.66
$1.47
                                                        Option 6
California
North Atlantic
Mid-Atlantic
South Atlantic0
Gulf of
Mexico
Great Lakes
Inland
National Total
$2.2
$5.0
$3.3
$0.0
$17.0
$30.8
$41.7
$102.5
$o.od
$0.1
$0.4
$0.0
$0.5
$0.3
$0.3
$1.7
$2.2
$5.0
$2.9
$0.0
$16.5
$30.5
$41.4
$100.8
1,518,773
2,129,180
7,214,556
0
1,344,996
9,055,971
16,880,055
38,143,532
$1.45
$2.35
$0.40
$0.00
$12.25
$3.37
$2.45
$2.64
771,000
930,000
13,700,000
0
8,860,000
14,300,000
17,600,000
56,161,000
$2.85
$5.37
$0.21
$0.00
$1.86
$2.13
$2.35
$1.79
  a    The non-use benefits category in this table may include some categories of use values that were not taken into account by the
      recreation and commercial fishing analyses.
  b    The non-use value per age-1 equivalent reported in the table includes the value placed on the fish's contribution to non-use
      ecological services (e.g., population, health, sustainability, and overall ecosystem health).
  c    No benefits or costs  are expected in the South Atlantic region because all potentially regulated facilities in this region already meet
      the national categorical requirements in the baseline and therefore would not be required to install technologies to comply with this
      option.
  d    Positive non-zero value less than $50,000.

  Source: U.S. EPA Analysis, 2004.
E3A-12

-------