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and workover fluids, and produced sand. It is therefore more likely to show impacts. The Gulf
6 gas-only was the only project to show an early closure due to increased costs of treatment and
workover fluids. As a small gas-only project, it bears costs for produced water and treatment and
workover fluids. The Gulf 12 oil and gas model is considered representative of a "typical" Gulf
project. The projects bear costs for produced water and produced sand. These costs for zero
discharge of NORM sand and treatment and workover fluids are included in every model run as
appropriate, and the costs are varied for the method of produced water disposal.
Change in some financial statistics is on a continuous scale, e.g., NPV, corporate cost per
BOE, and production cost per BOE. Change in two other statistics, years of production and,
therefore present value of total production, is on a discrete scale. A project either operates in a
given year, or it shuts down. In examining Table 7-25, there is no greater loss of production seen
for projects bearing the costs of zero discharge for treatment and workover fluids and produced
sand, than is associated with the costs for a given produced water option. For example, all
produced water options cause the Gulf 6 gas-only model to have a 9-year lifetime (i.e., it shuts
down one year early, see Table 7-10). The costs for zero discharge of treatment and workover
fluids also cause the Gulf 6 gas-only project to shut one year early (see Table 7-18). The
combination of these costs, however, does not lead to the project shutting down two years early.
That is, loss of production estimates are not additive due to the discrete nature of measuring the
impact.
For the parameters where the changes can measured in a continuous manner, the
impacts appear to be additive. For example, the baseline NPV for the Gulf Ib project is $939
(thousand). The costs for offshore IGF lead to a $367 (thousand, 1986 dollars) decline in the
NPV (see Table 7-11). The zero discharge of treatment and workover fluids leads to a $3
(thousand, 1986 dollars) decline in the NPV (see Table 7-18). The zero discharge of NORM
produced sand leads to a $5 (thousand, 1986 dollars) decline in the NPV (see Table 7-21), for a
total of $375 (thousand, 1986 dollars). The NPV for these options combined is $566 (thousand,
1986 dollars). This is a decline of $373 (thousand, 1986 dollars), i.e., additive within rounding.
For an existing single-well structure in the Gulf of Mexico with its own production
equipment (Gulf-lb), but needing new floatation equipment, the combined effects of the selected
7-35
-------
options for produced water, treatment and workover fluids, and produced sand is expected to
reduce the net present value by 40 percent and increase the corporate cost per barrel-of-oil
equivalent (BOE) by 28 percent. (This model project is considered indicative of offshore
projects most sensitive economically because its source of revenue is a single producing well.
Most offshore platforms produce hydrocarbons from multiple wells.) For a Gulf of Mexico
project comprising 12 well slots and 10 producing wells, the same requirements lead to a four
percent decline in net present value and increase of three percent for the corporate cost per
BOE. (This model, termed Gulf 12, is considered representative of a typical offshore platform.)
There were no production losses beyond those already seen with the produced water option.
Similar patterns are seen in Table 7-26 for NSPS projects. For the IRR, NPV, corporate
cost per BOE, and production cost per BOE, impacts from the combined costs may be estimated
by adding the impacts see when each effluent is analyzed separately. The added costs are
sufficient to change the sign of the NPV from positive to negative for the Gulf Ib oil and gas
project when it must add IGF equipment. The NPV remained positive when the project had to
bear only the costs of produced water control. This change has been incorporated in the
estimation of the potential loss in production under the regulatory packages (see Table 9-3). For
years of production and present value of total production, the additional costs of zero discharge
for treatment/workover/completion fluids, produced sand, and drilling wastes, do not lead to
additional losses in production beyond that seen for any given .produced water option.
For a Gulf-lb project, the combined costs lead to a 2 to 5 percent increase in the
corporate cost of production, depending on whether new equipment is needed. If new
equipment is needed, the new present value becomes negative. These projects are assumed to be
canceled and production is lost. If new equipment is not needed, the net present value for the
project remains positive, but with a 65 percent decline in value from the baseline. For a more
typical Gulf-12 project, the same requirements lead to decrease in net present value of 5 to 6
percent, and an increased corporate cost of 1 to 1.5 percent per BOE.
In the real world, there will be projects that fall between the BAT and NSPS models,
e.g., platforms that are installed prior to promulgation but complete part of their drilling
program after this rule is issued. These platforms are much closer to the beginning of their
7-36
-------
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7-37
-------
economic life than to their midpoint but not all wells on the platform will have been drilled
under the new BAT requirements. For these platforms, the per-project impacts are estimated to
be equal to or less than the BAT per-project impacts, depending upon the number of wells
drilled under the new requirements.
7-38
-------
SECTION EIGHT
IMPACTS ON REPRESENTATIVE COMPANIES
This section evaluates the financial impact of BAT effluent guidelines and NSPS
standards on representative companies in the offshore oil and gas industry. Impacts are
examined in terms of several financial ratios for two entities: 1) for a "typical" major oil company,
and 2) for a "typical" independent oil company. The balance sheets and income statements for
"typical" majors and independents are developed in Section Three. The compliance costs
associated with the regulations are presented in Section Six of this report. The balance sheets
and costs were developed in terms of 1986 dollars. The focus of the economic impact analysis is
the change from the baseline value for the financial ratios caused by the incremental pollution
control costs, rather than the baseline values themselves. For this reason, neither the costs nor
the components were inflated to 1991 dollars for the company-level impact analysis.
8.1 METHODOLOGY
The costs of compliance borne by the industry will be financed by the oil and gas
companies operating in the offshore areas. The financial impact of these expenditures for a
given company depends on the size of the expenditures required and the current financial
condition of the company. Since the price that a company can command for its oil is set by the
world oil markets and not domestic costs, the Agency assumes no increase in oil price to offset
the costs of compliance.
In order to estimate the potential impacts on the representative companies, it is necessary
to determine the portion of the regulation's costs that will be borne by the individual companies.
Companies in the offshore oil and gas industry have been characterized using two model
companies. The typical major oil company represents the large integrated oil companies such as
Exxon and Mobil, which operate in many facets of the oil and gas industry. The typical
independent oil company represents the smaller nonintegrated oil producer who is typically
involved in only the upstream or production segment of the industry. The March 1991 EIA
8-1
-------
allocated the costs oi: regulation to a typical independent and typical major oil company based
upon expenditures on exploration and development. For instance, according to the 1986 API
Survey on Oil & Gas Expenditures, a typical major oil company accounted for approximately
2.77 percent of total offshore expenditures on exploration and development in 1986. It was
assumed, therefore, that a typical major oil company would likely bear 2.77 percent of the total
incremental pollution control cost of the regulation. The March 1991 EIA included the costs of
regulation on drilling fluids and drill cuttings, effluents generated only in the exploration and
development stages. Since produced water is the largest component of the total regulatory costs,
EPA reassessed the apportionment of costs among typical major and independent oil companies.
(Expenditures on exploration and development may not directly relate to the volumes of
produced water generated.)
Table 8-1 displays a listing from the Minerals Management Service (MMS, 1990) of the
top 98 oil producers in the Federal Outer Continental Shelf (OCS) region in 1989, ranked
according to volumes of oil produced. Although the offshore category of the oil and gas industry
includes operators in both state and federal waters, 90 percent of the BAT or existing structures
expected to incur additional costs are in federal waters (see Section Four). The OCS distribution
was, therefore, used to estimate what portion of incremental costs would be borne by both a
typical major oil company and a typical independent oil company. Of these 98 operators, 92
represent unique corporations (6 of the entries represent subsidiaries of previously listed
companies). The allocation between major and independent operators was determined according
to company listings in the PennWell Oil and Gas Directory (PennWell, 1991). Companies that
were involved in multiple facets of the oil and gas industry are listed as majors (i.e., exploration,
production, refining, marketing, etc.). Conversely companies involved in only upstream activities
are listed as independent operators (i.e., only exploration, development, or production). Several
of the operators listed in Table 8-1 were not listed in the PennWell directory, but were
considered to be independents.
There is generally an overall strong correlation between the volume of oil produced and
the volume of produced water generated. Furthermore, the volume of produced water that an
operator generates will have a direct effect upon the cost of complying with these regulations.
Accordingly, the distribution of operators in the OCS region was used to estimate the proportion
8-2
-------
TABLE 8-1
Oil Production, Reported in Barrels for 98 Ranking OCS Operators in 1989
Gulf of Mexico
OCS Operators
1. Chevron USA Inc.
2. Shell Offshore Inc.
3. Exxon Corp.
4. Conoco Inc.
5. Mobil Oil E & P
6. Union Oil Company of California
7. Marathon Oil Company
8. Texaco Inc.
9. Union Exploration Partners Ltd.
10. Mobil Producing Texas & New Mexico Inc.
11. Atlantic Richfield Company
12. Pennzoil E & P
13. BP Exploration Inc.
14. Odeco Oil and Gas Company
15. Amoco Production Company
16. CNG Producing Company
17. Placid Oil Company
18. Kerr-McGee Corporation
19. Oryx Energy Company
20. FMP Operating Company
21. Phillips Petroleum Company
22. Hf Aquitaine Operating Inc.
23. McMoran Oil & Gas Company
24. Sandefer Offshore Operating
25. TXP Operating Company
26. Apache Corp.
27. Sonat Exploration Company
28. Union Texas Petroleum Corp.
29. Howell Petroleum Corp.
30. Anadarko Petroleum Corp.
31. Taylor Energy Company
32. Mesa Operating Limited Partners
33. OXY USA Inc.
.34. Hall-Houston Oil Company
35. Forest Oil Corp.
36. Walter Oil & Gas Corp.
37. Tenneco Oil Company
38. Great Western Offshore Inc.
39. Hunt Oil Company
40. Nerco Oil & Gas Inc.
41. Amerada Hess Corp.
42. W&T Off shore Inc.
43. Alliance Operating Corp.
44. Mesa Petroleum Company
45. Huges Eastern Petroleum Inc.
46. Total Minatome Corp.
47. Samedan Oil Corp.
48. Canadianoxy Offshore Production
49. Texaco Producing Inc.
50. Corpus Christ! Oil and Gas Company
51. Columbia Gas Development Corp.
52. Elf Aquitaine Inc.
53. Union Pacific Resources Company
54. Pelto Oil Company
55. Santa Fe International Corp.
Subtotal (Continued next page)
Crude Oil
46,940,619
33,098,609
28,955,890
19,950,976
13,986,816
—
15,330,957
11,531,572
8,395,658
6,768,049
6,080,446
7,118,244
6,578,987
5,950,762
2,549,065
1,591,267
3,670,020
3,213,933
1,475,006
1,986,247
1,133,814
1,714,524
1,470,503
790,204
654,444
982,024
655,518
169,305
741,874
588,269
228,716
306,358
172,921
—
391,359
318,118
399,099
—
140,425
_
47,407
248,158
197,337
199,682
152,459
83,913
33,210
122,627
—
—
—
219
61,018
5,112
—
237,181,740
Condensct*
5.044,315
3,885,357
1,484,025
2.918,273
3,848,415
214
629,724
1,099,796
1,957,459
2,045,475
2.061,976
868,847
367,051
769,832
2,812^78
3.177,834
1,059,972
324,107
199.889
187.684
318,703
108,751 -
62,203
598,193
561,193
15,079
320,697
668,947
_
60,761
366,101
225,678
345,146
497,300
76,870
142,841
53,524
290,814
145,966
272,401
214,666
457
45,712
35,894
55,812
118,425
155.001
43,909
153.911
146,521
140.121.
139,645
61,422
106,502
106.005
41,397,712
Pacific*
Crude Oil &
Condartut*
2,964,957
5,065,058
9,519,054
_
w
13,117,209
—
9,784
_
_
—
_
_
_ .
«.
_
_
_
1,781,111
_
625,630
_
_
—
_
_
—
_
_
_
_
_
_
_
«.
_
_
_
_
«
_
_
_
_
_
_
_
_
—
_
_
'_
a.
_
33,082,803
Field
Volumes
Inbbl
54,949,891
42.049,024
39.958,970
22,869.249
17,835.231
13.117,423
15560,681
12,641,152
10.353,117
8.813,524
8,142,422
7,987,091
6,946,038
6,720.594
5,361,343
4,769,101
4,729.992
3,538,040
3,456,006
2,173.931
2,078,147
1,823,275
1.532,711
1,388,402
1,215,640
997,103
976,215
838,252
741,874
649,030
594,817
532,036
518,067
497,300
468,229
' 460,959
452,623
290,814
286,391
272.401
262,073
248,615
243,049
235,576
208,271
202,338
188,211
166,536
153,911
146.521
140.125
139,864
122,440
111.614
106.005
311,662,255
Source: MMS, 1990.
8-3
-------
TABLE 8-1 (continued)
Oil Production, Reported in Barrels for 98 Ranking OCS Operators in 1989
Gulf of Mexico
OCS Operators
56. Gas Transporation Corp.
57. Coastal Oil & Gas Corp.
58. Century Offshore Management
59. Diamond Shamrock Offshore Partners
60. Zapata Exploration Company
61. Quintana Petroloum Corp.
62. fvory Production Company
63. Enron Oil & Gas Company
64. Kirby Exploration Company Offshore
65. General Atlantic Energy Corp.
66. Brooklyn Union Exploration Company
67. Mitchell Energy Corp.
68. Mark Producing Inc.
69. Cockrell Oil Cop.
70. Conquest Exploration Company
71. Cliffs Oil and Gsa Company
72. Louisiana Land and Exploration
73. Houston Oil & Minerals Corp.
74. Getty Oil Company
75. Seagull Energy E&P Inc.
76. Koch Exploration Company
77. Gulfstar Operating Company
78. Felmont Oil Cop.
79. Mob!) Oil Corp.
80. Total Petroleum Inc.
81. Matagorda Island Development
82. Cashco Energy Corp.
83. Stone Petroleum Corp.
84. Ashland Exploration Inc.
85. ANR Production Company '
86. Southland Royalty Company
87. Flash Gas & Oil Southwest
88. Felmont Oil & Gas Company
80. PSI Inc.
go. Gulf Oil Corp.
91. DKM Offshore Energy Inc.
82. Offshore Energy Development
S3. Wayman W. Buchanan Inc.
94. Wacker Oil Inc.
65. B T Operating Company
96. Falcon Offshore Operating Company
97. Petrofina Delaware Inc.
98. Norcen Explorer Inc.
Field Total*
Crude Oil
94.596
93,173
2,911
—
—
17,008
46,793
—
39,792
34,824
—
38,778
18.371
—
14,117
—
—
11.873
—
—
—
— ,
—
4.852
7.595
—
_.
—
—
—
—
—
—
—
—
1,690
—
—
—
—
,_.
—
_
237,608,113
Condensat*
9,694
—
83,586
71,739
59,740
38,356
1,373
47,549
3,546
7,862
39,332
91
20,409
38,141
22,789
34,158
33,766
20.415
32,049
27,793
25,729
13,683
13,661
3,599
—
5,876
5,585
5,282
4,934
4,631
4,340
4,006
3,497
2959
1855
—
1,448
1,337
198
53
26
22
13
42,092,834
Pacific*
Crude Oil &
Condensate
_
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— .
—
—
—
—
—
—
—
—
—
—
•. —
33,082,803
Field
Volumes
Inbbl
104,290
93,173
86,497
71,739
59,740
55,364
48.166
47,549
43,338
42,686
39,332
38,869
38,780
38,141
36,906
34,158
33,766
32,288
32,049
27.793
25,729
13,683
13,661
8.451
7,595
5,876
5.585
5,282
4,934
4,631
4,340
4,006
3.497
2,959
1,855
1,690
1,448
1,337
198
53
26
22
13
312,783,750
LM\ 1 L. T)w vcJuflMA fMfV M tilGMA rrijtjrMjJ In 1t|A fMd aA ttl* WBfltlAAd flOt 1lW AdjtlSMd fifUj production fiQUm UlCt
tt>« eo*o*on raced and on wWeii (MM** p«y nyalti** to tht F*d*nl Gommmcnl.
Source: MMS, 1990.
8-4
-------
of regulatory cost to be borne by typical companies in the offshore industry. Table 8-2
summarizes the OCS operators according to oil production quantities and to whether or not they
are integrated companies. Note that the 29 majors represented approximately 90 percent of all
oil production from the OCS.1 This distribution was used to estimate that a typical major would
likely bear 3.1 percent of any additional pollution control costs (90 percent divided by 29).2
Similarly, since the 63 independent operators accounted for roughly 10 percent of OCS oil
production, it was assumed that a typical independent producer would bear 0.15 percent of the
costs of regulation.
The typical companies are assumed to raise the funds necessary for compliance through
two financing alternatives:
• All expenditures are financed by long-term debt.
• All expenditures are financed by working capital.
The potential impacts that result from the increase in pollution control expenditures are
estimated by examining the balance sheets of the typical major and independent before and after
the 3.1 and 0.15 percent portion of the costs have been borne. The balance sheets used to
represent the two typical companies are developed in Section Three of the March 1991 EIA.
The impacts are gauged in terms of four financial statistics:
Working Capital; The amount of liquid assets that are available to finance day-to-
day operations.
1MMS, 1990 gives a similar breakdown of gas producers in the OCS region. This breakdown
includes most of the same operators, but indicates that the independent producers play a larger role
in gas production than in oil production. Since the generation of produced water is greater with oil
production than gas production, we are using the offshore oil producers' distribution to allocate costs
to "typical" companies.
2Data from MMS, 1991 show 28 major oil companies operating in the Federal offshore region.
These 28 companies account for 90 percent of the oil production. The updated information results
in a typical major bearing 3.2 percent of the cost of the regulation; a change that would not
significantly affect the results presented in this section.
8-5
-------
TABLE 8-2
OIL PRODUCERS IN THE DCS REGION
Type of Number of Percent of Oil Production Percent of Per Company
Operator ' Companies Total (Millions of BBLS) Total Share of Costs
Major (Integrated) 29 32%
Independent (Non-Integrated) 63 68%
Total: 92
283.0 90% 3.12%
30.0 10% 0.15%
313.0
Source: HHS, 1990.
28-Oct-92
DCS PRD.WK3
8-6
-------
Current Ratio; The ratio of current assets to current liabilities. This provides an
indication of a company's ability to honor short-term obligations.
Long-term Debt to Equity Ratio: This ratio provides a measure of a company's
leverage: the proportion of debt being used to finance a company's assets.
Debt to Capital; An additional measure of a company's debt level or leverage.3
8.2 DRILLING FLUIDS AND DRILL CUTTINGS
Table 8-3 presents the average annual cost for the four options for the control of drilling
wastes. The annual cost ranges from $19 million to $148 million in 1986 dollars. A typical major
is expected to bear 3.1 percent of the total cost, resulting in incremental costs to the company
ranging from $0.59 million for the 3-Mile Gulf/California option to $4.61 million for the Zero
Discharge Gulf/California option. A typical independent would bear approximately 0.15 percent
of the total cost of an option. This translates into incremental costs of $0.03 million to $0.23
million for the same options.
Table 8-4 illustrates the balance sheet for a typical major and how it would change if the
costs for each option were borne entirely out of working capital. Table 8-5 shows the balance
sheet and how it would change if the costs were financed entirely by long-term debt. These two .
tables form the basis for the derivation of the change in financial ratios for a typical major
caused by the increased cost of incremental pollution control for drilling wastes (Table 8-6).
These costs cause only small discernable changes in the long-term-debt to equity and the debt-to-
capital ratios (<= 0.1 percent); ratios affected by financing through long-term debt. These costs
lead to small (<= 0.1 percent) changes in the ratios affects by financing through working capital
except for the Zero Discharge Gulf/California option. Here working capital declines by 0.6
percent.
3The debt to capital ratio used in this analysis is calculated as the book value of long-term debt
divided by the sum of stockholder equity and current liabilities.
8-7
-------
TABLE 8-3
ANNUAL COST OF POLLUTION CONTROL OPTIONS
DRILLING FLUIDS AND DRILL CUTTINGS
MILLIONS OF DOLLARS, 1986 DOLLARS
Option
1
2
3
4
Cost Scenario
3 Mile GUlf/ CA
8 Kile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Annuali zed
Cost
Of Option
$19
$33
S148
$21
Typical Typical
Major Independent
Portion Portion
$0.59
$1.03
$4.61
$0.66
$0.03
$0.05
$0.23
$0.03
Notes: Projects in Alaska are exempt from the barging requirement, however must comply
with the requirements for clean barite, toxicity, and static sheen.
Source: EPA estimates.
KSC SHRE
21-Dec-92
8-8
-------
TABLE 8-4
EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL COMPANY
COMPLIANCE COSTS FINANCED BY WORKING CAPITAL
DRILLING FLUIDS AND DRILL CUTTINGS
Parameters
Regulatory Cost borne by Major
Assets
Current Assets
Property, Plant and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
Long- terra Debt
Other Liabilities (a)
Total Liabilities
Shareholders' Equity
Total Liabilities
and Net Worth
1986
Dollars
$8,337
$24,799
$2,758
$35,894
$7,536
$5,443
$7,600
$20,579
$15,315
$35,894
8 Mile
3 Mile Gulf/ CA 3 Mile
$0.59
$8,336
$24,799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893
Gulf/
CA
$1.03
$8,336
$24.799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893
Regulatory Option
Zero Discharge
Gulf/ CA 4
$4.61
$8,332
$24,799
$2,758
$35,889
$7,536
$5,443
$7,600
$20,579
$15,310
$35,889
Mile Gulf/ CA
$0.66
$8,336
$24,799
$2,758
$35,893
$7,536
$5,443
$7,600
$20,579
$15,314
$35,893
Note:(a) Other liabilities include: deferred Federal and foreign income taxes, deferred
revenue, production payments, and other medium-term commitments.
(b) All values in Millions of dollars.
Source: EPA estimates.
M&C MAJ.WK3
21-Dec-92
8-9
-------
TABLE 8-5
EFFLUENT GUIDELINES IMPACTS ON TYPICAL MAJOR OIL COMPANY
COMPLIANCE COSTS FINANCED BY LONG-TERM DEBT
DRILLING FLUIDS AND DRILL CUTTINGS
Parameters
Regulatory Cost borne by Major
Assets
Current Assets
Property, Plant and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
Long-term Debt
Other Liabilities (a)
Total Liabilities
Shareholders' Equity
Total Liabilities
and Net Worth
1986
Dollars
$8,337
$24,799
$2,758
$35,894
$7,536
$5,443
$7,600
$20,579
$15,315
$35,894
8 Mile
3 Nile Gulf/ CA 3 Mile
$0.59
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894
Gulf/
CA
$1.03
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894
Regulatory Option
Zero Discharge
Gulf/ CA 4
$4.61
$8,337
$24,799
$2,758
$35,894
$7,536
$5,448
$7,600
$20,584
$15,310
$35,894
Mile Gulf/ CA
$0.66
$8,337
$24,799
$2,758
$35,894
$7,536
$5,444
$7,600
$20,580
$15,314
$35,894
Hote:(a) Other liabilities include: deferred Federal and foreign income taxes, deferred
revenue, production payments, and other medium-term commitments.
(b) All values in Millions of dollars.
Source: EPA estimates.
WC HAJ.WK3
21-DCC-92
8-10
-------
TABLE 8-6
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
DRILLING FLUIDS AND DRILL CUTTINGS
Working Capital (a)
Millions
Options
Baseline
3 Mile Gulf/ CA
8 Mile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Parameter
$801
$800
$800
$796
$800
Change
-0.1%
-0.1%
-0.6X
-0.1%
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.11
1.11
Change
-0.01%
-0.01%
-0.06%
-0.01%
Long Term Debt/
Equity
Parameter Change
35.5%
35.5%
35.5%
35.6%
35.5%
0.0%
0.0%
0.1%
0.0%
Debt/Capital
Ratio (b)
Parameter Change
23.8%
23.8%
23.8%
23.8%
23.8%
0.0%
0.0%
0.1%
0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
M&C MAJ.UK3
21-Dec-92
8-11
-------
Tables 8-7 and 8-8 show the balance sheet for a typical independent.4 Table 8-7
illustrates the changes caused by funding the increased pollution control costs for drilling wastes
through working capital; Table 8-8 shows the changes when the costs are funded through long-
term debt. The impacts are summarized in Table 8-9. Working capital decreases by 5.4 percent
for the Zero Discharge Gulf/California option, and 1.2 percent or less for the other options. The
other financial ratios are less sensitive, none show a change greater than 0.5 percent for any of
the options.
8.3 PRODUCED WATER — BAT
Table 8-10 presents the costs of compliance for the five BAT produced water control
options. The first option, BPT All, has no incremental costs associated with it. It is not
discussed further in this section. The annualized costs range from $39 million to $654 million in
1986 dollars for the other options. These costs are broken down into the approximate share of
the incremental costs that would be borne by a typical major and a typical independent oil
company. A typical major is expected to bear 3.1 percent of the total incremental cost, resulting
in total incremental costs to the company ranging from $1.2 for the Filter 4 Miles option to $3.0
million per year for Che Flotation All option to $20.3 million per year for the Zero Discharge
Gulf option. The typical independent would bear approximately 0.15 percent of the total cost of
an option. This translates into incremental costs ranging from $0.06 million to $1.00 million for
the same options.
Table 8-11 summarizes the potential impacts that the incremental costs would have on a
typical major as measured by four financial statistics. If the company were to finance all of the
incremental costs using working capital, it is estimated that the typical major's working capital
would decline by no more than 2.5 percent. Similarly, the current ratio would decrease by less
than 0.3 percent under any of the options. If the incremental costs were financed using long-
4As mentioned in Section Three, it was not possible to update the income statement and balance
sheet for 1986 for independents because of the takeover of Inexco by Louisiana Land and
Exploration in mid-1986. Dropping Inexco would have resulted in too few companies for
aggregation. The consumer price index was used to inflate the 1985 balance sheet to 1986 dollars.
8-12
-------
TABLE 8-7
EFFLUENT GUIDELINES IMPACTS ON TYPICAL INDEPENDENT OIL COMPANY
COMPLIANCE COSTS FINANCED BY WORKING CAPITAL
DRILLING FLUIDS AND DRILL CUTTINGS
Parameters
Regulatory Cost borne by Major
Assets
Current Assets
Property, Plant and
Equipment (Net)
Other Assets
Total Assets
Liabilities
Current Liabilities
Long-term Debt
Other Liabilities (a) -
Total Liabilities
Shareholders' Equity
Total Liabilities
and Net Worth
1986
Dollars
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
3 Mile Gulf/ CA
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
REGULATORY (
8 Mile Gulf/
3 Mile CA
$0.05
$55
$547
S3
$605
$51
$278
• $112
$441
$165
$605
>PTION
Zero Discharge
Gulf/ CA 4
$0.23
$55
; $547
$3
$605
$51
$278
$112
$441
$165
$605
Mile Gulf/ CA
$0.03
$55
$547
$3
$605
$51
$278
$112
$441
$165
$605
Note:(a) Other liabilities include: deferred Federal and foreign income taxes, deferred
revenue, production payments, and other medium-term commitments.
(b) All values in Millions of dollars.
(c) 1985 dollars inflated to 1986 dollars by 3.65X based oh change in Consumer Price Index.
Source: EPA estimates.
8-13
m&c ind.wk3
21-Dec-92
-------
TABIE 8-8
EFFLUENT GUIDELINES IMPACTS ON TYPICAL INDEPENDENT OIL COMPANY
COMPLIANCE COSTS FINANCED BY LONG-TERM DEBT
DRILLING FLUIDS AND DRILL CUTTINGS
REGULATORY OPTION
Parameters
Regulatory Cost born Other liabilities include: deferred Federal and foreign income taxes, deferred
revenue, production payments, and other medium-term commitments.
(b) All values fn Millions of dollars.
(c) 1985 dollan: inflated to 1986 dollars by 3.65% based on change in Consumer Price Index.
Source: EPA estimates.
8-14
St1-Dec-92
-------
TABLE 8-9
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUEN
DRILLING FLUIDS AND DRILL CUTTINGS
Working Capital (a)
SMUlions
Options
Baseline
3 Mile Gulf/ CA
8 Mile Gulf/ 3 Mile CA
Zero Discharge Gulf/ CA
4 Mile Gulf/ CA
Parameter
$4
$4
$4
$4
$4
Change
-0.7%
.-1.2X
-5.4%
-0.8%
Current Ratio (a)
Parameter
1.08
1.08
1.08
1.08
1.08
Change
-0.05%
-0.09%
-0.41%
-0.06%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
8-15
m&c ind.uk3
21-Dec-92
-------
TABLE 8-10
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
Option #
Option
Annualized
Cost
Of Option
Typical Typical
Major Independent
Portion Portion
1 BPT All
2 Flotation All
3 Zero 3 Miles Gulf
4 Zero Discharge Gulf
5 Filter 4 Miles
$0
$96
$115
$654
$39
$0.00
$2.99
$3.58
$20.30
$1.20
$0.00
$0.15
$0.18
$1.00
$0.06
Source: EPA estimates.
BAT SHFIE
21-Dec-92
8-16
-------
TABLE 8-11
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT PRODUCED WATER
Working Capital (a)
Millions
Parameters
Baseline
Flotation All
Zero 3 Hiles Gulf
Zero Discharge Gulf
Filter 4 Hiles
Parameter
$801
$798
$797
$781
$800
Change
-0.4%
-0.4%
-2.5%
-0.1%
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.10
1.11
Change
-0.04%
-0.04%
-0.24%
-0.01%
Long Term Debt/
Equity
Parameter
35.5%
35.6%
35.6%
35.7%
35.6%
Change
0.1%
0.1%
0.5%
0.0%
Debt/Capital
Ratio (b)
Parameter
23.8%
23.8%
23.8%
23.9%
23.8%
Change
0.1%
0.1%
0.5%
0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
8-17
bat_maj.wk3
21-Dec-92
-------
term debt, we would see slight increases in the two leverage ratios (Long-term Debt/Equity and
Debt/Capital ratios) of no more than 0.5 percent under the Zero Discharge Gulf option.
Table 8-12 displays the potential impacts that increased pollution control costs would
inflict upon the typical independent oil producer. If the company chose to finance the costs
through working capital, the available working capital would decline by 24 percent (from $4
million to $3 million) under the Zero Discharge Gulf option. Under this same option, the
current ratio drops from 1.08 to 1.06, a decline of 1.8 percent. Under the Flotation All option,
however, the decline in working capital is less than 4 percent, and the decrease in the current
ratio is under 0.3 percent. If the typical independent raised the funds required for compliance by
incurring long-term debt, the increase in the two leverage ratios would range from 0,1 percent to
1.0 percent for the Flotation All option and the Zero Discharge Gulf option, respectively.
8.4 PRODUCED WATER — NSPS
Table 8-13 presents the costs of compliance for the five NSPS produced water control
options. The first option, BPT All, has no incremental costs associated with it. It is not
discussed further in this section. The peak annualized costs range from $12 million to $347
million in 1986 dollars. This peak will occur in the 15th year of the regulation when the number
of new sources coming into production reach an equilibrium with those reaching the end of their
productive life. These costs are broken down into the approximate share of the incremental
costs that would be borne by a typical major oil company and a typical independent. The typical
major's portion of the incremental costs ranges from $0.4 million for the Flotation All option to
$10.8 million for the Zero Discharge Gulf and Alaska option. The typical independent would
bear incremental costs ranging from $0.02 million to $0.53 million for the same options.
Table 8-14 summarizes the potential impacts that the incremental costs would have on a
typical major as measured by several financial statistics. If the company were to finance all of
the incremental costs using working capital, it is estimated that the working capital would decline
by no more than 1.3 percent under any option. The current ratio would decrease by less than 0.2
percent under any option. If the incremental costs were financed using long-term debt, there
8-18
-------
TABLE 8-12
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT PRODUCED WATER
, i
r
Working Capital (a)
Millions
Parameters
Baseline
Flotation All
Zero 3 Miles Gulf
Zero Discharge Gulf
Filter 4 Miles
Parameter
$4
$4
$4
$3
$4
Change
,-3.5%
-4.2%
-24.0%
-1.4%
Current Ratio (a)
Parameter
1.08
1.08
1.08
1.06
1.08
Change
-0.27%
-0.32%
-1.81%
-0.11%
Long Term Debt/
Equity
Parameter
168.6%
168.8%
168.8%
170.2%
168.6%
Change
0.1%
0.2%
1.0%
0.1%
Debt/Capital
Ratio (b)
Parameter
128.8%
129.0%
129.0%
129.9X
128.9%
Change
0.1%
0.1%
0.8%
0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
8-19
bat ind.wk3
21-Dec-92
-------
TABLE 8-13
ANNUAL COST OF POLLUTION CONTROL OPTIONS
NSPS PRODUCED WATER
MILLIONS OF DOLLARS, 1986 DOLLARS
Annual i zed
Option
Number
1
2
3
4
5
Coat
Option Of Option
BPT All
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles
$0
$12
$62
$347
$16
Typical
Typical
Major Independent
Portion Portion
$0.00
$0.38
$1.92
$10.77
$0.50
$0.00
$0.02
$0.09
$0.53
$0.02
Source: EPA estimates.
NSPSSHRE
5!1-Dec-92
8-20
-------
TABLE 8-14
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
NSPS PRODUCED WATER
Working Capital (a)
$H ill ions
Option
Basel ine
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles
Parameter
$801
S801
$799
$790
$800
Change
•0.0%
-0.2%
-1.3X
-0.1X
Current Ratio (a)
Parameter
1.11
1.11
1.11
1.10
1.11
Change
-O.OOX
-0.02X
-0.13X
-0.01X
Long Term Debt/
Equity
Parameter
35.5%
35. 5X
35.6%
35. 6X
35.5X
Change
O.OX
O.OX
0.3X
O.OX
Debt/Capital
Ratio (b)
Parameter
23. 8X
23.8%
23.8%
23.9%
23.8X
Change
O.OX
O.OX
0.2X
O.OX
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt'financing approach only.
Source: EPA estimates.
8-21
nsps_maj.wk3
21-Dec-92
-------
would be a slight increases of 0.3 percent in the two leverage ratios under the Zero Discharge
Gulf and Alaska option.
Table 8-15 displays the expected impacts that increased pollution control costs would
inflict upon the typical independent oil producer. If the company chose to finance the costs
through working capital, the available working capital would by roughly 13 percent under the
Zero Discharge Gulf and Alaska option. Under this same option, the current ratio drops from
1.08 to 1.07, a decline of 1 percent. Under the Flotation All option, however, the decline in
working capital is only 0.4 percent, and the decrease in the current ratio is less than 0.1 percent.
If the typical independent raised the funds required for compliance by incurring long-term debt,
there would be an increase in the two leverage ratios ranging from 0 percent to 0.5 percent for
the Hotation All option and the Zero Discharge Gulf and Alaska option, respectively.
8.5 TREATMENT, WORKOVER, AND COMPLETION FLUIDS
Table 8-16 lists the annual estimated costs for the zero discharge of treatment, workover,
and completion fluids for BAT and NSPS projects. A typical major would bear approximately
$0.06 million while a typical independent would bear $0.003 million (i.e., $3,000 dollars). These
costs are small relative to those for the other effluents. The financial ratios show no change for
either the typical major (Table 8-17), and changes of 0.1 percent or less for the typical
independent (Table 8-18).
8.6 PRODUCED SAND
The annual cost for produced sand disposal is presented in the Development Document
for this rulemaking. The cost to a typical major is estimated to be $0.12 million while that for a
typical independent of estimated to be $0.01 million (Table 8-19). The changes in financial ratios
caused by these costs are very small and are comparable to those seen for the treatment,
workover, and completion fluid costs (Table 8-20 and 8-21).
8-22
-------
TABIE 8-15
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
NSPS PRODUCED UATER
Working Capital (a)
Millions
Long Term Debt/
Equity (b)
Debt/Capital
Ratio (b)
Current Ratio (a)
Parameters Parameter Change Parameter Change Parameter Change Parameter Change
Baseline $4 1.08 168.6%
Flotation All $4 -0.4% 1.08 -0.03% 168.6% 0.0%
Zero 3 Miles Gulf and Alaska $4 -2.3% 1.08 -0.17% 168.7% 0.1%
Zero Discharge Gulf and Alaska $4 -12.7% 1.07 -0.96% 169.4% 0.5%
Filter 4 Miles $4 -0.6% 1.08 -0.04% 168.6% 0.0%
128.8%
128.9%
128.9%
129.4%
128.9%
0.0%
0.1%
0.4%
0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
8-23
nsps_ind.wk3
21-Dec-92
-------
TABLE 8-16
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT AND NSPS TREATMENT, WORKOVER, AND COMPLETION FLUIDS
MILLIONS OF DOLLARS, 1986 DOLLARS
Cost Scenario
Discharae with Additional Controls for:
BAT Treatment & Workover Fluids
NSPS Treatment & Uorkover Fluids
NSPS Completion Fluids
Total Annual Cost
Annuali zed
Cost
Of Option
$1.50
$0.35
$0.19
$2.04
• Typical
Major
Portion
$0.05
$0.01
$0.01
$0.06
Typical
Independent
Portion
$0.002
$0.001
$0.000
$0.003
Source: EPA estimates.
TUC SHRE
21-Dee-92
8-24
-------
TABLE 8-17
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AND NSPS TREATMENT, WORKOVER, AND COMPLETION FLUIDS " . ';
Parameters
Baseline
Oil and Grease Limits
• ' Working Capital (a)
Millions
Parameter Change
$801
$801 -0.0%
Long Term Debt/
Current Ratio (a) Equity (b)
Parameter Change Parameter Change
1.11 ' 35.5%
1.11 -O.OSS " 35.5% 0:6%
Debt/Capital
Ratio (b)
Parameter
23.8%
• '" 23.8%
Change
u 0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates.
8-25
twc_maj.wk3
21-DCC-92
-------
TABLE 8-18
CHANGES IM FINANCIAL RATIOS FOR. A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AHD NSPS TREATMENT, WORKOVER, AND COMPLETION FLUIDS .
•-
Parameters
Baseline
Oil and Grease Limits
' Working Capital (a) ~ Long Term Debt/ Debt/Capital
SMillions Current Ratio (a) Equity (b) Ratio (b)
Parameter Change Parameter . Change .Parameter Change Parameter Change
$4 1.08 168.6% 128.8%
$4 -0.1% 1.08 , -0.0% . 168.6% 0.0% 128.8% 0.0%
Note: (a) These ratios affected by working capital approach only.
(b) These ratios affected by debt financing.approach only:
Source: EPA estimates.
8-26
twc ind.wk3
21-Dec-92
-------
TABLE 8-19
ANNUAL COST OF POLLUTION CONTROL OPTIONS
BAT AND NSPS PRODUCED SAND
MILLIONS OF DOLLARS, 1986 DOLLARS
Cost Scenario
Annualized
Cost
Of Option
Typical Typical
Major Independent
Portion Portion
ZERO DISCHARGE
$4
$0.12
$0.01
Source: EPA estimates.
sandSHRE
21-Dec-92
8-27
-------
TABLE 8-20
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL MAJOR AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AND NSPS PRODUCED SAND
Parameters
BASELINE
ZERO DISCHARGE
Working Capital (a)
Millions
Parameter, Change
$801
$801 -0.0%
Current Ratio (a)
Parameter Change
1.11
1.11 -0.00%
Long Term Debt/
Equity (b)
Parameter Change
35.5%
35.5% 0.0%
Debt/Capital
Ratio (b)
Parameter
23.8%
23.8%
Change
0.0%
Note: (a) These ratio® affected by working capital approach only.
(b) These ratios affected by debt financing approach only.
Source: EPA estimates..
8-28
SAHO_maj.wk3
21-Dec-92
-------
TABLE 8-21
CHANGES IN FINANCIAL RATIOS FOR A TYPICAL INDEPENDENT AS A RESULT OF EFFLUENT GUIDELINES REGULATIONS
BAT AND NSPS PRODUCED SAND
Parameters
Baseline
Zero Discharge
Working Capital (a)
Millions Current Ratio
Parameter Change
168.6%
168.6% 0.0%
Debt/Capital
Ratio (b)
Parameter Change
128.8%
128.9% 0.0%
Note: (a) These ratios affected by working capital approach only.
These ratios affected by debt financing approach only.
Source: EPA estimates.
8-29
sand ind.Mk3
21-Dec-92
-------
8.7 COMBINED REGULATORY PACKAGES
Table 8-22 presents the costs of compliance for the two regulatory packages. The total
annualized costs in the first year range from $122 million to $144 million in 1986 dollars. The
costs drop to $36 and $86 million, respectively, in the 15th year of the regulation. The portion of
these costs borne by the typical major oil company ranges from $3.8 million to $4.5 million for
first year costs, and from $1.1 to $2.7 million in year 15 cost. For the typical independent, the
share ranges from $0.18 million to $0.22 million and from $0.05 to $0.13 million for the same
packages.
Table 8-23 summarizes the potential impacts that the incremental costs would have on a
typical major as measured by several financial statistics. Under Package B, working capital
declines by 0.3 to 0.6 percent while the current ratio shows change of less than 0.1 percent.
Impacts on working capital are less for the other package. When long-term debt is considered as
the financing method, we see increases in the leverage ratios of 0.1 percent or less under any
given package.
Table 8-24 displays the potential impacts that increased pollution control costs would
inflict upon the typical independent oil producer. The greatest impacts are seen when working
capital is used exclusively to finance the additional pollution control. Under this financing
scenario, we see declines in working capital of nearly 4.5 to 5.3 percent. The current ratio
declines by 0.4 percent or less. When long-term debt is the financing mechanism, increases in
the leverage ratios are 0.2 percent or less under any given package.
8-30
-------
TABLE 8-22
ANNUAL COST OF POLLUTION CONTROL OPTIONS
COMBINED REGULATORY PACKAGES
MILLIONS OF DOLLARS, 1986 DOLLARS
Package Waste Stream
Total
Year Annualized
of Cost
Effluent Control Option Regulation of Package
Typical Typical
Major Independent
Portion Portion
Drilling Fluids & Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment & Workover Fluids
NSPS Treatment & Workover Fluids
NSPS Completion Fluids
Produced Sand
Drilling Fluids & Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment & Workover Fluids
NSPS Treatment & Workover Fluids
NSPS Completion Fluids
Produced Sand
3 Mile Gulf/CA
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
Year One
Year Fifteen
Year One
3 Mile Gulf/CA
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska Year Fifteen
Oil and Grease Limits
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
$122
$36
$144
$86
$3.77
$1.11
$4.47
$2.66
$0.18
$0.05
$0.22
$0.13
Source: EPA estimates.
PKG SHRE 21-Dec-92
8-31
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8.8 REFERENCES
PennWell. 1991. PennWell Directories, 1991 U.S.A. Oil Industry Directory. 30th Edition,
January.
MMS. 1990. U.S. Minerals Management Service, Federal Offshore Statistics: 1989. OCS Report
MMS 90-0072, Tables 60 and 61,1990.
MMS. 1991. U.S. Minerals Management Service, Federal Offshore Statistics: 1990. OCS Report
MMS 91-0068, Tables 60 and 61,1991.
8-34
-------
SECTION NINE
IMPACTS ON PRODUCTION
The incremental costs of additional pollution control potentially can lead to lost
production because projects are closed early or are not undertaken. This section presents the
methodology for evaluating the potential production loss under different regulatory options.
9.1 METHODOLOGY
The basic approach uses the change in the present value of production due to
incremental pollution control costs to estimate the potential production loss. First, total
"baseline" production1 is estimated — that is, the present value of production from all projects
before any incremental costs. To obtain total baseline production, production by project is
calculated by multiplying the present value of production for a particular project by the number
of such projects. This number is aggregated over all projects to provide total estimated
production.
Production is then recalculated using the present value of production under different
regulatory options. Production is set to zero if a project, begins with a positive net present value
but has a negative net present value under a regulatory option. Under these circumstances, the
project would either not be undertaken (NSPS) or would close rather than make the additional
investment (BAT). The recalculated production estimate takes into consideration early
curtailment of projects, immediate project shutdown (BAT), or projects not undertaken (NSPS).
This approach takes into account lost production over the entire lifetime of the project, not just
during the first year of the regulation. Since the analysis is performed with the assumption of a
constant oil price, a project that is considered uneconomical due to increased pollution control
costs is counted as a loss for the entire time period. That is, projects are not considered to
Production is expressed in terms of barrels-of-oil equivalent (BOE) in order to compare both oil
and gas production on a common basis. The conversion factor is based on the heating value of the
product. A barrel of oil is 5.8 million BTU, and an MMCF of gas is 1,021 million BTU. An MMCF
of gas is equivalent to 176.03 BOE.
9-1
-------
become economical later in time due to rising oil prices as in the analysis by Grigalunas and
Opaluch, 1988.
The same set of factors is used to calculate of the cost of a regulatory option and the
production tinder that option. These factors include:
• For existing structures in the Gulf of Mexico (BAT), 37 percent use onshore
treatment and disposal of the produced water.
I iX^ LJW/1 V/k/llLUCkV \Ji iiAV/iAinvk* fc.*****. •» V«M.»- •»•••——— ___——
equirement for improved gas flotation are as follows:
Oil only facilities - 40 percent
Oil and gas facilities - 60 percent
Gas only facilities - 80 percent
The remaining projects are assumed to bear increased annual costs to upgrade the
performance of existing equipment.
• For new structures (NSPS), only 20 percent need an improved gas flotation
system while the remaining 80 percent are assumed to need to upgrade their
equipment and procedures.
The reader is referred to Section XII of the development document for the basis of these costing
assumption;;.
9.2 PRODUCED WATER — BAT
Table 9-1 shows potential production loss under the various regulatory options for
existing stnictures estimated to bear incremental costs of pollution control. The Flotation All
option leads to about a 0.4 percent decrease in production (15 million BOB over the 15-year
time period). The Zero 3 Miles Gulf includes an exemption from the zero discharge
requirement for single-well structures in the Gulf that have their own production equipment
(Gulf Ib stnictures) and Pacific projects. These structures must meet flotation requirements.
The production loss under this option is also 0.4 percent (17 million BOB over the 15-year time
period). Extending the zero discharge requirement to all structures in the Gulf of Mexico (Gulf
Ib projects and Pacific projects also meet flotation, not zero discharge in this option), leads to a
9-2
-------
TABLE 9-1
CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
BAT PRODUCED WATER
Option
Number
1
2
3
4
5
Scenario
Baseline (BPT All}
Flotation All
Zero 3 Miles Gulf
Zero Discharge Gulf
Filter 4 Miles
Total PV of
Product i on
(Millions of BOE)
4,201
4,187
4,184
4,101
4,186
Potential Loss
(Millions
Data
15
17
100
16
in Production
of BOE)
Percent
-0.4%
-0.4%
-2.4%
-0.4%
Source: EPA estimates.
PROD IMP.WK3
21-Dec-92
9-3
-------
production loss of 2.4 percent (100 million BOE over the 15-year time period). The Filter 4
Miles option is associated with a production loss of 0.4 percent (16 million BOE over the 15-
year time period).
93 PRODUCED WATER — NSPS
Table 9-2 shows potential production loss from incremental pollution controls on
produced water for new projects. None of the options examined, including Zero Discharge Gulf
and Alaska option, leads to more than a 0.3 percent loss in production (21 million BOE over the
15-year time period). Options involving improved gas flotation or filtration within 4 miles of
shore result in less than a one-tenth of one percent loss in production.
9.4 COMBINED EFFECTS OF SELECTED REGULATORY OPTIONS
Table 9-3 is a list of the regulatory packages considered in this report. Table 9-4
summarizes the potential production loss under each of these packages. The impacts of
increased pollution controls on drilling fluids, drill cuttings, produced water, produced sand, and
treatment, workover, and completion fluids are included in these estimates. As shown in Section
Seven, there are no incremental production losses beyond those already seen for the produced
water options. Under Waste Package A (Rotation All), there is a production loss'of about 0.1
percent (15 million BOE over the 15-year time period). Under Waste Package B (Zero 3 Miles
Gulf and Alaska), the production loss is approximately 0.2 percent (19 million BOE over the 15-
year time period).
9.5 REFERENCES
Grigalunas, Thomas A. and James J. Opaluch. 1988. Comments on EPA-Funded Economic
Study Eastern Research Group Economic Impact Analysis of Effluent Limitations
Guidelines and Standards for the Notice of Data Availability for Drilling Fluids and Drill
Cuttings for the Offshore Oil and Gas Industry. Economic Analysis Incorporated.
Peacedale, Rhode Island. December.
9-4
-------
TABLE 9-2
CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
NSPS PRODUCED WATER
Option
Number
1
2
3
4
5
Scenario
Baseline (BPT All)
Flotation All
Zero 3 Miles Gulf and Alaska
Zero Discharge Gulf and Alaska
Filter 4 Miles
Total PV of
Product i on
(Millions of
7.598
7,598
7,596
7,577
7,597
Potential Loss
(Millions
BOE} Data
1
2
21
1
in Production
of BOE)
Percent
-0.0%
-0.0%
-0.3%
-0.0%
Source: EPA estimates.
PROD IMP.WK3
21-Dec-92
9-5
-------
TABLE 9-3
REGULATORY PACKAGES
Packages
V/aste Stream
Regulatory Option
B
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS TWC Fluids
Produced Sand
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS TWC Fluids
Produced Sand
3-Mile Gulf/California
Flotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
9-6
-------
TABLE 9-4
CUMULATIVE POTENTIAL LOSS OF PRODUCTION (MILLIONS OF BOE)
OVER 15 YEAR PERIOD OF ANALYSIS
IMPACTS OF COMBINED REGULATORY PACKAGES
Package Scenario
Baseline
Total PV of
Production
(Millions of BOE)
Potential Loss in Production
(Millions of BOE)
Data
Percent
Flotation All
11.800
11.784
15
-0.1%
B Zero 3 Mile Gulf and Alaska
11,781
19
-0.2%
Source: EPA estimates.
PROD IMP.WIG
21-pec-92
9-7
-------
-------
SECTION TEN
SECONDARY IMPACTS OF BAT AND NSPS REGULATIONS
Although the exists and economic impacts of BAT and NSPS regulations would fall
primarily on the major and independent oil companies, secondary effects in other sectors of the
economy would also occur. In this section, EPA reviews the potential effects of regulatory costs
on federal revenues, state revenues, the balance of trade, and support industries. The average
annual cost of the regulations is developed in Section Six.
The impacts are investigated for two packages of regulatory options:
Packages
A
B
Waste Stream
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand
Drilling Fluids and Drill Cuttings
BAT Produced Water
NSPS Produced Water
BAT Treatment and Workover Fluids
NSPS Treatment, Workover, and
Completion Fluids
Produced Sand
Regulatory Option
3-Mile Gulf/California
Rotation All
Flotation All
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
3 Mile Gulf/California
Zero 3 Miles Gulf
Zero 3 Miles Gulf and Alaska
Oil and Grease Limits
Oil and Grease Limits
Zero Discharge
These costs change through time as existing structures cease operation and no longer incur BAT
costs, while new structures continue to come into operation and bear NSPS costs. The costs of
the regulatory packages are presented for the first year of the regulation when BAT costs are at
their highest, and in the fifteenth year of the regulation when NSPS costs are highest.
10-1
-------
10.1 IMPACTS ON FEDERAL REVENUES
Offshore oil and gas activity generates revenue for the federal government from sources
such as income taxes paid by developers, leasing payments, and royalties. All of these revenue
sources could be affected by effluent guidelines limitations costs.
It is assumed that companies involved in offshore oil and gas production have over
$100,000 of net income annually, and that their marginal tax rate is therefore 34 percent. Thus,
any expenditure or depreciation item generates a tax savings of 34 percent of its face value. As a
result, the federal government loses 34 percent of the cost of compliance through tax savings to
the company.
Developers could possibly reduce the impact of the "remaining regulatory costs" (i.e., 66
percent of all costs) by reducing their lease bonus bids. Since the costs of effluent guidelines
limitations and standards can reduce the return on offshore oil and gas projects, it is logical that
operators would, pay less for the right to explore offshore areas. Under the $21/bbl scenario with
restricted activity, an estimated 91 percent of projected development is allocated to federal
waters (see Table 10-1); therefore, EPA assumes 91 percent of the remaining costs could be
recouped by the company through lower lease bids on federal areas.
Table 10-2 lists the potential impacts on federal revenues. For example under year one
of regulatory Package A, the total annual cost of the regulation is $122 million (1986 dollars).
Revenue lost to the federal government through tax savings equals $122 x .34 or $41 million
(1986 dollars; $47 million in 1991 dollars). In year 15, the cost from regulatory Package A drops
to $36 million with a concomitant loss of $12 million in tax revenues (1986 dollars; $14 million in
1991 dollars).
There also may be a potential loss of federal revenue through lower lease bids. This loss
is equal to 91 percent of the remaining cost. For example, under regulatory Package A the
potential loss" due to lower lease bids equals ($122 minus $41) x .91 or $73 million (1986 dollars;
$82 million in 1991 dollars). Companies may or may not choose to reduce their bonus bids by
the full amount available. Hence, entries in this column are labeled "potential" losses. The
potential losses shown in Table 10-2 are the maximum bid reductions that recoup all cost
10-2
-------
TABLE 10-1
RATIO OF FEDERAL-TO-STATE PRODUCTION
PROJECTED PRODUCTIVE DEVELOPMENT WELLS IN OFFSHORE REGION (15-YEAR PERIOD)
Region
Gulf
Pacific
Alaska
Total
Percent
Source:
Number of
State Wells
538
0
69
607
of Total 8.8%
EPA Estimates.
Nunfcer of
Federal Wells
5.914
38Z
29
6,325
91.2%
Total Number
of Productive Wells
6,452
382
98
6,932
T10-1.WK3
21-D6C-92
10-3
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increases remaining after the tax savings. The potential losses range from $73 to $87 million
(1986 dollars; $82 to $97 million in 1991 dollars) in the first year of the regulation. The total
potential revenue loss to the federal government ranges from $114 million to $136 million (1986
dollars; $129 to $153 million in 1991 dollars) in the first year of the regulation. By the fifteenth
year, the loss has dropped to $34 to $81 million for the two regulatory packages (1986 dollars;
$38 to $91 million in 1991 dollars).
Table 10-3 lists the results of recent OCS sales. In 1986, only $187 million was received
in bonuses in two lease sales in the Gulf. This was the lowest level of bonus receipts for several
years. Interest picked up again in 1987, when two lease sales in the Gulf brought in $497 million
in apparent high bids. In 1988, OCS sales brought in $1,260 million in bonuses. The potential
loss in federal revenues in the first year due to lower lease bids and tax savings to the companies
(from Table 10-2) ranges from 9 to 10.8 percent of the 1988 bonuses. These losses, however, are
only potential losses; that is, companies may choose not to recoup all cost increases through
lower bonus bids.
The third source of potential losses in federal revenues is the loss of royalties due to early
closure of projects or projects not undertaken. This reduction in royalty revenues would be the
result of a potential loss in future production, which is investigated in Section Nine. The loss of
royalties resulting from lost production is not investigated in this report. The potential loss in
production under regulatory Package A results in a decline in production 0.1 percent. This
translates into a 0.1 percent decline in associated revenues.
10.2 IMPACTS ON STATE REVENUES
Industry could reduce the impacts of the cost of compliance with new regulations by
reducing lease bonus bids on state tracts. The well projections estimate that 9 percent of future
offshore activity will take place in state waters (see Table 10-1). Potential loss in revenue for the
states is calculated as the cost of the regulatory package times the percentage borne by the
industry (i.e., not including the 34 percent tax savings) times the portion of development that
takes place in state waters. For instance, under regulatory Package A, the calculation is $122
million x .66 x .09 or $7.22 million (1986 dollars; $8.13 million in 1991 dollars). Table 10-4
10-5
-------
TABLE 10-3
RECENT DCS LEASE BONUSES PAID
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
No. of Sales
3
7
5
7
6
3
2
2
7
2
2
Nunber of
Tracts Leased
218
430
357
1251
1387
681
142
640
1621
1049
825
Bonuses Paid
For Leases
(SHillion)*
$4,204
$6,653
$3,987
$5,749
$3,929
$1,558
$187
$497
$1,260
$646
$584
* current dollars.
'Source: HMS, 1991.
10-6
T10-3.WK3 08-Oct-92
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summarizes these costs, which range from $7.2 to $8.6 million in the first year of regulation
(1986 dollars; $8.1 to $9.6 million in 1991 dollars). These costs drop to $2.1 to $5.1 million in
the fifteenth year of the regulation (1986 dollars; $2.4 to $5.7 million in 1991 dollars).
These losses are only potential; companies may not choose to recoup all cost increases
through lower lease bids. In addition, the potential losses, should they occur, would be spread
among several states. New wells are projected for Alaska, the Pacific, and the Gulf of Mexico.
Under the $21/bbl restricted development scenario, the only drilling that occurs in California
waters is on existing leases. California, then, would not suffer any loss of bonus revenue due to
increased pollution controls. Affected states could include Alaska, Texas, Louisiana, Mississippi
and Alabama.
The example of Texas illustrates the potential impacts on state income. In 1990, Texas
produced 1,768,800 bbl of oil and 108,995,500 Mcf of gas from offshore state wells. In the same
year, the other major producing state in the Gulf of Mexico, Louisiana, produced 22,829,500 bbls
of oil and 178,633,000 Mcf of gas from offshore state wells (API, 1992). These figures convert to
20,955,278 barrels-of-oil equivalent (BOB) for Texas and 54,274,267 BOB for Louisiana. Texas,
therefore, generated approximately one-quarter (28 percent) of state offshore production in the
Gulf of Mexico in 1990, while Louisiana produced the remaining 72 percent. Since the
proportions can fluctuate from year to year, this analysis apportions 25 percent of the states' cost
of the regulation to Texas and the remaining 75 percent to Louisiana.
Table 10-5 shows the calculation to estimate the potential revenue loss through lower
bonus bids. The estimated loss is the product of four factors:
• Proportion of cost not shielded by tax savings on expensed and depreciated items.
• Portion of projects occurring in state waters.
• Portion of state water activity occurring in the Gulf of Mexico.
• Portion of Gulf of Mexico state water activity occurring in Texas.
"N
The last parameter is the proportion of production occurring in Texas state waters in relation to
total production in 1985 for state waters in the Gulf of Mexico. The potential loss ranges from
10-8
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10-9
-------
$1.6 to $1.9 million (1986 dollars; $1.8 to $2.1 million in 1991 dollars) in the first year of the
regulation, and from $0.5 to $1.1 million (1986 dollars; $0.5 to $1.3 million in 1991 dollars) in the
fifteenth year of the regulation.
Table 10-6 presents total income to Texas from oil and gas bonuses and from all sources
for 1984 through 1989. Texas received $25 million in lease bonus revenues in 1986 and more in
1988. Potential losses range from 6 to 7 percent of 1986 bonuses. Total state revenues for 1986
are $17,952 million; compared to total state revenues, the impact of the most expensive
regulatory package is less than 0.1 percent.
Tables 10-7 and 10-8 repeat the calculations for Louisiana, whose fiscal year runs from 1
July to 30 June. Ilie potential loss in revenue ranges from $4.8 to $5.7 million (1986 dollars;
$5.4 to $ 6.4 million in 1991 dollars) in the first year of the regulation. Louisiana's income from
bonuses fell from $60 million in fiscal year 1984-1985 to $26.0 million in 1985-1986 to $12 million
in 1986-1987, due, in part, to the crash in oil prices. The data after 1987 indicate how this sector
of the economy has begun to recover. Bonuses were $28 million in 1987-1988 and $15 million in
1988-1989. The revenue loss associated with the first year of regulatory Package A is about 40
percent of Louisiana's 1986 bonus income. The impact of regulatory Package A on total state
revenue for 1985-1986 (the lowest total revenue in the series), however, is still less than 0.1
percent.
103 IMPACT ON BALANCE OF TRADE
The United States is rapidly approaching the time when it imports more oil than it
produces. The Department of Energy projects this time to arrive in 1994 (DOE, 1989), but it is
already happening sporadically on a monthly basis. For example, in January 1990, the United
States imported 54 percent of our domestic demand for oil and gas (OGJ, 1990a). The recent
concern over maintaining domestic oil sources is not expected to prevent a decline in domestic
oil production. A shortage of trained personnel and workover rigs are factors cited as limiting
any near-term sizable increase in domestic production (OGJ, 1990b; OGJ, 1990c; and OGJ,
1990d). In other words, unless domestic demand for oil is curbed, the United States will
10-10
-------
TABLE 10-6
TOTAL TEXAS STATE REVENUES AMD BONUS REVENUES
Year
1985
1986
1987
1988
1989
Bonus Revenues*
(Will ion)
$60.3
$25.4
$18.4
$26.0
$24.3
Total State Revenues*
($Hillion>
$16,980
$17.952
$17,524
$20,357
$21,479
* Current dollars.
Source: Plaut, 1990.
T10-6.WK3 08-Oct-92
10-11
-------
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10-12
-------
TABLE 10-8
TOTAL LOUISIANA STATE REVENUES AND BONUS REVENUES
Year
1984-1985
1985-1986
1986-1987
1987-1988
1988-1989
Bonus Revenues*
CSMUtion)
$59.7
$26.0
$12.1
$27.7
$14.7
Total State Revenues*
( SMill ion)
$8,804
$8.800
$9,306
$9,105
$10,186
* Current dollars.
Source: Hoppenstedt, 1990.
T10-8.WK3 08-Oct-92
10-13
-------
continue to import a growing percentage of its domestic oil consumption. This phenomenon is
occurring in the absence of any incremental pollution control costs.
The potential loss in production is investigated in Section Nine. Even under regulatory
Package B with the higher projected costs, production declines over the entire 15-year period do
not exceed 0.2 percent. This is a small percentage compared to the estimated annual decline in
domestic production of about 3 percent seen in the DOE projections (DOE, 1989). In other
words, the change in the balance of trade expected from this regulatory effort will be insignificant
compared to changes caused by outside factors.
10.4 IMPACTS ON SERVICE INDUSTRIES
In addition to major and independent oil companies, a third group of companies provides
a variety of specialized services to the offshore oil and gas developers. These firms construct,
own, and operate mobile drilling rigs; fabricate and install offshore platforms; provide
geophysical, drilling mud, and well logging services; build and install pipelines to transport oil
and gas from platforms to onshore terminals; and own and operate boat and helicopter fleets
that provide support services to offshore drilling rigs and platforms.
Regulatory costs can be incurred through increased capital and annual operating costs
required for the disposal of produced water. Since the well operators are the ones who purchase
and operate the disposal equipment, they will ultimately bear the cost. All costs, then, are
assumed to be passed through to the operator. Under these conditions, no negative impacts are
incurred by the service industries. Sections Seven and Eight examine the impacts on individual
projects and representative companies, respectively. In addition, when the regulations become
effective, activity for the service industry will increase due to the need to retrofit existing
facilities. In this respect, the regulations could lead to a temporary positive impact on the service
industry.
10-14
-------
10.5 IMPACTS ON INFLATION
«",...•••'" • ' "'
The regulations can lead to higher costs to the operators. When evaluating this effect on
typical companies, it was assumed that they could not raise prices to recover these costs. This is
because the price that the companies will receive for their product is determined by the world oil
price and not domestic costs. Given our nation's continued growth in oil demand, supply (and
therefore price) is still largely controlled by the behavior of the OPEC members (see DOE, 1989,
and Harvard, 1988). Because of the inability of the companies to raise prices in response to
increased costs, substantial impacts on inflation from increased cost of pollution controls on
offshore oil and gas effluents are not anticipated. The impacts on the companies (Section Eight)
and the impacts on production (Section Nine) were investigated under this set of assumptions.
10.6 REFERENCES
API, 1992. American Petroleum Institute, Basic Petroleum Data Book. Volume XII, Number 2,
Section XI, Tables 18 & 19, May.
DOE. 1989. U.S. Department of Energy, Annual Energy Outlook: Long-term Projections 1989.
Energy Information Agency, DOE/EIA-0383(89), January 1989.
Harvard. 1988. Harvard University, Lower Oil Prices: Mapping the Impact. Energy and
Environmental Policy Center, 1988.
Hoppenstedt. 1990. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc., and David Hoppenstedt, Louisiana State Budget Office, Baton Rouge, LA,
March 8,1990.
MMS. 1991. U.S. Minerals Management Service, Federal Offshore Statistics; 1990. MMS 91-
0068, TableS.
OGJ. 1990a. "OGJ Newsletter," Oil and Gas Journal. February 19, 1990.
OGJ. 1990b. "Despite Output Push, U.S. Probably Cannot Avoid Oil Production Decline in
1991," Oil and Gas Journal. September 17,1990, pp.21-24.
OGJ. 1990c. "W. Coast Best Potential for Output Hike Soon," Oil and Gas Journal. October 1,
1990, pp.38-42.
OGJ. 1990d. "U.S. Oil Flow Hike Unlikely Outside W. Coast," Oil and Gas Journal. October 15,
1990, pp. 32-36.
10-15
-------
Plaut. 1990. Personal communication between Maureen F. Kaplan, Eastern Research Group,
Inc., and Tom Plaut, Economic Analysis Department, Texas Comptroller's Office,
Austin, TX, March 8,1990.
10-16
-------
SECTION ELEVEN
SMALL BUSINESS ANALYSIS
Public Law 96-354, known as the Regulatory Flexibility Act, requires EPA to determine if a
significant impact on a substantial number of small businesses occurs as a result of proposed
regulations. If there is a significant impact, the act requires that alternative regulatory
approaches that mitigate or eliminate economic impacts on small businesses be examined.
Various definitions of small businesses are used by federal agencies in procurement
activities and regulatory analysis (47 CFR 121.3). These standards are based on number of
employees or sales volume. Employee standards of 100, 200, 250, and 500 have been used. Sales
standards of $100,000, $1,000,000, $2,500,000 and $7,500,000 have also been employed. The
Small Business Administration uses a standard of 250 employees for the oil and gas extraction
point-source category (SIC 1311).
Production companies would incur the direct regulatory impact of BAT and NSPS.
Production companies are generally large corporate or large independent firms. Revenues for a
typical independent oil company were $160 million in 1985 while in 1986, revenues for a typical
major are estimated at $35.3 billion. Large majors and large independents each typically employ
well over 500 people. Both these measures indicate that energy production companies are not
small businesses. Therefore a formal Regulatory Flexibility Analysis (RFA) is not required.
11-1
-------
-------
APPENDIX A
SELECTION OF OFFSHORE OIL AND GAS PROJECTS
Offshore oil and gas platforms vary by size, volume and type of production, and
geographic location. Platform sizes range from one well, in Gulf of Mexico installations, to
approximately 100 wells at artificial islands off the northern coast of Alaska. The volume of
production on a platform ranges from several barrels to over 100,000 barrels per day. A given
platform may produce oil, both oil and gas, or only gas. Platform locations include the Gulf of
Mexico, the Pacific, and Cook Inlet, Alaska. Production began from artificial islands in the
Beaufort Sea region of Alaska in 1987. Future production may occur in other Arctic regions.
The area off the Atlantic Coast is not expected to be developed within the time frame of this
analysis.
The economics of oil and gas production and pollution control differ among platforms
because of the variability of platform features. To capture these differences, representative
model projects have been developed for the various geograpWcal areas. The projects reflect
variations in three parameters:
• Geographic region
• Size (number of wellslots)
• Type of production (oil, gas, or both)
The model projects have been reviewed and updated from those described in Economic
Impact Analysis of Proposed Effluent Limitations and Standards for the Offshore Oil and Gas
Industry. (EPA, 1985).
A-l
-------
A.1 GENERAL PARAMETER CATEGORIES
The model projects presented below reflect three key factors: geographic region, size,
and production type. In all, 32 model projects are presented. They characterize the range of
platform types expected to be installed during the study period.
A.I.I Geographic Region
Offshore oil and gas deposits are known to exist in or are posited for:
« Gulf of Mexico - offshore Florida, Alabama, Mississippi, Louisiana, and Texas
• Pacific - California, Oregon, and Washington
• Alaska - Beaufort Sea, Chukchi Sea, Hope Basin, Norton Basin, St. Matthew Hall,
Navarin Basin, Aleutian Basin, Bowers Basin, Aleutian Arc, St. George Basin,
North Aleutian Basin, Cook Inlet, Shumagin, Kodiak, and Gulf of Alaska
• Atlantic - North, Mid-, and South Atlantic
These areas are shown in Figures A-l and A-2.
Three regions—Gulf, Pacific, and Alaska—differ significantly with respect to the principal
factors affecting offshore economics (geology, depth, weather, productivity, etc.). They are also
geographically separate. Accordingly, separate models are developed for each of the three
regions. Within Alaska, weather and geologic conditions vary from region to region, so projects
are developed for four separate areas of the state: Cook Inlet, Beaufort Sea, Norton Basin, and
Navarin Basin. The Atlantic region also has its own characteristics. Due to leasing and
exploration constraints, however, no projects are projected for the Atlantic within the time frame
of the analysis (see Section Four). No models are presented for the Atlantic in this report; see
the economic impact analysis for the 1991 proposal for a discussion of Atlantic models.
A-2
-------
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A-3
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A-4
-------
A.1.2 Number of Well Slots
Platform size is the second key variable. Model projects within the regions are designed
to reflect the different sizes of existing and planned structures.
For the Gulf, the selection of model structure sizes is based on the information in the
MMS Platform Inspection System, Complex/Structure Data Base as of March 1988. Table A-l
summarizes the number of structures in the Gulf of Mexico by the number of available wellslots.
The most predominant are a single wellslot structures where four out of five have no production
equipment. Given the large number of these structures we model a "Gulf la" as a single well
structure with no production equipment and a "Gulf Ib" as a single well structure with
production equipment. Other projects chosen to represent the region are structures with 4, 6,
12, 24, 40, and 58 wellslots. The larger structures are expected to become more prevalent in the
deeper waters.
Table A-2 summarizes the number of wellslots per platform in Pacific OCS waters.
Existing and planned structures contain from 15 to nearly 100 wellslots, with an average of 55
wellslots per platform (MMS, 1986). Three structures of varying sizes are chosen to model the
Pacific region; their associated number of wellslots is 16, 40, and 70.
i
In most regions of Alaska, there are no existing platforms. The size and configuration of
platforms in these regions will evolve as successful discoveries are made and developed. As a
result, there is no basis upon which to define a variety of platform sizes in the Alaskan regions.
In each region, one typical size is selected based on available projections or engineering studies.
For example, the number of wells projected for Arctic projects is based on the information in
OTA (1985). The selected platform sizes are:
• Cook Inlet -12 or 24 wellslots, depending on type of production
• Beaufort Sea - 48 wellslots
• Norton Basin - 34 wellslots
• Navarin Basin - 48 wellslots
A-5
-------
gulf#.wk1
TABLE A-1
NUMBER OF STRUCTURES BY THE NUMBER OF UELLSLOTS AVAILABLE
GULF OF MEXICO, MARCH 1988
Number of
Uellslots
Available
1
2
3
4
5
6
7
8
9
10
11
12
13 .
14
15
16
18
19
20
21
22
23
24
25
26
27
28
30
32
35
36
40
58
62
Missing
TOTAL
Note: Blanks
Number of
Structures
1,283
207
143
203
37
181
31
79
80
31
12
287
32
20
29
33
152
2
9
23
5
3
121
6
5
3
9
2
5
1
3
6
1
1
52
3,097
indicate no
Production Equipment
Yes
20.0%
34.8%
49.7%
60.6%
75.7%
82.3%
90.3%
94.9%
93.8%
96.8%
100.0%
92.3%
100.0%
95.0%
89.7%
97.0%
95.4%
100.0%
77.8%
91.3%
80.0%
100.0%
95.9%
66.7%
80.0%
100.0%
100.0%
100.0%
0.0%
100.0%
100.0%
100.0%
100.0%
100.0%
structures with
No
80.0%
65.2%
50.3%
39.4%
24.3%
17.7%
9.7%
5.1%
6.3%
3.2%
0.0%
7.7%
0.0%
5.0%
10.3%
3.0%
4.6%
0.0%
22.2%
8.7%
20.0%
0.0%
4.1%
33.3%
20.0%
0.0%
0.0%
0.0%
100.0%
0.0%
0.0%
0.0%
0.0%
0.0%
intermediate
numbers of wellslots.
Source: HMS Platform Inspection System, Complex/Structure
Data Base, March 1988.
A-6
-------
# slots.wk1
28-Feb-92
TABLE A-2
NUMBER OF WELLSLOTS OM PACIFIC DCS PLATFORMS
Platform
Name
Number of
Uellslots
Year
Installed
Water
Depth (ft)
Existing A 57 1968 188
B 63 1968 188
C .• = •• 60 1977 193
Edith 72 1983 161
Ellen 80 1980 265
Eureka 60 1984 700
Gail 36 . 1987 739
Gilda 96 1981 210
Gina 15 1980 95
Grace 48 1979 318
Habitat . 24 1981 303
Harvest 50 1985 670
Hermosa 48 1985 602
Henry 28 1979 291
Hidalgo . 56 1987 430
Hillhouse 60 1969 190
Hogan 66 1967 150
Hondo 28 1976 842
Houchin , 60 1968 151
Irene 72 1985 242
Proposed Hacienda 48 -- '300
Harmony 60 1992 1300
Heritage 60 1992 1075
Julius 70 T989 478
Average Number of Wei Is lots ,54.9 •-•"•'•
Source: MHS, 1986; Ocean Industry, 1987a.
A-7
-------
In the Beaufort Sea, two configurations are modeled: a gravel island and a platform. (See
Section A.2.4 for further description of these configurations.)
Based on the six regions and the size categories within each region, a total of 16
region/size categories are defined. These are shown in the left column of Table A-3.
A.1.3 Type of Production
The type of production is the third variable in defining the model projects. Crude oil,
natural gas, or both may be produced at a platform, depending on the reservoir and the
economics of recovery. The options are: oil only, oil and gas, and gas only.
In the Gulf, the MMS data indicate that, where the type of production is known, very few
(under 5 percent) of the structures produce only oil. We maintain oil-only versions of the Gulf
models to evaluate the costs of BAT regulations because the composition of the effluent differs
between oil-only and oil-and-gas production. For the projected platforms, all Gulf platforms that
produce oil are assumed to have associated gas as well. There are no gas-only platforms among
large Gulf platfbrms. Only small projects (less than 40 wellslots) are assumed to produce only
gas.
The same pattern is found in the Pacific, where the large projects produce oil with gas
(but not gas only) and small projects produce either oil with gas or gas only. W. Guerard of the
California Department of Conservation stated that all oil fields produce some gas, but that as an
oil field gets older, it produces less gas (Guerard, 1989). For the purpose of evaluating the
pollutant removals from produced water effluent guidelines, all projected platforms that produce
oil are assumed to have associated gas as well.
In Alaska, projects in the Cook Inlet are assumed to produce oil with gas or gas only.
For the Arctic regions, there is no infrastructure to deliver gas from these regions to the Lower
48 States nor is such infrastructure planned for the next ten years, so just oil-only projects are
proposed for these regions.
A-8
-------
TABLE A-3
DISTRIBUTION OF OIL, OIL/GAS, AND GAS PRODUCING PLATFORMS
BY REGION AND SIZE
PRODUCTION TYPE
REGION AND
WELLSLOT SIZE
Gulf la?
Gulf lba
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
OIL OIL/GAS
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
. Yes
Yes
Yes
Yes
GAS COMMENTS
Yes
Yes
Yes
Yes
Yes
Yes
No No gas-only platforms among large Gulf
Gulf 58 Yes Yes No
Pacific 16 No Yes Yes
Pacific 40 No Yes No
Pacific 70 No Yes No
Cook Inlet 12/24 No Yes Yes"
Beaufort Sea 48
platforms.
No gas-only platforms among large Gulf
platforms.
No gas-only platforms among large Gulf
platforms.
No gas-only platforms among large Gulf
platforms.
- Gravel island
- Platform
Norton Basin 34
Navarin 48
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
infrastructure
infrastructure
infrastructure
infrastructure
for
for
for
for
gas
gas
gas
gas
delivery.
delivery.
delivery.
delivery.
Source: EPA model project configurations based on typical projects reported in the
Department of the Interior Mineral Management Service Platform
Inspection System, Complex/Structure Database, and the literature.
"The Gulf la shares production equipment with three other single-well stuctures
while the Gulf Ib has its own production equipment.
bThe gas-only case is modeled as 12 wells.
A-9
-------
A.2 DESCRIPTION OF MODEL PROJECTS
A.2.1 Gulf of Mexico Model Projects
Gu\f 1-, 4-, and 6-Wett Platforms
Small platforms in the Gulf either have their own production facilities or are simple
superstructures (i.e., well protectors) that ship produced hydrocarbons (before water separation)
to a central onshore or offshore production facility. Platforms in the latter category are referred
to as satellite facilities. By servicing several platforms, centralized facilities offer economies of
scale in oil and gas production over small platform structures with their own production
equipment. Satellite platforms cannot be used in all situations, however. If the platform is in a
remote location so that the cost of additional pipelines outweighs the cost advantage of central
processing, or the production from the platform is transported via intercompany pipelines that do
not accept crude unless it is already separated from the produced water, then the production
facility is located directly on the specific platform.
The MMS Platform Inspection System provides information on the number of wellslots
per OCS platform and whether platforms have their own production equipment. Table A-l
summarizes the data in the 1988 MMS files. Two models are used for a single-wellslot structure
in the Gulf, one without production equipment and one with production equipment. These are
referred to as the Gulf la and Gulf Ib models, respectively. The majority of 4- and 6-wellslot
structures have their own production equipment and are modeled as such in this report.
Gutftt-Wett and 24-Wett Platforms
These two model projects represent typical medium-sized production structures common
in the Gulf (see Table A-l). The DOI-MMS Platform Inspection System Reports are used to
define representative features of the 12- and 24-wellslot platforms (Tables A-4 and A-5). The
typical 12-wellslot steel jacket platform occurs in 0 to 200 feet of water (67 feet in the model
project), 0 to 10 miles offshore (6 miles in the model project). Of the 12 slots, an average of 10
A-10
-------
TABLE A-4
SAMPLE 12-WELL STRUCTURES USED
IN SELECTING 12-WELL MODEL PROJECT
AREA ,
West Cameron
East Cameron
South Timbalier
Main Pass
Main Pass
East Cameron
West Delta
West Cameron
Matagorda ' Island
Ship Shoal
BLOCK
513
222
161
042
043
033
095
522
665
168
WATER
DEPTH
(FEET)
170
110
117
30
27
42
150
177
74
,58
MILES
FROM
SHORE
93
67
32
11
10
8
27
95
15
27
WELL-
SLOTS
12
12
12
12
12
12
12'
12
12
12
SLOTS
IN
USE
8
12
9
12
12
10
9
6
7,
8
YEAR
INSTALLED
1974
1973
1964
1965
1967
1972
1968
1978
1979
1973 ,
Source: MMS, 1987a.
A-ll
-------
TABLE A-5
SAMPLE STRUCTURES USED
IN SELECTING 24-WELL MODEL PROJECT
AREA.
High Island
East Cameron
Grand Isle
Vermilion
Eugene Island
South Marsh Island
South Pass
South Timbalier
South Timbalier
South Timbalier
Ship Shoal
Vermilion
Vermilion
Mississippi Canyon
Grand Isle
BLOCK
349A
322
081
023
256
128
037
026
026
026
225
247
321
311
022
WATER
DEPTH
(FEET)
278
230
177
36
137
225
108
60
55
60
146
139
205
425
55
MILES
FROM
SHORE
115
95
38
6
53
75
7
8
8
8 •
54
65
87
46
8
WELL-
SLOTS
24
18
24
25
18
24
24
18
26
24
21
24
24
24
24
SLOTS
IN
USE
9
16
17
4
7
18
13
18
26
18
18
14
22
19
23
YEAR
INSTALLED
1979
1975
1971
1977
1977
1975
1962
1971
1971
1979
1971
1972
1972
1978
1957
Source: MMS, 1987a.
A-12
-------
are in use for production at any one time (10 in the model project). The typical 24-wellslot
steel-jacket platform occurs in 50 to 500 feet of water (100 feet in the model project) and 5 to 50
miles offshore (20 in the model project). Of the 24 slots, an average of 18 are in use for
production at any time (18 in the model project).
Gulf 40-Well Platform. The Gulf 40-well case represents those platforms expected to
produce large reservoirs in water depths averaging 200 feet and of distances from shore
averaging 50 miles. A selection of existing structures in this size range is described in Table A-6.
Again, EPA uses the MMS Platform Inspection System Reports to define representative features
of this model project. Platforms in this case are expected to be constructed on the far offshore
tracts now being leased. No gas-only platforms are expected to be in this category. Of the 40
wellslots, an average of 32 are in use for production at any time.
Gulf 58-Well Platform. The largest model project in the Gulf is based on platforms
Cognac and Bullwinkle. Both are 60-slot steel-jacket platforms. Cognac, with an overall length
of 1,265 feet, was installed in 1978 in Mississippi Canyon, while the 1,615-foot Bullwinkle was
installed in Green Canyon in 1988. Cognac and Bullwinkle are set approximately 15 and 90
miles offshore at depths of 1,023 and 1,353 feet, respectively (Offshore, 1986, MMS Offshore
Platform Inspection System). Information on the Gulf projects is summarized in Table A-7.
A.2.2 Pacific Model Projects
Most of the platform development in the Pacific is expected to occur off the coast of
Southern California. The California offshore area is characterized by several old, fully developed
fields and by high-potential areas in the Santa Maria Basin, the Santa Barbara Channel, and off
Long Beach. Most of the current production is oil; in 1986 the oil/gas ratio was 531 ft?/bbl.
There are only 21 nonassociated gas wells currently producing offshore California; 6 of these
wells are in State waters. Habitat, the Pitas Point platform with 12 wells producing in 1986, is
the only nonassociated gas producer to date. Virtually all future production is expected to be oil
(California, 1987). Platform types in newly discovered fields are used as the basis for the Pacific
A-13
-------
TABLE A-6
SAMPLE STRUCTURES USED
IN SELECTING 40-WELL MODEL PROJECT
AREA
Main Pass
South. Marsh Island
South Marsh Island
South Marsh Island
South Marsh Island
West Delta
The Elbow
East Breaks
South Pass
South Pass
South Pass
BLOCK
153
130
130
130
130
080
331
160
070
070
065
WATER
DEPTH
(FEET)
290
215
215
215
216
102
241
935
290
264
300
MILES
FROM
SHORE
14
82
82
82
82
13
80
110
9
9
9
WELL-
SLOTS
32
36
40
36
36
30
35
40
40
40
32
SLOTS
IN
USE
32
36
31
36
36
23
35
2
40
40
32
YEAR
INSTALLED
1970
1975
1978
1974
1975
1971
1972
1981
1977
1974
1969
Source: MMS, 1987a.
A-14
-------
TABLE A-7
PROJECT DESCRIPTIONS
GULF OF MEXICO
GULF OF MEXICO PROJECTS
PARAMETER
Platform type
Location
- State waters
- Federal OCS waters
Distance from shore
- mi
- km
Water depth
. - ft
- m
Number of wellslots
Number of producing wells
GULF
1
well
pro-
tector
yes
yes
3
4.8
33
10
1
1
GULF
4
steel
jacket
yes
yes
3
4.8
' 33
10
4
4
GULF
6
steel
j acket
yes
yes
3
4.8
33
10
6 ' ' .-.
6
GULF
12
steel
jacket
yes
yes
6
9.7
66
20
12
10
GULF
24
steel
j acket
yes
yes
20
32.0
100
30
24
18
GULF
40
steel
j acket
no
yes
50
80.4
200
60
40
32
GULF
58
steel
jacket
no
yes
100
161
590
180
58
50
Source: EPA estimates.
A-15
-------
model projects. Most of these are in the peak production range of 20,000 to 72,000 barrels oil
per day (bopd).
Platforms producing from smaller reservoirs are represented by the 16-wellslot model
project that is patterned after the 6,000 bopd Platform Gina. The larger reservoirs are
represented by the 40-wellslot project patterned after Platform Gail or the 70-wellslot project
patterned after Platform Edith. The number of producing wells expected with each project are
14,33, and 60, respectively. This information is summarized in Table A-8.
A.2.3 Alaskan Model Projects
The Alaskan offshore area is quite diverse. Platform designs range from conventional
platforms in Cook Inlet to severe weather structures in the Arctic areas. Model projects are
selected to span a range of conditions in the Alaskan offshore areas.
Cook Inlet. This model project represents the platform types expected to be used in
southern Alaska—that is, Cook Inlet/Shelikof Strait, Bristol Bay, and Gulf of Alaska. This
region is free of Arctic ice and has moderate environmental conditions. Accordingly,
conventional platform designs similar to existing Cook Inlet structures, including the recently
installed Steelhead platform, define the model projects.
Southern Alaska platforms may be expected to produce oil, gas, or both. Table A-9 lists
information about existing platforms in Cook Inlet (Alaska, 1984; Ocean Industry, 1987b).
Although these are in the Coastal subcategory, they do provide some information for future
offshore projects in Alaska. There are 15 platforms with a total of 326 drilled wells. For oil and
gas projects, a 24-well platform with 20 producers is proposed. A 12-wellslot model project with
10 producing wells is selected to represent gas-only projects in the region. Both the 24-wellslot
and 12-wellslot structures are assumed to be in 50 meters of water and 20 miles offshore.
A-16
-------
TABLE A-8
PROJECT DESCRIPTIONS
PACIFIC REGION
PARAMETER
Platform type
Location
- State waters
- Federal OCS waters
Distance from shore
- mi
- km
Water depth
- ft
- m
Number of wellslots
Number of -producing wells
PACIFIC 16
steel jacket
no
yes
5
8.0
300
90
16
14
PACIFIC 40
steel jacket
yes
yes
3
4.8
300
90 •
40
33
PACIFIC 70
steel jacket
no
yes
5
8.0
1,000
300
70
60
Source: EPA estimates.
A-17
-------
TABLE A-9
PLATFORMS IN COOK INLET
FIELD
N. Cook Inlet (gas -only)
Granite Point
Trading Bay
McArthur River
Middle School Ground
Total
A Platform
Bruce
Anna
Granite Point
Spark
TSA
Monopod
King Salmon
Grayling
Dolly Vardin
Steelhead
Baker
A
C
Dillon
YEAR
INSTALLED
1968
1966
1966
1966
1968
1968
1966
1967
1967
1967
1987
1965
1964
1964
1965
WELLS
DRILLED
12
17
26
17
7
9
31
24
37
36
36
20
24
16
14
326
Source: Johnsion, 1988.
A-18
-------
Arctic Alaska Model Projects
The first Arctic offshore production began at the end of 1987. The Endicott field lies 10
miles northeast of Prudhoe Bay in the State waters of the Beaufort Sea. The field was
discovered in 1978 and production began in October 1987 (Alaska, 1988). This project forms the
basis for the Beaufort Sea gravel island project described below. The other Arctic projects are
based on the 1985 report from the Office of Technology Assessment entitled Oil and Gas
Technologies for the Arctic and Deepwater (OTA, 1985).
Beaufort Sea Gravel Island. The plan to develop the Endicott field includes a 5-mile
causeway into the shallow waters of the Beaufort Sea linking two artificial gravel islands. The
islands are located about 2-1/2 miles off the coast in 4 to 12 feet of water. Eighty to 120
development wells are planned. The EPA project is a single island with 48 wells, half the size of
the Endicott project (Alaska, 1988; Drilling Contractor, 1987),
Beaufort Sea Platform. The Beaufort Sea platform is assumed to be located 20 miles
offshore in 50 feet of water. This location has extremely low temperature conditions and is
covered with ice 10 months out of the year. The OTA report lists this project as being
developed from a gravel island but also notes that alternatives such as concrete, steel, hybrid
structures built as caissons, or complete bottom-mounted units may be preferable, depending on
site-specific conditions. The OTA scenario has seven islands/platforms with a total of 271 wells;
a footnote indicates that the number of wells is probably a minimum. The EPA project is a
single 48-wellslot structure with 40 producing wells.
Norton Basin. The Norton Basin has a slightly more temperate climate than the Beaufort
Sea; ice coverage is only 8 months out of the year. On the other hand, platform designs must
address strong bottom currents and storm surges. As with the Beaufort Sea scenario, the OTA
report initially lists development as a set of four gravel islands with a total of 136 wells. The
same footnote listing platform alternatives to the gravel island is given for the Norton Basin.
The EPA model project assumes a 34-wellslot platform 40 miles from shore in 50-foot water with
28 producing wells.
A-19
-------
Navarin Basin. The Navarin Basin has light-to-moderate conditions with 5-month ice
coverage. In contrast to moderate ice conditions and temperature, the Navarin Basin is also
marked by severe storms, wind-driven waves, spray-icing, and the potential for soft soil. The
OTA report projects either a gravity platform or a steel, pile-founded structure, depending on
site conditions. The proposed location is 400 to 700 miles offshore in 450 feet of water. The
OTA scenario consists of seven production platforms and two service platforms with a minimum
of 271 wells. The EPA project is a single structure with 48 wellslots and 40 producing wells.
Table A-1Q summarizes the information for the Alaska projects.
A3 REFERENCES
Alaska. 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation Commission, n.d.
Alaska. 1988. 5-Year Oil and Gas Leasing Program. Alaska Department of Natural Resources,
January.
California. 1987. 72nd Annual Report of the State Oil and Gas Supervisor. California
Department of Conservation.
Drilling Contractor. 1987. "Endicott oilfield development is on schedule," Drilling Contractor.
August/September, pp. 25-26.
EPA. 1985. Economic Impact Analysis of Proposed Effluent Limitations and Standards for the
Offshore Oil and Gas Industry, prepared for the U.S. Environmental Protection Agency
by Eastern Research Group, Inc., EPA 440/2-85-003, July 1985.
Guerard. 1989. Personal communication between Maureen F. Kaplan, Eastern Research Group,
and William Guerard, California Department of Conservation, 12 May.
Johnson. 1988. Individual well production printouts sent to Maureen F. Kaplan, Eastern
Research Group, Inc., by Elaine Johnson, Alaska Oil and Gas Conservation Committee,
25 February.
MMS. 1986. U.S. Department of the Interior, Minerals Management Service, Pacific Summary
Report/Index November 1984-Mav 1986. MMS 86-0060.
MMS. 1987a. U.S. Department of the Interior, Minerals Management Service, Offshore
Platform Inspection System, Complex/Structure List. April 23.
A-20
-------
TABLE A-10
PROJECT DESCRIPTIONS
ALASKA
PARAMETER
Platform type
Location
- State waters
- Federal OCS
waters
Distance from
shore
- mi
- km
Water depth
- ft
- m
Number of
wellslots
Number of
producing wells
COOK
INLET
OIL,
OIL/GAS
steel
jacket
yes
yes
3
5
50
15
24
20
COOK
INLET
GAS
steel
jacket
yes
yes
5
8
50
15
12
10
BEAU-
FORT
GRAVEL
ISLAND
gravel
island
yes
yes
•3
5
15
5
48
40
.BEAU-
FORT
PLATFORM
steel
structure/
caisson
no
yes
20
32
50
15
48
40
NORTON
BASIN
steel
structure/
caisson
no
yes
40
64
50
15
34
28
NAVARIN
BASIN
gravity
plat-
form
no
yes
400-
700
640-
1,130
450
137
48
40
Source: EPA estimates.
A-21
-------
MMS. 1987b. U.S. Department of the Interior, Minerals Management Service, 5-Year Leasing
Program Mid-1987 to Mid-1992. April.
Ocean Industry. 1987a. "1987 Platform Survey," Ocean Industry. March 1987, pp. 64-68.
Ocean Industry. 1987b. "Steelhead brings new life to aging Cook Inlet field," Ocean Industry,
November, pp. 35-36.
Offshore. 1986. The Gulf of Mexico," Offehore, February, pp. 38-45.
OTA. 1985. Oil and Gas Technologies for the Arctic and DeePwater. Office of Technology
Assessment, Washington, D.C.
A-22
-------
APPENDIX B
BASE CASE TIMING OF PROJECT DEVELOPMENT
B.1 PHASES OF PROJECT DEVELOPMENT
The financial performance of model projects depends upon the timing of costs and
revenues. Costs incurred in the present must be offset by future revenues; revenues whose worth
is reduced by inflation (see Appendix J for details).
In developing the economic models for the 32 model projects, EPA assumes that there
are four phases of project development: exploration, delineation, development, and production.
The exploration phase is the time from the lease sale through exploration well drilling. After a
discovery, additional wells may be drilled to delineate the extent of the reservoir; this occurs
during the delineation phase. The delineation phase is included in the economic model projects
to capture the costs and timing considerations for larger projects. This phase does not occur
with all projects and it is generally subsumed within the discussion of exploratory efforts. Hence,
there is no need for a separate discussion of delineation phase impacts. Delineation wells are
included in the number of projected wells; they are therefore included in the costs of the
regulation.
The development phase includes planning, building, and installing the platform, and
drilling development wells. The production phase is the time during which oil and/or gas is being
produced. EPA assumes that the exploration and delineation phases of the model projects are
discrete in time and that the development phase overlaps the production phase. Six wells are
drilled each year on platforms with up to 12 wellslots (and one operating drilling rig) and 12 per
year are drilled on larger platforms (with two operating drilling rigs). Five-sixths of these wells
are production wells and one-sixth are service wells. Production wells are in full production the
year they are drilled.
B-l
-------
B.2 DURATION OF PROJECT DEVELOPMENT PHASES
The geographic region (climate) in which the project is located, the size of the platform,
water depth, distance from shore, and any previous oil and gas development in the area are
important detemminants of project timing. Length of time for project development varies from 1
year between lease sale and start of production for a single-well structure in the Gulf of Mexico
(located close to shore in 40 feet of water and in a highly developed area) to 12 years for the
Beaufort Sea 48-well platform (located in extremely severe climate conditions). The data sources
for each region are discussed separately below.
B.2.1 Gulf of Mexico
For the Gulf of Mexico, project timing is developed from a series of MMS and industry
sources (MMS, 1982; MMS, 1986a; MMS, 1986b). Exploratory drilling is assumed to begin
within a year of the lease sale. Figure B-l shows the time to first spud date (i.e., the date when
drilling begins on the first exploratory well) for all OCS sales held from 1975 through 1984. The
average annual time to first spud is less than 6 months for this time period, although the times
for any given sale range from a few weeks to 11 months.
No delineation wells are proposed for the small Gulf projects (Gulf 1, Gulf 4, and Gulf
6) so no time accrues between the start of exploration and the start of delineation for these
projects. For the Gulf 12, Gulf 24, and Gulf 40 projects, exploratory wells are drilled within a
year of lease sale. An additional year is spent in exploratory drilling for the Gulf 58 project.
• The time period between the start of delineation and the start of development in the Gulf
4 and Gulf 6 projects is assumed to be 1 year. No additional time is assumed to pass between
the start of delineation and the start of development for the Gulf 12, Gulf 24, and Gulf 40
projects. A two-year period between the start of delineation and the start of development is
assigned to the Gulf 58 project.
B-2
-------
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B-3
-------
For the time between the start of the development to the start of operation, one year is
assigned to the Gulf 1, Gulf 4, and Gulf 6 projects; 2 years are assigned to the larger oil and
oil/gas projects; aind 3 years to the Gulf 24 gas-only project.
The timing assumptions are summarized in Table B-l for the Gulf of Mexico projects.
Figure B-2 shows the time from lease sale to initial production for the 1975 to 1984 period.
Times range from 5 months to over 3 years. Since Figure B-2 shows the time to earliest
production, and we are developing "typical projects," our time frame should be and is at the
higher end of the range. The 6-year schedule for the Gulf 58 project is based on Shell's
Bullwinkle project—a 60-slot platform installed in 1989 on a tract leased in OCS Sale 72 in 1983
(OGJ, 1988c). The time from lease sale to the start of operation ranges from 2 to 6 years. This
is consistent with the information in (1) MMS (1986b), where tracts leased in the April 1984 sale
were in production by mid-1986, but not tracts leased in July 1984 or later sales; (2) MMS
(1987a), where projects in Federal waters are assumed to take 4 years for the central Gulf, 5
years for the western Gulf, and 8 years for the eastern Gulf, and (3) OTA (1985), where
production lead times of 2 years are proposed for the Gulf area.
B.2.2 Pacific
The Pacific region required updating from the 4 to 5 years allowed from base sale to start
of operation (EPA, 1985). Table B-2 summarizes the project timing for several recent and
projected platforms. The time from lease sale to start of operation ranges from 6 to 20 years.
Changing environmental regulations and litigation caused a 5-year delay between platform
installation and production for the Hondo A platform and a 15-year delay in confirmation
drilling on Tract P-0205 (Ocean Industry, 1986 and 1987a).
In light of these developments, tuning for the Pacific projects has been revised from that
given by EPA (1985). Figure B-3 shows the time from lease sales to first spud date in the
Pacific. The times range from less than 1 month to 17 months. We therefore allocate 1 year
between lease sale and the start of exploration for the Pacific model projects.
B-4
-------
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18
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I
9-
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3-
(No walls drilled
to data)
1963 1964 1966 1968 1975 1979 1981 1982 1982 1983 1984
SALE PI P2 • P3 P4 35 48 -53 68 RS53 73 80
Laaca ecilac and yaare held
Figure B-3. Pacific Region: Time From Lease Sale to First Spud Date
Source: MMS 1986a.
B-8
-------
Table B-2 indicates that discovery wells typically were drilled 2 to 3 years after lease sale.
The time between the start of exploration and the start of delineation when the discovery would
occur is therefore 1 to 2 years. Platforms have been set 4 or more years from the lease sale, or
from 1 to 4 years after the start of delineation. Production usually occurs within 1 to 3 years
after the .platform has been set, depending on how much other construction is required. For
example, at the end of 1987, platforms Harvest and Henriosa had wells drilled but were waiting
for onshore processing facilities to be completed prior to going into production (Rau, 1987).
This information is summarized in Table B-3. The time from lease sale to start of
operation now ranges from 5 to 10 years. The revised project timing also agrees with the
information in Figure B-4 on the time from lease sale to initial production. The range in project
timing corresponds well to that in the United States for the 5-year leasing plan (MMS, 1987a)
where West Coast projects take from 5 to 10 years from lease sale to initial production. For
deepwater projects off California, OTA (1985) estimates a production lead time of 10 years.
B.2.3 Alaska
Project timing varies greatly in Alaska depending upon where the project is located. For
the Cook Inlet projects, the area is relatively free of severe climatic conditions and the region is
mature in terms of oil and gas development, so many facilities are already in place. The
platforms that exist in Cook Inlet are in the coastal subcategory. Information about these
platforms can be used to estimate timing for model projects in a relatively ice-free area in
offshore Alaskan waters. The Beaufort Sea/North Slope region now has the trans-Atlantic
pipeline in place, while the Bering Sea is undeveloped. Project timing, then, is shortest in the
Cook Inlet area and longer for the Arctic regions.
Figure B-5 shows the time from lease sale to spud date of the first exploratory well. The
range is from 5 to 36 months, with an average of 18 months. We allocate 1 year to the time
between lease sale and the start of exploration for the Cook Inlet projects and 2 years for
projects in other areas.
B-9
-------
TABLE B-3
PROJECT TIMING
PACIFIC REGION
TIMING
PACIFIC
16
OIL AND
OIL/GAS
PACIFIC
40
GAS
ONLY
PACIFIC
70
PACIFIC
16
Years between lease sale and start 1
of exploration
Years between start of exploration 1
and start of delineation
Years between start of delineation 1
and start of development
Years between start of development 2
and start of operation
Total years between lease sale and 5
start of operation
10
Source: EPA estimates.
B-10
-------
70
60-
50-
40-
30-
20-
10-
(no production)
81. ZD
i
(no production to data)
1963 1964 1966
SALES PI P2 P3
1968 1975 1979 1981 1982 1983 1984
P4 35 48 53 RS53 & 68 73 80
Leaca sales and yearn held
Figure B-4. Pacific Region: Time From Lease Sale to Initial Production
Source: MMS 1986a.
B-ll
-------
40-
35
30
20
10
5
1976 1977 1978 1979 I960
SALE 39 CI BF 55 80
LOOM
lo* and y*ar
1981
71
> h«ld
1982
70
1983
57
Figure B-5. Alaska Region: Time From Lease Sale to First Spud Date
Source: MMS 1986a.
B-12
-------
The Steelhead platform is the first platform to be installed in Cook Inlet since 1968. The
jacket was installed in mid-1986 and production was expected to begin by the end of 1987. On
this basis, 2 years are allocated for the time between the start of development and the start of
production for the Cook Inlet projects (MMS, 1987b; Ocean Industry, 1987d).
In the Endicott field in the Beaufort Sea region, the final permits for development were
issued in January 1985. By the end of 1986 the gravel project was completed, and by the end of
1987 the equipment sealift was completed and initial production begun (Drilling Contractor,
1987a and 1987b). On this basis, 3 years are allocated for the time from the start of
development to the start of operation for the Beaufort gravel island, and platforms in the
Beaufort Sea, Norton Basin, and Navarin Basin.
The Endicott field was discovered in 1978 and began production in 1987 (Drilling
Contractor, 1987b). A range of 7 to 10 years is allocated for the time between the start of
exploration and start of operation for the Beaufort Sea gravel island projects. The Beaufort Sea
platform is assumed to take 1 year longer than the Beaufort Sea gravel island because it is
located further offshore and in deeper water. A total of 5 years is allocated to this period for
the Cook Inlet projects. ,
Project timing assumptions for Alaska projects are summarized in Table B-4. The time
span ranges from 6 years for projects in Cook Inlet to 12 years for projects in the Beaufort Sea.
The project lead times for platforms in the Norton Basin (9 years), Navarin Basin (11 years), and
the Beaufort Sea (12 years) correspond to those presented in OTA (1985). This range is
somewhat broader than that proposed in the EIS for the 5-Year Leasing Plan where Alaska
projects take 9 to 12 years from lease sale to first development (MMS, 1987a) to allow for more
variation in the analysis. It is unlikely that projects in the well-developed Cook Inlet area would
have a 9-year project lead time.
B 3 REFERENCES
Drilling Contractor. 1987a. "Arctic: Poor economics delay prospecting," Drilling Contractor.
February/March, pp. 17-19.
B-13
-------
TABLE B-4
PROJECT TIMING
ALASKA
TIMING
MODEL PROJECT
OIL
OIL/
GAS GAS
BEAU-
FORT
COOK GRAVEL BEAUFORT NORTON NAVARIN COOK COOK
INLET ISLAND PLATFORM BASIN BASIN INLET INLET
Years between lease sale 1
and start of exploration
Years between start of 1
exploration and start
of delineation
Years between start of 2
delineation and start
of development
Years between start of 2
of development and
start of operation
Total years between 6
lease sale and
start of operation
11
12
9 11
Source: EPA estimates.
B-14
-------
Drilling Contractor. 1987b. "Endicott oilfield development is on schedule," Drilling Contractor.
August/September, pp. 25-26.
EPA. 1985. Economic Impact Analysis of Proposed Effluent Limitations and Standards for the
Offshore Oil and Gas Industry, prepared for the U.S. EPA by Eastern Research Group,
EPA 440/2-85-003, July.
MMS. 1982. U.S. Department of the Interior, Minerals Management Service, Draft Regional
Environmental Impact Statement. Gulf of Mexico, August.
MMS. 1986a. U.S. Department of the Interior, Minerals Management Service, PCS National
Compendium. MMS 86-0017, May.
MMS. 1986b. U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico
Summary Report/Index November 1984-June 1986. MMS 86-0084.
MMS. 1986c. U.S. Department of the Interior, Minerals Management Service, Pacific Summary
Report/Index. November 1984-Mav 1986. MMS 86-0060.
MMS. 1987a. U.S. Department of the Interior, Minerals Management Service, Proposed 5-Year
Outer Continental Shelf Oil and Gas Leasing Program. Mid-1987 to Mid-1992. Final
Environmental Impact Statement, MMS 86-0127, January.
MMS. 1987b. U.S. Department of the Interior, Minerals Management Service, Alaska Summary
Index: January 1986-December 1986. MMS 87-0016.
Ocean Industry. 1986. "Activity moves ahead off California coast," Ocean Industry. October, pp.
24-27.
Ocean Industry. 1987a. "Chevron's Gail platform launched—finally." Ocean Industry. May, p. 11.
Ocean Industry. 1987b. "1987 Platform Survey," Ocean Industry. March, pp. 64-68.
Ocean Industry. 1987c. "Chevron skirts obstacle, will drill from Gail early next year," Ocean
Industry. December, p. 9.
Ocean Industry. 1987d. "Steelhead brings new life to aging Cook Inlet field," Ocean Industry.
November, pp. 35-36.
Offshore. 1987a. "Field developers proceed cautiously in recovery," Offshore. November, pp. 30-
36.
OGJ. 1988. "Oil and gas production to build on 5-year-old leases in Gulf," Oil and Gas Journal.
4 January, pp. 15-18.
OTA. 1985. Office of Technology Assessment. Oil and Gas Technologies for the Arctic and
Deepwater. Washington, DC, May.
B-15
-------
Rau, D. 1987. Personal communication between Maureen F. Kaplan, Eastern Research Group,
Inc., and Denny Rau, Minerals Management Service, Pacific Office, Ventura District, 15
December.
B-16
-------
APPENDIX C
LEASE PRICES
The economic model begins with the purchase of the lease for exploration and
development. The lease cost is amortized over the productive life of the project, and is taken as
a depletion allowance on a company's income statement (see Section J.2.4.1).
The lease price for each model project is a function of four factors:
Lease Price =
Price per X Exploratory Wells
Tract Discovery Well
Ratio of Expected
Production
Platforms
Discovery Well
The price per tract is the average price paid for tracts in that region in 1986. These prices are
described in Section C.I. The ratio of the number of successful exploratory wells ("discovery
well") to all exploratory wells is the fraction of exploration wells that successfully discover
economic oil or natural gas. This fraction is also called the discovery efficiency and is discussed
in Section C.2. The number of platforms per discovery well is described in Section C.3. Section
C.4 describes the methodology used to scale the lease costs by the ratio of expected production
for the various model projects to the production of a typical project for the region.
C.1 AVERAGE LEASE COST PER TRACT
Lease sales have been held annually for OCS tracts in the Gulf of Mexico for many years.
The most recent lease sales for the Pacific and Alaska were held in 1984 and 1984, respectively.
To estimate 1986 lease prices for the Gulf of Mexico, we use the average cost per tract from the
1986 lease sale (see Table C-l). The Gulf of Mexico is a well-studied, mature producing region.
Prices in the area rise and fall according to market prices. If lower prices are being paid for
tracts in the Gulf of Mexico, lower prices are assumed to be paid for tracts in other regions.
C-l
-------
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To estimate lease prices for other regions, we use the ratio of 1986/1983 prices and
1986/1984 prices for the Gulf of Mexico (see Table C-l). The price per acre in the most recent
lease sale is multiplied by the appropriate ratio to obtain an estimated 1986 cost per acre for that
region. The cost per acre is multiplied by the average tract size in the most recent year to arrive
at the estimated price per tract. For example, the most recent lease sale in the Pacific was held
in 1984 (see Table C-2). The cost per acre in 1984 ($543.19) is multiplied by the 1986/1984 ratio
of the Gulf of Mexico prices (0.53) to estimate a cost per acre of $286.15 in 1986. The average
tract size in 1984 was 4,972 acres. The estimated average lease price in 1986 is 4,972 x $286.15,
or $1,422,814.
The information for Alaska is presented in Table C-3. The 1984 prices were used to .
estimate 1986 prices. For Alaska, there is also information on sales in State waters and the
prices are far lower than for the Federal regions. The 1986 State lease prices are used for the
Cook Inlet projects while the estimated 1986 Federal lease prices are used for the Arctic
projects.
C.2 DISCOVERY EFFICIENCY
Discovery efficiency is a parameter representing the fraction of exploration wells that
successfully discover economic petroleum reserves. For example, if five wells are drilled in a
basin, and one is successful, the discovery efficiency is 1/5 or 0.20. The inverse of the discovery
efficiency is the number of exploratory wells that must be drilled to obtain a single successful
well.
For this report, we choose to calculate discovery efficiencies based on historical data,
using all exploratory wells drilled as of January 1,1985 (API, 1988, Section XI, Table 7).
Discovery efficiencies may be calculated on a year-by-year basis, but since the number of offshore
wells drilled in any given year is small, we prefer to use the all-time data. This information is
presented in Table C-4. Note the effects of rounding: for the Pacific and Gulf of Mexico, the
discovery efficiency is 0.14, rounded up from the more precise estimate of 0.135. The number of
C-3
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disc_eff.wlc1
TABLE C-4
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Region
Number of
Exploratory
Discovery Wells Per
OH Gas Dry Total Efficiency Discovery
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal-GOH
TOTAL GULF OF MEXICO
GRAND TOTAL
20
44
0
0
0
44
0
0
267
45
0
312
376
7
10
0
0
0
10
2
0
349
273
0
624
641
73
294
8
6
38
346
0
24
3999
1732
241
5996
6415
100
348
8
6
38
400
2
24
4615
2050
241
6932
7432
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.14
3.70
7.41
7.41
7.31
Mote: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API 1988; HHS 1986b.
C-6
-------
exploratory wells per discovery well (7.41) is the inverse of the more precise figure (0.135) rather
than of the rounded figure (0.14).
C.3 NUMBER OF PLATFORMS PER DISCOVERY WELL
The number of platforms per discovery well is a measure of the quantity of reserves
identified by that well. In the economic model, the cost of all exploratory wells (successful and
unsuccessful) is divided among the number of platforms that tap the discovered field.
A year for which we have consistent data for the number of discovery wells and the
number of platforms is 1984. As of 1 January 1985, there were 936 discovery wells in the Gulf of
Mexico (see Table C-4). At the end of 1984, there were 3,155 platforms in Federal waters and
an additional 901 in State waters (MMS, 1986c). This results in a ratio of (3,155+901)7936, or
4.3 production platforms per discovery.
For the Pacific, older offshore discoveries are produced from onshore completions and
from artificial islands; a historical analysis is unlikely to provide a valid ratio. Based on the
number of platforms installed in existing identified fields (see Table A-l), a projected ratio of 2.0
platforms per discovery is used in this analysis.
For Alaska, relatively few wells are projected to be drilled during the 1986-2000 period
(see Section 4). Such a situation could occur if only one platform is drilled per discovery well
and that assumption is used here.
C.4 RATIO OF EXPECTED PRODUCTION
Section C.I derives the average lease cost for a project in various OCS regions. The
average lease cost should be scaled upwards or downwards according to the size of the model
project. For each region, a typical project is chosen. The lease prices for the other projects in
the region are scaled upwards or downward depending on whether the project is larger or smaller
C-7
-------
than the typical project. The number of producing wells in the project is used as a surrogate
index to represent the expected value of reserves used by a company in formulating a bid. This
assumes thai: if, for example, a tract results in a 58-well platform, the company had good reason
to believe that a very large reservoir underlay the tract prior to bidding.
For the Gulf, a project with 4 producing wells is considered typical (i.e., the Gulf 4
«
project). As of October 1985, there were 1,563 platforms with 4 wells or fewer (see Table A-3)
while there was a total of 3,155 platforms (all sizes) at the end of 1984 (MMS, 1986c). A 4-well
platform has, a production ratio of 1.0 and the lease price is scaled accordingly.
For the Pacific, the 40-well platform with 33 producing wells is considered typical. The
70-well platform with 60 producing wells has a production ratio of 1.8. Only one project is
envisioned for the Atlantic, so the production ratio must be 1.0.
Projects in Cook Inlet. Alaska, are already scaled according to expected production (20
producing wells for oil or oil/gas, and 10 producing wells for the gas-only project), so the
production ratio is 1.0. For the Arctic projects, 40 producing wells is considered typical, thereby
giving the smaller Norton Basin project a production ratio of 0.7.
Table C-5 lists the model projects, number of producing wells, production ratios, average
lease prices, number of exploratory wells per discovery wells, and the number of platforms per
discovery. The right-hand column of Table C-5 is the model project lease price used in the
economic analysis.
C5 . REFERENCES
Alaska. 1987. Alaska Department of Natural Resources, Five-Year Oil and Gas Leasing
Program, January.
API. 1988. Basic Petroleum Data Book. American Petroleum Institute, Vol. VIII, No. 1,
January.
C-8
-------
$lease.uk1
21-Dec-92
TABLE C-5
LEASE PRICES FOR MODEL PROJECTS
Number of
Model Producing Production
Region Project Wells Ratio
Gulf 1
4
6
12
24
40
58
Pacific 16
40
70
Alaska Cook Inlet
Cook Inlet-gas
Beaufort-gravel
Beaufort-plat.
Norton
Navarin
1
4
6
10
18
32
50
14
33
60
20
10
40
40
28
40
0.3
1.0
1.5
2.5
4.5
8.0
12.5
0.4
1.0
1.8
1.0
1.0
1.0
1.0
0.7
1.0
Exploratory
Lease Wells/
Price Discovery
($000) Well
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,318
$1,423
$1,423
$1,423
$15
$15
$1,918
$1,918
$1,918
$1.918
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
7.41
3.70
3.70
3.70
3.70
3.70
3.70
Model
Platforms/ Project Lease
Discovery Price ($000)
4.3
4.3
4.3
4.3
4.3
4.3
4.3
2.0
2.0
2.0
.0
.0
.0
.0
.0
.0
$568
$2,271
$3,407
$5,678
$10,221
$18,170
$28,391
$2,236
$5,272
$9,585
$56
$56
$7,097
$7,097
$4,968
$7,097
Note: 1986 dollars.
Source: EPA estimates.
C-9
-------
MMS. 1986a. U.S. Department of the Interior, Minerals Management Service, Outer
• Continental Shelf Statistical Summary 1986. OGS Report, MMS 86-0122, December.
MMS. 1986b. U.S. Department of the Interior, Minerals Management Service, Atlantic
Summary Index: January 1985 - June 1986. OCS Information Report, MMS 86-0071.
MMS. 1986c. U.S. Department of the Interior, Minerals Management Service, Federal Offshore
Statistics; 1984. OCS Report, MMS 86-0067.
MMS. 1987a. U.S. Department of the Interior, Minerals Management Service, Federal Offshore
Statistics: 1985. OCS Report, MMS 87-0008.
MMS. 1987b. U.S. Department of the Interior, Minerals Management Service, Proposed 5-Year
Outer Continental Shelf Oil and Gas Leasing Program. Mid-1987 to Mid-1992. Final
Environmental Impact Statement, MMS 86-0127, January.
C-10
-------
APPENDIX D
EXPLORATION PHASE ASSUMPTIONS
The exploration phase assumptions include geological and geophysical expenses, discovery
efficiency, drilling costs, and the number of platforms built per successful exploration well. The
data and methodology used to develop estimates for each of these parameters are discussed in
separate sections below. Exploratory costs are apportioned to successful efforts (see Section
D.4). Hence the economic model addresses costs from all phases prior to production and
through the operating life of the project.
D.1 GEOPHYSICAL AND GEOLOGICAL COSTS
Before a decision to drill is made, the proposed site is subjected to a variety of geological
and geophysical prospecting procedures. These may include seismic analysis of the particular site
and a study to evaluate the geological structures with regard to known neighboring productive
formations. These costs are modeled as a percentage of the lease bid. For offshore production
in the lower 48 States, this percentage ranged from 6.5 percent in 1980 to 16.3 percent in 1984 to
110.5 percent in 1986 (Commerce, 1982; API, 1986; API, 1987a). Onshore and offshore
components have not been separated for Alaska in the recent API surveys. For this region,
geological and geophysical costs ranged from 33 percent of lease bids in 1980 to 12.6 percent in
1984 to 107.7 percent in 1986 (Commerce, 1986; API, 1986; API, 1987a). The 1986 values are
used in this analysis.
D-l
-------
D.2 DISCOVERY EFFICIENCY
A discovery efficiency is the fraction of wells drilled that are successful in locating
economically recoverable deposits of oil and/or gas. This parameter is discussed in Section C.2.
The discovery efficiencies are repeated in Table D-l for convenience.
D3 DRILLING COSTS
The drilling costs per well are based upon the data in the 1986 Joint Association Survey
on Drilling Costs (API, 1987b). The number of oil or gas wells, footage drilled, and costs for the
different State and Federal offshore regions are given in Table D-2. Regional summaries are
given for the Gulf of Mexico, Pacific and Alaska. The data in Table D-2 include exploratory,
delineation, and development wells (Oshinski, 1988).
Table D-3 summarizes average well depths and costs. It is apparent that dry holes tend
to have a higher cost per foot than productive wells, particularly in Alaska and the Pacific.
These data highlight some of the distinctive features of offshore operations. Exploratory and
delineation wells are drilled from mobile drilling rigs, which is more expensive than drilling
development wells from a fixed platform. Exploratory and delineation wells are plugged and
abandoned at the end of operations after all information is gathered. Even if economically
recoverable deposits of petroleum are identified, exploratory wells are not turned into production
wells. Dry hole costs, then, predominantly reflect exploratory well costs. There is some
corruption by a small number of dry development wells. It is not possible to separate these
effects from the available data, but the effects are presumed to be minor. On this basis, dry hole
costs .for each region are used as exploratory well costs. The average regional well depths shown
here are similar to but not the same as those shown in the Development Document or preamble
because these reflect one year of data (1986) while the Development Document estimates reflect
five years of data.
D-2
-------
disceff2.wk1
TABLE D-1
TOTAL EXPLORATORY OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Region
Alaska
California
Oregon
Washington
Federal Pacific
TOTAL PACIFIC
Alabama
Florida
Louisiana
Texas
Federal -COM
TOTAL GULF OF MEXICO
GRAND TOTAL
Oil
20
44
0
0
0
44
0
0
267
45
0
312
376
Gas
7
10
0
0
0
10
2
0
349
273
0
624
641
Dry
73
294
8
6
38
346
0
24
3999
1732
241
5996
6415
Number of
Exploratory
Discovery Wells Per
Total Efficiency Discovery
100
348
8
6
38
400
2
24
4615
2050
241
6932
7432
0.27
0.16
0.00
0.00
0.00
0.14
1.00
0.00
0.13
0.16
0.00
0.14
0.14
3.70
7.41
7.41
7.31
Note: Well count includes wells in both Federal and State waters.
na = not applicable
Source: API 1988; HMS 1986a.
D-3
-------
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D.4 NUMBER OF PLATFORMS PER DISCOVERY WELL
The cost of the lease and exploration efforts is shared by the number of platforms built
per discovery well. This number of platforms per discovery well is discussed in Section C.3. For
convenience, the information is reproduced here:
• Alaska - one platform per discovery
• Gulf - 4.3 platforms per discovery
• Pacific - 2 platforms per discovery.
D.5 REFERENCES
API. 1986. 1984 Survey on Oil and Gas Expenditures. American Petroleum Institute,
Washington, DC, October.
API. 1987a. 1986 Survey on Oil and Gas Expenditures. American Petroleum Institute,
Washington, DC, December.
API. 1987b. 1986 Joint Association Survey on Drilling Costs. American Petroleum Institute,
Washington, DC, November.
API. 1988. Basic Petroleum Data Book. American Petroleum Institute, Vol. VIII, No. 1,
January.
Commerce. 1982. U. S. Department of Commerce, Bureau of the Census, Annual Survey of Oil
and Gas. 1980. Current Industrial Reports, MA-13k(80)-l, March 1982. These surveys
were not continued beyond 1982 data. The American Petroleum Institute (API)
undertook its survey due to the termination of the one by the Bureau of the Census.
Efforts have been made to maintain continuity between the surveys although less detailed
information is available in the API publications.
MMS: 1986. Atlantic Summary/Index; January 1985 - June 1986. U.S. Department of the
Interior, Minerals Management Service, OCS Information Report, MMS 86-0071.
Oshinski. 1988. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc., and John Oshinski, Statistics Department, American Petroleum Institute,
Washington, DC, 22 February.
D-6
-------
APPENDIX E
DELINEATION PHASE ASSUMPTIONS
The delineation phase of offshore oil and gas reserves involves the collection of adequate
geological and reservoir data to determine the size, shape, and physical characteristics of the
discovered petroleum supply. This usually involves drilling one or more delineation wells. Not
all projects have a delineation phase. The phase is included in the economic model to capture
the costs and timing considerations for larger projects. Delineation efforts are generally included
in discussions of oil and gas exploration. Hence there is no need for a separate analysis of
delineation phase impacts. Delineation wells are included in the number of projected wells; they
are therefore included in the cost of the regulation. ,
The two parameters of interest for this phase are: cost per delineation well, and number
of delineation wells per project. Each parameter is discussed in a separate section below.
E.1 COST PER DELINEATION WELL
Delineation wells differ from exploration wells in that more geologic data are collected in
the form of directional drilling, cores, and logs. The well costs presented in the Joint Association
Survey on drilling costs, however, are a composite of all wells—exploratory, delineation, and
development (Oshinski, 1988). For this study, we use the same cost for delineation wells as for
exploration wells, that is, dry hole costs. The logic behind using dry hole costs is discussed in
Section D.3. The regional delineation well costs are presented here for convenience:
• Alaska - $13,851,011.
• Pacific - $5,887,793.
• Gulf of Mexico - $4,354,555.
E-l
-------
E.2 NUMBER OF DELINEATION WELLS PER PROJECT
The OTA report on oil and gas technologies for the Arctic and deepwater assume that 5
delineation wells will be used except for the nearshore Gulf of Mexico, where only 3 are drilled
(OTA, 1985, p. 118). Table E-l summarizes information on the number of delineation wells
planned or drilled for several projects. As these data show, the OTA estimates are too high. In
addition to the data in Table E-l, it should be noted that some projects in the Gulf of Mexico
proceed without delineation wells. For example, Standard Oil is seeking in-house design
approval of a platform for development of a discovery on Ewing Bank block 826, without any
mention of delineation wells (Ocean Industry, 1986b).
On the basis of this information, EPA proposes the following number of delineation wells
per project:
• No delineation wells - Gulf 1 and Gulf 4.
• 1 delineation well - Gulf 6.
• 2 delineation wells - Gulf 12, Gulf 24, Gulf 40, Gulf 58, Pacific 16, Pacific 40,
Pacific 70, Cook Inlet 24, and Cook Inlet 12.
• 3 delineation wells - Beaufort Sea gravel island, Beaufort Sea platform, Bering
platform, and Norton platform.
E3 REFERENCES
Ocean Industry. 1982. "Gas & Oil Wrapup," Ocean Industry. June. pp. 113-119.
Ocean Industry. 1986a. "Exploration and development continue in Beaufort Sea," Ocean
Industry, October, pp. 34-40.
Ocean Industry. 1986b. "Gulf of Mexico operators respond to new challenges," Ocean Industry.
October, pp. 15-20.
OGJ. 1984. "Exxon Wants Big Expansion Unit on North Slope," Oil and Gas Journal. February
20. pp. 34-35.
E-2
-------
delin.wkl
28-Feb-92
TABLE E-1
NUMBER OF DELINEATION WELLS FOR TYPICAL OFFSHORE PROJECTS
Region
Field Block
Number of
Delineation
Wells
References
Alaska
Endicott
(Sag River/
Duck Island)
Seal Island
Sandpiper
Colvilie Delta
Pacific Sockeye
Huesco
Gulf of
Mexico
High Island
Vermillion
S. Marsh Is.
Matagorda Is.
Mustang Is.
Green Canyon
Viosca Knoll
A-487
A-476
76
236
487
739
21
52
60
862
3
3-4
2
4
3
1
1
1
1
1
1
2-3
2
2-4
2-3
1
OGJ 1984
Ocean Industry 1986a
Ocean Industry 1986a
Ocean Industry 1986a
PEI 1983
PEI 1983
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Ocean
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
Industry
1982
1982
1982
1982
1986b
1986b
1986b
1986b
1986b
1986b
E-3
-------
Oshinski. 1988. Personal communication between Maureen F. Kaplan, Eastern Research
. Group, Inc., and John Oshinski, Statistics Department, American Petroleum Institute, 25
February.
OTA. 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office of Technology
Assessment, Washington, DC.
PEL 1983. "The Pacific Coast," Petroleum Engineer International 55, December, pp. 21-23.
E-4
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APPENDIX F
DEVELOPMENT PHASE ASSUMPTIONS
The development phase involves the construction and installation of production structures
and the drilling of development wells. The development phase is included in the economic
model to address timing considerations and costs incurred to produce oil and gas once a
reservoir has been identified by the exploration and delineation phases. The parameters needed
to define the development phase of the economic model are:
• Platform/gravel island cost
• Lease equipment cost (also known as deck equipment cost)
• Development well cost
• Number of development wells
• Number of wells installed each year
Each of these parameters is discussed in a separate section below.
F.1 PLATFORM/GRAVEL ISLAND COST
The Joint Association Survey on drilling costs instructs the operator to report
expenditures through the "Christmas tree," the assembly of valves, pipes, and fittings used to
control the flow of oil and gas from the casinghead. For our project, it is useful to quote from
the instructions for the survey:
"Do not report the cost of lease equipment such as artificial lift equipment and downhole
lift equipment, flow lines, flow tanks, separators, etc. that are required for production...
F-l
-------
For OFFSHORE WELLS, include costs on fixed platforms and islands. Where facilities
' serve more than one well, the costs should be allocated to each well on the basis of the
operator's best current estimate of the ultimate number of wells that will use the facility.
Also include cost expirations (depreciation and amortization) for company-owned mobile
platforms, barges, and tenders."
(API 1987a, Appendix B, p. 1)
In other words, platform and island costs are included in the well costs used in this report.
Lease equipment costs, however, are not included in the well costs and are estimated separately
in Section F.2.
F.2 LEASE EQUIPMENT COSTS
For the offshore production in the Lower 48 States, the average cost of lease equipment
is based on the 1986 Annual Survey of Oil and Gas Expenditures line entry for lease equipment
(API, 1987b, Table HI; Oshinski, 1988). The 1986 expenditure for offshore lease equipment is
$1,032 million. According to the JAS survey on drilling, 898 offshore wells were drilled in 1986;
885 of these were in the lower 48 States. This results in an average of $1.166 million
($1,032/885) in lease equipment per offshore well. To obtain the lease equipment costs for each
project, we multiply $1.166 million by the number of producing wells in that project see (Table
F-l).
A different procedure must be used for Alaska because the survey does not differentiate
between onshore and offshore costs for lease equipment (API, 1987b). Several different sources
of actual and estimated costs are used for the Alaska projects.
For the Cook Inlet projects, costs are based on the Steelhead platform. OGJ (1986)
refers to a $200 million project. We use an estimate of $200 million for the lease equipment cost
for the 48-wellslot platform. Using the same assumption as OTA (1985), that there are no
economies of scale on development costs, lease equipment costs are estimated at $100 million for
the 24-wellslot platform and $50 million for the 12-wellslot platform. This is approximately $5
F-2
-------
Equip.wk1
TABLE F-1
LEASE EQUIPMENT COSTS - GULF AND PACIFIC
»
f
Region Project
Gulf 1b
4
6
12
24
48
58
Pacific 16
40
70
lumber of
'reducing Lei
Wells Co:
1
4
6
10
18
32
50
14
33
60
ase Equipment
sts ($MM 1986)
$1.166
$4.664
$6.996
$11.660
$20.988
$37.312
$58.300
. $16.324
438.478
$69.960
Source: EPA estimates.
21-Dec-92
F-3
-------
million per producing well, or about four times as expensive as for projects in the lower 48 States
offshore region.
The development cost for the Beaufort Gravel Island is based on the figures available for
the Endicott field. Offshore (1986) cites a $1.4 billion development cost. Ocean Industry
(1987b) mentions that the gravel project was completed ahead of schedule and $600 million
under budget. This results in an estimate of $800 million to develop the Endicott field. The
study by the Office of Technology considers platform and facilities to account for 65 to 70
percent of total development costs (OTA, 1985, p. 118). We follow the OTA methodology and
use the midpoint, 67.5 percent, as the percentage of development costs not associated with
drilling. This results in an estimated $540 million in lease equipment costs. Since the Endicott
field has two islands, the estimated cost per island is $270 million, or about $6.75 million per
producing well.
The lease equipment costs for the Beaufort platform. Navarin platform, and Norton
platform are based on the information in OTA (1985). For the Arctic deepwater projects, only
engineering estimates are available since there are no such existing projects. We begin with the
OTA estimated development costs (Table F-2, right-hand column), obtain the non-drilling
development costs by multiplying by 67.5 percent, and divide by the number of platforms/islands
in the scenario. The resultant 1984 costs are then deflated by 0.4 percent to 1986 costs, based on
the implicit price deflators for gross national product for producers' durable equipment
(Economic Report, 1987, Table B-3).
Table F-2 summarizes the cost estimates for the Alaska projects. Lease equipment costs
range from $50 million in Cook Inlet to $524.4 million in the Navarin Basin. On a per-
producing-well basis, lease equipment costs range from $5 million to $13.11 million, or 4 to 12
times the cost for offshore wells in the lower 48 States. As a check on these figures, we divide
the $1,039 million spent in 1986 for lease equipment (API, 1987a) by the 257 wells drilled in
Alaska in 1986 (API, 1987b). This is approximately $4 million per well. If lease equipment costs
are less for onshore wells in Alaska as they are in the lower 48 States, then the estimate falls
within the range projected for the analysis.
F-4
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F.3 DEVELOPMENT WELL COSTS
Development well costs are based on the costs for productive wells (see Table F-3).
These estimates must be adjusted upwards to account for dry development wells. The regional
discovery efficiencies for offshore development wells are given in Table F-4. The composite cost
for a development well is the cost of a productive development well plus the fraction of a dry
development well. The equation used is: .
Composite cost for a
development well
Cost per development well +
[number of development wells per producing well -1)
*(dry hole cost per foot) * depth of producing well
For an oil well in the Gulf of Mexico, the composite development well cost is $3,364,631 + (.4 x
$389.81 x 9,8885) or $4,905,866. Table F-5 summarizes development well costs for the Gulf of
Mexico. Pacific, and Alaska regions.
F.4 NUMBER OF PRODUCTION WELLS PER PLATFORM
The number of production wells in use at an offshore platform varies widely, depending
on the success of drilling programs, the size of the reservoir, the need for injection programs to
maintain production, and project economics. The MMS Platform Inspection System Complex list
shows widely varying situations. For example, some mature 12-wellslot platforms have never
produced from more than 3, 4, or 5 wellslots while others are producing from all 12. Based on
the MMS data, the average platform in the Gulf of Mexico is producing from three-fourths to
five-sixths of its wellslots. Model projects were defined to fall within these bounds.
F.5 RATE OF INSTALLATION OF DEVELOPMENT WELLS
EPA has used the drilling rate of 6 wells per year per drilling rig. For platforms with
more than 12 wellslots, two drilling rigs are assumed. This means that small projects, such as the
Gulf 4, are brought to peak production in their first year. Twelve-well platforms are developed
F-6
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dev disc
TOTAL DEVELOPMENT OFFSHORE WELLS DRILLED TO JANUARY 1, 1985
Number of
Development
Discovery Wells Per
Gas Dry Total Efficiency Producing^Well
Alaska
California
Alabama
Louisiana
Texas
Federal-GOM
TOTAL GULF OF MEXICO
259
3516
8144
104
69
8318
13
25
4
4283
454
19
4757
32
327
1
4480
700
58
5239
304
3868
3
16907
1258
146
18314
0.89
0.92
0.67
0.74
0.44
0.60
0.71
1.12
1.09
1.40
Hotei"well count includes wells in both Federal and State waters.
Source: API, 1988.
F-8
-------
devjcost.wkl
DEVELOPMENT WELL COST - 1986 DATA*
Region
Gulf
Pacific
Alaska
Type of
Production
oil, oil/gas
gas
oil, oil/gas
gas
oil, oil/gas
gas
Number of
Development
Wells Per
Producing
Well
1.4
1.4
1.09
1.09
1.12
1.12
Average
Depth
(ft)
9,885
11,174
6,872
6,477
10,868
7,721
Cost per foot <$/ft>
Productive Dry
$340.37 $389.81
$408.05 $389.81
$267.98 $833.59
$721.18 $833.59
$335.47 $1,507.90
$231.95 $1,507.90
Composite Cost
per
' Development
Well ($)
$4,905,866
$6,301,845
$2,357,117
$5,157,007
$5,612,431
$3,187,985
Note: Current dollars.
Source: EPA estimates, see Table D-2.
F-9
-------
within 2 years while larger platforms, e.g., 40 to 60 wells, require a 3- to 5-year development
period. The 1- to 5-year period corresponds well with the 1- to 4-year span seen under "most
intense development and production" in the MMS EIS for the 5-year leasing program (MMS,
1987, Table IV.A.1-1).
F.6 REFERENCES
API. 1987a. 1986 Joint Association Survey on Drilling Costs. American Petroleum Institute,
Washington, DC, November.
API. 1987b. 1986 Survey on Oil and Gas Expenditures. American Petroleum Institute,
Washington, DC, November.
API. 1988. Basic Petroleum Data Book. Vol. VIII, No. 1, American Petroleum Institute,
Washington, DC, January.
Economic Report. 1987. Economic Report of the President. 1987. Council of Economic
Advisors, Washington DC, January.
MMS. 1987. U.S. Department of the Interior, Minerals Management Service. Proposed 5-Year
Outer Continental Shelf Oil and Gas Leasing Program. Mid-1987 to Mid-1992: MMS 86-
0127, January.
Ocean Industry. 1987a. "Giant fields set to boost California, Alaska output," Ocean Industry.
October, pp. 27-33.
Ocean Industry. 1987b. "Endicott oilfield development is on schedule," Ocean Industry.
August/September, pp. 25-26.
Offshore. 1986. "The World Offshore: Alaska," Offshore. July. p. 11.
OGJ. 1986. "New Cook Inlet platform to get drilling modules," Oil and Gas Journal. 17
November, p. 32.
Oshinski. 1988. Personal communication between Maureen F. Kaplan, Eastern Research Group
Inc., and John Oshinski, Statistics Department, American Petroleum Institute,
Washington, DC, 25 February.
OTA. 19S5. Oil and Gas Technologies for the Arctic and Deepwater. Office of Technology
Assessment, Washington, DC, May.
F-10
-------
APPENDIX G
PROPUOTPN/OPERATION PHASE ASSUMPTIONS
Hie production and operation phase of an offshore project encompasses the period of
time from first oil or gas production until shutoff of all wells. It is during this phase that
revenues are accrued. The project shuts down when the revenues for the year are insufficient to
cover that year's costs. Project lifetime determines, in part, the amount of oil and gas produced,
as well as total revenues for the project.
Parameters required to define this phase include:
a Peak production rate ;
• Production decline rate
• Time at peak production
• Annual operation and maintenance costs ....
Each parameter is discussed in its own section below.
G.1 PEAK PRODUCTION RATE
Well performance is a complex function of the thickness of the oil zone, geometry of the
zone, effective permeability of the zone to oil, effective drainage radius of the well, and other
factors. It is not surprising, then, that peak production rate and production decline rate are two
' •' • • .,...« -.''.'.,• .... ; .' ..;-,' '.-..' •''
parameters for which it is difficult to obtain "typical values." In this study, we assume that peak
production occurs in the first year of operation. Field data, where available, are used to estimate
• . • • • '.--"* . . . - . • . *
average initial production rates.
G-l
-------
6.1.1 Gulf of Mexico
Recent environmental impact statements for OCS sales in the Gulf of Mexico use "typical
production profiles" per well to back-calculate the number of wells required to develop the
estimated resources in the sale. The key factor is the cumulative amount of oil and gas produced
per well and this varies by region. The typical production profile has production climbing for 5
years, remaining at peak production for 3 to 4, years and then declining at rates between 5
percent and 10 percent per year. Gas wells are assumed to peak a few years later than oil wells
and then decline at rates between 5 percent and 15 percent per year (Crawford, 1988).
To use the information in the EIS in this analysis, we begin by examining at the
cumulative production per well. This ranges from 470,000 bbl to 1,579,000 bbl per well. Gas
production ranges from 5.3 BCF to 10 BCF (MMS, 1986 and 1987a). Oil wells typically have a
10- to 11-year lifetime, while gas wells have a typical lifetime of 13 to 15 years (Crawford, 1988).
The MMS "typical" well is a composite of an oil well and a gas well. There were 8,318 oil
wells and 4,757 gas wells in the Gulf of Mexico as of 1 January 1985 (see Table F-4). The
number of projected wells is multiplied by 63.6 percent (8,313/13,075) to obtain the number of
oil wells. The remaining wells are assumed, to be gas wells (see Table G-l, columns 3 and 4).
Total cumulative oil production is divided by the estimated number of wells to calculate the
cumulative production per oil well. The same procedure is followed to obtain the cumulative
production per gas well.
Exponential decline rates are calculated for an oil well using 2 years at peak production,
10-year lifetime, an annual decline rate of 15 percent, and setting the cumulative production to
the minimum and maximum cumulative production per oil well (740,384 and 2,481,937 bbl; see
Table G-l). Initial production rates are back-calculated to match the production profile. The
initial production rates for oil wells in the Gulf range from 330 bopd to 1,110 bopd. We use a
value of 500 bopd to allow for the production of lease condensate by gas wells. In 1985, the
Gulf of Mexico OCS region produced 321,509,934 bbl of oil and 537,402 MMcf for an average of
1.671 Mcf gas produced for every barrel of oil (MMS, 1987b; DOE, 1986, Table 3). For an
initial production rate of 500 bopd, there would be an associated 835 Mcf of gas production.
G-2
-------
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G-3
-------
The same methodology is used to fit an exponential decline function to gas production.
The production assumptions are a 20-year lifetime, a 15 percent annual decline rate, and 4 years
at peak production. Cumulative production per well ranges from 14,483,944 Mcf to 27,485,810
Mcf (see Table G-l). Back-calculated initial production rates range from 4,000 Mcf/day to 8,000
Mcf/day. We use a value of 4,000 Mcf/day to allow for the production of casinghead gas by oil
wells.
G.1.2 Pacific
The California Department of Conservation maintains records of oil and gas production
in Federal and State waters. W.-Guerard (1988) supplied peak production rates per well for
fields that started from 1980 and after (see Table G-2). The peak production rates range from
286 bopd in the Santa Clara field to 2,840 bopd in the Hondo field. We use a value of 900 bopd
in our model project. To estimate the amount of associated casinghead gas, we use the 1986 gas-
to-oil ratio for offshore California wells (see Table G-3). The average ratio is 531 ft3/bbl, so the
model project would have a peak production of 900 bopd with 478 Mcf/day. An initial
production rate of 5,000 Mcf/day is used for the gas-only project. This is lower than the first-
year production from the Pitas Point field, but we also assume a longer period at peak
production (see below).
G.1.3 Alaska
The Alaska Oil and Gas Conservation Commission supplied first-year production data for
wells in Cook Inlet and the Beaufort Sea (Johnson, 1988). Engineering studies form the basis
for the estimates for the Norton and Navarin Basin platforms.
G-4
-------
ca_prod.uk1
27-Mar-92
TABLE G-2
PEAK PRODUCTION RATES - CALIFORNIA
Field
Year of
Peak
Production
Peak Production
bopd or Mcf/day
OIL PRODUCTION
Beta
Hondo
Hueneme
Santa Clara
Average oil
1981
1981
1982
1980
535
2,840
1,074
286
1,184
GAS PRODUCTION
Pitas Pt.
1985
11,185
Source: Guerard, 1988.
G-5
-------
ca_og.wk1
27-Har-92
TABLE G-3
1986 GAS TO OIL RATIOS - CALIFORNIA
Region
State
Federal
Field or Area
District 1
District 2
District 3
Beta
Carpinteria
Dos Cuadras
Hondo
Hueneme
Santa Clara
1986
Oil and
Condensate
(bbl)
30,238,026
1,333,390
3,061,615
7,040,207
1,978,018
5,063,795
11,100,847
644,002
2,893.559
1986
Associated
Gas
(Hcf)
7,404,239
3,087,795
2,419,052
2,444,898
1,524,822
2,557,080
10,370,192
178,251
3,635,212
Gas to Oil
Ratio
(cf/bbl)
245
2316
790
347
771
505
934
277
1256
TOTAL
63,353,459 33,621,541
531
Source: California, 1987.
G-6
-------
Cook Inlet
Table G-4 calculates the average daily first-year production for 27 wells on platforms in
Cook Inlet. The production ranges from 19 bopd to 7,004 bopd. We use a value of 1,960 bopd
in this analysis. Associated casinghead gas ranges from 7 Mcf/day to 2,256 Mcf/day. A value of
900 Mcf/day is used for the oil with casinghead gas projects.
Arctic Alaska
The Endicott field in the Beaufort Sea began production in late 1987. Sixteen wells
began production in October 1987. Table G-5 summarizes the November and December
production from those wells, i.e., the first two full months of production. Production is likely to
drop from the impressive average of 5,783 bopd, even within the first year, but it is apparent that
Endicott will be an enormous producer like neighboring Prudhoe Bay.'
Table G-6 lists the various engineering estimates for oil production in the Arctic. These
range from 1,570 bopd in the Norton Basin to 4,000 bopd in the Beaufort Sea, Navarin Basin,
and St. George Basin. We use an estimate of 1,960 bopd for the oil production scenario in
Arctic Alaska. There is no infrastructure for gas transport, so no oil/gas or gas-only scenarios
are considered for the Arctic regions.
Table G-7 summarizes the model assumptions for peak production rates.
G.2 PRODUCTION DECLINE RATE
The pattern of decline in a well's productivity can vary greatly due to many factors (see
Section G.I). EPA models production decline as an exponential function, i.e., a constant
percentage of the remaining reserves produced in any given year. A general rule of thumb is
that peak production represents 10 to 15 percent of total reserves for the first 2 years and then
declines approximately 15 percent per year (Muskat, 1949; North, 1985).
G-7
-------
cook.wkl
AVERAGE'FIRST-YEAR PROOUCTIOM FOR OIL WELLS IN COOK INLET, ALASKA
Completion Date
Platform
Dolly Varden
Grayling
King Salmon
Year Hon
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
68
3
3
4
5
5
7
7
8
10
10
1
1
2
1
4
3
8
4
5
7
12
2
1
11
, 3
5
7
Day
5
27
19
5
21
26
3
30
14
7
1
1
19
1
2
1
23
21
28
3
5
15
4
27
23
22
2
Year Production
Oil (bbl) Gas (Hcf)
1,013,373
939,231
1,311,355
1,156,454
281,638
454.628
665,112
3,585
31,288
158,005
1,421,897
989,160
1,323,508
1,955,376
541,645
1,385,189
374,595
839,892
4,227
631,633
56,108
1,686,065
1,180,773
99,971
989,789
971,676
1,274,686
298,105
269,847
367,279
319,006
85,455
126,515
171,993
891
8,658
40,598
391,143
261 ,991
394,258
586,373
124,537
364,644
116,415
205,396
0
191,365
13,981
474,326
326,314
24,366
280,947
257,253
410,560
Average Daily
Production
Oil (bbl) Gas (Kef)
3,367
3,366
5,122
4.819
1,257
2,877
3,675
29
401
1,859
3,896
2,710
4,188
5,357
1,984
4,542
2,882
3,307
19
3,490
2,158
5,269
3,262
2,940
3,497
4,357
7,004
990
967
1,435
1,329
381
801
950
7
111
478
1,072
718
1,248
1,607
456
1,196
896
809
0
1,057
538
1,482
901
717
993
1,154
2,256
Source: Johnson, 1988.
G-8
-------
endicott.wkt
27-Mar-92
TABLE G-5
INITIAL PRODUCTION FROM ENDICOTT FIELD, BEAUFORT SEA, ALASKA
Monthly Production
Nov
Oil (bbl)Gas (Mcf)
238,603
269,964
210,326
125,502
164,240
243,696
230,273
245,612
162,298
117,291
138,905
232,460
243,017
.235,009
168,092
48,265
AVERAGE
193.044
223.977
174,992
98,358
118,966
202,388
230,547
202,071
135,626
98,165
105,438
182,227
201,925
318,449
244,519
38,415
.......
Dec
Oil (bbl)
185,341
168,940
12,612 .
48,223
198,145
181,826
142,490
223,189
215,708
206,092
206,282
209,881
217,055
208,137
115.670
30,890
Gas (Mcf)
135,456
140,306
9,771
30,082
140,770
143,815
153,769
176,437
178.112
153,383
144,965
156,141
173,498
350,650
233,215
24.438
Total
Oil (bbl)
423,944
438,904
-. 222,938
173,725
362,385
425,522
372,763
468,801
378,006
323,383
345,187
442,341
460,072
443,146
283,762
79.155
352,752
Gas (Mcf)
328,500
364,283
184,763
128,440
259,736
346,203
,384,316
378,508
313,738
251,548
250,403
338,368
375,423
669,099
477,734
62,853
319,620
Average Average
bopd Mcf per day
6,950
7.195
3,655
2,848
5,941
6,976
6,111
7,685
6,197
5,301
5,659
, 7,251
7.542
7,265
4,652
1,298
5,783
5,385
5,972
3,029
2,106
4,258
5,675
6,300
6,205
5,143
4,124
4,105
5,547
6,154
10,969
7,832
1,030
5,240
Source: Johnson, 1988.
G-9
-------
TABLE G-6
ENGINEERING ESTIMATE OF PEAK PRODUCTION RATES - ALASKA
PEAK
PRODUCTION RATE
DATA SOURCE REGION
EIS St. George Basin
N. Aleutian Basin
Norton Basin
Scenario Studies Norton Basin
Beaufort Sea
Norton Basin
Navarin Basin
OIL GAS
BOPD MMCF/DAY SOURCE
4,000 26.3
3,500 26.6
1,570 10.3
3,000-
4,000
4,000
2,000
4,000
MMS 1985a
MMS 198 5b
MMS 1985C
MMS 1985d
OTA 1985
OTA 1985
OTA 1985
Source: AEI noted.
G-10
-------
TABLE G-7
PEAK OFFSHORE PER-WELL PRODUCTION RATES
REGION
Gulf
Pacific
PROJECT
1
4
6
12
24
40
58
16
40
70
Alaska3
Cook Inlet
Beaufort Sea - Gravel
Beaufort Sea - Platform
Norton
Navarin
12
24
48
48
34
48
OIL ONLY
BOPD
500
500
500
500
500
500
500
900
900
900
1,960
1,960
1,960
1,960
1,960
OIL AND GAS
BOPD MCF/DAY
500
500
500
500
500
500
500
900
900
900
1,960
478
478
478
900
GAS-ONLY
MCF/DAY
835
835
835
835
835
835
835
4,000
4,000
4,000
4,000
4,000
4,000
4,000
5,000
15,000
Source: EPA estimates.
is no infrastructure to transport produced gas from the Arctic
G-ll
-------
The decline rate for the Pacific is based on the need to balance to conflicting sets of
information. The decline rate used in the MMS estimates of future production use a 40%
decline rate (MMS, 1985e). Since this information is the basis for the NSPS projections
presented in Section 4, it is necessary that the decline rates used in the models be very similar in
order to maintain comparability between the two sets of projections. EPA reduced the decline
rate to 33% in response to the field data presented in DOE, 1989. Decline rate assumptions are
summarized in Table G-8.
G.3 YEARS AT PEAK PRODUCTION
The length of time each well remains at peak production depends upon the rate of
reservoir pressure decline, as well as other factors. All-oil and oil/gas projects are assumed to
remain at peak production for 2 years.
Gas projects in the Gulf and Pacific are assumed to remain at peak production for 4
years (Crawford, 1988). For Alaska, gas projects are assumed to remain at peak production for
16 years. Figure G-l shows the production history of the North Cook Inlet gas field from 1969
through 1984 to support this assumption.
G.4 OPERATION AND MAINTENANCE COSTS (O&M)
The annual 1986 costs of operating and maintaining an offshore platform are taken from
DOE (1987). This survey includes O&M costs for a 12-wellslot platform in 100 and 300 feet of
water as well as an 18-wellslot platform in 100, 300, and 600 feet of water (Table G-9).
A breakdown of the cost for a 12-wellslot platform in 100 feet of water is given in
Table G-10. The platform is assumed staffed 24 hours a day with one crew. A crew is 12 people
•working 12 hours on and 12 hours off, so six people are working at any given time. In the next
cost subcategory, equipment and administration, the term "surface equipment" refers to
production equipment, flow control valves, and/or dehydrators/line heaters (for gas operation)
located on the platform surface. The third cost category is workover costs. For a 12-wellslot
G-12
-------
TABLE G-S
PRODUCTION DECLINE RATES
PRODUCTION DECLINE RATES (%)
REGION
PROJECT
OIL-ONLY
OIL/GAS
GAS-ONLY
Gulf
Pacific
Alaska
1 15
4 15
6 15
12 15
24 15
40 15
58 15
16 33
40 33
70 33
Cook Inlet 10
Beaufort Sea -Gravel 10
Beaufort Sea - Platform 10
Norton Bagin 10
Navarin Basin 10
15
15
15
15
15
15
15
22
15
— = Not applicable.
Source: EPA estimates.
G-13
-------
DRILY GflS. MCF/DflT
X1D3
100
so
0 1000
I
2
a,
*
ffi
t>
HH
6
Jf
I
1
o
iba so a looo
NO. OF PROD. HELLS
too 10
DfULT HflTER. BBLS/DflT
G-14
-------
gulf_o&m.wk1
27-Har-92?
TABLE G-9
1986 PPERATION AND MAINTENANCE COSTS FOR GULF OF MEXICO PLATFORMS
Wellslots
Water
Depth (ft)
Cost
(1986 S)
12
12
18
18
18
100
300
100
300
600
12,366,500
$2,482,300
$2,833,400
$2,963,100
$3,268,100
Source: DOE, 1987.
G-15
-------
OiH_gulf.wk1
ANNUALGOPERAnHG COSTS - 12-SLOT PLATFORM IN GULF OF MEXICO
100 FT WATER DEPTH (1986$)
Component
Labor Subcategory
Labor
Supervision
Payroll Overhead
Food Expense
Labor Transportation
C annum cat ions
Component Subcategory
Cost ($) Cost ($>
$1,265,200
$528,900
$79,300
$211,600
$55,200
$374,700
$15,500
Model Projects
Gulf 1 Gulf 4 Gulf 6
$770 $140,578 $210,867
Equipment & Administrative Subcategory
Surface equipment $84,600
Operating Supplies *lf'|22
Administrative $*IHS2
Insurance $252,200
$605,900
Workover Subcategory
Uorkover
SUBTOTAL COSTS
Costs for operation of remote
production platform
TOTAL COSTS
$495,400 $495,400
$2,366,500 $2,366,500
$50,492 $201,967 $302,950
$148,620 $346,780 $396,320
$199,882 $689,324 $910,137
$172,331
$2.366,500 $2,366.500 $372,213 $689,324 $910,137
Source: DOE, 1987.
G-16
-------
platform, it is assumed that the workover rig takes one day to travel to the platform, two days to
set up, nine days to workover three wells, two days to tear down the equipment, and one day to
move off. In other words, six of the fifteen days are for transit, set-up, and break-down; costs
that would be borne even if working over only one well.
These assumptions make it inappropriate to use data from the 12-wellslot and 18-wellslot
platforms, perform a regression analysis, and extrapolate back to the smaller Gulf projects. The
DOE/EIA data for each of the cost categories can be scaled to estimate the annual operating
costs for the smaller Gulf projects.
Table G-ll summarizes the assumptions for the labor subcategory for the Gulf 1, Gulf 4,
and Gulf 6 projects. The Gulf 1 is essentially untended; a crew of two inspect the structure 4
times a year. One day is assumed for each inspection. The Gulf 4 and Gulf 6 platforms are
assumed to have a crew of 4 and 6 people, respectively, that commute to the rig on a daily basis.
The work day is assumed to be eight hours. The labor costs for these small projects are scaled
from the Gulf 12 costs as a percentage of labor hours. For example, the Gulf 4 requires 11,680
person-hours a year or 11.11 percent of the hours required for the Gulf 12 platform. The labor
costs for the Gulf 4 are (11,680/105,120) x $1,265,200 or $140,578.
The equipment and administrative costs are scaled according to the number of wells on
the project. For example, the costs for this subcategory for the Gulf 6 is $302,950 or one-half
the costs for the Gulf 12 project.
Workover costs are also scaled. Gulf 1 projects are assumed to be worked over every two
years. Each workover takes 9 days (6 for preparation and disassembly, and three for the
workover itself). The proportion of the workover costs borne each year is (9/2)/15 or 30 percent.
The Gulf 4 and Gulf 6 projects are assumed to have an average of one and a half and two wells
worked over per year, respectively. The cost proportions are (6 + 4.5)/15 or 70 percent and (6
+ 6)/15 or 80 percent, respectively.
One last factor needs consideration. The Gulf la is assumed to have no production
equipment and shares a production platform with three other single-well structures. The O&M
G-17
-------
0&H_gulf.wk1
TABLE G-11
LABOR ASSUMPTIONS FOR SHALL GULF PROJECTS
Labor Component
DOE/EIA
Study
Model Project
Gulf 1 Gulf 4 Gulf 6
Hours per Day
Days per Year
People per Crew
Person-hours per Year
Fraction of DOE/EIA study
24
365
12
105,120
100*
8 8
4 365
2 4
64 11,680
0.06X 11.11%
8
365
6
17,520
16.67X
Source: DOE, 1987; Funk, 1989.
G-18
-------
costs for the Gulf la therefore includes one-fourth of the annual operating costs for a Gulf 4
platform.
The DOE/EIA data can be used to estimate annual operating costs for the larger projects
in the Gulf. To project O&M cost for the model projects, a regression analysis was fit to the
data using the following equation.
Cost = a + b (wellslots) + c (depth)
The values for a, b, and c are $1,286,123, $80,859, and $840, respectively. Table G-12 shows the
estimated O&M costs for platforms in the Gulf of Mexico.
For the Pacific and Cook Inlet projects, we use the basic equation presented above and
then adjust for regional differences (see Table G-13). The O&M costs' for California onshore oil
and gas operations are approximately 144 percent of onshore operations for Texas and Louisiana
(see Table G-14). The regional multiplier for the Pacific is therefore 1.44. For Cook Inlet
scenarios, a multiplier of 1.6 is used (EPA, 1985).
The information in OTA (1985) forms the basis for estimating the operating costs for
Arctic Alaska scenarios (see Table G-15). The costs per scenario are divided among the number
of platforms or islands and then deflated to 1986 values.
G.S REFERENCES
Alaska. 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation Commission, n.d.
California. 1987. 72nd Annual Report of the State Oil and Gas Supervision: iQSfi
Department of Conservation. Division of Oil and Gas, Publication No. PR06,1987.
Crawford. 1988. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc. and Gerald Crawford, MMS, GOM Regional Office, New Orleans, LA, 4
March and 7 March.
DOE. 1986. Natural Gas Annual 1985. U.S. Department of Energy. Energy Information
Administration. DOE/EIA-0131(85), November.
G-19
-------
gulf_o&m.wk1
OPERATING COSTS FOR GULF OF MEXICO PLATFORMS
Project
Nunber of
WeUslots
Water
Depth (ft)
Cost
($1986)
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
1
1
4
6
12
24
40
58
33
33
33
33
66
100
200
590
$372,213
$199,882
• $689,324
$910,137
$2,311,861
$3,310,725
$4,688,455
$6,471,456
Source: EPA estimates.
G-20
-------
gulf_o&m.wk1
TABLE G-13
OPERATING COSTS FOR PACIFIC AND COOK INLET PLATFORMS
Project
Pacific 16
Pacific 40
Pacific 70
Cook Inlet 24
Cook Inlet 12
Number of
Uellslots
16
40
70
24
12
Water
Depth (ft)
300
300
1000
50
50
Cost
($1986)
$2,831,820
$4,772,439
$7,786,100
$3,268,733
$2,298,424
Regional
Cost
Factor
1.44
1.44
1.44
1.60
1.60
Estimated
Cost
($1986)
$4,077,821
$6,872,312
$11,211,984
$5,229.973
$3,677,478
Source: EPA estimates.
G-21
-------
ca cost.vikl
27-Har-92
RATIO OF11986 OPERATION & MAINTENANCE COSTS - CALIFORNIA AND GULF COAST
Well Operation & Maintenance Cost - 10 Primary Oil Wells
(ft) California Louisiana West1 Texas South Texas Average Gulf
California/
Gulf Coast
Ratio
2,000
4,000
8,000
10,000
.
$119,700
$162,400
$280,200
$403,700
$117,600
$171,700
$203,000
$252,800
$88,300
$102,200
$141,700
$188,900
$98,500
$146,500
$175,100
$232,400
$101,467
$140,133
$173,267
$224,700
1.18
1.16
• 1.62
1.80
1.44
Source: DOE, 1987.
G-22
-------
ak_o&m.wk1
TABLE G-15
OPERATION AND MAINTENANCE COSTS FOR ALASKA PROJECTS
Project
Beaufort platform
Navarin Basin
Norton Basin
Beaufort Gravel
Operation and Number of
Maintenance Islands/
Cost ($HM 1984) Platforms
$168.0
$132.0
$73.0
$120.0
7
7
4
7
Cost per
Platform
($MM 1984)
$24.0
$18.9
$18.0
$17.1
Cost per
Platform
<$MM 1986)
$25.3
$19.9
$19.0
$18.1
Note: 1984 prices inflated by 5.56% based on change in consumer price index.
Sources: OTA, 1985; Economic Report. 1988.
G-23
-------
DOE. 1987. Costs and Indices for Domestic Oil and Gas Field Equipment and Production
Operations 1986. U.S. Department of Energy. Energy Information Administration.
DOE/EIA-0185(86), September.
DOE 1989 Department of Energy Comments on the Technical, Economic, and Environmental
Data Made Available in 53 FR 41356 on October 21,1988 for the Offshore Oil and Gas
Subcategory Effluent Guidelines, January 19.
Economic Report. 1988. Economic Report of the President. Council of Economic Advisors,
Washington, DC, February.
EPA. 1985. Economic Impact Analysis of Proposed Effluent Limitations and Standards for the
Offshore Oil and Gas Industry, prepared for the U.S. Environmental Protection Agency
by Eastern Research Group, Inc., EPA 440/2- 85-003, July.
Guerard. 1988. Personal communication between Maureen F. Kaplan, Eastern Research Group,
Inc., and William Guerard, California Department of Conservation, 2 March.
Johnson. 1988. Individual well production printouts sent to Maureen F. Kaplan, Eastern
Research Group, Inc., by Elaine Johnson, Alaska Oil and Gas Conservation Committee,
25 February.
MMS. 1985a. U.S. Department of the Interior, Minerals Management Service, St. George Basin
Sale 89: Final Environmental Impact Statement. MMS 85- 0029, April.
MMS. 1985b. North Aleutian Basin Sale 92: Final Environmental Impact Statement. U.S.
Department of the Interior, Minerals Management Service, MMS 85- 0052, September.
MMS. 1985c. Norton Basin Sale 100: Final Environmental Impact Statement. U.S. Department
of the Interior, Minerals Management Service, MMS 85-0085, December.
MMS. 1985d. Scenarios for Petroleum Development of the Nnrtnn Basin Planning Area -
Northeastern Bering Sea. U.S. Department of the Interior, Minerals Management
Service, OCS Report, MMS 85-0013.
MMS. 1985e. Certain Input Values Used in the 30-Year Projection of Future Oil and Gas
Production from United States Outer Continental Shelf Areas. Attachment to 30-Year
Projections of Oil and Gas Production from United States Outer Continental Shelf
• Areas. Memorandum from Chief, Offshore Resource Evaluation to Associate Director
for Offshore Leasing. U.S. Department of the Interior. U.S. Minerals Management
Service.
MMS. 1986. Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales 110
' and 112: Gulf of Mexico OCS Region. U.S. Department of the Interior, Minerals
Management Service, OCS EIS, MMS 86-0087, November.
G-24
-------
MMS. 1987a. Final Environmental Impact Statement: Proposed Oil and Gas Lease Sales
113/115/116: Gulf of Mexico PCS Region. U.S. Department of the Interior, Minerals
Management Service, OCS EIS, MMS 87-0077, October.
MMS. 19875. Federal Offshore Statistics: 1985. U.S. Department of thP TnfPr.w
Management Service, OCS Report, MMS 87-0008.
Muskat, M. 1949. Physical Principles of Oil Production. McGraw-Hill, New York, NY.
North, F.K. 1985. Petroleum Geology. Allen & Unwin, Boston, MA.
OTA. 1985. Oil and Gas Technologies for the Arctic and Deepwater. Office
Assessment, Washington, DC, May.
USGS. 1981. United States Geological Survey. Circular 860.
G-25
-------
-------
APPENDIX H
PRODUCED WATER ASSUMPTIONS
Peak water production is used in determining the equipment required on the platform to
comply with proposed regulatory options. Average annual water production is used to estimate
the annual operation and maintenance cost (O&M) for each platform. The capital (equipment)
and O&M costs are factored into the economic model for each platform to calculate the
annualized cost for each regulatory option. The total annual average volume of produced water
generated during the 15-year time period is used to estimate the amount of pollutants removed
by each regulatory option.
The capital and O&M costs are calculated by EPA, Engineering and Analysis Division on
the basis of the produced water volumes presented in this appendix. These costs will be
documented in the Development Document supporting the Offshore Oil and Gas regulation.
H.1 MODELING ASSUMPTIONS
Modeling assumptions differ depending upon whether a well produces oil or only gas.
These assumptions are outlined in the sections below.
H.1.1 Projects with Oil Production
For projects that produce oil or oil with gas, water production is calculated as a function
of total liquid production. In other words, the well is assumed to produce a constant volume of
fluid during its lifetime, but the proportion of fluid that is water will increase as the well ages.
To evaluate water production as a function of total liquid production, we need to estimate
several parameters:
• Relationship of oil decline and water increase
H-l
-------
• Functional form of oil production decline
• Decline rate of oil production
• Initial watercut (i.e., percentage of water in the initial production fluid)
Oil production is assumed to decline at an exponential rate. The rate of decline varies by
region (see Appendix G for more details). As oil production declines, water production
increases to mamtain a constant volume. (Figure H-l illustrates the oil and water production
from a well with an initial production rate of 100 bbl/day for two years and a 15 percent
exponential decline every year thereafter.)
Initial watercut data are available from Alaska for platforms in coastal waters and gravel
islands in offshore waters (Table H-l). Initial watercut values range from 0.1 percent to 4.3
percent with a median value of 0.9 percent. We round this value upwards to 1 percent for
Alaska and all other regions. .
H.1.2 Projects with Gas-Only Production
There is generally little water produced with gas-only operations. Under these
circumstances we estimate water production with a watengas ratio. Water production for gas
wells is assumed to be a function of gas production times a watengas ratio. A constant watengas
ratio was used in the economic impact analysis of the disposal of onshore production wastes
under Section 8002(m) of RCRA (EPA, 1987).
An Appalachian basin survey is the only survey that investigates water production from
gas wells (Flanriery and Lannan, 1987). The survey appears well designed and covers
approximately 10 percent of existing Appalachian Basin wells, including 12,274 gas wells.
Approximately 39 percent of the gas wells produce no water at all, even with gas production ,
rates exceeding 60 Mcf/day. An additional 51 percent produce less than 10 barrels of water per
month. Less than 1 percent produce in excess of 100 barrels of water a month. Averaging the
survey data results in an estimated watengas ratio of 17.2 bbl per MMcf.
H-2
-------
BARRELS
120
100
Figure H-l
Water : Oil Relationship
Exponential Oil Decline
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30
H-3
-------
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H-4
-------
For comparison, the waterrgas ratio for offshore California gas wells can be calculated
from the annual report of the oil and gas supervisor. Table H-2 shows the data for 1985,1986,
and 1987 (California, 1986; California, 1987; and California, 1988). The ratio for the wells in
State waters increases fourfold from 1985 to 1986. The 1986 waterrgas ratio for gas wells in
State waters is 16.2 bbl per MMcf, which is similar to the ratio from the Appalachian basin. The
waterrgas ratio for gas wells in State waters climbs another fourfold from 1986 to 1987 when it is
67 bbl per MMcf. Note also that by 1987, two of the six gas wells had stopped producing. For
gas wells in Federal waters for 1985 through 1987 and for gas wells in State waters for 1985, the
waterrgas ratios range from 4.1 to 6.4 bbl per MMcf.
The North Cook Inlet field has the sole gas-only platform in Alaska. Although the field
is in coastal waters, we use the data as indicative of the potential water production from gas-only
operations in offshore southern Alaska. For the North Cook Inlet field, gas production is
approximately 130 MMcf/day while water production is generally about 10 bbl/day with
fluctuations as high as 100 bbl/day (see Figure H-2). This results in a watengas ratio of 0.08 bbl
per MMcf with fluctuations as high as 0.77 bbl per MMcf. In 1984, the North Cook Inlet field
produced 46,981 MMcf of gas and 5,058 bbl of water for a waterrgas ratio of 0.11 bbl per MMcf
(Alaska, 1984).
The monthly summaries of production for the Federal Gulf of Mexico list oil, condensate,
gas, casinghead gas, and water; that is, no distinction is made between produced water from gas
operations and produced water from oil and oil-with-gas operations. Discussions with MMS
personnel revealed that, in general, little water is produced with gas-only operations, although
there are exceptions (Lowenhaupt, 1989).
From the California data in Table H-2 and the Alaska data in Figure H-2, we see that
water production from gas operations can be extremely variable. The highest waterrgas ratio
seen in the offshore and onshore data is about 67 bbl of water per MMcf produced. This high
value, however, appears in only a few wells that appear to be close to the end of their economic
lifetime. The average value seen in the onshore Appalachian data — 17 bbl/MMcf— exceeds
the waterrgas ratios seen for the Alaska data, offshore Federal California gas wells, and offshore
H-5
-------
1000
DRILY CHS. MCF/OflT
100 10
X1Q3
i
§
CO
1000
ico »o
GflILT HRTER. BBLS/OflT
H-6
-------
h20_gas.wk1
TABLE H-2
OFFSHORE WATER:GAS RATIOS - CALIFORNIA
Year
1985
1986
1987
Number
Region of Wells
State
Federal
Combined
State
Federal
Combined
State
Federal
Combined
6
15
21
6
15
21
4
18
22
Gross Gas
Production
(Hcf)
6,126,304
31,227,299
37,353,603
5,341,798
27,279,321
32,621,119
2,067,900
23,424,998
25,492,898
Water Water:0i I
Production Ratio
-------
State California gas wells for two of the three years of data. The 17 bbl/MMcf is the watengas
ratio used in this analysis.
H.2 PEAK WATER PRODUCTION
H.2.1 Projects with Oil Production
Peak water production is the amount of water produced in the last year of the economic
lifetime of the well. Table H-3 shows the sample calculations for the Gulf 24 model with 18
productive wells. Peak oil production occurs in the second year of operation at a rate of 9,000
bbl/day. With an initial watercut of 1 percent, total fluid production is 9,090 bbl/day. Water
production is the difference between oil production and total fluid production. For example, in
year 19, water production is 8,489 bbl/day (i.e., 9,090 bbl/day total fluid production minus 601
bbl/day oil production). Cumulative water production in Year 19 is 104,088 bbl/day.
Peak water production, then, depends on the economic lifetime of the project. The same
project will have different peak water production rates for BAT and NSPS evaluations because
different oil prices are assumed in the BAT and NSPS analyses. Project lifetimes and peak water
production rates are summarized in Table H-4.
H.2.2 Projects with Gas-Only Production
Peak water production for gas-only projects occurs at the time of peak gas production.
There is no difference in peak water production for gas-only projects depending upon whether
the scenario studied is BAT or NSPS. Peak water production rates for all projects are given in
Table H-4.
H-8
-------
h20 mex.ukl
27-Mar-92
TABLE H-3
WATER PRODUCTION ESTIMATES - GULF OF MEXICO
GULF 24 MODEL
Oil Production (bbl/d)
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Year 1
6000
6000
5100
4335
3685
3132
2662
2263
1923
1635
1390
1181
1004
853
725
617
524
446
379
322
274
233
198
168
143
121
103
88
75
63
Year 2 Year 3 Year 4 Year 5
3000
3000
2550
2168
1842
1566
1331
1131
962
817
695
591
502
427
363
308
262
223
189
161
137
116
99
84
71
61
52
44
37
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
6000
9000
8100
6885
5852
4974
4228
3594
3055
2597
2207
1876
1595
1355
1152
979
832
708
601
511
435
369
314
267
227
193
164
139
118
101
Water
•eduction
(bbl/d)
60
90
990
2205
3238
4116
4862
5496
6035
6493
6883
7214
7495
7735
7938
8111
8258
8382
8489
8579
8655
8721
8776
8823
8863
8897
8926
8951
8972
8989
Average
Cumulative • Annual
Water Water
Production Production
(bbl/d) (kbbl/yr)
1.
3,
6,
10,
15,
21.
27,
33,
40,
47,
55,
62,
70.
78,
87,
95,
104,
112,
121,
130,
138,
147,
156,
165,
174,
183,
192,
201,
60
150
140
345
583
698
560
056
091
584
467
681
177
911
849
960
217
600
088
667
322
043
819
642
505
403
329
279
251
240
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
2
22
27
139
305
481
651
811
961
,099
.226
,343
,450
,549
,640
.724
,801
,873
,939
,000
,056
.109
,158
,203
,245
,285
.322
,357
,389
,420
,448
Notes:
500 bbl/day initial production per well
15% decline rate
1% initial watercut
18 producing wells.
H-9
-------
peakji20.wk1
21-Dec-92
TABLE H-4
PEAK WATER PRODUCTION RATES - EXISTING AND PROJECTED STRUCTURES
Project
Type Region Model
Economic Lifetime
of Project (Years)
Existing Projected
Peak Water Production
Rate per Project
(bbl/day)
Existing Projected
OIL
ONLY
Gulf
Pacific
Cook Inlet*
Beaufort
Platform
Beaufort Island
Navarin
Norton
OIL
AND
GAS
Platform
Platform
Gulf
,
Pacific
1a
1b
4
6
12
24
40
58
16
40
70
24
48
48
48
34
1a
1b
4
6
12
24
40
58
16
40
70
13
17
18
18
16
18
20
22
8
9
11
**
**
**
**
**
14
18
19
19
17
19
21
23
8
9
11
15
19
20
20
18
20
22
24
9
10
12
30
28
30
30
27
16
20
21
21
19
21
23
25
9
10
12
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
**
**
**
**
**
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
445
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
37,449
73,405
74,503
74,503
51,169
454
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
Cook Inlet*
24
30
37,449
GAS
ONLY
Gulf 1a
1b
4
6
12
24
Pacific 16
Cook Inlet* 12
14
18
19
20
17
19
11
16
20
21
21
19
21
13
29
68
68
272
408
680
1,224
1,190
68
68
272
408
680
1,224
1,190
2,550
Notes; * Existing platforms in Cook Inlet are in the coastal subcategory.
** Produced water from gravel islands in the Beaufort Sea
(i.e., the Endicott field) is reinjected per State requirement.
There are no platforms currently producing in the Beaufort,
Navarin, or Norton areas. Economic impacts are evaluated for these
projects and projects in the non-coastal region near Cook Inlet
that may occur at some point in the future.
Source: EPA estimates.
H-10
-------
H.3 AVERAGE WATER PRODUCTION
H.3.1 Projects with Oil Production
Average water production for oil-only and oil-with-gas projects is the cumulative water
production through the last economic year of production divided by the economic lifetime of the
well. For example, for a Gulf 24 model with an economic lifetime of 20 years (see Table H-3),
average annual water production is calculated as:
Cumulative water production (bbl/dav) * 365 davs/vr / 1000
Economic lifetime of model project
or,
112.667
* 365 /j
20 /
1000 = 2,056 kbbl/yr
Average
annual
water
production
(kbbl/yr)
Average water production by structure is listed in Table H-5.
This methodology is used for oil-only and oil-with-gas projects. Projects with associated
gas production are not assumed to produce more water than projects that produce only_oil. If
gas production is coming from separate gas wells on a platform, this approach may overestimate
water production since gas wells generally produce less water than oil wells. This may occur in
existing structures but there is no information by which to adjust existing structure counts for this
phenomenon. Projected structures are assumed to have associated gas production for oil-with-
gas model projects and are unaffected by this assumption.
H.3.2 Projects with Gas-Only Production
For average water flow rates, regional average watengas ratios are used where available.
For California the ratio is 7 bbl water per MMcf (see Table H-2 for wells in Federal waters).
The 7:1 ratio is also used for Gulf of Mexico projects. For Alaska, a 1:1 ratio is used, based on
H-ll
-------
avg_h20.wk1
21-Dec-92
TABLE H-5
AVERAGE ANNUAL WATER PRODUCTION RATES - EXISTING AND PROJECTED STRUCTURES
Project
Type Region Model
Economic Lifetime
of Project (Years)
Existing Projected
Average Annual
Water Production
Rate per Project
(kbbl/yr)
Existing Projected
OIL Gulf
ONLY
Pacific
Cook Inlet*
Beaufort Platform
Beaufort Island
Navarin Platform
Norton Platform
la
1b
• 4
6
12
24
40
58
16
40
70
24
48
48
48
34
13
17
18
18
16
18
20
22
8
9
11
**
**
**
**
**
15
19
20
20
18
20
22
24
9
10
12
30
28
30
30
27
90
107
443
665
994
1,939
3,505
5,486
2,358
5,213
9,324
**
**
**
**
**
99
114
469
703
1,071
2,056
3,696
5,767
2,579
5,720
10,128
9,247
17,100
17,766
17,766
12,054
OIL
AND
GAS
Gulf
Pacific
1a
1b
4
6
12
24
40
58
16
40
70
14
18
19
19
17
19
21
23
8
9
11
Cook Inlet* 24
16
20
21
21
19
21
23
25
9
10
12
30
95
111
456
685
1,034
2,000
3,604
5,631
2,358
5,213
9,324
104
117
480
720
1,105
2,109
3,782
5,893
2,579
5,720
10,128
9,247
GAS
ONLY
Gulf
Pacific
Cook Inlet*
la
1b
4
6
12
24
16
12
14
18
19
20
17
19
11
**
16
20
21
21
19
21
13
29
6
5
20
28
54
89
112
**
6
5
18
27
49
81
98
40
Notes: * Existing platforms in Cook Inlet are in the coastal subcategory.
** Produced water from gravel islands in the Beaufort Sea
(i.e., the Endicott field) is reinjected per State requirement.
There are no platforms currently producing in the Beaufort, Navarin,
or Norton areas. Economic impacts are evaluated for these projects
and projects in the non-coastal region near Cook Inlet that may occur
at some point in the future.
Source: EPA estimates.
H-12
-------
the data from the North Cook Inlet field (see Section H.1.2; this value is rounded upwards to a
1:1 ratio). For projects with oil production, average annual water production is calculated as the
cumulative water production divided by the number of years of production. Because a watengas
ratio is used to calculate water production from gas projects, and gas production declines over
the life of the well, average water production for longer-lived gas projects is lower than for
shorter-lived gas projects. Average water production by structure is listed in Table H-5.
H.4 TOTAL ANNUAL WATER PRODUCTION
Total amount of water produced is estimated in two steps. First, in order to obtain water
production by model project, the number of each model project is multiplied by the average
annual water production associated with each project. These project totals are then summed
over all projects to obtain the grand total of water produced during the time period. Projects
will be installed and come into production throughout the time period, but the amount of water
produced by each project will be the average annual water flow.
H.4.1 Existing Structures (BAT)
Gulf of Mexico
The number of structures in production in the Gulf of Mexico is presented in Table H-6.
The count include both structures in State and Federal waters. The data sources and
methodology used to derive the count of structures likely to incur BAT costs is described in
Section Four.
The estimated annual water production for projects in the Gulf of Mexico is 903 million
bbl/yr (see Table H-7). For comparison, the MMS estimate of produced water generated in the
Federal Gulf of Mexico in 1987 is approximately 500 million barrels (Miller, 1989; reproduced as
Attachment H-l). MMS (1989) indicates that in 1986, approximately 70.2 million barrels of
water were discharged in offshore Louisiana State waters while another 5.1 million barrels were
H-13
-------
TABLE H-6
BAT STRUCTURES IN OFFSHORE WATERS
BASED OH 4 NAUTICAL MILE CUT-OFF
Number of Structures
Project Type
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf Totals
Pacific 16
Pacific 40
Pacific 70
Pacific Totals
Totals
Oil Only
Gas Only
Oil and
Gas
Within Beyond Within Beyond Within Beyond
102
11
26
1
0
0
0
140
0
0
0
0
140
43
10
18
18
22
5
1
117
0
0
0
0
117
151
30
13
3
0
0
0
197
0
0
0
0
197
376
240
163
157
104
39
0
1079
1
0
0
1
1080
27
16
16
2
4
8
0
73
7
0
7
14
87
195
82
104
125
215
188
2
911
1
5
11
17
928
Total
Within Beyond Total
280
57
55
6
4
8
0
410
7
0
7
14
424
614
332
285
300
341
232
3
2107
2
5
11
18
2125
894
389
340
306
345
240
3
2517
9
5
18
32
2549
There are currently no facilites in the Atlantic region.
There are no facilities in the Alaska region that do not already re-inject their produced water.
Notes:
Sources: EPA estimates; HHS, 1988; CCC, 1988; SAS runs dated July, 1990.
H-14
-------
TABLE H-7
ESTIMATED AVERAGE ANNUAL PRODUCED WATER GENERATED BY PROJECTS
IN THE GULF OF MEXICO
Structure
Type
Oil
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Oil With Gas
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Gas
Gulf 1a
Gulf 1b
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Total
Average Annual
Water Production
Per Project
Number (kbbl/yr)
145
21
44
19
22
5
1
0
222
98
120
127
219
196
2
0
527
270
176
160
104
39
2.517
90
107
443
665
994
1,939
3,505
5,486
95
111
456
685
1,034
2,000
3,604
5,631
6
5
20
28
54
89
Water
Production
Per Project
Ckbbl/yr)
13,050
2,247
19,492
12,635
21,868
9,695
3,505
0
21,090
10,878
54,720
86,995
226,446
392,000
7,208
0
3,162
1,350
3,520
4,480
5,616
3,471
903,428
Source: EPA estimates.
H-15
-------
IN REPLY
REFER TO:
ATTACHMENT H-I
WATER PRODUCTION IN THE FEDERAL GULF OF MEXICO - 1987 DATA
United States Department of the Interior
MINERALS MANAGEMENT SERVICE
ROYALTY MANAGEMENT PROGRAM
PRODUCTION ACCOUNTING DIVISION
P.O. BOX 17110
DENVER, COLORADO 80217
PAD/RGB
Mail Stop 657
.'JAN 2 7 1939
Ms. Maureen Kaplan
Environmental Protection Agency
6 Whittemore Street
Arlington, Massachusetts 02714
Dear Ms. Kaplan:
Subject: Volumes of Water Disposed of in Gulf of Mexico in 1987
The information below is provided in accordance with a telephone conversation
between you and John Marshall of this office on January 23, 1989.
The following volume/categories of water were disposed of in the Gulf of
Mexico in 1987:
a. Injected on a lease'
b. Transferred off lease
c. Surface pit
d. Overboard
e. Meter differential
f. Well test
g. Gathering system
TOTAL
19,357,689
74,557,893
25,368,097
378,978,944
79,870
146,548
-12,325
498,476,716*
* or 498.5 million barrels of water disposed of in Gulf in 1987
If.you have any questions, please do not hesitate to call Mr. Marshall at
303-231-3635 or our toll-free number 800-525-7922.
Sincerely,
%'chael A.^ilUr, Chief
Reporter Contact Branch
H-16
-------
discharged in offshore Texas State waters. We assume, for this report, that the volumes of water
discharged are equal to the volumes of water generated. We also assume that 1987 water
production did not differ drastically from 1986 water production. This results in approximately
573 million barrels/yr of produced water generated in the Gulf of Mexico. The BAT O&M costs,
then, are capable of handling an additional 58 percent over 1987 water production rates. The
capital (equipment) costs are determined by peak, not average, flow rates so the infrastructure is
capable of handling even larger volumes of produced water.
California
The categorization of structures off the California coast is done on the basis of the
number of available wellslots. Table H-6 lists the number of structures by category, while
Table H-8 presents the estimated annual water production.
The 1987 water volumes for the Federal OCS and the Huntington, South Elwood,
Summerland, and Carpinteria fields were added for an actual count of 107 million barrels. The
estimated water production is 213 million barrels. The estimated volume of water for the Pitas
Point gas field is 112 thousand barrels compared to an actual count of 140.5 thousand barrels
(California, 1988).
Alaska
Production in Alaska is currently in Cook Inlet and in the Endicott Field (Beaufort Sea
region off the North Slope). The platforms currently existing in Cook Inlet are considered to be
coastal and so do not fall under the jurisdiction of this regulation. The Endicott field is already
injecting its produced water to comply with State requirements. No BAT costs, therefore, are
incurred by existing Alaska projects.
H-17
-------
TABLE H-8
ESTIMATED AVERAGE ANNUAL PRODUCED WATER GENERATED BY PACIFIC PROJECTS
Structure
Type
Number
Average Annual
Water Production
Per Project
(kbbl/yr)
Water
Production
Per Project
Oil
Pacific 16
Pacific 40
Pacific 70
Oil with Gas
Pacific 16
pacific 40
Pacific 70
Gas
Pacific 16
8
5
18
.1
2,358
5,213
9.324
2,358
5,213
9,324
112
18,864
26,065
167,832
112
Total
32
212,873
Source: EPA estimates.
H-18
-------
H.4.2 Projected Structures (NSPS)
Section Four presents the methodology used to project the number of structures for the
15-year time period after the regulation goes into effect. Table H-9 summarizes the number of
structures under the $21/bbl oil price scenario. Table H-10 lists the annual average volume of
water produced during this tune period. The average annual volume of water produced is
approximately 454 million barrels.
H.5 REFERENCES
Alaska. 1984. 1984 Statistical Report. Alaska Oil and Gas Conservation Commission, n.d.
California. 1986. 71st Annual Report of the State Oil and Gas Supervisor; 1985. California
Department of Conservation. Division of Oil and Gas, Publication No. PR06.
California. 1987. 72nd Annual Report of the State Oil and Gas Supervisor; 1986. California
Department of Conservation. Division of Oil and Gas, Publication No. PR06.
California. 1988. 73rd Annual Report of the State Oil and Gas Supervisor: 1987. California
Department of Conservation. Division of Oil and Gas, Publication No. PR06.
CCC. 1988. Oil and Gas Activities Affecting California's Coastal Zone. California Coastal
Commission, 2nd edition, December.
ERG. 1987. Report to Congress, Management of Wastes from the Exploration. Development.
and Production of Crude Oil. Natural Gas, and Geothermal Energy. Volume 1: Oil and
Gas, EPA/530-SW-88-003, December.
Flannery, D.M. and R.E. Lannan 1987. An Analysis of the Economic Impact of New Hazardous
Waste Regulations on the Appalachian Basin Oil and Gas Industry. Robinson &
McElwee, Charleston, WV, February.
Lowenhaupt. 1989. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc., and Jake Lowenhaupt, MMS, Gulf of Mexico Office, 9 January.
Miller. 1989. Letter to Maureen F. Kaplan, Eastern Research Group, Inc. from Michael A.
Miller, Chief, Reporter Contact Branch, Minerals Management Service, dated 27 January.
MMS. 1989. D. F. Boesch and N. N. Rabalais, eds. Produced Waters in Sensitive Coastal
Habitats: An Analysis of Impacts. Central Gulf of Mexico. MMS 89-0031, June.
H-19
-------
TABLE H-9
NSPS STRUCTURE ALLOCUTIONS
$21/bbl SCENARIO
All Platforms
Region
Gulf
Model
Gulf
Gulf
Gulf
Gulf
Gulf
Gulf
1b
4
6
12
24
40
Total
76
235
123
180
114
27
Oil
12
89
34
84
62
27
Gas
64
146
89
96
52
0
Within 4-Hiles
Total
23
60
43
14
0
0
Oil
0
27
15
14
0
0
Gas
23
33
28
0
0
0
Beyond 4-Miles
Total
53
175
80
166
114
27
Oil
12
62
19
70
62
27
Gas
41
113
61
96
52
0
Alaska
Cook Inlet 12 101
Cook Inlet 24 110
B. Gravel Island* 220
Total Platforms - All Regions 759 311 448 142 58
* Oil only; all other projects are assumed to produce oil and casinghead gas.
0
0
0
84
1
1
0
617
0
1
0
253
1
0
0
364
H-20
-------
TABLE H-10
ESTIMATED AVERAGE ANNUAL NSPS WATER PRODUCTION
S21/BBL RESTRICTED DEVELOPMENT SCENARIO
Average Annual
Project Water Production Number of
Type Model
-------
-------
APPENDIX I
BASE CASE FINANCIAL ASSUMPTIONS AND RATES
The economic and financial accounting assumptions used in the economic model are
based upon common oil industry financing methods and procedures. Changes in tax
computations due to the Tax Reform Act of 1986 (Public Law 99-514) are incorporated in the
EPA model.
1.1 INCREMENTAL IMPACT OF MODEL PROJECT ON CORPORATE INCOME TAX
RATE
It is assumed that the model projects are incremental to the other activities,of the
company and, therefore, the net taxable income is marginally taxed at the U.S. corporate rate of
34 percent. This assumption implies that the company has at least $100,000, of other net income
•without this project. In addition, it is assumed that any net losses in the initial years of a project
can be applied to the net income of other projects, so that an effective tax shield of 34 percent of
the loss is realized. Therefore, the yearly net cash outflow is 100 percent minus 34 percent, or 66
percent of the year's loss. This is appropriate because of the customary size and level of
activities of firms undertaking offshore oil exploration and production: The basis for Federal
income is gross revenues minus royalty payments, severance taxes, depletion and depreciation
allowances, and operating costs.
1.2 SEVERANCE TAXES
Since the Outer Continental Shelf regions are under the jurisdiction of the Federal
government, it is assumed that State severance taxes are not applicable to the revenues generated
by OCS production. Consequently, severance taxes are not included in the analysis of model
projects located in Federal waters. The projects expected to be located in State waters and
1-1
-------
therefore subject to severance taxes for tax purposes are the Gulf 1-well, 4-well, 6-well, 12-well,
and 24-well platforms; Cook Inlet projects the Beaufort Sea 48-well gravel island; and the
California 40-wellslot platform.
Texas State severance taxes are 4.6 percent on oil and 7.45 percent on gas. Louisiana
imposes a 12.5 percent severance tax on oil and a $0.07 per Mcf tax on gas. (Using the 1982
wellhead price, the Louisiana $0.07 tax is equivalent to a 1.3 percent tax on gas.) Based on
cumulative oil and gas production data for Texas and Louisiana offshore leases through 1981, an
average severance tax of 6.19 percent was calculated and this value is used for the Gulf projects
in State waters.
California, at present, has no severance taxes.
The Alaska severance tax structure consists of nominal rates that are then adjusted by a
formula. The fomiula is referred to as the Economic Limit Factor (ELF).
Nominal tax rates on oil are 12.25 percent of gross revenues for the first 5 years of
production and 15 percent thereafter. The ELF formula for oil is:
460 xWD
PEL
(ELF = i-
where:
PEL = monthly production at the economic limit
TP = total monthly production
' WD = well days for the month (assumed to be 30).
The monthly production at the economic limit value is confidential between the oil company and
the Alaska Department of Revenues. Three hundred bbl/day/well or 9,000 bbl/month/well is
used for the economic limit (PEL) in this analysis (Logsdon, 1988).
1-2
-------
As an example, suppose monthly production is 50,000 barrels. Then the ELF is:
460x30
9,000
/ 9.000
ELF = (l - 50,000
= (0.82)1'533 = .74
If the ELF is greater than 0.7, then the tax rate is the nominal rate. If the ELF is less
than 0.7, severance taxes are calculated as follows:
For the first five years of production:
Oil Severance Taxes = Gross revenues x 12.25 percent x ELF.
After the first five years of production:
Oil Severance Taxes = Gross revenues x 15.00 percent x ELF.
The oil ELF is applied as long as it is positive.
The nominal severance tax rate on natural gas is 10 percent, which is adjusted by the
following ELF formula:
PEL
ELF = 1 - TP
where:
PEL = monthly production at the economic limit
TP = total monthly production.
1-3
-------
Three thousand Mcf/day/well or 90,000 Mcf/month/well is used for the economic limit (Logsdon,
1988). Gas severance taxes are calculated as follows:
Gas Severance Taxes = Gross revenues x 10.00 percent x ELF.
Unlike the oil severance ELF, the gas ELF is applied regardless of value, as long as it is positive.
For offshore leases, the basis for the severance tax calculation would be on the basis of
(gross revenues - exempt revenues), where royalty payments to state government are considered
exempt revenues.
L3 ROYALTY RATES
Operators of oil- and gas-producing properties are usually required to pay royalties to the
lessors or owners of the land based on the value of extracted production. This includes the
Federal government for OCS leases and State governments for leases located in State waters. In
many instances, Hie royalty rate is a floating rate that varies from year to year, or a complex
calculation based on the amount or mix of production. For the model projects, it is assumed
that an average fixed rate of one-sixth (17 percent) of total gross revenues is the best
approximation of royalty payments for a typical large project in Federal waters and 22 percent
for a. project on a State-owned tract.
1.4 RENTAL PAYMENTS
Rental payments generally comprise a negligible cash outflow in the overall set of costs
for an oil and gas project. For this reason, they have been excluded from the analysis.
1-4
-------
1.5 DEPRECIATION
The Tax Reform Act of 1986 modifies the Accelerated Cost Recovery System (ACRS) for
property placed in service after 31 December 1986. Under the new system, most oil and gas
equipment will be classified as seven-year property. The recovery method for this class is double
declining balance (Snook and Magnuson, 1986). The schedule used to write off capitalized costs
in the model is as follows:
Year 1 14.29% of costs
Year 2 24.49%
Year 3 17.49%
Year 4 12.49%
YearS 8.93%
Year 6 8.92%
Year? 8.93%
YearS 4.46%
Year 1 in the above table is defined as the first year in which the equipment is placed in service.
According to relevant accounting principles, this is the first year in which the equipment
produces oil or gas.
The value of the deduction for depreciation is reduced by inflation. To maintain the
calculations on a constant-dollar basis, the value of the deduction is adjusted downwards in later
years by the inflation rate. (See Section 1.8).
1.6 BASIS FOR DEPRECIATION
The Tax Reform Act of 1986 repealed the Investment Tax Credit (Snook and Magnuson,
1986; Coopers and Lybrand, 1986). This means that the initial basis for depreciation is 100
percent of the total capitalized costs.
1-5
-------
1.7 CAPITALIZED COSTS
It is assumed that the tax payer (oil company) elects to expense intangible drilling costs
incurred in the development of oil and gas wells. Intangible drilling costs (IDCs) are estimated,
on the average, to represent 60 percent of the cost of production wells and their infrastructure
(Commerce, 1982; Commerce, 1983; API, 1986). The Tax Reform Act limits major integrated
producers to ejrpensing 70 percent of IDCs with the remaining 30 percent capitalized (that is, a
major may only expense 0.60 times 0.70, or 42 percent of its IDCs). Independents are still
allowed to expense 100 percent of their IDCs. The remaining 40 percent of the total cost is
capitalized and treated as depreciable assets for tax purposes (Snook and Magnuson, 1986).
Dry holes are written off in the year in which the cost is incurred. For independents, the
proportion of the exploratory drilling cost that is capitalized is therefore equal to 40 percent of
the total drilling cost times the discovery efficiency. For majors, the proportion is 58 percent of
the total drilling cost times the discovery efficiency. The remaining drilling costs are expensed.
1.8 INFLATION RATE
The effective value of depreciation and cost-basis-depletion deductions is reduced by
inflation since the expenditures occur in year(s) prior to the deduction. The model calculates an
"adjusted depreciation" as follows:
Adjusted depreciation _
in Year X
Depreciation in Year X
YearX
(1 + inflation rate)
An "adjusted cost-basis-depletion" is calculated in a similar manner.
The change in the "Fixed Weight Price Index" is used as a measure of inflation for this
analysis. Since 1982, the values are:
1-6
-------
1982 6.2
1983 4.1
1984 4.0
1985 3.7
1986 2.8
for an average of 4.2 percent (Economic Report, 1987). This value is used in the analysis to
deflate depreciation and depletion.
1.9 ESCALATION OF GENERAL PROJECT COSTS IN REAL TERMS
It is assumed that costs will remain constant in real terms, i.e., the rate of increase in
material and labor costs is equal to the rate of inflation.
1.10 OIL DEPLETION ALLOWANCE
The EPA model calculates depletion on a cost basis, which is appropriate for major
producers. Cost depletion allows the producer to recover the leasehold cost over the producing
lifetime of the well. The leasehold cost consists of the bonus bid (see Appendix C), and certain
geological, geophysical, and legal costs (see Appendix D).
Cost depletion is based on units of production and is represented by the following
formula:
B = U + S
where:
B
S
U
adjusted basis of leased property
units sold during the period
units remaining at the end of the period.
1-7
-------
The initial basis of the property used in the EPA model consists of the bonus bid and the
geological and geophysical expenses. (That is, the legal costs incurred in acquiring the lease are
not explicitly included in the model. It is assumed they form a minimal increment to the overall
leasehold cost.) The basis is then adjusted downwards to account for the depletion taken in each
period. The portion of the adjusted basis taken as depletion in any given period is the units sold
during the period, divided by the units sold and the recoverable units remaining. For the
purposes of the model, it is assumed that all units produced in a period are sold in the same
period. Thus, the depletion for any given period is equal to the adjusted basis multiplied by the
ratio of units produced in the period to the sum of the units produced and remaining. In this
manner, the leasehold cost is amortized over the productive life of the well.
The value of the cost-basis depletion is reduced in later years by inflation. (See Section
1.8 for the methodology used to correct for this in the calculations). The value used in the
annual cash flow is the inflation-adjusted value. The unadjusted value is used to calculate the
basis for depletion in subsequent years.
1.11 SALVAGE
It is assumed that the after-tax cost to remove the infrastructure and to retire the well at
the end of its economic life is approximately equal to their salvage values. Hence, there is no
additional positive or negative cash flow. ...
1.12 INVESTMENT TAX CREDIT
The Tax Reform Act of 1986 repealed the Investment Tax Credit (Snook and Magnuson,
1986; Coopers and Lybrand, 1986).
1-8
-------
1.13 WINDFALL PROFITS TAX
A phaseout of the Windfall Profits Tax of 1980 began in January 1991. Though the low
price of oil, however, meant it had no effect in recent years. For these reasons, the effects of the
Windfall Profits Tax have not been included in the analysis.
1.14 DISCOUNT RATE
The discount rate used in this analysis represents the opportunity cost of capital for
investments in oil and gas production (Brigham, 1982). The cost of capital is the investor's
expected rate of return for a particular investment; that is, the cost of capital is the return that
could be earned elsewhere in the economy on projects of equivalent risk. The riskier the
investment, the higher the cost of capital.
The opportunity cost of capital is modeled as:
Real cost
of
Capital
= I 1 + nominal cost I -
j_l + inflation ratej
where:
nominal cost = [equity cost * equity share] + [debt share * debt cost].
The equity cost is the sum of the risk-free return and the risk premium. For the risk-free
return, EPA uses the average return on long-term U.S. Treasury bonds. The risk premium is the
product of the average industry risk (i.e., the industry beta) and the market risk for long-term
investment.
The debt and equity shares are the portions of capital financed by debt and equity,
respectively. These are estimated by the average share of debt or equity in the firm's value.
1-9
-------
The debt cost is the after-tax cost of debt, i.e., the product of the current cost of debt and
(1 minus the cor]x>rate tax rate). For the current cost of debt, the interest rates for Moody's Baa
corporate bonds are used.
The next point to consider is whether to use long-term or short-term estimates for each of
these parameters. The productive life of the project can be several decades in the EPA model.
On this basis, long-term average values are used in estimating the cost of capital.
Table 1-1 compiles twenty-year averages for risk-free returns, current cost of debt, and
inflation rates. (Most projects in this study are no longer profitable after twenty years of
production.) Table 1-2 gives the average long-term debt-to-capital ratio for 19 major integrated
companies. This ratio varies around 25 percent for the time period investigated. On this basis,
we use 25 percent as the debt share and 75 percent as the equity share in the cost of capital
calculations.
The cost of capital is calculated in Table 1-3. Sources for the remaining parameter values
are cited hi the table. The estimated cost of capital is 7.55 percent. This value is rounded
upwards to 8 percent for use in the analysis.
US REFERENCES
API. 1986. 1984 Survey on Oil and Gas Expenditures, American Petroleum Institute,
Washington, DC, October.
Brealey, R.A. and S. Meyers. 1984. Principles of Corporate Finance. McGraw-Hill, New York,
NY, 2nd edition.
Brigham, E.F. 1982. Financial Management: Theory and Practice, The Dryden Press, New
York, NY, 3rd edition.
Commerce. 1982. Annual Survey of Oil and Gas. 1980. U. S. Department of Commerce,
Bureau of the Census, Current Industrial Reports, MA-13k(80)-l, March.
Commerce. 1983. Annual Survey of Oil and Gas. 1981, U. S. Department of Commerce,
Bureau of the Census, Current Industrial Reports, MA-13k(81)-l, March.
MO
-------
TABLE 1-1
TWENTY-YEAR AVERAGES FOR RISK-FREE, CORPORATE BORROWING,
AND INFLATION RATES
YEAR
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
RISK-
FREE
RATE
5.07
5.65
6.67
7.35
6.16
6.21
6.84
7.56
7.99
7.61
7.42
8.41
9.44
11.46
13.91
13.00
11.10
12.44
10.62
7.68
CORPORATE
BORROWING
RATE
6.23
6.94
7.81
9.11
8.56
8.16
8.24
9.50
10.61
9.75
8.97
9.49
10.69
13.67
16.04
16.11
13.55
14 . 19
12.72
10.39
INFLATION
RATE
2.6
3.7
4.4
3.6
3.5
2.9
5.5
7.8
8.0
5.3
5.1
6.2
8.5
9.3
9.3
6.2
'4.1
4.0
3.7
2.8
Average
8.63
10.54
5.3
Source: Economic Report, 1987; Table B-68 (10-year U.S. Treasury securities
and Moody's Baa corporate bonds) and Table B-4 (inflation rate).
1-11
-------
TABLE 1-2
DEBT/CAPITAL RATIO (%)
MAJOR INTEGRATED OIL COMPANIES IN 19-COMPANY EPA GROUP
(1977-1985)
Amerada Hess
American Pctroffna
Atlantic Richfield
Diamond Shamrock
Exxon
Getty Oil (Texaco)
Gulf Oil (Chevron)
Kerr-HcGee
Mobil Oil
Hurphy Oil
Occidental Petroleum
Phillips Petroleun
Shell Oil (Royal Dutch
1977
36.7
26.4
34.2
38.1
14.4
5.8
13.5
20.9
25.2
35.5
26.8
21.0
20.6
1978
36
45
34
38
13
4
14
16
25
.0
.8
.6
.4
.3
.7
.1
.6
.6
40.5
39
16
18
.4
.3
.4
1979
30.0
40.4
29.4
38.1
13.3
4.0
13.0
20.4
21.3
32.3
39.0
13.6
30.6
1980
29.5
33.5
27.1
36.0
12.5
10.8
10.7
24.1
19.0
19.1
25.6
12.4
33.0
1981
35.2
28.1
28.9
34.0
12.0
9.8
13.0
33.1
17.3
21.1
20.1
15.0
31.3
1982
38.9
26.0
28.7
34.3
10.6
16.6
14.6
29.7
21.1
16.9
43.5
22.7
27.8
1983
40.3
31.4
26.2
37.0
10.5
—
--
27.1
24.4
15.1
34.0
23.3
19.1
1984
40.1
39.1
26.9
28.1
11.6
--
--
23.5
40.9
14.3
43.3
26.0
17.3
1985
40.
6
40.8
43.9
40.
10.
--
--
23.
35.
13.
47.
64.
14.
7
4
4
8
7
6
3
6
Petroleun)
Standard Oil of California
(Chevron)
Standard Oil of Indiana
(Amoco)
Standard Oil of Ohio
Sun Company
Texaco
Union Oil Company
Unweighted
Company Averane*
19.7 17.2 13.0 12.4 11.3 10.6 43.4 28.9
23.5 21.1 18.8 21.4 22.0 20.1 17.3 16.9
65.4 50.3 39.8 36.1 33.8 29.2 26.4 25.4
19.4 16.8 34.5 28.6 24.7 24.8 25.3 20.7
24.8 21.8 18.0 15.1 12.8 14.1 41.0 31.6
28.6 26.0 21.9 18.3 18.6 17.6 15.3 64.1
26.2 27.6 25.2 23.1 22.7 23.9 23.8 28.2 33.1
16.2
25.2
71.9
18.9
19.1
Souica: S&P 1982; S&P 1986.
•Simple average calculated from the ratios for all companies in the
sample.
1-12
-------
TABLE 1-3
COST OF CAPITAL CALCULATIONS
PARAMETER
VALUE
SOURCE
Risk- free return
Industry beta
Market risk
Risk premium
Cost of debt
Debt cost
Debt share
Equity share
Inflation rate
Nominal cost
Real cost
8
0
8
6
10
6
25
75
5
13
7
.63%
.84%
.00%
.72%
.54%
.96%
.00%
.00%
.30%
.25%
.55%
See Table 1-1.
Kavanaugh, M. 1987. Average beta
for 24 petroleum companies. Standard
& Poor ' s Stock Reports .
Brealey and Myers 1984.
Calculated.
See Table 1-1.
Tax Reform Act of 1986, highest
corporate tax bracket is 34 percent.
See text.
See text.
See Table 1-1.
Source: as listed.
1-13
-------
Coopers and Lybrand. 1986. Tax Reform Act of 1986: Analysis. New York NY.
Economic Report. 1987. Economic Report of the President 1987. Council of Economic
Advisors, January, Table B-4.
Kavanaugh, M. 1987. "Cost of Capital in the Petroleum Industry: Memorandum to Mahesh
Poder, OPPE, Environmental Protection Agency, from M. Kavanaugh, January 15.
Logsdon, C. 1988. Personal communication between Maureen F. Kaplan, Eastern Research
Group, Inc., and Charles Logsdon, Alaska Department of Revenue, March 15.
Snook, S.B. and W.J. Magnuson, Jr. 1986. "The Tax Reform Act's Hidden Impact on Oil and
Gas," The Tax Adviser. December, pp. 777-83.
1-14
-------
APPENDIX J
EPA ECONOMIC MODEL FOR OFFSHORE PETROLEUM PRODUCTION
J.I INTRODUCTION
The EPA model simulates the costs and petroleum production dynamics expected in the
development and production of an offshore well for oil and/or gas. Data to define the well and
the petroleum reservoir are entered into the model. Through the use of internal algorithms, the
model calculates the economic and engineering characteristics of the project. Outputs from the
model include: production volume, project economics, and summary statistics.
The model is^ structured to be flexible. It is capable of modeling projects on a single-well
or multiple-well basis with exploration and development occurring within a single year or over a
decade. Flexibility is possible through the use of user-specified inputs for a wide variety of
variables. Inputs include, but are not limited to: lease bids, development schedules,
infrastructure and operating costs, initial petroleum production, production decline rates, tax rate
schedules, and wellhead prices. The data define the proposed development project.
From the user-specified data, costs and production performance are calculated on a
yearly basis through a series of algorithms. The model calculates yearly production, present
value of yearly production, and present value of production income. The model generates a
consistent set of annual values and summary statistics to evaluate the project. All dollar amounts
in this analysis and in the accompanying printout are in thousands of 1986 dollars.
J.1.1 Model Phases *
The project life of an offshore well producing oil and/or gas is divided into five phases:
(1) from lease bid to the start of exploration, (2) from the start of exploration to the start of
J-l
-------
delineation, (3) from the start of delineation to the start of development, (4) from the start of
development to the start of production, and (5) production. The length of each of these phases
is an exogenous variable input to the model.
For multiple-well projects, the impetus to begin production is great and the production
phase may overlap the development phase; that is, petroleum production may begin while some
wells are still being drilled. The EPA model is capable of modeling this situation (see Section
J.2).
The project operates for 30 years or for as long as it is profitable. Project economics are
evaluated annually within the model algorithms and the project is shut down at the first negative
cash flow.
J.1.2 Economic Overview of the Model
The economic character of the model phases is quite different. Phases one through four
generate cash outflows; no revenues are earned during this period. The fifth phase, production,
generates net cash inflows. During this phase, the project continues to operate as long as
operating cash inflows exceed cash expenses.
J.L2.1 Cash Flows - Categorizfftion
The model deals with a number of basic cash flows (or resource transfers). The basic
cash flows are as follows:
Leasing Phase:
Lease bid - cost of acquiring rights to explore and develop a tract
of land.
J-2
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Exploration Phase:
Delineation Phase:
Development Phase:
Production Phase:
Cr&G costs - geological and geophysical expenses incurred prior to
drilling.
Exploration well costs - cost of drilling an exploration well.
Incremental drilling costs - additional cost of drilling due to new
regulations concerning muds and cuttings.
Delineation well costs - costs of drilling a delineation well.
Incremental drilling costs - additional cost of drilling due to new or
revised regulations concerning drilling fluids and drill cuttings.
Development well costs - costs of drilling a development well
(includes prorated cost of building and installing a petroleum
production platform; see Appendix F).
Infrastructure costs - cost of production equipment installed on the
platform.
Incremental drilling costs - additional cost of drilling due to new or
revised regulation concerning drilling fluids and drill cuttings.
Incremental capital costs - additional costs due to new equipment
required for additional pollution control of produced water,
treatment and workover fluids, and/or produced sand.
Revenues from oil and gas production - production levels
multiplied by price forecasts.
O&M costs - cost of operating and maintaining the well.
Incremental O&M costs - additional cost due to new or revised
regulations concerning produced water, treatment and workover
fluids, and/or produced sand.
The basic cash flows, summarized above, are affected by a number of factors that are
depicted in Table J-l below. The matrix in Table J-l can be illustrated by using the lease bid as
an example. Initially, the lease bid generates a cash outflow in the initial phase of the project.
Three factors, however, allow a portion of that outflow to be recouped during the production
phase of the project. These factors, the Federal and State corporate tax rates and the depletion
allowance for major integrated producers, are denoted by plus signs in the table because of their
positive effect on the project cash flow. (Major producers are allowed to amortize the leasehold
J-3
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J-4
-------
cost over the productive life of the well and use this allowance to reduce taxable revenue. For a
more detailed discussion of the depletion allowance, see Section 1.10.)
J.2 STEP-BY-STEP DESCRIPTION OF THE MODEL
The ensuing discussion is a sequential overview of how the code operates. It starts with
the lease bid and ends with the shut down of the well either after 30 years of production or when
the project becomes unprofitable. To illustrate the code, the inputs, calculations, and outputs for
a 12-well oil and gas platform in the Gulf of Mexico are used. The project was chosen because
its size and production type are common in the Gulf (see Appendix A).
The discussion is based on the computer printout attached to this appendix.
Identification numbers for specific lines are given in the right-hand margin. A list of user-
specified inputs is given in Table J-2. All dollar values te.|g.. costs and revenues^ are expressed in
thousands of 1986 dollars. Values on spreadsheet may differ in the final digit from numbers
presented in the text due to rounding.
J.2.1 Phase One - Leasing
The lease cost (line 1) is a user-specified input, the value of which is based on 1986 lease
sales in the Gulf of Mexico. See Appendix C for regional lease costs and their derivation.
J.2.2 Phase Two - Exploration
Line 2 represents the costs of geological and geophysical (G&G) investigation of the site
as a percentage of lease cost. The value shown in line 2 is based on information in the API cost
survey for 1986 (see Section D.I). The total leasehold cost (Jine_3) is the sum of the lease bid
and G&G expenses. The total leasehold cost is a cash outflow in Year 0 of the project; the
J-5
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TABLE J-2
EXOGENOUS VARIABLES PROVIDED TO EPA ECONOMIC MODEL
IDENTIFICATION
NUMBER
PARAMETER
1
2
4
5
6
7
8
9
10
12
13
23
24
25
36
37
38
39
40
41
48
56
57
58
59
62
63
64
65
•66
67
68
69
70
71
72
73
74
75
.Lease cost.
Geological and geophysical expense.
Real discount rate.
Inflation rate.
Years between lease sale and exploration.
Percent of cost considered expensible intangible drilling
costs.
Drilling mud cost increment.
Federal corporate tax rate.
Drilling cost per exploratory well.
Discovery efficiency.
Platforms per successful exploratory well.
Years between start of exploration and delineation.
Number of delineation wells drilled.
Cost per delineation well.
Total platform cost.
Pollution control capital costs (produced water).
Years between delineation and development.
Number of development wells drilled.
Number of development wells drilled per year.
Drilling cost per development well.
Annual Pollution Control Capital Costs.
Percent watercut in oil and gas to start.
Oil and gas production decline rate.
Cost escalator.
Royalty rate.
Depreciation schedule.
Severance tax rate - oil.
Severance tax rate - gas.
Gas-only flag.
Years between development and production.
Years at peak production.
Oil - peak production rate (bbl/day).
Gas - peak production rate (MMCF/day).
Number of producing wells.
Number of wells put in service per year.
Wellhead price per barrel - oil.
Wellhead price per Mcf - gas.
Total operating costs.
Annual pollution control equipment operating cost (produced
water}-.
Source: EPA estimate.
J-6
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value on line 3 is therefore the present value of the leasehold cost. The leasehold cost forms the
basis for the depletion allowance as calculated on a cost basis for major integrated producers.
Line 4 is the real discount rate, i.e., the cost of capital. This value is used throughout the
code to discount future cash inflows, cash outflows, and production in order to express them in
present value terms. .
LineS is the inflation rate. This parameter is used to reduce the value of the deductions
for cost-basis depletion and depreciation in future years.
Line 6 is the number of years between the lease bid and the start of exploration. For all
projects in the Gulf of Mexico, exploration begins in the same year as the lease sale. For other
regions, the number of years between lease bid and the start of exploration varies from one to
two years (see Appendix B).
The petroleum industry has considerable latitude in its treatment of costs. An oil
company can expense, in the period incurred, costs that would normally be capitalized. This
immediate expensing of a portion of capital costs provides a significant tax advantage.
Line 7 contains the percentage of drilling costs that are considered "Intangible Drilling
Costs" (IDCs) and are eligible for expensing. An initial value of 60% is used in this analysis as
the percentage of costs considered IDCs. This is based on annual surveys of expenditures (see
Section 1.7). Under the Tax Reform Act of 1986, independents may expense 100% of IDCs,
while majors may expense only 70%. Since the project is assumed to be a venture by a major
company, the value shown is 42 percent (0.60 x 0.70).
The additional costs due to new pollution control regulations on drilling muds and
cuttings are entered in line 8. The Federal corporate income tax rate is entered on line 9.
The drilling cost for a well depends on the depth drilled, environmental requirements,
and regional costs for parts and labor. The cost of drilling a well has been summarized in
Section D.3, and is entered on line 10. The discovery efficiency (the ratio of productive wells to
J-7
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all wells drilled) also varies by region, depending upon the predictability of the reservoir. All-
time regional averages are used in this study (see line 12. Section D.2). Line 13 is the number of
platforms buill: per successful exploratory well. This parameter varies by region (see Section
C.3).
Line 14 displays the exploratory well costs for the project. The exploratory well cost is
the sum of the cost of drilling the well and the drilling mud cost increment divided by the
product of the discovery efficiency and the number of platforms per successful well. This cost is
spread over the number of years between the start of exploration and the start of delineation
(see line 23). For the 12-well GOM project, the annual exploratory well costs are:
Annual
Explora-
tory Well
Costs
(well cost + incremental drilling fluid cosfl
(discovery efficiency * no. of platforms per
successful well)
(4.355 + (ft -5- 1 = $7,234
(.14 * 4.3)
Years
of
Exploration
One year for exploration is scheduled for this project (line 23).
The annual cost of successful efforts (line_15) is the product of the annual exploratory
well cost and the discovery efficiency:
Annual Cost of
Successful Efforts
Annual Total Well Cost
* Discovery Efficiency
($7,234 * .14) = $1,013
' Annual expensed costs (line 16) are the sum of two factors: (1) the product of the
annual cost of successful efforts times the percent costs expensed (line 7) and (2) dry hole
expenses:
J-8
-------
Annual Expensed = (cost of successful efforts x % expensed)
Costs + (exploratory costs x (1-disc. eff.))
($1,013 * .42) + ($7,234 * .86)
$425+ $6,221
= $6,646 (note rounding)
In other words, the annual expensed cost is the sum of unsuccessful efforts and the expensible
portion of intangible drilling costs for successful wells.
The expensed cost is $6,646/yr for each year of exploration. The actual cash outflow,
however, is dependent upon the corporate tax rate. The expenses reduce the tax bill for a
profitable corporation. The calculations to determine the actual cash outflow, shown below,
assume a marginal corporate tax rate of 34 percent (see line 17).
Expensed Cash Flows =
(1 - tax rate) * Expensed Costs
(1 - .34) * $6,646 = $4,387
Capitalized cash flows, line 18. are the exploration costs that are not expensed. The
proportion of drilling efforts that may be expensed depends upon whether the corporation is a
major or independent producer. For the Gulf of Mexico project, a major producer is assumed.
Under the Tax Reform Act of 1986, a major may" expense 70 percent of the intangible drilling
costs (IDCs) and the IDCs are estimated to be 60 percent of the drilling costs. For a major,
then, 1 - (0.6 x 0.7) or 58 percent of the successful drilling costs are capitalized:
Capitalized Cash Flows
0.58 * Cost of Successful Effort
(line 18)
0.58 * $1,013 = $587
Since capitalized costs generate no tax shield in the year incurred, the capitalized cash flow is
equal to the capitalized cost.
J-9
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Once the various exploration costs and cash flows have been calculated, they are put in
present value terms as of the lease year. For all Gulf of Mexico offshore projects, exploration
costs are incurred in Year 0, the year the lease was obtained. For these projects, the present
value of all exploration costs are the same as the value for Year 0.
Present values are calculated for expensed exploration cash flows, capitalized exploration
cash flows, and all exploratory costs (lines 19, 20, and 22). The sum of all capitalized exploration
cash flows is given in line 21.
J.23 Phase Three - Delineation
If an exploratory well discovers petroleum, delineation wells may be drilled to confirm the
size and extent of the reservoir. In this project, one year is assumed to pass between the start of
exploration and the start of delineation (line 23: see Appendix B for timing assumptions). Two
delineation wells are drilled (line 24). each costing the same as an exploratory well (line 25). As
with exploratory wells, the costs are allocated over the number of platforms per successful
exploratory well (line 27).
The annual delineation costs (line 28) are the product of the number of delineation wells
and the cost per delineation well, divided by the number of platforms per successful exploratory
well. This cost is allocated over the number of years between the start of delineation and the
start of development if its value is greater than one (line 37). For the 12-well Gulf of Mexico
project, the annual delineation well costs are:
Annual
Delineation
Well
Cost
(well cost + incremental drilling fluid cost)
* number of delineation wells
-s- number of platforms per successful discovery
($4,355 * 2) -^ 4.3
$2,026
J-10
-------
The tax shield (line 29) is the product of the annual delineation cost, the percentage of
drilling costs considered intangible drilling costs (which are therefore eligible for expensing), and
the corporate tax rate:
Tax Shield =
Drilling Cost
* Percentage of drilling costs considered IDCs
* Percent of IDC that can be expensed
* Federal corporate tax rate
$2,026 * 0.6 * 0.7 * .34
$289
Expensed cash flow (line 30^ is the annual delineation well cost times the expensed
percentages of IDCs minus the tax shield:
Expensed Cash Flow = (Annual delineation cost
* percentage considered expensible IDCs)
-tax shield
($2,026 * 0.42) - $289
= $562 (note rounding)
Capitalized cash flow (lineSl) is the annual delineation well cost times the portion of costs that
cannot be expensed.
Capitalized cash flow = delineation costs * (1 - 0.42)
$2,026* .58
$1,175
Once the various delineation costs and cash flows have been calculated, they are put in
present value terms of the half year. The delineation costs are incurred in Year 1 of the 12-well
Gulf of Mexico project. The costs and cash flows must be adjusted by the time value of money,
i.e., the discount rate. For this project, the delineation costs are discounted as follows:
J-ll
-------
Present Value = cost in Year 1 -s- 1.081
For the expensed cash flow, this is
PV expensed cash flow
$561 4- 1.08
$520
Present values are calculated for expensed cash flow, capitalized delineation costs, and total
delineation costs (lines 32-35).
J.2.4 Phase Four - Development
The costs of production equipment and other infrastructure costs are entered in line 36.
Additional construction costs for the installation of pollution control equipment are entered
separately in line 37. For this project, there are 2 years between the start of development and
the start of production (line 66). Costs for both types of construction are allocated over the first
year or over the years of construction minus 1 year (line 47).
The development phase in the code is structured to accommodate the drilling of
development wells after a reservoir has been determined. Separate entries for the total number
of wells in the project, the number of wells drilled each year, and the drilling cost per well
appear in lines 39 through 41. respectively.
Lines 42 through 48 calculate the costs incurred each year from the drilling of
development wells, and the construction of production and pollution control facilities. The total
annual capital development costs are given in line 49.
The tax shield, line 50. is the product of the annual total capital development costs, the
corporate tax rate, and the percent of costs expensed. For Year 1 of the 12-well Gulf of Mexico
project, this is $11,660 x 0.34 x .42 or $1,665. The expensed cash flow, line 51. is the total annual
capital development costs (line 49) times the percentage of costs expensed (line 7) minus the tax
shield (line 50). For Year 2,-this is ($29,436 x 0.42) - $4,203 or $8,160. The capitalized cash
J-12
-------
flow, line 52, is the product of total capital costs and (1 - the percentage of expensible IDCs).
For Year 3, this is $19,624 x 0.58 or $11,382. Note that the sum of the tax shield, the expensed
costs, and the capitalized costs is equal to the total costs.
As with the exploration costs, development costs are discounted to determine their
present value in the lease year. Present values of all development costs, expensed development
costs, and capitalized development costs are given in lines 53 through ss. respectively.
J.2.5 Phase Five - Production
In the production phase of the project, a variety of financial and engineering variables
interact to form the economic history of the well. Line 57 provides the production decline rate
for oil and gas. The EPA model incorporates an exponential function for production decline,
i.e., a constant proportion of the remaining reserves is produced each year. For every barrel
produced in the initial year of operation in this project, 0.85 barrel is produced in the second
year, 0.852 or 0.723 barrel in the third year, and so forth.
The EPA model is capable of handling cost escalation (see line 58). In this report, we
are considering costs in real terms, and thus no escalation is assumed.
The royalty rate paid to the lessor of the land is provided in line 59. The depreciation
schedule is listed in line 62. State severance taxes on oil and gas are given in lines 63 and 64.
respectively. Note the flag for calculating severance taxes for Alaska since these must be
adjusted by the Economic Limit Factor (ELF).
Line 65 is a flag to identify gas-only projects. The flag is necessary for the proper
calculation of depletion on a cost basis within the code.
The number of years that a well produces at its peak rate is given in line 67. The peak
production rates per well for oil and gas are given in lines 68 and 69. respectively. Note that
these are figures for daily production and that the units for gas production are MMcf/day.
J-13
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Since not all wells are turned into producing wells (e.g., some are exploratory wells in
offshore operations or reinjection wells), lines 70 and 71 specify the number of producing wells
and the rate at which they enter production.
The wellhead prices for oil and gas are entered on lines 72 and 73. respectively. Annual
operating costs are entered on line 74. while line 75 contains the incremental costs of water
disposal due to compliance with pollution control regulations.
77 provides the number of producing wells in service and is calculated from the total
number of producing wells and the number of wells that go into service per year. The barrels of
oil produced per day (line 78) is a function of the number of wells and the year in which they
went into service.
In general, production for a group of wells that went into service in the same year is
calculated as:
Daily Production = # of wells x # of barrels/day x decline rate"
where a. = year of production - number of years at peak production.
This is extended to calculate production for wells going into service in different years. For
example, in line 78,
Daily Production Year 3
Year 4
6 wells * 500 bopd
3,000 bopd
(6*500) + (4*500)
3,000 + 2,000
5,000 bopd
J-14
-------
YearS
Year 6
(6 * 500 * 0.85) + (4 * 500)
2,550 + 2,000
4,550 bopd
(6 * 500 * 0.852) + (4 * 500 * 0.85)
2,168+.1,700
3,868 bopd
and so forth.
The annual oil production is calculated as 365 times the daily production (line 80). The
price per barrel is repeated in line 81 for convenience in cross-checking the gross revenues for oil
production (line 85). Lines 82. 83. and 84 list the daily gas production, annual gas production,
and wellhead price per Mcf. .
J.2.4.1 Income Statement
Lines 85 through 107 comprise an income statement that is repeated annually for a 30-
year project lifetime. Since most projects become uneconomical before this, lines 108 through
114 check for .a negative net cash flow and readjust the actual production, revenues, and cash
flows to zero when appropriate.
Lines 85 and 86 list the revenues from oil and gas production. Total cash inflow for the
year is given in line 87. Royalty payments are calculated on the basis of gross revenues (lines 88
and 89; see line 60 for the royalty rate). Severance taxes are calculated on the basis of gross
revenues minus royalty payments (lines 90. and 91: see lines 63 and 64 for severance tax rates).
The economic limit factor (ELF) for the calculation of severance taxes for Alaska is given in
lines 92 and 93 (see Section H.2 for a-more complete discussion of severance tax calculations for
Alaska). Net revenues for Year 3, line 94. are calculated as:
J-15
-------
Net revenues = Total Gross revenues - royalty payments
- severance taxes
$30,783 - $5,738 - $1,034 - $1,259 - $227
= $22,525 (note rounding)
Operating costs are given in line 95; incremental operating costs due to pollution control
appear in line 97. The entry on line 98 is the sum of the capitalized costs spent in the
exploration, delineation, development, and production phases to that year:
Capitalized Costs
For Year 3
= Capitalized Costs in the Exploration Phase
+ Capitalized Costs in the Development Phase
+ Capitalized Costs in Development Phase up to that year
$587+ $1,175 + $6,763 + $17,073 = $25,598 ..;....
(line 21) (line 33) (line 52)
The adjusted depreciation allowance is listed in line 99. The depreciation schedule under
the Tax Reform Act of 1986 is found on line 62. The unadjusted depreciation allowance is the
product of $25,598 (capitalized costs) and the depreciation rate for the appropriate year, e.g.,
$25,598 x 14.29% = $3,658'for the first year of operation for the project (Year 3).
The figure of $3,658 would be used in the tax calculations for the company. The value of
that deduction, however, has been eroded by inflation. To adjust for this effect, we calculate a
deduction that is deflated, e.g., $3,658 H- (1 + inflation rate)Ye"x or $3,658 + (1.042)3 = ($3,658
•*• 1.131) = $3,234; see line 99 and note rounding.
The operating earnings (line 100) are defined as net revenues (line_94) minus operating
'costs (line 95) minus pollution control operating costs (line 96). For Year 3 of the project:
Operating Earnings
Net revenues - operating costs
- pollution control operating costs
$22,524 - $2,312 - $0 = $20,212
J-16
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Line 101. earnings before interest and ODA (oil depletion allowance), subtracts
depreciation and amortization from operating earnings. For Year 3,
Earnings Before
Interest and ODA
$20,212- $3,234 = $16,978 (note rounding)
For major integrated producers; the depletion allowance is calculated on a cost basis, that
the leasehold cost is amortized over the productive life of the well:' -
Depletion
Allowance =
in "Year X"
Leasehold
Cost
Taken
Depletion
Allowance x
from "Year X" "
"Year X" Production
Total Production
For Year 3, the depletion allowance for the Gulf project is:
($11,952-0)* (1,095,000 bbl^ 13,875,110 bbl)
(Line 3)
$943 .
Depletion is calculated based on oil production only, unless the gas-only flag is set in line 65.
The figure of $943 must be deflated because the leasehold cost was spent in Year 0, but
the deduction is not taken until a later year. For Year 3, the adjusted depletion allowance (line
102) is calculated as: " '" ' : , ,
Adjusted
Depletion
Allowance
in "Year X'
(line 90)
Depletion Allowance
in "Year X" /(I + inflation rate)Year x
fJ-17
-------
For Year 3 in tfie project, the adjusted depletion allowance is:
$943 •=- (1.042)3
$834
The depletion allowance is calculated on an unadjusted basis for every year and then deflated. If
the project ends while a depletion allowance may still be taken, the depletion allowance in that
year and subsequent years is termed "surplus depletion" (line 116V
Earnings before interest and taxes (line 1041 is defined as the earnings before interest
and ODA (line 1011 minus the adjusted oil depletion allowance (line 102V For Year 3 of the
project, earnings before interest and taxes are $16,979 - $834 = $16,145.
The earnings in line 104 form the basis for Federal income tax. This is calculated in line
105 on the basis of information in line 9 (Federal tax rate). Earnings after taxes are given in line
106-
The project cash flows, line 107. are determined by adding non-cash expenses,
depreciation, and depletion to earnings after taxes. The net cash flow for Year 3 is $10,656 +
$3,233 + $834 = $14,723.
The cash flows forecasted for the project may or may not be sufficient to justify
continuation, of operations. In some circumstances, net cash flows may be positive only because
of large values for depreciation, e.g., where large capital expenditures are required on a small
project or later in the operating life of the project. Under these circumstances, the project is
likely-to shut down even though cash flow is positive. Project shutdown is evaluated by the
parameter
J-18
-------
Project shutdown
Net cash flow (Line 1071
- (tax rate * depreciation and amortization)
(line 9) (line 99^
- (1-tax rate) * (expensed pollution control
capital costs)
(line 96)
which calculates the actual cash outlay in that year. If the parameter is equal to or less than
zero, the project is assumed to shut down. The model prints a "1" in line 108 for years in which
the project operates and a "0" for years in which the project does not operate.
In the event that the project is shut down, certain variables must be recalculated to
reflect that decision. Lines 109 through 114 restate production volumes, revenues, and cash flow
in light of the shutdown; that is, production and revenues are set to zero after the project shuts
down. Other project variables, such as depreciation, are recalculated because of the earlier
shutdown date. Unexpended capitalized costs and surplus depreciation are given in lines 115 and
116.
income statement for the second and third decades of operation is found on lines
117 through 155 and 156 through 190. respectively.
J.2.6 Summary Statistics
At the end of the project, all costs and revenues are put in present value terms as of the
lease year; see lines 191 through 222. Two terms have not been discussed previously. Line 194.
expensed investment cash flows, is defined as the sum of the present values for expensed
exploration cash flows (line 19) and expensed delineation and development costs (lines 32 and
54) minus the present value of unexpended expensed investment costs. For the project, this is
$4,387 + $520 + $14,307 - 0 = $19,214 (note rounding). Line 195. capitalized costs, is the sum
of the present values of capitalized exploration costs (line 20) and capitalized delineation and
development costs (lines 34 and 55) minus the present value of unexpended capital costs. For
the project, this is $587 + $1,088 + $29,934 - $0 = $31,609 (note rounding).
J-19
-------
The present value of total company costs is the summation of the present values of the
parameters so listed in Table J-3; see line 204. This parameter provides a measure of the
present value of net company resources expended in development and operation of petroleum
projects. Entries marked with a "plus" in the column contribute to corporate costs. Excess
depreciation and surplus depletion lower corporate costs and are therefore marked with a
"minus."
Total company costs for oil are the present values for oil royalties and severance taxes
and the oil portion of the remaining costs (see line 205). These costs are apportioned by the
ratio of oil revenues to total revenues. An analogous procedure is followed to obtain the total
company cost for gas (see line 206).
The capital and the annual operation and maintenance costs for incremental pollution
control of produced water effluents are given in terms of present value and are annualized over
the economic lifetime of the well. The annualized cost is given in line 207.
Oil and gas production is also discounted to give present value equivalent (see lines 208
through 210). Corporate costs per barrel and corporate costs per Mcf are obtained by dividing
the present value of the company cost by the present value equivalent of production (see lines
211 through
The present value of social costs (lines 214 through 216) provides a measure of the value
of net social resources expended in the development and operation of offshore petroleum
projects. The difference between company cost and social cost is that the social cost ignores the
effects of transfers that do not use social resources. The items included in social cost are listed
in Table H-3. Social cost per unit of production is obtained by dividing the social cost by the
present value equivalent of production (lines 217 through 219).
The net present value of the project, line 220. is calculated as:
J-20
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-H
JJ
2
0
hold cost
xpenses
capitalized expl
0) (1) i-H
to re
re o jj
a) «a o
. H) O EH
+
CO
4J
W
O
o
g
•H
4J
RS
0)
a
capitalized deli
rH
m
4J
o
EH
+
to
CO
O
u
4J
8
1
rH
capitalized deve
rH
Rl
4J
^-
to
s
0
(H
CO
R)
O
i)
a
V)
expensed investm
o
5)
H-
to
capitalized cost
M-i
o
^1
+
•r "r H*
to
a
o
4-) Rl
re 4J
a) 'a,
Pi R)
O 0
i i
to
JJ
to
0
u
1-1
pollution contro
royalties
ii i it I
o o
> >
M4 Pi
+ +
H* + 'H~ I 1
§tn
4J
-H 0)
JJ O
severance taxes
operating costs
income taxes
excess depletion
surplus deprecia
all investment o
IM IIH tu IM IM IH
o o o o o o
£ Ei Us £ 5; 5;
present value.
n
ft
J-21
-------
Net Present =
Value
PV of Cash
Inflows
PV of Cash
Outflows
= PV of Operating Cash Rows
- PV of Expensed Investment Cash Flows
- PV of Capitalized Costs
- PV of Leasehold Costs
+ PV of Excess Depletion
+ PV of Surplus Depreciation
A positive net present value is indicative of a profitable project at the assumed discount rate, i.e.,
it generates more revenue than investing the capital in a project with that expected rate of
return.
The internal rate of return (line 221} equates the present value of capital in the
exploration and development of the project with the present value of the operating cash flows.
An internal rate of return higher than the discount rate is indicative of a profitable project.
The net present value and the internal rate of return are inverse methods of evaluating
the profitability of a project. In calculating the net present value, the discount rate is fixed and
the net present value may vary. In calculating the internal rate of return, the net present value is
set to zero and the discount rate is allowed to fluctuate.
J-22
-------
Run Date:
Project Type:
Lease Bid:
G&G Expense:
Leasehold Cost:
Real Discount Rate:
Inflation Rate:
Yrs Btwn Lease Sale & Strt of Exp:
Percent Costs Expensed:
Drilling Hud Cost Increment:
Corporate Tax Rate:
08-Feb-90
Gulf 12
OIL and GAS
$5,678
110.50SJ
$11,952
8.00X
4.20X
0
42.00%
$0
34X
1986 data
LINE
NO,
1
2
3
4
5
6
7
8
9
Cost Per Exploratory Well.:
Drilling Hud Cost Increment:
Discovery Efficiency:
Platforms per Successful Expl. Wei
EXPLORATION COSTS
$4,355
-$0
4.3
Explor. Costs Per Platform:
Cost of Successful Efforts:
Expensed Costs:
Expensed Cash Flows:
Capitalized Cash Flows:
PV of Expensed Exploration Cash Flows:
PV of Capitalized Expl. Cash Flows:
Total Capitalized Expl. Costs:
PV of all Exploratory Costs:
Year
0
$7,234
$1,013
$6,647
$4,387
$587
lows:
;:
Year Year
1
$0
so
$0
$0
$0
$4,387
$587
$587
$7,234
Year
2
$0
$0
SO
$0
$0
3
$0
$0
$0
$0
$0
10
11
12
13
14
15
16
17
18
19
20
21
22
DELINEATION COSTS
Years Between Start of Expl.
and Delineation:
Number of Delineation Wells
Drilled:
Cost per Delineation Well:
Drilling Hud Cost Increment:
Platforms Per Find:
Total Delineation Costs:
Tax Shield:
Expensed Cash Flow:
Capitalized Cash Flow:
1
2
$4,355
JO
4.3
Year Year Year Year
1234
$2,026
$289
$561
$1,175
$0
$0
£0
$0
$0
$0
$0
$0
SO
$0
$0
$0
23
24
25
26
27
28
29
30
31
J-23
-------
PV Expensed Cash Flow:
Total Capitalized Delineation Costs:
PV of Capitalized Delineation Costs
PV of all Delineation Costs:
Total Platform Cost:
Pollution Control Capital Costs:
Yrs btwn Delineation & Constn:
Hwber of Wells Drilled:
Nurber Uells Drilled Per Year:
Drilling Co«t Per Well:
Drilling Cost Per Well:
Drilling Hud Cost Increment:
Well Start:
Hurfoer of Uells Drilled:
Total Drilling Costs for Year:
Annual Platform Cost:
Annual Poll Cont Capital Costs:
Total Annual Capital Cost:
Tax Shield:
Expensed Cash Flovi:
Capitalized Cash Flow:
PV of All Construction Costs:
PV of Expensed Construction Costs:
PV of Capitalized Construction Costs:
FINANCIAL RATES
Percent Vater Cut in 04G to Start
Oil/Cat Prod. Decl. Rate/Year (X)
Coct Escalator (X):
Royalty Rate (X):
Federal Tax Rate (X):
Average Depreciation tife (years)
Deprec. rate (subs, years):
State Severance Tax Rate-Oil:
(If Alaska enter 99)
State Severance Tax Rate-Gas:
(If Alaska enter 99)
$520
ts: $1,175
tsc S1.08S
S1.876
CONSTRUCTION COSTS
$11,660
$0
0
10 ' •
6
$4,906
Year Year Year Year fsar . Year Year Year Year
12345 6 7 S 9
$4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906 $4,906
$0 SO $0 $0 $0 $0 $0 SO SO
01234 5678
06 4 0 0 0 0 0 0
SO $29,436 $19,624 $0 $0 $0 SO SO $0
$11,660 $0 $0 SO $0 $0 SO SO $0
$0 $0 $0 SO $0 $0 SO SO SO
$11,660 $29,436 $19,624 $0 $0 $0 $0 $0 SO
$1,665 $4,203 $2,802 $0 $0 $0 $0 SO $0
$3,232 $8,160 $5,440 SO $0 $0 SO SO SO
$6,763 $17,073 $11,382 $0 $0 $0 $0 $0 $0
$51,611
: $14,307
sts: $29,934
:: 10X
: 85X
OX
22X
34X
: 7
14.29JC 24.49X 17.49% 12.49X 8.93X 8.92X 8.93X 4.46X
6.19X
LINE
NO.
32
33
34
35
36
37
38
39
40
41
•'ear
10
$4,906 42
$0 43
9 44
0 45
$0 46
SO . 47
$0 48
SO 49
$0 50
SO 51
$0 52
53
54
55
56
57
58
59
60
61
62
63
6.19X
64
J-24
-------
Gas Only? <1=yes, 0=no):
Yrs Btwn Strt Dev & Strt Prod <<5)
Number of Years at Peak Prod (=>1)
Oil Peak Prod. Rate/Well(bb):
Gas Peak Prod. Rate/Wei I(MMCF/D):
No. of Producing Wells:
No. of Wells Put in Service/Year:
Price of Oil Per Barrel:
Price of Gas Per MCF:
Total Operating Costs <$000):
Poll Cont Oper Costs ($000):
Days of Production Per Year:
Producing Wells:
Barrels of Oil Per Day:
Days of Production Per Year:
Barrels of Oil Per Year:
Price/Barret of Oil:
MMCF of Gas Per Day:
HHCF of Gas Per Year:
Price/HCF of Gas:
Annual Oil Revenues ($000):
Annual Gas Revenues (SOOO):
Total Revenues ($000):
Royalty Payments-Oil ($000):
Royalty Payments-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev. Taxes-Oil:
ELF for Alaska Sev. Taxes-Gas:
Net Revenues ($000):
Total Operating Costs ($000):
Exp. Poll.Cont.Cap.Costs ($000):
Poll.Con.Operating Costs ($000):
Capitalized Costs (SOOO):
Adjstd Deprec I Amort ($000):
Operating Earnings ($000):
Earnings Before Interest and COA:
Adjstd Depletion (Cost Basis):
Surplus Depletion:
PRODUCTION
0
i 2
l 2
500
0.835
10
6
S23.82
$2.57
$2,312
$0
365
Year
3
COSTS
LINE
Ktn
65"
66
67
68
69
70
71
72
73
74
75
Year
4
Year
5
Year
6
Year
7
Year
8
Year
9
Year
10
Year
11
Year
12
76
OIL PRODUCTION
6
3000
365
1095000
$23.82
4
5000
365
1825000
$23.82
0
4550
365
1660750
$23.82
0
3868
365
1411638
$23.82
0
3287
365
1199892
$23.82
'2794
365
1019908
$23.82
2375
365
866922
$23.82
2019
365
736884
$23.82
1716
365
626351
$23.82
1459
365
532398
$23.82
77
78
79
80
81
GAS PRODUCTION
5
1829
$2.57
$26,083
$4,700
$30,783
$5,738
$1,034
$1,259
$227
0.25
-2.59
$22,524
$2,312
SO
$0
$25,598
$3,233
$20,212
$16,979
$834
en
8
3048
$2.57
$43,472
$7,833
$51,304
$9,564
$1,723
$2,099
$378
0.25
-2.59
$37,540
$2,312
$0
$0
$11.382
$6,697
$35.228
$28,531
$1,334
so
8
2773
$2.57
$39,559
$7,128
$46,487
$8,703
$1,568
$1,910
$344
0.19
-2.95
$34,162
$2,312
$0
$0
$0
$5,914
$31,850
$25,936
•$1,165
$0
6
2357
$2.57
$33,625
$6,059
$39,684
$7.398
$1,333
$1,623
$293
0.10
-3.64
$29,037
$2,312
$0
$0
$0
$4,053
$26,725
$22,672
$950
$0
5
2004
$2.57
$28,581
$5,150
$33,731
$6,288
$1,133
$1,380
$249
0.02
-4.46
$24,682
$2,312
$0
$0
$0
$2,780
$22,370
$19,590
$773
$0
5
1703
S2.57
$24,294
$4,377
$28,672
$5,345
$963
$1,173
$211
ERR
-5.43
$20,979
$2,312
$0
.$0
$0
$2,374
$18,667
$16,293
$632
$0
4
1448
$2.57
$20,650
$3,721
$24,371
$4,543
$819
$997
$180
ERR
-6.56
$17,833
$2,312
$0
$0
$0
$2,280
$15,521
$13,241
$516
$0
3
1231
$2.57
$17,553
$3,163
$20,715
$3,862
$696
$847
$153
ERR
-7.90
$15,158
$2,312
$0
$0
SO
$1,430
$12,846
$11,416
$421
$0
3
1046
$2.57
$14,920
$2,688
$17,608
$3,282
$591
$720
$130
ERR
-9.47
.$12,884
$2.312
*o
$0
$0
$323
$10,572
$10,249
$343
$0
2
889
$2.57
$12,682
$2,285
$14,967
$2,790
$503
$612
$110
ERR
-11.32
$10,951
$2,312
$0
$0
$0
$0
$8,639
$8,639
$280
• so
82
83
84
85
86
87
OO
88
Qf\
89
f\f\
90
O T
91
rto
92
flO
93
<"» A
94
95
Of
96
97
98
99
100
101
102
103
J-25
-------
Earnings Before Int and Taxes:
Statutory Tax:
Earnings Before Int After Tax:
Het Cash Flow:
Shutoff?
Actual OH Prod./Year (Barrels.):
Actual Gas Prod./Year (HMCF):
Actual Gross Revenues ($000):
Actual Het Revenues ($000):
Actual Het Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Costs Hot Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels OH Per Year:
Price Per Barrel:
HNCF Gas Per Day:
WCF Cas Per Year:
Price Per HCF:
Oil Revenues ($000):
C«s Revenues ($000):
Total Revenues ($000):
Royalty Payments-Oil ($000):
Royalty Payments-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev. Taxes-Oil.".
ELF for Alaska Sev. Taxes-Gass
Het RevenuesCSOOO):
Operating Costs:
Exp. Poll.Cont.Cap.Co«s ($000):
Pollution Control Operating Costs:
For PV Poll. Control:
Adjstd Deprec t AMort ($000):
Operating Earnings ($000):
Earnings Before Interest and OOA:
Adjstcd Depletion (Cost Basis):
Surplus Depletion:
Earnings Before Int and Taxes:
LINE
$16,145
$5,489
£10,656
$14,723
1
1095000
1829
$30,783
$22,524
$14,723
$5,489
$0
$0
Year
13
$27,197
$9,247
$17,950
$25,981
1
1825000
3048
$51 ,304
$37,540
$25,981
$9,247
$0
$0
Year
14
$24,771
$8,422
$16,349
$23,427
1
1660750
2773
$46,687
$34,162
$23,427
$8,422
$0
$0
Year ,
15
$21,722
$7,386
$14-,337
$19,340
1
1411638
2357
$39,684
$29,037
$19,340
$7,386
$0
$0
Year
16
$18,815
$6,397
$12,418
$15,973
1
1199892
2004
$33,731
$24,682
$15,973
$6,397
$0
$0
Year
17
$15,661
$5,325
$10,336
$13,343
1
1019908
1703
$28,672
$20.979
$13,343
$5,325
$0
$0
Year
18
$12,725
$4,327
$8,399
$11,194
1
866922
1448
$24,371
$17,833
$11,194
$4,327
$0
$0
Year
19
$10,995
$3,738
$7,257
$9,107
1
736884
1231
$20,715
$15,158
$9,107
$3,738
$0
SO
Year
20
$9,906
$3,368
$6,538
$7,204
1
626351
1046
$17,608
$12,884
$7,204
$3,368
$0
$0
Year
21
$8,360
$2,842
$5,517
S5.797
1
532398
889
$14,967
$10,951
$5,797
$2,842
$0
$0
Year
22
NO.
104
105
106
107
108
109
110
111
112
113
114
115
116
OIL PRODUCTION
1240
365
452539
$23.82
1054
365
384658
$23.82
896
365
326959
$23.82
761
365
277915
$23.82
647
365
236228
$23.82
550
365
200794
$23.82
468
365
170675
$23.82
397
365
145074
$23.82
338
365
123312
$23.82
287
365
104816
$23.82
117
118
119
120
CAS PRODUCTION
2
756
$2.57
$10,779
$1,942
$12,722
$2,371
$427
• $520
$94
ERR
-13.49
$9,309
2312
$0
i: $0
SO
$0
$6,997
; $6,997
$228
$0
$6,768
2
642
$2.57
$9,163
$1,651
$10,813
$2,016
$363
$442
$80
ERR
-16.05
$7,912
2312
$0
$0
$0
$0
$5,600
$5,600
$186
SO
$5,414
1
546
$2.57
$7,788
$1,403
$9,191
$1,713
$309
$376
$68
ERR
-19.05
$6,726
2312
SO
$0
SO
SO
$4,414
$4,414
$152
SO
$4,262
1
464
$2.57
$6,620
$1,193
$7,813
$1,456
S262
$320
$58
ERR
-22.59
$5,717
2312
SO
$0
SO
SO
$3,405
$3,405
$124
$0
$3,281
1
395
$2.57
$5,627
$1,014
$6,641
$1,238
$223
$272
$49
ERR
-26.76
$4,859
2312
$0
SO
SO
SO
$2,547
$2,547
$101
SO
$2,446
1
335
$2.57
$4.783
S862
$5,645
$1,052
$190
$231
$42
ERR
-31.65
$4,130
2312
SO
SO
SO
SO
$1,818
$1,818
$82
$0
$1,736
1
285
$2.57
$4,065
$733
$4,798
$894
$161
$196
$35
ERR
-37.42
$3,511
2312
' SO
SO
so
so
$1,199
$1,199
$67
$0
$1,131
1
24?.
$2.57
$3,456
$623
$4,078
$760
$137
$167
$30
ERR
-44.20
$2,984
2312
SO
SO
SO
$672
$672
$55
SO
$617
1
206
$2.57
$2,937
$529
$3,467
S646
$116
$142
$26
ERR
-52.17
$2,537
2312
$0
SO
SO
$225
S225
$45
$0
$180
0
175
$2.57
$2,497
$450
$2,947
$549
$99
$121
$22
ERR
-61.56
$2,156
2312
SO
SO
SO
($156)
($156)
$37
$37
($192)
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
J-26
-------
Statutory Tax:
Earnings Before Int After Tax:
•Net Cash Flow:
Shutoff?
Actual Oil Prod./Year (Barrels):
Actual Gas Prod./Year (HHCF):
Actual Gross Revenues ($000):
Actual Net Revenues ($000):
Actual Net Cash Flow ($000):
Actual Taxes Paid ($000):
Capitalized Costs Not Expended:
Surplus Depreciation:
Barrels Oil Per Day:
Days of Production Per Year:
Barrels Oil Per Year:
Price Per Barrel:
MMCF Gas Per Day:
HHCF Gas Per Year:
Price Per MCF:
Oil Revenues ($000):
Gas Revenues ($000):
Total Revenues ($000):
Royalty Payments-Oil ($000):
Royalty Paywsnts-Gas ($000):
Severance Taxes-Oil ($000):
Severance Taxes-Gas ($000):
ELF for Alaska Sev Taxes-Oil:
ELF for Alaska Sev Taxes-Gas:
Net Revenues($000):
Operating Costs:
Pollution Control Operating Costs
For PV Poll. Control:
Operating Earnings ($000):
•Earnings Before Interest and ODA:
Adjsted Depletion (Cost Basis):
Surplus Depletion:
Earnings Before Int and Taxes:
Statutory Tax:
Earnings Before Int After Tax:
$2,301
$4,467
$4,695
1
452539
756
$12,722
$9,309
$4,695
$2,301
$0
SO
$1,841
$3,573
$3,760
1
384658
642
$10,813
$7,912
$3,760
$1,841
SO
$0
$1,449
$2,813
$2,965
1'
326959
546
$9,191
$6,726
$2,965
$1,449
$0
$0
81,115
82,165
$2,289
1
277915
464
87,813
85,717
82,289
$1,115
$0
SO
$832
$1,614
$1,716
• 1 ,
236228
395
$6,641
$4,859
$1,716
$832
$0
$0
$590
$1,146
$1,228
1
200794
335
$5,645
$4,130
$1,228
$590
$0
$0
$385
S747
$814
1
170675
285
$4,798
$3,511
$814
$385
$0
$0
$210
S407
S462
1
145074
242
$4,078
$2,984
$462
$210
$0
$0
$61
$119
$163
1
123312
206
$3,467
$2,537
$163
$61
$0
$0
LINE
NO.
(565)144
($127)145
($91)146
0
0
0
$0
$0
so
so
$0
$0
147
148
149
150
151
152
153
154
155
Year Year Year Year Year Year Year Year Year Year
23
24
25
26
27
28
29
30
31
32
OIL PRODUCTION
244
365
89093
$23.82
207
365
75729
$23.82
176
365
64370
$23.82
150
365
54714
$23.82
127
365
46507
$23.82
108
365
39531
$23.82
92
365
, 33601
$23.82
78
365
28561
S23.82
67
365
24277
$23.82
57
365
20636
$23.82
156
157
158
159
GAS PRODUCTION
0
149
$2.57
$2,122
$382
$2,505
$467
$84
$102
$18
ERR
-72.60
$1,833
2312
: SO
SO
(S479)
($479)
$77
$77
($556)
($189)
($367)
0
126
S2.57
$1,804
$325
$2,129
$397
$72
S87
$16
ERR
•85.58
$1,558
2312
SO
SO
C$754)
($754)
$65
$65
($819)
($279)
($541)
0
107
S2.57
$1,533
$276
$1,810
$337
$61
$74
S13
ERR
-100.86
$1,324
2312
SO
SO
<$988)
(S988)
$55
$55
($1,043)
($355)
($689)
0
91
$2.57
$1,303
$235
$1,538
$287
$52
$63
$11
ERR
-118.84
$1,125
2312
SO
$0
($1,187)
($1,187)
$47
$47
($1,234)
($419)
($814)
0
78
$2.37
$1,108
$200
$1,307
$244
$44
$53
S10
ERR
-139.99
$937
2312
$0
SO
($1,355)
($1,355)
$40
$40
($1,395)
($474)
($921)
0
66
$2.57
$942
$170
$1.111
$207
$37
$45
$8
ERR
-164.87
$813
2312
SO
SO
($1,499)
($1,499)
$34
S34
($1,533)
($521)
($1,012)
0
56
$2.57
$800
$144
$945
$176
$32
$39
$7
ERR
-194.14
$691
2312
SO
SO
($1,621)
($1,621)
$29
$29
($1,650)
($561)
($1,089)
0
48
$2.57
$680
$123
$803
$150
$27
$33
$6
ERR
-228.57
$588
2312
SO
$0
($1.724)
($1.724)
$25
$25
($1,749)
($595)
($1.154)
0
41
$2.57
$578
$104
$682
$127
$23
S28
$5
ERR
-269.09
$499
2312
$0
$0
($1,813)
($1,813)
$21
$21
($1,834)
($623)
($1,210)
0
34
$2.57
$492
$89
$580
'$108
$19
$24
$4
ERR
-316.75
$424
2312
$0
$0
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
{$1,888)i76
($1,888)! 77
$18
$18
178
179
($1.905)180
($648)181
($1,258)182
J-27
-------
Met Cash Flow:
Shutoff?
Actual Oil Prod./Year (Barrels):
Actual Gas Prod./Year (HHCF>:
Actual Gross Revenues ($000):
Actual Het Revenues ($000):
Actual Het Cash Flow (MOO):
Actual Taxes Paid ($000):
PV of Het Revenues:
PV of Excess Depletion:
PV of Surplus Depreciation:
PV of Expensed Invest Cash Flows:
PV of Capitalized Costs:
PV of Leasehold Cost:
PV Poll. cent. Costs:
PV of Royalties - oil:
PV of Royalties - gas:
PV of Severance taxes - oil:
PV of Severance taxes - gas:
PV of Income Taxes Paid:
PV of Operating Costs:
Total Cocpany Costs:
Total Cowpany Costs - Oil:
Total Company Costs - Gas:
Annualized Poll.Coot.Costs:
($290)
• 0
0
0
SO
SO
SO
SO
$152,784
S30
SO
$19.213
$31,610
$11,952
SO
$38,923
$7,013
$8,542
$1,539
$37,393
$19,036
$175,192
$148,445
$26,747
$0
$476) ($633) ($767) ($881) ($978)
0000 0
0 00 0 0
0000 0
$0 $0 $0 $0 $0
$0 $0 $0 SO SO
$0 $0 $0 $0 $0
$0 $0 $0 $0 $0
191 pv Equiv. of Oil (bbt): 7,427,539
192 pv Equiv. of Gas (MMCF): 12,404
193 pv BOE 9,611,069
194 Amortized Company Cost per bbl:
195 Amortized Company Cost pep Hef :
196 Amortized Company Cost per BOE:
197
198 pv of Social Costs - Total: $86,031
199 pv of Social Costs - Oil: $72,896
200 pv of Social Costs - Gas: St3,135
201
202 Amortized Social Cost per bbl:
203 Amortized Social Cost per Hcf :
Amortized Social Cost per BOE:
204
205 Net Present Value of Project:
206 internal Rate of Return:
207 NO. of Years of Production: 19
($1,060) ($1,130)
0 0
0 0
0 0
$0 $0
SO $0
$0 SO
$0 $0
$19.99
$2.16
$18.23
$9.81
$1.06
$8.95
$33,610
0.201
LINE
NOo
($1,189) ($1,240) 183
0 0 184
0 0 185
0 0 186
$0 SO 187
$0 $0 188
SO so 189
$0 $0 190
208
209
210
211
. 212
213
214
215
216
217
218
' 219
220
221
222
J-28
-------