United States Solid Waste and EPA530-R-99-032
Environmental Protection Emergency Response NTIS: PB99-156 135
Agency (5305W) January 1998
Background Documents
for the Cost and
Economic Impact
Analysis of Listing Four
Petroleum Refining
Wastes as Hazardous
under RCRA Subtitle C
Printed on paper that contains at least 30 percent postconsumer fiber
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BACKGROUND DOCUMENTS
FOR THE
COST AND ECONOMIC IMPACT ANALYSIS
OF LISTING FOUR PETROLEUM REFINING WASTES
AS HAZARDOUS UNDER RCRA SUBTITLE C
Prepared for:
Office of Solid Waste
Economics, Methods and Risk Assessment Division
U.S. Environmental Protection Agency
Washington, D.C. 20460
Prepared by:
DPRA Incorporated
E-1500 First National Bank Building
332 Minnesota Street
St. Paul, Minnesota 55101
(612) 227-6500
January 10, 1998
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DOCUMENT 1
COST AND ECONOMIC IMPACT ANALYSIS
OF LISTING HAZARDOUS WASTES
FROM THE
PETROLEUM REFINING INDUSTRY
September 21, 1995
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INDEX
Document 1 "Cost and Economic Impact Analysis of Listing Hazardous Wastes from the
Petroleum Refining Industry," September 21, 1995.
Document 2 "'Other Benefits' from Recovery of Oil in Coker Processing Units,"
memorandum, August 24, 1995.
Document 3 "Impacts of SBREFA and Unfunded Mandates on the Proposed Petroleum
Refining Hazardous Waste Listing," memorandum, March 31, 1997.
Document 4 "Cost Impact Analysis of the Definition of Solid Waste Headworks Exemption
for the Proposed Listings of Three Petroleum Refining Industry Wastes," April
9, 1997.
Document 5 "Cost Impact Analysis of the Coking Exemption on Crude Oil Tank Sludge and
Clarified Slurry Oil Sludge Compliance Costs from Listing as a RCRA
Hazardous Waste," January 10, 1998.
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September 21, 1995
Mr. Andrew Wittner
U.S. Environmental Protection Agency
Office of Solid Waste, Regulatory Analysis Branch
Room S-256
401 M Street, S.W.
Washington, D.C. 20460
RE: Contract No. 68-W3-0008
Work Assignment No. 208
Revised Draft Final Report, Cost and Economic Impact Analysis of Listing Hazardous
Wastes from the Petroleum Refining Industry
Dear Andy:
Enclosed please find three copies (two bound and one unbound) of the revised Draft Final
Report for the Cost and Economic Impact Analysis of Listing Hazardous Wastes from the
Petroleum Refining Industry. The report incorporates the revised methodology for estimating
additional waste quantities and the corresponding revisions to the cost estimates.
Please do not hesitate to call me at (612) 227-6500 if you have any questions or need
additional assistance.
Sincerely,
/
Dave Gustafson
Associate Engineer
Enclosure
cc: Bill Moody,- ICF
DPRA project file
200 Researcn Orve D0 Box 111 Vannanan. Kansas 66502 ';;8Dnone 913-539-3565 '** 9'3-539-5353 '^ex/"0*3"
Otherotiices: :nanot:e. 3ailas. jsnver. Milwaunee. 5:. ?3i:i. .Vasmnqior,
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DRAFT FINAL REPORT
COST AND ECONOMIC IMPACT ANALYSIS
OF LISTING HAZARDOUS WASTES
FROM THE
PETROLEUM REFINING INDUSTRY
Prepared for:
Office of Solid Waste
Regulatory Analysis Branch
U.S. Environmental Protection Agency
Washington, D.C. 20460
Prepared by:
DPRA Incorporated
E-1500 First National Bank Building
332 Minnesota Street
St. Paul, Minnesota 55101
(612) 227-6500
September 21, 1995
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ACKNOWLEDGEMENT
This report was prepared by DPRA Incorporated (DPRA) under Contract No. 68-W3-0008
for the Regulatory Analysis Branch, Office of Solid Waste, U.S. Environmental Protection
Agency. The EPA Work Assignment Managers were Andrew Wittner and Yvette Hopkins.
The study team included Chris Lough, David Gustafson, Carol Sarnat, Carolyn Petersen,
Mary Blel, Shirley Smith, and Thomas Myers. We also would like to acknowledge Gwen di
Pietro, Kristy Allman, and John Vierow of SAIC for their expertise in waste generation and
management practices.
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TABLE OF CONTENTS
Page
EXECUTIVE SUMMARY ES-1
1. INTRODUCTION 1-1
1. Purpose 1-2
2. Scope of Study 1-2
3. Organization of Report 1-3
2. INDUSTRY PROFILE 2-1
1. Overview of Products and Processes 2-1
1. General Product Descriptions 2-1
2. General Process Descriptions 2-2
2. Profile of Affected Facilities 2-5
1. Refinery Capacity and Utilization 2-17,
2. Large and Small Refineries . 2-17
3. Refinery Complexity . 2-17
3. Market Structure . , 2-21
1. Market Concentration 2-21
2. Industry Concentration 2-23
4. Market Supply Characteristics ' 2-23
1. Past and Present Production 2-25
2. Supply Determinations 2-25
3. Exports of Petroleum Products 2-25
5. Market Demand Characteristics 2-28
1. Demand Determinants 2-28
2. Past and Present Consumption 2-28
3. Product Pricing 2-30
4. Imports of Refined Petroleum Products 2-30
6. Industry Trends and Market Outlook 2-32
1. Environmental Regulations 2-32
2. Demand Outlook 2-32
3. Supply Outlook (Production and Capacity) 2-34
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LIST OF TABLES
Table ES.l Summary of Cost of Compliance
Table ES.2 Summary of Economic Impacts
Table 1.1 Newly Listed Hazardous Wastes
Table 2.1 List of Refineries Affected by the Listing Determination
Table 2.2 Refinery Capacity and Utilization, 1984-1993
Table 2.3 List of Small Entities
Table 2.4 Companies with 200,000 b/cd or Greater of Crude Capacity .
Table 2.5 Major Refineries and Crude Capacity
Table 2.6 Petroleum Products Supplied to the U.S. Market by Type
Table 2.7 Exports and Domestic Refinery Production
Table 2.8 Petroleum Products Supplied to the U.S. Market by Type
Table 2.9 Prices of Petroleum Products to End Users
Table 2.10 Imports and Domestic Consumption of Refined Petroleum Products
Table 3.1 Total Waste Quantities by Waste Stream Listing
Table 3.2 Reported and Adjusted 1992 RCRA 3007 Survey Quantities
Table 3.3 Listing Determination Annualized Generation and Final
Management Quantities
Table 3.4 Summary of Baseline and Listing Compliance Waste Management
Practices for the Petroleum Refining Industry
Table 3.5 Summary of Baseline and LDR Compliance Waste Management
Practices for the Petroleum Refining Industry
Table 3.6 Summary of Baseline and Contingent Management Compliance Waste
Management Practices for the Petroleum Refining Industry
Table 3.7 Derivation of Incremental Compliance Costs
Table 3.8 Summary of Baseline Management Unit Costs
Table 3.9 Summary of Compliance Management Unit Costs and Cost Equations
Table 3.10 Summary of Baseline/Compliance Transportation Unit Costs for the
Petroleum Refining Industry
Table 3.11 RCRA Administrative Costs
Table 3.12 Annualized Costs for the Petroleum Refining Hazardous Waste
Listings - Listing and LDR Scenarios
Table 3.13 Annualized Costs for the Petroleum Refining Hazardous Waste
Listings - Contingent Management Scenario
Table 4.1 Baseline 1992 Domestic Production and Price
Table 4.2 Baseline Inputs for the Petroleum Refining Industry
Table 4.3 Summary of Economic Impacts
age
ES-7
ES-8
1-3
2-6
2-18
2-19
2-22
2-24
2-26
2-27
2-29
2-31
2-33
3-12-
3^14
3-15
3-21
3-26
3-28
3-34
3-37
3-43
3-59
3-64
3-76
3-77
4-6
4-7
4-9
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age
LIST OF FIGURES
Figure 3.1 Typical Petroleum Refining Process Flow Diagram 3-3
Figure 3.2 Fluid Catalytic Cracking 3-4
Figure 3.3 Hydrotreating/Hydrorefining 3-5
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EXECUTIVE SUMMARY
Pursuant to the provisions of the Hazardous and Solid Waste Amendments of 1984 (HSWA),
the Environmental Protection Agency (EPA) is listing, as hazardous wastes, certain waste
streams generated by the petroleum refining industry. This action is expected to require
changes in the current waste management practices of firms within this industry and thereby
compel them to incur additional costs associated to comply with EPA's hazardous waste
regulations. This report assesses the likely changes in waste management practices brought
on by this waste listings determination and analyzes the costs and economic impacts
associated with these changes at the facility level. This Cost and Economic Impact Analysis
was possible at the facility-specific level because substantial plant-specific data were available
from EPA's 1992 RCRA Section 3007 Survey responses and engineering site visits.
Executive Order No. 12866 requires that regulatory agencies determine whether a new
regulation constitutes a significant regulatory action. A significant regulatory action is
defined as an action likely to result in a rule that may:
Have an annual effect on the economy of $100 million or more or adversely
affect in a material way the economy, a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or state, local, or
tribal governments or communities;
Create a serious inconsistency or otherwise interfere with an action taken or
planned by another agency;
Materially alter the budgetary impact of entitlements, grants, user fees, or loan
programs or the rights and obligations of recipients thereof; or
Raise novel legal or policy issues arising out of legal mandates, the President's
priorities, or the principles set forth in Executive Order 12866.
EPA estimated the costs and potential economic impacts of this listing of petroleum refining
wastes to determine if it is a significant regulatory action as defined by the Executive Order.
ES.l Cost Impacts
This listing has determined that four petroleum refining residuals (crude oil sludges, clarified
slurry oil (CSO) sludges, hydrotreating catalysts, and hydrorefming catalysts) are hazardous
wastes and subject to RCRA Subtitle C regulation. These four petroleum refining wastes are
currently being generated and managed in non-RCRA Subtitle C management units at 162
refineries which are owned and operated by 80 companies. The quantity of waste at the
point of generation ranges from 91,600 to 177,900 metric tons per year, with an expected
ES-1
-------
value of approximately 134,800 metric tons per year. Approximately 36 percent of this
expected affected quantity was reported by the industry in the 1992 RCRA 3007 Survey.
The remaining 64 percent was added by EPA as estimates for non-reported quantities.
Three scenarios are evaluated in this Cost and Economic Impact Analysis. The first
scenario, Listing Scenario, assesses the costs incurred by the petroleum refining industry to
comply with Subtitle C regulation excluding Land Disposal Restriction (LDR) regulations.
The Listing Scenario assumes an end disposal management of Subtitle C landfilling or
continued combustion of wastes, where indicated as the baseline management practice, in a
Subtitle C incinerator/BIF. The second scenario, LDR Scenario, expands on the Listing
Scenario by adding in cost impacts attributable to LDR regulations. Two options are
assessed for the LDR Scenario. In Option 1, the upper bound estimate, the oil-based sludges
are combusted in off-site Subtitle C incinerators and the metal catalysts are combusted in off-
site incinerators followed by vitrification and Subtitle C landfill of the ash. In Option 2, the
lower bound estimate, oil-based sludges are assumed to be managed in on-site Subtitle C
incinerators for those refineries generating sufficient quantities and are currently in the
RCRA permitting program (thereby, avoiding potential corrective action costs). Metal
catalysts are assumed to be regenerated/reclaimed in RCRA-exempt off-site metal recovery
units. The third scenario, Contingent Management Scenario, expands on the LDR Scenario,
Option 2, by allowing contingent management for the oil-based sludges in Subtitle D units.
Contingent management means that the wastes will no longer be regulated as hazardous if
they are placed in these Subtitle D units. The wastes are still subject to Subtitle C storage
and transportation requirements prior to placement in these units. Two options are assessed
for the Contingent Management Scenario. In Option 1, CSO sludges are contingently
managed in either Subtitle D land treatment units with run-on/run-off controls or Subtitle D
landfills. Crude oil sludges are managed in on-/off-site Subtitle C incinerators and metal
catalysts are regenerated/reclaimed in off-site metal recovery units. In Option 2, crude oil
tank sludges also are contingently managed in Subtitle D land treatment units with run-
on/run-off controls. The compliance management practices for the other waste streams are
the same as in Option 1.
The total incremental cost of the listings under the Listing Scenario, on a before-tax basis, is
estimated to be between $4 and $16 million per year with an expected value of $8 million
per year.
The total incremental cost of the listings under the LDR Scenario is estimated to range from
$21 to $101 million per year. The expected value is $41 million per year. This expected
value represents incineration management of the two oil-based sludges on site when it is
economically feasible and off-site reclamation/regeneration of the two metal catalysts.
The total incremental cost of the listings under the Contingent Management Scenario is
estimated to range from $3 to $42 million per year. If contingent management regulations
are promulgated for CSO sludges alone the expected value is $24 million per year. If
contingent management regulations are promulgated for both crude oil tank sludges and CSO
ES-2
-------
sludges the expected value is $6 million per year. Results of the cost impact analysis are
summarized in Table ES.l.
All of the above cost estimates under each scenario reflect implementation of a waste
minimization opportunity for filtering "oily" crude oil tank sludges and CSO sludges and
recycling the oil filtrate back into process units. Revenues from the recycled oil are
estimated at $1.3 million per year.
The petroleum refining industry is expected to incur no corrective action costs as a result of
the listings determination. The RCRA Corrective Action Program is triggered when a
facility seeks a RCRA Part B permit. EPA assumes that unpermitted facilities will avoid
potential corrective action costs by shipping wastes off site for management and thereby no
constructing and permitting new waste management units. EPA estimates that two
unpermitted facilities generate sufficient waste to economically construct an on-site
incinerator if they choose. Potential corrective action costs range from $0 to $7.2 million
per year with a cost of zero representing the expected value.
ES.2 Industry Profile
The entities affected by this listings determination are classified in SIC 2911, Petroleum
Refining. As of January 1, 1995, there are 173 refineries owned/operated by 84 companies -
in the United States. Based on data obtained from the 1992 RCRA 3007 Survey, 162
refineries owned/operated by 80 companies generate wastes affected by this listings
determination. Companies that operate petroleum refineries are characterized as vertically
integrated if they own and operate segments responsible for both exploration and production
of crude oil and for marketing the finished petroleum products after refining occurs. The
crude capacity of the major, vertically integrated companies in the petroleum refining
industry represented 69 percent of nationwide production in 1994. The Small Business
Administration defines petroleum companies with crude'capacity less than or equal to 75,000
barrels per calendar day (b/cd) as a small entity. Based on this cutoff, 45 of the 80
companies affected by this listings determination, or 56 percent, are considered small
entities.
ES.3 Economic Impacts
Partial equilibrium analysis is used to evaluate economic impacts of the listings on the
petroleum refining industry in an effort to specify market demand and supply, estimate the
post-control shift in market supply, predict the change in market equilibrium (price and
quantity), and estimate plant closures. Petroleum refineries produce several hundred
products. The economic impacts analysis evaluates the impact of the listings based on ten
petroleum products (i.e., ethane/ethylene, butane/butylene, normal butane/butylene,
isobutane/isobutylene, finished motor gasoline, jet fuel, distillate and residual fuel oil,
asphalt, and petroleum coke), which represents 91 percent of domestically refined petroleum
products in 1992. Because compliance costs for the hazardous waste listings cannot be
ES-3
-------
allocated to any specific products, output in the partial equilibrium model is defined as a
composite, bundled good equal to the sum of price multiplied by the weighted production
volumes of all ten products.
A bounding analysis was conducted to evaluate the potential economic impacts of this listings
determination. The Listing Scenario, lower bound option, assumes an end disposal
management method of Subtitle C landfilling or continued combustion of wastes, where
indicated as the baseline management practice, in a Subtitle C incinerator/BIF. The LDR
Scenario management assumptions and quantity estimates for the crude oil tank sludge and
CSO tank sludge used in the economic impact analysis differ from the cost impact analysis
assumptions due to late revisions in the designation of LDR management practices and
quantity estimation methodology. The total before-tax incremental costs for the LDR
management assumptions described below range from $16 to $70 million compared to the
range of $21 million to $101 million presented in the cost impact analysis. The LDR
Scenario, upper bound option, assumes a pretreatment management method of solidification
prior to Subtitle C landfill for metal-based wastes and combustion in a Subtitle C
incinerator/BIF for organic-based wastes. The lower bound LDR Scenario, assumes a
pretreatment management method of solidification prior to Subtitle C landfill for metal-based
wastes and combustion in a Subtitle C incinerator/BIF for organic-based wastes for those
refineries generating sufficient quantities to warrant on-site incineration. This regulatory
option represents the most cost-effective option for compliance with the listings and LDRs. ,
The results of the economic impacts analysis are summarized in Table ES.2.
Predicted price increases and reductions in domestic output are less than 1 percent for the ten
products evaluated under both the Listing and LDR compliance scenarios. Projected price
increase for the ten products combined range from 0.03 to 0.76 percent under the low and
high cost scenarios, respectively. Under the low and high cost scenarios, production is
expected to decrease ranging from 1.3 to 30.9 million barrels per year, representing a 0.02
to 0.59 percent decrease in annual production, respectively. The value of shipments or
revenues for domestic producers are expected to increase for the ten products combined
ranging from $9.0 to $213 million annually for the low and high cost scenarios, respectively.
This revenue increase results given that the percent increase in price exceeds the percent
decrease in quantity for goods with inelastic demand. The model estimates that up to two
refineries may close as a result of the predicted decrease in production, under both regulatory
scenarios. Those refineries with the highest per unit control costs are assumed to be
marginal in the post-control market. No significant regional impacts are anticipated from
implementation of the listings since only up to two facilities are anticipated to close and
impacts overall are estimated to be minimal.
Under the low and high cost scenarios, the number of workers employed by firms in SIC
2911 are estimated to decrease ranging from 12 to 282 workers annually, representing a 0.03
and 0.59 percent decrease in total employment, respectively. The small magnitude of
predicted job loss directly results from the relatively small decrease in production anticipated
and the relatively low labor intensity in the industry. An estimated decrease in energy use
ES-4
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ranging from $1.02 to $24.32 million annually is expected for the industry, under the low
and high cost scenarios, respectively. As production decreases, the amount of energy input
utilized by the refining industry also declines. The change in energy use does not consider
the increased energy use associated with operating and maintaining the regulatory control
equipment due to the lack of available data. Finally, imposition of the listings will further
increase the negative balance of trade. Under the low and high cost scenarios, net exports
are anticipated to decline ranging from 0.2 to 4.7 million barrels annually, representing a 0.1
and 2.8 percent decline, respectively. The dollar value of the total decline in net exports
ranges from $6.35 to $152.6 million ($1992) annually. Given the magnitude of the estimated
compliance costs, refineries are expected to incur minimal economic impacts.
Economic impacts may be over-estimated as a result of the following model assumptions:
the model assumes that all refineries compete in a national market. In reality,
some refineries are protected from market fluctuations by regional or local trade
barriers and may therefore be less likely to close;
the total cost of compliance is assigned exclusively to ten petroleum products,
rather than the entire product slate for each refinery;
some refineries may find it profitable to expand production in the post-control
market. This would occur when a firm found its post-control incremental unit cost to
be smaller than the post-control market price. Expansion by these firms would result
in a smaller decrease in output and increase in price than otherwise would occur;
the economic analysis was based on the listing of five waste streams including
unleaded gasoline sludge, which has since been removed from the list of wastes
included in this listing determination. Compliance costs associated with unleaded
gasoline sludge represent 11 to 14 percent of the total compliance cost used in the
evaluation of economic impacts under the lower and upper bound scenarios,
respectively. As a result, economic impacts for the 98 facilities generating unleaded
gasoline sludge will be overestimated;
the regulatory options used to evaluate economic impacts differ slightly from those
that were used to calculate the cost of compliance. This difference does not affect the
total cost of compliance for the Listing Scenario or the lower bound LDR Scenario,
but does have an impact on the upper bound LDR Scenario, such that costs were
understated by $8 million. As a result, economic impacts may be underestimated for
the upper bound LDR Scenario; and
ES-5
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the economic analysis was based on a lower estimate for crude oil tank sludge
quantities, each having 9,000 MT/yr managed in final management practices. These
quantities were revised to 14,600 and 13,100 MT/yr, respectively. As a result,
impacts for facilities generating these sludges are understated for all scenarios
presented in Table ES.2.
ES.4 Regulatory Flexibility Analysis
The Regulatory Flexibility Act of 1980 (RFA) requires agencies to assess the effect of
regulations on small entities and to examine regulatory alternatives to alleviate any adverse
economic effects on this group. Section 603 of the RFA requires an Initial Regulatory
Flexibility Analysis (IRFA) to be performed to determine whether small entities will be
affected by the regulation. If affected small entities are identified, regulatory alternatives
that mitigate the potential impacts must be considered.
For SIC 2911, Petroleum Refining, the Small Business Administration defines small entities
as those companies with refinery capacity less than or equal to 75,000 barrels of crude per
calendar day. Based on this criterion, approximately 56% or 45 of the 80 companies
affected by the listing determination are considered to be small.
Even under the highest cost scenario, the estimated impacts of the listing determination are
minimal. Predicted price increases and reductions in domestic output are less than 1 percent
for the ten products evaluated. The small magnitude of predicted job loss directly results
from the relatively small decrease in production anticipated and the relatively low labor
intensity in the industry.
Under the Agency's Revised Guidelines for Implementing the Regulatory Flexibility Act, the
Agency is committed to considering regulatory alternatives in rulemakings when there are
any estimated economic impacts on small entities. Despite the high percentage of small
entities in the population of refineries affected by the listing determination, anticipated
impacts as a result of implementation of the listing are minimal, with only up to two plant
closures predicted under each of the scenarios evaluated. Because economic impacts are
estimated to be minimal, no small entity exemptions or options were judged to be necessary
in an effort to reduce economic impacts on small entities.
ES-6
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TABLE ES.l
Summary of Cost of Compliance
($ millions per year)1
Waste Stream
Crude Oil Tank Sludge
Clarified Slurry Oil
Sludge
Hydrotreating Catalyst
Hydrorefming Catalyst
RCRA Administrative
Costs
TOTAL
Listing Scenario
Subtitle C Landfill of
Sludges and Catalysts
2.2
11.0-3.91
2.8
[1.4-4.8]
1.3
(0.8 -2.9]
1.5
[0.7 - 3.8]
0.5
[0.4 - 0.6]
8.3
[4.3 - 16.0]
LDR Scenario
Option 1
Off-Site Incineration of
Sludges and Off-Site
Incineration and
Vitrification of
Catalysts
21.6
[9.3 -38.8]
22.5
[11.2-37.6]
5.0
13.5-7.61
11.6
[8.3 - 16.5)
0.5
[0.4 - 0.7)
61.3
[32.7 - 101.2]
LDR Scenario
Option 2
On-/Off-Site
Incineration of
Sludges and
Regen./Reclam. of
Catalysts
16.7
[8.1 -28.3]
16.8
[9.4 - 26.5[
2.3
[1.2-4.5]
3.9
[1.9 -7.9]
0.8
[0.6 - 1.0]
40.6
[21.3 -68.3[
Contingent Management
Scenario
Option 1
Subtitle D Landfill and
Land Treatment (w/
contr.) of CSO Sludges,
On-/Off-Site Incineration
of Crude Oil Sludges and
Regen./Reclam. of
Catalysts
17.5
[8.5 - 29.8]
(0.5)
[(0.3) - (0.8)]
2.3
(1.2-4.5]
3.9
[1.9-7.91
0.6
[0.5 -0.8]
23.8
[11.8 -42.2|
Contingent Management
Scenario
Option 2 ,
Subtitle D Landfill and
Land Treatment (w/
contr.) of CSO Sludges,
Sub. D Land Treatment
(w/ contr.) of Crude Oil
Sludges and
Regen./Reclam. of
Catalysts
(0.5)
1(0.2) -(1.0)]
(0.5)
1(0.3) - (0.8)|
2.3
[1.2-4.51
3.9
[1.9 -7.9|
0.5
|0.3 -0.6|
5.6
|3.1 - 11.2]
1 Costs are presented as the average cost followed by the range of costs from low to high in brackets. Parentheses indicate negative values, credits.
ES-7
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TABLE ES.2
Summary of Economic Impacts
Economic
Impacts
Listing Scenario
Lower Bound1
LDR Scenario
Lower Bound2
LDR Scenario
Upper Bound3
PRIMARY ECONOMIC IMPACTS4
Average Price Increase
Over All Products
Annual Production Decrease
Amount (MMbbl)
Percentage Change
Annual Value of Shipments
Amount (MMS92)
Percentage Change
Number of Plant Closures
0.03%
(1.3)
(0.03%)
$9.0
0.01%
0-2
0.08%
(3.27)
(0.06%)
$22.59
0.02%
0-2
0.76%
(30.93)
(0.59%)
$213.34
0.16%
0-2
SECONDARY ECONOMIC IMPACTS3
Annual Job Loss
Number
Percentage Change
Annual Decrease In Energy Use
Amount (MMS92)
Percentage Change
Annual Net Foreign Trade Loss
Amount (MMbbl)
Percentage Change
Dollar Value ($/MMbbl)
(12)
(0.03%)
($1.02)
(0.03%)
(0.20)
(0.12%)
($6.35)
(30)
(0.06%)
($2.57)
(0.06%)
(0.49)
(0.3%)
($15.96)
(282)
(0.59%)
($24.32)
(0.59%)
(4.70)
(2.8%)
($152.60)
1 assumes an end disposal management method of Subtitle C landfilling or continued combustion of wastes, where
indicated as the baseline management practice in a Subtitle C incinerator/BIF.
2 .assumes a pretreatment management method of solidification prior to Subtitle C landfill for metal-based wastes
and combustion in an on-site Subtitle C incinerator/BIF for organic-based wastes for those refineries generating
sufficient quantities to warrant on-site incineration.
3 assumes a pretreatment management method of solidification prior to Subtitle C landfill for metal-based wastes
and combustion in an off-site Subtitle C incinerator/BIF for organic-based wastes.
4 brackets indicate decreases or negative values.
ES-8
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1. INTRODUCTION
This report presents a cost and economic impact analysis corresponding to the listings
determination for four additional hazardous wastes from the petroleum refining industry by
the U.S. Environmental Protection Agency (EPA). These waste listings are pursuant to the
Hazardous and Solid Waste Amendments of 1984 (HSWA) and a proposed consent decree
between the Environmental Defense Fund (EDF) and EPA in which EPA agreed to
promulgate a final listing determination for petroleum refining wastes on or before October
31, 1996 (EDF v. EPA, DC DC, No.89-0598, 6/18/91). The expected effects of this
listings determination involve increased costs for treatment and disposal of newly listed
hazardous wastes and capital investment expenditures to manage and reduce these wastes
compared to current management practices by most firms in the affected industries.
Executive Order No. 12866 (FR V. 58 No. 170, 51735, October 4, 1993) requires that
regulatory agencies determine whether a new regulation constitutes a significant regulatory
action. A significant regulatory action is defined as an action likely to result in a rule that
may:
Have an annual effect on the economy of $100 million or more or adversely
affect in a material way the economy, a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or state, local, or-
tribal governments or communities;
Create a serious inconsistency or otherwise interfere with an action taken or
planned by another agency;
Materially alter the budgetary impact of entitlements, grants, user fees, or loan
programs or the rights and obligations of recipients thereof; or
Raise novel legal or policy issues arising out of legal mandates, the President's
priorities, or the principles set forth in Executive Order 12866.
EPA estimated the costs and potential economic impacts of the listings determination of
petroleum refining wastes to determine if it is a significant regulatory action as defined by
the Executive Order.
The Regulatory Flexibility Act of 1980 requires federal agencies to assess the effects of
regulations on small entities and to examine regulatory alternatives that may bring about any
adverse effects on these small entities. EPA conducted a regulatory flexibility screening
analysis. The results of this analysis are presented in Chapter 4.
1-1
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1.1 Purpose
Four additional waste streams, referenced as K169 through K172, are being listed as
hazardous in the petroleum refining industry. This report presents the cost and economic
impact analysis that was performed for these waste listings.
This analysis estimates how facilities in the petroleum refining industry may be economically
impacted by the regulation, as well as how the aggregate industry may be affected. Best
estimates of the cost effects of the listings were determined and then compared to the value
of production on both a facility-specific and industry-wide basis.
1.2 Scope of Study
The scope of the study involves the petroleum refining industry, for which hazardous waste
listings under Part 261 of RCRA are being promulgated. This industry produces petroleum
products made from petroleum crude oil and natural gas. Petroleum products made from
crude oil include still gas, liquified gas, motor gasoline, aviation gasoline, jet fuel, kerosene,
special naphtha, petrochemical feeds, distillates, lubricants, waxes, coke, asphalt/road oil,
residuals, and other miscellaneous products.
A total of 172 of the 173 petroleum refining facilities submitted 1992 RCRA 3007 Surveys
on their petroleum refining products manufactured on site, manufacturing and waste
management practices, and other supporting information. Of the 172 facilities that responded
to the survey, one facility is closed, and nine do not generate the listed wastes or manage
them in non-exempt waste management units. This study addresses the cost of compliance
and economic impacts for the 162 facilities affected by the listings determination.
A total of two sludges and two spent catalysts waste streams are currently being listed as
hazardous wastes. The wastes are briefly described in the following table (see Chapter 3 for
further details).
1-2
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TABLE 1.1. NEWLY LISTED HAZARDOUS WASTES
WASTE STREAM
K169
K170
K171
K172
NEWLY LISTED HAZARDOUS WASTE
Crude oil storage tank sludge
Clarified slurry oil sludge from catalytic cracking
Catalyst from catalytic hydrotreating
Catalyst from catalytic hydrorefming
1.3 Organization of the Report
The remainder of this report is divided into three main chapters. Chapter 2 presents an
economic profile for the petroleum refining industry. For this industry, available economic
profile data are developed including products manufactured, number and location of facilities,
production capacity and utilization, market structure and industry concentration, supply and
demand conditions, and industry trends and market outlook.
Chapter 3 profiles the hazardous waste streams to be listed, their generation rates, and
current and alternative compliance hazardous waste management practices. Unit costs and
prices for the current and alternative compliance hazardous waste management practices are
presented in this chapter as well as a summary of the regulatory costs.
Chapter 4 documents the economic impacts of the hazardous waste listings determination.
1-3
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2.0 INDUSTRY PROFILE
This section presents a profile of the petroleum refining industry, which is the subject of this
listings determination. Refining is the process which converts crude oil into useful fuels and
other products for consumers and industrial users. All affected facilities are classified under
SIC 2911, Petroleum Refining.
Sections 2.1 and 2.2 present an overview of industry products and processes and the
population of affected facilities, respectively. The petroleum refining market structure
including market supply, demand characteristics, and industry trends are described in
Sections 2.3 through 2.6.
2.1 Overview of Products and Processes1
2.1.1 General Product Descriptions
Petroleum products are made from petroleum crude oil and natural gas. Synthetic products,
while similar, differ in that they are made from other raw materials such as coal, peat,
lignite, shale oil and tar sands. The principal classes of products made from crude oil
include still gas, liquified gas, motor gasoline, aviation gasoline, jet fuel, kerosene, special
naphtha, petrochemical feeds, distillates, lubricants, waxes, coke, asphalt/road oil, residuals,
and miscellaneous.
Three major classes of petroleum products include fuels, building materials, and chemicals.
Fuels include gases, liquids, and semisolids. Common fuel uses include burning in furnaces
to produce heat, aspirating into internal combustion engines to supply mechanical power, and
injecting into jet engines to create thrust. Building materials made from petroleum products
include petroleum asphalt used for roofing and road coverings, petroleum waxes used for
waterproofing, and plastics, elastomers, and other resins used for various construction
purposes. Chemicals derived from petroleum, often referred to as petrochemicals, have
numerous uses including adhesives, cleaners, drugs, fungicides, inks, paints, and solvents.2
The economic analysis for this listings determination is based on the evaluation of ten
primary petroleum products including motor gasoline, jet fuel, distillate fuel, residual fuel,
liquified petroleum gases (4), asphalt, and petroleum coke. Based on 1992 production data
1 Process information in this section is from "OSW Listing Determination for the Petroleum Refining Industry,
Waste Characterization Part HI", Science Applications International Corporation, September 15, 1994.
2 Petroleum Processing Handbook, Chapter 1, "Petroleum Products," by Harold L. Hoffman, 1992.
2-1
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reported in the RCRAr3007 Survey, these products account for approximately 91 percent of
domestically refined petroleum products.3
Motor gasoline is defined as a complex mixture of relatively volatile hydrocarbons that has
been blended to form a fuel suitable for use in spark-ignition engines. Motor gasoline
includes reformulated gasoline, oxygenated gasoline, and other finished gasoline. Jet fuel is
a low freezing distillate of the kerosene type used primarily for turbojet and turboprop
aircraft engines. Distillate fuel oil is a general classification for one of the petroleum
fractions produced in conventional distillation operations. It is used primarily for space
heating, on-and-off-highway diesel engine fuel, and electric power generation. Residual fuel
oil is a heavy oil that remains after the distillate fuel oils and lighter hydrocarbons (e.g.,
ethane/ethylene, propane/propylene) are distilled away in refinery operations. Primary uses
include commercial and industrial heating, electricity generation, and to power ships.
Liquified petroleum gases (LPG) include ethane/ ethylene, propane/propylene, normal
butane/butylene, and isobutane/isobutylene. Asphalt includes crude asphalt as well as other
finished products including cements, fluxes, emulsions, and petroleum distillates blended with
asphalt to make cutback asphalts. Petroleum coke is a residue, the final product of the
condensation process in cracking. Marketable coke includes those grades of coke produced
in delayed or fluid cokers, which may be recovered as relatively pure carbon.
2.1.2 General Process Descriptions
The refining process transforms crude oil into a wide range of petroleum products which
have a variety of applications. Refined products include liquified petroleum gases such as
ethane/ethylene, propane/propylene, normal butane/butylene, and isobutane; finished motor
gasoline, unleaded and leaded; finished aviation gasoline; jet fuel; distillate fuel oil; residual
fuel oil; special naphthas; lubricants; waxes; asphalt and road oil; coke; petrochemical
feedstocks; sulfur; and hydrogen. The output of each refinery is a function of its crude oil
feedstock and its preferred petroleum product slate. These products are produced using the
processes described in the following -subsections.
Catalytic Cracking
Cracking is the process in which long-chained hydrocarbon oil molecules are decomposed
(broken-down) into shorter-chained hydrocarbons, low-boiling molecules. Catalytic cracking
breaks heavy gas oils and residual oils into simpler and lighter hydrocarbons using high heat
and catalyst to promote the decomposition reactions. It is an effective process for increasing
the yield of products ranging from naphtha to reduced crude oil. The silica alumina catalyst
used in this process has a small particle size and moves through the reactor as a fluid and is
commonly called fluid catalytic cracking. Coke (i.e., solid carbon) forms on the catalyst
? RCRA 3007 Survey and U.S. Department of Energy, Energy Information Administration, Petroleum Supply
Annual 1993, DOE/EIA-0340(93)/1.
2-2
-------
causing it to lose its reactivity and become spent. Metals such as vanadium and nickel fron.
the crude oil also deposit on the catalyst, reducing activity. The catalyst is continuously sent
to a regenerator where the coke is burned off and the catalyst is recycled to the catalytic
reactor. To control metal formation on the catalyst and maintain reactivity, catalyst is
continuously withdrawn from the regenerator and replaced with fresh catalyst. Catalyst fines
also become entrained in the flue gas and can be removed in an electrostatic precipitator or a
wet gas scrubber or can be sent to a stack (depending on air permits). Clarified slurry from
residual oils also may be stored temporarily in tanks. Relatively infrequently (every 10 to 20
years), these storage tanks require sludge removal due to maintenance, inspection, or sludge
buildup. Clarified slurry oil sludges which may be generated during this process are not
limited to "tank sludges." For this residual, sludges are generated from tank storage and,
more rarely, filtration prior to tank storage.
Catalytic Hydrotreating and HydroreFming
Catalytic hydrotreating and hydrorefining are used to improve the quality of a process feed
stream. These processes remove sulfur from a process feed stream by converting
mercaptans4 to a carbon-based structure and hydrogen sulfide gas, which is fractionated.
These processes may also remove nitrogen, asphaltene, and metal contaminates. The catalyst
used in these processes is typically cobalt or nickel and molybdenum or alumina. Catalyst
lifetime is approximately 1 to 5 years, after which the catalyst is replaced. Catalyst activity -
losses occur because of poisons from the crude, coke deposits, and structural breakdown
from severe operating conditions in the hydrotreating and hydrorefining processes.
Catalytic Reforming
Catalytic reforming increases the octane of gasoline by dehydrogenation5 and molecular
rearrangement of naphthas. This process uses a precious metal catalyst. Fixed bed
reforming is semi-regenerative and cyclic and generates a relatively large quantity of catalyst
on an infrequent basis. Continuous reforming generates a relatively small quantity of catalyst
on a continuous basis.
Thermal Processes
A thermal process is any refining process that utilizes heat without the aid of a catalyst. In
the delayed coking process, residuum is heated to the point of cracking and is charged to a
coke drum. In the coke drum, the residuum cracks, forming a wide range of products and
coke (a solid hydrocarbon residue poor in hydrogen). The gaseous products are recovered in
a fractionator and the coke deposits are recovered in a drum. Once the drum is full, the
4 Mercaptan is the common name for a thiol, which is a chemical functional group containing sulfur.
Dehydrogenation is the removal of hydrogen from a chemical compound.
2-3
-------
coke is hydraulically drilled out and dropped to a concrete pad. Delayed coking is the most
common thermal process. Other types of thermal processes include fluid coking,
visbreaking,- Dubbs units, and thermal cracking. The drilling process produces coke fines
that are entrained in the decoking water. This water is filtered to remove the fines and is
recycled to a decoking water surge drum. The fines are typically placed on the coke pile.
Liquid Treating
Caustic treating removes impurities such as mercaptans and naphthalenes from light
hydrocarbons (e.g., kerosene and lighter hydrocarbon products). A slip stream of caustic is
continuously removed from this process. All spent caustics are corrosive. Caustic
regeneration is sometimes used in this process.
Sulfur Complex and H?S Removal
Sulfur-containing compounds are removed as hydrogen sulfide (H2S) gas at many points in
the refinery and are sent to an H2S removal system where the gas is contacted with an
aqueous amine in an absorption column. The sulfur laden amine is routed to a desorber
where it is heated, causing the H2S gas to come out of solution. The H2S is then sent for
sulfur recovery. The sulfur-free amine solution is returned to the absorption column. A slip
stream of sulfur-free amine from the desorber is filtered to remove any corrosion products. -
The filters are changed monthly. The Claus Unit is the most common unit used for the
production of sulfur from hydrogen sulfide. It converts H2S into elemental sulfur through the
use of heat and an alumina catalyst. Sulfur dioxide in the off-gas (i.e., tail gas) is further
converted to H2S and sour water using another catalyst. The H2S is recycled to the Claus
unit. Sulfur production uses an alumina catalyst, which is changed every two to three years.
H-.SQ, Alkylarion
Alkylation is the formation of complex saturated6 molecules by the combination of a
saturated and an unsaturated molecule. Olefin7 and isobutane gases are contacted over
concentrated sulfuric acid (H2SO4) catalyst to synthesize alkylates for octane boosting in
motor and aviation fuels. The reaction products are separated by distillation and are
scrubbed with caustic (see Liquid Treating). A portion of the acid catalyst is continuously
bled and replaced with a fresh acid to maintain reactor concentrations around 90 percent.
Sludge is generated in a neutralization pit. Sludge may also be generated in process line
junction boxes, in the spent H2SO4 holding tank, and during turnarounds.
A saturated hydrocarbon contains no double or triple bonds.
7 An olefin is an open-chain hydrocarbon having one or more double bonds per molecule.
2-4
-------
HF Alkvlatrorr
Olefin and isobutane gases are also contacted over concentrated hydrofluoric (HF) acid
catalyst to synthesize alkylates for octane boosting in motor and aviation fuel. The reaction
products are separated by distillation and are scrubbed with caustic. The volume and type of
sludge generated are dependent on the types of influents to the neutralization pit [e.g., acid
soluble oil (ASO), and potassium hydroxide scrubber water from air pollution control
equipment] and the type of neutralizing agent used (e.g., sodium, calcium, or potassium
ions). Neutralizing controls fluoride levels to the wastewater treatment plant. Some
facilities discharge acid soluble oil to their HF neutralization pit, where it becomes part of
the HF sludge.
Storage
Nearly all refineries store feed and products in tanks. Relatively infrequently (every 10 to 20
years), tanks require sludge removal due to maintenance, inspection, or sludge buildup.
Crude oil tank sludge consists of heavy hydrocarbons, basic sediment and water, and
entrapped oil that settles to the bottom of the tank. When removed, the oil is recovered
while the solids are collected and discarded as a waste. Unleaded gasoline tank sludge
consists of tank scale and rust. A typical cleaning procedure is to wash the tank with water
(to decrease benzene levels for occupational health safety reasons), send the water to the
sewer, and sweep or scrape the remaining solids for drumming and disposal. Sometimes
there are no solids.
2.2 Profile of Affected Facilities
This section describes the products and processes of the refining industry and identifies the
companies and refineries that generate the four wastestreams associated with this listings
determination.
The 1992 Petroleum Supply Annual, reports the number of operable refineries as of January
1, 1993 at 187, of which 175 were operating and 12 were idle. In support of these listings,
the 1992 RCRA 3007 Survey was submitted to 173 petroleum refining facilities to obtain
information on manufacturing and waste management practices and quantities of petroleum
refining products manufactured. Of the 173 facilities surveyed, one facility did not respond,
one facility is closed, and nine do not generate wastes included in this listings determination.
The 162 facilities that generated wastes included in this listings determination are
owned/operated by 80 companies. A summary of refineries (by company) affected by this
listings determination and their 1992 capacity from the RCRA 3007 Survey is presented in
Table 2.1.
2-5
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
PLANT
STATE
CRUDE
CAPACITY
(Mb/sd)
AGE REFINING, INC.
Age Refining, Inc.
TX
5
AMERADA HESS CORPORATION
Port Reading Refining Facility
Hess Oil Virgin Island Corp.
NJ
VI
54
545
AMOCO CORPORATION
Amoco Oil Co.- Mandan Refinery
Salt Lake City
Amoco Yorktown Refinery
Amoco Whiting Refinery
Texas City Refinery
ND
UT
VA
IN
TX
60
40
56
440
440
ANCHOR GASOLINE
Canal Refinery
LA
12
ASHLAND OIL, INC.
Ashland Petroleum Refinery No.4
Ashland Pet. Catlettsburg Refinery
St. Paul Park Refinery
OH
KY
MN
66
245
67
ASPHALT MATERIALS, INC.
Laketon Refining Corporation
Calumet Lubricants Company
IN
LA
9.5
6.5
ATLANTIC RICHFIELD COMPANY
Cherry Point Refinery
WA
190
2-6
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
Arco Los Angeles Refinery
PLANT
STATE
CA
CRUDE
CAPACITY
(Mb/sd)
242
BARRETT REFINING CORPORATION
Barrett Refining Corp.
OK
10.5
BHP PETROLEUM AMERICAS, INC.
BHP Petroleum Americas Refining, Inc.
HI
95
BP EXPLORATION & OIL, INC.
Toledo Refinery
Lima Refinery
BP Oil Co. Ferndale Refinery
Alliance Refinery
Marcus Hook Refinery
OH
OH
WA
LA
PA
130
155
95
228.5
186
CHEMOIL REFINING CORPORATION
Chemoil
CA
16
CHEVRON CORPORATION
Pascagoula Refinery
Hawaii Refinery
El Segundo Refinery
Richmond Refinery
Richmond Beach Asphalt Refinery
Salt Lake Refinery
Philadelphia Refinery
Chevron El Paso Refinery
Willbridge Asphalt Refinery
MS
HI
CA
CA
WA
UT
PA
TX
OR
291
58
263
240
5
49
180
194
15
2-7
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
Port Arthur Refinery
PLANT
STATE
TX
CRUDE
CAPACITY
(Mb/sd)
194
GITGO PETROLEUM CORPORATION
Citgo Corpus Christ! Refinery
TX
140
CLARK REFINING & MARKETING CORP.
Clark Refining & Marketing Corp.
IL
70.7
THE COASTAL CORPORATION
Coastal Eagle Point Oil Refinery
Coastal Refining - Augusta
Coastal Refining & Marketing - Wichita
Coastal Refining & Marketing Inc.
NJ
KS
KS
TX
125
20.8
27
79
COUNTRYMARK COOPERATIVE, INC.
Countymark Cooperative, Inc.
IN
22.6
CROSS OIL & REFINING CO., INC.
Cross Oil & Refining Co., Inc.
AR
7
CROWN CENTRAL PETROLEUM CORP
Crown Central Petroleum Corp
La Gloria Oil and Gas Company
TX
TX
105
60
CRYSEN CORPORATION
Crysen Refining, Inc
Sound Refining, Inc
UT
WA
9.5
11.1
DIAMOND SHAMROCK, INC.
Three Rivers Refinery
McKee Plants
TX
TX
57
120
2-8
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
PLANT
STATE
CRUDE
CAPACITY
(Mb/sd)
E.I. DUPONT DE NEMOURS & CO (CONOCO)
Billings Refinery
Lake Charles Refinery
Denver Refinery
Ponca City Refinery
MT
LA
CO
OK
52
179
42.7
138.1
ERGON, INC.
Ergon Refining, Inc.
MS
12
EXXON CORPORATION
Exxon Co USA Billings Refinery
Baton Rouge Refinery
Exxon Baytown Refinery
Benicia Refinery
MT
LA
TX
CA
44
438
418
132
FARMERS UNION CENTRAL EXCHANGE
Cenex, Laurel Refinery
MT
42.5
FARMLAND INDUSTRIES
Coffeyville Refinery
KS
62
FTNA OIL & CHEMICAL COMPANY
Port Arthur
Big Spring
TX
TX
134.7
60
FIRST OIL INTERNATIONAL
Caribbean Petroleum Corp. Inc.
PR
40.4
FLYING J INC.
Flying J
UT
14
2-9
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
PLANT
STATE
CRUDE
CAPACITY
(Mb/sd)
FRONTIER OIL CORPORATION
Frontier Cheyenne Refinery
WY
38.9
GARY-WILLIAMS ENERGY CORP.
Bloomfield Refining Co.
NM
20
GENERAL PARTNER-CASTLE ENERGY CORP.
Indian Refining Limited Partnership
IL
69
GIANT INDUSTRIES, INC.
Ciniza Refinery
NM
20.8
GOLD LINE REFINING, LTD.
Gold Line Refining
LA
11.4
HOLLY CORPORATION
Artesia Refinery
NM
34
HORSHAM CORPORATION
Clark Hartford Refinery
IL
61.2
HO WELL CORPORATION
Howell Hydrocarbons & Chemicals, Inc.
TX
1.9
HUNT CAPITAL CORPORATION
Tuscaloosa Refinery
AL
44
HUNTWAY PARTNERS, L.P.
Huntway Refining Company
Huntway Refining Company
Sunbelt Refining Company
CA
CA
AZ
5.5
8.4
8.5
KERR MCGEE REFINING CORPORATION
2-10
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
Kerr McGee Wynnewood Refinery
Cotton Valley Facility
Southwestern Refining Company
Bakersfield
PLANT
STATE
OK
LA
TX
CA
CRUDE
CAPACITY
(Mb/sd)
45
8.5
104
23
KOCH INDUSTRIES, INC.
Koch Refining Company
Koch Refining Company
MN
TX
255
135
LION OIL COMPANY
Lion Oil Refinery
AR
50
LOUISIANA LAND & EXPLORATION, INC.
LL&E Petroleum - Mobile Refinery
AL
74
LYONDELL-CTTGO REFINING CO. LTD
Lyondell-Citgo Refining Co. Ltd
TX
283
MAPCO PETROLEUM, INC.
Mapco Alaska Petroleum, Inc., North Pole Refinery
Mapco Petroleum, Inc.
AK
TN
118
78.
MOBIL CORPORATION
Torrance Refinery
Mobil Paulsboro Refinery
Beaumont Refinery
Mobil Chalmette Refinery
Joliet Refinery
CA
NJ
TX
LA
IL
135.4
110.1
275
167
173.7
MURPHY OIL CORPORATION
2-11
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
*
Meraux Refinery
Superior Refinery
PLANT
STATE
LA
WI
CRUDE
CAPACITY
(Mb/sd)
100
35
NATIONAL COOP. REF. ASSOC.
McPherson Refinery
KS
80
NAVAJO NORTHERN, INC.
Montana Refining Company
MT
7.2
PACIFIC REFINING COMPANY
Pacific Refining Company
CA
52.1
PARAMOUNT PETROLEUM CORPORATION
Paramount Petroleum Corporation
CA
46.5
PENNZOIL COMPANY
Atlas Processing Company
Pennzoil Products Co., Roosevelt Refinery
Rouseville
LA
UT
PA
41.
8
16.5
PETROLEOS DE VENEZUELA, S.A. (PDVSA)
Citgo Lake Charles Refinery
LA
320
PETRO SOURCE REFINING PARTNERS
Eagle Springs
NV
6.1
PHILLIPS PETROLEUM COMPANY
Sweeny Refinery & Petrochemical Complex
Phillips 66 Co. , Borger Complex
Phillips 66 Co., Woods Cross Refinery
Phillips Puerto Rico Corp, Inc.
TX
TX
UT
PR
. 190
111
26
44.1
2-12
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
PLANT
STATE
CRUDE
CAPACITY
(Mb/sd)
PLACID REFINING COMPANY
Placid Refining Company
LA
48.5
PRIDE COMPANIES, L.P.
Pride Refining, Inc.
TX
45
QUAKER STATE CORPORATION
Congo Refinery
WV
12
SAN JOAQUTN REFINING COMPANY
San Joaquin Refining Company (SIR)
CA
21
SAUDI REFINING, INC. (STAR ENTERPRISE)
Star Enterprise Delaware City Refinery
Port Arthur Plant
Louisiana Plant
DE
TX
LA
152
246.8
242
SHELL OIL COMPANY
Deer Park Manufacturing Complex
Shell Oil Co., Norco Refinery
Odessa Refinery
Anacortes Refinery
Wood River Manufacturing Complex
Martinez Manufacturing Complex
TX
LA
TX
WA
IL
CA
225
215
29.5
94.2
286
130
SINCLAIR OIL CORPORATION
Sinclair, Wyoming Refinery
Tulsa Refinery
Little America Refining Company
WY
OK
WY
54
62
24.5
2-13
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
PLANT
STATE
CRUDE
CAPACITY
(Mb/sd)
SOLOMON, INC (PHIBRO ENERGY USA, INC.)
Houston Refinery
Krotz Springs
Texas City Refinery
TX
LA
TX
71
70
139.8
SOMERSET OEL, INC.
The Somerset Refinery, Inc.
KY
5.5
SOUTHLAND OIL CO.
Southland-Lumberton Refinery
Rogerslacy - Sandersville
MS
MS
5
10
SUN COMPANY, INC.
Sun Company, Inc.
Yabucoa Refinery
Toledo Refinery
Sun Philadelphia Refinery
Sun Co., Inc. (R&M) - Tulsa Refinery
PA
PR
OH
PA
OK
157.1
85
125
130
90
TENBY, INC.
Tenby, Inc.
CA
4
TESORO PETROLEUM CORPORATION
Tesoro Alaska Petroleum Co. - Kenai Refinery
AK
80
TEXACO,TNC
Eldorado Plant
Texaco Refining and Marketing - Areas 1 and 2
Los Angeles Plant
KS
CA
CA
88.3
49.5
95
2-14
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
Texaco Puget Sound Plant
PLANT
STATE
WA
CRUDE
CAPACITY
(Mb/sd)
134
TOSCO CORPORATION
Bayway Refinery
Avon Refinery
NJ
CA
200
160
TOTAL PETROLEUM, INC.
Ardmore Refinery
Alma Refinery
Colorado Refining Company
Arkansas City Refinery .
OK
MI
CO
KS
70
44.8
28 -
60
TRANSWORLD OIL, USA, INC.
Calcasieu Refining Co.
LA
13.5
U.S. OIL & REFINING CO
U.S. Oil & Refining Co.
WA
37
ULTRAMAR CORPORATION
Wilmington Refinery
CA
71
UNO- VEN COMPANY
UNO- YEN Refinery
IL
153
UNOCAL
LA Refinery, Wilmington Plant
Santa Maria Refinery
San Francisco Refinery
CA
CA
CA
65
44.4
77
USX (MARATHON OIL COMPANY)
Marathon Oil Co. , Texas Refining Division
TX
74
2-15
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TABLE 2.1
List of Refineries Affected by the Listing Determination
PARENT COMPANY/PLANT NAME
Illinois Refining Division - Robinson Refinery
Indiana Refining Division
Louisiana Refinery Division (Garyville)
Marathon Oil Co. , Michigan Refining Division
PLANT
STATE
IL
IN
LA
MI
CRUDE
CAPACITY
(Mb/sd)
175
52
263
75.9
VALERO ENERGY CORPORATION
Valero Refinery Co.
TX
28
WTTCO CORPORATION
Kendall Refining Co.
Golden Bear Products
PA
CA
10
10
WORLD OIL CORPORATION
Lunday-Thagard
CA
2.3
YOUNG REFINING CORP.
Young Refining Corp.
GA
2.6
Mb/sd = thousand barrels of crude oil per stream day
2-16
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2.2.1 Jiefinery Capacity and Utilization
Refinery capacity is the characteristic most often used to measure petroleum production and
output. In recent years, refining capacity has been falling even though product demand has
been rising. Trade industry reports indicate that marginally profitable refineries found new
environmental compliance requirements prohibitively costly, and capacity was reduced.8 As
demand increases, the need for additional refining capacity will intensify.
Table 2.2 presents refinery capacity and utilization for the period 1984 through 1993. These
data indicate that operable capacity has remained relatively constant over the past 10 years,
while capacity utilization has been increasing. This suggests that existing refineries are
operating closer to full capacity and will have limited opportunity to enhance production by
increasing utilization. In 1995, refining capacity is expected to decease slightly to 15.13
millions of barrels per calendar day (MMb/cd) from 15.14 MMb/cd in 1994, which will
further increase the utilization rate from 92.6 percent in 1994 to 93.3 percent in 1995.9
2.2.2 Large and Small Refineries
The Small Business Administration defines petroleum companies with crude capacity less
than or equal to 75,000 barrels per calendar day (b/cd) as a small entity. Capacity data
reported in barrels per stream day (b/sd) was converted to barrels per calendar day (b/cd) ,
using the conversion factor 0.95, for the purpose of determining small entities. Based on
this cutoff, 45 of the 80 companies affected by this listings determination, or 56 percent, are
considered small entities. Table 2.3 presents a listing of companies with reported capacity
less than or equal to 75,000 b/cd (or 78,947 b/sd).10
2.2.3 Refinery Complexity
Complexity is a measure of the different processes used in refineries. More complex
refineries have process units such as cracking, alkylation, reforming, isomerization,
hydrotreating and lubricant processing, which produce a wide range of products including
gasolines, low-sulfur fuel oils, lubricants, petrochemicals, and petrochemical feedstocks.
The level of complexity generally correlates to the types of products the refinery is capable
of producing. Higher complexity denotes a greater ability to enhance or diversify product
output, to improve yields of preferred products, and to process lower quality crude oil. In
theory, more complex refineries are more adaptable to change and are therefore potentially
less affected by regulation relative to less complex facilities.
8 Robert J. Beck, "Economic Growth, Low Prices to Lift U.S. Oil And Gas Demand In 1995," Oil & Gas
Journal. Vol.93, No.5, January 30, 1995, pp.51-68.
9 ibid.
10 Capacity data obtained from the 1992 RCRA 3007 Survey.
2-17
-------
TABLE 2.2
Refinery Capacity and Utilization, 1984-1993"
Year
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Number
of
Refineries
247
223
216
219
213
204
205
202
199
187
Capacity
(MMb/cd)
16.14
15.66
15.46
15.57
15.92
15.65
15.57
15.68
15.70
15.12
Gross Input
to Distillation
Units
(MMb/cd)
12.22
12.17
12.83
13.00
13.45
13.65
13.61
13.51
13.60
13.86
Utilization
(percent)
76.2
77.6
82.9
83.1
84.7
86.6
87.1
88.0
87.9
91.4
Notes:
MMb/cd = Million barrels of crude oil per calendar day
Utilization is derived by averaging reported monthly utilization.
11 U.S. Department of Energy, Energy Information Administration, Annual Energy Review 1993, Table 5.9
Refinery Capacity and Utilization, 1949-1993.
2-18
-------
TABLE 2.3
List of Small Entities
Parent Company
Age Refining, Inc.
Anchor Gasoline
Asphalt Materials, Inc.
Barrett Refining Corp.
Chemoil
Clark Refining & Marketing Corp.
Country mark Cooperative, Inc.
Cross Oil & Refining Co., Inc.
Crysen Corporation
Ergon, Inc.
Farmers Union Central Exchange
Farmland Industries
First Oil International
Flying J Inc.
Frontier Oil Corporation
Gary-Williams Energy Corp.
General Partner-Castle Energy Corp.
Giant Industries, Inc.
Gold Line Refining, Ltd.
Holly Corporation
Horsham Corporation
Howell Corporation
Hunt Capital Corporation
Number of
Refineries
1
1
2
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Total Crude
Capacity
(Mb/sd)
5.0
12.0
16.0
10.5
16.0
70.7
22.6
7.0
20.6
12.0
42.5
62.0
40.4
14.0
38.9
20.0
69.0
20.8
11.4
34.0
61.2
1.9
44.0
2-19
-------
TABLE 2.3
List of Small Entities
Parent Company
Huntway Partners, L.P.
Lion Oil Company
Louisiana Land & Exploration, Inc.
Navajo Northern, Inc.
Pacific Refining Company
Paramount Petroleum Corporation
Pennzoil Company
Petro Source Refining Partners
Placid Refining Company
Pride Companies, L.P.
Quaker State Corporation
San Joaquin Refining Company
Somerset Oil, Inc.
Southland Oil Co.
Tenby, Inc.
Transworld Oil, USA, Inc.
U.S. Oil and Refining Co.
Ultramar Corporation
Valero Energy Corporation
Witco Corporation
World Oil Corporation
Young Refining Corp.
Number of
Refineries
3
1
1
.1
1
1
3
1
1
1
1
1
1
2
1
1
1
1
1
2
1
1
Total Crude
Capacity
(Mb/sd)
22.4
50.0
74.0
7.2
52.1
46.5
65.5
6.1
48.5
45.0
12.0
21.0
5.5
15.0
4.0
13.5
37.0
71.0
28.0
20.0
2.3
2.6
Mb/sd = thousand barrels of crude oil per stream day
2-20
-------
2.3 Market Structure
This section describes the petroleum market and industry concentration. Data are presented
on the largest petroleum refining companies and their market share.
The U.S. petroleum product supply, demand and logistics system is a complex set of
facilities that supply petroleum products to meet regional demands. The markets for refined
petroleum products vary by geographic location. Regional markets may differ due to the
quality of crude supplied or the local product demand. Some smaller refineries that produce
only one product have single, local markets, while larger, more complex refineries have
extensive distribution systems and sell their output in several different regional markets.
In addition to differences in regional markets, each of the ten product categories in this
analysis possesses its own individual market segment, satisfying demand among different
end-use sectors. Each of the ten products, in and of themselves, are homogenous by nature.
As a result, product differentiation does not play a major role in the competitiveness among
refineries. However, if for example, the production of one refined product were to become
less costly after regulation, production of this product may increase at the expense of a
product with a more costly refining process.
2.3.1 Market Concentration
Market concentration is a measure of the output of the largest firms in the industry,
expressed as a percentage of total national output. A market concentration of 100 percent
would indicate monopoly control of the industry by one firm. Conversely, a concentration of
one percent would indicate the industry was comprised of numerous small firms.
Table 2.4 shows U.S. refining companies with more than 200,000 b/cd crude capacity as of
December 1994. Historically, the top four refining companies have comprised over 30
percent of the market share; however, market concentration ratios have been declining in
recent years. Based on reported total U.S. crude capacity of 15.3 MMb/cd for 1994, the top
four companies comprise 26 percent of the market share. Chevron Corporation remains the
largest U.S. refiner with 1.02 MMb/cd crude capacity, followed by Amoco Oil Co. and
Exxon Co. USA with 0.998 MMb/cd and 0.992 MMb/cd crude capacity, respectively. Shell
Oil Co. represents the fourth largest refiner with 0.964 MMb/cd crude capacity.
2-21
-------
TABLE 2.4
Companies With 200,000 b/cd or Greater of Crude Capacity
12
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Company
Chevron Corporation
Amoco Corporation
Exxon Corporation
Shell Oil Company
Mobil Corporation
BP Exploration & Oil, Inc.
Sun Company, Inc.
Saudi Refining, Inc. (Star Enterprise)
USX (Marathon Oil Company)
Citgo Petroleum Corporation
Atlantic Richfield Company
Tosco Corporation
E.I. DuPont De Nemours & Co. (Conoco)
Koch Industries, Inc.
Texaco, Inc.
Ashland Oil, Inc.
Phillips Petroleum Company
Clark Refining & Marketing Corp.
Solomon, Inc. (Phibro Energy USA, Inc.)
Lyondell-Citgo Refining Co. Ltd.
The Coastal Corporation
Unocal
Mapco Petroleum, Inc.
Fina Oil & Chemical Company
Total
Number of
Refineries
9
5
4
6
5
4
5
3
5
4
4
3
4
2
4
3
3
3
4
1
3
2
2
2
90
Crude Capacity
(Mb/cd)
1,021
998
992
964
900
705
687
600
579
545
450
437
435
420
393
347
311
309
283
265
235
222
220
220
12,536
Mb/cd = thousand barrels of crude oil per calendar day.
12 Anne K. Rhodes, "World Crude Capacity, Conversion Capability Inch Upward," Oil & Gas Journal.
Vol.92, No.51, December 19, 1994, pp.45-52.
2-22
-------
U.S. refineries number 173, with a total reported crude capacity of 15,319 Mb/cd as of
January 1, 1995.13 In the past year, the number of companies with crude capacity of
200,000 b/cd or greater increased from 22 to 24 and the number of refineries increased from
87 to 90. These 90 refineries have a total crude capacity of 12.5 MMb/cd, representing 82
percent of the total domestic crude capacity. The number of companies with a crude
capacity of less than 200,000 b/cd decreased from 84 to 71 in the past year. The number of
refineries associated with these companies also declined from 91 to 83. These 83 refineries
have a total crude capacity of 2.78 MMb/cd, representing 18 percent of the total domestic
crude capacity.
2.3.2 Industry Concentration
Vertical integration exists when the same firm supplies input for several stages of the
production and marketing process. Firms that are responsible for the exploration and
production of crude oil as well as for marketing the finished petroleum products are
vertically integrated. Within the petroleum refining industry, firms are classified as major or
independent. Generally, major firms are vertically integrated.
The Department of Energy (DOE) defines major refiners as "companies with a total refinery
capacity in the U.S. and its possessions of greater than or equal to 275,000 barrels per day
as of January 1, 1982".14 DOE's current list of major refiners are presented in Table 2.5. -
The crude capacity of the major, vertically integrated firms represents approximately 69 .
percent of total domestic crude capacity.
Horizontal integration refers to the operation of multiple refineries. As shown in Table 2.4,
the major oil companies operate several refineries, which are often distributed around the
country. Chevron operates nine domestic refineries, the largest number of refineries
operated by a major oil company. Together, the major refiners operate 74 of the 173
operating refineries, representing 43 percent of the total number of refineries.
2.4 Market Supply Characteristics
This section summarizes the factors affecting the supply side of the petroleum refining
industry. Historical production data are presented as well as discussions regarding supply
determinates and the role of exports.
13 ibid.
14 U.S. Department of Energy, Energy Information Administration, Petroleum Marketing Annual 1993,
DOE/EIA-0487(93).
2-23
-------
TABLE 2.5
Major Refineries and Crude Capacity15
Major Refiners
Amerada Hess Corporation1
Amoco Corporation
Ashland Oil, Inc.
Atlantic Richfield Company
BP Exploration & Oil, Inc.
Champlin Refinery-
Chevron Corporation
Citgo Petroleum Corporation
Conoco
Exxon Corporation
Lyondell-Citgo Refining Co.
Marathon Oil Company
Mobil Corporation
Phillips Petroleum Company
Shell Oil Company
Southland Oil Company
Star Enterprise
Sun Company, Inc.
Texaco, Inc.
Unocal
Uno-Ven Company
Total
Crude Capacity
(Mb/cd)
--
998
347
450
705
na
1,021
545
435
992
265
579
900
311
964
17
600
687
393
222
145
10,575
Percent of' Domestic
Crude Capacity (%)
-
6.51
2.26
2.94
4.60
na
6.67
3.55
2.84
6.48
1.73
3.78.
5.88
2.03
6.29
0.11
3.92
4.48
2.57
1.45
0.95
69.04
Mb/cd = thousand barrels of crude oil per calendar day
1 refinery shutdown 1/1/94
2 data not available
15 Anne K-. Rhodes, "World Crude Capacity, Conversion Capability Inch Upward," Oil & Gas Journal.
Vol.92, No.51, December 19, 1994, p.48.
2-24
-------
2.4.1 Past and Present Production
Table 2.6 presents data on the domestic supply of petroleum products over the past 14 years.
Domestic refinery production decreased in the early 1980s followed by a period of steady
increase from 1984 through 1989. Production decreased in the first two years of the 1990s.
as a result of warmer winter temperatures, economic slowdown, and higher prices resulting
from the Gulf War and has been increasing since 1992, as a result of a growing economy.
All major petroleum products showed a net increase in supply over the past 14 years, with
the exception of residual fuel. This decrease in residual fuel demand reflects a move in the
industry away from heavier fuels toward lighter, more refined ones. This trend is expected
to continue as a result of increasing efforts to reduce air emissions. Motor gasoline
represents the largest component of total petroleum product supplied, representing 43 percent
of total petroleum product supplied in 1993. Supply of motor gasoline has increased steadily
since 1980, peaking at 7.48 MMb/d in 1993. Distillate fuel, the second largest component
of total petroleum product supplied, historically has represented approximately 17 to 18
percent of total petroleum product supplied, peaking at 3.16 MMb/d in 1989. Supply of jet
fuel peaked in 1990, at 1.52 MMb/d, representing an increase of 50 percent from product
supplied levels in the early 1980s.
2.4.2 Supply Determinations
As previously discussed, the complexity of a refinery determines the product slate the
refinery is capable of producing. The decision as to how much crude oil to allocate to the
production of each product is for the most part a function of the marginal cost of producing
each product. The price of crude oil, the primary input to the refining process, and the
profit margin associated with alternative refined product drive the decision regarding product
slate.
2.4.3 Exports of Petroleum Products
Table 2.7 presents export levels and domestic refinery output for the past decade. Exports as
a percentage of domestic refinery output steadily increased from 1984 to 1991, fell slightly in
1992 and increased to approximately 5.8 percent in 1993. Petroleum coke and distillate and
residual fuels oils are exported in the highest volumes, averaging 75 percent of total refined
product exports over the past 10 years. Although exports as a percentage of domestic
refinery output have, for the most part, increased over time, they represent a small fraction
of total domestic output.
2-25
-------
TABLE 2.6
Petroleum Products Supplied to the U.S. Market by Type16
(millions of barrels per day)
Year
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Motor
Gasoline
6.58
6.59
6.54
6.62
6.69
6.83
7.03
7.21
7.34
7.33
7.24
7.19
7.27
7.48
Jet
Fuel
1.07
1.01
1.01
1.05
1.18
1.22
1.31
1.39
1.45
1.49
1.52
1.47
1.45
1.47
Distillate
Fuel
2.87
2.83
2.67
2.69
2.85
2.87
2.91
2.98
3.12
3.16
3.02
2.92
2.98
3.04
Residual
Fuel
2.51
2.09
1.72
1.42
1.37
1.20
1.41
1.26
1.38
1.37
1.23
1.16
1.09
1.08
LPGs
1.47
1.47
1.50
1.51
1.57
1.60
1.51
1.61
1.66
1.67
1.56
1.69
1.76
1.73
Other
2.57
2.08
1.86
1.94
2.07
1.95
2.05
2.19
2.30
2.29
2.40
2.27
2.47
2.43
Total
17.07
16.07
15.30
15.23
15.73
15.73 '
16.28
16.67
17.28
17.33
16.99
16.71
17.03
17.24
16
U.S. Department of Energy, Energy Information Administration, Petroleum Supply Annual 1993,
DOE/EIA-0340(93)/1, Tables S4-S10.
2-26
-------
TABLE 2.7
Exports and Domestic Refinery Production17
(millions of barrels per day)
Year
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Exports
0.54
0.58
0.63
0.61
0.66
0.72
0.75
0.89
0.86
0.90
Domestic
Refinery
Production
13.68
13.75
14.52
14.63
15.02
15.17
15.26
15.20
15.30
15.50
Exports as a
Percentage of
Production (%)
4.0
4.2
4.3
4.2
4.4
4.7
4.9
5.9
5.6
5.8
17 U.S. Department of Energy, Energy Information Administration, Petroleum Supply Annual 1993,
DOE/EIA-0340(93)/1, Tables Sl-2, and S4-S10.
2-27
-------
2.5 Market Demand Characteristics
This section summarizes the characteristics of the demand side of the petroleum refining
industry. Information is presented on past and present consumption and the effect price and
exports have on domestic demand.
2.5.1 Demand Determinants
The demand for refined petroleum products is a function of economic growth, price, and the
price of competing substitutes. Demand for petroleum products generally tracts the growth
or decline of the economy. The degree to which price influences quantity demanded is
referred to as price elasticity of demand, which is a measure of the sensitivity of buyers of a
product to a change in the price of the product. Further discussion of price elasticity is
presented in Section 4.3.
In some markets, economic growth is the more important factor affecting demand, whereas
price is salient in others. For example, the demand for jet fuel is a function of the overall
health of the airline industry, as well as price. In contrast, the demand for distillate fuel, for
residential heating, is less influenced by economic growth. Price, as well as climate and
mean temperature are the primary determinants of distillate fuel demand. Whereas climate
and temperature are exogenous factors, which will determine heating needs regardless of
price, high prices affect use of substitute fuels, conservation measures (e.g., adjusting
thermostats), and other energy-efficient behaviors (e.g., purchase of energy-efficient
appliances). Significantly higher prices for heating fuel in relation to substitute fuels create
incentives for consumers to switch from oil to natural gas or electric heat.
In the industrial sector, fuel oil competes with natural gas and coal for the boiler-feed
market. High prices relative to other fuels will encourage fuel-switching, especially at
electric utilities and in industrial plants having dual-fired boilers. In the early 1980s, most
new boilers in the utility sector were coal-fired. Today, oil is becoming more competitive as
environmental regulations require the use of low-sulfur fuels and reduced air emissions.
2.5.2 Past and Present Consumption
Table 2.8 presents petroleum product supplied (i.e., consumption) by product type for the
U.S. market.18 Consumption of all types of petroleum products has primarily increased
over the past ten years, with the exception of residual fuel, which has decreased
approximately 21 percent since 1984. Since 1984, the largest percentage increase in
consumption,
18 DOE uses the term-"product supplied" as a proxy for consumption. It is calculated by adding refinery
production, natural gas liquids production, supply of other liquids, imports, and stock withdrawals, and subtracting
stock additions, refinery inputs, and exports.
2-28
-------
TABLE 2.8
Petroleum Products Supplied to the U.S. Market by Type19
(millions of barrels per day)
Year
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Motor
Gasoline
6.69
6.83
7.03
7.21
7:34
7.33
7.24
7.19
7.27
7.48
Jet
Fuel
1.18
1.22
1.31
1.39
1.45
1.49
1.52
1.47
1.45
1.47
Distillate
Fuel
2.85
2.87
2.91
2.98
3.12
3.16
3.02
2.92
2.98
3.04
Residual
Fuel
1.37
1.20
1.41
1.26
1.38
1.37
1.23
1.16
1.09
1.08
LPGs
1.57
1.60
1.51
1.61
1.66
1.67
1.56
1.69
1.76
1.73
Other
2.07
1.95
2.05
2.19
2.30
2.29
2.40
2.27
2.47
2.43
Total
15.73
15.73
16.28
16.67
17.28
17.33
16.99
16.71
17.03
17.24
19 U.S. Department of Energy, Energy Information Administration, Petroleum Supply Annual 1993,
DOE/EIA-0340(93)/1, Tables S4-S10.
2-29
-------
24.5 percent, is associated with jet fuel, followed by "other"20 and motor gasoline for a
percentage increase of 17 and 12 percent, respectively. Residual fuel represents the only fuel
to show a decline in use and is expected to continue in the future as a result of increasing air
emissions regulations.
All major petroleum products showed lower demand in 1991 and 1992 in comparison to 1990
levels, with the exception of LPGs. Total consumption increased in 1993 for all fuels in
comparison to 1990 levels, with the exception of jet and residual fuels.
Over the past 10 years, demand for motor gasoline increased from 6.69 MMb/d in 1984 to a
high of 7.48 MMb/d in 1993. In 1993, motor gasoline consumption represented
approximately 43 percent of total product supplied, followed by jet fuel, representing 18
percent of total consumption. Demand for jet fuel increased from 1.18 MMb/d in 1984 to a
high of 1.52 MMb/d in 1990. Changes in demand for distillate fuel oil are similar, whereby
consumption increased from 2.85 MMb/d in 1984 to a high of 3.16 MMb/d in 1989.
Currently, distillate fuel oil represents approximately 6.7 percent of total product supplied.
Residual fuel demand, in response to lower-priced natural gas and air emissions concerns,
decreased from a high of 1.41 MMb/d in 1986 to a low of 1.08 MMb/d in 1993. As
evidenced by these data, consumption of all petroleum products primarily increased over the
past 10 years, with the exception of residual fuel.
Overall, changes in consumption of petroleum products are attributed to dramatic price
increases and supply disruptions as a result of political upheaval and wars. Variation among
fuels is more related to changes in the price of petroleum products relative to other fuels, as
well as other energy sources.
2.5.3 Product Pricing
Table 2.9 presents average prices of petroleum products to end users. Prices for petroleum
products have shown volatility over the past two decades, with large increases in the early
1980s followed by substantial declines by the end of the decade. Prices increased slightly in
1990 and have continued to decline to the present. The volatility of prices for petroleum
products is primarily due to fluctuations in the global market for crude oil and the inelastic
demand for petroleum products. Inelastic demand allows refiners to pass crude oil price
increases on to consumers due to the homogeneity of products and limited ability to switch
easily to alternative fuels.
2.5.4 Imports of Refined Petroleum Products
Imports of refined petroleum products ranged from a high of 2.30 MMb/d in 1988 to a low
20 Other petroleum products include pentanes plus other hydrocarbons and oxygenates, unfinished oils,
gasoline blending components and all finished petroleum products except finished motor gasoline, distillate fuel oil,
residual fuel oil, jet fuel, and liquefied petroleum gases.
2-30
-------
TABLE 2.9
Prices of Petroleum Products to End Users21
(cents per gallon, excluding taxes)
Petroleum Product
Motor Gasoline
Aviation Gasoline
Kerosene-Type Jet Fuel
Propane (Consumer Grade)
Kerosene
No. 1 Distillate
No. 2 Distillate
No. 2 Diesel Fuel
No. 2 Fuel Oil
Average
No. 4 Fuel Oil/Diesel Fuel
Residual Fuel Oil
Average
Price in 1978
48.4
51.6
38.7
33.5
42.1
41.0
37.7
40.0
39.6
31.1
29.8
Average
Price in 1993
75.9
99.0
57.9
67.4
75.5
66.5
60.2
60.2
60.2
50.2
33.7
Highest Average Price
Between Years of
1978 to 1993
114.7(1981) .
131.2 (1982)
102.4 (1981)
74.5 (1986, 1990)
112.3 (1981)
103.9 (1981)
99.5 (1981)
91.4(1981)
95.8(1981)
79.7 (1981)
75.6(1981)
21
U.S. Department of Energy, Energy Information Administration, Petroleum Marketing Annual 1993,
DOE/EIA-0487(93), Table 2.
2-31
-------
of 1.80 MMb/d in 1992 over the past ten years. Table 2-10 presents import levels of re fir
petroleum products and domestic consumption over the past decade. Imports as a percent or
domestic consumption reached a high of 13.3 percent in 1988 and have declined, for the
most pan, thereafter. Imports as a percent of domestic consumption for 1993 are roughly
the same as in 1982.
2.6 Industry Trends and Market Outlook
This section presents an overview of selected environmental regulations affecting the
petroleum refining industry and the supply and demand outlook in the near future.
2.6.1 Environmental Regulations
Passage of the Clean Air Act Amendments of 1990 prompted U.S. refiners to install new
processes and equipment to comply with stricter specifications for gasoline and diesel fuel.
Investment in "clean fuels" projects are mandatory in order for many refineries to stay in
business, but do little to increase capacity or provide return on investment. Trade journal
reports indicate that the cost of compliance led to some facility shutdown of plants too
economically marginal to support the debt required for modernization.22 Refiners' costs are
estimated to increase 2-3 cents/gallon for-reformulated gasoline and 12-17 cents/gallon for ,
gasoline meeting California Air Resources Board specifications.
The impact of environmental regulations vary based on a refinery's location, complexity,
market position, and corporate structure (i.e., major or independent). As a result, refiners in
rural areas, with less stringent regulation, may not need to secure as much capital as refiners
in congested or highly regulated areas. Obtaining capital for refinery upgrades generally is
harder for independents than for majors. Refinery shutdowns are based less on size than on
marketing position. Highly competitive markets where refinery margins are weak, and
regulations stringent, will tend to experience greater economic impacts and facility closures.
Refineries that can process a wide variety of crude oils will have an advantage in that they
have greater flexibility in modifying their product slate in an effort to reduce the impact of
environmental regulations.
2.6.2 Demand Outlook
Economic improvement in the past several years led to marginal increases in energy and
petroleum consumption in 1992 and more significant increases in 1993 and 1994. Demand
for petroleum products is expected to increase further in 1995.
22 Ralph Ragsdale, Bechtel Corporation, "U.S. Refiners Choosing Variety of Routes to Produce Clean Fuels,"
Oil and Gas Journal. March 21, 1993, Vol.92, No. 12, pp.52-58.
2-32
-------
TABLE 2.10
Imports and Domestic Consumption of Refined Petroleum Products23
(millions of barrels per day)
Year
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
Imports
2.01
1.87
2.05
2.00
2.30
2.22
2.12
1.84
1.81
1.83
Domestic
Consumption
15.73
15.73
16.28
16.67
17.28
17.33
16.99
16.71
17.03
17.24
Imports as a
Percent of
Consumption (%)
12.8
11.9
12.6
12.0
13.3
12.8
12.5
12.8
11.0
10.6
23 U.S. Department of Energy, Energy Information Administration. Petroleum Supply Annual 1993,
DOE/EIA-0340(93)/1, Table SI.
2-33
-------
The clean fuels requirements of the Clean Air Act Amendments created increased demand for
oxygenated fuels. The reformulated gasoline program is mandatory in areas noncompliant
with atmospheric ozone or carbon monoxide limits. Although regions not classified as
"noncompliant" can opt out of the reformulated program, some states are taking the initiative
to join the program creating increased demand for oxygenated fuels.24
2.6.3 Supply Outlook (Production and Capacity)
Economic growth and low prices are expected to increase oil demand in the next year.
Despite modest improvement in oil prices, trade journal reports predict a decline in U.S.
crude oil output of 2.4 percent for 1995, following a decline of 3 percent in 1994.25 U.S.
production has been falling since 1985, except for a modest increase in 1991, when prices
rose in the wake of Iraq's invasion of Kuwait. U.S. crude oil production has been falling at
an average rate of 260,000 barrels per day since 1985. Falling U.S. production and rising
demand mean increased petroleum imports again in 1995. Trade journals report that there
are potential problems in U.S. product supply because refining capacity is being stretched as
product demand moves up and capacity expansion remains limited by environmental
regulations and costs.26 Increased production costs as a result of environmental regulation
could further reduce U.S. output and increase imports of petroleum products from abroad.
In recent years, refining capacity has been falling even though product demand has been
rising. Trade journal reports indicate that marginally profitable refineries found the new
environmental compliance requirements prohibitively costly and capacity was reduced due to
plant modifications.27 A major issue in the near future will be the need for additional
refining capacity to meet rising demand. In 1994, U.S. refiners processed more crude
domestically but also boosted product imports. When the required domestic refining capacity
is not available, then product imports are used to fill the gap. If additional environmental
regulations result in the shutdown of more facilities, the import of petroleum products may
increase further.
24 Ralph Ragsdale, Bechtel Corporation, "U.S. Refiners Choosing Variety of Routes to Produce Clean Fuels,"
Oil and Gas Journal. March 21, 1993, Vol.92, No. 12, pp.52-58.
25 Robert J. Beck, "Economic Growth, Low Prices To Lift U.S. Oil And Gas Demand In 1995," Oil & Gas
Journal. January 30, 1995, Vol.93, No.5, pp.51-68.
26 ibid.
27 ibid.
2-34
-------
3.0 COST IMPAT ANALYSIS
A total of four wastes generated during petroleum refining are being listing as hazardous
under RCRA. This chapter examines the four wastes, the quantity of each generated, their
current management practices, compliance management practices available after listing, the
unit costs and prices of managing these wastes, and the total incremental compliance costs.
Information on quantities of waste generated, waste management costs, and current
management practices are based on the 1992 RCRA 3007 Survey of the Petroleum 'Refining
Industry. The 162 facilities affected by the listings determination (i.e., facilities that manage
these four listed wastes in non-exempt waste management units) are owned and operated by
80 companies.
3.1 Hazardous Wastes1
The newly listed wastes generated in the petroleum refining industry are as follows:
K169 - Crude oil storage tank sludge;
K170 - Clarified slurry oil sludge from catalytic cracking;
K171 - Catalyst from catalytic hydrotreating; and
K172 - Catalyst from catalytic hydrorefining.
Figure 3.1 illustrates the points of origin for the newly listed wastes associated with the
petroleum refining industry. This is an illustrative facility diagram and does not necessarily
represent a specific plant. These wastes and selected characteristics for each are described
below.
1. K169 - Crude oil storage tank sludge
Nearly all refineries store feedstock materials and products in tanks. Every 10 to 20 years
crude oil storage tanks require sludge removal due to maintenance, inspection, or sludge
buildup. Crude oil tank sludge consists of heavy hydrocarbons, basic sediment and water,
and entrapped oil that settles to the bottom of the tank. When removed, the oil is recovered
while the solids are collected and discarded as a waste (see K169, Figure 3.1).
2. K170 - Clarified slurry oil sludge from catalytic cracking
Nearly all refineries store feedstock materials and products in tanks. Every 5 to 10 years
clarified slurry oil tanks require sludge removal due to maintenance, inspection, or sludge
buildup. Clarified slurry oil is the lowest boiling fraction from the catalytic cracking main
fractionator. It contains some catalyst and catalyst fines. Clarified slurry oil sludges are not
1 Process information in this section is taken from "OSW Listing Determination for the Petroleum Refining
Industry - Waste Characterization Part ffl", Science Applications International Corporation, September 15, 1994.
3-1
-------
limited to "tank sludges." For this residual, sludges are generated from tank storage and,
more rarely, filtration prior to tank storage (see K170, Figure 3.1 and Figure 3.2).
3. K171 - Catalyst from catalytic hydrotreating
Catalytic hydrotreating removes sulfur by converting mercaptans to H2S, which is
fractionated. The catalyst is typically cobalt or nickel and molybdenum on alumina.
Catalyst lifetime is approximately 1 to 5 years, after which the catalyst is replaced (see
K171, Figure 3.1 and Figure 3.3). Catalyst "activity" losses occur because of poisons from
the crude, coke deposits, and structural breakdown from severe operating conditions.
4. K172 - Catalyst from catalytic hydrorefming
Catalytic hydrorefming removes sulfur by converting mercaptans to H2S, which is
fractionated. The catalyst is typically cobalt or nickel and molybdenum on alumina.
Catalyst lifetime is approximately 1 to 5 years, after which the catalyst is replaced (see
K172, Figure 3.1 and Figure 3.3). Catalyst "activity" losses occur because of poisons from
the crude, coke deposits, and structural breakdown from severe operating conditions.
3-2
-------
K169
L^-
Typi
Atmospheric =^ 2
Distillation ~ £
I
Vacuum
DistillaHon
FIGURE 3.1
cal Petroleum Refining Process Flow Diagram
CiToO _
^
Naphtha^. Hvdro
4 "^ Treating
1
^ Hydro
treating
K171
Hvv Atm Gas Oil
;
Lt Vac Gas Oil _
HvvVGO _
^^^^L
K171
** ^ Reformaje ^
Ketorming ^
Alkvlate
_,, . fr_ Alkylation ASO
Diesel and Jet Fuel _
Frr Fluidizcd FCC Gasoline
Feed Catalytic r
^b- I-fifHrn- "^^ j~ , , ,i r __^_^_^ J*J ^^
K172 Kl/0
» Ihermal ' ^
Process
!"(f , , V°K£,fc
^ Sulfur Sulfur^
Complex
3-3
-------
FIGURE 3.2
Fluid Catalytic Cracking
Flue Gas
to Boiler
Aim. Gas Oil
Light VGO
Heavy VGO
CokerGasOil
'-x
ser
ctor
(Electrostatic
^Precipilator
Spent
t
)a
>-
ttalyst
Fines
^T-
Fractionator
01
QO
^ Recycle Catalyst |
t Make-up Catalyst
Equilibrium
^Catalyst
Recycle
3-4
C4 and Lighter
^Gasoline
^Light Cycle
"Gas Oil
p.Heavy Cycle
Gas Oil
CSO K170
-------
FIGURE 3.3
Hydrotreating/Hydrorefining
Light Gas Oil
VGO
Naphtha
Make-up Hz
H2S and Light Ends
f ^
Reactor
_ Recycle
Product
v»_^
JH2
M
O
M
2
re
PH
0)
CD
^J
M
O*
d«
d.
fi
Cfl
X
T
Spent
Catalyst
K171 K172
Product
Reform feed
Jet & Diesel fuels
for Blending
FCC Feed
3-5
-------
3.2 Annual Hazardous Waste Quantities
Annual hazardous waste quantities were developed on a plant specific level for each newly
listed waste. This section describes the development of the annual hazardous waste quantities
considered in the analysis.
3.2.1 Methodology
The methodology for developing annual hazardous waste, questions is divided into three parts.
The first part presents the methodology for estimating annual generation quantities for
facilities reporting generating wastes in the 1992 RCRA 3007 Survey. The second part
presents the methodology for predicting annual generation quantities for facilities which did
not report generating wastes in the Survey. The third part discusses how contaminated soil
and debris quantities were addressed.
Reporting Facilities
Most of the wastes reported by facilities through the 1992 RCRA 3007 Survey were
generated less than once per year. In order to evaluate the cost and economic impact of this
listing on each facility, wastes generated less than once per year were annualized. For
example, if a facility had five storage tanks which were cleaned once every ten years, EPA *
assumed that one tank would be cleaned at an even-year interval rather than several tanks in
the same year. To obtain a yearly average cost of cleaning these tanks which can be applied
to the economic analysis for the year 1992, the quantity of waste generated in the cleaning of
each of the five tanks was divided by the generation frequency of ten years. The final
quantity of this waste used in the analysis is the sum of the annualized generation quantities
for the five tanks. For those wastes with reported quantities and generation frequencies,
EPA used this procedure to annualize the quantities.
If the generation frequency of a waste was not reported, EPA assumed the frequency to be
the same as that of similar wastes generated at the facility. When this assumption was not
possible, EPA assumed the average generation frequency of all facilities reporting that waste.
The average generation frequency for each waste stream is as follows:
Average Waste Stream Generation Frequency
Waste Stream
K169
K170
K171
K172
Average Generation Frequency (years)
10.5
9
3.5
2.5
3-6
-------
The RCRA 3007 Survey only required the reporting of crude oil and CSO tank sludge
quantities that were generated during a two-year period (1991 and 1992). The catalyst
residuals were not limited to this two-year reporting period. Because of the two-year
reporting period, tank sludge quantities needed to be estimated for tanks which were not
cleaned out during this period. The RCRA 3007 Survey captured cleanout quantities from
approximately 21 percent of the existing crude oil tanks and 56 percent of the existing CSO
tanks.
As noted above, on average crude oil tanks are cleaned out once every 10.5 years and CSO
tanks are cleaned out once every 9 years. Also, on average there are approximately 8 crude
oil tanks per refinery and 3.4 CSO tanks per refinery. Based on the average number of tanks
per facility and the clean-out frequency, crude oil sludge is generated every 1.3 years at a
facility and CSO sludge is generated every 2.6 years.
For facilities reporting generating tank sludges in the 3007 Survey, EPA estimated quantities
for the other tanks not cleaned out during the two-year reporting period by assigning the
average reported quantity generated per tank at that facility. These assigned quantities were
then annualized using the facility-specific or industry-average frequency of generation.
Some facilities reported generating a waste(s) but did not report a waste quantity. When
possible, EPA estimated missing quantities based on the average of other similar wastes at '
the same facility. EPA estimated quantities for the remaining facilities based on industry
waste generation to daily crude rate relationships. Waste generation estimates were based on
the daily throughput rate of crude oil rather than products because the wastes cannot be
directly related to particular products. Statistical tests proved a correlation exists between the
rate of sludge and catalyst residual generation and daily crude oil rate. To estimate missing
quantities, EPA estimated waste generation using regression techniques to predict sludge and
catalyst generation .quantities.
EPA used regression methods to determine the relationship (i.e., line) that is the best
predictor of annual waste generation quantities. EPA's procedure was to plot the data and
the annual crude rate and annual waste quantity data, graph the regression line, and identify
the points that lie outside the 95 percent prediction interval of the regression equation for this
line. These points were assumed to be "outliers" and not representative of the population of
data points as a whole. Linear regression equations were recalculated on the remaining data
points. The "r-values" (a statistical parameter that predicts correlation between two sets of
data) indicated that there was statistical correlation between the annual generation quantities
for each sludge and catalyst residual and annual crude oil rates and therefore, inferences can
be drawn from these regression relationships. The "r-squared values" were low for all the
linear regression equations. This means that there is high variability in the Y-values (annual
waste quantities) explained by the regression line.
The regression equations for each waste stream are presented in the table below. EPA ran
sensitivity analyses on the cost and economic impact analyses because of the high variability
3-7
-------
of the annual waste quantities explained by the regression line. See Section 3.2.2 for a
discussion on data limitations.
Linear Regression Equations
(Annual Waste Quantities are in MT/yr;
Daily Crude Oil Rates are in Mb/cd)
Waste
Stream
K169
K170
K171
K172
Linear Regression Equation
Annual Waste Quantity = 0.000856 * (Daily Crude Oil Rate
* 365)U623
Annual Waste Quantity (MT) =
Rate * 365)°'83047
Annual Waste Quantity (MT) =
Crude Oil Rate * 365)
Annual Waste Quantity (MT) =
* (Daily Crude Oil Rate * 365)]
0.0163 * (Daily
3.3573 + 0.001
exp [3.6624 +
Crude Oil
15 * (Daily
1.714x 10-5
These linear regression equations were applied to units at facilities which did not report
waste generation quantities. For each unit with an unknown quantity, the daily crude rates
were entered into the linear regression equations to estimate sludge and catalyst waste
quantities. These total waste stream quantities, which represents the generation of that waste
for the entire facility, were divided by the number of units at the facility which generate that
waste. For example, if a facility had three crude oil storage tanks, the daily crude rate was
inserted into the crude oil tank sludge linear regression equation. This annual crude oil
sludge quantity was then divided by three to estimate the sludge quantity generated from each
tank.
A few facilities reported generating a quantity of zero for various wastes. EPA used best
engineering judgement to determine whether or not this zero quantity was feasible. If it was
determined unlikely that the particular management method would not generate a waste, a
quantity was estimated. For example, a facility reporting a zero waste quantity from a
filtration unit followed by disposal in a landfill was assumed to be incorrect unless the
facility noted otherwise.
A few facilities provided generation and disposal quantities, but did not provide quantities
involved with intermediate treatment steps. For example, a facility may have provided a
quantity entering a treatment step such as pressure filtration, but the quantity of sludge
leaving this step was not reported. As presented below, EPA determined average ratios of
the quantity leaving the step to quantity entering the step based on quantity data reported by
3-8
-------
other facilities. The appropriate ratio was multiplied by the quantity reported entering the
step to estimate the quantity leaving the step.
Treatment Method Average Quantity Leaving/Quantity Entering
Washing with Water 0.9
Sludge De-watering 0.6
Pressure Filtration/Centrifuging 0.4
On-site Stabilization 1.6
Non-Reporting Facilities
The regression equations presented previously also were used to estimate waste generation
quantities for facilities EPA believes generate specific waste residuals but did not report
quantities in the 1992 RCRA 3007 Survey. EPA made the following assumptions when
identifying those facilities with non-reported waste residuals (and quantities):
1. All facilities with existing crude oil storage tanks or clarified slurry oil storage
tanks generate crude oil storage tank sludges (K169) or clarified slurry oil tank
sludges (K170) unless it has been specifically stated in a cover letter or
communication that the residual is not generated.
2. All facilities with hydrotreating or hydrorefming units generate hydrotreating
catalyst residuals (K171) or hydrorefming catalyst residuals (K172).
Contaminated Soil and Debris
Approximately 600,000 cubic yards of contaminated soil and debris were reported by 33
facilities in the 1992 RCRA 3007 Survey. Almost all of this quantity was generated by 7 out
of the 33 facilities. This quantity was not included in the analysis because (1) these 1992
one-time quantities have likely already been managed, (2) management of soil and debris
exhibiting TC characteristic hazard (e.g., benzene) are already regulated under RCRA
Subtitle C due to the TC listings and the Phase II LDR regulations, and (3) refineries will
likely manage non-hazardous soil and debris under current regulations (RCRA Subtitle D)
prior to final listing of the newly listed wastes included in this analysis.
3-9
-------
3.2.2 Data Limitations
Many facilities did not report waste quantities. Estimates for these quantities were based on
generation in other units at the same facility, generation at other reporting facilities, and on
the daily crude throughput rate. The waste generation regression analyses determined a
statistical correlation between the annual waste quantity and daily crude rate data sets, but,
the regression equations had low "r-squared" values indicating high variability in the
prediction of annual waste generation quantities. Also, the generation of many wastes cannot
be directly related to the production of single products. Therefore, regression equations were
derived as tools for estimating annual waste generation. Because of the low "r-squared
values", sensitivity analyses of the cost and economic impacts have been conducted which
evaluate impacts using annual waste generation estimates that are 50 percent smaller (lower-
bound estimate of waste generation quantity) and 50 percent higher (upper-bound estimate of
waste generation quantity) than the amount predicted by the regression equations.
Some of the facilities with missing quantities are not "typical" refineries. These facilities do
not generate the same variety of products as the majority of the facilities. For example, an
asphalt facility will generally produce only heavy products such as asphalt and possibly heavy
residual fuel oil. Very few of these facilities reported all waste quantities, therefore, a
separate average waste to crude ratio for these "non-typical" refineries cannot be determined.
As a result, all available data from both "typical" and "non-typical" refineries were used to *
develop the average ratios to be applied to all facilities.
3.2.3 Waste Summaries
The following subsections summarize the waste quantities for each newly listed waste.
Waste quantities were based on 1992 data from the RCRA 3007 Survey. Table 3.1 presents
the total waste quantity generated for each waste stream .listing. The total reported waste
quantity and total annualized waste quantity (including estimates for non-reported quantities)
affected by this listing are presented.' These quantities represent the amount of waste
generated at the point of generation (e.g., tank cleanout) prior to any type of treatment or
disposal.
1. K169 - Crude oil storage tank sludge
Petroleum refineries produce between 45,900 and 114,700 Mton/year with a typical value of
approximately 80,300 Mton/year of crude oil storage tank sludge (K169) affected by this
listing. EPA estimates that 145 facilities generate this waste. Eighty-five of the 93 facilities
reporting generating this waste did not report quantity for cleaning out all of their tanks.
Fifteen of the 93 facilities did not provide a quantity. EPA also estimated that an additional
52 facilities did not report generating this waste. Waste quantities for these non-reported
quantities were estimated using the methodology described in Section 3.2.1. These estimates
account for approximately 86 percent of the typical annual quantity.
3-10
-------
2. K17Q - Clarified slurry oil sludge from catalytic cracking
Petroleum refineries produce between 18,300 and 35,400 Mton/year with a typical value of
approximately 26,800 Mton/year of clarified slurry oil sludge from catalytic cracking (K170)
affected by this listing. EPA estimates that 101 facilities generate this waste. Thirty-seven
of the 54 facilities reporting generating this was did not report quantities for cleaning out ail
of their tanks. Six of the 54 facilities did not provide a quantity. EPA also estimated that an
additional 47 facilities did not report generating this waste. Waste quantities for these non-
reported quantities were estimated using the methodology described in Section 3.2.1. These
estimates account for approximately 64 percent of the typical annual quantity.
3. K171 - Catalyst from catalytic hydrotreating
Petroleum refineries produce between 6,700 and 6,900 Mton/year with a typical value of
approximately 6,800 Mton/year of catalyst from catalytic hydrotreating (K171) affected by
this listing. EPA estimates that 130 facilities generate this waste. Fourteen of the 127
facilities reporting this waste did not provide a quantity. EPA also estimated that an
additional 3 facilities did not report generating this waste. Waste quantities for these non-
reported quantities were estimated using the methodology described in Section 3.2.1. These
estimates account for approximately 3 percent of the typical annual quantity.
4. K172 - Catalyst from catalytic hydrorefming
Petroleum refineries produce between 20,700 and 20,900 Mton/year with a typical value of
approximately 20,800 Mton/year of catalyst from catalytic cracking (K172) affected by this
listing. EPA estimates that 55 facilities generate this waste. EPA also estimated that an
additional 2 facilities did not report generating this waste. Waste quantities for these non-
reported quantities were estimated using the methodology described in Section 3.2.1. These
estimates account for approximately 1 percent of the typical annual quantity.
3-11
-------
TABLE 3.1
TOTAL WASTE QUANTITIES BY WASTE STREAM LISTING
Waste
Stream
K169
K170
K171
K172
Total'0
- No. of
Fac. w/
Non-
Exempt
Waste
Mgmt.
145
101
130
55
162
No. of
Non-
Reporting
Fac.">
52
.47
3
2
Reported Point
of Generation
Waste Quantity
(All Years)
(MT/yr)
136,000
60,600
13,500
26,400
236,500
Annualized
Reported Point
of Generation
Waste Quantity
(All Years)
(MT/yr)
11,400
9,700
6,600
20,600
48,300
Added Unreported Annualized Point of Generation Quantities
(MT/yr)
Average
[Low - High]
Additional Tank
Quantities for
Reporting
Facilities0"
63,900
[31,900-95,8001
1 1 ,600
. [5,800 - 17,400|
0
|0-0|
0
|0-0|
75,500
[37,700- 113,2001
Non-Quantified
Wastes for
Reporting
Facilities'"
900
[400 - 1 ,300j
700
[300- 1,0001
200
[100-300|
0
[0-01
1,800
[900 - 2,600)
Total Tank
Quantities for
Non-Reporting
Facilities'1'1
4,100
[2,100 -6,200|
4,900
(2,400 - 7,300|
0
|0 - 100|
100
|100-200|
9,200
[4,600 - 13,800|
Annualized
Point of Generation
Waste Quantity
(MT/Yr}"'
80,300
[45,900 - 114,700]
26,800
|18,300-35,400|
6,800
[6,700 - 6,900|
20,800
[20,700 - 20,900|
134,800
[91,600 - 177,900)
"" The number of facilities assumed to be generating this waste stream but did not report any quantities in the Survey.
(b) The estimated additional quantity of waste generated from all other tanks at facilities that did not report quantities for a|l existing tanks.
(c) The estimated quantity of waste for waste streams which were reported being generated but were not quantified.
-------
3.2.4 Comparison of 1992 RCRA Section 3007 Survey Quantities and Annual
Hazardous Waste Quantities
A comparison of the 1992 RCRA 3007 Survey quantities and the annual waste quantities
used in the cost and economic impact analysis is presented here to demonstrate how the data
was derived from those numbers that may be presented in other EPA analyses supporting this
listings determination. Costs are directly related to the quantity of the waste being managed
and costs may be incurred at several steps from the point of generation, through intermediate
storage and treatment steps, and at the point of final management (disposal). The cost model
spreadsheet supporting this analysis tracks the waste quantities and costs for each step of the
waste treatment train on a waste-by-waste and refinery-by-refinery basis.
Table 3.2 presents the waste quantities that have been presented in other EPA analyses. This
table presents the waste quantities reported in the 1992 RCRA 3007 Survey as being disposed
(i.e., quantities reaching the end of the waste management train) in 1992 only, ignoring all
quantities reported being disposed in previous and later years.
Reported and predicted waste generation quantities (i.e., quantities entering the waste
treatment train) for all years (1992, 1993, 1994, etc.) were annualized based on the reported
generation frequencies. This annualization methodology "smooths out" the peaks and valleys
associated with these infrequently generated (i.e., not generated annually) wastes over time. *
EPA chose to annualize all reported waste quantities in order to assign quantity and costs
attributable to the listings determination to all refineries impacted by the listing and utilize a
larger set of responses reported in the 3007 RCRA Survey. This approach also enabled EPA
to estimate unreported quantities without having to predict the year of generation. Table 3.3
presents the "typical" annualized generation and final management waste quantities used in
the cost analysis. The annualized generation quantity is higher or lower depending on the
waste than the quantity reported being generated in the year 1992 (comparison of column 4
in Table 3.2 with column 6 in Table 3.3). As a note, the Table 3.3 annual final management
quantities for crude oil tank sludges and clarified slurry oil sludge have been decreased
because EPA assumes that all refineries who are currently not filtering oily sludges will
install a filtration unit to recycle the oil back into process units as a cost-effective waste
minimization practice (see discussion in Section 3.3.1). If the waste minimization practice is
not implemented the totals would be 17,400 and 18,000 MT/yr, respectively. In Table 3.3,
Column 5 presents the annual quantity entering waste management trains (i.e., point of
generation), Column 6 presents the "non-process recycled" annual quantities reaching the end
of the waste management train (i.e., final management), and Column 10 presents the annual
quantities reaching the end of the waste management train that incur an additional cost in the
final management step.
3-13
-------
TABLE 3.2
REPORTED AND ADJUSTED 1992 RCRA 3007 SURVEY QUANTITIES IN METRIC TONS'
(1)
Waste Stream
Crude Oil Tank Sludge
Clarified Slurry Oil Sludge
Hydrotreating Catalyst
Hydrorefining Catalyst
TOTAL
(2)
Reported
Final
Management
Quantity2
22,017
24,010
5,640
18,634
70,301
(3)
Exempted
Final Mgmt.
Quantities Based
on the
Definition of
Solid Waste3
9,826
581
133
0
10,540
(4)
Final
Management
Quantity
Excluding DSW
Exemptions4
12,191
23,429
5,507
18,634
59,761
(5)
Exempted
Final Mgmt.
Quantities
Assoc. w/ Metal
Reclamation
Units5
0
0
4,274
15,388
19,662
(6)
Final Mgmt.
Quantities
Associated
with
Headwaters
Exemption
2,118
250
0
0
2,368
(7)
Final
Management
Quantities
Currently
in
Compliance
4,019
3,564
639
198
8,420
(8)
Adjusted
Final
Management
Quantity6
6,054
19,615
594
3,048
29,311
1 U.S. EPA, Office of Solid Waste, "Listing Background Document for the 1992-1996 Petroleum Refining Listing Determination," Draft Final, prepared by SAIC, August 31,
1995.
2 Total includes quantities where the final management practice (disposition) is landfill, land treatment, incineration, industrial furnace, recycling, recovery, reclamation, reuse,
wastewater discharges, off-site stabilization, and storage. It excludes on-site intermediate storage and treatment (e.g., water washing, stabilization, and filtering) management
practices.
' Based on the definition of solid waste (DSW), all oil-bearing residuals reinserted into petroleum refining processes or used directly as effective substitutes are exempted from the
listing.
4 Equals Col. 2 - Col. 3.
5 Metal reclamation units (including catalyst regeneration) are included under the exemption for "smelting, melting, and refining furnaces that process hazardous wastes solely for
metal recovery."
6 Equals Col. 4 - Col. 5 - Col. 6 - Col. 7. These totals are lower than the totals used for costing in that costs requiring compliance management may be incurred at various points
in the management process.
3-14
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TABLE 3.3
LISTING DETERMINATION ANNUALIZED GENERATION AND FINAL MANAGEMENT QUANTITIES IN METRIC TONS'-"
(1)
Waste Stream
Crude Oil Tank Sludge
Clarified Slurry Oil
Sludge
Hydrotreating Catalyst
Hydrorefming Catalyst
TOTAL
(2)
Reported
Point of
Generation
Quantity2
136,000
60,600
13,500
26,400
236,500
(3)
Annual
Reported
Point of
Generation
Quantity3
11,400
9,700
6,600
20,600
48,300
(4)
Added
Annual
Unreported
Generation
Quantities4
68,900
17,200
200
100
86,500
(5)
Annual Total
Point of
Generation
Quantity5
80,300
26,800
6,800
20,800
134,800
(6)
Annual
Final
Mgmt.
Quantity*
14,600
13,100
6,600
20,100
54,400
(7)
Final Mgmt.
Headwaters
Exemption
Quantity7
2,700
500
0
0
3,200
(8)
Final Mgmt.
Quantities
Currently in
Compliance*
1,300
2,000
200
100
3,600
(9)
Final Mgmt.
Quantity w/
No Incr.
Compl. Cost9
1,400
900
0
0
2,300
(10)
Listing
Annual
Final Mgmt.
Quantity10
k
9,200
9,700
6,400
20,000
45,300
1 Source: DPRA Cost Model derived from Petroleum Refining Database (1992 RCRA 3007 Survey).
2 Total includes quantities at the point of generation prior to any treatment or disposal. Total only includes waste streams having a potential associated mciemenl.il cost <>t
compliance. In many cases (unless filtration is required) oil-bearing residuals exempted under the definition of solid waste have no associated incremental compliance cost and
therefore, are not included.
* Total reported generation quantity is annualized to represent an average quantity of waste generated per year.
4 Estimate of additional waste generated by facilities that reported generating a waste but did not report a quantity, and estimates for facilities that did not report generating a waste
when it should have been generated, annualized to represent an average quantity of waste generated per year.
5 Total reported and unreported generation quantity is annualized to represent an average quantity of waste generated per year.
6 Total final management quantity is annualized to represent an average quantity of waste managed per year.
7 Total amount of the annualized final management quantity exempt because of the wastewater treatment headwaters exemption.
1 Total amount of the annualized final management quantity already managed in units that comply with RCRA Subtitle C regulations.
9 Total amount of the annualized final management quantity with no incremental compliance cost due to the benefits (recycled oil value) obtained from adding a filtration unit as a
waste minimization practice.
10 Total includes exempt metal reclamation quantities because the "metals reclamation unit exemption" does not apply to RCRA Subtitle C storage requirements. No incremental
compliance costs are incurred for the metal reclamation unit itself. Col. 10 = Col. 6 - Col. 7 - Col. 8 - Col. 9
" Costs are incurred at various points in the management of these wastes, beginning with the point of generation (Col. 4) and ending witli the final management (Col. 10).
3-15
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3.3 Waste Management Practices and Compliance Costs
This section describes the current (baseline) waste management practices for each newly
listed waste and the alternative waste management practices assumed after listing.
3.3.1 Current (Baseline) and Compliance Waste Management Practices
Current waste management practices were provided in the 1992 RCRA 3007 Survey by
facilities in the petroleum refining industry. When a reported waste management train
seemed incomplete, EPA made the following assumptions:
Where a facility reported a final waste management practice of storage, washing,
or filtration, EPA assigned the most common final waste management practice
reported by other facilities as the ultimate disposition of the waste.
Where a facility reported a final waste management practice of off-site
management (e.g., landfill or incineration) with no prior on-site storage (e.g.,
container or tank) indicated, EPA assigned the most common waste storage practice
reported by other facilities as the storage mechanism prior to off-site management.
Compliance waste management practices were developed to address the RCRA Subtitle C
requirements imposed by the waste listings. It should be noted that frequently several
individual waste management methods make up the components of the waste management
practice (i.e., waste management train). Because of the number of waste management trains,
baseline and compliance costs were developed for the individual components of each waste
management train. Then the costs for each of the components was summed together to
develop baseline and compliance cost estimates for the complete waste management train.
Compliance management practices were assumed under three different scenarios, compliance
due to the listing alone, compliance due to land disposal restriction (LDR) and listing
regulations combined, and compliance due to contingent management, LDR, and listing
regulations combined. The scenarios are defined as follows:
The Listing Scenario assumes an end disposal management method of Subtitle C
landfill or continued combustion of wastes, where indicated as the baseline
management practice, in a Subtitle C incinerator/BIF.
The LDR Scenario assumes two options. In the first option, the metal-based
wastes are combusted in a Subtitle C incineration followed by vitrification and
Subtitle C landfill of the ash and the organic-based wastes are combusted in off-site
Subtitle C incinerator/BIF units. This option reflects the highest cost situation. Other
technologies may be applicable (e.g., solvent extraction instead of incineration or
solidification instead of vitrification for metal-based wastes) to meet LDR standards,
but these are lower cost options and will not provide an upper-bound to the cost and
3-16
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economic analysis. In the second option, the metal-based catalyst residuals are
reclaimed/recovered to take advantage of the exclusion from RCRA Subtitle C
regulation. The oil-based wastes are combusted in either an on- or off-site Subtitle C
incinerator/BIF depending on the economic feasibility of constructing on-site
incinerator units. If a facility does not currently have a RCRA Part B permit, EPA
assumed the facility would choose not to construct an on-site incinerator in order to
avoid incurring costs under the RCRA corrective action program (see Section 3.3.6
for discussion of corrective action costs). This option reflects the most likely cost to
the petroleum refining industry (excluding corrective action costs) due to the listing
and LDR regulations if the Contingent Management Scenario is not proposed as an
alternative management option.
The Contingent Management Scenario expands the second option of the LDR
Scenario. Instead of combusting the oil-based wastes in an on- or off-site Subtitle C
incinerator/BIF, the wastes can be excluded from RCRA Subtitle C regulation under
the definition of a solid waste if managed in certain Subtitle D management units.
Crude oil tank sludges are excluded if contingently managed in Subtitle D land
treatment units having run-on/run-off controls. The contingent management exclusion
does not allow exclusion from Subtitle C storage and transportation requirements prior
to the contingent management practice. CSO sludges are excluded if contingently
managed in Subtitle D land treatment units with run-on/run-off controls or Subtitle D -
landfills. Option 1 of the Contingent Management Scenario assumes that Contingent
Management Scenarios are proposed for both the crude oil and CSO sludges. Option
2 assumes that contingent management only is proposed for the CSO sludge.
The following list summarizes the compliance management practices assumed for the listing,
LDR, and contingent regulatory options:
Storage and treatment of wastes are performed in accumulation tanks or containers
(i.e., meeting the 40 CFR 262.34 requirements, therefore, a permit is not required).
Existing tank systems and container storage areas are retrofitted with secondary
containment systems. In addition, the current management practices which use
treatment impoundments in the wastewater treatment system incur no incremental
compliance cost of upgrading to a tank system because of the "headwaters
exemption" granted to tank residuals (flushing waters) discharged to on-site
wastewater treatment facilities at petroleum refineries.
Closure of non-compliance land disposal units is required if the existing
accumulated/disposed wastes are physically disturbed (see 54 FR 36597 regarding
retroactive application of Subtitle C requirements). EPA assumes, because of
retrofitting economics and LDR requirements, that non-compliance disposal surface
impoundments and waste piles (i.e., drying on pad) will be dredged and cleared of
any newly listed wastes prior to final listing instead of constructing new Subtitle C
units. These units will be recommissioned for uses other than management of the
3-17
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newly listed wastes. The compliance management practice for the newly listed oil-
based sludges is filtration followed by disposal in a Subtitle C landfill (Listing
Scenario), Subtitle C incineration (LDR Scenario), or Subtitle D landfill/land
treatment (Contingent Management Scenario).
For the Listing and LDR Scenarios, non-RCRA land treatment units will be
abandoned because acceptance of other nonhazardous wastes (i.e., wastes not
covered by this listing) will disturb the contained newly listed wastes. For those
units currently accepting other nonhazardous wastes (not newly listed), costs could
not be estimated for alternative management of those wastes due to closure of the
unit because waste quantity data is unavailable. Many facilities responded in the
1992 RCRA 3007 Survey that their land treatment units are permitted under RCRA.
EPA's RCRIS database confirmed the permitted status of these units. However,
LDR regulations currently exist for hazardous wastes that would likely have been
disposed in these permitted units by refineries (e.g., D001, D018, F037, F038, and
soil and debris wastes). EPA assumes that "no-migration" variances have not been
granted for most, if not all, of these units. Therefore, EPA assumes that due to
new LDR regulations promulgated since 1992, none of the newly listed wastes are
currently managed in RCRA permitted land treatment units, but, have been
switched over to non-RCRA land treatment units. Also, all newly listed wastes that
are currently characteristically hazardous and reported being managed in land
treatment units in 1992 are assumed now to be in compliance with all applicable
Subtitle C regulations. EPA also assumes that management of these
characteristically hazardous wastes under LDRs will be the same, therefore, no
incremental compliance costs will be incurred. For the Contingent Management
Scenario, Subtitle D land treatment units will continue to be allowed management
practices for oil-based wastes if they have proper run-on/run-off controls.
For the Listing and LDR Scenarios, because new wastes accumulated/disposed prior
to the final listing will not be disturbed in a landfill, EPA assumes that these units
will not have to be closed or abandoned. For landfills, use of the particular cells
containing the newly listed wastes will be discontinued prior to final listing. The
remaining portion of the landfill will continue to be used. For the Contingent
Management Scenario, Subtitle D landfill units will continue to be allowed as a
management practice for CSO sludges only.
Recycling/recovery/regeneration/reclamation is frequently reported as a current
management practice. Some recycling practices and residuals that are recycled are
exempt from RCRA under either the §261.2 definition of materials that are not solid
waste when recycled (e.g., reused as ingredients in an industrial process to make a
product, such as a distillation unit, coker, and catalytic cracker or direct use as
effective substitutes for commercial product, such as transfer with coke product or
other refinery product) or the §266.100 exemption for "smelting, melting, and
refining furnaces that process hazardous waste solely for metal recovery." It should
3-18
-------
be noted that" residuals from certain metal reclamation and regeneration processes
are not exempt from RCRA Subtitle C storage, transportation, and/or management
requirements when they are used to produce or contained in products that are
applied to or placed on land, involve speculative accumulation of metals, or partial
reclamation of metals.
For newly listed waste streams for which
recycling/recovery/regeneration/reclamation is not an option, the disposal options
consist of Subtitle C landfill under the Listing Scenario and Subtitle C incineration
followed by vitrification prior to Subtitle C landfill under the LDR Scenario. Other
LDR options possibly could include solvent extraction instead of incineration and
solidification instead of vitrification.
Table 3.4 summarizes baseline and compliance waste management practices for wastes
impacted by the listing. Table 3.5 summarizes compliance waste management practices for
listed wastes impacted by LDR regulations. Table 3.6 summarizes compliance waste
management practices for listed wastes impacted by contingent management regulations. The
following narratives also detail how each listed waste is managed under baseline practices
and what the assumed compliance practices will be for that waste after listing.
1. K169 - Crude oil storage tank sludge
The most common residual disposal method for crude oil storage tank sludge is disposal in
an off-site Subtitle D or C landfill. Pressure filtration/centrifuging is a common residual
treatment method. Other treatment methods include thermal treatment, off-site incineration,
washing with distillate or water, sludge thickening or de-watering, settling, filtration,
chemical or thermal emulsion breaking, land treatment, discharge to on-site wastewater
treatment facility, drying on a pad, and stabilization. Other disposal methods include
discharge to surface water under NPDES, disposal in an on-site Subtitle C landfill, and
disposal in an on-site surface impoundment.
For the Listing Scenario, the assumed compliance practice is disposal in an on-/off-site
Subtitle C landfill. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
Discharge of flushing waters to on-site wastewater treatment systems will be continued
because of a "headwater exemption" provided for waste-derived sludges from wastewater
treatment systems that are not already hazardous due to a previous listing. The practice of
disposing this waste in land treatment and disposal surface impoundment units will be
abandoned.
For the LDR Scenario, the assumed compliance practice is disposal in an on-/off-site Subtitle
C incinerator. Storage and treatment units will be retrofitted with secondary containment
systems to meet Subtitle C accumulation storage and treatment tank regulations. Discharge
of flushing waters to on-site wastewater treatment systems will be continued because of a
3-19
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"headwater exemption^ provided for waste-derived sludges from wastewater treatment
systems that are not already hazardous due to a previous listing. The practice of disposing
this waste in land treatment and disposal surface impoundment units will be abandoned.
For the Contingent Management Scenario, the assumed compliance practice is disposal in a
Subtitle D land treatment unit with run-on/run-off controls. Storage and treatment units will
be retrofitted with secondary containment systems to meet Subtitle C accumulation storage
and treatment tank regulations. Discharge of flushing waters to on-site wastewater treatment
systems will be continued because of a "headwater exemption" provided for waste-derived
sludges from wastewater treatment systems that are not already hazardous due to a previous
listing. The practice of disposing this waste in disposal surface impoundment units will be
abandoned.
2. K170 - Clarified slurry oil sludge from catalytic cracking
The most common residual disposal method for clarified slurry oil sludge from catalytic
cracking is disposal in an off-site Subtitle D or C landfill. Pressure filtration/centrifuging is
a common residual treatment method. Other treatment methods include on-site industrial
flare, washing with distillate, sludge thickening or de-watering, settling, filtration, thermal
emulsion breaking, land treatment, discharge to on-site wastewater treatment facility, drying
on a pad, and stabilization. Other disposal methods include disposal in an on-site Subtitle D
landfill.
For the Listing Scenario, the assumed compliance practice is disposal in an on-/off-site
Subtitle C landfill. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
Discharge of flushing waters to on-site wastewater treatment systems will be continued
because of a "headwater exemption" provided for waste:derived sludges from wastewater
treatment systems that are not already hazardous due to a previous listing. The practice of
disposing this waste in land treatment and on-site Subtitle D landfill units will be abandoned.
For the LDR Scenario, the assumed compliance practice is disposal in an on-/off-site Subtitle
C incinerator. Storage and treatment units will be retrofitted with secondary containment
systems to meet Subtitle C accumulation storage and treatment tank regulations. Discharge
of flushing waters to on-site wastewater treatment systems will be continued because of a
"headwater exemption" provided for waste-derived sludges from wastewater treatment
systems that are not already hazardous due to a previous listing. The practice of disposing
this waste in land treatment and on-site Subtitle D landfill units will be abandoned.
3-20
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TABLE 3.4
SUMMARY OF BASELINE AND LISTING COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Mgmt
Code(<)
Wastes Managed
Compliance Management Practice (b)
RESIDUAL STORAGE METHODS '
Tank
Container (e.g., drum)
Pile
Roll-on/Roll-off Bin
Other
01-A
01-B
01 -C
01-E
01-F
K169, K170, K171, K172
K169, K170, K171, K172
K169, K170, K172
K169, K170, K171, K172
K169, K170, K171, K172
Upgrade to Subtitle C accumulation storage tank
Upgrade to Subtitle C accumulation container storage area
Clear waste pile and recommission for non-hazardous waste use and
replace with Subtitle C accumulation roll-on/roll-oft bin storage area
Upgrade to Subtitle C accumulation roll-on/roll-off bin storage area
Assumed similar to roll-on/roll-off bin storage practice; upgrade to
Subtitle C accumulation roll-on/roll-off bin storage area
RESIDUAL TREATMENT METHODS
On-site Industrial Furnace
Other On-site Thermal
Treatment
Off-site Incineration
Washing with Distillate
Washing with Water
Other Cleaning/Extraction
Sludge Thickening
02-E
02-F
03 -A
04-C
04-D
04-E
05-A
K170
K169
K169, K171
K169, K170
K169
K171, K172
K169, K170
Ship off site to Subtitle C BIF
Ship off site to Subtitle C BIF
Ship off site to Subtitle C incinerator
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
3-21
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TABLE 3.4 (CONTINUED)
SUMMARY OF BASELINE AND LISTING COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Sludge De-watering
Settling
Filtration
Pressure Filtration/Centriftiging
Chemical Emulsion Break
Thermal Emulsion Break
Other Phase Separation
On-site Land Treatment
Pit-site Land Treatment
Discharge to On-site WWT
Facility
Drying on a Pad
On-site Oxidation of Pyrophoric
Material
On-site Stabilization
Mgmt
Code(>)
05-B
05-C
05-D
05-E
05-F
05-G
05 -J
06-A
06-B
07
08
10
H-A
Wastes Managed
K169, KI70
K169, KI70
K169, K170
K169, K170
K169
KI69, K170
K169, K171, K172
K169, K170, K171
KI69, KI70
K169, K170
K169, K170
K17I, K172
K169, K170, IQ71, K172
Compliance Management Practice ""
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment lank
Abandon land treatment unit; ship off site to Subtitle C landfill
Ship off site to Subtitle C landfill
Same as baseline if conducted in wastewater treatment tank system
discharging to NPDES outfall or POTW because of "headwaters
exemption;" upgrade to Subtitle C accumulation treatment tanks
discharging to on-site injection well or on-site disposal impoundment
Clear drying pad and recommission for non-hazardous waste use and
replace with Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
Upgrade to Subtitle C accumulation treatment tank
3-22
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TABLE 3.4 (CONTINUED)
SUMMARY OF BASELINE AND LISTING COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Off-site Stabilization
Other Treatment
Mgmt
Code*"
11-B
13
Wastes Managed
K171
K169
Compliance Management Practice (b|
Ship off site to Subtitle C stabilization
Upgrade to Subtitle C accumulation treatment tank
RESIDUAL RECYCLE METHODS
On-site Coker
On-site Catalytic Cracker
On-site Distillation
On-site Asphalt Production Unit
On-site Replacement Catalyst
for Another Unit
On-site Nonprecious Metal
Catalyst
Reclamation/Regeneration
14- A
14-B
14-C
14-D
14-E
14-G
K169, K170
K169, K170
K169, K170
K169, K170
K17I
K171
Oil-bearing residuals that are generated at petroleum refineries and
are reinserted into petroleum refining processes are exempt from
Subtitle C storage, transportation, and management regulation.
Oil-bearing residuals that are generated at petroleum refineries and
are reinserted into petroleum refining processes are exempt from
Subtitle C storage, transportation, and management regulation.
Oil-bearing residuals that are generated at petroleum refineries and
are reinserted into petroleum refining processes are exempt from
Subtitle C storage, transportation, and management regulation.
Ship off site to Subtitle C BIF
Catalyst residuals that are generated at petroleum refineries and are
reinserted into petroleum refining processes are exempt from
Subtitle C storage, transportation, and management regulation.
Catalyst residuals that are generated at petroleum refineries and are
reinserted into petroleum refining processes are exempt from
Subtitle C storage, transportation, and management regulation.
Spent catalyst residuals that can no longer be regenerated are
shipped off site to Subtitle C landfill.
3-23
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TABLE 3.4 (CONTINUED)
SUMMARY OF BASELINE AND LISTING COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Other On-site Recovery
Other On-site or Off-site
Recycling/Reclamation/Reuse
Mgmt
Code<"
14-1
15
Wastes Managed
K171
K169, K170, K171, K172
Compliance Management Practice lb|
i
If description provided, assigned most similar recycling practice .
listed above. If no description provided, assigned most frequently
reported recycling practice for that waste stream.
If description provided, assigned most similar recycling practice
listed above. If no description provided, assigned most frequently
reported recycling practice for that waste stream
RESIDUAL TRANSFER METHODS
Transfer of Off-site Precious or
Nonprecious Metal Catalysts for
Reclamation/Regeneration
Transfer For Off-site Direct
Use as a Fuel or to Make a
Fuel
Transfer with Coke Product or
Other Refinery Product
Transfer for Use as Ingredient
in Products that are Placed on
the Land
16-A
16-B
16-C
16-E
K171.K172
K169, K170
K169, K170
K169
Metal recovery management practices are exempt. Residuals from
these reclamation/regeneration practices are "waste-derived" and not
exempt from RCRA Subtitle C storage, transportation, and/or
management when they are used to produce or contained in products
that are applied to or placed on land, involve speculative
accumulation of metals, or partial reclamation of metals.
Ship off site to Subtitle C BIF
Residuals are assumed to be product materials and exempt from
Subtitle C storage, transportation, and management requirements.
Ship off site to Subtitle C BIF
3-24
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TABLE 3.4 (CONTINUED)
SUMMARY OF BASELINE AND LISTING COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Transfer to Other Off-site Entity
Mgmt
Code1"
16-G
Wastes Managed
K169, K17I
Compliance Management Practice (b|
Assigned the most commonly reported transfer practice listed above (
for that waste stream.
RESIDUAL DISPOSAL METHODS
NPDES
Off-site Municipal Subtitle D
Landfill
Off-site Industrial Subtitle D
Landfill
Off-site Subtitle C Landfill
On-site Subtitle D Landfill
On-site Subtitle C Landfill
On-site Surface Impoundment
17- A
17-D
17-E
17-F
18-A
18-B
18-D
K169
K169, K170, K171
K169, K170, K171, K172
K169, K170, K171, K172
K170, K171, K172
K169, KI71, K172
K169
Same as baseline
Ship off site to Subtitle C landfill
Ship off site to Subtitle C landfill
Same as baseline
Ship off site to Subtitle C landfill
Same as baseline
Discontinue practice of discharging these sludges to a disposal
surface impoundment; Dredge impoundment and recominission for
non-hazardous waste use; Construct on site Subtitle C filtration unit
and ship sludge residuals to off site Subtitle C landfill
'"' Management code corresponds to the coding system used in the 1992 RCRA Section 3007 Survey.
-------
TABLE 3.5
SUMMARY OF BASELINE AND LDR COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
LDR Compliance Management Practice
RESIDUAL STORAGE METHODS
Waste Pile
Other
01 -C
01-F
K169, K170, K172
K169, K170, K171, K172
Assumed, because of economics, the waste pile was abandoned in
anticipation of LDR regulations under the listing compliance management
practice; Same as listing compliance management practice
Assumed practice conducted in tanks, no LDR impact
RESIDUAL TREATMENT METHODS
On-site Land Treatment
Off-site Land Treatment
Discharge to On-site WWT
Facility
Drying on a Pad
Other Treatment
06 -A
06-B
07
08
13
K169, K170, K171
K169, K170
K169, K170
K169, K170
K169
Assumed, because of economics, the land treatment unit was abandoned in
anticipation of LDR regulations under the listing compliance management
practice; Oil-based wastes will require combustion in an incinerator/EMF;
Metal-based wastes will require Subtitle C incineration followed by
vitrification and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wastes will require combustion in an incinerator/BIF
A "headwaters exemption" has been granted for oil-based sludges
(flushing waters) discharged to on-site wastewater treatment system; no
LDR impact
Assumed, because of economics, the drying pad was cleared and
recommissioned for non-hazardous waste use in anticipation of LDR
regulations under the listing compliance management practice; Same as
listing compliance management practice
Assumed conducted in tanks; no LDR impact
3-26
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TABLE 3.5 (CONTINUED)
SUMMARY OF BASELINE AND LDR COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
LDR Compliance Management Practice
RESIDUAL DISPOSAL METHODS
Off-site Municipal Subtitle D
Landfill
Off-site Industrial Subtitle D
Landfill
Off-site Subtitle C Landfill
On-site Subtitle D Landfill '
On-site Subtitle C Landfill
On-site Surface Impoundment
17-D
17-E
17-F
18-A
18-B
18-D
K169, K170, K17I
K169, K170, K171, K172
K169, K170, K17I, K172
K170, K171, K172
K169, K171, K172
K169
Oil-based wastes will require combustion in an incinerator/BIF; Metal-
based wastes will require Subtitle C incineration followed by vitrification
and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wastes will require combustion in an incinerator/BIF; Metal-
based wasles will require Subtitle C incineration followed by vitrification
and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wasles will require combustion in an incinerator/BIF; Metal-
based wastes will require Subtitle C incineration followed by vitrification
and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wastes will require combustion in an incinerator/BIF; Metal-
based wastes will require Subtitle C incineration followed by vitrification
and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wastes will require combustion in an incinerator/BIF; Metal-
based wastes will require Subtitle C incineration followed by vitrification
and Subtitle C landfill of ash or will be reclaimed in metals
reclamation/regeneration units
Oil-based wastes will require combustion in an incinerator/BIF
3-27
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TABLE 3.6
SUMMARY OF BASELINE AND CONTINGENT MANAGEMENT COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Mgmt
Code(1)
Wastes Managed
Contingent Management Compliance Management Practice
RESIDUAL STORAGE METHODS
Waste Pile
Other
01 -C
01-F
K169, K170, K172
K169, K170, K171, K172
Assumed, because of economics, the waste pile was abandoned in
anticipation of LDR regulations under the listing compliance management
practice; Crude oil sludges will be disposed in Subtitle D land treatment
units with run-on/run-off controls; CSO sludges will be disposed in
Subtitle D land treatment units with run-oii/run-off controls or Subtitle D
landfill units; Metal-based wastes will be reclaimed in metal catalyst
reclamation/regeneration units
Assumed practice conducted in tanks, no contingent management impact
RESIDUAL TREATMENT METHODS
On-site Land Treatment
Off-site Land Treatment
Discharge to On-site WWT
Facility
06-A
06-B
07
K169, K170, K171
K 169, K 170
K169, K170
Crude oil sludges and CSO sludges will be disposed in Subtitle D land
treatment units with run-on/run-off controls; Metal-based wastes will be
reclaimed in metal catalyst reclamation/regeneration units; For metal-
based wastes, because of economics, the land treatment unit was
abandoned in anticipation of LDR regulations under the listing compliance
management practice;
Crude oil sludges and CSO sludges will be disposed in Subtitle D land
treatment units with run-on/run-off controls;
A "headwaters exemption" has been granted for oil -based sludges
(flushing waters) discharged to on-site wastewater treatment system; No
contingent management impact
3-28
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TABLE 3.6 (CONTINUED)
SUMMARY OF BASELINE AND CONTINGENT MANAGEMENT COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
Drying on a Pad
Other Treatment
Mgmt
Code(t)
08
13
Wastes Managed
K169, K170
K169
Contingent Management Compliance Management Practice
Assumed, because of economics, the drying pad was cleared and >
recommissioned for non-hazardous waste use in anticipation of LDR
regulations under the listing compliance management practice; Same as
listing compliance management practice
Assumed conducted in tanks; no contingent management impact
RESIDUAL DISPOSAL METHODS
Off-site Municipal Subtitle D
Landfill
Off-site Industrial Subtitle D
Landfill
Off-site Subtitle C Landfill
On-site Subtitle D Landfill
17-D
17-E
17-F
18-A
KI69, K170, K171
K169, K170, K171, K172
K169, K170, K171, K172
K170, K171, K172
Crude oil sludges will be disposed in Subtitle D land treatment units with
run-on/run-off controls; CSO sludges will be disposed in Subtitle D
landfill units; Metal-based wastes will be reclaimed in metal catalyst
reclamation/regeneration units
Crude oil sludges will be disposed in Subtitle D land treatment units with
run-on/run-off controls; CSO sludges will be disposed in Sub'title D
landfill units; Metal-based wastes will be reclaimed in metal catalyst
reclamation/regeneration units
Crude oil sludges will be disposed in Subtitle D land treatment units with
run-on/run-off controls; CSO sludges will continue to be disposed in
Subtitle C landfill units; Metal-based wastes will be reclaimed in metal
catalyst reclamation/regeneration units
CSO sludges will be disposed in Subtitle D landfill units; Metal-based
wastes will be reclaimed in metal catalyst reclamation/regeneration units
3-29
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TABLE 3.6 (CONTINUED)
SUMMARY OF BASELINE AND CONTINGENT MANAGEMENT COMPLIANCE WASTE MANAGEMENT PRACTICES
FOR THE PETROLEUM REFINING INDUSTRY
Baseline Management Practice
On-site Subtitle C Landfill
On-site Surface Impoundment
Mgmt
Code"'
18-B
18-D
Wastes Managed
K169, K171, K172
K169
Contingent Management Compliance Management Practice
Crude oil sludges will be disposed in Subtitle D land treatment units'with
run-on/run-oft controls; Metal-based wastes will be reclaimed in metal
catalyst reclamation/regeneration units
Crude oil sludges will be disposed in Subtitle D land treatment units with
run-on/run-off controls
Management code corresponds to the coding system used in the 1992 RCRA Section 3007 Survey.
3-30
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For the Contingent Management Scenario, the assumed compliance practice is disposal in a
Subtitle D land treatment unit with run-on/run-off controls or landfill. Storage and treatment
units will be retrofitted with secondary containment systems to meet Subtitle C accumulation
storage and treatment tank regulations. Discharge of flushing waters to on-site wastewater
treatment systems will be continued because of a "headwater exemption" provided for waste-
derived sludges from wastewater treatment systems that are not already hazardous due to a
previous listing.
3. K171 - Catalyst from catalytic hydrotreating
The most common residual disposal method for catalyst from catalytic hydrotreating is
disposal in an off-site Subtitle D or C landfill. Residual treatment methods include off-site
incineration, other cleaning/extraction, other phase separation, on-site land treatment, on-site
oxidation of pyrophoric material, and stabilization. Other disposal methods include disposal
in a on-site Subtitle D or C landfill.
For the Listing Scenario, the assumed compliance practice is disposal in an on-/off-site
Subtitle C landfill. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
Off-site combustion practices will be transferred to Subtitle C incineration units. The
practice of disposing this waste in on-site land treatment and Subtitle D landfill units will be"
abandoned.
For the LDR Scenario, the assumed compliance practice is either disposal in an off-site
Subtitle C incinerator followed by vitrification and Subtitle C landfill of the ash or metal
catalyst reclamation/regeneration. Storage and treatment units will be retrofitted with
secondary containment systems to meet Subtitle C accumulation storage and treatment tank
regulations. Off-site combustion practices will be transferred to Subtitle C incineration units.
The practice of disposing this waste in on-site land treatment and Subtitle D landfill units will
be abandoned.
For the Contingent Management Scenario, the assumed compliance practice is metal catalyst
reclamation/regeneration. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
Off-site combustion practices will be transferred to metal catalyst reclamation/regeneration
units. The practice of disposing this waste in on-site land treatment and Subtitle D landfill
units will be abandoned.
4. K172 - Catalyst from catalytic hydrorefining
The most common residual disposal method for catalyst from catalytic hydrorefining is
disposal in an off-site Subtitle D or C landfill. Residual treatment methods include other
cleaning/extraction, other phase separation, on-site oxidation of pyrophoric material, and
stabilization. Other disposal methods include disposal in an on-site Subtitle D or C landfill.
3-31
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For the Listing Scenario, the assumed compliance practice is disposal in an on-/off-site
Subtitle C landfill. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
The practice of disposing this waste in on-site Subtitle D landfill units will be abandoned.
For the LDR Scenario, the assumed compliance practice is either disposal in an off-site
Subtitle C incinerator followed by vitrification and Subtitle C landfill of the ash or metal
catalyst reclamation/regeneration. Storage and treatment units will be retrofitted with
secondary containment systems to meet Subtitle C accumulation storage and treatment tank
regulations. The practice of disposing this waste in on-site Subtitle D landfill units will be
abandoned.
For the Contingent Management Scenario, the assumed compliance practice is metal catalyst
reclamation/regeneration. Storage and treatment units will be retrofitted with secondary
containment systems to meet Subtitle C accumulation storage and treatment tank regulations.
The practice of disposing this waste in on-site Subtitle D landfill units will be abandoned.
3.3.2 Current (Baseline) and Compliance Waste Management Costs
Frequently, several individual waste management methods make up the components of the -
waste management practice (i.e., waste management train) for storing, treating, recycling,
and disposing a waste stream. Because of the significant number of waste management trains
reported by the petroleum refining industry, current (baseline) and compliance management
costs were developed for the individual components of each waste management train. The
incremental difference in cost between the baseline and compliance management costs for
each individual component of the waste management train were summed together to develop
incremental compliance cost estimates for the complete waste management practice.
For example, Petroleum Refinery X generates 100 metric tons per year of crude oil tank
sludge. The current waste management train is to filter the oily sludge, recycling 60 metric
tons (MT) of oil filtrate back to the distillation unit, and storing 40 MT of filter sludge in
roll-on/roll-off bins within an accumulation container storage area prior to spreading the
sludge in an on-site Subtitle D land treatment unit. To comply with Subtitle C accumulation
treatment tank regulations, the filtration operation will require the construction and
maintenance of a secondary containment system underneath the filtration unit ($2,500/yr).
The cost for operating and maintaining the filtration unit will not change and a new filtration
unit will not need to be purchased ($0/yr). The 60 MT of oil filtrate recycled back to the
distillation unit is exempt from regulation under the "definition of solid waste". A recycled
oil credit is applied to the oil filtrate if the facility has not been de-oiling its sludges as a
baseline management practice (S110/MT credit; see Section 3.3.7 for waste minimization
discussion). To comply with Subtitle C accumulation container storage area regulations, a
new accumulation container storage area will need to be constructed and maintained
($4,800/yr). To comply with Subtitle C disposal regulations, the refinery will abandon the
3-32
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on-site land treatment-unit (S87/MT), choose not to construct an on-site Subtitle C land
treatment unit in anticipation of future LDR regulations that will mandate the closure of such
a unit, and transport and dispose the waste in an off-site Subtitle G landfill (S73/MT for
transport and S233/MT for Subtitle C landfill). Under the LDR Scenario, off-site Subtitle C
incineration (S92/MT for transport and S1,867/MT for Subtitle C incineration) will be the
required disposal method.
The following table (Table 3.7) demonstrates how the incremental compliance cost was
derived for the management of this waste stream. Incremental management costs for other
waste streams (e.g., CSO sludge and hydrotreating and hydrorefining catalysts) generated by
this refinery were calculated in a similar manner with compliance management practices
dependent upon the current waste management trains reported in the RCRA 3007 Survey for
these wastes. These waste stream-specific incremental compliance costs were then
aggregated into a total for the refinery. Incremental RCRA administrative compliance costs
(e.g., manifest system implementation, contingency plan and emergency procedures, and
permit applications) were added to the facility total.
3-33
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TABLE 3.7
DERIVATION OF INCREMENTAL COMPLIANCE COSTS
Baseline
Management
Filtration
Unit
Accumulation
Container
Storage Area
Recycle Oil
Filtrate to
Distillation
Unit
Disposal of
Filtration
Sludge
Compliance Cost
(A)
Construct Subtitle C
Filtration Unit
Secondary
Containment:
$2,500/yr
Construct Subtitle C
Accumulation
Container Storage
Area:
$4,800/yr
Recycled Oil Credit:
S110/MT * 60MT.
Transport to Off-Site
Subtitle C Landfill:
(S73/MT + S233/MT)
* 40 MT
Transport to Off-Site
Subtitle C Incineration:
(S92/MT +
$1,867/MT) * 40 MT
Baseline Cost
(B)
No Subtitle C
Secondary
Containment
Exists:
$0/yr
No Subtitle C
Accumulation
Storage Area
Exists:
$0/yr
Not Applicable
(Oily Sludge)
On-Site Land
Treatment:
$87/MT * 40 MT
Total Incremental Compliance Management Cost
Incremental
Compliance Cost
(A-B)
$2,500/yr
$4,800/yr
($6,600/yr)
Listing Scenario:
$8,760/yr
LDR and Listing
Scenario:
$74,880/yr
Listing Scenario:
$9,460/yr
.LDR and Listing
Scenario:
$75,580/yr
3-34
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Current Management Practices
Current waste management practice unit costs were provided in the 1992 RCRA 3007 Survey
by facilities in the petroleum refining industry. Where a facility did not report a unit cost,
an average cost was derived from the unit costs provided by other facilities using similar
management practices. If data were not available to derive an industry-based average unit
cost, EPA estimated a unit cost for the management practice.
Statistical tests were conducted on the reported industry unit costs for each baseline
management practice to identify outlier or extreme values. These outliers were
assumed to be reporting errors since they are significantly different (using a 95
percent confidence interval) from the unit costs provided by other facilities. Twenty
management unit costs unit costs provided by industry were not used because they
were determined to be statistical outliers for a given baseline management practice.
Costs reported by facilities as flat fees were not included in the average since these
expenses do not represent unit costs.
From the remaining list of industry-reported unit costs, average industry unit costs
were developed for the following baseline management practices:
- Off-site incineration
- On-site land treatment
- Off-site land treatment
- Off-site municipal Subtitle D landfill
- Off-site industrial Subtitle D landfill
- Off-site Subtitle C landfill
- On-site Subtitle D landfill
- On-site Subtitle C landfill
- Transfer of metal catalysts for reclamation/regeneration
- Transfer for use as a fuel- or to make a fuel
All unit costs are in 1992 dollars. These average industry unit costs were assigned to
facility-specific waste streams using these baseline management practices that had no
reported unit cost or had a reported unit cost which was identified as an outlier.
For all other baseline management practices, unless unit costs were reported, EPA
estimated unit costs. EPA estimated unit costs for the following baseline management
practices:
- On-site industrial furnace
- Off-site stabilization
- On-site disposal surface impoundment
- Transfer for use as an ingredient in products that are placed on the land
3-35
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Table 3.8 presents the*unit costs for each baseline management practice. The table is
organized by management practice, management code, and wastes managed. The cost
information in the table is labeled estimated or industry average.
The following list summarizes the major baseline waste management assumptions that EPA
used in developing the costs for the current waste management practices.
Wastes reported as being managed in an "invalid" baseline management method were
assumed, when possible, to be managed in the same way as other similar wastes at
the same facility. When this was not possible, the waste was assumed to be managed
in the most frequently used disposal or recycling method for that waste based on other
reporting facilities. If process recycling/metal catalyst reclamation was assumed, that
unit of the facility was removed from the analysis and no cost impact was included
due to its exemption from RCRA Subtitle C requirements under the definition of solid
waste.
Wastes reported as being managed in an "other" baseline management practice were
assumed to be managed by the most frequent method used by other reporting
facilities. For example, if "other on-site thermal treatment" was reported, the most
frequently used on-site thermal treatment was assumed. If "other treatment" was
reported, the most frequent of all types of treatment was assumed.
3-36
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TABLE 3.8
SUMMARY OF BASELINE MANAGEMENT UNIT COSTS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code"1
Wastes Managed
Unit Cost""
RESIDUAL STORAGE METHODS
Tank
Container (e.g., drum)
Pile
Roll-on/Rolhoff Bin
Other
01-A
01-B
OI-C
01-E
OI-F
K169, K170, K171, K172
K169, K170, K171, K172
K169, KI70, K172
K169, KI70, KI71, K172
K169, K170, KI7I, K172
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
RESIDUAL TREATMENT METHODS
On-site Industrial Furnace
Other On-site Thermal
Treatment
Off-site Incineration
Washing with Distillate
Washing with Water
02-E
02-F
03-A
04-C
04- D
KI70
KI69
KI69, K171
K169, K170
K169
Facilities Reporting Cost: 0
Facilities Not Reporting Cost: 1
Estimated: $50/MT
Facilities Reporting Cost: 1
Facilities Not Reporting Cost: 0
Facilities Reporting Cost: 25
Facilities Not Reporting Cost: 6
Industry Average: $1,867/MT
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
3-37
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TABLE 3.8 (CONTINUED)
SUMMARY OF BASELINE MANAGEMENT UNIT COSTS
(1992 Dollars)
Baseline Management Practice
Other Cleaning/Extraction
Sludge Thickening
Sludge De-watering
Settling
Filtration
Pressure Filtration/Centrifuging
Chemical Emulsion Break
Thermal Emulsion Break
Other Phase Separation
On-site Land Treatment
Off-site Land Treatment
Discharge to On-site WWT
Facility
Mgmt
Code'"
04-E
05-A
05-B
05-C
05-D
05-E
05-F
05 -G
05 -J
06-A
06-B
07
Wastes Managed
KI71, K172
K169, K170
K169, K170
K169, K170 -
K169, K170
KI69, K170
KI69
KI69, K170
K169, K171, K172
K169, K170, K171
K169, K170
K169, K170
Unit Cost""
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremenial cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Facilities Reporting Cost: 12
Facilities Not Reporting Cost: 13
Industry Average: $87/MT
Facilities Reporting Cost: 1 1
Facilities Not Reporting Cost: 1
Industry Average: $78/MT
Same as compliance, therefore, no incremental cost.
3-38
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TABLE 3.8 (CONTINUED)
SUMMARY OF BASELINE MANAGEMENT UNIT COSTS
(1992 Dollars)
Baseline Management Practice
Drying on a Pad
On-site Oxidation of Pyrophoric
Material
On-site Stabilization
Off-site Stabilization
Other Treatment
Mgmt
Code"1
08
10
ll-A
11-B
13
Wastes Managed
K169, K170
K171, K172
K169, K170, K171, K172
K171
K169
Unit Cost11"
Same as compliance, therefore, no incremental cost (c). .'
Same as compliance, therefore, no incremental cost (c).
Same as compliance, therefore, no incremental cost (c).
Facilities Reporting Cost: 1
Facilities Not Reporting Cost: 3
Estimated: $82/MT
Estimated or industry average of the industry's most frequent
management method for the same waste managed.
RESIDUAL TRANSFER METHODS
Transfer of Precious or
Nonprecious Metal Catalysts for
Reclamation/Regeneration
Transfer for Off-site Direct Use
as a Fuel or to Make Fuel
Transfer for Use as an
Ingredient in Products that are
Placed on the Land
16-A
16-B
16-E
K171, KI72
K169, K170
K169
Facilities Reporting Cost: 86
Facilities Not Reporting Cost: 28
Industry Average: $725/MT
Facilities Reporting Cost: 13
Facilities Not Reporting Cost: 6
Industry Average: $752/MT
Facilities Reporting Cost: 2
Facilities Not Reporting Cost: 1
Estimated: $50/MT
3-39
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TABLE 3.8 (CONTINUED)
SUMMARY OF BASELINE MANAGEMENT UNIT COSTS
(1992 Dollars)
Baseline Management Practice
Transfer to Off-site Entity
Mgmt
Code("
16-G
Wastes Managed
K169, K171
Unit Costlb)
Estimated or industry average of the industry's most frequent transfer
method for the same waste managed.
RESIDUAL DISPOSAL METHODS
NPDES
Off-site Municipal Subtitle D
Landfill
Off-site Industrial Subtitle D
Landfill
Off-site Subtitle C Landfill
On-site Subtitle D Landfill
17- A
17-D
17-E
17-F
18-A
KI69
K169, K170, K17I
K169, K170, K171, K172
K169, K170, K171, K172
KI70, K171, K172
Same as compliance, therefore, no incremental cost.
Facilities Reporting Cost: 24
Facilities Not Reporting Cost: 12
Industry Average: $52/MT
Facilities Reporting Cost: 59
Facilities Not Reporting Cost: 20
Industry Average: J58/MT
Facilities Reporting Cost: 60
Facilities Not Reporting Cost: 22
Industry Average: $233/MT
Facilities Reporting Cost: 13
Facilities Not Reporting Cost: 5
Industry Average: $49/MT
3-40
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TABLE 3.8 (CONTINUED)
SUMMARY OF BASELINE MANAGEMENT UNIT COSTS
(1992 Dollars)
Baseline Management Practice
On-site Subtitle C Landfill
On-site Surface Impoundment
Mgmt
Code'"
18-B
18-D
Wastes Managed
K169, K171, K172
K169
Unit Cost(b)
Facilities Reporting Cost: 4 ;
Facilities Not Reporting Cost: 3
Industry Average: $43/MT
Facilities Reporting Cost: 1
Facilities Not Reporting Cost: 2
Estimated: $|0/MT
"" Management code corresponds to the coding system used in the 1992 RCRA Section 3007 Survey.
"" EPA used the unit costs reported by facilities except when unit costs were determined to be statistical outliers for that practice. When unit costs were not
provided by the facility, EPA calculated an industry average based on unit costs reported by facilities, excluding outliers, where applicable or estimated unit costs
and cost equations. Unit costs that are industry averages or are estimated by EPA are identified in the table as industry average and estimated, respectively.
10 Management costs (i.e., operation and maintenance costs) for baseline and compliance are the same for this management method. Secondary containment is
not included in the baseline cost for all facilities. Secondary containment costs are the compliance costs for the facilities where required.
3-41
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Listing Management Practices
Unit costs, unit prices, and cost equations were developed to determine annualized costs for
alternative compliance waste management practices for each waste listing on a facility
specific basis. Costs, prices, and cost equations were obtained from the industry averages
derived from the 1992 RCRA 3007 Survey, previous listing determinations and land disposal
restrictions analyses. When necessary, cost estimates were developed specifically for this
rule using cost data from engineering cost documents.
Table 3.9 presents the unit costs for the compliance waste management practices. The
information in the table is organized similarly to Table 3.8. Incremental compliance costs
can be determined for each management practice by subtracting the baseline management
cost in Table 3.8 from the compliance management cost in Table 3.9. For example, the
incremental compliance cost for wastes currently managed in off-site municipal Subtitle D
landfills is S181/MT (S233/MT - $52/MT).
The following list summarizes the major waste management assumptions that EPA used in
developing the costs for the compliance waste management practices.
*
EPA-derived 1992 cost estimates were annualized assuming an interest rate of 7
percent over 20 years on a before-tax cost basis.
Existing disposal impoundments do not meet Subtitle C surface impoundment
minimum technological requirements and are, therefore, dredged with the sludges
being transported and disposed to an on-/off-site Subtitle D Landfill prior to the date
of final listing, and recommissioned for non-hazardous wastes use. The disposal
impoundments are replaced with on-site filtration and off-site Subtitle C landfill.
Facilities need to upgrade their storage areas to meet the Subtitle C container
accumulation (i.e., <90 day storage) requirements. Because wastes are stored for
<90 days, these storage areas do not need permits. Costs for container accumulation
areas are estimated using the cumulative waste generation amount within one year
(i.e., periodically generated wastes were not annualized) to reflect peak demand
conditions.
Facilities need to upgrade their storage/treatment tanks to meet the Subtitle C
accumulation (i.e., <90 day storage) tank requirements. Because wastes are
stored/treated for <90 days, these tanks do not need permits. Costs for accumulation
tanks are estimated using the cumulative waste generation amount within one year
(i.e., periodically generated wastes were not annualized) to reflect peak demand
conditions.
3-42
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TABLE 3.9
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'1'
Wastes Managed
Unit Cost or Cost Equation (bl
RESIDUAL STORAGE METHODS '
Tank
Container (e.g., drum)
01 -A
01-B
K169, K170, K171, K172
K169, K170, K171, K172
Upgrade to Subtitle C accumulation tank system:10
0-350 MT/yr $2,500/yr
350-1,040 MT/yr $2,700/yr
1 ,040-2 ,420 MT/yr $3 , 1 00/y r
2 ,420-5 , 1 80 MT/yr $3 ,600/y r
5, 180-8,640 MT/yr $4,100/yr
8,640-12, 100 MT/yr $4,600/yr
12, 100-16,730 MT/yr $5,000/yr
Upgrade to Subtitle C accumulation container storage area:"'
0-20 MT/yr $3,300/yr
20-70 MT/yr $4,600/yr
70-4,680 MT/yr $4,800/yr
4,680-9,360 MT/yr $6,100/yr
3-43
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Pile
Roll-on/Roll-off Bin
Other
Mgmt
Code"1
01-C
01-E
01-F
Wastes Managed
KI69, KI70, K172
K169, K170, K171, K172
K169, K170, K171, K172
Unit Cost or Cost Equation lbl
Construct new Subtitle C accumulation tank storage system:1'" '
0-350 MT/yr $3,800/yr
350-1,040 MT/yr $4,400/yr
1,040-2,420 MT/yr $5,600/yr
2, 420-5 ,180 MT/yr $7,400/yr
5, 180-8,640 MT/yr $8,900/yr
8,640-12,100 MT/yr $10,300/yr
12,100-16,730 MT/yr $ll,400/yr
16,730-19,010 MT/yr $12,4()0/yr
19,010-27,650 MT/yr $13,700/yr
27,650-43,200 MT/yr $17,100/yr
43, 200-69, 130 MT/yr $20,500/yr
Upgrade to Subtitle C accumulation container storage area:"'
0-20 MT/yr $3,300/yr
20-70 MT/yr $4,600/yr
70-4,680 MT/yr $4,800/yr
4,680-9,360 MT/yr $6,100/yr
Assume most common storage type reported by the industry for that
waste type.
3-44
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
Unit Cost or Cost Equation (bl
KLSIDUAL TREATMENT METHODS
On-site Industrial Furnace
Other On-site Thermal
Treatment
02-E
02-F
K170
K169
Listing or LDR Scenarios:
Estimated: $IOO/MT plus RCRA Part 264 and 270 administrative
costs to permit
Contingent Management Scenario:
See Management Code 06-A
See Management Code 02-E
3-45
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Off-site Incineration
Washing with Distillate
Washing with Water
Other Cleaning/Extraction
Mgmt
Code'"
03-A
04-C
04-D
04-E
Wastes Managed
K169, K171
K169, K170
K169
K171, K172
Unit Cost or Cost Equation (b)
Listing and LDR Scenarios:
Off-site Subtitle C industry average: $1,867/MT
LDR Scenario:
Construct new on-site Subtitle C incinerator:
0-35 MT/yr $640,000/yr
35-75 MT/yr $659,000/yr
75-125 MT/yr $686,000/yr
125-175 MT/yr $708,000/yr
175-225 MT/yr $728,000/yr
225-325 MT/yr $745,000/yr
325-750 MT/yr $820,000/yr
750-1, 250 MT/yr $938,000/yr
1 ,250- 1 ,750 MT/yr $ 1 ,039 ,000/y r
1 ,750 and over MT/yr $1,131 ,000/y r
Contingent Management Scenario:
K169 - See Management Code 06- A
K171 - See Management Code 16-A
See Management Code 01 -A
See Management Code 01 -A
See Management Code 01 -A
3-46
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Sludge Thickening
Sludge De-watering
Settling
Filtration
Pressure Filtration/Centrifuging
Chemical Emulsion Break
Thermal Emulsion Break
Other Phase Separation
Mgmt
Code'"
05-A
05-B
05-C
05-D
05-E.
05-F
05-G
05 -J
Wastes Managed
K169, K170
K169, K170
K169, K170
K169, K170
KI69, K170
K169
K169, K170
K169, K171, K172
Unit Cost or Cost Equation (b>
See Management Code 01-A .'
See Management Code 01-A
See Management Code 01-A
See Management Code 01-A
See Management Code 01-A for existing units
Waste Minimization Opportunity for Oily Sludges (see Section
3.3.7):
Construct new on-site Subtitle C pressure filtration/centrifuge unit:
0 - 350 MT/yr $3,300/yr
350 - 1,040 MT/yr $3,600/yr
1 ,040 - 2,420 MT/yr $4,200/yr
2,420 - 5,180 MT/yr $4,900/yr
See Management Code 01-A
See Management Code 01-A
See Management Code 01-A
3-47
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
Unit Cost or Cost Equation
On-site Land Treatment
06-A
K169, K170, K171
Listing Scenario:
Abandon on-sile land treatment unit and dispose waste in on-/off-
site Subtitle C Landfill (see Management Code 17-F for costs)
LDR Scenario:
K169, K170 - See Management Code 03-A
K171 - Option 1 See Management Code 03-A for incinerator
costs; Estimated vitrification cost is $240/MT; Option 2 See
Management Code 16-A
Contingent Management Scenario:
K169, KI70 - For existing units, no increase in cost due to
compliance if run-on/run-off controls exist; For new units,
construct on-site Subtitle D land treatment unit with run-on/run-ot'f
controls:
Estimated: $21/MT for on-site land treatment plus $2,200/yr for
run-on/run-off controls (size < 750 MT/yr) or $2,600/yr for
controls (size 750 - 1,500 MT/yr)
K171 - See Management Code 16-A
3-48
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Off-site Land Treatment
Discharge to On-site WWT
Facility
Drying on a Pad
On-site Oxidation of Pyrophoric
Material
On-site Stabilization
Off-site Stabilization
Other Treatment
Mgmt
Code"'
06-B
07
08
10
11-A
11-B
13
Wastes Managed
K169, K170
K169, K170
K169, K170
K17I, K172
K169, K170, K171, K172
K171
K169
Unit Cost or Cost Equation (b>
Listing Scenario:
Ship to off-site Subtitle C landfill (see Management Code 17-F for
costs)
LDR Scenario:
Ship to off-site Subtitle C incinerator (see Management Code 03-A)
Contingent Management Scenario:
No increase in cost due to compliance
i The headwaters exemption results in no increase in cost due to
compliance for wastewaters discharged to NPDES or POTW; If
wastewater is discharged into on-site disposal impoundment then
wastewater treatment system tanks require upgrading to Subtitle C
accumulation tank systems (see Management Code 01 -A for costs)
See Management Code 01-C
See Management Code 01 -A
See Management Code 01-A
Estimated: $75/MT
See Management Code 01-A
3-49
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code"'
Wastes Managed
Unit Cost or Cost Equation ""
RESIDUAL TRANSFER METHODS .'
Transfer of Precious or
Nonprecious Metal Catalysts for
Reclamation/Regeneration
Transfer to Non-Petroleum
Refinery for Direct Use as a
Fuel or to Make a Fuel
Transfer for Use as an
Ingredient in Products that are
Placed on the Land
Transfer to Other Off-site Entity
16-A
16-B
16-E
16-G
K171, K172
K169, K170
K169
K169, K17I
Assume a 5 percent increase in the baseline price passed back to
refiners for increased Subtitle C storage, transportation, and
management costs incurred from waste-derived residuals at metal
reclamation/regeneration facilities.
Estimated: $180/MT
Estimated: $180/MT
Assume most common reported transfer method reported by
industry for each waste type.
RESIDUAL DISPOSAL METHODS
NPDES
Off-site Municipal Subtitle D
Landfill
Off-site Industrial Subtitle D
Landfill
17- A
17-D
17-E
K169
K169, K170, K171
K169, K170, K171, K172
No increase in cost due to compliance
See Management Code 18-A
See Management Code 18-A
3-50
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'1'
Wastes Managed
Unit Cost or Cost Equation (b)
Off-site Subtitle C Landfill
17-F
K169, K170, K171, K172
Listing Scenario:
Off-site Subtitle C Industry Average: J233/MT
LDR Scenario:
K169, K170 - See Management Code 03-A
K171, K172 - Option 1 -- See Management Code 03-A for
incinerator costs; Estimated vitrification cost is $240/MT; Option 2
-- See Management Code 16-A
Contingent Management Scenario:
K169 - See Management Code 06-A
K170 - No increase in cost due to compliance
KI71 - See Management Code 16-A
3-51
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
Unit Cost or Cost Equation (b)
On-site Subtitle D Landfill
18-A
K170, K171, K172
Listing Scenario:
See Management Code 17-F
LDR Scenario:
K169, KI70 - See Management Code 03-A
K171, KI72 - Option 1 -- See Management Code 03-A for
incinerator costs; Estimated vitrification cost is $240/MT; Option 2
-- See Management Code 16-A
Contingent Management Scenario:
K169 - See Management Code 06-A
K170 - No increase in cost due to compliance
K171, K172 -See Management Code 16-A
3-52
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
Mgmt
Code'"
Wastes Managed
Unit Cost or Cost Equation (b)
On-site Subtitle C Landfill
18-B
K169, K17I, K172
Listing Scenario:
No increase in cost due to compliance
LDR Scenario:
K169 - See Management Code 03-A
KI71, K172 - Option 1 -- See Management Code 03-A for
incinerator costs; Estimated vitrification cost is $240/MT; Option 2
See Management Code 16-A
Contingent Management Scenario:
K169 - See Management Code 06-A
KI71, K172 - See Management Code 16-A
3-53
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TABLE 3.9 (CONTINUED)
SUMMARY OF COMPLIANCE MANAGEMENT UNIT COSTS AND COST EQUATIONS
(1992 Dollars)
Baseline Management Practice
On-site Surface Impoundment
Mgmt
Code(t)
18-D
Wastes Managed
KI69
Unit Cost or Cost Equation (b)
One-lime dredging of impoundment sludge and disposal in off-site '
Subtitle D Landfill at $90/MT prior to final listing and then
recommission impoundment for non-hazardous waste use; Manage
sludge using upgrade of existing on-site filtration system (see
Management Code 01 -A for costs)
Listing Scenario:
Dispose in off-site Subtitle C landfill (see Management Code 17-F
for costs).
LDR Scenario:
See Management Code 03-A
Contingent Management Scenario:
See Management Code 06-A
'" Management code corresponds to the coding system used in the 1992 RCRA Section 3007 Survey.
(b) EPA used the unit costs reported by facilities except when unit costs were determined to be statistical outliers for that practice. When unit costs were not
provided by the facility, EPA calculated an industry average based on unit costs reported by facilities, excluding outliers, where applicable or estimated unit costs
and cost equations. Unit costs that are industry averages or are estimated by EPA are identified in the table as industry average and estimated, respectively.
(c> Management costs (i.e., operation and maintenance costs) for baseline and compliance are the same for this management method. Secondary containment is
not included in the baseline cost for all facilities. Secondary containment costs are the compliance costs for the facilities where required.
ld) Management costs (i.e., O&M costs) for baseline and compliance are the same for this management method. Secondary containment is not included in the
baseline cost for all facilities. The compliance cost will involve closure of the drying pad and construction of a drying tank system with secondary containment.
3-54
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Sludges and "spent catalysts are managed by Subtitle C landfill. The two options for
Subtitle C landfill are 1) off-site (i.e., commercial transport and disposal) and 2) on-
site landfill. EPA assumed the industry average of S233/MT for off-site Subtitle C
landfill reported by the petroleum refining industry and S73/MT for transport by truck
with dumpsters. On-site landfilling is economical only for those facilities generating
_>_2,300 Mton/year of metal-based residuals (i.e., spent catalysts) only, assuming that
LDR regulations will require incineration of oil-based residuals. In the Listing
Scenario, which allows landfill as an option for oil-based residuals, no facilities
generate enough waste to construct an on-site landfill.
There are no additional compliance costs, only additional revenues for facilities
currently recycling residuals back into their process units. For some metal catalyst
regeneration/reclamation processes, waste-derived residuals are not exempt from
RCRA Subtitle C storage, transportation, and/or management requirements.
Appendix A presents the annual before-tax incremental compliance costs for the Listing
Scenario. Incremental compliance costs range from $4 million to $16 million per year. The
expected value for the listing option is $8 million per year.
LDR Management Practices
Table 3.9 presents the unit costs for the LDR compliance waste management practices.
The following list summarizes the major waste management assumptions that EPA used in
developing the costs for the LDR compliance waste management practices.
EPA-derived 1992 cost estimates were annualized assuming an interest rate of 7
percent over 20 years on a before-tax cost basis..
Oil-based residuals (crude and CSO tank sludges) are managed by Subtitle C
incineration. The two options for Subtitle C incineration are 1) off-site (i.e.,
commercial transportation and incineration) and 2) on-site incineration. EPA assumed
the industry average of $1,867/MT for off-site incineration reported by the petroleum
refining industry and S163/MT for truck transport of drummed wastes. On-site
incineration is economical only for those facilities generating ,>.415 Mton/year of
waste. Eight facilities, which are currently in the RCRA program, generate enough
waste to construct new on-site incinerators. Two facilities will permit an existing on-
site incinerator. Two facilities have existing permitted on-site incinerators. Two
facilities that generate enough waste, which are not in the RCRA program and do not
have existing on-site incinerators are assumed to ship their waste to an off-site
incinerator. EPA assumes that these two facilities will choose to avoid potential
corrective action costs which are triggered when a facility applies for a RCRA Part B
permit.
3-55
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Metal-based residuals (spent catalysts) are managed by Subtitle C incineration
followed by vitrification and Subtitle C landfill of the ash or are managed in metal
catalyst reclamation/regeneration units. The two options for are 1) off-site Subtitle C
incineration followed by Subtitle C vitrification and Subtitle C landfill of the ash and
2) metal catalyst reclamation/regeneration. EPA assumed the industry average of
$1,867/MT for off-site Subtitle C incineration and ash disposal reported by the
petroleum refining industry and S163/MT for truck transport of drummed wastes, and
S240/MT for Subtitle C vitrification. EPA assumed an industry average of S725/MT
for off-site transfer of precious or nonprecious metal catalysts for
reclamation/regeneration.
Appendix B presents the before-tax incremental compliance costs for the combined affect of
the listing and LDR waste management practices (LDR Scenario) for high-cost and low-cost
options. The high-cost LDR option assumes all affected oil-based sludge residuals will be
incinerated off-site and all metal catalyst residuals will be combusted in a Subtitle C
incinerator followed by Subtitle C vitrification and Subtitle C landfill of the ash off site. The
low-cost LDR option assumes on- and off-site incineration of oil-based sludge residuals
depending on the economic viability of constructing a unit on site and off-site
reclamation/regeneration of metal catalyst residuals. Incremental compliance costs range
from $21 million to $101 million per year. The expected value for the high-cost LDR option
is $61 million per year and for the low-cost option it is $41 million per year.
Contingent Management Practices
Table 3.9 presents the unit costs for the compliance waste management practices.
The following list summarizes the major waste management assumptions that EPA used in
developing the costs for the contingent compliance management waste management practices.
For CSO sludges, if the waste is currently managed in a Subtitle D landfill it will
continued to be managed in this unit. Otherwise, the waste will be managed in an
existing or newly constructed on-site land treatment unit with run-on/run-off controls
unless the waste is currently managed in an off-site land treatment unit, where the
practice is assumed to be continued.
Under the second option, crude oil sludges will be managed in an existing or newly
constructed on-site land treatment unit with run-on/run-off controls unless the waste is
currently managed in an off-site land treatment unit, where the practice is assumed to
be continued. Cost savings (benefits - approximately $200,000 in annual savings)
result from the switch from Subtitle D and C landfill practices to Subtitle D land
treatment units with run-on/run-off controls.
3-56
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Appendix C presents the before-tax incremental compliance costs for the Contingent
Management Scenario for the high-cost and low-cost options. The high-cost contingent
management option assumes that crude oil sludges will be incinerated on or off site
depending on the economic viability of constructing an incinerator on site. CSO sludges are
managed in either a Subtitle D land treatment unit with run-on/run-off controls or a Subtitle
D landfill. The low-cost option assumes crude oil sludges are managed in Subtitle D land
treatment units with run-on/run-off controls. Metal catalysts are reclaimed/regenerated off
site under both options. Incremental compliance costs range from $3 million to $42 million
per year. The expected value for the high-cost contingent management option is $24 million
per year and for the low-cost option it is $6 million per year.
3.3.3 Current (Baseline) and Compliance Waste Transportation Costs
Current waste transportation practice unit costs were provided in the 1992 RCRA 3007
Survey by facilities in the petroleum refining industry. Where a facility did not report a unit
cost, an average cost was derived from the unit costs provided by other facilities using
similar transportation practices. If data were not available to derive an industry-based
average unit cost, EPA estimated a unit cost for the transportation practice. These unit costs
also were used for compliance cost estimates. For example, incremental compliance costs
for wastes currently transported by truck in drums to a Subtitle D landfill, which now will be
managed in a Subtitle C landfill, are S189/MT ($224/MT-$45/MT). Note that these
industry-average unit costs reflect the average distance the industry is transporting their
wastes.
Statistical tests were conducted on the reported industry unit costs for each baseline
transportation practice to identify outlier or extreme values. These outliers were
assumed to be reporting errors since they are significantly different (using a 95
percent confidence interval) from the unit costs provided by other facilities. Eight
transportation unit costs provided by industry were not used because they were
determined to be statistical outliers for a given baseline transportation practice. Costs
reported by facilities as flat fees were not included in the average since these expenses
do not represent unit costs.
From the remaining list of industry-reported unit costs, average industry unit costs
were developed for the following baseline transportation practices:
- Truck with drums to Subtitle D landfill
- Truck with dumpsters to Subtitle D landfill
- Truck with a bed to Subtitle D landfill
- Tanker truck to Subtitle D landfill
- Truck with other container to Subtitle D landfill
- Truck with drums to Subtitle C landfill
- Truck with dumpsters to Subtitle C landfill
- Truck with a bed to Subtitle C landfill
3-57
-------
- Tanker truck to Subtitle C landfill
- Truck with other container to Subtitle C landfill
- Truck with drums to incinerator
- Truck with dumpsters to incinerator
- Truck to facility for direct use as a fuel or to make a fuel
- Truck with drums to catalyst regenerator
- Truck with dumpsters to catalyst regenerator
All unit costs are in 1992 dollars. These average industry unit costs were assigned to
those facilities using these baseline transportation practices that had no reported unit
cost or had a reported unit cost which was identified as an outlier.
For all other baseline transportation practices, unless unit costs were reported, EPA
estimated unit costs. EPA estimated unit costs for the following baseline
transportation practices:
- Truck to industrial furnace
- Barge
- Pipeline
No additional transportation practices are assumed for compliance. Applicable . '
baseline transportation costs also were used for compliance transportation costs.
Table 3.10 presents the unit costs for each baseline and compliance transportation practice.
The table is organized by transportation practice, transportation code, and wastes managed.
The cost information in the table is labeled estimated or industry average.
The following list summarizes the major baseline waste transportation assumptions that EPA
used in developing the costs for the current waste transportation practices.
Wastes reported as being transported in an "invalid" baseline transportation method
were assumed, when possible, to be transported in the same way as other similar
wastes with similar management methods at the same facility. When this was not
possible, the waste was assumed to be transported in the most frequently used
transportation method for that waste based on other reporting facilities.
Wastes reported as being transported in an "other" baseline transportation method
were assumed to be transported by the most frequent method used by other reporting
facilities.
3-58
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TABLE 3.10
SUMMARY OF BASELINE/COMPLIANCE TRANSPORTATION UNIT COSTS
FOR THE PETROLEUM REFINING INDUSTRY
(1992 Dollars)
Baseline
Transportation
Practice
Tran.
Code
Wastes Managed
Unit Cost
Truck
TR-2
K169, K170, K171, K172
Subtitle D landfill
Facilities Reporting Cost: 82
Facilities Not Reporting Cost: 76
Industry Average:
Truck with drums: S45/MT
Truck with dumpsters: S27/MT
Truck with bed: S17/MT
Tanker truck: S55/MT
Truck with other container: S72/MT
Subtitle C landfill
Facilities Reporting Cost: 62
Facilities Not Reporting Cost:
18
Industry Average:
Truck with drums: S224/MT
Truck with dumpsters: S73/MT
Truck with bed: S47/MT
Tanker truck: S123/MT
Truck with other container: S178/MT
3-59
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TABLE 3.10 (CONTINUED)
SUMMARY OF BASELINE/COMPLIANCE TRANSPORTATION UNIT COSTS
FOR THE PETROLEUM REFINING INDUSTRY
(1992 Dollars)'1"
Baseline
Transportation
Practice
Tran.
Code
Wastes Managed
Unit Cost
Truck (con't)
TR-2
Incineration
Facilities Reporting Cost: 17
Facilities Not Reporting Cost: 4
Industry Average:
Truck with drums: S163/MT
Truck with dumpster: S92/MT
Industrial furnace
Facilities Reporting Cost: 2
Facilities Not Reporting Cost: 0
Estimate: (Truck) S47/MT
Reclamation/Regeneration
Facilities Reporting Cost: 84
Facilities Not Reporting Cost: 37
Industry Average:
Truck with drums: S95-S167/MT
Truck with dumpster: S74/MT
Truck with other container: $80
S129/MT
Direct Use as Fuel or to Make a Fuel
Facilities Reporting Cost: 13
Facilities Not Reporting Cost: 4
Industry Average: S102/MT
Use as an Ingredient in Product Land
Applied
Facilities Reporting a Cost: 5
Facilities Not Reporting a Cost: 1
Industry Average: S34/MT
3-60
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TABLE 3.10 (CONTINUED)
SUMMARY OF BASELINE/COMPLIANCE TRANSPORTATION UNIT COSTS
FOR THE PETROLEUM REFINING INDUSTRY
(1992 Dollars)*'
Baseline
Transportation
Practice
Barge
Ship
Pipeline
Tran.
Code
TR-3
TR-4
TR-5
Wastes Managed
K171
K169
K169
Unit Cost
Facilities Reporting Cost: 2
Facilities Not Reporting Cost: 1
Estimated: S300/MT
Facilities Reporting Cost: 3
Facilities Not Reporting Cost: 0
Facilities Reporting Cost: 1
Facilities Not Reporting Cost: 9
Estimate: SO/MT
(1) Management code corresponds to the coding system used in the 1992 RCRA Section 3007 Survey.
""' EPA used the unit costs reported by facilities except when unit costs were determined to be statistical outliers for
that practice. When unit costs were not provided by the facility, EPA calculated an industry average based on unit
costs reported by facilities, excluding outliers, where applicable or estimated unit costs and cost equations. Unit
costs that are industry averages or are estimated by EPA are identified in the table as industry average and estimated,
respectively.
3-61
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3.3.4 RCRA Administrative Compliance Costs
Facilities generating and managing listed hazardous wastes are subject to Parts 262. 264,
266, and 270 of RCRA. RCRA administrative compliance activities for each of these pans
are briefly described below.
RCRA Part 262 standards regulate generators of hazardous waste. All facilities producing a
newly listed waste are subject to this part. There are four subparts to the Part 262 standards.
First, those facilities generating hazardous waste must obtain an EPA identification number.
Second, an approved manifest system must be established for those facilities shipping wastes
off site. Third, before transporting hazardous waste off site, a series of pre-transport
requirements must be satisfied such as labeling, marking, and placarding. Fourth, specified
recordkeeping and reporting requirements are applicable.
RCRA Part 264 standards apply to owners/operators of hazardous waste treatment, storage,
and disposal facilities. Facilities seeking compliance after listing through use of a new on-
site Subtitle C landfill or incinerator will be subject to this part. Part 264 has six applicable
subparts which address general facility standards (Subpart B); preparedness and prevention
(Subpart C); contingency plan and emergency procedures (Subpart D); manifest systems,
recordkeeping, and reporting (Subpart E); closure (Subpart G); and financial requirements
(Subpart H).
RCRA part 266 includes standards for the management of specific hazardous wastes and
specific types of hazardous waste management facilities. Facilities seeking compliance after
listing through the use of on-site boilers and industrial furnaces (BIFs) will be subject to this
part. The requirements for BIFs are the same as those described for Part 264 above.
RCRA Part 270 standards address RCRA permitting requirements for facilities that treat,
store, or dispose of hazardous wastes. Facilities seeking compliance after listing through use
of a Subtitle C landfill, incinerator, or BIF will be subject to this part. Part 270 requires a
facility to submit a RCRA Part B permit application and obtain a RCRA permit. RCRA Part
B permits for incinerators and BIFs include trial burn requirements to assure proper
combustion of the newly listed wastes.
The listings RCRA administrative and on-going compliance costs were based on engineering
estimates for activities required by 40 CFR Parts 262, 264, 266, and 270. The basis for
these costs are for five to six waste listings2. These estimates appear to be reasonable
compared to more detailed cost estimates in the September 1994 document entitled
"Economic Benefits of RCRA Noncompliance (EBN)". The basis for the EBN costs varied
from four to nine waste streams, with six being typical, so that approximate costs per waste
2 These costs were developed based on the assumption that five to six of the original number of residuals being
considered would be listed. Since only four wastes are being listed, the RCRA administrative costs are estimated to
be too high by approximately 20 to 30 percent overall.
3-62
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Of,
stream were used in -the comparison. For permitting costs, the EBN document itself was
used for cost estimating. For BIFs, no EBN costs have been published, so no comparison
was possible. The EBN costs themselves were compared to EPA Information Collection
Request (ICR) cost data and were generally higher due to the increased level of detail of
costs for required activities in the EBN document.
Table 3.11 summarizes the RCRA administrative costs associated with each of the RCRA
Parts described above.
3-63
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TABLE 3.11
RCRA ADMINISTRATIVE COSTS
(1992 Dollars)
RCRA
Part
Activity
Initial Items
Initial
Cost
Periodic Items
Periodic
Cost
'262
Generator Requirements:
New listing (i.e., facility
currently a hazardous waste
generator) and new wastes
managed off-site
Assess current waste generation and
management practices, evaluate
regulations listing the new wastes, review .
procedures for packaging and labeling,
personnel training, and contingency plan
and local emergency arrangements
$2,300
if permitted
TSDF/BIF
facility
tola! costs
are
$900
Additional time for
completing manifest for
newly listed wastes,
packaging and marking,
annual portion of biennial
report, personnel training,
and contingency plan and
local emergency
arrangements
$3,200/yr
if permitted
TSDF/BIF
facility total
costs are $1,600
262
Generator Requirements:
New listing and all new
wastes managed on-site
Assess current waste generation and
management practices, evaluate
regulations listing the new wastes,
personnel training, and contingency plan
and local emergency arrangements
$2,000
if permitted
TSDF/BIF
facility
total costs
are $700
Additional time for annual
portion of biennial report,
personnel training and
contingency plan and local
emergency arrangements
$400/yr
if permitted
TSDF/BIF
facility total
costs are $100
262
Generator Requirements:
First listing (i.e., facility
not currently a hazardous
waste generator) and-new
wastes managed off-site
Become aware of and understand
responsibilities under regulations, assess
current waste generation and management
practices, obtain EPA ID number, review
and determine applicable DOT -
requirements, develop procedures for
manifesting, packaging, and labeling, and
purchase tile cabinet for storing manifests
and reports, personnel training, and
contingency plan and local emergency
arrangements
$9,800
if permitted
TSDF/BIF
facility
total costs
are $2,200
Complete manifest,
packaging and labeling of
hazardous waste for off-site
shipment, annual portion of
biennial report, filing
exception report, personnel
training, and contingency
plan and local emergency
arrangements
$6,700/yr
if permitted
TSDF/BIF
facility total
costs are $2,800
3-64
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TABLE 3.11 (CONTINUED)
RCRA ADMINISTRATIVE COSTS
(1992 Dollars)
RCRA
Part
Activity
Initial Items
Initial
Cost
Periodic Items
Periodic
Cost
262
Generator Requirements:
First listing and all new
wastes managed on-site
Become aware of and understand
responsibilities under regulations, assess
current waste generation and management
practices, and obtain EPA ID number,
personnel training, and contingency plan
and local emergency arrangements
$7,900
if permitted
TSDF/BIF
facility
tola! costs
are $1,300
Annual portion of biennial
report, personnel training,
and contingency plan and
local emergency
arrangements
$2,400/yr
if permitted
TSDF/BIF
facility total
costs are $600
264,
Parts
A-H
TSDF Requirements (if
landfill and/or incinerator):
Not currently a TSDF
Prepare waste analysis plan, conduct
waste analysis on newly listed wastes,
personnel training, inspection schedule,
personnel training, purchase required
preparedness and prevention equipment,
make arrangements with local authorities,
prepare contingency plan, record waste
analyses results in operating record,
prepare closure plan and closure cost
estimate, select financial assurance
mechanisms for closure and third party
liability, submit Part A application, and
corrective action scheduling
$53,000 (a)
$84,000 (b)
Review waste analysis plan
and contingency plan,
conduct and record
inspections, personnel
training review, test and
maintain preparedness and
prevention equipment,
maintain operating record,
and review closure plans
and cost estimates,
financial assurance, and
corrective action schedule
$ll,000/yr (a)
$16,000/yr (b)
3-65
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TABLE 3.11 (CONTINUED)
RCRA ADMINISTRATIVE COSTS
(1992 Dollars)
RCRA
Part
264,
Parts
A-H
266
266
Activity
TSDF Requirements (if
landfill and/or incinerator):
Currently a TSDF
Boiler and Industrial
Furnace (BIF)
Requirements:
Not currently a TSDF
Boiler and Industrial
Furnace (BIF)
Requirements:
Currently a TSDF
Initial Items
Conduct waste analysis on newly listed
wastes; modify waste analysis plan,
inspection schedule, personnel training,
contingency plan, closure plan, closure
cost estimate, financial assurance
mechanism for closure, and Part A
application; and record waste analyses
results in operating record, and corrective
action scheduling
Same as Part 264
Same as Part 264
Initial
Cost
$4 1,000 (a)
$69,000. (l>)
$53,000
$41,000
Periodic Items
Review waste analysis plan
and contingency plan,
conduct and record
inspections, personnel
training, maintain operating
record, and review closure
plans and cost estimates,
financial assurance, and
corrective action schedule
Same as Part 264
Same as Part 264
Periodic
Cost
$6,500/yr (a)
$ll,000/yr (b)
$ll,000/yr
$6,500/yr
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TABLE 3.11 (CONTINUED)
RCRA ADMINISTRATIVE COSTS
(1992 Dollars)
RCRA
Part
266
270
270 .
270
Activity
Boiler and Industrial
Furnace (BIF)
Requirements:
Small quantity exempt
(i.e., facility burns <330
gallons/month, which is
estimated to be < IS
Mton/yr based on stack
height of 50 meters)
Part A Requirements
Not Currently Permitted
Part A Requirements
Currently Permitted
Part B Permit
Requirements - BIF:
Not currently permitted
Part B Permit
Requirements - BIF:
Currently permitted
Initial Items
Submit written notification to EPA
Part A application
Modify Part A application
Part B permit application consisting of the
following requirements: general
information, SWMU, and BIF (including
trial burns)
Modify. Part B permit for BIF (including
trial burns)
Initial
Cost
$100
$2,400 (a)
$3,500 (b)
$600 (a)
$900 (b)
$117,000
$108,000
Periodic Items
Document compliance with
the hazardous waste
quantity, firing rate, and
heating value per calendar
month
Permit renewal every 10
years
Permit renewal every 10
years
Periodic
Cost
$300/yr
$0/yr
$0/yr
$43,000/10 yr
$39,000/10 yr
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TABLE 3.11 (CONTINUED)
RCRA ADMINISTRATIVE COSTS
(1992 Dollars)
RCRA
Part
270
270
Activity
Part B Permit
Requirements -
Incineration:
Not currently permitted
Part B Permit
Requirements -
Incineration:
Currently permitted
Initial Items
Part B permit application consisting of the
following requirements: general
information, SWMU, and incineration
(including trial burns)
Modify Part B permit for incineration
(including trial burns)
Initial
Cost
$268,000
$255,000
Periodic Items
Permit renewal every 10
years
Permit renewal every 10
years
Periodic
Cost
$99,000/1 Oyr ,
$95,000/10 yr
(a) TSDF administrative costs if one new unit
(b) TSDF administrative costs if two new units
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3.3.5 Corrective Action Compliance Costs
Incremental corrective action costs associated with unpermitted facilities include the cost to
conduct a RCRA Facility Investigation (RFI), a Corrective Measures Study (CMS), and
remediate solid waste management units (SWMUs) and areas of concern (AOCs). Because
of the petroleum refinery waste listings, some of the 97 unpermitted refineries of the 162
affected by the listings determination may be brought into the RCRA permitting program. A
certain number of the currently unpermitted facilities will seek a RCRA Part B permit for
incinerators or BIFs. RCRA corrective action is typically triggered by facilities seeking a
RCRA permit. RCRA Facility Assessments (RFAs) will be conducted at these facilities to
determine the need for corrective action (RFI, CMS, and remediation) prior to issuing a
permit. Currently, permitted facilities will likely have already gone through this process,
therefore, corrective action costs have already been incurred or assessed under the Corrective
Action nilemaking. EPA assumed that industry will avoid triggering the corrective action
process by not constructing on-site Subtitle C units requiring permits unless the facility
already has a RCRA Part B permit for other types of on-site treatment, storage, and disposal
units. However, if this assumption is incorrect, corrective action cost estimates were derived
as follows.
The following probabilities of facilities incurring corrective action costs were assumed:3
There is a 75 percent probability that corrective action investigation (RFI and CMS)
and remediation will be conducted at a facility.
Separating the two activities, there is a 66 percent probability that both corrective
action investigations and remediations will be conducted at a facility and a 9 percent
probability that only corrective action investigations will be conducted.
The Draft Final Rule Corrective Action RIA presents corrective action costs expressed as a
present value using a seven percent'discount rate in 1992 dollars. The Draft Final Rule
Corrective Action RIA does not provide detailed information on how the discounting was
applied (i.e., what costs occurred in what year). The following corrective action cost
estimates, which reflect a 7 percent before-tax discount rate, were derived based on the
Proposed Rule and Final Rule Corrective Action RIAs.
The weighted average correction action remediation (only) cost per "triggered"
facility is $600,000/yr with a range from $2,000/yr to $17.0 million/yr.
3 Estimates of probabilities that corrective action is triggered at a facility and corrective action costs were
obtained from the U.S. EPA, "Draft Regulatory Impact Analysis for the Final Rulemaking on Corrective Action for
Solid Waste Management Units," Office of Solid Waste, March 1993, and the U.S. EPA, "Regulatory Impact
Analysis for the Proposed Rulemaking on Corrective Action for Solid Waste Management Units," Office of Solid
Waste, Juae 25, 1990.
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Approximately 15 percent of the triggered facilities incur corrective action
investigation and remediation costs greater than $900,000/yr.
Approximately 60 percent of the triggered facilities incur corrective action
investigation and remediation costs between $90,000/yr and S900,000/yr.
Approximately 25 percent of the triggered facilities incur corrective action
investigation and remediation costs less than $90,000/yr.
Typical investigation costs are $33,800/yr for an RFI and $9,800/yr for a CMS.
Using the above estimates, the following assumptions were used in the bounding analysis for
corrective action compliance costs:
Listing Scenario:
No unpermitted facilities would need a RCRA permit. Three facilities will be
seeking to permit existing units (i.e., on-site incinerators/BIFs), but, these facilities
already have RCRA Part B permits.
LDR Scenario, Option 1 - Off-site Subtitle C Incineration:
No unpermitted facilities would need a RCRA permit. Three facilities will be
seeking to permit existing units (i.e., on-site incinerators/BIFs), but, these facilities
already have RCRA Part B permits. Two facilities already have permitted on-site
incinerators.
LDR Scenario, Option 2 - On-Site Subtitle C Incineration:
EPA assumed that no unpermitted facilities will construct an on-site incinerator.
However, two unpermitted facilities generate enough waste to construct and permit
an on-site incinerator. Eight permitted facilities will seek to construct and permit
an on-site incinerator under their current permit. Two permitted facilities will be
seeking to permit existing units under their current permit. Two facilities already
have permitted on-site incinerators.
Contingent Management Scenario, Option 1 - On-Site Subtitle C Incineration of
Crude Oil Tank Sludges and Subtitle D Management of CSO Sludges:
EPA assumed that no unpermitted facilities will construct an on-site incinerator.
However, one unpermitted facility generates enough waste to construct and permit
an on-site incinerator. Three permitted facilities will seek to construct and permit
an on-site incinerator under their current permit. Two permitted facilities will be
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seeking to permit existing units under their current permit. Two facilities already
have permitted on-site incinerators.
Contingent Management Scenario, Option 2 - Subtitle D Management of Oil-Based
Sludges:
No unpermitted facilities will need a RCRA permit. One facility already has a
permitted on-site landfill.
Corrective action incremental compliance costs may be incurred under the LDR Scenario
(Option 2) and the Contingent Management Scenario (Option 1) when it is economically
feasible to construct new on-site incinerators at unpermitted facilities. EPA assumed that
unpermitted facilities will not seek to construct and permit a new on-site incinerator because
of the corrective action implications. Therefore, corrective action costs are zero for all
scenarios. However, if facilities do choose to construct on-site incinerators, the corrective
action incremental compliance costs would range from $2.0 million (Best Case) to $7.2
million (Worst Case) annually for Option 2 of the LDR Scenario, and from $0.7 million
(Best Case) to $2.7 million (Worst Case) annually for Option 1 of the Contingent
Management Scenario. Corrective action costs may be incurred because facilities will be
applying for RCRA Part B permits if the facility is currently unpermitted. No incremental
corrective action costs are incurred under the Listing Scenario, Option 1 of LDR Scenario
when off-site incineration management is assumed, and Option 2 of the Contingent
Management Scenario when Subtitle D management of oil-based sludges is assumed.
The corrective action cost results are. summarized as follows:
LDR Scenario, Option 2 - On-site Subtitle C Incineration:
Possibly two unpermitted facilities may incur total corrective action costs ranging
from $ 0.3 million/yr-under the best case, $0.9 million/yr under the expected case,
to $1.8 million/yr under the worst case.
Contingent Management Scenario, Option 1 - Subtitle D Management of Oil-Based
Sludges:
Possibly one unpermitted facility may incur total corrective action costs ranging
from $0.2 million/yr under the best case, $0.4 million/yr under the expected case,
to $0.9 million/yr under the worst case.
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The following assumptions were used in preparing the worst, expected, and best cases:
Worst Case:
Assume 100 percent of the facilities are triggered for corrective action.
Assume corrective action investigation and remediation costs are $900,000/yr. This
value represents the 85th percentile of the estimated corrective action costs in the
. Draft Final Rule Corrective Action RIA.
Expected Case:
Assume 75 percent of the facilities will incur corrective action investigation costs of
$43,600/yr. This value assumes costs of $33,800/yr to conduct an RFI and
$9,800/yr to conduct a CMS.
Assume 66 percent of the facilities will incur corrective action remediation costs of
$600,000/yr. This value represents the weighted average corrective action
remediation cost estimated in the Draft Final Rule Corrective Action RIA.
Best Case:
Assume 50 percent of the facilities will incur corrective action investigation costs of
$43,600/yr. At a minimum, some percentage of the facilities will be investigated.
The Draft Final Rule Corrective Action RIA indicates that of the 5,800 facilities
subject to corrective action, 3,500 (60 percent) will require an RFI. EPA assumed
for a "best case" analysis that the percentage would be lower than 60 percent and
assumed that only 1 in every 2 facilities (50 percent) will be investigated.
Assume 37 percent of the facilities will incur corrective action remediation costs of
$600,000/yr. The Draft Final Rule Corrective Action RIA indicates that of the
5,800 facilities subject to corrective action, only 2,600 facilities (45 percent) will
require remediation. EPA assumed for a "best case" analysis that the percentage
would be lower than 45 percent and assumed that'a proportionate number (74
percent; 2,600/3,500) of the facilities requiring corrective action investigation will
require remediation in the "best case" analysis.
3.3.6 Data Limitations
Many facilities did not report unit treatment, transportation, recycling, and disposal costs in
the 1992 RCRA 3007 Survey. Estimates for these unit costs were based on the average
derived from other reporting facilities. Where not enough data were provided, EPA
estimated unit costs. Because of the potential for over or underestimating incremental
compliance costs using industry averages and cost estimates as surrogates to facility-specific
3-72
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costs, sensitivity analyses on the cost and economic impacts have been conducted using
industry average and estimated unit costs that are 25 percent lower (lower-bound estimate of
incremental cost of compliance) and 25 percent higher (upper-bound estimate of incremental
cost of compliance) to bound uncertainties within the cost estimates.
3.3.7 Waste Minimization Opportunities
Regulatory compliance costs for the petroleum refining industry can be lowered through use
of waste minimization practices. De-oiling (i.e., using a filtration unit) of crude oil storage
tank and clarified slurry oil (CSO) tank sludges is a common management practice within the
industry. EPA assumed that facilities will implement filtration of oily crude oil and CSO
sludges as a cost-effective waste minimization practice. The cost of installing and operating
a filtration unit was added to those facilities that did not report filtration of their oily sludge
wastes. Based on data reported by those facilities currently filtering their sludges, 60 percent
of the waste stream becomes oil filtrate that is recycled back to a process unit on site. Only
40 percent remains as a filtration sludge requiring further management. When estimating
revenues gained from substituting the oil filtrate for crude oil feedstock, EPA assumed that
90 percent of the filtrate is oil with an assumed value (credit) equal to 90 percent of crude
oil. Revenues from the oily sludge filtration were estimated to be approximately $1.3
million per year.
3.4 Regulatory Compliance Costs
Under Executive Order 12866, EPA must determine whether a regulation constitutes a
"significant regulatory action." One of the criteria for defining a significant regulatory
action, as defined under the Executive Order, is if the rule has an annual effect on the
economy of $100 million or more. To determine whether the listing is a significant
regulatory action under this criteria, all costs are annualized on a before-tax basis assuming a
seven percent real rate of return. The savings attributable to corporate tax deductions or
depreciation on capital expenditures for pollution control equipment are not considered in
calculating before-tax costs.
3.4.1 Annualization of Before-Tax Compliance Costs
A facility-by-facility annualized before-tax cost analysis was conducted for 162 facilities, in
the petroleum refining industry, which generate wastes affected by the listings determination.
The 162 facilities are owned and operated by 80 manufacturers. Several facilities submitted
incomplete information to EPA regarding waste generation. However, average data from the
other petroleum refining facilities were used as proxy values for the plants without waste
generation data to avoid understating industry regulatory compliance cost impacts. Nine
facilities do not generate any of the new waste stream listings, one facility is closed, and one
facility did not respond to the survey; consequently, these facilities were excluded from this
compliance cost impact analysis of the petroleum refining industry.
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Annual before-tax baseline and compliance costs were estimated for each facility and each
waste listing using the unit costs, prices, and waste quantities discussed previously. Before-
tax compliance costs were used because they represent a resource or social cost of the
listings determination, measured before any business expense tax deductions available to
affected companies. In reformulating the social costs of compliance, EPA used a discount
rate of seven percent, assumed a 20-year borrowing period, a 20-year operating life for
tanks, secondary containment systems, container storage areas, and incinerators, and a 10-
year operating life for filtration units for annualizing capital costs.
The following formula was used to determine the before-tax annualized costs:
Annual Before-Tax Costs =
(Capital and One-Time Initial Costs)(CRF20) + (10-YR Capital Costs/1.07!0)(CRF20) +
(Annual O&M Costs) + [(5-YR O&M Costs/1.075) + (5-YR O&M Costs/1.0710)~+
(5-YR O&M Costs/ 1.07ls)](CRF,o) + (10-YR O&M Costs/1.07'°)(CRF,0) + (Closure
Costs/1.0721)(CRF20)
Where: CRFn = Capital recovery factor (i.e., the amount of each future annuity
payment required to accumulate a given present value) based on
a 7 percent real rate of return (i) and a 20-year borrowing
period (n) as follows:
a + nnm
(1 + i)n-l = 0.09439 when n = 20
f
The compliance costs are engineering cost estimates that are specific to each waste stream.
These costs include capital costs for items such as less.than 90-day container storage areas,
treatment tanks, incinerators and O&M costs for management of hazardous wastes (i.e.,
transportation and landfill disposal): In addition, plants will incur 40 CFR Part 262 (first
and new listing notification), 264 (treatment tanks, container storage areas, and on-site
incinerator), 266 (on-site boiler or industrial furnace), and 270 (on-site boiler or industrial
furnace, and on-site incinerator Part B permit) administrative costs. Corrective action costs
are assumed to be zero for this listings determination. At a maximum, they may reach $1.8
million per year.
3.4.2 Annualized Compliance Costs
A summary of the annual incremental before-tax compliance costs for each waste due to the
listing and the listing including LDR regulations is presented in Table 3.12. A similar
summary of the annual incremental before-tax compliance costs for the Contingent
Management Scenario is presented in Table 3.13. More detailed summaries, including the
baseline and compliance cost totals, are presented in Appendices A, B, and C. Appendices
A, B, and C present the before-tax incremental compliance costs due to the listing (Listing
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Scenario), the listing'including LDR regulations (LDR Scenario), and the listing with
contingent management options (Contingent Management Scenario). In the Listing Scenario,
EPA assumed all affected oil-based sludge residuals and metal catalyst residuals will be
disposed in off-site Subtitle C units corresponding to their current Subtitle D units (e.g.,
landfill, incinerator, or BIF), except for land treatment which will shift to Subtitle C landfill.
The shift to Subtitle C landfill is a major portion of the total incremental compliance cost.
An assessment was made of the economic viability of constructing a landfill unit on-site,
however, none of the refineries generate enough of the affected wastes to find construction of
on-site landfill units to be cost-effective. Incremental compliance costs range from $4
million to $16 million per year with an expected value of $8 million per year.
EPA assumed Subtitle C incineration/BIF of all oil-based residuals and Subtitle C
incineration followed by Subtitle C vitrification and Subtitle C landfill of the ash of metal
catalyst residuals under the LDR Scenario (Option 1). The shift to Subtitle C incineration of
the oil-based residuals is a major portion of the total incremental compliance cost. An
assessment also was made of the economic viability of constructing an incineration unit on
site. A few of the refineries generate enough of the affected wastes for construction of on-
site incineration units to be cost-effective (Option 2). EPA assumed under Option 2 that
facilities will ship metal catalyst residuals to off-site metal catalyst regeneration/reclamation
operations to take advantage of the exemption from RCRA Subtitle C regulation for metals
recovery. Incremental compliance costs range from $33 million to $101 million per year ~
with an expected value of $61 million per year for Option 1, and from $21 million to $68
million per year with an expected value of $41 million per year for Option 2.
EPA assumed on-/off-site Subtitle C incineration/BIF of crude oil tank sludges depending on
the economic viability, disposal of CSO sludges in Subtitle D land treatment units with run-
on/run-off controls or Subtitle D landfills, and reclamation/regeneration of metal catalyst
residuals under the Contingent Management Scenario (Option 1). Option 2 allows the
contingent management alternative of crude oil tank sludges being disposed in Subtitle D land
treatment units with run-on/run-off controls. Incremental compliance costs range from $12
million to $42 million per year with an expected value of $24 million per year for Option 1,
and from $3 million to $ 11 million per year with an expected value of $6 million per year
for Option 2.
The estimated annual before-tax costs are not greater than the $100 million significant
regulatory action criteria. The significant regulatory action criteria of adverse impacts on the
economy, a sector of the economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments o.r communities is evaluated in
Chapter 4.
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TABLE 3.12
ANNUALIZED COSTS FOR THE PETROLEUM REFINING HAZARDOUS WASTE LISTINGS'
LISTING AND LDR SCENARIOS
($ MILLIONS)
(1)
Waste Stream
Crude Oil Tank Sludge
Clarified Slurry Oil Sludge
Hydrotreating Catalyst
Hydrorefming Catalyst
RCRA Administrative Costs
TOTAL
(2)
Listing Scenario
Average Cost
(Low-High)
2.2
|1.0 -3.9|
2.8
|1.4 - 4.8|
1.3
|0.8 -2.9|
1.5
[0.7-3.81
0.5
[0.4 - 0.6|
8.3
[4.3 - 16.0|
(3)
LDR Scenario, Option 1
Off-Site Incineration ot Sludges and
Off-Site Incineration and Vitrification
of Catalysts
Average Cost
(Low-High)
21.6
[9.3 -38.8|
22.5
[11.2 -37.6|
5.0
[3.5-7.61
11.6
|8.3 - 16.5|
0.5
[0.4 - 0.7)
61.3
[32.7- 101.2|
(4)
LDR Scenario, Option 2
On-/Off-Site Incineration of Sludges
and Regeneration/Reclamation of
Catalysts2
Average Cost
(Low-High)
16.7
[8.1 -28.3|
16.8
|9.4 - 26.5|
2.3
11.2-4.51
3.9
|1.9 -7.9|
0.8
[0.6 - 1.0)
40.6
[21.3 -68.3|
' Cost uncertainty (Low-High) is estimated using a +/- 50% adjustment of any estimated quantities and a +/- 25% adjustment of any estimated costs. Current
management practice and transportation unit costs were provided in the 1992 RCRA 3007 Survey. If unit costs were not reported, an industry-based average unit
cost was used. If data were not available to derive an industry-based average, EPA estimated a unit cost for the management practice based on previous listing
determinations, land disposal restrictions analyses, and engineering cost documents. Compliance management practice, transportation, and RCRA administrative
unit costs, prices, and cost equations were obtained from industry-based averages derived from the 1992 RCRA 3007 Survey, previous listing determinations and
land disposal restrictions analyses, and engineering cost documents.
2 Ou-site incinerators are assumed only for those facilities (hat manage a large enough quantity of waste so that an on-site incinerator is more economical for the
facility and which are currently in the RCRA program. All other facilities are assumed to continue managing wastes off site.
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TABLE 3.13
ANNUALIZED COSTS FOR THE PETROLEUM REFINING HAZARDOUS WASTE LISTINGS'
CONTINGENT MANAGEMENT SCENARIO
($ MILLIONS)
(1)
Waste Stream
Crude Oil Tank Sludge
Clarified Slurry Oil Sludge
Hydrotreating Catalyst
Hydrorefining Catalyst
RCRA Administrative Costs
TOTAL
(2)
Contingent Management Scenario, Option 1
Subtitle D Landfill and Land Treatment (w/ controls) of
CSO Sludge, On-/Off-Site Incineration of Crude Oil
Tank Sludges and Regeneration/Reclamation of Catalysts
Average Cost
(Low-High)
17.5
|8.5 -29.8|
(0.5)
1(0.3) - (0.8)|
2.3
11.2 -4.5|
3.9
[1.9 -1.9}
0.6
|0.5 -0.8|
23.8
[11.8-42.2]
(3)
Contingent Management Scenario, Option 2
Subtitle D Landfill and Land Treatment (w/ control;,) of CSO
Sludge, Subtitle D Land Treatment (w/ controls) of Crude Oil
Tank Sludges and Regeneration/Reclamation of Catalysts
Average Cost
(Low-High)
(0.5)
1(0-2) -(l.0)|
(0.5)
[(0.3) -'(0.8)|
2.3
[1.2-4.51
3.9
[1.9-7.9J
0.5
[0.3 - 0.6|
5.6
[3.1 - 11.2|
1 Cost uncertainty (Low-High) is estimated using a +/-. 50% adjustment of any estimated quantities and a -)-/- 25% adjustment of any estimated costs. Current
management practice and transportation unit costs were provided in the 1992 RCRA 3007 Survey. If unit costs were not reported, an industry-based average unit
cost was used. If data were not available to derive an industry-based average, EPA estimated a unit cost for the management practice based on previous listing
determinations, land disposal restrictions analyses, and engineering cost documents. Compliance management practice, transportation, and RCRA administrative
unit costs, prices, and cost equations were obtained from industry-based averages derived from the 1992 RCRA 3007 Survey, previous listing determinations and
land disposal restrictions analyses, and engineering cost documents.
2 Oil-site incinerators are assumed only for those facilities that manage a large enough quantity of waste so that an on-site incinerator is more economical tor the
facility and which are currently in the RCRA program. All other facilities are assumed to continue managing wastes off site.
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4.0 ECONOMIC IMPACTS OF NEWLY LISTED WASTES
This section presents the estimated economic impacts of this listings determination for
selected petroleum refining wastes. A facility-by-facility economic analysis was conducted
for 163 facilities in the petroleum refining industry that generate wastes affected by this
listings determination.1 Partial equilibrium analysis is used to specify the baseline market
supply and demand, estimate the post-control shift in market supply, estimate the change in
equilibrium price and quantity, and predict plant closures.
The remainder of this section is organized as follows: The economic impacts methodology
and data sources and limitations are discussed in Section 4.1. Sections 4.2 and 4.3 present
the industry economic impacts and limitations of the analysis, respectively. The regulatory
flexibility analysis is presented in Section 4.4.
4.1 Economic Impacts Methodology
Economic effects are defined as the difference between the projections of the likely effects on
facilities that result from regulatory compliance and the industrial activity likely in the
absence of regulation (i.e., baseline conditions). Imposition of regulatory requirements may
have an adverse economic effect on industry since expenditures must be made that do not
necessarily contribute directly to improved operating efficiency measured in terms of
economic return on investment. The difference between the baseline and post-regulatory
costs is equal to the incremental cost of compliance on which economic impacts are
evaluated.
Economic impacts were evaluated for two regulatory scenarios the Listing Scenario and the
Listing and LDR Scenario, which reflects compliance with both the listings and land disposal
restrictions (LDRs). The Listing Scenario assumes an end disposal management method of
Subtitle C landfilling, continued combustion of wastes (where indicated as the baseline
management practice) in a Subtitle C incinerator/BIF, or continued metals
reclamation/recovery. The combined Listing and LDR Scenario adds a pretreatment
management method of solidification prior to Subtitle C landfill for metal-based wastes and
assumes combustion in a Subtitle C incinerator/BIF for organic-based wastes. For the lower
bound Listing and LDR Scenario, on-site incineration is assumed for those entities generating
sufficient quantities of waste, whereby the economics favors on-site incineration. This
scenario represents the most cost-effective alternative for compliance with the listing as well
as LDRs.
1 The economic analysis is based on the listing of five wastestreams including unleaded gasoline sludge, which
has since been removed from the list of wastes included in this listings determination. Also, the economic analysis is
based on a lower estimate for crude oil tank sludge and CSO tank sludge quantities, each having 9,000 MT/yr
managed in final management practices. These quantities have since been revised to 14,600 and 13,100 MT/yr,
respectively.
*
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4.1.1 Partiat Equilibrium Analysis
Partial equilibrium analysis is used to estimate primary and secondary economic impacts
resulting from implementation of the listings. Primary economic impacts include changes in
the market equilibrium price and output levels, changes in the value of shipments or revenues
to domestic producers, and plant closures. Secondary impacts include changes in
employment, use of energy inputs, balance of trade, and regional refinery distribution.
The baseline or pre-control petroleum refining market is defined by a domestic market
demand equation, a domestic market supply equation, and a foreign market supply
equation.2 The purchase of regulatory control equipment results in an upward shift in the
domestic supply curve for refined petroleum products. The height of the shift is determined
by the after-tax cash flow required by refineries to offset the per unit increase in production
cost as a result of the listings determination. The partial equilibrium model assumes that
refineries will seek to increase the price of the product they sell by an amount that recovers
the capital and operating costs of the regulatory control requirements over the useful life of
the equipment.
Petroleum refineries produce several hundred products. The economic impacts analysis
evaluates the impact of the listings on ten petroleum products (i.e., ethane/ethylene,
butane/butylene, normal butane/butylene, isobutane/isobutylene, finished motor gasoline, jet -
fuel, distillate and residual fuel oil, asphalt, and petroleum coke) which represent 91 percent
of the 1992 domestically produced petroleum products. Because compliance costs for the
hazardous waste listings cannot be allocated to any specific products, output in the partial
equilibrium model is defined as a composite, bundled good equal to the sum of price
multiplied by the weighted production volumes of each of the ten products.
Primary Economic Impacts - The impact of the listings on market equilibrium price
and output is derived by solving for the post-control market equilibrium and
comparing the new equilibrium price and quantity to the pre-control equilibrium.
Trade impacts are reported as the change in both the volume and dollar value of net
imports (exports minus imports). It is assumed that a refinery will close if its post-
control supply price exceeds the post-control market equilibrium price.
Secondary Economic Impacts - The estimates of the labor and energy market impacts
associated with the listings are based on input-output ratios and estimated changes in
domestic production. The labor market impacts are measured as the number of jobs
lost due to domestic output reductions. The estimated number of job losses are a
function of the change in level of production that is anticipated to occur as a result of
2 See Appendix D for a detailed discussion of the economic impacts methodology and the partial equilibrium
model algorithms.
4-2
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the listings. The reduction in energy inputs associated with the listings results fro:..
the reduction in expenditures for energy inputs due to production decreases.
Foreign supply is assumed to have the same price elasticity of supply as domestic
supply. The U.S. had a negative trade balance in 1992 for each of the refined
products, with the exception of distillate fuel oil, which had a slightly positive trade
balance of $1.1 million. Therefore, net exports are negative for all products except
distillate fuel oil in the baseline model. Foreign and domestic post-control supply are
added together to form the total post-control market supply. The intersection of this
post-control supply with market demand determines the new market equilibrium price
and quantity. Post-control domestic output is derived by 'deducting post-control
imports from the post-control output.
Economic Welfare Impacts - Regulatory control requirements will result in changes in
the market equilibrium price and quantity of petroleum products produced and sold.
These changes in the market equilibrium price and quantity will affect the welfare of
consumers of petroleum products, producers of petroleum products, and society as a
whole. The total economic cost of the listings is equal to the sum of the changes in
consumer surplus, producer surplus, and the residual surplus and represents the value
that society places on goods and services not produced as a result of resources being
diverted to increased waste management and disposal under this listings
determination.
Consumer Surplus - The change in consumer surplus includes losses of surplus
incurred by both foreign consumers (of U.S. exports) and domestic consumers.
The partial equilibrium model assumes that the consumer surplus change is
allocable to foreign and domestic consumers in the same ratio as sales are
divided between foreign and domestic consumers in the pre-control market.
Consumers, in total, will experience a loss or gain in economic welfare
depending on the magnitude of the changes in post-control price and quantity.
Producer Surplus - The change in producer surplus is composed of two
elements. The first element relates to output eliminated as a result of
regulatory controls on the treatment and disposal of listed wastes. The second
element is associated with the change in price and cost of production for the
new market equilibrium quantity. The total change in producer surplus is the
sum of these two components. Output eliminated as a result of control costs
causes producers to suffer a welfare loss in producer surplus. Refineries
remaining in operation after regulatory controls are implemented realize a
welfare gain of the post-control equilibrium price minus the pre-control
equilibrium price on each unit of production for the incremental increase in the
price and, in addition, realize a decrease in welfare per unit for the capital and
operating cost of implementing the required control equipment.
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Residual Surplus - The changes in economic surplus, as measured by the
changes in consumer and producer surplus must be adjusted to reflect the true
change in social welfare as a result of this listings determination. The
adjustments are necessary due to tax effects differences and to the difference
between the private and social discount rates. Two adjustments to economic
surplus are necessary to account for tax effects. The first relates to the per
unit control cost that reflects after-tax control costs and is used to predict the
post-control market equilibrium. A second tax-related adjustment is required
because changes in producer surplus have been reduced by a factor of (1-t) to
reflect the after-tax welfare impacts of regulatory treatment and disposal
requirement costs on affected refineries. Economic surplus must also be
adjusted because of the difference between private and social discount rates.
The private discount rate is used to shift the supply curve of refineries in the
industry since this rate reflects the marginal cost of capital to affected
refineries. The economic costs of the regulation, however, must consider the
social cost of capital. This rate reflects the social opportunity cost of
resources displaced by investments in regulatory treatment and disposal
equipment. Together, the adjustment for the two tax effects and the social
cost of capital equal the residual change in economic surplus.
Additional detail regarding the calculation of changes in economic welfare is provided
in Appendix D (see Changes in Economic Welfare). The results of the economic
impact analysis for each regulatory scenario evaluated are presented in Section 4.2.
4.1.2 Data Sources and Limitations
The partial equilibrium model described above requires baseline values for variables and
parameters that characterize the petroleum refining market. Table 4.1 lists the variable and
parameter inputs to the model that vary for the ten petroleum products evaluated. Table 4.2
lists variables and parameters that are assumed to be the same for all petroleum products.
Data on production volumes were obtained from the 1992 RCRA 3007 Survey. Facilities
were asked to report 1992 product yields for all finished products produced at the refinery.
Quantity (i.e., refinery output) data are reported in millions of barrels. Imports and exports
(1992) of the ten petroleum products evaluated were obtained from the Petroleum Supply
Annual, 1992. The baseline market prices ($1992) were obtained from the Petroleum
Market Annual, 1993. Prices are stated in barrels per gallon excluding taxes. Other sources
for baseline market prices ($1992) include Platts Oil Gram for prices on liquified petroleum
gases; Pace Consultants for petroleum coke; and the Asphalt Institute for prices on asphalt.
A marginal tax rate of 34 percent, private discount rate of 10 percent, and social discount
rate of 7 percent are assumed in the economic analysis. An equipment life of 20 years is
assumed for treatment/disposal units including tanks and incinerators and 10 years for
filtration units. The number of workers per unit of output, labor, and the energy
expenditures per value of shipments were derived from the U.S. Department of Commerce,
4-4
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Annual Survey of Manufactures (ASM), 1991. Data from the ASM used to derive these
estimates include the 1991 annuai values for total number of workers employed, total
expenditures'on energy, and the value of shipments for SIC 2911.
A bounding analysis was conducted for two regulatory scenarios to account for uncertainty in
reporting quantities and cost estimates. The lower bound analysis assumes a 50 percent
reduction in any estimated quantity (non-reported) and a 25 percent reduction in any
estimated cost. The upper bound analysis assumes a 50 percent increase in any estimated
quantity (non-reported) and a 25 percent increase in any estimated cost. Additionally, the
economic analysis was based on the listing of five wastestreams including unleaded gasoline
sludge, which has since been removed from the wastes to be listed under this listings
determination. Compliance costs associated with unleaded gasoline sludge represent 11 and
14 percent of the total compliance cost used in the evaluation of economic impacts under the
lower and upper bound regulatory scenarios, respectively. As a result, economic impacts for
the 98 facilities generating unleaded gasoline sludge will be overestimated. Finally, the
regulatory options used to evaluate economic impacts differ slightly from those that were
used to calculate the cost of compliance. This difference does not affect the total cost of
compliance for the Listing Scenario or the lower bound Listing and LDR Scenario, but does
have an impact on the upper bound Listing and LDR Scenario, such that costs are
understated by $8 million. As a result, economic impacts may be underestimated for the
upper bound Listing and LDR Scenario.
4.2 Estimated Industry Impacts
For purposes of presentation, the results of the economic impacts analysis are presented as a
bounding analysis whereby the Listing Scenario, lower bound, represents the least costly
compliance option. The Listing and LDR Scenario, off-site incineration, represents the worst
case or most costly compliance option. The Listing and LDR Scenario, on-site incineration,
assumes on-site incineration for those refineries generating sufficient quantities of wastes,
whereby the economics favors on-site incineration. This scenario represents the most cost-
effective regulatory alternative assuming compliance with both the listings and LDRs.
Results are presented on an aggregate basis to protect the confidentiality of facilities affected
by this listings determination.
The partial equilibrium model is used to analyze the market outcome of this listings
determination. The purchase of regulatory compliance equipment will result in an upward
shift in the domestic supply curve for refined petroleum products. The height of the shift is
determined by the after-tax cash flow required to offset the per unit increase in production
costs. Since the control costs vary for each of the domestic refineries, the post-control
supply curve is segmented, or a step function. Underlying production costs for each refinery
are unknown; therefore, a worst case scenario is assumed. The plants with the highest
control costs per unit of production are assumed to also have the highest pre-control per unit
4-5
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TABLE 4.1
Baseline 1992 Domestic Production and Price
Variable/Products
Ethane/Ethylene
Propane/Propylene
Normal Butane/Butylene
Isobutane
Finished Motor Gasoline
Kerosene-Type Jet Fuel
Distillate Fuel Oil
Residual Fuel Oil
Asphalt and Road Oil
Coke
Domestic
Production1
(million bbls)
19.4
176.3
90.1
15.8
2,565.1
529.3
1,070.1
378.1
129.3
154.2
Price2
($1992)
8.53
12.90
15.19
18.61
28.43
25.41
25.51
12.94
30.80
1.36
1 As reported in the 1992 RCRA 3007 Survey
2 Sources: U.S. Department of Energy, Energy Information Administration, Petroleum Marketing Annual, 1993,
Table 4, U.S. Refiner Prices of Petroleum Products for Resale; Platts Oil Gram Spot Price Assessment
(Average of March 6, June 4, October 2, 1992) for ethane/ethylene, propane/propylene, normal
butane/butylene, and isobutane; Pace Consultants for Coke; and the Asphalt Institute for Asphalt.
4-6
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TABLE 4.2
Baseline Inputs for the Petroleum Refining Industry
Variable/Inputs Value
Demand Elasticity (e) -0.646
Supply Elasticity (7) 1.24
Tax Rate (t) 0.34
Private Discount Rate (r) 0.10
Social Discount Rate 0.07
Equipment Life (T)1 20/10 years
Labor (Lo)2 9.12 Workers
Energy (Eo)3 $0.03
Import Ratio4 0.07
Export Ratio5 0.02
Number of Operating Petroleum Refineries 173
1 20-year life assumed for treatment tanks and incinerators and a 10-year life assumed for filtration units.
2 Production workers per million barrels produced per year.
3 Energy expenditures per dollar value of shipments.
* Value of imports divided by value of domestic production, computed from Table 2, Petroleum Supply Annual,
1992, DOE/EIA.
5 Value of exports divided by value of domestic production, computed from Table 2, Petroleum Supply Annual,
1992, DOE/EIA.
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cost of production. Thus, firms with the highest per unit cost of regulatory control are
assumed to be marginal in the post-control market.
4.2.1 Listing Scenario
The lower bound regulatory option, Listing Scenario, assumes an end disposal management
method of Subtitle C landfilling or continued combustion of wastes, where indicated as the
baseline management practice, in a Subtitle C incinerator/BIF. Table 4.3 presents the
economic impacts predicted by the partial equilibrium model.
Primary Economic Impacts - Under this scenario, the average price for all ten
products combined is estimated to increase 0.03 percent. Domestic production is
expected to decrease by 1.3 million barrels per year, representing a 0.03 percent
decrease in annual production. The value of shipments or revenues for domestic
producers are expected to increase for the ten products combined by approximately
$9.0 million annually. This revenue increase results given that the percent increase in
price exceeds the percent decrease in quantity for goods with inelastic demand.
The model estimates that up to two refineries may close as a result of the predicted
decrease in production. Those refineries with the highest per unit control costs are
assumed to be marginal in the post-control market. Refineries that have post-control'
supply prices that exceed the market equilibrium price are assumed to close. This
assumption is consistent with the theory of perfect competition, which presumes all
firms in the industry are price takers. Firms with the highest per unit regulatory
compliance costs may not have the highest underlying cost of production. As a
result, this assumption may overstate the number of plant closures and other adverse
effects of the listing. In addition, a single national market for a homogeneous product
is assumed in the partial equilibrium analysis. There are some regional trade barriers,
however, that would protect individual refineries from closure.
The estimated primary impacts reported depend on the set of parameters used in the
partial equilibrium model. One of the parameters, the price of elasticity of demand,
consists of a range for the ten products evaluated.3 The midpoint of the weighted
average of price elasticities associated with the ten products evaluated was used to
estimate the reported economic impacts. Sensitivity analyses were performed for the
low and high weighted average elasticities. In general, the sensitivity analysis shows
that the estimated primary impacts are relatively insensitive to reasonable changes of
price elasticity of demand estimates.
Secondary Economic Impacts - Implementation of the listings will have an impact on
secondary markets including the labor and energy markets, foreign trade, and regional
3 See Appendix D, Table D.3 for product-specific price elasticities.
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TABLE 4.3
Summary of Economic Impacts
Economic
Impacts
Listing Scenario
Lower Bound1
Listing and
LDR
Scenario
Lower Bound2
Listing and
LDR Scenario
Upper Bound3
PRIMARY ECONOMIC IMPACTS4
Average Price Increase
Over All Products
Annual Production Decrease
Amount (MMbbl)
Percentage Change
Annual Value of Shipments
Amount (MM$92)
Percentage Change
Number of Plant Closures
0.03%
(1.3)
(0.03%)
$9.0
0.01%
0-2
0.08%
(3.27)
(0.06%)
$22.59
0.02%
0-2
0.76%
(30.93)
(0.59%)
$213.34
0.16%
0-2
SECONDARY ECONOMIC IMPACTS3
Annual Job Loss
Number
Percentage Change
Annual Decrease In Energy Use
Amount (MMS92)
Percentage Change
Annual Net Foreign Trade Loss
Amount (MMbbl)
Percentage Change
Dollar Value ($/MMbbl)
(12)
(0.03%)
($1.02)
(0.03%)
(0.20)
(0.12%)
($6.35)
(30)
(0.06%)
($2.57)
(0.06%)
(0.49)
(0.3%)
($15.96)
(282)
(0.59%)
($24.32)
(0.59%)
(4.70)
(2.8%)
($152.60)
assumes an end disposal management method of Subtitle C landfilling or continued combustion of wastes, where
indicated as the baseline management practice in a Subtitle C incinerator/BIF.
2 assumes a pretreatment management method of solidification prior to Subtitle C landfill for metal-based wastes
and combustion in an on-site Subtitle C incinerator/BIF for organic-based wastes for those refineries generating
sufficient quantities to warrant on-site incineration.
assumes a pretreatment management method of solidification prior to Subtitle C landfill for metal-based wastes
and combustion in an off-site Subtitle C incinerator/BIF for organic-based wastes.
brackets indicate decreases or negative values.
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effects. UndeT this scenario, the number of workers employed by firms in SIC 2911
is estimated to decrease by 12 workers annually, representing a 0.03 percent decrease
in total employment. The estimated decrease in employment reflects only direct
employment losses due to reductions in domestic production of refined petroleum
products. Gains in employment anticipated to result from operation and maintenance
of regulatory control equipment have not been included in the analysis due to the lack
of available data. An estimated decrease in energy use of $1.02 million annually is
expected for the industry. As production decreases, the amount of energy input
utilized by the refining industry also declines. The change in energy use does not
consider the increased energy use associated with operating and maintaining the
regulatory control equipment due to the lack of available data. For this reason,
energy impacts may be overstated.
Implementation of the listings will increase the cost of production for domestic
refineries relative to foreign refineries, all other factors held constant. This change in
the relative price of imports will cause domestic imports of refined petroleum
products to increase and domestic exports to decrease. The balance of trade overall
for refined petroleum products is currently negative (i.e., imports exceed exports).
Imposition of the listings will further increase the negative balance of trade. Net
exports are anticipated to decline by 0.20 million barrels annually, representing a 0.12
percent decline. The dollar value of the total decline in net exports is estimated at '
$6.35 million ($1992) annually. No significant regional impacts are anticipated from
implementation of the listings since only up to two facilities are anticipated to close
and impacts overall are minimal.
Economic Welfare Impacts - Regulatory controls affect society's economic well-being
by causing a reallocation of productive resources within the economy. Resources are
allocated away from the production of goods and services (i.e., refined petroleum
products) to waste management and disposal. By definition, the economic costs of
pollution control are the opportunity costs incurred by society for productive
resources reallocated in the economy to regulatory control. The economic cost of this
listings determination can be measured as the value that society places on goods and
services not produced as a result of resources being diverted to increased waste
management and disposal.4
The sum of the change in consumer surplus, producer surplus, and residual surplus to
society constitutes the economic cost of the regulation. Under this scenario, there is a
welfare gain to producers of $24.71 million annually and a welfare loss to consumers
of $43.36 million annually. The residual surplus, which accounts for tax effects and
differences between the private and social discount rates, is estimated at a gain of
4 See Appendix D, Changes in Economic Welfare, for a discussion of measures of consumer, producer, and
residual surplus.
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$14.02 million annually for a net economic cost or opportunity loss to society of
$4.63 million annually (i.e., [(24.71 + 14.02) - 43.36 = -4.'63]). This would
suggest that the loss to society in terms of goods and services not produced, as a
result of resources being diverted to increased waste management and disposal, is
valued at $4.63 million annually.
4.2.2 Listing and LDR Scenario, Lower Bound Regulatory Option
The lower bound regulatory option, Listing and LDR Scenario, assumes a pretreatment
management method of solidification prior to Subtitle C landfill for metal-based wastes and
combustion in a Subtitle C incinerator/BIF for organic-based wastes for those refineries
generating sufficient quantities to warrant on-site incineration. This scenario represents the
most cost-effective option for compliance with the listings and LDRs.
Primary Economic Impacts - Under this scenario, the average price for all ten
products combined is estimated to increase 0.08 percent. Domestic production is
expected to decrease by 3.27 million barrels per year, representing a 0.06 percent
decrease in annual production. The value of shipments or revenues for domestic
producers are expected to increase for the ten products combined by approximately
$22.6 million annually. Similar to the Listing Scenario, it is estimated that up to two
refineries may close as a result of the decrease in production predicted by the model.-
Secondary Economic Impacts - Under this scenario, the number of workers employed
by firms in SIC 2911 is estimated to decrease by 30 workers annually, representing a
0.06 percent decrease in total employment. The estimated decrease in employment
reflects only direct employment losses due to reductions in domestic production of
refined petroleum products. An estimated decrease in energy use of $2.57 million
annually is expected for the industry. Imposition of the listings will further increase
the negative balance of trade. Net exports are anticipated to decline 0.49 million
barrels annually, representing a 0.3 percent decline. The dollar value of the total
decline in net exports is estimated at $15.96 million ($1992) annually. No significant
regional impacts are anticipated from implementation of the listing, since only up to
two refineries are anticipated to close and impacts overall are minimal.
Economic Welfare Impacts - The sum of the change in consumer surplus, producer
surplus, and residual surplus to society constitutes the economic cost of this listings
determination. Under this regulatory option, there is a welfare gain to producers of
$57.7 million annually and a welfare loss to consumers of $108.9 million annually.
The residual surplus, which accounts for tax effects and differences between the
private and social discount rates, is estimated at a gain of $30.9 million annually for a
net economic cost or opportunity loss to society of $20.3 million annually (i.e., [(57.7
+ 30.9) - 108.9 = -20.3]). This would suggest that the loss to society in terms of
goods and services not produced, as a result of resources being diverted to increased
waste management and disposal, is valued at $20.3 million annually.
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4.2.3 Listing and LDR Scenario, Upper Bound Regulatory Option
The upper bound regulatory option, Listing and LDR Scenario, assumes a pretreatment
management method of solidification prior to Subtitle C landfill for metal-based wastes and
combustion in a Subtitle C incinerator/BIF for organic-based wastes.
Primary Economic Impacts - Under this scenario, the average price for all ten
products combined is estimated to increase 0.76 percent. Domestic production is
expected to decrease by 30.9 million barrels per year, representing a 0.59 percent
decrease in annual production. The value of shipments or revenues for domestic
producers are expected to increase for the ten products combined by approximately
$213 million annually. Similar to the Listing Scenario, it is estimated that up to two
refineries may close as a result of the decrease in production predicted by the model.
Secondary Economic Impacts - Under this scenario, the number of workers employed
by firms in SIC 2911 is estimated to decrease by 282 workers annually, representing
a 0.59 percent decrease in total employment. The estimated decrease in employment
reflects only direct employment losses due to reductions in domestic production of
refined petroleum products. An estimated decrease in energy use of $24.32 million
annually is expected for the industry. Imposition of the listings will further increase
the negative balance of trade. Net exports are anticipated to decline 4.7 million
barrels annually, representing a 2.8 percent decline. The dollar value of the total
decline in net exports is estimated at $152.6 million ($1992) annually. No significant
regional impacts are anticipated from implementation of the listing, since only up to
two refineries are anticipated to close and impacts overall are minimal.
Economic Welfare Impacts - The sum of the change in consumer surplus, producer
surplus, and residual surplus to society constitutes the economic cost of this listings
determination. Under the Listing and LDR Scenario, there is a welfare gain to
producers of $616.8 million annually and a welfare loss to consumers of $1,033.75
million annually. The residual surplus, which accounts for tax effects and differences
between the private and social discount rates, is estimated at a gain of $318.58 million
annually for a net economic cost or opportunity loss to society of $98.37 million
annually (i.e., [(616.8 + 318.58) - 1033.75 = -98.37]). This would suggest that the
loss to society in terms of goods and services not produced, as a result of resources
being diverted to increased waste management and disposal, is valued at $98.37
million annually.
4.3 Limitations of the Analysis
Limitations associated with the partial equilibrium model are as follows: First, a single
national market for a homogeneous product is assumed in the partial equilibrium analysis.
There are some regional trade barriers, however, that would protect individual refineries.
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The analysis also assumes that the refineries with the highest control costs are marginal m.
the post-control market. Refineries that are marginal in the post-control market have per unit
control costs that significantly exceed the average. In addition, the cost allocation
methodology assigns all of the control costs to the ten petroleum products evaluated in the
analysis rather than the entire product slate for each refinery. As a result, impacts may be
overestimated for the predicted post-control market equilibrium price and quantity, revenues,
and plant closures. Furthermore, some refineries may find it profitable to expand production
in the post-control market. This would occur when a firm found its post-control incremental
unit cost to be smaller than the post-control market price. Expansion by these firms would
result in a smaller decrease in output and increase in price than otherwise would occur.
Additionally, the economic analysis was based on the listing of five wastestreams including
unleaded gasoline sludge, which has since been removed from the list of wastes to be listed
under this listings determination. As a result, economic impacts for the 98 facilities
generating unleaded gasoline sludge, are overestimated. Also, quantity estimates have been
increased for the facilities generating crude oil tank sludge and CSO tank sludge. These
revised quantity estimates and resulting cost of compliance estimates are not accounted for in
the economic analysis. As a result, economic impacts for facilities generating these sludges
are underestimated for the scenarios presented in Table 4.3. Finally, because the regulatory
options used to evaluate economic impacts differ slightly from those that were used to
calculate the cost of compliance, economic impacts may be underestimated for the upper
bound Listing and LDR Scenario.
4.4 Regulatory Flexibility Analysis
The Regulatory Flexibility Act of 1980 requires agencies to assess the effect of regulations
on small entities and to examine regulatory alternatives that alleviate any adverse economic
effects on this group. Section 603 of the Regulatory Flexibility Act (RFA) requires an Initial
Regulatory Flexibility Analysis (IRFA) to be performed to determine whether small entities
will be affected by the regulation. If affected small entities are identified, regulatory
alternatives that mitigate the potential impacts must be considered. Small entities as
described in the Act are only those "businesses, organizations, and governmental jurisdictions
subject to regulation."
4.4.1 Criteria and Methodology
The analysis described in this section examines whether the listing determination will affect
small entities. EPA sets guidelines and criteria for identifying and evaluating whether a
regulation will have an economic impact on small entities.5 The guidelines address the
following procedures:
5 "EPA Guidelines for Implementing the Regulatory Flexibility Act," Office of Regulatory Management and
Evaluation, Office of Policy, Planning and Evaluation, Revised April 1992.
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Identify the small entities affected by the rule;
Determine if small entities are affected by the rule; and
Determine whether the operating statute allows the Agency to consider regulatory
alternatives to minimize the rule's impacts on small entities.
The Act specifies that the term "small entity" shall be defined as including small businesses,
small organizations, and small government jurisdictions. The Regulatory Flexibility Act
defines small businesses as those firms that satisfy the criteria established under Section 3 of
the Small Business Act. The Agency may use an alternative definition of "small business"
after consultation with the Small Business Administration (SBA) and public comment.
Similarly, alternative definitions of small organizations and small government jurisdictions
are allowed after public comment. The SBA criteria apply to firm size, whereas the
economic impact analysis for this rule is conducted at the facility level (i.e., refinery level).
For single-plant firms, the SBA criteria can be applied directly. For firms (i.e., companies)
owning more than one refinery, crude capacity is aggregated for all plants (i.e., refineries) to
determine the overall size of the company.
For all identified small entities, EPA guidelines suggest four criteria be applied to evaluate
the severity of impacts on small businesses:
Compare total annual compliance cost (i.e., capital, operating, reporting, etc.) to
operating characteristics of the firm, such as: annual sales, annual operating
expenditures, net profits, cash flow, working capital, and net worth.
Compare capital compliance costs to operating characteristics of the firm, such as
net worth and working capital.
Compare administrative costs to operating characteristics of the firm, such as net
profits, labor costs, working expenditures, and cash flow.
Examine administrative requirements in comparison with supply of personnel and
resources, training requirements, technical capabilities, and workload demands placed
on existing employees.
4.4.2 Screening Analysis: Small Entity Impacts
For SIC 2911, Petroleum Refining, the Small Business Administration defines small entities
as those companies with refinery capacity less than or equal to 75,000 barrels of crude per
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calendar day.6 .Based on this criterion, approximately 56 percent or 45 of the 80 companies
affected by the listing determination are considered to be small.
Even under the highest cost scenario, the estimated impacts of this listings determination are
minimal. Predicted price increases and reductions in domestic output are less than 1 percent
for the products evaluated. The small magnitude of predicted job loss directly results from
the relatively small decrease in production anticipated and the relatively low labor intensity in
the industry. Given the magnitude of the estimated compliance costs, refineries are expected
to incur minimal economic impacts.
Under the Agency's Revised Guidelines for Implementing the Regulatory Flexibility Act, the
Agency is committed to considering regulatory alternatives in rulemakings when there are
any estimated economic impacts on small entities. Despite the high percentage of small
entities in the population affected by this listings determination, anticipated impacts as a
result of implementation of the listings are minimal, with only up to two plant closures
predicted under each of the scenarios evaluated. Because economic impacts are estimated to
be minimal, no small entity exemptions or options were judged to be necessary in an effort
to reduce economic impacts on small entities.
6 "EPA Guidelines for Implementing the Regulatory Flexibility Act," Office of Regulatory Management and
Evaluation, and Office of Policy, Planning and Evaluation, Appendix C, 13 CFR, Part 121, Revised April 1992.
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APPENDIX A
ANNUALIZED INCREMENTAL COMPLIANCE COSTS
FOR THE PETROLEUM REFINING HAZARDOUS WASTE LISTINGS
LISTING SCENARIO
($ millions)
Waste Stream
K169
K170
K171
K172
RCRA
Number of
Facilities with
Non-Exempt Waste
Management Trains
145
101
130
55
162
TOTALS
Total Annualized
Waste Quantity
(Metric Tons)*
Average
(Low-High)
80,300
[45,900- 114,700]
26,800
[18,300-35,400]
6,800
[6,700 - 6,900]
20,800
[20,700 - 20,900]
NA
134,800
[91,600- 177,900]
Total Annual
Baseline Cost
Average
(Low-High)
$2.8
[$1.6- $4.0]
$2.1
[$1.5 -$2.8]
$4.8
($4.5 -$5.2]
$8.4
[$7.9 - $8.9]
$0.0
]$0.0 - $0.0]
Total Annual
Compliance Cost
Average
(Low-High)
$3.8
[$1.9 -$6.4]
$3.9
[$2.1 -$6.2]
$5.8
|$4.1 -$7.7]
$9.1
[$6.5 - $12.0)
$0.5
[$0.4 - $0.6]
Total Annual Incremental i
Cost of Compliance
Average
(Low-High)
$2.2
[$1.0- $3.9|
$2.8
[$1.4- $4. 8]
$1.3
[$0.8 - $2.9]
$1.5
[$0.7 - $3.8]
$0.5
[$0.4 - $0.6]
$8.3
[$4.3 -$16.0]
* Average quantity generated to daily crude rate ratios of similar waste streams at reporting facilities were applied to non-reporting facilities.
A-l
-------
APPENDIX B
ANNUALIZED INCREMENTAL COMPLIANCE COSTS
FOR THE PETROLEUM REFINING HAZARDOUS WASTE LISTINGS
LAND DISPOSAL RESTRICTIONS SCENARIO
($ millions)
Waste
Stream
K169
K170
K171
K172
RCRA
Number of
Facilities
with
Non-Exempt
Waste
Management
Trains
145
101
130
55
162
TOTALS
Total Annual! zed
Waste Quantity
(Metric Tons)*
Average
(Low-High)
80,300
[45,900- 114,700|
26,800
[18,300-35,400]
6,800
[6,700 - 6,900]
20,800
[20,700 - 20,900]
NA
134,800
[91,600- 177,900]
Total Annual
Baseline Cost
Average
(Low-High)
$2.8
[$1.6 -$4.0]
$2.1 .
[$1.5 - $2.8[
$4.8
[$4.5 - $5.2]
$8.4
[$7.9 - $8.9]
$0.0
[$0.0 - $0.0]
LDR Scenario, Option I
Off-Site Incineration of Sludges and
Off-Site Incineration and Vitrification
of Catalysts
Total Annual
Compliance Cost
Average
(Low-High)
$23.8
[$10.5 - $42.0]
$24.2
($12.3 - $39.8]
$9.6
($6.9 - $12.6]
$19.5
[$14.3 - $25.0]
$0.5
[$0.4 - $0.7]
Total Annual
Incremental Cost of
Compliance
Average
(Low-High)
' $21.6
[$9.3 - $38.8]
$22.5
[$11. 2 -$37.6]
$5.1
($3.5 - $7.6]
$11.6
[$8.3 - $16.5]
$0.5
[$0.4 - $0.7]
$61.3
[$32.7- $101.2]
LDR Scenario, Option 2
On-/Off-Site Incineration of Sludges '
and Regeneration/Reclamation
of Catalysts
Total Annual
Compliance Cost
Average
(Low-High)
$18.9
[$9.3 -$31. 6]
$18.4
[$10.5 - $28.5]
$6.9
[$4.6 - $9.5]
$11.8
($8.0 -$16.3]
$0.8
[$0.6-$1.0|
Total Annual
Incremental Cost of
Compliance
Average
(Low-High)
$16.7
($8.1 -$28.3]
$16.8
[$9.4 - $26.5]
$2.3
[$1.2 -$4.5]
$3.9
[$1.9 -$7.9]
$0.8
[$0.6 - $1.0]
$40.6
[$21. 3- $68.3|
Average quantity generated to daily crude rate ratios of similar waste streams at reporting facilities were applied to non-reporting facilities.
B-l
-------
APPENDIX C
ANNUALIZED INCREMENTAL COMPLIANCE COSTS
FOR THE PETROLEUM REFINING HAZARDOUS WASTE LISTINGS
CONTINGENT MANAGEMENT SCENARIO
($ millions)
Waste
Stream
K169
K170
K171
K172
RCRA
Number of
Facilities
with
Non-Exempt
Waste
Management
Trains
145
101
130
55
162
TOTALS
Total Annualized
Waste Quantity
(Metric Tons)*
Average
(Low-High)
80,300
(45,900- 114,7001
26,800
118,300-35,4001
6,800
[6,700 - 6,900]
20,800
[20,700 - 20,9001
NA
134,800
[91,600- 177,9001
Total Annual
Baseline Cost
Average
(Low-High)
$2.8
[$1.6-$4.0|
$2.1
[$1.5 -$2.8)
$4.8
[$4.5 - $5.2]
$8.4
[$7.9 - $8.9|
$0.0
[$0.0 - $0.01
Contingent Management Scenario, Option 1
Subtitle P Landfill and Land Treatment
(w/ controls) of CSO Sludge,
On-/Off-Site Incineration
of Crude Oil Tank Sludges and
Regeneration/Reclamation of Catalysts
Total Annual
Compliance Cost
Average
(Low-High)
$19.7
1$9.7 - $33.0)
($0.5)
[($0.3)-(<$0.1)J
$6.9
[$4.6 - $9.5]
$11.8
[$8.0 - $16.3]
$0.6
[$0.5 - $0.8)
Total Annual
Incremental Cost of
Compliance
Average
(Low-High)
$17.5
[$8.5 - $29.8]
($0.5)
[($0.3) - ($0.8)]
$2.3
[$1.2 -$4.5]
$3.9
[$1.9 -$7.91
$0.6
($0.5 - $0.8]
$23.8
[$11. 8- $42.2|
Contingent Management Scenario, Option 2
i
Subtitle D Landfill and Land Treatment
(w/ controls) of CSO Sludge,
Subtitle D Land Treatment (w/ controls)
of Crude Oil Tank Sludges and
Regeneration/Reclamation of Catalysts
Total Annual
Compliance Cost
Average
(Low-High)
$1.0
[$0.7 -$1.2]
($0.5)
[($0.3)-(<$0.1)|
$6.9
l$4.6 - $9.5|
$11.8
[$8.0 -$16. 3]
$0.5
[$0.3 - $0.6]
Total Annual
Incremental Cost of
Compliance
Average
(Low-High)
($0.5)
|($0.2) -($1.0)1
($0.5)
1($0.3) - ($0.8)|
$2.3
[$1.2 -$4.5]
$3.9
[$1.9 -$7.9]
$0.5
[$0.3 - $0.6]
$5.6
[$3.1 -$11.2]
Average quantity generated to daily crude rate ratios of similar waste streams at reporting facilities were applied to non-reporting facilities.
C-l
-------
APPENDIX D
ECONOMIC METHODOLOGY1
This appendix presents details of the economic methodology and algorithms used to calculate
economic impacts. The first and second sections present an overview of partial equilibrium
analysis and the algorithms used in the model. The calculation of market demand and supply
elasticities is discussed in the third section.
Introduction
The economic methodology used in this analysis is outlined in this section. The following
subsections present the baseline values used in the partial equilibrium analysis and describe the
analytical methods used to conduct each of the following analyses:
Partial equilibrium analysis
Impact of control costs on market price and quantity
Trade impacts and plant closures
Economic surplus changes
Labor and energy impacts
Market Model
Partial Equilibrium Analysis
A partial equilibrium model is used by economists to evaluate a single market for a commodity,
in this case, petroleum products, in isolation. Given fixed prices of all other commodities, the
conditions for equilibrium in a single market can be examined. The economic analysis uses a
partial equilibrium model to evaluate economic impacts of the listing determination on the
petroleum refining industry in an effort to specify market demand and supply, estimate the post-
control shift in market supply, predict the change in market equilibrium (price and quantity), and
estimate plant closures.
This appendix was prepared with the assistance of MathTech, Inc. and information contained in "Economic
Impact Analysis For the Petroleum Refinery NESHAP," Revised Draft, Office of Air Quality Planning and Standards,
U.S. EPA, Research Triangle Park, NC, EPA Contract No. 68-D1-0144, March 15, 1994.
D-l
-------
Market Demand and Supply
The baseline or pre-control petroleum refining market is defined by a domestic market demand
equation, a domestic market supply equation, and a foreign market supply equation. The
following equations identify the market demand, supply, and equilibrium conditions:
Qd = «P (EQ-1)
02 = /3P7 (EQ-2)
Q.f = PP7 (EQ-3)
Qd = Q* + Q[ = Q (EQ-4)
where,
Q = annual output or quantity of petroleum products purchased in the U.S.
Qd = annual quantity of the petroleum products domestically demanded
02 = annual quantity of the products produced by domestic suppliers
Qf = annual quantity of the products supplied by foreign producers to the
domestic economy
P = price of the petroleum product
Superscripts e and 7 reference price elasticity of demand and price elasticity of supply,
respectively.
The constants a, j8 and p are computed such that the baseline equilibrium price is normalized
to one. The market specification assumes that domestic and foreign supply elasticities are the
same. This assumption was necessary because data were not readily available to estimate the
price elasticity of supply for foreign suppliers.
Market Supply Shift
The domestic supply equation shown above may be solved for the price of the petroleum
product, P, to derive an inverse supply function that will serve as the baseline supply function
for the industry. The inverse domestic supply equation for the industry is as follows:
(EQ-5)
D-2
-------
A rational profit maximizing firm will be willing to supply the baseline (pre-control) output if
the price of the product it sells increases by an amount that recovers the capital and operating
costs of the regulatory control requirements over the useful life of the equipment. This
relationship is identified in the following equation:
[(C * Q)-(V+D)](l-t)*D = K + yl (EQ.6)
O
where,
C = increase in the supply price
Q = annual output
V = measure of annual operating and maintenance costs of controls
t = marginal corporate income tax rate
S = capital recovery factor
D = annual depreciation (straight-line depreciation is assumed)
K = the present value of the investment cost of control and closure equipment
V1 = the present value of periodic operating and maintenance costs of controls
Solving for C yields the following expression:
C - (K+vl)S-P H. V+D (EQ-7)
Q(l-t) Q
Estimates of the annual operation and maintenance control costs and of the investment costs for
treatment and disposal (V, V1 and K, respectively) were obtained from industry averages derived
from the 1992 RCRA 3007 Survey, previous listings documents including the land disposal
restrictions RIAs, and engineering studies.
D-3
-------
Values for K are computed as:
K = £ K, * f, (EQ-8)
k
where the subscript k references the timing (in years) of up front and future capital costs, where
fk = 1/(1 + r)k
Similarly, we compute V as
V1 = £ Vv * fv (EQ-9)
where the subscript v references the timing of up front and periodic (non-annual) operating and
maintenance costs and
fv =
Depreciation (D) and the capital recovery factory (S) are computed as follows:
D = 1/T£ Kk * fk (EQ-10)
k
S = r(l+r)T/[(l+r)T-l] (EQ-11)
where, r equals the discount rate or cost of capital faced by producers and is assumed to be a
rate of 10 percent and T is the life of the post-control treatment equipment.
D-4
-------
Regulatory control costs will raise the supply price for each refinery by an amount equivalent
to the per unit cost of the annual recovery of investment costs and annual and periodic operating
costs of the regulatory control equipment or Q (where /' denotes domestic refinery 1 through
168). The aggregate domestic market supply curve does not identify the supply price for
individual plants. Therefore, we adopt a worse-case assumption that marginal plants (highest
cost producers) in the post-control market also face the highest compliance cost (per unit of
output). Based on this assumption, the post-control supply function becomes the following:
P = (Qs/ft"1' + C(Q, q,.) (EQ-12)
where,
C(C,-, q^) = a function that shifts the post-control supply function
Q = vertical shift that occurs in the supply curve for the zth refinery o reflect
post-control costs, sorted by per unit control costs
q,- = quantity produced by the zth refinery
This shift in the supply curve is illustrated in Figure D-l.
Impact of Supply Shift on Market Price and Quantity
The impact of the listing determination on market equilibrium price and output is derived by
solving for the post-control market equilibrium and comparing the new equilibrium price and
quantity to the pre-control equilibrium. Since the post-control domestic supply is segmented,
a special algorithm was developed to solve for post-control market equilibrium. The algorithm
first searches for the segment in the post-control supply function at which equilibrium occurs and
then solves for the post-control market price that clears the market.
Since the market clearing price occurs where demand equals post-control domestic supply plus
foreign supply, the algorithm simultaneously solves for the following post-control variables:
equilibrium market price
equilibrium market quantity
change in the value of domestic production or revenues to producers
quantity supplied by domestic producers
quantity supplied by foreign producers
The market impacts of control costs are assessed by comparing baseline equilibrium values with
post-control equilibrium values for each of the variables listed above.
D-5
-------
FIGURE D-l
Post-Control Shift in the Supply Curve
(Not Drawn to Scale)
S0 = Pre-Control Industry Supply Curve
Si = Post-Control Industry Supply Curve
P0 = Pre-Control Equilibrium Price
PI = Post-Control Equilibrium Price
D-6
-------
Trade Impacts-
Trade impacts are reported as the change in both the volume and dollar value of net imports
(exports minus imports). It is assumed that exports comprise an equivalent percentage of
domestic production in the pre- and post-control markets. The supply elasticities in the
domesticand foreign markets have also been assumed to be equal. As the volume of imports
rises and the volume of exports falls, the volume of net exports will decline. However, the
dollar value of net exports might rise when demand is inelastic, as is the case for the petroleum
products of interest. The dollar value of imports will increase since both the price and quantity
of imports increase. Alternatively, the quantity of exports will decline, while the price of the
product will increase. Price increases for products with inelastic demand result in revenue
increases for the producer. Consequently, the dollar value of exports is anticipated to increase.
Since the dollar value of imports and exports rise, the resulting change in the value of net
exports will depend on the magnitude of the changes for imports relative to exports.
The following algorithms are used to compute the trade impacts:
AQ °<
AVIM
= Q," - Qos'
(P, Q,'1)- (P0.Q0Sr)
Qo
AVX = P,
(EQ-13)
x'0 - P0 x Qx'<
where,
AQ
sf
AVX
the change in volume of imports
the change in the dollar value of imports
the change in the volume of exports
the change in the dollar value of exports
the quantity of exports by domestic producers in the pre-control
market
Subscripts 0 and 1 refer to the pre- and post-control equilibrium values, respectively. All other
terms have been previously defined.
The change in the quantity of net exports (ANX) is simply the difference between the change in
the volume of imports, expressed as AQx5d - AQsf. The reported change in the dollar value of
net exports (AVNX) is the difference between the equations for change in the value of exports
and the change in the value of imports, or AVX - AVIM.
D-7
-------
Plant Closures
It is assumed that a refinery will close if its post-control supply price exceeds the post-control
market equilibrium price. Post-control supply prices for the individual refinery are computed
as described in Industry Supply and Demand Elasticities.
Changes in Economic Welfare
Regulatory control requirements will result in changes in the market equilibrium, price and
quantity of petroleum products produced and sold. These changes in the market equilibrium
price and quantity will affect the welfare of consumers of petroleum products, producers of
petroleum products, and society as a whole. The procedure for estimating the welfare change
for each group is presented below in the following subsections.
Change in Consumer Surplus. The change in consumer surplus includes losses of
surplus incurred by both foreign consumers (of U.S. exports) and domestic
consumers. Although the change in domestic consumer surplus is the object of
interest, no method is available to distinguish the marginal consumer as domestic or
foreign. Therefore, an assumption is made that the consumer surplus change is
allocable to the foreign and the domestic consumer in the same ratio as sales are
divided between foreign and domestic consumers in the pre-control market. The
change in domestic surplus (ACSJ becomes the following:
ACSd = [1 -
i ACS (EQ-14>
where
ACS = I (Q/a)1/£ - P0Q0 + FjQ, (EQ-15)
Q,
ACSd represents the change in domestic consumer surplus that results from the
change in market equilibrium price and quantity resulting from the imposition of
regulatory controls. While ACS includes foreign consumer surplus losses due to
purchases of U.S. exports, ACSd is the change in consumer surplus relevant to the
domestic economy.
D-8
-------
Change in Producer Surplus. The change in producer surplus is composed of two
elements. The first element relates to surplus losses on output eliminated as a result
of reduced post-control equilibrium quantity. The second element is associated with
the change in price and higher costs of production due to compliance with the
regulation. The total change in producer surplus is the sum of these two
components. After-tax measures of surplus changes are required to estimate the
impacts of controls on producers' welfare. The after-tax surplus change is computed
by multiplying the pre-tax surplus change by a factor of 1 minus the tax rate, (1-t),
where t is the marginal tax rate.
Output eliminated as a result of control costs causes producers to suffer a welfare
loss in producer surplus. The post-control welfare loss on eliminated output is given
by:
- J
dQ
(1-t)
(EQ-16)
Refineries remaining in operation after regulatory controls are implemented realize
a welfare gain of PI P0 on each unit of production for the incremental increase in
the price and realize a decrease in welfare per unit for the capital and operating cost
of implementing the required control equipment of Q. The post-control loss in
producer surplus for refineries remaining in the market is specified by the following
equation:
(EQ-17)
The total post-control loss in producer surplus, APS, is given by the sum of (EQ-16)
and (EQ-17). Specifically,
APS =
- J
Q,d
Q.t
D-9
(EQ-18)
-------
Since domestic surplus changes are the subject of interest, the welfare gain
experienced by foreign producers due to higher prices is not considered. This
procedure treats higher prices paid for imports as a dead-weight loss in consumer
surplus. From a world economy perspective, higher prices paid to foreign producers
represent a transfer of surplus from the United States to other countries. The higher
prices paid for imports represent a welfare loss from the perspective of the domestic
economy.
Residual Effect on Society. The changes in economic surplus, as measured by the
changes in consumer and producer surplus, previously discussed must be adjusted
to reflect the true change in social welfare as a result of regulation. The adjustments
are necessary due to tax effects differences and to the difference between the private
and social discounts rates.
Two adjustments to economic surplus are necessary to account for tax effects. The
first relates to the per unit control cost Q that reflects after-tax control costs and is
used to predict the post-control market equilibrium. The true cost of regulatory
treatment and disposal requirements must be measured on a pre-tax basis.
A second tax-related adjustment is required because changes in producer surplus
have been reduced by a factor of (1-t) to reflect the after-tax welfare impacts of
regulatory treatment and disposal requirement costs on affected refineries. As noted
previously, a dollar loss in pre-tax producer surplus imposes an after-tax burden on
the affected refinery of (1-t) dollars. In turn, a one dollar loss in after-tax producer
surplus causes a complimentary loss of t/(l-t) dollars in tax revenues.
Economic surplus must also be adjusted because of the difference between private
and social discount rates. The private discount rate is used to shift the supply curve
of refineries in the industry since this rate reflects the marginal cost of capital to
affected refineries. The economic costs of the regulation, however, must consider
the social cost of capital. This rate reflects the social opportunity cost of resources
displaced by investments in regulatory treatment and disposal equipment.
The adjustment for the two tax effects and the social cost of capital are referred to
as the residual change in economic surplus, ARS. This adjustment is given by the
following equation:
m
ARS = -Y (C.-pc.)q. + APS * [t/(l-t)] (EQ-19)
D-10
-------
where, pc; equals the per unit cost of controls for each refinery with the tax rate
assumed to be zero, the discount rate assumed to be the social discount rate of 7
percent.
Total Economic Costs. The total economic costs of the listings, EC, are the sum
of the losses in consumer surplus, producer surplus, and the residual surplus.
This relationship is defined in the following equation:
EC = ACS + APS + ARS (EQ-20)
Labor and Energy Impacts
The estimates of the labor and energy market impacts associated with this listing determination
are based on input-output ratios and estimated changes in domestic production. The
methodologies used to estimate each impact are described below in the following subsections.
Labor Impacts. The labor market impacts are measured as the number of jobs
lost due to domestic output reductions. The estimated number of job losses are
a function of the change in level of production that is anticipated to occur as a
result of this listing determination. The change in employment is computed as
follows:
AL = Q- * Q, (EQ-2D
where, AL equals the change in employment and L0 equals the baseline employ-
ment level. All other variables have previously been defined.
Energy Impacts. The reduction in energy inputs associated with the listing
determination results from the reduction in expenditures for energy inputs due to
production decreases. The expected change in use of energy inputs is calculated
as follows:
AE ,
where, AE equals the change in expenditures on energy inputs and EO is the
baseline expenditure on energy inputs per dollar of refined petroleum output. All
other variables have previously been defined.
D-ll
-------
Baseline Inputs
The partial equilibrium model described above requires baseline values for variables and
parameters that characterize the petroleum refining market. Table D. 1 lists baseline prices and
production volumes for the petroleum products. Table D.2 lists variables and parameters that
are assumed to be the same for all petroleum products.
The baseline conditions in the petroleum refining industry are characterized by the baseline
parameters and variables in the tables. The baseline market prices ($1992) were obtained from
the Petroleum Market Annual, 1993. Prices are stated in cents per gallon excluding taxes.
Quantities of petroleum products produced (1992) were obtained from the 1992 RCRA 3007
Survey. Quantity (i.e., refinery output) data are reported in millions of barrels per stream day.
Imports and exports of the ten petroleum products of interest (1992) were obtained from the
Petroleum Supply Annual, 1992. Sources for the price elasticity of supply and demand are
discussed in the following section, Industry Supply and Demand Elascities. A marginal tax rate
of 34 percent, private discount rate of 10 percent, and social discount rate of 7 percent are
assumed in the economic analysis. An equipment life of 20 years was assumed for
treatment/disposal units including tanks and incinerators and 10 years for filtration units. The
number of workers per unit of output (L) and the energy expenditures per value of shipments
(E) were derived from the U.S. Department of Commerce, Annual Survey of Manufactures
(ASM), 1991. Data from the ASM used to derive these estimates include the 1991 annual values,
for total number of workers employed, total expenditures on energy, and the value of shipments
for SIC 2911.
Data inputs also include the number of domestic refineries operating in 1992 and annual
production per refinery. The number of operating refineries and annual production per refinery
were obtained from the 1992 RCRA 3007 Survey.
As Table D.I indicates, petroleum refineries produce several products. However, compliance
costs for the hazardous waste listing cannot be allocated to any specific products. Accordingly,
output in the partial equilibrium model is defined as a composite, bundled good equal to the sum
of price multiplied by the weighted production volumes of each product. Specifically, we define
Qi, the composite production level for refinery i, as follows:
0. E P»' * Qwi (EQ-23)
where, P equals product prices and the subscript w references the various products listed in
Table D. 1. The baseline price of the composite product is normalized to unity (i.e., one dollar).
Given these definitions, the partial equilibrium model predicts percentage changes in price and
output levels.
D-12
-------
In some cases, impacts- are reported in barrels rather than in units of the composite good for ease
of interpretation. Production measures are converted to barrels by dividing production of the
composite good by the weighted average refined product price, where the average is computed
across industry-wide production.
Industry Supply and Demand Elasticities
Demand and supply elasticities are crucial components of the partial equilibrium model that is
used to quantify the economic impact of regulatory control cost measures on the petroleum
refinery industry. This section discusses the price elasticities of demand and supply used as
inputs to the partial equilibrium analysis. Estimates of price elasticities of demand for several
refined products were available from the economic literature. The price elasticity of supply used
for this analysis was estimated by Pechan and Math tech (1993).
Price Elasticity of Demand
The price elasticity of demand, or own-price elasticity of demand, is a measure of the sensitivity
of buyers of a product to a change in price of the product. The price elasticity of demand
represents the percentage change in the quantity demanded resulting from each 1 percent change
in the price of the product.
Petroleum products represent a very important energy source for the United States. Many
studies have been conducted which estimate the price elasticity of demand for some or all of the
petroleum products of interest. Over one hundred studies of the demand for motor gasoline
alone have been conducted (see Dahl and Stern for a survey of these model results). Numerous
published sources of the price elasticity of demand for petroleum products exist and are
discussed in detail in the Industry Profile for the Petroleum Refinery NESHAP (Pechan, 1993).
Ranges in estimates of own-price elasticities of demand for several refined products are listed
in Table D.3.
As noted earlier, refinery production is defined as a bundled, composite good of products refined
at domestic plants. As a result, the partial equilibrium model requires a corresponding
composite price elasticity. We compute the composite demand elasticity as the weighted average
of the mid-points of the range reported in Table D.3. Specifically, we compute the composite
demand elasticity, e, as
w (EQ-24)
where, the subscript w references the refined products listed in Table D.3, the e are the mid-
points of the ranges listed in Table D.3, and the Q are industry-wide production levels of refined
products.
D-13
-------
The demand elasticity estimates for the individual products that are components of the composite
elasticity are close in magnitude. As Table D.3 indicates, the lower and upper ranges of the
estimates for seven of the ten products are bounded by -0.50 and -1.00. While the estimate for
jet fuel, -0.15, falls outside this range, it is more inelastic, meaning that using the composite
elasticity will overstate somewhat the adverse impacts for this product.
Price Elasticity of Supply
The price elasticity of supply or own-price elasticity of supply, is a measure of the
responsiveness of producers to changes in the price of a product. The price elasticity of supply
indicates the percentage change in the quantity supplied of a product resulting from each 1
percent change in the price of the product.
Few estimates of the price elasticity of supply are available in the economic literature. Two
studies estimate the price elasticity of supply for gasoline to be 1.962 and 1.473, respectively.
However, both studies use data covering time periods during the decade of 1979 and,
accordingly, are somewhat dated. This analysis uses the estimate reported by Pechan and
Mathtech (1993). This study estimates a supply elasticity of 1.24 for the composite of refined
products listed in Table D.3. As a result, it is consistent with the composite demand elasticity
used in this analysis.
2 Zarate, Marco, Letter from Marco A. Zarate to James Durham, U.S. Environmental Protection Agency,
Chemical and Petroleum Branch, November 30, 1993.
3 Murphy, Patrick, Letter from Patrick Murphy, Radian to James Durham, U.S. Environmental Protection Agency,
Chemical and Petroleum Branch, December 3, 1993.
D-14
-------
TABLE D.I
Baseline 1992 Domestic Production and Prices
Variable/Products
Ethane/Ethylene
Propane/Propylene
Normal Butane/Butylene
Isobutane
Motor Gasoline
Kerosene-Type Jet Fuel
Distillate Fuel Oil
Residual Fuel Oil
Asphalt and Road Oil
Coke
Domestic
Production1
(millions bbls)
19.4
176.3
90.1
15.8
2,565.1
529.3
1,070.1
378.1
129.3
154.2
Price2
(1992 $)
8.53
12.90
15.19
18.61
28.43
25.41
25.51
12.94
30.80
1.36
1 As reported in the 1992 RCRA 3007 Survey
2 Sources: U.S. Department of Energy, Energy Information Administration, Petroleum Marketing Annual, 1993, Table
4, U.S. Refiner prices of Petroleum Products for Resale; Plait's Oil Gram Spot Price Assessment (Average of
March 6, June 4, October 2, 1992) for ethane/ethyiene, propane/propylene, normal butane/butylene, and
isobutane; Pace Consultants for Coke; and the Asphalt Institute for Asphalt.
D-15
-------
TABLE D.2
Baseline Inputs for the Petroleum Refining Industry
Variable/Inputs
Value
Demand Elasticity (e)
Supply Elasticity (7)
Tax Rate (t)
Private Discount Rate (r)
Social Discount Rate
Equipment Life (T)
Labor (L0)'
Energy (Eo)2
Import Ratio3
Export Ratio4
Number of operating petroleum refineries
-0.646
1.24
0.34
0.10
0.07
20 years
9.12 Workers
$0.03
0.07
0.02
175
1 Production workers per million barrels produced per year.
2 Energy expenditures per dollar value of shipments.
3 Value of imports divided by value of domestic production, computed from Table 2, Petroleum Supply Annual, 1992,
DOE/EIA.
4 Value of exports divided by value of domestic production, computed from Table 2, Petroleum Supply Annual, 1992,
DOE/EIA.
D-16
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TABLE D.3
Estimates of Price Elasticity of Demand1
Fuel Type
Long-Run
Elasticity
Motor Gasoline
Jet Fuel
Residual Fuel Oil
Distillate Fuel Oil
Liquified Petroleum Gases2
-0.55 to -0.82
-0.15
-0.61 to -0.74
-0.50 to -0.99
-0.60 to-1.0
1 Elasticities were not available for coke and asphalt.
2 Represents the elasticity for the following products-- ethane/ethylene, propane/propylene, normal butane/butylene, and
isobutane/isobutylene.
D-17
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DOCUMENT 2
"OTHER BENEFITS" FROM RECOVERY OF OIL
IN COKER PROCESSING UNITS
August 24, 1995 .
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MEMORANDUM
TO: Andy Wittner, EPA/OSW/RAB
FROM: Dave Gustafson and Chris Lough, DPRA Incorporated
DATE: August 24, 1995
SUBJ: "Other Benefits" from Recovery of Oil in Coker Processing Units
This memorandum presents our current understanding of the "coker exemption" and its
potential benefits to the petroleum refining industry based on a conversation with you, Max
Diaz and a review of the draft preamble language.
Policy Decision
EPA is including cokers under the definition of a petroleum refining process (e.g.,
distillation unit, catalytic cracker, and fractionation unit). Therefore, all oil-bearing residuals
that are generated at petroleum refineries and reinserted into the petroleum refining process
are excluded from regulation under the definition of solid waste.
As a result, previously listed wastes for the petroleum refining industry may now be recycled
back to cokers and no longer be defined as a hazardous waste. It is up to the industry to
prove that these wastes are oil-bearing. The wastes include the following:
F037 - primary separation sludge;
F038 - secondary separation sludge;
K048 - dissolved air floatation (DAF) float;
K049 - slop oil emulsion solids; and
K051 - API separator sludge.
Also note, cokers are viewed as process units under the Clean Air Act and are subject to
regulations under the National Emission Standards for Hazardous Air Pollutants from
petroleum refineries.
Background
The primary purpose of a petroleum coker is to upgrade lower value hydrocarbons into light
ends that are used to produce more valuable product fuels. While coke is being produced,
the coker thermally converts longer-chained (heavy) hydrocarbons to middle-chained and
short-chained (light end) hydrocarbons that are used to produce high grade fuels (e.g.,
gasoline, kerosene, jet fuel, etc.). A typical coker yields about 30% petroleum coke and
-------
70% light hydrocarbons. The light hydrocarbons are returned to the refining process to
produce high grade fuels.
Some facilities are already recycling previously listed wastes ("unofficially") back to the
coker. The listed wastes are transferred from wastewater treatment tanks to the coker via a
closed system. The wastes are conveyed via hard pipe or tank trucks to stationary tanks or
containers where oil is recovered and/or secondary materials are prepared for insertion into
the coker.
Because of the high water content, these wastes are being used in the quench (i.e., cooling)
process. When the coke product is ready it is quenched with water because the coker
operates at approximately 900 degrees Fahrenheit. The recycled wastes are fed into the
coker as a slug ahead of the quench water. Most of the oil fraction (70 percent) is
volatilized with the off gases and recovered in the light hydrocarbon product stream. The
remaining heavy fraction (30 percent) is converted into coke. At the same time, because of
the low heating value (high water content) of the waste, the coke will begin to be cooled
(quenched). After the waste has been fed into the coker, quench water is fed into the coker
unit to complete the cooling process.
The facility has a couple of limitations to consider when feeding the wastes into the coker.
If the solids content is too high, the injection nozzles may clog. If too much water is added
the system may "vapor lock." DPRA assumes that vapor lock means that too much water
vapor and hydrocarbon gases are generated too quickly to be handled through the stack,
causing a pressure build-up which either triggers system shut-down; or if cokers have an
open-burner (i.e., flame), similar to incinerators, it may be extinguished causing system
failure. DPRA would need to research coker process systems to clarify how these wastes
can cause process upsets, but, that is beyond the scope of our immediate needs. If the waste
has too high of an ash content, the value of the petroleum coke may be reduced. Finally,
cokers can be continuous processes. If the coker shuts down, refinery processes linked to
the coker will need to be altered or shut down. Therefore, it appears that the coker
operators have some incentives to maintain proper coker operation. Once again, we do not
truly know how much leeway operators have in the "quality" of their coker feed streams.
Waste Stream Characteristics
The following table presents estimates of the waste stream characteristics for the previously
listed wastes. Characterization data was obtained from the "Regulatory Impact Analysis for
the Listings of Primary and Secondary Oil/Water/Solids Separation Sludges from the
Treatment of Petroleum Refinery Wastewaters" (October 1990) and "Background Document
for Capacity Analysis for F037 and F038 Petroleum Refining Wastes to Support 40 CFR 268
Land Disposal Restrictions" (December 1991).
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E-1500 First National Bank Building St. Paul. Minnesota 55101-1314 Te!ennone 612-227-550C ' < 512-227-5522
April 9, 1997
Mr. Andrew Wittner
U.S. Environmental Protection Agency, Crystal Station
Office of Solid Waste
Economics, Methods and Risk Assessment Division
2800 Crystal Drive
Arlington, Virginia 22202
RE: Cost Impact Analysis of the Definition of Solid Waste Headworks Exemption for the
Proposed Listings of Three Petroleum Refining Industry Wastes;
DPRA WA No. 3825.202
Dear Andy:
Attached is the final draft report of the Cost Impact Analysis of the Definition of Solid Waste
Headworks Exemption for the Proposed Listings of Three Petroleum Refining Industry
Wastes. If no headworks exemption or conditional exemption are granted, the cost for off-
site management of tank and reactor wastewaters (wash waters), at an expected value of
$11.4 million, will be almost twice the cost associated with the management of the sludges
and catalysts, at approximately $5.9 million under the Listing Scenario.
Please call me with any questions or comments at 612/227-6500,
Sincerely,
Dave Gustafson
Senior Associate
cc: Gwen Di Pietro, SAIC
John Vierow, SAIC
Chris Lough, DPRA
Mailing Address: P.O1. Box 727 Manhattan. Kansas 66505 Telephone 913-539-3565 FAX 913-539-5353
Courier Address: 200 Research Drive Manhattan. Kansas 66503
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COST IMPACT ANALYSIS
OF THE DEFINITION OF SOLID WASTE HEADWORKS EXEMPTION
FOR THE PROPOSED LISTINGS OF
THREE PETROLEUM REFINING INDUSTRY WASTES
This report presents a cost impact analysis of the definition of solid waste headworks
exemption for the proposed listing of three petroleum refining residuals (clarified slurry oil
(CSO) sludge, hydrotreating catalyst, and hydrorefining catalyst) as hazardous wastes. These
residuals will be subject to RCRA Subtitle C regulation.
ISSUES
Under the proposed listing, a headworks exemption was provided for CSO sludge under the
definition of solid waste for wastewaters discharged to an oil-recovery system before primary
oil/water/solids separation in the wastewater treatment system. In contrast, a headwaters
exemption was not provided for hydrotreating and hydrorefining catalysts under the definition
of solid waste for wastewaters discharged to the wastewater treatment system. This analysis
evaluates two separate issues:
1.) If CSO sludge wastewaters are not granted a headwaters exemption under the
definition of solid wastes, what will be the cost impacts to the petroleum
refining industry?
2.) If hydrotreating or hydrorefining catalyst wastewaters are not granted a
headwaters exemption under the definition of solid waste, what will be the cost
impacts to the petroleum refining industry?
PUBLIC COMMENTS
EPA has received public comment on the proposed Petroleum Refining Waste Listings (60
FR 57747, November 20, 1995) regarding the need to exempt from RCRA regulation the
disposal of wastewater from hydrotreating and hydrorefining catalyst reactor removal
practices. The industry commenters suggested that the exemption should be similar to the
"headworks exemption" proposed for wastewater generated from CSO sludge tank removal
practices. For catalysts, this reactor cleanout activity is referred to as "wet dumping." The
headwaters exemption is a regulatory option because the wash waters associated with the
removal of these catalysts will be managed in existing wastewater treatment units subject to
regulation under the Clean Water Act and some existing treatment impoundments subject to
RCRA Minimum Technology and Land Disposal Restriction regulation.
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CSO Sludge Headworks Exemption Comments
John H. Medley, Mobil Corporation's Environmental Health and Safety Issues Coordinator.
provided information on the volume of water typically routed to the wastewater treatment
system during water washing/hydroblasting activities when CSO tanks are cleaned to recover
useful hydrocarbon and sediment and prepared for taak inspection. Two Mobil Oil
Corporation refineries had data on CSO tank cleanout wastewater volumes. At one refinery.
approximately 3,000 barrels of water were used to water wash/hydroblast the tank in
preparation for inspection. This water wash is conducted after the tank has been first cleaned
using a diesel or kerosene wash: thus, the wastewater should contain small quantities of
sediment. The other refinery estimated a volume range of 2.000 to 5.000 barrels of water.
The wash water is typically pumped via a temporary pump and flexible connector to the
nearest sewer grate, where it can flow to the primary oil/water separation at the front of the
wastewater treatment plant.'
John H. Medley also contacted Conoco and provided volume data from their experiences.
Conoco estimates it generates approximately 1,000 barrels per year for its four refineries.
These numbers have been annualized, whereas Mobil's numbers are episodic volume
estimates.'
Hydrotreating and Hydrorefining Catalyst Headworks Exemption Comments
Philip T. Cavanaugh, Chevron Companies, Vice President and General Manager Federal
Relations, provided comments on the impacts of Subtitle C regulation of wash water from
hydrotreating and hydrorefming catalyst reactor cleanout activities. He believes that this wash
water should be granted the same exemption from the definition of solid waste as CSO
sludge. As the proposed regulation now stands, catalyst wash waters are hazardous because
of the derived-from listed hazardous waste rule.3
Chevron states that it uses significant amounts of water for the safe removal of catalyst in
order to minimize its risks due to self-heating tendencies (i.e., pyrophoric material). At one
of Chevron's refineries, over 7,000 MT/yr of hydrotreating catalyst is wet dumped and sent to
metal reclamation. Wet dumping involves filling the reactor with water ("drill water") to
1 John H. Medley, Mobil Corporation, letter to Max Diaz, U.S. EPA. regarding Docket No. F-95-PRLP-
FFFFF; Clarified Slurry Oil Sediment Headworks Exemption - Supplemental. September 25. 1996.
2 John H. Medley, Mobil Corporation, facsimile to Max Diaz. U.S. EPA. regarding data on CSO headworks
exemption. September 25, 1996.
3 Philip T. Cavanaugh, Chevron Companies, Vice President and General Manager Federal Relations, letter
to EPA RCRA Docket Clerk (530SW), U.S. EPA, regarding hazardous waste management system, identification and
listing of hazardous waste, petroleum refining process wastes. Land Disposal Restrictions for newly identified wastes.
and CERCLA hazardous substance designation and reponable quantities, March 21. 1996 (Docket No. F-95-PRLP-
FFFF).
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mitigate the pyrophoric -nature of the catalyst. The slurry is drained from the reactor into a
special "spiral" classifier (manufactured by Wemco) to minimize water shipped in the storage
containers. The catalyst is then taken to a covered RCRA permitted oxidation pad and
carefully spread to allow the catalyst to continue to oxidize. Drill water continues to drain
from the catalyst on the oxidation pad and is collected and returned to the wet dump storage
tank. The catalyst is typically sent to metals reclamation. At another refinery, the catalyst is
mixed with cement and sent to disposal instead of utilizing an oxidation pad.
According to Chevron, the advantages of wet dumping catalyst is that it is rapid, the catalyst
is nonpyrophoric when wet, wet catalyst can be handled in air. and reactor cool down time is
reduced. One Chevron refinery uses 400,000 gallons (approximately 1.500 MT) of water in
its wet dumping process. The water is stored, reused, and eventually fed to the headworks of
the refinery wastewater treatment system. This volume comprises a small fraction of the
overall wastewater treatment volume.
One Chevron refinery has a two-stage reverse osmosis treatment unit installed prior to the
headworks to meet NPDES permit requirements for removing nickel. This process treats two
million gallons per year (approximately 7,600 MT/yr) which comprises less than one-tenth of
one percent of the total effluent treatment system volume of eight million gallons per day.
According to Chevron, if this wastewater is listed, the complete volume would be considered
hazardous under the mixture rule.
Chevron is concerned about the following cost issues relating to wet dumping:
Listing of these materials will increase disposal, reclamation, and transportation
costs;
The listing would result in less cost incentives to remove or reduce hazardous
characteristics prior to shipment to avoid RCRA Subtitle C regulation:
Higher incentive to shorten the downtime of the reactor (between 18 and 36 hours)
increasing production and resulting in higher concentrations of organics in the residual
(and higher hazard characteristics);
Cheaper RCRA Subtitle C disposal practices will be preferred over RCRA-exempt
(non-hazardous) reclamation practices:
Hazardous waste manifests, LDR forms, etc.;
HAZWOPER training and annual certification for all personnel involved in the wet
dump including operators, maintenance, and contractors;
Disposal of decontamination water and contaminated coveralls, cartridge respirators.
scaffolding, gaskets, etc, will require hazardous waste disposal;
Reactor internals could be considered hazardous debris upon replacement: and
Catalyst samples pulled during the run of the unit could be considered hazardous
waste.
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RCRA 3007 SURVEY .
EPA conducted an assessment of the RCRA 3007 Survey database to determine the number
of refineries that generate CSO tank sludge and hydrotreating and hydrorefining catalyst
wastes. These data are presented in Table 1.
Because of the 1992 RCRA 3007 Survey format and infrequent generation (e.g., CSO tanks are
cleaned out on average once every nine years), EPA believes that not all facilities that generate
specific waste residuals reported the activity and its associated quantities in the 1992 RCRA
3007 Survey. EPA made the following assumptions when identifying those facilities with non-
reported waste residuals (and quantities):
1. All facilities with existing clarified slurry oil storage tanks generate clarified slurry oil
tank sludges unless it has been specifically stated in a cover letter or communication that
the residual is not generated.
2. All facilities with hydrotreating or hydrorefining units generate hydrotreating catalyst
residuals or hydrorefining catalyst residuals.
The totals in Table 1 will not exactly match those in Tables 2 through 4 because of variances
in survey responses in different sections of the RCRA 3007 Survey.
Table 2 presents the reported cleanout activities for CSO tanks in the RCRA 3007 Survey.
Eighteen (18%) of the 103 facilities reporting CSO sludge generation clearly generate
wastewater during their tank cleanout activities.
Table 3 presents the reported cleanout activities for hydrotreating and hydrorefining reactors
in the RCRA 3007 Survey. Twenty-seven (20%) of the 134 facilities reporting hydrotreating
and/or hydrorefining catalyst generation clearly generate wastewater during their tank cleanout
activities.
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Table 1. Number of Facilities Generating Waste
Waste
CSO Sludge
Hydrotreating
Catalyst
Hydrorefining
Catalyst
No. of Facilities
Reporting Waste
Generation and
Waste Qaantliy
48
113
53
No. of Facilities
Reporting Waste
Generation and No
Waste Quantity
6
14
0
Estimated No. of
Facilities
Misreporting not
Generating Waste
47
3
2
Total Estimated
No. of Facilities
Generating
Waste
101
130
55
Source: U.S. EPA. Draft Final Report: Cost and Economic Impact Analysis of Listing Hazardous Wastes
from the Petroleum Refining Industry. September 21. 1995.
Table 2. Number of Facilities Conducting CSO Tank Cleanout Activities
Tank Cleanout Activity
Non- Water Generating Cleanout
Activities: Diesel/Gas
Oil/Kerosene/Solvent Wash. Installed
Mixer. Proprietary Tank Cleaning.
Centrifuge
Water Generating Cleanout
Activities: Water Wash. Steam
Stripping, Wastewater Treatment Plant
Discharge
Cleanout Activities Not Reported:
None. Invalid, Not Reported
TOTAL
No. of Facilities Reporting
Ckanout Activity
21
18
64
103
Percentage of Facilities
20
18
62
100
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Table 3. Number of-Facilities Conducting Hydrotreating and/or Hydrorefining Reactor
Cleanout Activities
Reactor Cleanout Activity
Large Volume Water Generating
Cleanout Activities: Water Wash. Wet
Dump. Water Fill, Soda Ash Wash.
Diesel Wash
Small Volume Water Generating
Cleanout Activities: Steam Stripping
Cleanout Activities that May
Generate a Small Volume of Water:
Hydrogen Sweep, Nitrogen Sweep,
Evacuation, Oxidation. Reduction.
Neutralization. Sulfiding
Cleanout Activities Not Reported:
None. Invalid. Not Reported
TOTAL
No, of Facilities Reporting
Cleanout Activity
12
15
87
20
134
Percentage of Facilities
11
9
65
15
100
SURVEY CLARIFICATION AND WASTEWATER GENERATION ESTIMATES
The RCRA 3007 Survey does not capture wash water volumes. Only one facility reported a
discharge volume to a wastewater treatment system in 1992 (i.e., 250 MT for the episodic
event or an annual rate of 100 MT/yr).
EPA contacted nine corporations which provided data on 12 petroleum refineries to clarify
their RCRA 3007 Survey responses. Refinery personnel were asked to clarify whether their
tank/reactor cleanout activities generate wastewaters. If so, they were asked to estimate the
wash water generation volume and describe how these wash waters are managed (both pre-
treatment and final management).
Initially, 22 refineries were selected for potential contact. These sites were selected to
provide a good mix of large and small refineries, represent different corporate practices (i.e.,
these 22 sites reflect 22 different corporations), and possible regional differences (i.e.,
midwest, east, south, and west).
Enough data were gathered to conduct the analysis after having attempted to contact 14 of the
22 refineries. Of the 14 refineries contacted, nine responded (i.e., provided data), three did
not return telephone calls, and two have had their telephone numbers changed since the 1992
RCRA Survey and were not tracked further. The nine responders represent nine different
-------
corporations and provided data for 12 refineries. These 12 refineries represent eight large an
four small refineries with one located in the midwest, two in the east, four in the south, and
five in the west.
Clarified Slurry Oil Sludge
EPA contacted eight corporations which generate CSO sludge to obtain wastewater data. Based
on these contacts, wastewater data were obtained for ten facilities (note that one corporation
provided data for four facilities). One facility was not able to estimate wastewater volumes.
EPA also used wastewater data provided in writing to EPA by Mobil and Conoco. Mobil
provided data for two facilities and Conoco provided average data for its four facilities.
Additional CSO tank wash water generation volume data were provided through public
comments. Data were available for two additional corporations, representing six refineries.
Two of these refineries are small and four are large. Two are located in the south, two are
located in the west, and two have unknown locations.
The CSO tank cleanout method affects the potential to generate CSO sludge wastewater. Based
on facility contacts and professional judgement, EPA assumes that the following CSO tank
cleanout methods reported in the RCRA 3007 Survey will generate CSO sludge wastewater:
water wash, discharge to WWTP, and steam stripping. EPA assumes that the following cleanout
methods will not generate CSO sludge wastewater when they are not combined with any
methods that will generate wastewater: diesel (or other similar solvent) wash, proprietary tank
cleaning, centrifuge, and mixer. EPA also assumes that facilities reporting no cleanout method
may generate CSO sludge wastewater. Based on these categories, 18 facilities will generate
wastewater, 21 facilities will not generate wastewater, and 64 facilities may generate wastewater.
EPA used reported or estimated wastewater generation volumes for the 82 of the 103 facilities
that have a potential to generate CSO sludge wastewaters. Actual reported data were available
for 14 of the 103 facilities. Four of the 14 facilities do not generate wastewater. Six unique
average wash volumes were provided by the remaining 10 facilities: 2,750; 2,800; 14,000;
16,333; 17,500; and 20,000 gallons per CSO tank cleanout. EPA was not able to assign the
actual data provided for the two Mobil facilities because the specific facilities generating these
wastewaters could not be determined. However, these two volumes were included in the
determination of the average wastewater (wash water) generation estimate of 12,230 gallons per
year per CSO tank. The average annualized wastewater generation per CSO tank estimate was
determined by averaging all non-zero annualized wastewater volumes available on a per tank
basis. This volume estimate was applied to all facilities with unknown wastewater volumes
conducting tank cleanout methods with potential to generate CSO sludge wastewaters.
To determine the total annualized CSO sludge wastewater volume for each facility that will or
may generate this wastewater, EPA applied the known or average volume estimate, as
appropriate. The average volume estimate is on an annualized per tank basis. Therefore. EPA
multiplied this average volume per tank by the number of CSO tanks at each facility. For those
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facilities not reporting the number of CSO tanks. EPA used the average of 3.8 CSO tanks per
facility. The total annualized CSO sludge wastewater volume for those facilities which provided
estimates is 190.300 gallons per year. The total annualized CSO sludge wastewater volume for
those facilities that will generate wastewater. but have the average volume estimate applied, is
330.200 gallons per year. The total annualized CSO sludge wastewater volume for those
facilities that may generate wastewater and have the average volume estimate applied is
2,878,900 gallons per year. EPA assumed an expected wastewater volume of 50 percent of this
total volume for the 64 facilities that may generate wastewater, resulting in an expected
wastewater generation volume of 1,439,500 gallons per year. The total expected CSO sludge
wastewater volume for all facilities is 1,960,000 gallons per year (190,300 + 330,200 +
1,439,500).
A range of CSO sludge wastewater volumes also was determined. The minimum annualized
total volume estimate was based on actual reported data. The minimum reported volume was
assigned to the remaining facilities that will or may generate wastewater, and includes 50 percent
of the volume of those facilities that may generate wastewater. The minimum annualized total
wastewater volume estimate for all facilities was 588,300 gallons per year. The maximum
annualized total volume estimate was based on actual reported data. The maximum reported
volume was assigned to the remaining facilities that will or may generate wastewater, and
includes 100 percent of the volume of those facilities that may generate wastewater. The
maximum annualized total wastewater volume estimate for all facilities was 5,438,300 gallons
per year. Table 4 presents a summary of the total wastewater volume estimates for CSO tank
cleanouts.
Table 4. CSO Tank Cleanout Wastewater Volumes1
Category
Facilities Reporting Wastewater
Volumes
Facilities Generating Wastewater
but Did Not Report Volumes
Facilities that May Generate
Wastewater and Did Not Report
Volumes
TOTAL
Number of Affected Facilities1
10
8
32
[32 -64]3
50
[50 - 82]
Aanualizcd Total CSO
Wastewater Volume
(gallons per year}
190,300
330,200
[74,300 - 540,000] .
1,439,500
[323,700 - 4,708,000]
1,960,000
[588.300 - 5.438.300]
1 Quantities are presented as the average followed by the range from low to high in brackets.
: Does not include facilities that do not generate wastewater.
3 Based on facility contacts, EPA assumes that a minimum of 50 percent of the facilities will be affected.
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Hydrotreating and Hydrorefining Catalysts
EPA contacted nine corporations which generate these catalysts to obtain wastewater data.
Based on these contacts, wastewater data were obtained for nine facilities (note that one
corporation provided data for four facilities). The three remaining facilities were not able to
estimate wastewater volumes.
The reactor cleanout method affects the potential to generate reactor cleanout wastewater.
Based on facility contacts and professional judgement, EPA determined that the following
reactor cleanout methods will generate a "large" amount of wastewater: water wash, wet
dump, water fill, soda ash wash, and diesel wash. EPA determined that steam stripping will
generate a "small" amount of wastewater. EPA assumed that all other reported cleanout
methods may generate a "small" amount of wastewater when they are not combined with any
methods that will generate a "large" amount of wastewater. EPA assumed that facilities
reporting no cleanout method may generate wastewater. Based on these categories, 12
facilities will generate a "large" amount of wastewater. 15 facilities will generate a "small"
amount of wastewater. and 87 facilities may generate wastewater. An additional 20 facilities
which did not report a cleanout method may generate wastewater.
Based on telephone communications and public comments, EPA used or estimated wastewater
generation volumes for 132 of the 134 facilities that have a potential to generate reactor
cleanout wastewaters (two facilities reported no wastewater generation). Actual reported data
were used for nine of the 134 facilities. Two of the nine facilities do not generate
wastewater. Six of the nine facilities generate "large" volumes of wastewater. Three unique
volume .estimates were provided by these six facilities: 53,125; 240,000; and 500,000 gallons
per year. An average annualized wastewater generation estimate per refinery of 264,400
gallons per year was determined by averaging these annualized wastewater volumes. Only
one facility with a cleanout method categorized as "small" reported a non-zero wastewater
volume. This volume was approximately 15 times smaller than the "large" volume average.
Therefore, the average "small" wastewater generation volume has been assumed to be 15
times less than the "large" volume. These volume estimates were applied, as appropriate, to
all facilities with unknown wastewater volumes with the potential to generate reactor cleanout
wastewaters.
To determine the total annualized reactor cleanout wastewater volume for each facility that
will or may generate this wastewater, EPA applied known or the average "large" or "small"
volume estimates, as appropriate. The average volume estimates are on an annualized basis
for all hydrotreating and hydrorefining reactors at the facilities. The total annualized reactor
cleanout wastewater volume for those facilities which provided estimates is 969,200 gallons
per year. The total annualized reactor cleanout wastewater volume for those facilities
generating a "large" amount of wastewater and have the average volume applied is 1,586,400
gallons per year. The total annualized reactor cleanout wastewater volume for those facilities
generating a "small" amount of wastewater and have the average volume estimate applied is
264,000 gallons per year. The total annualized reactor cleanout wastewater volume for those
-------
facilities that mav generate a "small" amount of wastewater and have the average volume
estimate appb'ed is 739,200 gallons per year, assuming an expected generation of 50 percent
of the maximum for this volume category. Based on the 113 facilities reporting reactor
cleanout methods in the RCRA 3007 Survey, 12 (11 %) will generate a "large" amount of
wastewater, 16 (14%) will generate a "small" amount of wastewater, and 84 (75%) mav
generate a "small" amount of wastewater. EPA assumes an expected volume of 50 percent of
the maximum for the "may generate a small amount" category. Applying these percentages
to the 20 facilities that mav generate wastewater results in an expected wastewater generation
volume of 762,000 gallons per year. The total expected reactor cleanout wastewater volume
for all facilities is 4,320.800 gallons per year (969,200 + 1.586,400 + 264,000 + 739,200 +
762,000).
A range of reactor cleanout wastewater volumes also was determined. The minimum
annualized total volume estimate includes actual data for those facilities providing it, applies
the minimum reported volume to the remaining facilities that will or may generate
wastewater, and includes 50 percent of the volume of those facilities that may generate
wastewater. The minimum annualized total wastewater volume estimate for all facilities is
1,639,400 gallons per year. The maximum annualized total volume estimate includes actual
data for those facilities providing it, applies the maximum reported volume to the remaining
facilities that will or may generate wastewater. and includes 100 percent of the volume of
those facilities that may generate wastewater. The maximum annualized total wastewater
volume estimate for all facilities is 7,559,300 gallons per year. Table 5 presents a summary
of the total wastewater volume estimates for reactor cleanouts.
10
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Table 5. Hydrotreating and Hydrorefining Reactor Cleanout Wastewater Volumes'
Category
Facilities Reporting Wastewater
Volumes
Facilities Generating Large
Wastewater Volumes but Did Not
Report Volumes
Facilities Generating Small
Wastewater Volumes but Did Not
Report Volumes
Facilities that May Generate Small
Wastewater Volumes and Did Not
Report Volumes
Facilities that May Generate Large
or Small Wastewater Volumes and
Did Not Report Volumes
TOTAL
Number of Affected Facilities5
73
6
15
42
[21 - 84]
12
[9 - 20]
82
[58 - 132]
AonuaJized Total Hyrfrotreatiog
and Hydrorefining Reactor
Wastewater Volume
(gallons per year)
969.200
1,586.400
[318.700 - 3.000.000]
264.000
[52.500 - 499.500]
739.200
[147.000 - 1.398.600]
762.000
[152.000- 1,692.000]
4,320.800
[1.639.400 - 7.559,300]
1 Quantities are presented as the average followed by the range from low to high in brackets.
: Does not include facilities that do not generate wastewater.
: Six facilities are "large" and one facility is "small.".
11
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COST IMPACT ANALYSIS
Two risk reduction alternatives are evaluated for use in EPA cost-benefit and cost-risk
reduction decision analyses. These risk reduction alternatives relate to the management of
wash waters from clarified slurry oil (CSO) tank and hydrotreating and hydrorefining reactor
cleanout activities at petroleum refineries.
The first risk reduction alternative is the granting of a headworks exemption (Risk Reduction
Alternative 1). Under this alternative, wastewaters generated from CSO tank and catalyst
reactor cleanouts will be granted an exclusion from RCRA under the definition of a hazardous
waste (40 CFR 261.3(a)(2)(iv)) by not being defined as a hazardous waste.
The second risk reduction alternative is that no headworks exemption is granted for either
CSO sludge or catalyst wastewaters (Risk Reduction Alternative 2). Under this alternative
four cost options- are evaluated.
Risk Reduction Alternative 1: Headwaters Exemption Granted for CSO Tank
and Hydrotreating and Hydrorefining Catalyst Reactor Wash Waters
Under the definition of hazardous waste, EPA has proposed to exempt CSO tank wash waters
and is considering a proposal to exempt hydrotreating and hydrorefining catalyst reactor wash
waters only if refineries dispose the wash waters at the front of the headworks. By granting
this exemption, the residuals will not be listed as hazardous wastes and downstream
wastewaters and sludges (i.e., biological treatment wastewater and sludges) to be derived from
or mixed with these wastes will not become listed hazardous wastes under CFR
261.3(a)(2)(iv).
If this risk alternative is selected by EPA, zero incremental compliance costs will be incurred.
However, for analytical/decision purposes, by granting this exemption EPA has reduced the
RCRA compliance costs and regulatory burden for petroleum refineries. The "avoided"
compliance costs are quantified under Alternative 2.
Risk Reduction Alternative 2: No Headwaters Exemption Granted:
Wastewater Treatment Tank Exemption Applies; and
Land Disposal Restrictions Apply to Wastewater Treatment Impoundments
This risk reduction alternative reflects the potential cost of CSO tank and hydrotreating and
hydrorefining reactor wash water management if a headwaters exemption is not granted. The
potential risk is from wash water sediments and wastewaters reaching downstream biological
treatment surface impoundments (i.e., non-RCRA regulated") and tanks in the refinery's on-site
wastewater treatment system or a commercial TSD's off-site wastewater treatment system.
The following four cost options are evaluated.
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The first two cost options assess the incremental compliance costs if a "conditional
exemption" was granted by EPA instead of a "headworks exemption." Costs associated with
a conditional exemption (details are provided below) are evaluated because this would have
been EPA's second regulatory relief option (after a headworks exemption) to avoid expensive
impoundment redesign and sludge management costs. The conditional exemption options
provide equivalent risk reduction to RCRA Subtitle C impoundment redesign and sludge
management, but, at lower cost if additional risk management is deemed necessary by EPA.
A conditional exemption will exempt downstream biological treatment impoundments and
tanks from RCRA design, operation, and permitting requirements (i.e.. Minimum Technology
Requirements, 40 CFR 264, and Land Disposal Restrictions, 40 CFR 268) and exempt their
derived biological treatment sludges, which will become hazardous under the mixture rule,
from RCRA management requirements. If the headworks exemption or conditional exemption
are not granted, biological treatment impoundments and tanks may be managing sludges that
are being mixed with hazardous waste sediments, in addition to wastewaters. from the CSO
tank and catalyst reactor wash waters. The mixture may be considered a listed hazardous
waste under the mixture rule.
A conditional exemption, as well as a headworks exemption, allows refineries to avoid the full
RCRA Subtitle C compliance cost for those owners who choose to manage wash waters on site.
These costs will be significantly higher than any of the cost options evaluated in this analysis.
Biological treatment surface impoundments, under Land Disposal Restrictions 40 CFR 268.4,
must meet RCRA sampling, dredging, sludge management, design, and monitoring,
requirements. Under Minimum Technology Requirements, 40 CFR 264, impoundments must
meet RCRA design and operation requirements. In addition. RCRA permits will be required for
impoundments under 40 CFR 270. Biological treatment tanks will remain exempt from RCRA
design and operation requirements under the wastewater treatment tank exemption. The
biological treatment sludges from these units will become hazardous under the mixture rule and
subject to RCRA Subtitle C regulation. Significant incremental compliance costs will be
avoided if a conditional exemption (or headworks exemption) is granted.
Under the conditional exemption (Cost Options 1 and 2), incremental compliance costs depend
on the sediment characteristics of the wash water. Dissolved air flotation (DAF) and API oil-
water separators exist at the front end of all existing wastewater treatment plants in the
petroleum refining industry. These wastewater treatment tank units should adequately separate
out the oils of these wash waters since these separation methods have been approved for
previous petroleum refining listings. The dissolved organic constituents that remain will be
treated in subsequent biological treatment units, which could be surface impoundment units.
Once again, given their common acceptance and use, EPA believes that biological treatment
methods will adequately treat refinery watewaters with dilute organic constituent concentrations,
unless data can be provided otherwise. Based on telephone communications with the petroleum
refining industry, EPA believes that dissolved metal constituents are not an issue with these
wash waters, but, suspended metals are. The concern is whether the DAF/API separators will
adequately remove suspended sediments (e.g., catalyst fines -- low-density metal particles) in the
wash waters. If suspended sediments are adequately removed by DAF/API separators, no
13
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incremental compliance costs will be incurred by the petroleum refineries if a conditional
exemption is granted. However. EPA has doubt (but no data) that the existing DAF/API
separators (i.e.. wastewater treatment tanks) will adequately remove these sediments, since it is
unlikely that these separators operate at 100 percent efficiency. As a result, hazardous ("listed")
sediments will become mixed with the biological treatment sludges generated by the downstream
biological treatment tanks and surface impoundments, causing these sludges to become
hazardous under the mixture rule and require management under RCRA Subtitle C regulations.
As a result, a filtration system is proposed for Cost Options 1 and 2 to remove these hazardous
sediments prior to their introduction to downstream treatment units.
Over half (38 out of 72 respondents from API's survey entitled "Management of Residual
Materials: 1994 - Petroleum Refining Performance," from September 1996) of the petroleum
refineries likely operate surface impoundments downstream of their'oil-water separation units.
Approximately 40 percent (16 out of the 38 respondents) of those refineries with surface
impoundments have obtained RCRA permits for them. Therefore, approximately 30 percent (22
out of 72 respondents) operate wastewater treatment systems containing surface impoundments
which will incur large compliance costs if the headworks exemption or conditional exemption is
not granted. To avoid these compliance costs, a conditional exemption may be granted if the
wastewaters are adequately treated prior to reaching the downstream biological treatment units.
The incremental compliance costs associated with the conditional exemption are discussed
below.
Cost Option 1 - Conditional Exemption. In-line Filtration System
Install a filtration system (e.g., sand filtec) within the existing wastewater treatment
system to collect sediments prior to discharge to a biological treatment impoundment or
treatment tank. All plant wastewaters would be filtered.
Cost Option 2 - Conditional Exemption. Redundant API Separator/DAF/Filtration
System
Install a small-scale, batch-operated, redundant DAF/API separator system adjacent to
. the existing wastewater treatment units with a small-scale filtration system for dedicated
treatment of wash waters only. Discharge treated wash water into the headworks of the
existing wastewater treatment system.
The third cost option under Risk Reduction Alternative 2 is to manage the wash waters off-site at
a RCRA permitted treatment facility. If both exemptions are granted, this cost option may be the
most cost effective for some refineries. However, if neither exemption is granted, this cost
option is the most cost effective, given the intermittent nature of when these cleanout activities
are conducted, compared to the costs for retrofitting downstream impoundments and managing
biological treatment sludges under RCRA Subtitle C.
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Cost Option 3 -"Off-site RCRA Subtitle C Treatment
Transport wash waters to a commercial, off-site RCRA permitted treatment facility. EPA
assumed the off-site RCRA treatment facilities will typically be composed of all tank
systems.
The fourth cost option reflects the most cost effective cost option for refinery operators of the
above three options if the conditional exemption is granted.
Cost Option 4 - Conditional Exemption. Cost Effective Treatment Option
Under Cost Option 4. EPA assigned the minimum cost from the previous three cost
options for each refinery to reflect the most cost effective solution if a conditional
exemption is granted.
Cost Analysis
Based on the RCRA 3007 Survey, EPA determined that 103 facilities own CSO tanks which
have the potential to generate CSO sludge wastewaters (i.e., wash waters) if the refinery used a
water-generating cleanout method. Note that only 101 of the 103 facilities would be affected by
a CSO sludge listing for non-wastewater. The additional two facilities have CSO tanks, but
management of the CSO sludge itself would be exempt under a recycling exemption. Yet, these
facilities may generate wash waters from their tank cleanout activities.
CSO tank wash water volumes were not reported in the RCRA 3007 Survey. Based on data
obtained from public comments to the proposed listing and follow-up survey clarification
telephone ommunication, approximately 2,750 to 20,000 gallons of wash water are generated
per tank per year. An average value is 12,230 gallons per tank per year. Given that
approximately 50 percent of the CSO tank cleanouts generate a wastewater. the petroleum
refining industry generates between 588,300 and 5,438.300 gallons of wastewater per year.
with an average total volume of 1,439,500 gallons per year.
Based on the RCRA 3007 Survey, EPA determined that 134 facilities have the potential to
generate hydrotreating and/or hydrorefining reactor wastewaters.
Catalyst reactor wash water volumes were not reported in the RCRA 3007 Survey. Based on
data obtained from public comments to the proposed listing and follow-up survey clarification
telephone communication, approximately 3,500 to 500,000 gallons of wash water are
generated per facility per year. The average values are 17,600 gallons per facility per year
for management methods generating a "small" amount of wastewater and 264,400 gallons per
facility per year for management methods generating a "large" amount of wastewater. Given
that 43 to 99 percent of the 134 facilities with hydrotreating and hydrorefining reactors
generate wastewater, the petroleum refining industry generates between 1,639,400 and
15
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7.559.300 gallons of .wastewater per year, with a typical total volume of 4.320.800 gallons per
year.
Risk Reduction Alternative 1: Headwaters Exemption
CSO tank and catalyst reactor wash waters are exempted under the definition of solid waste if
these wash waters are treated in an oil-recovery system prior to discharge to the wastewater
treatment system. All refineries have API separator/DAF units readily available on site at the
front end of their wastewater treatment system. Therefore, there is no incremental cost of
compliance due to listing this waste if a headwaters exemption is granted under the definition
of solid waste.
Risk Reduction Alternative 2: Cost Option 1 - Conditional Exemption. In-line
Filtration System
Under Cost Option 1. CSO tank and catalyst reactor wash waters are discharged to the
existing wastewater treatment system via the existing sewer system. However, a sand filter
would be installed within the existing treatment system to collect sediments. The filtration
system is sized the manage all plant wastewaters. Capital costs for this system include
filtration beds, piping, pumps, instrumentation, foundations, treatment buildings (which also
act as secondary containment), modifications of NPDES permits, and corrosion protection.
Operation and maintenance costs include building maintenance, instrumentation maintenance,
corrosion protection, pump replacement, electricity, and labor. Filtration system costs were
developed for 11 different flowrates within the range of flowrates considered in this analysis.
Costs were annualized on a before-tax basis assuming a 20-year borrowing period and a 7
percent real rate of return. Curve-fit equations, based on total wastewater treatment system
flowrates, were developed from these 11 system costs.
Incremental compliance costs for Cost Option 1 are based on the estimated total wastewater
treatment system flowrate for each facility. Total plant wastewater treatment system flowrates
were estimated based on API's survey entitled "Management of Residual Materials: 1994 -
Petroleum Refining Performance," from September 1996 which states that the quantity of
water discharged daily from 72 refineries surveyed in 1994 ranged from 0 to 34 million
gallons per day with a median value of 1.73 million gallons per day. EPA assumed that the
minimum flowrate would be 50,000 gallons per day rather than no discharge for a
conservative estimate. For the facilities potentially affected by listing of CSO tank and
hydrotreating and hydrorefining reactor wash water, EPA applied the minimum, median, and
maximum discharge flowrates to the minimum, median, and maximum crude daily rates,
respectively, as reported by the facilities in the RCRA 3007 Survey. A curve-fit equation for
total facility wastewater flowrate was developed as a function of facility crude daily rate.
Costs for the filtration systems are based on the estimated total facility wastewater flowrates.
Zero incremental costs were assumed for facilities generating no CSO tank, hydrotreating, or
hydrorefining wash water.
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Risk Reduction-Alternative 2: Cost Option 2 - Conditional Exemption. Redundant Ar
Separator/DAF/Filtration Svstem
L'nder Cost Option 2, CSO tank and catalyst reactor wash waters are treated on site in a
permitted RCRA Subtitle C wastewater treatment tank system prior to discharge to the
existing wastewater treatment system. First, EPA assumes that the wastewater will need to be
pumped into a tanker truck rather than to the sewer lines for the facility's wastewater
treatment plant. A hazardous waste tanker truck service will need to be contracted when a
tank cleanout is conducted. The truck will haul the wash waters from the tank to the a small-
scale, batch-operated API separator unit. EPA assumes that an API separator/DAF units will
be necessary to remove any separable oil layer. The recovered oil is assumed to be recycled
back into a process unit. The oil handling cost and value received from the recovered oil
likely cancel each other out. The remaining wastewaters are assumed to contain low
concentrations of organics and are transferred to a.DAF for further oil and volatile organic
constituent stripping. Therefore, zero incremental compliance costs are assumed for sludge
management. Finally, to satisfy the conditional exemption, the remaining wastewaters are
filtered prior to discharge to the main wastewater treatment plant. The filtered sediments are
hazardous due to the listing and are assumed to be managed with the listed wastewater
treatment sludges from the main wastewater treatment plant. These sludges have traditionally
been generated and managed within the context of the main wastewater treatment plant.
Capital costs for Cost Option 2 include a holding/equalization tank, an oil/water separator, a
DAF with a compressor, a pressure sand filtration unit, transfer pumps, piping, instrumentation,
foundation, corrosion protection, permitting, secondary containment, and start-up. Operation
and maintenance costs include compressor maintenance, pressure sand filtration unit
replacement, pump replacement, treatment chemicals, annual inspection and reporting, labor,
electricity, and transportation of wash water to the system. Closure costs include
decontamination, testing for success of pad and tank decontamination, and residual transport and
disposal. Treatment system costs were developed for five different flowrates within the range of
flowrates considered in this analysis. Costs were annualized on a before-tax basis assuming a
20-year borrowing period and a 7 percent real rate of return. Curve-fit equations, based on the
maximum amount of wash water generated during a given CSO tank or reactor cleanout, were
developed from these five system costs.
Incremental compliance costs for the management of CSO tank wash waters and hydrotreating
and hydrorefining reactor wash waters were developed assuming that wash waters from all three
sources would be managed in the same treatment system. Treatment system costs for each
facility for Option 2 are based on the maximum amount of wash water generated during a given
CSO tank or hydrotreating or hydrorefining reactor cleanout.
Risk Reduction Alternative 2: Cost Option 3 - Off-site RCRA Subtitle C Treatment
Under Cost Option 3, CSO sludge and catalyst reactor cleanout wastewaters are treated off
site in a commercial RCRA Subtitle C wastewater treatment tank system. First, EPA assumes
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that the wastewater will need to be pumped into a tanker truck rather than to the sewer lines
for the facility's wastewater treatment plant. A hazardous waste tanker truck service will
need to be contracted when a tank cleanout is conducted. The truck will haul the wash
waters off site to a commercial hazardous wastewater treatment facility.
Cost Option 3 includes transportation and treatment of hazardous wash water at an off-site
hazardous wastewater treatment facility located within 200 miles of each refinery. Treatment
costs for Cost Option 3 are based on the annual generation of wash waters from CSO tank and
reactor cleanouts for each facility.
Risk Reduction Alternative 2: Cost Option 4 - Conditional Exemption. Cost Effective
Treatment Option
The Least Cost Option includes the least expensive of the other three Alternative 2 options for
each facility. Table 6 presents the incremental costs for the four options.
Cost Impacts
Incremental costs for the three options under Risk Reduction Alternative 2 above were
calculated for each facility. For those facilities which may generate wastewater, a range of
incremental costs was developed. For the expected incremental cost, the expected wash water
volumes were assumed. This expected cost includes 100 percent of the incremental costs for
facilities expected to generate wash water and 50 percent of the incremental costs for facilities
which may generate wash water. For the minimum incremental cost, the minimum wash water
volumes were assumed. This minimum cost includes 100 percent of the incremental costs for
facilities expected to generate wash water and 25 percent of the incremental costs for facilities
which may generate wash water. For the maximum incremental cost, the maximum wash water
volumes were assumed. This maximum cost includes 100 percent of the incremental costs for
facilities expected to generate wash water and 100 percent of the incremental costs for facilities
which may generate wash water.
Incremental compliance cost estimates for the listing of CSO sludge, hydrotreating catalyst,
and hydrorefining catalyst wastes that are non-wash waters are presented in Table 7. Annual
incremental costs for wash water treatment in Table 6 can be added to costs in Table 7 to
determine the total cost of compliance for a given option.
In summary, if no headworks exemption is granted, between $3.8 and $26.9 million (expected
value of $11.4 million) in incremental compliance costs are incurred by the petroleum
refining industry for off-site management of CSO tank and hydrotreating and hydrorefining
wash waters. On-site management RCRA compliance costs relating to treatment
impoundment closure, or impoundment permitting and redesign, in conjunction with
biological treatment sludge management, will be substantially higher than off-site
management of wash waters and were not estimated. Once again, if no headworks exemption
is granted, but, EPA grants a conditional exemption, between $1 and $3.7 million (expected
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DOCUMENT 4
COST IMPACT ANALYSIS OF THE DEFINITION OF SOLID WASTE
HEADWORKS EXEMPTION
FOR THE PROPOSED LISTINGS OF THREE
PETROLEUM REFINING INDUSTRY WASTES
April 9, 1997
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MEMORANDUM
TO: Andy Wittner. EPA/OSW/EMRAD
FROM: Chris Lough, DPRA Incorporated
DATE: March 31, 1997
SUBJ: Impacts of SBREFA and Unfunded Mandates on the Proposed Petroleum
Refining Hazardous Waste Listing
This memorandum updates the Regulatory Flexibility Analysis included in the Addendum to
the Draft Final Report, Cost and Economic Impact Analysis of Listing Hazardous Wastes
from the Petroleum Industry (October 30, 1995), to reflect the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). It also presents an assessment of the potential
for unfunded mandates resulting from this proposed rulemaking.
Background of SBREFA
Since its passage in 1980, the Regulatory Flexibility Act (RFA) has generally required every
federal agency to prepare regulatory flexibility analyses for any notice-and-comment rule it
issues, unless the agency certifies that the rule "will not, if promulgated, have a significant
economic impact on a substantial number of small entities," which include small businesses,
small governments, and small nonprofit organizations. The RFA was amended on March 29,
1996 by SBREFA in ways that strengthened the RFA's analytical and procedural
requirements.
Prior to SBREFA's enactment, the Agency issued guidance regarding implementation of the
RFA. The most recent guidance (dated April 1992) advised EPA program offices to prepare
regulatory flexibility analyses for any rule that would have "any impact" on "any number" of
small entities, which is more than the RFA requires. It still remains the Agency's policy that
program offices should assess the impact of every rule on small entities and minimize any
impact to the extent feasible, regardless of the size of the impact or number of small entities
affected. Further, the outcome of that assessment and the steps taken to minimize any impact
should be discussed or summarized in the preamble to the rule. In view of the changes made
by SBREFA, however, the Agency has decided to implement the RFA as written; that is,
regulatory flexibility analyses as specified by the RFA will not be required if the Agency
certifies that the rule will not have a significant economic impact on a substantial number of
small entities.
Where the Agency does not certify that a rule will have no significant economic impact on a
substantial number of small entities, regulatory flexibility analyses meeting the applicable
statutory requirements must generally be prepared for the rule. Even where the Agency
certifies that a rule will not have significant economic impact on a substantial number of
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small entities, the Agency's policy is that an assessment of the rule's impact on any small
entities must still be made and efforts to minimize that impact undertaken. EPA has prepared
guidance1 regarding Criteria and thresholds for determining whether a particular rule will not
have a significant impact on a substantial number of small entities, as well as direction on
how to prepare regulatory flexibility analyses, if required.
Existing Regulatory Flexibility Analysis
The regulatory flexibility analysis conducted for the Addendum examined whether the
proposed petroleum waste listing will affect small entities. By way of background, EPA set
forth guidance and criteria for identifying and evaluating whether a regulation will have an
economic impact on small entities.2 The guidelines address the following procedures:
Identify the small entities affected by the rule;
Determine if small entities are affected by the rule; and
Determine whether the operating statute allows the Agency to consider
regulatory alternatives to minimize the rule's impacts on small entities.
The RFA specifies that the term "small entity" shall be defined as including small businesses, ,
small organizations, and small government jurisdictions. The Act defines small businesses as
those firms that satisfy the criteria established under Section 3 of the Small Business Act.
The Agency may use an alternative definition of "small business" after consultation with the
Small Business Administration (SBA) and public comment. The SBA criteria apply to firm
size, whereas the economic impact analysis for the proposed rule was conducted at the facility
level (i.e., refinery level). For single-plant firms, the SBA criteria was applied directly. For
firms (i.e., companies) owning more than one refinery, crude capacity was aggregated for all
plants (i.e., refineries) to determine the overall size of the company.
Section 603 of the RFA requires a screening analysis be performed to determine whether
"small business, organizations and governmental jurisdictions" will be affected by the
regulation. If the regulation will have a "significant economic impact" on a "substantial
number" of small entities, EPA is required to perform an Initial Regulatory Flexibility
Analysis which evaluates the opportunities for and outcomes of introducing alternative
regulatory options that minimize a rule's impact on small entities.
For SIC 2911, Petroleum Refining, the Small Business Administration defines small entities
as those companies with refinery capacity less than or equal to 75,000 barrels of crude per
calendar day. Based on this criterion, 32 of the 66 companies (48%), affected by the listing
1 EPA Interim Guidance for Implementing the Small Business Regulatory Fairness Act and Related Provisions
of the Regulatory Flexibility Act, prepared by EPA SBREFA Task Force, February 5, 1997.
2 "EPA Guidelines for Implementing the Regulatory Flexibility Act," Office of Regulatory Management and
Evaluation, Office of Policy, Planning and Evaluation. Revised April 1992.
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determination are considered to be small entities. Because a sizable percentage of small
entities were affected, the Agency conducted an industry impact analysis to determine the
impact on small entities. EPA determined, however, that even under the highest cost scenario
(i.e.. LDR upper bound), the estimated impacts of the listing determination were minimal,
with almost no measurable impact on plant operations. Predicted price increases and
reductions in domestic output were less than 1 percent for the ten petroleum products
evaluated. For the lower bound and midpoint scenarios, impacts on the major variables of
average price increase, annual production decrease, and job loss were all less than one-tenth
of one percent.
Despite the high percentage of small entities in the population of refinery companies affected
by the listing determination, anticipated impacts as a result of implementation of the listings
were insignificant, with only up to two plant closures predicted under each of the scenarios
evaluated. Because economic impacts were estimated to be minimal, no small entity
exemptions or options were judged to be necessary in an effort to reduce economic impacts
on small entities. Hence, EPA published in the preamble to the November 20, 1995 proposed
rule, pursuant to Section 605(b) of the Regulatory Flexibility Act, "the Administrator certifies
that this rule will not have a significant economic impact on a substantial number of small
entities."
Impacts of SBREFA
The purpose of the Regulatory Flexibility Act (RFA), which remains the same under the
SBREFA amendments, is to ensure that in developing rules, agencies identify and consider
ways of tailoring regulations to the size of the regulated entities to minimize any significant
economic impact a rule may impose on a substantial number of small entities. The RFA does
not require that an agency necessarily minimize a rule's impact on small entities if there are
legal, policy, factual or other reasons for not doing so. The RFA requires only that agencies
determine, to the extent feasible, the rule's economic impact on a substantial number of such
entities, and explain its ultimate choice of regulatory approach. The intent of SBREFA is to
strengthen the RFA's analytical and procedural requirements.
The RFA references the definition of "small business" found in the Small Business Act,
which itself authorizes the Small Business Administration (SBA) to further define "small
business" by regulation. The SBA's small business definitions are codified at 13 CFR
121.201, and the SBA reviews and reissues those definitions every year. SBA's most recent
revisions to its "size standards" can be found in the January 31, 1996 Federal Register (61 FR
3280). For SIC 2911, Petroleum Refining, the SBA defines a small business as a firm with
no more than 1,500 employees nor more than 75,000 barrels per day capacity of petroleum-
based inputs, including crude oil or bona fide feedstocks. These two criteria (i.e.,
employment and capacity) remain unchanged from the previous regulatory flexibility
screening analysis conducted for the proposed listing. In that analysis, the Agency chose not
to use SBA's criterion of company-level employment because few companies employ more
than 1,500 employees, and data on the number, of employees at the company level were much
less readily available than were capacity data.
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As stated previously r the RFA requires that an agency prepare an Initial Regulatory Flexibilr
Analysis for proposed and final rules, unless the head of the agency certifies that the rule(s)
will not have a significant impact on a substantial number of small entities. The RFA does
not define "significant economic impact on a substantial number" of small entities. Agencies
therefore have substantial discretion in determining what is not a significant economic impact
on, and a substantial number of, small entities. EPA's interim guidance suggests analytical
methods, criteria and thresholds for making that determination. As noted above, if an agency
certifies that a rule will not have a significant economic impact on a substantial number of
small entities, it must support that certification with a factual explanation. Implementation of
the SBRJEFA/RFA guidance will provide the factual predicate for certifying a rule. The RFA
authorizes the head of an agency to certify a rule. EPA's Administrator has delegated that
authority to the Agency official who has the authority to sign the rule for which a
certification has been prepared, except that the authority to certify under the RFA cannot be
redelegated below the Office Director level. Further, when an agency certifies a rule, it must
publish that certification in the Federal Register at the same time it publishes the proposed or
final rule to which the certification applies. The provisions of certification and publishing the
certification in the Federal Register remain the same under SBREFA.
Under the RFA, as amended by SBREFA, if the rule will not have any adverse effect on any
small entity subject to the rule's requirements, the program office may certify that the
proposed and final rules will not have a significant economic impact on a substantial number
of small entities on that basis. For a proposed or final rule that will have an adverse effect
on one or more small entities, however, the program office must determine the extent of the
impact and the number of small entities affected.
SBREFA's Economic Criteria
EPA's Interim Guidance provides suggested economic criteria for assessing the impact of a
rule on small entities. These criteria are drawn from standard economic analyses and vary by
type of small entity in view of the different economic characteristics of small businesses,
governments, and nonprofit organizations. Further, for each type of small entity, several
different criteria are listed. The criteria vary in terms of the type of data involved, and thus a
program office may choose to apply one criterion over the others based on the type of
information available. The guidance document nevertheless indicates a preferred criterion for
each type of small entity. Where the program office has the necessary information, it should
generally use the preferred criterion. The program office may nonetheless use one of the
other criteria, or even a criterion not included in the guidance, where it has sound reasons for
doing so and it explains those reasons in the rulemaking record. For small businesses, the
preferred criterion is the annualized compliance costs as a percentage of sales (i.e., the sales
test). The other quantitative criteria for evaluating the economic impact of a rule on small
businesses are: debt-financed capital compliance costs relative to current cash flow ("cash
flow test") and annualized compliance costs as a percentage of before-tax profits ("profit
test").
The application of the preferred criterion, the "sales test," on the proposed petroleum waste
listing, yields a quantitative estimate of the rule's impact on small entities. The Interim
Guidance presents a matrix that categorize the rule based on the magnitude of its impact (as
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measured using the preferred criteria) and the number of endues expected to experience an
impact of a particular magnitude.3 Each category establishes either a process for
determining, or a presumption regarding, whether the rule can be certified as having no
significant impact on a substantial number of small entities.
The scope of each category is defined by various thresholds for three variables: the
magnitude of the impact the absolute number of small entities that will experience that
impact, and the percentage of all the small entities subject to the rule that will experience that
impact. It is important to keep in mind, however, that the thresholds are only guidelines for
determining whether a rule will not have a significant impact on a substantial number of
small entities. The RFA itself does not establish a formula for making this determination, and
indeed, it would be impossible to develop a formula that would yield an appropriate answer in
the context of every rule. For that reason, the thresholds are used to define categories that
establish no more than a presumption; program offices and the Agency as a whole will have
to exercise judgment in deciding whether to prepare a regulatory flexibility analysis for, or
certify, a given rule.
EPA performed a screening analysis to evaluate the economic impact of the proposed waste
listing on small entities using the preferred criterion (i.e., the sales test) whereby annualized
compliance costs as a percentage of sales (i.e., revenues) for the ten petroleum products
previously evaluated were calculated. For each waste stream (i.e., clarified slurry oil sludge, '
hydrotreating catalyst, and hydrorefining catalyst) and compliance option (i.e., listing scenario,
LDR scenarios, and contingent management scenario) described in the Addendum, EPA
determined the costs as a percentage of sales for each small entity at the close of 1992 (i.e..
32 companies operating 36 refineries). The following summarized results are reported:
Summary of Economic Impacts of Small Entities
Range of Annualized Compliance Costs
Range of Annual Company Refinery Sales
Range of Annualized Compliance Costs as
a Percentage of Company Refinery Sales
Listing
Scenarios
$4,566 -
$305.379
LOR Scenario
Lower Bound
$4,556 -
$7.561,781
LDR Scenario
Upper Bound
$4,556 -
$11,765.904
Contingent
Management
Scenario
$4,556 -
$2.321.305
519,377.340 - $1.218,936.710
0.001% -
0.236%
0.001% -
0.620%
0.001% -
0.965%
0.001% -
0.236%
As stated previously, the legal test for certifying a rule is whether the rule "will not. if promulgated, have a
significant economic impact on a substantial number of small entities." The test thus has two stepsfirst, will the
impact on any small entities subject to the rule be significant, and second, will the number of small entities
significantly impacted be substantial? The Agency may certify a rule if its impact is significant but only with respect
to a small number or percentage (i.e., not a "substantial number") of the small entities subject to the rule's
requirements. The Agency may also certify a rule if its impact falls on a substantial number of small entities, but its
impact is not significant. The Agency may not certify a rule if a substantial number of the small entities subject to
the rule's requirements will be significantly impacted by the rule.
-------
The above results represent a worst-case economic impact on small entities resulting from the
listing of CSO tank sludge, hydrotreating catalyst, and hydrorefining catalyst. The range of
annualized compliance costs for each regulatory option reported above is based on the highest
possible cost estimated for each facility (i.e., cost estimates incorporating the greatest amount
of uncertainty), rather than the expected compliance cost outcome. As is evident from the
table, all small entities affected by the proposed listing have compliance costs as a percentage
of sales of less than one percent, the threshold to determine potential economic impact. As a
result, the proposed rule received a Category 1 ranking and the rule is presumed not to have
a significant economic impact on a substantial number of small entities.4 Therefore, the
Agency would support a certification that the rule will not have a significant economic impact
on a substantial number of small entities.5
Unfunded Federal Mandates
In this section, EPA evaluates the potential implications of the Unfunded Mandates Reform
Act of 1995 (UMRA) for the proposed petroleum listing determination. UMRA (P.L.I04-4),
which was signed into law on March 22, 1995, defines two categories of unfunded federal
mandates, intergovernmental and private sector mandates, which must be considered.
Unfunded federal mandates are defined as the following:
Any provision in legislation, statute, or regulation that would impose an
enforceable duty on state, local or tribal governments or the private sector,
except as a condition of federal assistance or a duty arising from participation
in a voluntary federal program; or
Any provision that would reduce or eliminate federal financial assistance to
state, local, or tribal governments for compliance with pre-existing regulations.
In addition to the criteria listed above, unfunded intergovernmental mandates are defined as
any provision that relates to a pre-existing federal program under which $500 million or more
is provided annually to state, local, and tribal governments under entitlement authority.
Tide II (Section 202) of UMRA requires that a federal agency prepare a written statement for
any proposal that is likely to result in a rule that includes an unfunded federal mandate
resulting in expenditures of $100 million or more in any one year by smaller government
bodies (i.e., state, local, and tribal governments) in the aggregate or by the private sector.
This written statement can be prepared as part of any other analysis prepared by EPA for
rulemakings and must include the following:
4 Although not required, the Assistant Administrator of the program office developing the rule may, at his or
her discretion, decide to prepare a regulatory flexibility analysis for the rule.
5 The certification statement must be included in the Regulatory Flexibility section of the rule's preamble and
by at least a summary of the factual basis for the certification. If only a summary is provided, a full explanation must
be provided elsewhere in the rulemaking record and the summary should reference that explanation.
6
-------
Identification of the provision of federal law under which the rule is
promulgated;
An assessment of the costs and benefits of the mandate, including the extent to
which federal resources (e.g., financial assistance) will be available to carry out
the mandate;
An estimate of the future compliance costs;
An estimate of the effect on the national economy (if feasible, relevant, and
material); and
A description of the Agency's prior consultation with affected governments,
including summaries of the comments and concerns raised and the Agency's
evaluation of those comments.
Under Section 205, agencies must also develop a process to permit elected state, local, and
tribal government officials to provide "meaningful and timely input" into the development of
regulatory proposals "containing significant intergovernmental mandates." In addition,
agencies must consider a "reasonable number of regulatory alternatives" and select the least
costly, most cost-effective, or least burdensome alternative that achieves the objectives of the
rule, unless the provisions of the alternative are inconsistent with the law or an explanation is
provided by the head of the affected agency.
EPA has determined that the proposed listing does not contain a federal mandate that will
result in an expenditure of $100 million or more in any one year to state, local, or tribal
governments in the aggregate or the private sector. According to the Addendum, the upper
bound of the range of potential average annual costs is estimated to be $39.6 million,
considerably below the $100 million annual threshold. Therefore, the proposed rule is not
subject to the requirements of Sections 202 and 205 of the UMRA. No additional guidance,
other than what is contained in OMB's "Economic Analysis of Federal Regulations Under
Executive Order 12866" (January 11, 1996) for the analysis of unfunded federal mandates,
could be located since EPA published the proposed rule on November 20, 1995 (60 FR
57747). In that OMB document, the only reference to the assessment of potential unfunded
federal mandates was the requirement that all economic analyses of proposed regulations
should satisfy the requirements of Title II of the UMRA.
cc: Gwen De Pietro, SAIC
Dave Gustafson, DPRA
7
-------
DOCUMENT 3
IMPACTS OF SBREFA AND UNFUNDED MANDATES
ON THE PROPOSED PETROLEUM REFINING
HAZARDOUS WASTE LISTING
March 31, 1997
-------
Waste Stream
D008 D018 K052
KO^^ K050 K051 F037
K050 D007 D004 D005 D006
K050 D028
K050 D004 0005 D006 D007 0008
F037 0007 0008
0007 0008 K050
K050 0007
^DOOl 0018 F037
' F038 0001
K050 0007 0008
XD001 0003 0018 K051
K049 K050 K051
DOwd K050
0001 0018 U220 U239 F037
' F037 F038 K048 K051
0009 0018 K050
K048 K050 K051 K052
K051 F037 0008 0018
D001 0018 K052
0007 0008 F037 K050
0008 K052
K051 K052
Number of
Gens Streams
Generation
(tons)
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
6.000
5.769
3.350
3.000
2.250
2.237
2.234
2.185
1.750
1.608
1.523
,1.300
0.590
0.583
0.550
0.250
0.238
0.140
0.125
0.000
0.000
0.000
0.000
9264953.375
2,043,031 ~ 2 million tons
Did not include any waste streams that are
D004 - D011 (metals), K050 (heat exchanger
bundles), or K052 (leaded tank bottoms).
-------
Waste Stream
D \ D002 D003 D008 D018 K052 U019 U159 U220
F037 DO19 D022
D007 D018 F037
F037 K049 K051 D018
D001 K050
' F037 D018 D027
K051 K048 K049 K050 D018
K051 F037 F038 D018 D001
K050 D001 D003 D018
F037 F038 D003 D018
/D003 D018 K049
K052 D018
K050 K051 F037
Fv_; F038 K048 K049 K050 K051 K052
D018 F037 K049 K050
D001 K051
K048 K049 D001 D018
D007 D008 D018 F037 F038 K048 K049 U019 U055
U056 U220 U239
D018 K050
K050 0018
F037 K050
F037 D003 D018 D001
K051 K050 D001 D018
/K049 K051
K050 D007 D008 D009
/F D001 D018
/K049 K051 D018
K049 K051 F037
Number of Generation
Gens Streams (tons)
1
1
1
1
2
1
1
1
1
1
1
3
2
1
1
2
1
1
1
2
1
1
1
1
1
2
1
1
1
1
1
1
3
1
1
1
1
1
1
3
2
1
1
2
1
2
1
2
1
1
1
1
1
2
1
1
56.000
54.660
54. 140
47.837
45.730
40.460
37.110
35.800
35.500
33.000
28.880
24.380
23.830
->2.570
18.000
17.500
16.423
15.710
14.903
13.729
13.500
12.236
12.150
10.253
10.100
8.705
7.312
6.500
-------
Waste Stream
K 3 K050 K051 K052 D008 D018 F037 F038
K051 D018 D005
/K048 F038 D018
/ K051 K049 D018 F037
F039 K048
K051 D007 D008 D009
/ D001 D018 K048 K049
K051 K050
/D018 K048 K051
' D018 F037 K048 K051
/ D018 F037 F038 K048 K051
/ K048 K051 F037
D001 D002 D008 D009 D018 K052 U019 U055 U220
F^.7 D019 D022 D018 D001
D001 D018 K050
K049 K050
F037 D008
D007 D008 D018 F037
K051 K049 K048
D001 D002 D003 D008 D018 F005 F037 F038 K048
K049 K050 K051 K052
D001 D002 D003 D007 D008 D018 F037 F038 F039
K048 K049 K050 K051 K052
K051 K048 K050
K049 D003 D018
D001 D003 D007 F037
DOD7 D018 F037 K050
KOal K050 K049 K048
D018 F037 K048 K049 K050 K051
K050 D001 D018
Number of Generation
Gens Streams (tons)
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
1
1
1
1
1
1
1
1
1
2
1
3
1
1
1
1
1
1
2
1
1
1
1
1
1
1
2
2
1
1
1
1
1
1
1
1
2
3
1
3
205.800
179.203
178.000
159.150
148.253
148.210
146.710
145.540
141.510
140.000
133.000
126.400
122.350
112.685
97.715
91.550
91.000
90.900
88.774
88.000
86.000
78.290
74.605
68.000
63.550
63.530
57.760
56.281
-------
Waste Stream
D 1 D007 F037 F038 K048 K051
K049 K050 K051 F038
K052 D008
XK048 K051 F038
K048 K049 K050 K051 K052 F037
D001 D018 K048 K049 K050 K051 F037 F038
/ F038 K048
K049 F037 K050
/ K049 K051 F037 D018
F039 K048 K051
/ K051 F037 F038
/ D018 F037 F038 K048 K049
F037 F038 K050
7 D^ .1 D018 K049
F037 F038 K049 K050 K051
7 K051 F037
K051 K050 D001
/ F037 F038 K049
/D003 D018 K051
F037 F038 K048 K049 K050 K051
/K049 K051 D001 D018
/D003 F037 K048 K049 K051
K052
D001 D018 D008 K050 F037
K051 K050 F037
D004 D005 D006 D007 D008 D009 D010 D011 D018
F F038 K048 K049 K050 K051 K052 U019 U055
Number of Generation
Gens Streams (tons)
D007 D008 D018 F037 F038
D001 D018 K051
1
1
4
1
1
1
1
1
1
1
1
1
1
1
1
3
1
1
1
1
1
1
19
1
1
1
1
2
1
1
8
1
1
1
1
1
1
2
2
1
1
1
1
3
1
1 .
1
1
1
1
21
1
1
1
1
2
1175.260
1123.100
1052.650
984.800
923.965
850.779
818.020
702.500
672.122
662.546
654.100
640.210
571.435
564.800
559.000
509.291
475.777
457.440
448.120
372.260
360.337
306.000
297.608
288.255
274.130
273.270
232.000
219.200
-------
Waste Stream
/ Dr " F037
'' D018 F037 F038
/ K048 K049 K051 F037 F038
/D018 K048 K049
F037 K048 K049 K050 K051
/ F038
/ D001 K049 K051
K050 K051
/ K048 K051 F037 F038
K048 K051 K049 K050 F037
/ F037 F038 D018
K050
/K049 D001 D018
Dc.x D007 D008 D018 K048 K049 K050 K051 K052
D018 K048 K050 K051
/ K051 D018
/ D001 F037 F038
K051 K048 K049 K050
D018 F037 F038 K048 K049 K050 K051
' F037 F038 K048 K049 K051
K048 K049 K050 K051 F037 D018
D018 K048 K049 K050
/K049 K051 F037
D018 D001 K048 K049 K050 K051
/ D018 K051
D018 F037 F038 K048 K049 K050 K051 K052 P110
U U055 U056 U220
K048 K049 K050 K051 K052
K048 K049 K050 K051
Number of
Gens Streams
Generation
(tons)
9
2
1
2
1
11
1
5
2
1
5
72
1
1
1
8
1
1
2
2
1
1
3
1
3
1
3
3
9
4
2
2
1
13
1
5
3
1
5
76
3
4
1
11
1
3
2
2
1
1
4
1
3
1
5
5
8619.630
7620.000
6383.279
5977.100
5419.000
4271.963
4171.500
4040.890
3560.704
3270.800
2690.396
2638.367
2598.585
2450.000
2341.000
2279.364
2204.590
2089.100
1927.600
1872.040
1836.900
1808.527
1675.538
1535.552
1465.890
1320.370
1261.000
1205.343
-------
Waste streams, waste stream counts, generator counts, and generation in tons
for 1993 BRS GM forms reporting SIC 2911 and a waste code in the F037,
F <3, K048-52.
Waste Stream
D007 D008 D018 F037 F038 K048 K049 K050 K051
K052
D018 K048 K049 K050 K051
/D018 F038
yK048 D018
K048 K049 K050 K051 F037
/ K048
/ F037
/ D018 K049
/ F037 F038
K048 K052 F037
/ IT
-------
EPA Waste Code
F037/F038
K048
K049
K051
Total % Solids
Content
5
5
12
20
Total % Water
Content
82
82
40
65
Total % Oil
Content
13
13
48
15
Given the above waste stream characteristics for F037/F038, K048, K049, and K051, the
solids content is very high for some of these waste streams. They are at levels that indicate
that some of the samples may have been taken after filtering the wastes. At high solid
concentrations, the wastes can not be pumped from the wastewater treatment tank via hard
pipe to the coker.
DPRA assumes a range of 50 to 100 percent of the waste quantity may be fed back to the
coker. Some wastes will not be recycled back to the coker in order to maintain coke product
quality and/or efficient operation of the coker. Overall, DPRA assumes a percent oil
fraction that ranges from 15 to 50 percent, with a typical value of 15 percent oil.
Waste Quantity
Attached is a printout from the 1993 Biennial Report System of all F037, F038, and K048
through K052 waste stream generation quantities for SIC 2911 (petroleum refining). In
1993, the petroleum refining industry generated 9.3 million tons (8.5 million metric tons) of
these seven waste types. For this analysis, DPRA excluded all quantities associated with
K050, K052, and/or wastes containing heavy metals (D004-D011) as not being appropriate to
manage in a coker. The resulting quantity is 2.0 million tons (1.8 million metric tons).
Benefit Estimate
Assuming that 50 to 100 percent of the 1.8 million metric tons are recycled back to the
coker, this waste contains approximately 135,000 to 270,000 metric tons (15 percent) of oil.
Of these amounts, 70 percent of the oil is condensed into vapors for light hydrocarbon
recovery and 30 percent is converted into petroleum coke ($1.36/barrel; S6.16/MT).
Assuming that 90 percent of the oil is recovered from the condensed vapors and the
recovered light hydrocarbons (pre-fuel quality) has 110 percent of the feedstock value of oil
($18.43/barrel; $136/MT) results in a benefit of approximately $13 to $26 million. This
estimate does not include any costs for handling and transporting the waste to the coker or
the coker operator's time to monitor and feed the wastes into the coker.
-------
value of S2.1 million* in compliance costs will be incurred. However, if a headworks
exemption is granted, no incremental compliance costs will be incurred and the above RCRA
Subtitle C costs will be avoided
Table 6. Annual Incremental Costs for Wash Water Treatment
Risk Reduction Alternative and
Cost Option
Alternative 1 : Headwaters exemption
Alternative 2: Cost Option 1 - Conditional
Exemption, In-line Filtration System (large
system handling all plant wastewaters)
Alternative 2: Cost Option 2 - Conditional
Exemption, Redundant API/DAF/Filtration
System (small system handling only wash
waters)
Alternative 2: Cost Option 3 - Off-site
Subtitle C Treatment
Alternative 2: Cost Option 4 - Conditional
Exemption. Least Cost Option
Annual Incremental Costs for Treatment
of CSO Tank and Hydrot realms and
Hydrorefhiing Reactor Wasli Waters
$0
$9.4 Million
($6. 6, Million -$14.8 Million)
$2.1 Million
($1.2 Million -$3.8 Million)
$11. 4 Million
($3. 8 Million -$26. 9 Million)
$2.1 Million
($1.0 Million -$3.7 Million)
19
-------
TABLE 7. Summary uf the Incremental Compliance Costs
by Waste Stream and Cost Impact Option
($ millions per year)1
Waste Stream
Clarified Slurry Oil
Sludge
Hydrotreating
Catalyst
Hydrorefining
Catalyst
RCRA Admin.
Costs
TOTAL
Listing Scenario
stJtHitteCUodfaiof
Stodges and Cwdysts
2.6
[1.3-4.51
1.3
[0.8 - 2.9|
1.5
[0.7 - 3.8|
0.4
[0.3 -0.5|
5.9
[3.1-11.71
tDR Scenario, Option \
Off-Siie Incineration of Sludges and
Incineration and Vitrification
Of Catalysts
22.5
[11.2- 37.6|
5.0
[3.5-7.61
11.6
[8.3 - 16.5|
0.4
[0.3 - 0.5[
39.6
[23.3 - 62.3|
IPS Scenario, Option 2
OtWOff-SUe fncineratwn of Sludges
and Regeneration/Reclamation
of Catalysts
17.8
[9.9 - 28.0|
2.3
|1.2 -4.5|
3.9
[1.9 - 7.9|
0.7
[0.5 - 0.8|
24.7
|l i.6 - 41.2|
Contingent Management Scenario
(Conditional Listing)
Subtitle P Landfill and Land
Tr«atnien( (w/ controls) of Sludges
and Regenertttion/Keclanjation
o(" Catalysts
(0.5 1
hO.ti - (O.H)|
2.i
|l.2 .4.5|
3.9
[1.9 - 7.1J|
0.4
|0. 1 - 0.5|
6.1
M.I - 12.1|
1 Costs are presented as the average cost followed by the range of costs from low to high in brackets. Parentheses indicate negative values, credits.
Source: U.S. EPA, "Addendum to Draft Final Report: Cost and Economic Impact Analysis of Listing Three H;uardous Wastes from ihe Petroleum Refining
Industry," October 30, 1995.
20
-------
DOCUMENT 5
COST IMPACT ANALYSIS OF THE
COKING EXEMPTION
ON CRUDE OIL TANK SLUDGE AND CLARIFIED SLURRY OIL SLUDGE
COMPLIANCE COSTS FROM LISTING AS A RCRA HAZARDOUS WASTE
January 10, 1998
-------
:-'500 Ffst National BaM SuilCiiig S: =5ui. Minnesota 55'C1-'3'.:
January 10, 1998
Mr. Andrew Wittner
U.S. Environmental Protection Agency, Crystal Station
Office of Solid Waste
Economics, Methods and Risk Assessment Division
2800 Crystal Drive
Arlington, Virginia 22202
RE: Cost Impact Analysis of the Coking Exemption on Crude Oil Tank Sludge and
Clarified Slurry Oil Sludge Compliance Costs from Listing as a RCRA Hazardous
Waste; DPRA WA No. 3821.316
Dear Andy:
Attached is the final draft report of the Cost Impact Analysis of the Coking Exemption on
Crude Oil Tank Sludge and Clarified Slurry Oil Sludge Compliance Costs from Listing as a
RCRA Hazardous Waste. The long term incremental compliance cost of listing with LDR
impacts four petroleum refining wastes (crude oil tank sludge, clarified slurry oil sludge,
hydrotreating catalyst, and hydrorefming catalyst), including the coking exemption for the
sludges, ranges from approximately $35 to $75 million (1997$) annually, with an expected
long term cost of around $50 million per year.
Please call me with any questions or comments at 612/227-6500.
Sincerely,
Dave Gustafson
Senior Associate
cc: Chris Long, SAIC
Chris Lough, DPRA
Mailing Adcress: PQ. Box 727 Manhattan. Kansas 66505 Teieunone 913-539-3565 FAX 913-539-5353
Courier Address: 2GO Researcn Drive Manhattan. Kansas 66503
Other offices: Dallas. Denver. Milwaukee. St. Paul. Washington
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COST IMPACT ANALYSIS
OF THE COKING EXEMPTION ON
CRUDE OIL TANK SLUDGE AND CLARIFIED SLURRY OIL SLUDGE
COMPLIANCE COSTS FROM LISTING AS A RCRA HAZARDOUS WASTE
This report presents a cost impact analysis of the redefinition of petroleum cokers as process
recycling units under the definition of solid waste (DSW). This rulemaking will exempt petroleum
coking units from all regulatory requirements (i.e., design, operation, and permitting standards)
under RCRA Subtitle C when recycling crude oil tank sludges (COTS) or clarified slurry oil
(CSO) sludge for the production of petroleum coke, when the sludge is introduced into the non-
quench cycle of the coker, or the quench cycle of the coker if data is provided to show that oil
recovery occurs in amounts that show quenching is more like a normal refining operation. A
complete exemption from RCRA Subtitle C storage, transportation, and management regulations
is granted for all crude oil storage tank sludges and clarified slurry oil sludge that are recycled as
feedstock into petroleum coking units (i.e., the front end of the coking unit rather than the quench
cycle) for the purpose of producing petroleum coke.
ISSUE
Under the proposed listing, a coking exemption is being provided for COTS and CSO sludge that
are recycled back into an on-site coking process unit, off-site coking process unit owned by the
same company, or an off-site coking process unit owned by another company. Currently, COTS
and CSO sludge are typically managed in Subtitle D landfill or land treatment units. Without the
coking exemption, to comply with the listing itself, they will be required to be managed in Subtitle
C landfill units. In addition, to comply with the Land Disposal Restrictions (LDR) requirements
being specified simultaneously with the listing, they ultimately will be managed in Subtitle C
thermal destruction (i.e., incineration) units. The scope of the analysis covers the impact the
coking exemption has on compliance costs associated with COTS and CSO sludge.
GENERATION AND MANAGEMENT
COTS Generation and Current Management
Nearly all refineries store feedstock materials and products in tanks. Periodically crude oil storage
tanks (COTS) require sludge removal due to maintenance, inspection, or sludge buildup. The
average reported cleanout frequency in the 1992 RCRA 3007 Survey is once every 10.5 years.
Also, on average, there are approximately eight crude oil tanks per refinery. Based on the
average number of tanks per facility and the clean-out frequency, crude oil tank sludge is
generated every 1.3 years at a facility. Crude oil tank sludge consists of heavy hydrocarbons,
sediment and water, and entrapped oil that settles to the bottom of the tank. When removed, the
-------
oil is recovered while the solids are collected and discarded as a waste. The discarded waste may
now be recycled in coking units under the newly proposed DSW rulemaking.
Petroleum refineries generate between 45,900 and 114,700 metric tons per year (Mtons/yr) with a
typical value of approximately 80,300 Mtons/yr of COTS affected by this listing.1 EPA estimates
that 145 facilities generate this waste. Given the infrequent tank cleanout schedule and the
structure of the 1992 RCRA 3002 Survey, 85 of 93 facilities reported generating this waste but
did not report the total quantity associated with cleaning out all of their tanks. Fifteen facilities
did not report cleanout quantities for any of their tanks. EPA also estimated that an additional 52
facilities have existing crude oil storage tanks but did not report generating this waste. All
facilities with existing crude oil storage tanks are assumed to generate COTS unless it has been
specifically stated in a cover letter or communication that the residual is not generated. Waste
quantities for these non-reported quantities were estimated based on quantities reported by other
refineries and their crude oil usage. These estimates account for approximately 86 percent of the
typical annual quantity.
The 80,300 metric tons of COTS generated annually reflects the average annual quantity at the
point of generation (i.e., prior to entering the waste management train). The annual quantity that
is ultimately managed (i.e., reaches its final disposition) for COTS is much lower because
refineries are filtering oily sludges and recycling the oil fraction back into process units. EPA
assumes that all refineries who currently are not filtering oily sludges will install a filtration unit to *
recycle the oil back into process units as a cost-effective waste minimization practice. Some
refineries reported both the quantity entering and exiting pressure filtration/centrifuge units,
providing an estimate of the oil recovery rate. Based on this ratio, on average, 60 percent of the
COTS volume filtered is recovered as oil and recycled back into process units. The "non-process
recycled" annual quantities reaching the end of the waste management train (i.e., final
management) is 14,600 Mtons/yr. If this filtration waste minimization practice is not
implemented, the total would be 17,400 Mtons/yr. Of the 14,600 Mtons/yr, 2,700 Mtons/yr
qualify for the wastewater treatment headworks exemption and 1,300 Mtons/yr currently are
managed in RCRA Subtitle C disposal units.
For this cost analysis, it is assumed that refineries will de-oil the COTS first prior to placement in
the coker. Therefore, the analysis continues to assume an oil-benefit for the recovered oil
quantity, but excludes this same quantity from being available for a potential coke-benefit to avoid
double counting of cost benefits. In addition, if the COTS is currently managed in the wastewater
treatment headworks, it is assumed that the refinery will continue to manage the waste in that
manner under the headworks exemption because of its likely low BTU content and low carbon
content. Finally, those wastes currently being managed in RCRA Subtitle C disposal units now
may be recycled in coking units and subject to potential cost benefits from the DSW coking
1 This quantity excludes amounts that currently are managed in RCRA-exempt process recycling units
including on-site cokers (the focus of this cost impact analysis), on-site catalytic crackers, on-site distillation units,
and other reported on-site/off-site recycling/reclamation/reuse practices that are not land applied.
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recycling exemption. This analysis will focus on the economic tradeoffs between coker recycling
and RCRA Subtitle C management options for the 11,900 Mtons of de-oiled COTS disposed
annually (14,600-2,700).
The most common residual disposal methods for COTS are disposal in an off-site Subtitle D or C
landfill. Pressure filtration/centrifuging is a common residual treatment method. Other treatment
methods include thermal treatment, off-site incineration, washing with distillate or water, sludge
thickening or de-watering, settling, filtration, chemical or thermal emulsion breaking, land
treatment, discharge to an on-site wastewater treatment facility, drying on a pad, and stabilization.
Other disposal methods include discharge to surface water under NPDES, disposal in an on-site
Subtitle C landfill, and disposal in an on-site surface impoundment.
CSO Sludge Generation and Current Management
Petroleum refineries produce between 18,300 and 35,400 Mton/year with a typical value of
approximately 26,800 Mton/year of clarified slurry oil sludge that is affected (i.e., subject to a
compliance cost) by this listing. EPA estimates that 101 facilities generate this waste. Thirty-
seven of the 54 facilities reporting generating this waste did not report quantities for cleaning
out all of their tanks. Six of the 54 facilities did not provide a quantity. EPA also estimated
that an additional 47 facilities did not report generating this waste. These estimates account
for approximately 64 percent of the typical annual quantity.
Similarly to COTS quantity estimates, the 26,800 metric tons of CSO sludge generated annually
reflects the average annual quantity at the point of generation (i.e., prior to entering the waste
management train). The "non-process recycled" annual quantities reaching the end of the waste
management train (i.e., final management) is 13,100 Mtons/yr. If the filtration waste minimization
practice is not implemented, the total would be 18,000 Mtons/yr. Of the 13,100 Mtons/yr, 500
Mtons/yr qualify for the wastewater treatment headworks exemption and 2,000 Mtons/yr
currently are managed in RCRA Subtitle C disposal units.
For this cost analysis, it is assumed that refineries will de-oil the CSO sludge first prior to
placement in the coker. Therefore, the analysis continues to assume an oil-benefit for the
recovered oil quantity, but excludes this same quantity from being available for a potential coke-
benefit to avoid double counting of cost benefits. In addition, if the CSO sludge is currently
managed in the wastewater treatment headworks, it is assumed that the refinery will continue to
manage the waste in that manner under the headworks exemption because of its likely low BTU
content and low carbon content. Finally, those wastes currently being managed in RCRA Subtitle
C disposal units now may be recycled in coking units and subject to potential cost benefits from
the DSW coking recycling exemption. This analysis will focus on the economic tradeoffs between
coker recycling and RCRA Subtitle C management options for the 12,600 Mtons of de-oiled
COTS disposed annually (13,100 - 500).
The most common residual disposal method for CSO sludge is disposal in an off-site Subtitle
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D or C landfill. Pressure filtration/centrifuging is a common residual treatment method.
Other treatment methods include on-site industrial flare, washing with distillate, sludge
thickening or de-watering, settling, filtration, thermal emulsion breaking, land treatment,
discharge to on-site wastewater treatment facility, drying on a pad, and stabilization. Other
disposal methods include disposal in an on-site Subtitle D landfill.
Compliance Management Scenarios
Under the Listing Scenario (i.e., incremental compliance cost due to listing), the assumed
compliance practice is disposal in an on-/off-site Subtitle C landfill. Storage and treatment units
will be retrofitted with secondary containment systems to meet Subtitle C accumulation storage
and treatment tank regulations. Discharge of flushing waters to on-site wastewater treatment
systems will be continued because of a "headwater exemption" provided for waste-derived
sludges from wastewater treatment systems that are not already hazardous due to a previous
listing. The practice of disposing this waste in land treatment and disposal surface impoundment
units will be discontinued. In the evaluation of the coking exemption costs/benefits, when
economically more advantageous, the cost for on-/off-site Subtitle C landfill and secondary
containment retrofitting costs will be substituted with lower costs associated with recycling in a
coking unit. Handling costs will be assumed to be equivalent. Only transportation and
disposal/recycling costs are compared.
For the Land Disposal Restrictions (LDR) Scenario (i.e., incremental compliance cost due to
listing and LDR regulations), the assumed compliance practice is disposal in either an on-site or
off-site Subtitle C incinerator, depending on which practice is more economical. Storage and
treatment units will be retrofitted with secondary containment systems to meet Subtitle C
accumulation storage and treatment tank regulations. Discharge of flushing waters to on-site
wastewater treatment systems will be continued because of a "headwater exemption" provided for
waste-derived sludges from wastewater treatment systems that are not already hazardous due to a
previous listing. The practice of disposing this waste in land treatment and disposal surface
impoundment units will be discontinued. In the evaluation of the coking exemption costs/benefits,
when economically more advantageous, the cost for on-/off-site Subtitle C incineration and
secondary containment retrofitting costs will be substituted with lower costs associated with
recycling in a coking unit. Handling costs will be assumed to be equivalent. Only transportation
and disposal/recycling costs are compared.
LOCATION OF PETROLEUM COKERS
Petroleum refiners operate 47 petroleum coking units according to the 1992 RCRA 3007 Survey.
Most of the units (51 percent) are located in Texas, Louisiana, and California. Table 1 presents
the number of petroleum coking units by state.
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Table 1. Petroleum Coking Units by State
State
Texas
California
Louisiana
Kansas
Illinois
Oklahoma, Washington, Ohio
Mississippi, Alabama, Utah,
Montana, Wyoming,
Minnesota, Indiana, New
Jersey, Virginia
Total
Cokers
10
8
6
4
4
2 each
1 each
47
FEED MATERIAL QUALITY
The percentage of the COTS and CSO sludge having the appropriate "material qualities" to serve
as feed material for petroleum cokers is a critical factor in determining the percentage of the total
quantity of COTS and CSO sludge generated that can be recycled in coking units. An important
quality is the carbon content. Available sampling data provide the percentage of oil and grease
and the carbon content of the waste. These data are used to estimate the percentage of the total
COTS and CSO sludge generation volume that may be appropriate for use as coker feed material.
The Petroleum Refining Listing Determination Final Background Document, from October 31,
1995, provides data for oil and grease and carbon content. For COTS, the 10th, mean, and 90th
percentile values for oil and grease content (5%, 34.3%, and 80%, respectively) and carbon
content (0%, 23%, and 65%, respectively) in percent volume. For CSO sludge, the 10*, mean,
and 90* percentile values for oil and grease content (5%, 29.5%, and 80%, respectively) and
carbon content (0%, 29%, and 70%, respectively) in percent volume. These data include both oily
and de-oiled COTS and CSO sludge. A simple linear regression analysis of the COTS data results
in the following predicted relationship between percent total organic carbon and percent oil and
grease:
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% Oil and Grease = 1.1458 x (% Total Organic Carbon) + 6.1566
no. of'samples = 3
degrees of freedom = 1
R-squared = 0.99827
Standard Error of Coefficient = 0.04770
Standard Error of Y Estimate = 2.2233
The Final Background Document provides a range of oil and grease content values for de-oiled
COTS of 4.87 percent to 41.1 percent. Oil and grease data for de-oiled CSO sludge is
unavailable. Given the similar 10* percentile, mean, and 90th percentile oil and grease values for
oily COTS and oily CSO sludge, the data available for de-oiled COTS is assumed for de-oiled
CSO sludge. The question to be answered is what minimum percent total carbon does the COTS
need to contain to have the appropriate material qualities to serve as feed material for a petroleum
coker? Once the minimum total percent carbon is estimated, the methodology will be to calculate
an equivalent percent oil and grease value using the regression equation provided above. Using
the calculated minimum oil and grease value, linear interpolation will be used between the range
of reported de-oiled COTS values to estimate a percentage of the total de-oiled COTS volume
generated that can be used as feed material for petroleum coking units.
Conoco, in its advertisement for its delayed coking technology, provides a feed analysis of a light
petroleum residual and a heavy petroleum residual. The percent carbon contents are 11.85
percent and 24.47 percent, respectively.2 COTS and CSO sludge should have characteristics that
are more similar to a heavy petroleum residual. So, they are assumed to have a typical value of
approximately 25 percent carbon content when oily. Conoco advertises that it can process light
petroleum residuals that contain only 11.85 percent carbon, therefore, a minimum value of 10%
carbon is assumed for heavy petroleum residuals such as COTS and CSO sludge when de-oiled.
Based on the regression equation, a de-oiled COTS waste that is 10 percent carbon contains
approximately 17.6 percent oil and grease. Through linear interpolation, approximately 65
percent of the total de-oiled COTS quantity has sufficient carbon content for use as feed material
in a petroleum coking unit [(41.1 - 17.6)7(41.1 - 4.87) = 0.649]. This amounts to 7,735 Mtons of
the 11,900 Mtons of de-oiled COTS and 8,190 Mtons of the 12,600 Mtons of de-oiled CSO
sludge disposed annually.
Another "material quality" issue that needs to be considered is how much petroleum coke is
produced from every ton of COTS and CSO sludge used as feed material. Does it differ from
other feed materials placed in the coking units? Does COTS and CSO sludge result in a lower-
grade petroleum coke? For this analysis it is assumed that the quality of petroleum coke
produced from COTS and CSO sludge will be similar to that produced from other petroleum
residuals used as feedstocks. If this is not the case, the unit management cost will be higher to
account for blending of the COTS and CSO sludge with other petroleum residuals over time in
2 http://www.conoco.com/coking/index.html, October 8, 1997.
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proportions that will not compromise the quality of the coke. The cost should not be significantly
higher because COTS and CSO sludge represents only a small fraction of the industry's feedstock
at 7,735 Mtons/yr and 8,190 Mtons/yr, respectively. In the early 1990s, the industry produced 17
million tons of petroleum coke annually, with coke representing approximately 30 percent of the
final product output from the coking unit.3'4 Production increased to 23 million Mtons (25
million tons) in 1994.5 The remainder of the feedstock is converted into petroleum liquid
products such, as naphtha, gas oil, and kerosene. Therefore, over 80 million tons of petroleum
residuals are processed by petroleum coking units annually.
REPORTED COKING UNIT COSTS
The first step in determining unit costs for coking recycling is to assess the data provided in the
1992 RCRA 3007 Survey for those petroleum refineries currently recycling COTS in cokers.
Reported unit costs for other wastes/residuals managed in cokers also are examined.
Reported On-Site Coker Practices
Four refineries reported recovering COTS in on-site coking units. Two refineries reported
recovering CSO sludge in on-site coking units. No refinery provided unit cost information for
COTS. Only one refinery reported a price for CSO sludge. Therefore, coking process costs were
estimated from coking price information. This estimate is presented in the next section of this
analysis.
Reported Transportation Methods
For transport from the tank to the coking unit, one refinery uses a vacuum truck and three
refineries use piping for transporting COTS. Two refineries use a vacuum truck and tanker truck
for transporting CSO sludge. Including other wastes/residuals reported being managed in cokers
in the 1992 RCRA 3007 Survey, four refineries report recovery of COTS, two refineries recover
CSO sludge, seven refineries recover unleaded gasoline tank sludge, two refineries recover
hydrofluoric alkylation sludge, two refineries recover off-spec product and fines from thermal
processes, and one refinery recovers sulfur complex sludge (other than Stretford).
3 DPRA Incorporated telephone communication with Ray Diamond, Pace Consultants (713/669-8800),
June 8, 1995.
4 http://www.conoco.com/coking/index.html, October 8, 1997.
5 1994 DOE Petroleum Supply Annual, Vol. 1, pp. 34, 51.
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Reported Unit Costs
Four refineries provided unit management costs for CSO sludge, unleaded gasoline tank sludge,
and sulfur complex sludge. Because of CBI issues, the associated waste types are not specified
with the unit costs. Two of these refineries use a tanker truck to transport their waste to on-site
coking units. It appears that because of the "bulk" nature of their operations (given their
transportation practices) they have coking unit costs of between $14/Mton and $100/Mton. Two
facilities use dumpsters or drums to transport their waste to on-site coking units and have
significantly higher coking unit costs of $l,400/Mton and $45,000/Mton. Because of the nature
of their transport operations, they likely manage very small quantities, resulting in high unit costs
because of the high labor costs associated with handling operations. For example, if it takes one
laborer, at $50/hour, eight hours to process 0.1 metric ton of sludge, the resulting unit cost is
$4,000/Mton.
For COTS and CSO sludge currently being transported to on-site cokers via bulk methods such as
tanker trucks and piping, it is more likely that the $14/Mton and $100/Mton reported above
reflect the coker management costs associated with current COTS processing in cokers.
However, COTS that are currently land farmed or landfilled are frequently transported via
dumpster, which would indicate that the $l,400/Mton unit cost value also is plausible.
As discussed in more detail later in this document, three scenarios were developed to bound the
incremental compliance cost estimates due to the listing and LDR impacts and a coker exemption
for COTS and CSO sludge. The results of this analysis are presented in Table 2.
For the lower bound scenario (columns A and D of Table 2), Subtitle D landfill transportation unit
costs are assumed for transportation to coker units because COTS and CSO sludge are exempt
from Subtitle C regulation for this scenario when recycled as feedstock in a coker. Since coker
transportation unit costs are very limited, average Subtitle D landfill transportation unit costs
reported by 82 facilities in the 1992 RCRA 3007 Survey are used as a proxy. An average
trucking distance of 100 miles to the nearest coker was assumed to derive a unit cost per Mton-
mile. Petroleum coking units are not as common and widely dispersed as Subtitle D landfills.
Therefore, transportation distances may be significant for refineries located in areas such as the
Rocky Mountain and Southwest regions of the U.S. The following unit costs are used in this
analysis:
Truck with drums: $0.45/Mton-mile,
Truck with dumpsters: $0.27/Mton-mile,
Truck with bed: $0.17/Mton-mile, and
Tanker truck: $0.55/Mton-mile.
For the expected scenario (columns B and E of Table 2), Subtitle C landfill transportation unit
costs are assumed for transportation to coker units because COTS and CSO sludge are hazardous
until they are inserted into the quench cycle of a coker, as assumed in this scenario. Also, only
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intracompany transfers are assumed in this scenario. Therefore, transportation distances are
greater than those assumed for the lower bound scenario. An average distance of 200 miles to the
nearest intracompany coker was assumed in deriving the unit cost estimates. The following unit
costs are used in this analysis:
Truck with drums: $1.12/Mtori-mile,
Truck with dumpsters: $0.36/Mton-mile,
Truck with bed: $0.24/Mton-mile, and
Tanker truck: $0.62/Mton-mile.
For the upper bound scenario (columns C and F of Table 2), only those refineries currently
recycling COTS and CSO sludge in cokers are assumed to continue this waste management
practice. Refineries not currently recycling COTS and CSO sludge in cokers (or managing these
wastes by other exempt management practices) are assumed to dispose of these wastes in an off-
site Subtitle C landfill for the listing scenario and an on- or off-site incinerator for the LDR
scenario. Therefore, unit costs for transportation of waste from other refineries to cokers are not
needed.
COKE PRICES AND COKING PROCESS UNIT COST ESTIMATE
In the early 1990s, the U.S. exported significantly more petroleum coke than that used
domestically. Of the approximately 17 million tons of petroleum coke that were produced
annually in the U.S., 16 million tons per year (94%) were exported and one million tons per year
(6%) were used domestically.6 World Production in 1991 was over 50 million Mtons, excluding
China and the Commonwealth of Independent States.7 Therefore, the U.S. produced less than
one-third of total world production. World exports of green and calcined petroleum coke were
around 17.9 million tpa between 1989 and 1991, with the U.S. accounting for 87% of the total
exports in 1991.8
U.S. petroleum coke production capacity has increased since the early 1990s. In 1994, the U.S.
produced 23 million Mtons of petroleum coke, of which 15 million Mtons were exported.9 The
U.S. domestic demand has increased while the quantity exported has remained approximately
constant. U.S. petroleum coke prices have dropped to a point where they are competitive with
6 DPRA Incorporated telephone communication with Ray Diamond, Pace Consultants (713/669-8800),
June 8, 1995.
7 "Roskill Reports on Metals and Minerals - Petroleum Coke," http://www.roskill.co.uk/petcoke.html,
October 8, 1997 (analysis uses early 1990s data, i.e., 1991 or 1992).
g Ibid.
9 1994 DOE Petroleum Supply Annual, Vol. 1, pp. 34, 51.
9
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other fuels. The U.S. domestic demand has increased because of lower prices and new
applications in industries such as cement kilns and electricity generation facilities. Therefore, the
percentage of the total U.S. coke production that is exported has decreased.
The world outlook is one of rapidly increasing supply leading to lower prices with the expansion
of coke production capacity at oil refineries to be prominent in the U.S. The reasons for this
capacity growth in the U.S. are changing qualities of crude oil and environmental regulations
requiring cleaner transportation fuels. Lower prices may mean increased use of petroleum coke
as a fuel by electricity and cement producers. Some electricity plants now exist that consume
petroleum coke as their sole fuel source. Petroleum coke also is an indispensable raw material for
the aluminum industry whose demand is anticipated to increase. If primary aluminum smelter
capacities are fully utilized, they would have consumed 6.4 million Mtons (approximately 13
percent) of petroleum coke worldwide in 1994.10
With projected increases in petroleum coke production capacity and increases in demand for
petroleum coke from the aluminum, electricity, and cement industries, petroleum coke producers
will be looking for additional feedstock materials. The 7,735 Mtons of COTS generated and
8,190 Mtons of CSO sludge generated annually (of feed material quality) represent a very small
fraction of the feedstock materials used in petroleum coke production. Therefore, petroleum
coking capacity and demand are not assumed to be market constraints to the petroleum refining
industry. However, petroleum coking operators may charge higher prices to refiners wanting to
recycle their COTS and CSO sludge knowing they are competing in a hazardous waste market
that includes high-priced Subtitle C landfill and Subtitle C incineration management as alternative
management methods.
Commercial coke prices from 1992 were obtained from Coal Week International. Commercial
prices from the first quarter of 1996 also were obtained to check that the petroleum coke market
has remained viable since 1992. All costs and prices used in the Economic Impact Analysis (EIA)
are 1992 dollars.
10 "Roskill Reports on Metals and Minerals - Petroleum Coke," http://www.roskill.co.uk/petcoke.html,
October 8, 1997 (analysis uses early 1990s data, i.e., 1991 or 1992).
10
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Petroleum Coke Prices
West Coast Gulf Coast
($/Mton: % Sulfur) fS/Mton; % Sulfur)
1/14/92 40-44 (< 2%) 29-31 (> 2%)
4/7/92 47-53 (< 2%) 13-18 (> 2%)
7/7/92 25-28 (< 2%) 8-10 (> 2%)
10/20/92 26-28 f< 2%) 5-7 f> 2%)
1992Avg. $36 $15
1/2/96 41-44(2%) 18-24(4%)
1/2/96 32-36(3.5%) 16-18(6%)
1/2/96 _^ 11-15 (6%)
1996 Avg. $38 $17
In using these prices, one must be concerned whether the coke product is marketable coke or
catalyst coke (e.g., an intermediate product used for heating purposes in the production of
gasoline). An initial step is to determine what the refinery price would be for selling the coke,
excluding reseller'markup and shipping costs. Paper trails of this type of information are very
limited, if not nonexistent, because resellers are not going to volunteer this type of information in
their price quotes. According to Pace Consultants, located on the Gulf Coast, refineries are
receiving an export price of approximately $7/Mton (adjusted for transportation costs) for
exported marketable coke (i.e., over seas) and $14/Mton (not adjusted for transportation costs)
for use within their own company as an intermediate product for heating purposes in the
production of gasoline.11 The marketable domestic coke price would be approximately $14/Mton
(not adjusted for transportation costs). The coking processing cost should be less than $7/Mton.
West Coast operations produce a lower sulfur coke and can charge a higher price because of the
11 DPRA Incorporated telephone communication with Ray Diamond, Pace Consultants (713/669-8800),
June 8, 1995.
Export Price ($15 per Mton):
$13.50 per short ton
- $5 or $6 for loading costs
- $1 for reseller markup
$6.50 - 7.50 per short ton refinery price (He indicated $5-7 per short ton as a refinery price.)
Within own company:
$13.50 short ton
- $ 1 for reseller markup
$12.50 per short ton
11
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quality of the product. -Refineries are receiving an export price of approximately $30/Mton
(adjusted for transportation costs) for exports and $35/Mton (not adjusted for transportation
costs) domestically.12 The coking process cost should not be different than the Gulf Coast.
For this analysis, it is assumed that East Coast and Midwest refineries that operate petroleum
coking units use similar petroleum oil feedstocks to the Gulf Coast refineries. Therefore, these
refineries produce high sulfur petroleum and follow the Gulf Coast price structure. East Coast
refineries are assumed to have similar export capabilities.
Accounting for profit, a coking process unit cost of $6/Mton is assumed for this analysis.
Transportation costs are not included in the coking process unit cost estimate and are added
separately.
COST IMPACT ANALYSIS
This analysis only assumes the costs associated with processing COTS and CSO sludge in a
petroleum coking unit. The value gained from the coke produced is not assessed for those
refineries that operate coking units. In addition, EPA did not consider the possibility that a
facility may build a coker for COTS and CSO "sludge management."
Methodology
Frequently, several individual waste management methods make up the components of the waste
management practice (i.e., waste management train) for storing, treating, recycling, and disposing
a waste stream. Because of the significant number of waste management trains reported by the
petroleum refining industry, current (baseline) and compliance management costs were developed
for the individual components of each waste management train. The incremental difference in
cost between the baseline and compliance management costs for each individual component of the
waste management train were summed together to develop incremental compliance cost estimates
for the complete waste management practice.
12 Export Price ($36 per Mton):
$33 per short ton
- $5 or $6 for loading costs
- $1 for reseller markup
$27 - $28 per short ton refinery price
Within own company:
$33 short ton
- $1 for reseller markup
$32 per short ton
12
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For example, Petroleum Refinery X generates 100 metric tons per year of crude oil tank sludge.
The current (baseline) waste management train is to filter the oily sludge, recycling 60 metric tons
(MT) of oil filtrate back to the distillation unit, and storing 40 MT of filter sludge in roll-on/roll-
offbins within an accumulation container storage area prior to spreading the sludge in an on-site
Subtitle D land treatment unit (S87/MT).
Under the listing and LDR scenarios without a coking exemption, the following compliance
activities need to be conducted. To comply with Subtitle C accumulation treatment tank
regulations, the filtration operation will require the construction and maintenance of a secondary
containment system underneath the filtration unit ($2,500/yr). The cost for operating and
maintaining the filtration unit will not change and a new filtration unit will not need to be
purchased ($0/yr). The 60 MT of oil filtrate recycled back to the distillation unit is exempt from
regulation under the "definition otf solid waste". A recycled oil credit is applied to the oil filtrate if
the facility has not been de-oiling its sludges as a baseline management practice ($110/MT credit).
To comply with Subtitle C accumulation container storage area regulations, a new accumulation
container storage area will need to be constructed and maintained ($4,800/yr). Under the listing
scenario, to comply with Subtitle C disposal regulations, the refinery will abandon the on-site land
treatment unit (S87/MT), choose not to construct an on-site Subtitle C land treatment unit in
anticipation of future LDR regulations that will mandate the closure of such a unit, and transport
and dispose the waste in an off-site Subtitle C landfill (S73/MT for transport and S233/MT for
Subtitle C landfill). Under the LDR scenario, off-site Subtitle C incineration (S92/MT for
transport and $1,867/MT for Subtitle C incineration) will be the required disposal method. The
baseline costs are subtracted from the compliance cost estimates developed for each scenario to
calculate an estimated incremental compliance cost.
Under the listing and LDR scenarios with a coking exemption, the compliance cost is the cheaper
of the above estimated costs compared with the cost of transporting and using the waste as
feedstock material in a coking unit. As noted previously, only 65 percent of the COTS and CSO
sludge quantity is assumed to be of sufficient quality to be used as feedstock for coking units.
The remaining 35 percent of the quantity is assumed to be managed in either a Subtitle C landfill
or Subtitle C incinerator.
Because of the uncertainty regarding plant-specific coker capacity availability, access limitations,
cost limitations, feedstock quality limitations, and state regulatory restrictions, three scenarios
were evaluated to bound the possible results of the listing and LDR scenarios with a coking
exemption. As an upper bound cost scenario, it is assumed that only those facilities currently
recycling COTS and CSO sludge will continue to do so. However, refiners will seek new cost
optimization solutions since coking is now economical when compared to Subtitle C management
instead of Subtitle D management. Therefore, a second scenario is considered assuming that,
when economical, facilities will transport COTS and CSO sludge to the nearest refinery within the
Same company (i.e., intracompany) that currently operates a coker. For this scenario, it is
assumed that intercompany transfers of COTS and CSO sludge will not occur because of liability
issues for management of hazardous waste. As a lower bound cost scenario, it is assumed that
13
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technology allowing insertion of de-oiled COTS and CSO sludges into coker feedstocks will be
developed and intercompany transfers will occur, with no market pricing. However, it is not
likely that there will be no market pricing given potential profits (compared to Subtitle C
management costs) and potential benefits received by both the generator and recycler.
Results
Table 2 presents the COTS and CSO sludge management costs for the listing and LDR scenarios
with the coker exemption. Columns A and D represent lower bound scenarios, assuming that
technology allowing insertion of de-oiled COTS and CSO sludges into coker feedstocks will be
developed and intercompany transfers will occur, with no market pricing. Subtitle D storage,
treatment, and transportation costs are assumed. Columns B and E represent cost-optimization
scenarios, assuming that refineries with cokers will manage COTS and CSO sludges in the quench
cycle of cokers, when economical, and other refineries will transfer sludges to other refineries
within the same company with cokers. Subtitle C storage, treatment, and transportation costs are
assumed. Columns C and F represent upper bound scenarios, assuming that only those refineries
currently recycling COTS and CSO sludge in cokers will continue to do so. EPA is promulgating
LDRs with the listing of four petroleum refining wastes at this time. Therefore, costs in columns
D, E, and F apply. Costs are anticipated to range between $22 and $113 million annually, with an
expected value of $46 million per year. Shortly following the promulgation of the listing
including LDR impacts, costs are anticipated to range between approximately $46 and $68 million'
annually due to sludge quality possibly being inappropriate for use as coker feedstock material and
as refineries obtain approval for inserting sludge into the quench cycle of the coker. In the long
term, improvements in technology for sludge use as coker feedstock material and intercompany
transfers with market pricing are possibilities. Given the potential for market pricing for
intercompany transfers of wastes for management in coking units, the minimum cost estimate is
more of a lower bound estimate (i.e., column D). The long term costs are estimated to range
between approximately $35 and $75 million annually with expected costs around $50 million per
year.
Seven facilities that generate COTS are located in Alaska, Hawaii, Puerto Rico, and Virgin
Islands. Two facilities that generate CSO sludge are located in Hawaii and Puerto Rico. For these
facilities, the transportation cost to the nearest coker is significant. Therefore, EPA assumes that
these facilities will not manage COTS or CSO sludge in a coker for the listing or LDR scenario.
It should be noted that for the lower bound listing scenario with a coking exemption (column A),
the non-continental facilities will incur approximately 40 percent of the incremental cost of
compliance associated with COTS. In addition, for the lower bound LDR scenario with a coking
exemption (column D), the non-continental facilities will incur over 22 percent of the incremental
cost of compliance associated with COTS. One of these facilities that generates COTS incurs a
high amount of the cost under both scenarios.
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Table 2. Annualized Incremental C^ ..pliance Costs for Management of
Four Petroleum Refining Wastes (1997$ millions)1
Waste Stream
Crude Oil Tank
Sludge
Clarified Slurry Oil
Sludge
Hydrotreating
Catalyst
Hydrorefining
Catalyst
RCRA
Administrative Costs
TOTAL
Unconditional Listing
A
1) De-oil Sludges
2) "Not Same
Person" Coking (100
% Used in
Feedstock)
3) Off-Site Subtitle
C Landfill
Remaining Sludges
4) Off-Site Subtitle
C Landfill of
Catalysts
1.1
[0.4-2.11
0.3
[0.0 - 0.9]
1.5
[0.9 - 3.21
1.7
[0.8-4.2]
0.6
[0.4-0.7]
5.2
[2.5-11.1]
B
1) De-oil Sludges
2) "Same Person"
Coking (100% Used
in Quench)
3) Off-Site Subtitle
C Landfill
Remaining Sludges
4) Off-Site Subtitle
C Landfill of
Catalysts
1.8
[0.8-3.31
1.1
[0.5-2.0]
1.5
[0.9 - 3.2]
1.7
[0.8 - 4.2]
0.6
[0.4 - 0.7]
6.7
[3.4 - 13.4]
C
1) De-oil Sludges
2) Continue Current
On-Site Coking
(100% Used in
Quench)
3) Off-Site Subtitle
C Landfill
Remaining Sludges
4) Off-Site Subtitle
C Landfill of
Catalysts
2.5
fl.l -4.4]
2.9
[1.4-5.0]
1.5
[0.9 - 3.2]
1.7
[0.8 - 4.2]
0.6
[0.4-0.7J
9.2
[4.6 - 17.5]
Unconditional Listing Including LDR Impact
D
1) De-oil Sludges
2) "Not Same
Person" Coking (100
% Used in
Feedstock)
3) Off-Site Subtitle
C Incineration
Remaining Sludges
4) Off-Site Subtitle
C Incineration &
Ash Vitrification of
Catalysts
8.7
[4.1 - 14.91
8.1
[3.9- 13.8]
5.6
[3.9 - 8.5]
13.0
[9.3- 18.4]
0.6
[0.4-0.8]
36.0
[21.6-56.4]
E
1) De-oil Sludges
2) "Same Person"
Coking (100% Used
in Quench)
3) Off-Site Subtitle
C Incineration
Remaining Sludges
4) Off-Site Subtitle
C Incineration &
Ash Vitrification of
Catalysts
13.2
[6.1 -22.91
13.8
[7.0 - 23.0]
5.6
[3.9 - 8.5]
13.0
[9.3 - 18.4]
0.6
[0.4 - 0.8J
46.2
[26.7 -73.6]
F
1) De-oil Sludges
2) Continue Current
On-Site Coking
(100% Used in
Quench)
3) Off-Site Subtitle
C Incineration
Remaining Sludges
4) Off-Site Subtitle
C Incineration &
Ash Vitrification of
Catalysts
24.1
[10.4-43.3]
25.1
[12.5-42.0]
5.6
[3.9-8.5]
13.0
[9.3- 18.4]
0.6
[0.4-0.81
68.4
[36.5 - 113.0]
15
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1 Ci_ are presented as the average cost followed by the range of costs from lo». .o high in brackets. In the economic impact analysis, 1992 costs were
estimated. Costs were inflated to 1997 dollars using an inflation factor of 1.11657. The inflation factor is based on Engineering News-Record construction
(25% weighted) and common labor (75% weighted) cost indexes. The inflation factor is weighted towards labor factors because compliance costs are more
operational in function. Costs are annualized assuming a discounted rate of seven percent over a 20 year period.
Notes:
1) All crude oil tank and clarified slurry oil sludges are assumed to be de-oiled in the cost estimate. The recovered oil is recycled back into process units. .For
those tcfineries that reported oil recovery fractions that data were used. For refineries that did not provide data, using an industry average for CSO sludge and
COTS, 60 percent of the quantity entering the filtration unit is assumed to be recovered as oil and the remaining 40 percent goes on for further management.
2) Of the remaining de-oiled sludge quantity (i.e., 40 percent fraction), 65 percent is assumed to have coker feedstock/quench quality. The remaining 35
percent is subject to Subtitle C management (see Note 3).
If sludges are recycled back into coking units through the quench cycle, they are not granted the oil-bearing exclusion (columns B, C, E, and F). Therefore, all
storage, treatment, and transportation of these wastes are subject to RCRA Subtitle C regulation. Columns B and E reflect management of sludges in cokers
owned by the same company (i.e., "same person"). Refineries owned by the same company will be willing to share any liability associated with handling
sludges subject to Subtitle C regulation.
If sludges are recycled back into coking units with the feedstock material, they are granted the oil-bearing exclusion (columns A and D). Therefore, all storage,
treatment, and transportation of these wastes are not subject to RCRA Subtitle C regulation. Columns A and D assume no technical limitations for using the
sludges as feedstock material for the coking unit. Currently, technical limitations appear to exist for using these sludges as feedstock materials in coking units
which will deter intercompany transfers (i.e., "not same person"). If so, the oil-bearing exclusion will not be available and Subtitle C regulations are attached
to the transferred waste and the costs in columns B and E should be used. However, a market may develop where refineries will charge more to handle
intercompany sludge transfers as a hazardous waste. If so, the costs will be between columns A and B and D and E, respectively.
3) LDRs are being promulgated for CSO sludge and COTS under this rulemaking. Therefore, the costs in columns D, E, and F apply. Where it is not
economically feasible to insert the sludge into a coking unit, Subtitle C incineration is the assumed compliance practice in the cost estimate.
4) LDRs are being promulgated for hydrotreating and hydrorefining catalysts under this rulemaking. Therefore, the costs in columns D, E, and F apply.
Subtitle C incineration and ash vitrification are the assumed compliance practice in the cost estimate.
Bold Numbers: The numbers in bold reflect the best approximation of the costs associated with this rulemaking. Costs are anticipated to range between
$22 and $113 million annually, with an expected value of $46 million per year. Shortly following the promulgation of the listing including LDR impacts, costs
are anticipated to range between approximately $46 and $68 million annually due to sludge quality being inappropriate for use as coker feedstock material. In
the long term, improvements in technology for sludge use as coker feedstock material and intercompany transfers with market pricing are anticipated. Given
the potential for market pricing for intercompany transfers of wastes inserted into the quench cycle of the coking units, the minimum cost estimate is unlikely.
The long term costs are estimated to range between approximately $35 and $75 million annually with an expected cost around $50 million per year.
16
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