96-28659. Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category

[Federal Register Volume 61, Number 242 (Monday, December 16, 1996)]
[Rules and Regulations]
[Pages 66086-66130]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-28659]



[[Page 66085]]

_______________________________________________________________________

Part III





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 435



Oil and Gas Extraction Point Source Category; Final Effluent 
Limitations Guidelines and Standards for the Coastal Subcategory; Final 
Rule

Federal Register / Vol. 61, No. 242 / Monday, December, 16, 1996 / 
Rules and Regulations

[[Page 66086]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 435

[FRL-5648-4]
RIN 2040-AB72


Final Effluent Limitations Guidelines and Standards for the 
Coastal Subcategory of the Oil and Gas Extraction Point Source Category

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: This Clean Water Act (CWA) regulation limits the discharge of 
pollutants into waters of the United States and the introduction of 
pollutants into publicly-owned treatment works by existing and new 
facilities in the coastal subcategory of the oil and gas extraction 
point source category.
    This regulation establishes effluent limitations guidelines and new 
source performance standards (NSPS) for direct dischargers based on 
``best practicable control technology currently available'' (BPT), 
``best conventional pollutant control technology'' (BCT), ``best 
available technology economically achievable'' (BAT), and ``best 
available demonstrated control technology'' (BADCT) for new sources. 
The regulation also establishes ``pretreatment standards for new 
sources'' (PSNS) and ``pretreatment standards for existing sources'' 
(PSES) discharging their wastewaters to publicly-owned-treatment works 
(POTWs). In essence, this final rule codifies the current permit 
requirements for coastal oil and gas dischargers--except that it also 
requires zero discharge of offshore produced water for discharges to 
the main passes of the Mississippi River, applies to discharges not 
currently authorized by permits, and establishes limitations in Cook 
Inlet, Alaska which are equal to those previously established for the 
offshore subcategory. The major wastestreams being limited are produced 
water, drilling fluids, and drill cuttings. These limitations are 
expected to reduce discharges of conventional pollutants by 2,780,000 
pounds per year, nonconventional pollutants by 1,490,000,000 pounds per 
year, and toxic pollutants by 228,000 pounds per year, assuming a 
baseline of current permit requirements. The statutory term ``toxic 
pollutant'' refers to a substance identified as belonging to one of the 
65 families of chemicals listed in the CWA as toxic.

DATES: The regulation shall become effective January 15, 1997, except 
for Sec. 435.45 NSPS which become effective December 16, 1996.
    The compliance dates for the guidelines and standards established 
with this rule are different. The compliance date for PSES is January 
15, 1997. The compliance date for NSPS and PSNS is the date the new 
source begins operation. Deadlines for compliance with BPT, BCT, and 
BAT are established in NPDES permits.
    In accordance with 40 CFR part 23, this regulation shall be 
considered issued for the purposes of judicial review at 1 pm Eastern 
time on January 15, 1997. Under section 509(b)(1) of the CWA, judicial 
review of this regulation can be had only by filing a petition for 
review in the United States Court of Appeals within 120 days after the 
regulation is considered issued for purposes of judicial review. Under 
section 509(b)(2) of the CWA, the requirements in this regulation may 
not be challenged later in civil or criminal proceedings brought by EPA 
to enforce these requirements.
    The incorporation by reference of certain publications listed in 
the regulations is approved by the Director of the Federal Register as 
of January 15, 1997.

ADDRESSES: For additional engineering information contact Mr. Ronald P. 
Jordan, Office of Water, Engineering and Analysis Division (4303), U.S. 
Environmental Protection Agency, 401 M Street, SW, Washington, DC 
20460, [phone]. For additional information on the economic 
impact analyses contact Dr. Matthew Clark, Office of Water, Engineering 
and Analysis Division (4303), U.S. Environmental Protection Agency, 401 
M Street, SW, Washington, DC 20460, [phone].
    The complete public record for this rulemaking, including EPA's 
responses to comments received during rulemaking, is available for 
review at EPA's Water Docket; Room M2616, 401 M Street SW, Washington, 
DC 20460. For access to Docket materials call [phone]. The 
Docket staff requests that interested parties call, between 9 am and 
3:30 pm, for an appointment before visiting the docket. The EPA 
regulations at 40 CFR part 2 provide that a reasonable fee may be 
charged for copying.
    EPA notes that many documents in the record supporting these final 
rules have been claimed as confidential business information (CBI) and, 
therefore, are not included in the record that is available to the 
public in the Water Docket. To support the rulemaking, EPA is 
presenting certain information in aggregated form or is masking 
facility identities to preserve confidentiality claims. Further, the 
Agency has withheld from disclosure some data not claimed as 
confidential business information because release of this information 
could indirectly reveal information claimed to be confidential.

FOR FURTHER INFORMATION CONTACT: Charles E. White, Office of Water, 
Engineering and Analysis Division (4303), U.S. Environmental Protection 
Agency, 401 M Street, SW, Washington, DC 20460, [phone].

SUPPLEMENTARY INFORMATION:

Regulated Entities

    As described in the proposed rule (60 FR 9428, February 17, 1995), 
EPA has clarified the definition of the Coastal Subcategory in the 
Coastal Guidelines. This definition is used to describe the regulated 
entities. Regulated categories and entities include:

------------------------------------------------------------------------
                                               Examples of regulated    
                 Category                             entities          
------------------------------------------------------------------------
Industry.................................  Facilities engaged in field  
                                            exploration, drilling,      
                                            production, and well        
                                            treatment in the oil and gas
                                            industry that are in areas  
                                            defined as ``coastal'' or   
                                            that discharge into areas   
                                            defined as ``coastal.''     
------------------------------------------------------------------------


The term ``coastal'' refers to a location in or on a water of the 
United States landward of the inner boundary of the territorial seas. 
Note that all inland bays and wetlands are included in this definition. 
In addition, any location in Texas or Louisiana between the Chapman 
Line and the inner boundary of the territorial seas is defined as 
``coastal.'' The Chapman Line is defined by points of latitude and 
longitude within the states of Texas and Louisiana which are stated in 
the rule.
    The preceding table is not intended to be exhaustive, but rather 
provides a guide for readers regarding entities likely to be regulated 
by this action. This table lists the types of entities that EPA is now 
aware could potentially be regulated by this action. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your facility is regulated by this action, you should carefully 
examine the applicability criteria Sec. 435.10 and Sec. 435.40 in the 
Regulatory Text section of the rule. If you have questions regarding 
the applicability of this action to a particular entity, consult the 
person

[[Page 66087]]

listed in the preceding FOR FURTHER INFORMATION CONTACT section.

Alternative Baseline for Impact and Benefits Analyses

    Subsequent to the issuance of general permits requiring zero 
discharge for coastal facilities along the Gulf of Mexico, EPA received 
individual permit applications from Texas dischargers seeking to 
discharge produced water. Additionally, the U.S. Department of Energy 
has provided the State of Louisiana with comments and analyses 
suggesting a change to the Louisiana state law requiring zero discharge 
of produced water to open bays by January 1997. Promulgation of this 
rule requiring zero discharge in these areas would generally preclude 
issuance of permits allowing discharge. Therefore, in addition to 
calculating the costs, economic impacts, and pollutant removals 
incremental to current permit limits, EPA has calculated an alternative 
estimate of these factors using an ``alternative baseline.'' This 
``alternative baseline'' assumes that zero discharge would no longer 
apply to Texas dischargers seeking individual permits and Louisiana 
open bay dischargers. Under this alternative baseline, this rule would 
reduce discharges of conventional pollutants by 11,300,000 pounds per 
year, nonconventional pollutants by 4,590,000,000 pounds per year, and 
toxic pollutants by 880,000 pounds per year.

Overview

    The preamble describes the legal authority, background, technical 
and economic basis, and other aspects of the final regulation. The 
definitions, acronyms, and abbreviations used in this notice are 
defined in appendix A to the preamble. The regulatory text for 
amendments to 40 CFR part 435, that implements this rulemaking, follows 
the preamble.

Organization of This Document

Preamble

I. Legal Authority
II. Purpose and Summary of this Rulemaking
    A. Purpose of this Rulemaking
    B. Summary of the Final Coastal Guidelines
III. Background
    A. Definitions of Guidelines and Standards
    B. Requirements for Promulgating, Reviewing, and Revising 
Guidelines and Standards
    C. History of the Rulemaking
IV. Description of the Industry
V. Major Changes to the Database for the Final Regulation
    A. Drilling Fluids and Drill Cuttings
    B. Produced Water
VI. Summary of the Most Significant Regulatory Changes From Proposal
VII. Basis for the Final Regulation
    A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent
    B. Produced Water and Treatment, Workover, and Completion Fluids
    C. Produced Sand
    D. Deck Drainage
    E. Domestic Wastes
    F. Sanitary Wastes
VIII. Economic Analysis
    A. Introduction
    B. Economic Impact Methodology
    C. Summary of Costs and Economic Impacts
    D. Cost-Effectiveness Analysis
IX. Non-Water Quality Environmental Impacts
    A. Drilling Fluids and Cuttings
    B. Produced Water and Treatment, Workover and Completion Fluids
X. Environmental Benefits Analysis
    A. Introduction
    B. Quantitative Estimate of Benefits
    C. Description of Non-Quantified Benefits
XI. Related Acts of Congress, Executive Orders, and Agency 
Initiatives
    A. Pollution Prevention Act
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Small Business Regulatory Enforcement Fairness Act of 1996 
(Submission to Congress and the General Accounting Office)
    E. Unfunded Mandates Reform Act
    F. Executive Order 12866 (OMB Review)
    G. Common Sense Initiative
XII. Related Rulemakings
    A. National Emission Standards for Hazardous Air Pollutants
    B. Requirements for Injection Wells
    C. Spill Prevention, Control, and Countermeasure
    D. Shore Protection Act Regulations
XIII. Summary of Public Participation
XIV. Regulatory Implementation
    A. Toxicity Limitation for Drilling Fluids and Drill Cuttings
    B. Diesel Prohibition for Drilling Fluids and Drill Cuttings
    C. Upset and Bypass Provisions
    D. Variances and Modifications
    E. Synthetic Drilling Fluids
    F. Removal Credits for Indirect Dischargers
    G. Implementation for NPDES Permit Writers
XV. Background Documents
Appendix A to the Preamble--Abbreviations, Acronyms, and Other Terms 
Used in This Document

I. Legal Authority

    This final regulation establishes effluent limitations guidelines 
and standards for the Coastal Subcategory of the Oil and Gas Extraction 
Point Source Category under sections 301, 304, 306, 307, 308, and 501 
of the Clean Water Act (CWA), 33 U.S.C. sections 1311, 1314, 1316, 
1317, 1318, and 1361. The regulation is also being promulgated pursuant 
to a Consent Decree entered in NRDC et al. v. Reilly, (D D.C. No. 89-
2980, January 31, 1992) and is consistent with EPA's latest Effluent 
Guidelines Plan under section 304(m) of the CWA. (See 61 FR 52582, 
October 7, 1996).

II. Purpose and Summary of This Rulemaking

A. Purpose of This Rulemaking

    This final rule establishes effluent limitations guidelines and 
standards for the control of the discharge of pollutants for the 
Coastal Subcategory of the Oil and Gas Extraction Point Source 
Category. The discharge limitations promulgated today apply to 
discharges from the coastal oil and gas industry. The processes and 
operations which comprise the coastal oil and gas subcategory (Standard 
Industrial Classification (SIC) Major Group 13) are currently regulated 
under 40 CFR part 435, subpart D. These regulations apply to those 
facilities engaged in field exploration, development drilling, 
production, and well treatment in the oil and gas industry that are in 
areas defined as ``coastal'' or that discharge into areas defined as 
``coastal.'' The term ``coastal'' refers to a location in or on a water 
of the United States landward of the inner boundary of the territorial 
seas. In addition, any location in Texas or Louisiana between the 
Chapman Line and the inner boundary of the territorial seas is defined 
as ``coastal.'' The Chapman Line is defined by points of latitude and 
longitude within the states of Texas and Louisiana which are stated in 
the rule. The final rule promulgated today is referred to as the 
Coastal Guidelines throughout this preamble.
    This preamble highlights key aspects of the Coastal Guidelines. The 
technology descriptions and economic analyses discussed later in this 
notice are presented in abbreviated form. More detailed descriptions 
are included in the Development Document for Final Effluent Limitations 
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas 
Extraction Point Source Category, referred to hereafter as the 
``Coastal Development Document.'' EPA's economic impact assessment is 
presented in detail in the Economic Impact Analysis of Final Effluent 
Limitations Guidelines and Standards for the Coastal Subcategory of the 
Oil and Gas Extraction Point Source Category (hereinafter, ``EIA''), 
included in the rulemaking record. EPA's complete environmental 
benefits analysis is presented in the Water Quality Benefits Analysis 
of Final Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory

[[Page 66088]]

of the Oil and Gas Extraction Point Source Category (hereinafter, 
WQBA), included in the rulemaking record.

B. Summary of the Final Coastal Guidelines

    This rule establishes regulations based on ``best practicable 
control technology currently available'' (BPT) for one wastestream 
where BPT did not previously exist, ``best conventional pollutant 
control technology'' (BCT), ``new source performance standards'' 
(NSPS), ``best available technology economically achievable'' (BAT), 
``pretreatment standards for existing sources'' (PSES), and 
``pretreatment standards for new sources'' (PSNS).
    Drilling fluids, drill cuttings, and dewatering effluent are 
limited under BCT, BAT, NSPS, PSES, and PSNS. BCT limitations are zero 
discharge, except for Cook Inlet, Alaska. In Cook Inlet, BCT 
limitations prohibit discharge of free oil. For both BAT and NSPS, EPA 
is establishing zero discharge limitations for drilling fluids, drill 
cuttings, and dewatering effluent except for Cook Inlet. In Cook Inlet, 
discharge limitations include no discharge of free oil, no discharge of 
diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the 
stock barite, and a toxicity limitation of 30,000 ppm SPP. For both 
PSES and PSNS, EPA is establishing zero discharge limitations in all 
coastal subcategory locations.
    Produced water and treatment, workover, and completion fluids are 
limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, EPA is 
establishing limitations on the concentration of oil and grease in 
produced water and treatment, workover, and completion fluids equal to 
current BPT limits. The Daily Maximum limitation for oil and grease is 
72 mg/l and the Monthly Average limitation is 48 mg/l. For BAT and 
NSPS, EPA is establishing zero discharge limitations, except for Cook 
Inlet, Alaska. In Cook Inlet, the Daily Maximum limitation for oil and 
grease is 42 mg/l and the Monthly Average limitation is 29 mg/l. For 
both PSES and PSNS, EPA is establishing zero discharge limitations.
    For produced sand, EPA is establishing zero discharge limitations 
under BPT, BCT, BAT, NSPS, PSNS, and PSES.
    Deck drainage is limited under BCT, BAT, NSPS, PSES, and PSNS. For 
BCT, BAT, and NSPS, EPA is establishing discharge limitations of no 
free oil. For PSES and PSNS, EPA is establishing zero discharge 
limitations.
    Domestic waste is limited under BCT, BAT, and NSPS. For BCT, EPA is 
establishing no discharge of floating solids or garbage as limitations. 
For BAT, EPA is establishing no discharge of foam as the limitation. 
For NSPS, EPA is establishing no discharge of floating solids, foam, or 
garbage as limitations. There are no PSES and PSNS for domestic waste 
under the Coastal Guidelines.
    Sanitary waste is limited under BCT and NSPS. For BCT and NSPS, 
sanitary waste effluents from facilities continuously manned by ten or 
more persons would contain a minimum residual chlorine content of 1 mg/
l, with the chlorine level maintained as close to this concentration as 
possible. Facilities continuously manned by nine or fewer persons or 
only intermittently manned by any number of persons must not discharge 
floating solids. EPA is establishing no BAT, PSES, or PSNS regulations 
for sanitary waste under the Coastal Guidelines.

III. Background

    The objective of the Clean Water Act is to ``restore and maintain 
the chemical, physical, and biological integrity of the Nation's 
waters''. To that end, it is the national goal that the discharge of 
pollutants to the nations waters be eliminated. CWA section 101.

A. Definitions of Guidelines and Standards

    To assist in achieving the objective of the CWA, EPA issues 
effluent limitations guidelines, pretreatment standards, and new source 
performance standards for industrial dischargers. These guidelines and 
standards are summarized below:
1. Best Practicable Control Technology Currently Available (BPT)--Sec. 
304(b)(1) of the CWA
    BPT effluent limitations guidelines apply to discharges of 
conventional, toxic, and nonconventional pollutants from existing 
sources. BPT guidelines are generally based on the average of the best 
existing performance by plants in a category or subcategory. In 
establishing BPT, EPA considers the cost of achieving effluent 
reductions in relation to the effluent reduction benefits, the age of 
equipment and facilities, the processes employed, process changes 
required, engineering aspects of the control technologies, non-water 
quality environmental impacts (including energy requirements), and 
other factors as the Administrator deems appropriate. CWA section 
304(b)(1)(B). Where existing performance is uniformly inadequate, BPT 
may be transferred from a different subcategory or category.
2. Best Conventional Pollutant Control Technology (BCT)--Sec. 304(b)(4) 
of the CWA
    The 1977 amendments to the CWA established BCT as an additional 
level of control for discharges of conventional pollutants from 
existing industrial point sources. In addition to other factors 
specified in section 304(b)(4)(B), the CWA requires that BCT 
limitations be established in light of a two part ``cost-
reasonableness'' test. EPA published a methodology for the development 
of BCT limitations which became effective August 22, 1986 (51 FR 24974, 
July 9, 1986).
    Section 304(a)(4) designates the following as conventional 
pollutants: biochemical oxygen demanding pollutants (measured as 
BOD5), total suspended solids (TSS), fecal coliform, pH, and any 
additional pollutants defined by the Administrator as conventional. The 
Administrator designated oil and grease as an additional conventional 
pollutant on July 30, 1979 (44 FR 44501).
3. Best Available Technology Economically Achievable (BAT)--Sec. 
304(b)(2) of the CWA
    In general, BAT effluent limitations guidelines represent the best 
existing economically achievable performance of facilities in the 
industrial subcategory or category. The CWA establishes BAT as a 
principal national means of controlling the direct discharge of toxic 
and nonconventional pollutants. The factors considered in assessing BAT 
include the age of equipment and facilities involved, the process 
employed, potential process changes, non-water quality environmental 
impacts, including energy requirements, and such factors as the 
Administrator deems appropriate. The Agency retains considerable 
discretion in assigning the weight to be accorded these factors. An 
additional statutory factor considered in setting BAT is economic 
achievability across the subcategory. Generally, the achievability is 
determined on the basis of total costs to the industrial subcategory 
and their effect on the overall industry financial health. As with BPT, 
BAT may be transferred from a different subcategory or category. BAT 
may be based upon process changes or internal controls, even when these 
technologies are not common industry practice.
4. Best Available Demonstrated Control Technology For New Sources 
(BADCT)--Sec. 306 of the CWA
    NSPS are based on the best available demonstrated treatment 
technology and

[[Page 66089]]

apply to all pollutants (conventional, nonconventional, and toxic). New 
facilities have the opportunity to install the best and most efficient 
production processes and wastewater treatment technologies. Under NSPS, 
EPA is to consider the best demonstrated process changes, in-plant 
controls, and end-of-process control and treatment technologies that 
reduce pollution to the maximum extent feasible. In establishing NSPS, 
EPA is directed to take into consideration the cost of achieving the 
effluent reduction and any non-water quality environmental impacts and 
energy requirements.
5. Pretreatment Standards for Existing Sources (PSES)--Sec. 307(b) of 
the CWA
    PSES are designed to prevent the discharge of pollutants that pass 
through, interfere with, or are otherwise incompatible with the 
operation of publicly-owned treatment works (POTW). The CWA authorizes 
EPA to establish pretreatment standards for pollutants that pass 
through POTWs or interfere with treatment processes or sludge disposal 
methods at POTWs. Pretreatment standards are technology-based and 
analogous to BAT effluent limitations guidelines.
    The General Pretreatment Regulations, which set forth the framework 
for the implementation of categorical pretreatment standards, are found 
at 40 CFR part 403. Those regulations contain a definition of pass-
through that addresses localized rather than national instances of 
pass-through and establish pretreatment standards that apply to all 
non-domestic dischargers. See 52 FR 1586, January 14, 1987.
6. Pretreatment Standards for New Sources (PSNS)--Sec. 307(b) of the 
CWA
    Like PSES, PSNS are designed to prevent the discharges of 
pollutants that pass through, interfere with, or are otherwise 
incompatible with the operation of POTWs. PSNS are to be issued at the 
same time as NSPS. New indirect dischargers have the opportunity to 
incorporate into their facilities the best available demonstrated 
technologies. EPA considers the same factors in promulgating PSNS as it 
considers in promulgating NSPS.

B. Requirements for Promulgating, Reviewing, and Revising Guidelines 
and Standards

    Section 304(m) of the CWA requires EPA to establish schedules for 
(i) reviewing and revising existing effluent limitations guidelines and 
standards and (ii) promulgating new effluent guidelines. On January 2, 
1990, EPA published an Effluent Guidelines Plan (55 FR 80), in which 
schedules were established for developing new and revised guidelines 
for several industry categories, including the coastal oil and gas 
industry. Natural Resources Defense Council, Inc., challenged the 
Effluent Guidelines Plan in a suit filed in the U.S. District Court for 
the District of Columbia, (NRDC et al. v. Reilly, Civ. No. 89-2980). On 
January 31, 1992, the Court entered a consent decree (the ``304(m) 
Decree''), which establishes schedules for, among other things, EPA's 
proposal and promulgation of effluent guidelines for a number of point 
source categories, including the Coastal Oil and Gas Industry. The most 
recent proposed Effluent Guidelines Plan was published in the Federal 
Register on October 7, 1996 (61 FR 52582).

C. History of the Rulemaking

    EPA promulgated BPT effluent limitations guidelines for all 
subcategories under the oil and gas point source category on April 13, 
1979 (44 FR 22069). Since then, EPA published a notice of information 
and request for comments on the coastal subcategory on November 8, 1989 
(54 FR 46919) and published the proposed Coastal Guidelines on February 
17, 1995 (60 FR 9428).

IV. Description of the Industry

    Coastal oil and gas activities include field exploration, drilling, 
production, and well treatment. Coastal activities are located on 
waters of the United States inland of the inner boundary of the 
territorial seas. These water bodies include inland lakes, bays and 
sounds, as well as saline, brackish, and freshwater wetland areas. 
Although the definition includes waters of the U.S. even in all inland 
states, EPA knows of no existing operations other than those in certain 
states bordering the coast. The definition also includes certain wells 
in Texas and Louisiana between the ``Chapman Line'' and the inner 
boundary of the territorial seas as coastal. Thus, at this time, the 
coastal oil and gas operations are located only in coastal states. 
Table 1 summarizes the number of producing wells and annual drilling 
activities for the coastal subcategory.

                                Table 1.--Profile of Coastal Oil and Gas Industry                               
----------------------------------------------------------------------------------------------------------------
                                                           Number of           Number of                        
       Coastal location                Region           producing wells       production        Annual drilling 
                                                            (1992)         facilities (1992)   activity (wells) 
----------------------------------------------------------------------------------------------------------------
Gulf of Mexico...............  Texas and Louisiana..                4675                 853                 686
                               Alabama and Florida..                  56              \1\ ND                   7
Alaska.......................  Cook Inlet...........                 237                   8                   9
                               North Slope..........                2085                  12                 161
California...................  Long Beach Harbor....                 586                   4                   7
                                                     -----------------------------------------------------------
    Total....................  .....................                7639                 877                 870
----------------------------------------------------------------------------------------------------------------
\1\ Not determined.                                                                                             

    The primary wastewater sources from the exploration and development 
phases of the coastal oil and gas extraction industry include the 
following:
     Drilling fluids
     Drill cuttings
     Sanitary wastes
     Deck drainage
     Domestic wastes
    The primary wastewater sources from the production phase of the 
industry include the following:
     Produced water
     Produced sand
     Well treatment, workover, and completion fluids
     Deck drainage
     Domestic wastes
     Sanitary wastes
    Drilling fluids and drill cuttings are the most significant waste 
streams from exploratory and development operations in terms of volume 
and pollutants. Produced water is the largest waste stream from 
production activities in terms of volumes discharged and quantity of 
pollutants.
    Discharges from coastal oil and gas operations in states along the 
Gulf of

[[Page 66090]]

Mexico, California, and Alaska are regulated by general and individual 
NPDES permits based on BPT, State Water Quality Standards, and on Best 
Professional Judgment (BPJ) of BCT and BAT levels of control.
    A more detailed description of the industry is included in the 
Coastal Development Document, contained in the record for this rule.

V. Major Changes to the Database for the Final Regulation

    This section describes several of the most significant changes 
which have occurred since proposal to the methodology and data base 
used to calculate compliance costs, pollutant reductions, and non-water 
quality environmental impacts. Other changes and issues are discussed 
in other sections of the preamble, the Development Document, the 
Economic Impact Analysis, the environmental benefits analysis 
documents, and the record for this rule.

A. Drilling Fluids and Drill Cuttings

    The compliance costs and pollutant removals presented in the 
Development Document for the proposed rule have been revised to reflect 
information received from coastal industry operators in response to the 
proposal. As in the analysis for the proposal, drilling waste 
compliance cost and pollutant reductions calculations apply only to 
operations in Cook Inlet, Alaska because the rest of the coastal 
subcategory is already attaining zero discharge. Since proposal, the 
industry profile in Cook Inlet has changed, increasing the total waste 
volume on which costs and removals are based by about 15 percent. In 
addition, industry-supplied information resulted in changes to 
particular cost items within the zero discharge analysis.
1. Drilling Projections
    EPA's profile of future drilling activity in Cook Inlet is based on 
information submitted by Cook Inlet operators. In the Development 
Document for the proposal, EPA identified one operator in the analysis 
which had recently canceled plans to drill six new wells. This 
information about the cancellation was received too late to allow for 
revision of the analysis prior to proposal. EPA has since proposal 
confirmed that the operator does not intend to drill these wells and 
they are not included in the revised cost and pollutant reductions 
analyses for the final rule. EPA received other information in comments 
on the proposal updating the drilling plans for other operators in Cook 
Inlet. Compared to the profile used for the proposal, the total number 
of new wells at existing platforms anticipated during the seven years 
following promulgation increased by four and the total number of 
platforms with drilling schedules decreased by two.
2. Engineering Costs
    As was done for the proposal, EPA evaluated two disposal 
technologies for complying with a zero discharge limitation for 
drilling fluids and drill cuttings: 1) transport to shore for land 
disposal; and 2) grinding of the drilling wastes followed by injection 
in a dedicated disposal well. At proposal, compliance costs were based 
on an assumption that both land disposal and downhole injection were 
available technologies for all drilling locations in Cook Inlet. Costs 
for both compliance technologies were developed for each operator and 
the lowest cost compliance scenario was selected as the likely cost of 
the proposed rule. As a result, costs for two operators were based on 
disposal by injection. In response to comments disputing the 
feasibility of injecting drilling wastes into the geologic formations 
present in Cook Inlet, EPA reviewed information in the record and 
sought additional information on this issue from industry and State and 
Federal authorities. Based on the limited data available to date, EPA 
believes that the information in the record indicates that certain 
sites in Cook Inlet may not be able to inject sufficient volumes of 
drilling wastes to enable compliance with zero discharge as EPA has 
defined the technology. See the Development Document and section VII of 
the preamble for additional information. For the final rule, EPA has 
based zero discharge compliance costs for all operators on disposal of 
the drilling wastes at landfills. This is because EPA is unable at this 
time, with the limited data available, to estimate the degree to which 
injection would be available in Cook Inlet.
    The costing methodologies for the landfill and injection scenarios 
in the final rule are based, in general, on the costing methodologies 
presented in the proposal. However, EPA improved the database and 
sought additional confirmatory data in response to comments on the 
proposal. Engineering costs have been adjusted from 1992 dollars to 
1995 dollars to better reflect the current cost of compliance with zero 
discharge. Certain changes resulting from EPA's reevaluation of costing 
assumptions have led to a revision in the cost of landfilling drilling 
wastes.
    In response to comments, EPA reevaluated certain assumptions 
related to the use of supply boats and barges in transporting drilling 
wastes to shore for disposal at landfills. These comments led to a 
reassessment of platform storage space and boat capacities and resulted 
in an increase in the number of boat trips required to haul the 
drilling wastes.
    As discussed at proposal, the sole land disposal site for drilling 
wastes in Cook Inlet (referred herein as the Kustatan landfill) is a 
private facility owned by two of the operators. While no regulatory 
obstacles would prohibit disposing of the wastes from other operators 
at the Kustatan landfill, since it is a private facility its 
availability for use by third parties cannot be assured. As a result, 
EPA's analysis considers the Kustatan landfill to be available for use 
by only two of the operators in the region. Since no other land 
disposal facilities in Alaska are believed available to the remaining 
Cook Inlet operators, the analysis for the proposal based land disposal 
costs for these operators on transporting the drilling wastes to a 
disposal facility in Idaho. In the preamble for the proposed rule, EPA 
discussed the availability of another disposal facility located in 
Oregon and stated that costs using this facility were expected to be 
``close to or less than the costs of using the Idaho facility.'' (See 
60 FR 9442) Further review of these facilities has shown that savings 
would in fact be realized using the Oregon facility and it is the 
disposal site used in the final cost analysis. EPA also revised costing 
estimates to address industry comments regarding specific fees 
associated with disposal at the Kustatan landfill.

B. Produced Water

1. Industry Profile
    a. Gulf of Mexico. For the analyses performed for the proposed 
rule, EPA used information provided by industry sources and state 
regulatory authorities to construct a profile of production facilities 
currently discharging in coastal areas of the Gulf of Mexico. Under 
regulations issued by the State of Louisiana, many facilities are 
required to cease discharges of produced water. Based on the data 
available to EPA at proposal, EPA estimated that there would be 216 
production facilities discharging in the Gulf of Mexico by July 1996 
(the original date scheduled for promulgating final Coastal 
Guidelines). Shortly before the proposal was published, EPA's Region 6 
published final NPDES General Permits regulating produced water and 
produced sand discharges to coastal waters in Louisiana and Texas (60 
FR

[[Page 66091]]

2387; January 9, 1995). These permits prohibited the discharge of any 
produced water derived from coastal waters of Louisiana and Texas. 
Because much of the industry covered by the proposed Coastal Guidelines 
is also covered by these General Permits, the industry profile used in 
the cost and economic analyses for the proposed rule overstates the 
number of facilities that would be incrementally affected by the final 
Coastal Guidelines. This discrepancy was noted at proposal. In the 
preamble for the proposed Coastal Guidelines, EPA stated that due to 
the close proximity (one month) of the timing of the publication of the 
Region 6 General Permits and the proposed guidelines, the costs and 
impacts of the proposed Coastal Guidelines was being presented in the 
preamble as if the General Permits were not final. EPA presented 
preliminary results of how the costs and impacts of the Coastal 
Guidelines would be reduced when the General Permits became effective 
and stated that the regulatory effects of the General Permits would be 
incorporated in the analysis conducted for the final guidelines. See 60 
FR 9430.
    The main difference between the general permits and the Coastal 
Guidelines is that the permits cover wastes generated by onshore 
Stripper Subcategory wells that are not covered under the Coastal 
Guidelines and the Louisiana permit does not cover produced water 
derived from Offshore Subcategory wells that is discharged into a major 
deltaic pass of the Mississippi River, or to the Atchafalaya River 
below Morgan City including Wax Lake Outlet. Since proposal, EPA has 
worked with industry sources and State regulatory authorities to 
identify those facilities whose discharges are covered by the Coastal 
Guidelines, but are not covered by General Permits. No facilities 
discharging Offshore Subcategory produced water into the Atchafalaya 
River were identified. Six production facilities with a total of eight 
outfalls were identified as discharging produced water derived from 
Offshore Subcategory wells into the major deltaic passes of the 
Mississippi River.
    As discussed in the Supplementary Information section of this 
preamble, subsequent to the issuance of the general permits requiring 
zero discharge in the Gulf of Mexico region, EPA received individual 
permit applications from Texas dischargers seeking to discharge 
produced water. Additionally, the U.S. Department of Energy (DOE) has 
provided the State of Louisiana with comments and analyses suggesting a 
change in the Louisiana state law requiring zero discharge of produced 
water to open bays by January 1997.
    Because promulgation of this rule requiring zero discharge in these 
areas would preclude issuance of permits allowing discharge, EPA also 
calculated an alternative estimate of the costs, economic impacts, and 
pollutant removals under an ``alternative baseline.'' This 
``alternative baseline'' assumes that zero discharge under the general 
permits would no longer apply to Texas dischargers seeking individual 
permits and Louisiana open bay dischargers. To do this, EPA reviewed 
the list of facilities requesting an individual permit in Texas, 82 as 
of the date of this writing, and identified the number of facilities 
discharging to open bays using information developed by the State of 
Louisiana for the DOE study of open bays. EPA obtained all available 
information about these facilities from the states and EPA's Coastal 
Questionnaire and used this information to develop estimates of the 
technological availability, costs and economic achievability, non-water 
quality environmental impacts, and pollutant removals achieved by zero 
discharge.
    b. Cook Inlet. EPA updated the profile of Cook Inlet production 
facilities with current hydrocarbon and water production rates to 
address information submitted by industry in comments. The profile was 
also updated with current waterflood rates for use in estimating 
compliance costs under the produced water zero discharge option. The 
most notable changes to the Cook Inlet production profile include one 
platform which resumed oil production and ceased waterflooding; two 
platforms that resumed waterflooding; and one platform substantially 
reduced its waterflood rate. Production and waterflood levels for the 
remaining Cook Inlet facilities have not changed significantly since 
1993. These profile changes are discussed in detail in the Development 
Document and the record for the final rule.
2. Engineering Costs
    a. Gulf of Mexico. Engineering costs have been adjusted from 1992 
dollars to 1995 dollars to better reflect the current cost of 
compliance with zero discharge. Other than the adjustment to 1995 
dollars, no significant changes were made to compliance cost estimates 
for the improved gas flotation option. The more significant changes to 
the cost estimates for the zero discharge option are discussed below.
    Total labor costs in the final analysis are nearly double the labor 
costs estimated at proposal. The labor burden associated with operating 
additional BAT/NSPS control technologies is unchanged from the analysis 
for the proposed rule, but the labor rate has been revised upward based 
on data from Bureau of Labor Statistics. Additional O&M costs were 
added to reflect the costs of replacing the filter cartridges used to 
remove solids from the produced water prior to injection.
    O&M costs for injection pretreatment chemicals were revised based 
on new data provided by the industry, in combination with the data used 
at proposal. Chemicals are already added to the produced water at 
treatment facilities and source water in waterflooding operations at 
existing production locations. The treatment chemical costs included in 
EPA's analysis are costs added incremental to current chemical 
expenditures. In response to comments about the potential for solids 
buildup causing downhole problems in injection wells, EPA reviewed the 
workover data in the record. For the final rule, the frequency of 
backwashing injection wells was doubled--from biennial to once 
annually.
    Pipeline costs have also been increased since proposal. While 
reviewing comments regarding pipeline costs, EPA detected a scale up 
error in the proposal analysis which led to underestimating costs.
    In estimating costs, EPA also took into account facility-specific 
data and comments where it showed discharges were currently capable of 
meeting limits based on operation of improved gas flotation.
    b. Cook Inlet. Other than to adjust costs to 1995 dollars, no 
significant changes were made to Cook Inlet compliance cost estimates 
for the limitations based on gas flotation. As at proposal, compliance 
with zero discharge for the Cook inlet facilities is based on the 
injection of produced water into production zones as part of the 
ongoing waterflood operations or into dedicated disposal wells where 
waterflooding operations do not exist.
    In response to concerns raised in industry comments, capital costs 
for installation of a centrifuge to dewater filtration backwash solids 
were added to platforms assumed to inject produced water under the zero 
discharge scenario. Centrifuges would be used to concentrate the solids 
removed from the filtered produced water, thus allowing the liquid 
portion of the backwash to be injected. The dewatered solids would then 
be disposed of by transport to a landfill (as costed by EPA) or 
injected into a disposal well. This disposal cost

[[Page 66092]]

is included as a new O&M cost in the analysis for the final Coastal 
Guidelines.
    O&M costs for treatment chemicals (e.g., scale inhibitors, 
corrosion inhibitors, biocides) were revised based on industry data. 
All locations that treat produced water prior to injection under the 
zero discharge scenario are assumed to incur costs for treatment 
chemicals. It should be noted that all facilities currently treating 
produced water for discharge already add some chemicals to enhance 
separation and provide protection of treatment equipment. Further, all 
facilities currently waterflooding seawater also add treatment 
chemicals prior to injection. The treatment chemical costs included in 
EPA's estimated compliance costs are incremental to current treatment 
facility and waterflooding chemical expenditures and therefore are 
considered to adequately address industry concerns about chemical 
addition costs resulting from injecting produced water into producing 
formations.
    Information in the record indicates that injection well workover 
costs were underestimated at proposal. Workover costs for the final 
analysis were increased based on comments from Cook Inlet operators and 
a comparison to cost data for workovers in the Gulf of Mexico.
3. Pollutant Reduction Estimates
    Similar to the February 1995 proposal, pollutant removals for the 
different produced water regulatory options of the final rule were 
determined by comparing the estimated effluent levels of pollutants 
after treatment by the BAT/NSPS treatment system (improved performance 
of gas flotation or reinjection) versus the effluent levels of 
pollutants associated with a typical BPT treatment (gravity separation 
or gas flotation).
    In the proposal, EPA characterized BPT treatment in the Gulf of 
Mexico using data collected from ten coastal oil and gas facilities 
located in Louisiana and Texas. Comments received subsequent to the 
proposal stated that the facilities included in the database do not 
adequately represent the quality of produced water which has undergone 
BPT-level treatment and, as a result, overestimate the pollutant 
reductions associated with the BAT/NSPS control options. Several 
comments also disputed the presence of certain pollutants included in 
EPA's BPT characterization.
    In response to these comments, EPA reassessed the characterization 
of BPT-level effluent quality. Certain pollutants were dropped for the 
final analysis because they are believed to have been measured as a 
result of laboratory contamination or are otherwise not expected to be 
present in produced water. In comparison to the total mass of 
pollutants removed by the technologies evaluated in the BAT/NSPS 
options, excluding these pollutants had negligible effect on the 
reductions estimates. The pollutants excluded from the final analysis 
and the reasons for the exclusion are discussed in the Development 
Document, the Response to Comments Document, and the record.
    Upon review of the data used at proposal, EPA determined that three 
of the facilities making up the Ten Facility dataset should be excluded 
from the BPT characterization for the final rule. These facilities had 
high levels of oil and grease, in excess of that allowed to be 
discharged under the BPT effluent limitations guidelines, and therefore 
the pollutant levels at these facilities are not considered 
representative of produced water which has been treated to a level 
which would allow discharge to surface waters. (Produced water from 
these facilities is disposed of through downhole injection.) EPA 
believes it is appropriate to continue using the effluent data 
collected from the remaining seven facilities to represent BPT-level 
pollutant concentrations, even though not all of these facilities 
actually discharge their produced water, since the treatment technology 
at these facilities is typical of that used at the majority of coastal 
facilities and the oil and grease content of the effluent for these 
facilities was lower than that required to meet the existing BPT 
effluent limitations. Total oil and grease measurements at these seven 
facilities range from 8 mg/l to 43 mg/l. When averaged together, the 
average oil and grease concentration for the seven facilities is 26.6 
mg/l, in contrast to an average of 53 mg/l when using data from all ten 
facilities. EPA notes that this revised calculation of the oil and 
grease concentration in BPT-level effluent for the coastal subcategory 
(26.6 mg/l) compares favorably to the BPT-level effluent data (25 mg/l) 
collected previously for the offshore subcategory. (See Section IX of 
the Development Document for Effluent Limitations Guidelines and 
Standards for the Offshore Subcategory of the Oil and Gas Extraction 
Point Source Category, EPA 821-R-93-003, January 1993.) The technology 
basis used to develop BPT limitations for the coastal subcategory is 
identical to the basis used to develop the offshore subcategory BPT 
limitations. (See the Development Document for Interim Final Effluent 
Limitations Guidelines and Proposed New Source Performance Standards 
for the Oil and Gas Extraction Point Source Category, EPA 440/1-76/
055a, September 1976.)
    EPA also took into account facility-specific data and comments 
where it showed discharges were currently capable of meeting limits 
based on operation of improved gas flotation in assessing pollutant 
reductions estimates.

VI. Summary of the Most Significant Regulatory Changes From 
Proposal

    This section briefly identifies the most significant changes from 
proposal. More detailed discussion of these changes, and identification 
and discussion of other issues are included in other sections of this 
notice, the Coastal Development Document, the Economic Impact Analysis, 
and the record for this rule. The most significant changes from 
proposal occurred with regards to: (1) Drilling fluids, drill cuttings, 
and dewatering effluent and (2) produced water and treatment, workover, 
and completion fluids.
    For drilling fluids, drill cuttings, and dewatering effluent, EPA 
proposed three options for both BAT and NSPS limitations. The three 
options were: (1) Zero discharge of drilling fluids, drill cuttings, 
and dewatering effluent except for Cook Inlet, where discharge 
limitations include no discharge of free oil, no discharge of diesel 
oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock 
barite, and a toxicity limitation of 30,000 ppm SPP; (2) Zero discharge 
of drilling fluids, drill cuttings, and dewatering effluent except for 
Cook Inlet, where discharge limitations include no discharge of free 
oil, no discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg 
cadmium limitations on the stock barite, and a toxicity limitation more 
stringent than 30,000 ppm SPP; and (3) Zero discharge everywhere. For 
both BAT and NSPS, option (1) has been selected for the final rule.
    For produced water and treatment, workover, and completion fluids, 
EPA proposed zero discharge everywhere for NSPS. For the final rule, 
NSPS limitations are zero discharge except for Cook Inlet, Alaska. In 
Cook Inlet, the Daily Maximum limitation for oil and grease is 42 mg/l 
and the Monthly Average limitation is 29 mg/l.

[[Page 66093]]

VII. Basis for the Final Regulation

A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent

1. Waste Characterization
    Drilling fluids and drill cuttings are typically discharged in bulk 
during episodes that occur intermittently during well drilling and at 
the end of the drilling phase.
    There are currently no drilling fluid or drill cuttings discharges 
in any coastal area except for Alaska's Cook Inlet. Zero discharge is 
generally met by a combination of landfilling and injection. On 
Alaska's North Slope, while all drilling fluids and most drill cuttings 
are injected, some cuttings are cleaned and used as fill material in 
the construction of drill pads and roads. These fill materials require 
a fill permit issued pursuant to section 404 of the CWA.
    In Cook Inlet, operators do not currently practice zero discharge, 
except for a small volume of drilling fluids and cuttings wastes 
(approximately one percent) which are not discharged because they do 
not meet current permit limits. Generally, drilling fluids and cuttings 
volumes average approximately 14,000 barrels (bbl) per new well drilled 
in Cook Inlet. (NOTE: The barrel is a standard oil and gas measurement 
and is equal in volume to 42 gallons). Based on industry projections 
given to EPA, an average of 89,000 bbls drilling fluids and cuttings 
are generated each year (bpy) in the Inlet. Pollutants present in these 
wastes include chromium, copper, lead, nickel, selenium, silver, 
beryllium and arsenic among the toxic metals. Toxic organics present 
include naphthalene, fluorene, and phenanthrene. Total Suspended Solids 
(TSS) make up the bulk of the pollutant loadings, part of which is 
comprised of the above mentioned toxic pollutants. TSS concentrations 
are very high due to the nature of the wastes.
    Operators use solids control equipment to remove drill cuttings 
from the drilling fluid systems which allows drilling fluids to be 
recycled and reduces the total amount of drilling wastes generated. 
Depending on the solids control system and the method of waste storage 
and disposal onsite, a small wastestream, termed ``dewatering 
effluent'' may be segregated from the drilling fluids and cuttings. 
Dewatering effluent may be discharged from reserve pits or tanks which 
store drilling wastes for reuse or disposal. Dewatering effluent may 
also be generated in enhanced solids control systems. Enhanced solids 
control systems, also known as closed-loop solids control operations, 
remove solids from the drilling fluid at greater efficiencies than 
conventional solids removal systems. Increased solids removal 
efficiency minimizes the buildup of drilled solids in the drilling 
fluid system, and allows a greater percentage of drilling fluid to be 
recycled. Smaller volumes of new or freshly made fluids are required as 
a result. An added benefit of the closed-loop technology is that the 
amount of waste drilling fluids can be significantly reduced. The 
installation of reserve pits is unnecessary in closed-loop systems for 
this reason.
    EPA's general permits for drilling operations in Texas and 
Louisiana (58 FR 49126, September 21, 1993) have limitations for the 
discharge of dewatering effluent, while other parts of the nation 
generally treat dewatering effluent as part of the drilling fluids 
wastestream. However, results from the 1993 Coastal Oil and Gas 
Questionnaire show that few operators discharge dewatering effluent as 
a separate wastestream. Additionally, contacts with industry indicate 
that the volume of dewatering effluent from reserve pits is small and 
growing smaller since the use of pits is phasing out due to state 
permit conditions, environmental or land owner concern, and the 
expanding use of closed-loop systems. EPA site visits to drilling 
operations, where these closed-loop systems were in place, showed that 
none of the dewatering effluent is discharged. Instead, it is either 
recycled, or sent with other drilling wastes to commercial disposal. 
Operators at these facilities explained that it is less expensive to 
send this wastestream along with drilling fluids and drill cuttings for 
onshore disposal rather than to treat for discharge.
2. Selection of Pollutant Parameters
    a. Pollutants Regulated. EPA is establishing BAT, BCT, NSPS, PSES, 
and PSNS limitations that would require zero discharge of drilling 
fluids, drill cuttings, and dewatering effluent, except for BAT, BCT, 
and NSPS in Cook Inlet, Alaska. Where zero discharge is required, EPA 
would be controlling all pollutants in the wastestream.
    For BAT and NSPS in Cook Inlet, discharge limitations for drilling 
fluids, drill cuttings, and dewatering effluent include no discharge of 
free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg 
cadmium limitations on the stock barite, and a toxicity limitation of 
30,000 ppm SPP.
    As presented in the Coastal Development Document, the prohibitions 
on the discharge of free oil and diesel oil would effectively remove 
toxic, nonconventional, and conventional pollutants. Diesel oil and 
free oil are considered, under BAT and NSPS, to be ``indicators'' for 
the control of specific toxic pollutants present in the complex 
hydrocarbon mixtures used in drilling fluid systems. Free oil is also 
an indicator for toxic pollutants present in crude oil. These 
pollutants include benzene, toluene, ethylbenzene, naphthalene, 
phenanthrene, and phenol. Additionally, diesel oil may contain from 20 
to 60 percent by volume polynuclear aromatic hydrocarbons (PAHs) which 
constitute the more toxic components of petroleum products. Control of 
diesel oil would also result in the control of nonconventional 
pollutants under BAT and NSPS. Diesel oil contains a number of 
nonconventional pollutants, including PAHs such as methylnaphthalene, 
methylphenanthrene, and other alkylated forms of the listed organic 
toxic pollutants.
    EPA is establishing BCT limitations for drilling fluids, drill 
cuttings, and dewatering effluent that prohibit the discharge of free 
oil (using the static sheen test) for Cook Inlet. The prohibition on 
the discharge of free oil would effectively reduce or eliminate the oil 
and grease in these discharges. EPA is limiting free oil under BCT as a 
surrogate for oil and grease in recognition of the complex nature of 
the oils present in drilling fluids, including crude oil from the 
formation being drilled.
    For Cook Inlet, prohibiting the discharge of diesel oil and free 
oil eliminates discharges of the above listed constituents, to the 
extent that these constituents are present in either of these two 
parameters, and reduces the level of oil and grease present in the 
discharged drilling fluids and cuttings. Also, limitations on cadmium 
and mercury content in barite will control toxic and nonconventional 
pollutants in drilling waste discharges. This limitation directly 
controls the levels of cadmium and mercury, and indirectly controls the 
levels of other toxic pollutant metals. Control of other toxic 
pollutant metals occurs because cleaner barite that meets the mercury 
and cadmium limits has been shown to have reduced concentrations of 
other metals. Evaluation of the relationship between cadmium and 
mercury and the trace metals in barite shows a correlation between the 
concentration of mercury with the concentration of arsenic, chromium, 
copper, lead, molybdenum, sodium, tin, titanium and zinc; and the 
concentration of cadmium with the concentration of arsenic, boron, 
calcium, sodium, tin, titanium, and

[[Page 66094]]

zinc. (See the Coastal Development Document).
    Toxicity of drilling fluids, drill cuttings, and dewatering 
effluent is being regulated as a nonconventional pollutant that 
controls certain toxic and nonconventional pollutants. It was shown, 
during EPA's development of the Offshore Guidelines, that control of 
toxicity encourages the use of less toxic, water-based drilling fluids, 
and where absolutely necessary, the use of less mineral oil added to a 
drilling fluid (and the pollutants, such as the PAH's, identified as 
constituents of mineral oil). A toxicity limitation thus encourages the 
use of low-toxicity drilling fluids and the use of low-toxicity 
drilling fluid additives.
    b. Pollutants Not Regulated. Where zero discharge is required, all 
pollutants are controlled. In Cook Inlet, EPA has determined that it is 
not technically feasible to specifically control each of the toxic 
constituents of drilling fluids and cuttings that are controlled by the 
limits on the pollutants established in this regulation.
    EPA has determined that certain of the toxic and nonconventional 
pollutants are not controlled by the limitations on diesel oil, free 
oil, toxicity, and mercury and cadmium in stock barite. EPA exercised 
its discretion not to regulate these pollutants because EPA did not 
detect these pollutants in more than a very few of the samples from 
EPA's field sampling program and does not believe them to be found 
throughout the industry; the pollutants when found are present in trace 
amounts not likely to cause toxic effects; and due to the large number 
and variation in additives or specialty chemicals that are only used 
intermittently and at a variety of drilling locations, it is not 
feasible to set limitations on specific compounds contained in 
additives or specialty chemicals. See the Coastal Development Document 
for further discussion.
3. Control and Treatment Technologies
    a. Current Practice. BPT effluent limitations guidelines for 
coastal drilling fluids and drill cuttings prohibit the discharge of 
free oil (using the visual sheen test). However, because of either EPA 
general and individual permits, state requirements, or operational 
preference, no drilling fluids and cuttings discharges are occurring in 
the coastal waters of the Gulf coast states or California. The only 
coastal operators disposing of drilling fluids and drill cuttings by 
discharge are located in Cook Inlet. In Cook Inlet, neither diesel nor 
mineral-oil-based drilling fluids or resultant cuttings may be 
discharged to surface waters. Compliance with the BPT limitations may 
be achieved either by product substitution (substituting a water-based 
fluid for an oil-based fluid), recycle and/or reuse of the drilling 
fluid, onshore disposal of the drilling fluids and cuttings at an 
approved facility, or disposal by injection where feasible. On Alaska's 
North Slope, all drilling fluids and most drill cuttings are injected, 
though some cuttings are cleaned for use as fill material for the 
construction of drilling pads and roads. This fill activity is 
regulated under section 404 of the CWA.
    NPDES permits issued by EPA for Cook Inlet drilling operations have 
also included BAT limitations based on ``best professional judgement'' 
(BPJ). The permit requirements allow discharges of drilling fluids and 
drill cuttings provided certain limitations are met including a 
prohibition on the discharges of free oil and diesel oil, as well as 
limitations on mercury, cadmium, toxicity and oil content. Operators in 
Cook Inlet typically employ the following waste management practices to 
meet those permit limitations:
    * Product substitution--to meet prohibitions on free oil and diesel 
oil discharges, as well as the toxicity and/or clean barite 
limitations,
    * Onshore treatment and/or disposal of drilling fluids and drill 
cuttings that do not meet the toxicity limitations,
    * Waste minimization--enhanced solids control to reduce the overall 
volume of drilling fluids and drill cuttings, and
    * Conservation and recycling/reuse of drilling fluids.

Refer to the Coastal Development Document for a detailed discussion of 
each of these waste management techniques.
    b. Additional Technologies Considered. EPA has evaluated an 
additional method for drilling fluid, drill cuttings, and dewatering 
effluent control and treatment in order to achieve zero discharge: 
namely, grinding and injection of drilling wastes. This process 
involves the grinding of the drilling fluids, drill cuttings, and 
dewatering effluent into a slurry that can be injected into a dedicated 
disposal well. The grinding system consists of a vibrating or rotating 
ball mill which pulverizes the cuttings and creates an injectable 
slurry. This comparatively contemporary technology has been 
successfully demonstrated on the North Slope, and has been used to a 
limited degree on the Gulf Coast. While injection has been demonstrated 
in other parts of the U.S., injection has not been demonstrated in Cook 
Inlet. EPA believes that the ability to inject is related to the 
subsurface conditions of the receiving formations. While the geology of 
the formations in areas other than Cook Inlet have been favorable to 
injection of drilling fluids and drill cuttings, the record indicates 
that geology amenable to grinding and injection does not appear to 
occur throughout Cook Inlet.
    In addition to grinding and injection, EPA has investigated the 
feasibility of onshore disposal for this wastestream. For the coastal 
subcategory drilling activities, in areas other than Cook Inlet, 
current permits require zero discharge of drilling fluids and cuttings 
or, in the case of the North Slope, zero discharge of drilling fluids, 
and drill cuttings except where drill cuttings are reused as a fill 
material. The fill activity is regulated under section 404 of the CWA. 
On-land disposal or downhole injection sites are available in these 
areas and are being utilized to comply with the zero discharge 
requirement.
    With respect to onshore disposal capacity, on-land disposal sites 
are available to two of the Cook Inlet operators. These two operators 
jointly own an oil and gas landfill disposal site on the west side of 
the Inlet. Unfortunately, no on-land oil and gas waste disposal 
facilities are available in Alaska to the other Cook Inlet operators 
who plan to drill after promulgation of this rule. Therefore, EPA has 
estimated the costs for disposing of drilling wastes at an on-land oil 
and gas waste disposal site in Oregon.
    Also with regard to zero discharge, EPA received information from 
operators concerned that compliance with zero discharge could 
significantly interfere with drilling operations. EPA has investigated 
the significant logistical difficulties and operational problems 
presented by storing and transporting drilling wastes in the Cook 
Inlet, due to the space constraints, combined with the extensive tidal 
fluctuations, strong currents, and ice formation during winter months. 
Also, EPA has taken into consideration supplementary costs incurred by 
additional winter transportation and storage of drilling wastes in its 
cost evaluation of the zero discharge option as described below.
    In addition to zero discharge, EPA considered allowing the 
discharge of the drilling fluids, drill cuttings, and dewatering 
effluent in Cook Inlet providing the discharge met certain limitations. 
These limitations would prohibit the discharge of diesel oil and free 
oil using the static sheen test, limit cadmium and mercury in the stock 
barite used in fluid compositions, and

[[Page 66095]]

limit toxicity at either 30,000 ppm (SPP) or a more stringent toxicity 
in range of 100,000 ppm (SPP) to 1 million ppm (SPP). (The measure of 
toxicity is a 96 hour test that estimates the concentration of 
suspended particulate phase (SPP) from a drilling fluid that is lethal 
to 50 percent of the tested organisms. See 40 CFR part 435, subpart A, 
appendix 2). Drilling fluids and drill cuttings not meeting these 
limitations would not be allowed to be discharged, and therefore, would 
have to be injected or sent to shore for disposal.
    As discussed above, one option at proposal would have retained the 
offshore limitations but required a more stringent toxicity limit. At 
proposal, EPA based the more stringent toxicity limitations, in part, 
on the volume of drilling wastes that could be injected or disposed of 
onshore without interfering with ongoing drilling operations. The more 
stringent toxicity limit would have been based on (1) the volume of 
drilling wastes that could be subjected to zero discharge without 
interfering with ongoing drilling operations and (2) a specified level 
of toxicity selected such that no more than this volume of waste, 
determined in the previous step, would exceed the specified level of 
toxicity. However, as pointed out in comments on the proposal and 
confirmed with further investigation, there are a number of problems 
with the database that would be used to establish a more stringent 
toxicity limitation. Many of the records in the database do not have 
either a waste volume identified or indicate whether the drilling 
fluids were discharged. Where waste volumes are reported, the methods 
used to determine these volumes are not consistent and they are not 
documented. It is also unclear whether the volumes and fluid systems 
reported for any given well represent a complete record of the drilling 
activity associated with the well. For these reasons, EPA rejected the 
option of developing a more stringent toxicity limitation for the final 
rule.
4. BAT and NSPS Options
    For final consideration, EPA developed two options for the BAT and 
NSPS level of control for drilling fluids and drill cuttings. 
Limitations for the dewatering effluent are the same as those for 
drilling fluids and drill cuttings.
    Option 1 would require zero discharge of drilling fluids, drill 
cuttings, and dewatering effluent for all coastal drilling operations 
except those located in Cook Inlet. Allowable discharge limitations for 
drilling fluids and cuttings in Cook Inlet would require compliance 
with a toxicity value of no less than 30,000 ppm (SPP); no discharge of 
free oil (as determined by the static sheen test); no discharge of 
diesel oil and 1 mg/kg of mercury and 3 mg/kg of cadmium in the stock 
barite. Limitations for Cook Inlet are identical to the limitations 
applicable to offshore discharges in Alaska. Option 1 was developed 
taking into consideration that Cook Inlet operations are unique to the 
industry due to a combination of geology available for grinding and 
injection, climate, transportation logistics, and structural and space 
limitations that interfere with drilling operations.
    Option 2 would prohibit the discharge of drilling fluids, drill 
cuttings, and dewatering effluent from all coastal oil and gas drilling 
operations. In Cook Inlet, this option uses onshore disposal as a basis 
for complying with zero discharge of drilling fluids and drill 
cuttings. Outside of Cook Inlet, this option uses a combination of 
grinding and injection and onshore disposal as a basis for complying 
with zero discharge of drilling fluids and drill cuttings.
    a. Costs. Operators would not incur any costs under Option 1 
because the requirements reflect current practice.
    Costs to comply with Option 2 (zero discharge all) are attributed 
only to Cook Inlet operators (North Slope operators are beneficially 
reusing a portion of their drill cuttings and all other coastal 
operators are already practicing zero discharge). Costs to comply with 
this option are estimated to be approximately $8,200,000 annually for 
the Cook Inlet operators. The basis for this cost analysis is that 
drilling fluids and drill cuttings generated in Cook Inlet would be 
hauled to shore for disposal. Costs for land disposal include water 
vessel transportation, storage prior to transport to the disposal 
facility, truck transportation to the disposal facility, and landfill 
disposal costs. While it was evaluated, grinding and injection is not 
used in the cost basis for Cook Inlet because, as mentioned earlier, 
geology amenable to grinding and injection does not appear to occur 
throughout Cook Inlet.
    To determine the volume of drilling wastes requiring disposal, EPA 
obtained the projected drilling schedules for the Cook Inlet operators 
using information from the 1993 Coastal Oil and Gas Questionnaire and 
contacts with industry. Using information about the volume of drilling 
fluids and drill cuttings generated per well, and the projected amount 
of drilling over the seven years following scheduled promulgation, EPA 
estimates that the total amount of drilling fluids and drill cuttings 
annually generated from these drilling operations will be approximately 
89,000 barrels.
    EPA also considered the logistical difficulties of transporting 
drilling wastes in Cook Inlet as part of EPA's costing analysis of the 
options. To achieve zero discharge, platforms would transport drilling 
wastes to the eastern side of Cook Inlet by supply boat, then: (1) 
Transfer the wastes to barges for transport to an existing landfill 
facility on the west side of the Inlet or (2) load these wastes onto 
trucks for transport to landfill disposal in Oregon. During periods of 
extensive ice floes, the drilling wastes are stored on the east side of 
the Inlet for extended periods of time.
    For new sources, EPA expects that the costs of complying with NSPS 
would be equal to or less than those for existing sources. Note that, 
due to the high cost of installing new sources and the low expectation 
of return, EPA does not expect new sources to be installed in Cook 
Inlet independent of any new environmental regulations.
    EPA also analyzed non-water quality environmental impacts for BAT 
and NSPS. These impacts are discussed in Section IX of the preamble.
    b. BAT and NSPS Option Selection. For both BAT and NSPS control of 
drilling fluids, drill cuttings and dewatering effluent, EPA is 
establishing zero discharge limitations, except for Cook Inlet. In Cook 
Inlet, discharge limitations include no discharge of free oil, no 
discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg cadmium 
limitations on the stock barite, and a toxicity limitation of 30,000 
ppm SPP. BAT limitations for dewatering effluent are applicable 
prospectively. BAT limitations in this rule are not applicable to 
discharges of dewatering effluent from reserve pits which as of the 
effective date of this rule no longer receive drilling fluids and drill 
cuttings. Limitations on such discharges shall be determined by the 
NPDES permit issuing authority.
    With regard to coastal facilities outside of Cook Inlet, zero 
discharge is technically and economically achievable and has acceptable 
non-water quality environmental impacts because it reflects current 
industry practices under existing permit requirements.
    With regard to coastal facilities in Cook Inlet, EPA rejected zero 
discharge in large part because the technology of grinding and 
injection has not been demonstrated to be available throughout Cook 
Inlet. Drilling fluids and drill cuttings cannot be injected into 
producing formations, as is sometimes the case for produced water, 
because

[[Page 66096]]

they would interfere with hydrocarbon recovery. Thus, operators must 
have available different formation zones with appropriate 
characteristics (e.g., porosity and permeability) for injection of 
drilling fluids and drill cuttings. See the Coastal Development 
Document for discussion of geologic characteristics for the injection 
of these drilling wastes. Unlike the coastal region along the Gulf of 
Mexico or the North Slope of Alaska, where the subsurface geology is 
relatively porous and formations for injection are readily available, 
the geology in Cook Inlet is highly fragmented and information in the 
record indicates that formations for injection may be not available 
throughout Cook Inlet. EPA reviewed information where attempts to grind 
and inject drilling fluids and drill cuttings failed in the Cook Inlet 
area. For example, one operator attempted to operate a grinding and 
injection well in the Kenai gas field failed due to downhole mechanical 
failure of the injection well (1992/1993). There, the well experienced 
abnormal pressure on the well annulus, necessitating shutdown of the 
disposal operation. The operator also attempted annular pumping of 
drilling fluids and drill cuttings in two production wells in the Ivan 
River Field (onshore on the west side of Cook Inlet) where the annuli 
of both wells plugged during injection. Another operator, attempting to 
pump drilling waste into the annuli of exploration wells, lost the 
integrity of the well.
    Because not all of the drilling fluids and drill cuttings can be 
injected, much of the waste would have to be land disposed. All but two 
of the operators would likely have to transport their drilling fluids 
and drill cuttings to a disposal facility out of state; the two other 
operators privately own the only drilling waste land disposal facility 
near Cook Inlet. (EPA is unaware of any other onshore disposal 
facilities coming into existence, as Cook Inlet is a fairly mature 
field nearing the end of its useful life. All but one of the existing 
platforms were installed in the 1960s. The newest platform began 
production in 1987, but production from the facility has remained well 
below expectations.) Land disposal is a problem for Cook Inlet 
operators, analogous to those faced by offshore operators in Alaska, 
because the climate and safety conditions that exist during parts of 
the year in Cook Inlet make transportation of drilling fluids and drill 
cuttings particularly difficult and hazardous. The harsh climate, snow, 
ice, and poor visibility from fog and snow often restrict land and sea 
transportation. Also, the extensive tidal fluctuations (frequently in 
excess of 30 feet), strong currents, and ice formation during winter 
months in the Inlet impose severe logistical difficulties for storing 
and transporting the drilling wastes. Moreover, the limited storage 
space on platforms and transportation-related difficulties and delays 
associated with a zero discharge limitation for all drilling wastes 
would impose severe operational constraints on drilling activities. 
Thus, for purposes for BAT and NSPS, EPA does not believe that land 
disposal of all drilling wastes is generally available for Cook Inlet 
operators.
    There are non-water quality environmental impacts associated with 
such transportation and land disposal. For BAT, EPA estimates that zero 
discharge would result in 5,200 Barrel of Oil Equivalents (BOE) of fuel 
being used annually, resulting in 36 tons or 72,000 pounds of air 
emissions to move the waste from Cook Inlet to Oregon and sites near 
Cook Inlet. While EPA believes the non-water quality environmental 
impacts--in and of themselves--are not unacceptable, by comparison with 
the operational constraints discussed above and pollutants removed by 
zero discharge, 4,300 pounds of toxic pollutants annually, these non-
water quality environmental impacts weigh against requiring zero 
discharge in Cook Inlet.
    Again, for NSPS control of drilling fluids, drill cuttings, and 
dewatering effluent, EPA is establishing zero discharge limitations, 
except for Cook Inlet. In Cook Inlet, discharge limitations include no 
discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury 
and 3 mg/kg cadmium limitations on the stock barite, and a toxicity 
limitation of 30,000 ppm SPP. Both inside and outside of Cook Inlet, 
these NSPS limitations are technically and economically achievable and 
has acceptable non-water quality environmental impacts because they 
reflect current practice. With regard to the potential for a barrier to 
entry, NSPS are equal to BAT limitations. BAT limitations have been 
demonstrated to be economically achievable for existing structures. 
Design and construction of pollution control equipment on new 
production facilities is generally less expensive than retrofitting 
existing facilities. Therefore, while the NSPS are equal to BAT 
limitations, it is less costly for new structures to meet these 
requirements and these costs would not inhibit development of new 
sources.
5. BCT
    a. BCT Cost Test Methodology. EPA establishes BCT limitations based 
on a methodology which became effective August 22, 1986 (51 FR 24974, 
July 9, 1986). This methodology compares the costs of conventional 
pollutant removal under BCT with the cost of conventional pollutant 
removal at a publicly owned treatment works (POTW). A description of 
this methodology is contained in the preamble to the proposed rule (60 
FR 9428, 9444) and the Coastal Development Document. If all options 
fail either of the two tests, then BCT limitations must be set at a 
level equal to BPT limitations.
    b. BCT Costs Test Calculations and Options Selection. (i) Coastal 
Subcategory Except for Cook Inlet. Because all operators throughout the 
coastal subcategory, except in Cook Inlet, are currently practicing 
zero discharge of drilling fluids and drill cuttings and dewatering 
effluent, zero discharge was the only option considered. There is zero 
cost for this limitation. Thus, EPA determined that zero discharge 
passes the BCT cost tests and is the appropriate BCT limitation for 
this wastestream. BCT limitations for dewatering effluent are 
applicable prospectively. BCT limitations in this rule are not 
applicable to discharges of dewatering effluent from reserve pits which 
as of the effective date of this rule no longer receive drilling fluids 
and drill cuttings. Limitations on such discharges shall be determined 
by the NPDES permit issuing authority.
    (ii) Cook Inlet. EPA considered two BCT options for Cook Inlet: BPT 
limitations (no free oil) or zero discharge. BCT limits in the final 
rule are established equal to BPT. Although zero discharge was 
determined to be not available in Cook Inlet, the BCT cost test was 
calculated to show whether such a limitation would have passed the cost 
test. EPA determined that zero discharge limitations would not have 
passed the BCT cost test. Costs, pollutant reductions, and the results 
of the BCT cost test are presented in detail in the Coastal Development 
Document. BCT limitations for dewatering effluent are applicable 
prospectively. BCT limitations in this rule are not applicable to 
discharges of dewatering effluent from reserve pits which as of the 
effective date of this rule no longer receive drilling fluids and drill 
cuttings. Limitations on such discharges shall be determined by the 
NPDES permit issuing authority.

[[Page 66097]]

6. PSES and PSNS
    Section 307 of the CWA authorizes EPA to develop pretreatment 
standards for existing sources (PSES) and new sources (PSNS). 
Pretreatment standards are designed to prevent the discharge of 
pollutants that pass through, interfere with, or are otherwise 
incompatible with the operation of POTWs. The pretreatment standards 
for existing sources are to be technology based and analogous to the 
best available technology economically achievable (BAT) for direct 
dischargers. The pretreatment standards for new sources are to be 
technology-based and analogous to the best available demonstrated 
control technology used to determine NSPS for direct dischargers. New 
indirect discharging facilities, like new direct discharging 
facilities, have the opportunity to incorporate the best available 
demonstrated technologies, including process changes, and in-plant 
controls, and end-of-pipe treatment technologies. EPA determines which 
pollutants to regulate in PSES and PSNS on the basis of whether or not 
they pass through, interfere with, or are incompatible with the 
operation of POTWs.
    Based on comments, the 1993 Coastal Oil and Gas Questionnaire, and 
other information reviewed as part of this rulemaking, EPA has not 
identified any existing coastal oil and gas facilities which discharge 
drilling fluids, drill cuttings, or dewatering effluent to POTW's, nor 
are any new facilities projected to direct these wastes in such manner. 
However, due to the high solids content of drilling fluids and drill 
cuttings, EPA is establishing pretreatment standards for existing and 
new sources equal to zero discharge because these wastes would 
interfere with POTW operations. For further discussion, see the Coastal 
Development Document. For PSNS, zero discharge would not cause a 
barrier to entry, as further discussed in the Economic Impact Analysis.

B. Produced Water and Treatment, Workover, and Completion Fluids

    At proposal, produced water was discussed and analyzed separately 
from treatment, workover, and completion fluids (TWC). However, EPA 
also proposed that discharge limitations for TWC be set equal to 
discharge limitations for produced water. As stated at that time, based 
on responses to the 1993 Coastal Oil and Gas Questionnaire and EPA's 
Region 10 Discharge Monitoring Reports, the typical industry practice 
is to combine produced water with treatment, workover, and completion 
fluids for purposes of wastewater treatment. Because the treatment 
technologies for these wastestreams are linked, EPA has combined these 
wastestreams in the final rule for purposes of discussion.
1. Waste Characterization
    Produced water is brought to the surface during the oil and gas 
extraction process and can include: formation water extracted along 
with oil and gas; injection water used for secondary oil recovery that 
has broken through the formation and mixed with the extracted 
hydrocarbons; and various well treatment chemicals added during the 
production and oil/water separation processes. Produced water is the 
highest volume waste in the coastal oil and gas industry. Depending on 
the age of a well and site-specific formation characteristics, the 
produced water can constitute between 2 percent and 98 percent of the 
gross fluid production at a particular well. Generally, in the early 
production phase of a well the produced water volume is relatively 
small and the hydrocarbon production makes up the bulk of the fluid. 
Over time, the formation approaches hydrocarbon depletion and the 
produced water volume usually exceeds the hydrocarbon production. Based 
on information received in the 1993 Coastal Oil and Gas Questionnaire, 
the average produced water rate from a well is approximately 1180 
barrels per day (bpd) in Cook Inlet and 270 bpd in the Gulf Coast. EPA 
estimates under current permit requirements that 119 million barrels 
per year (bpy) of produced water are discharged to surface waters by 
the coastal oil and gas industry.
    As part of this rulemaking, EPA has embarked upon a systematic 
effluent sampling program to identify and quantify the pollutants 
present in produced water, with an emphasis toward the identification 
of listed toxic pollutants. Details of EPA's data collection activities 
are presented in the Coastal Development Document. The information 
collected has confirmed the presence of a number of organic and metal 
toxic pollutants in produced water.
    Pollutants contained in produced water discharges from facilities 
in the coastal oil and gas industry with treatment systems able to meet 
BPT permit limits were identified as part of EPA's sampling effort. A 
summary of the data from these sampling activities is contained in the 
Coastal Development Document. EPA's sampling data and the industry-
supplied Cook Inlet Study identified many organic toxic pollutants and 
12 of the 13 metal toxic pollutants as being present in BPT treated 
discharges of produced water following some treatment for oil and 
grease (oil) removal. The toxic organics most often present in 
significant amounts were benzene, naphthalene, phenol, toluene, and 
ethylbenzene. In addition to the toxic pollutants, EPA identified total 
suspended solids, oil and grease, and a number of nonconventional 
pollutants including barium, chlorides, ammonia, magnesium, strontium 
and iron present in produced water.
    TWC fluids are primarily generated during production. Well 
treatment and workover fluids are inserted downhole in a producing well 
to increase a well's productivity or to allow safe maintenance of the 
well. Completion fluids are inserted downhole after a well has been 
drilled, and serve to clean the wellbore and maintain pressure prior to 
production. In most operations, these fluids resurface with the 
production fluids once production is initiated and can be reused, 
discharged, or injected in a disposal well.
    According to results obtained in the 1993 Coastal Oil and Gas 
Questionnaire, EPA estimates that approximately 275,000 bbls (205,000 
and 70,000 bpy of treatment/workover and completion fluids 
respectively) of TWC fluids are discharged annually from coastal oil 
and gas operations in Texas and Louisiana under current permit 
requirements.
    The composition of the discharges is highly dependent on the 
fluid's purpose, but they generally consist of acids (in the case of 
treatment) or weighted brines (for workover of completion). The 
principal pollutant in these fluids is oil and grease ranging in 
concentration from 15 to 722 mg/l. Total suspended solids, another 
major constituent in these fluids, is present in concentrations ranging 
from 65 to 1600 mg/l. Prominent toxic metals that exist in these wastes 
include chromium, copper, lead, and zinc. Priority organics are also 
present including acetone, benzene, ethylbenzene, xylene, toluene, and 
naphthalene.
    Under current permit requirements, EPA estimates that approximately 
314,000 pounds of priority pollutants and 3,700,000 pounds of 
conventional pollutants are being discharged annually into the coastal 
subcategory. In addition, approximately 2.55 million pounds of 
nonconventionals are being discharged including boron, calcium, cobalt, 
iron, manganese, molybdenum, tin, vanadium, and yttrium.
2. Selection of Pollutant Parameters
    a. Pollutants Regulated. Where zero discharge is required, all 
pollutants

[[Page 66098]]

found in produced water and treatment, workover, and completion fluid 
discharges are controlled. Where discharges are allowed, i.e., Cook 
Inlet, EPA is regulating oil and grease under BAT as an indicator 
pollutant controlling the discharge of toxic and nonconventional 
pollutants. Operationally, oil and grease is measured by EPA's method 
for Total Oil and Grease. Oil and grease is limited for produced water 
under BCT as a conventional pollutant. BCT limits for treatment, 
workover, and completion fluids prohibit the discharge of ``free oil'' 
as a surrogate for control over the conventional pollutant ``oil and 
grease.'' No discharge of ``free oil'' is determined by the static 
sheen test. EPA is prohibiting discharge of ``free oil'' as a surrogate 
for control over the conventional pollutant ``oil and grease'' in 
recognition of the complex nature of the oils present in drilling 
fluids, including crude oil from the formation being drilled. Oil and 
grease is limited under NSPS as both a conventional pollutant and as an 
indicator pollutant controlling the discharge of toxic and 
nonconventional pollutants.
    It has been shown (see the Coastal Development Document) that oil 
and grease serves as an indicator for toxic pollutants in the produced 
water wastestream, including phenol, naphthalene, ethylbenzene, and 
toluene. During its development of the Offshore Guidelines, EPA showed 
that gas flotation technology (the technology basis for the oil and 
grease limitations) removes both metals and organic compounds, 
resulting in lower concentration levels in the discharge for the above 
toxic pollutants (see Section IX of the Offshore Development Document).
    b. Pollutants Not Regulated. For Cook Inlet, EPA evaluated the 
feasibility of regulating separately each of the constituents present 
in produced water and treatment, workover, and completion fluids during 
the development of the Offshore Guidelines. Based on that analysis, EPA 
determined for the Coastal Guidelines that it is not feasible to 
regulate each pollutant individually for reasons that include the 
following: (1) The variable nature of the number of constituents in the 
produced water and treatment, workover, and completion fluids, (2) the 
impracticality of measuring a large number of analytes, many of them at 
or just above trace levels, (3) use of technologies for removal of oil 
which are effective in removing many of the specific pollutants, and 
(4) many of the organic pollutants are directly associated with oil and 
grease because they are constituents of oil, and thus, are directly 
controlled by the oil and grease limitation. See the Coastal 
Development Document for more details.
3. Control and Treatment Technologies
    a. Current Practice. With regards to produced water, information 
collected by EPA through the 1993 Coastal Oil and Gas Questionnaire as 
well as industry contacts indicate that no coastal oil and gas 
facilities are discharging in Alabama, Alaska's North Slope, 
California, Florida, or Mississippi. This is due to a combination of 
factors including operational preference, waterflooding, and/or state 
and federal requirements. The Louisiana Department of Environmental 
Quality issued regulations in 1992 (LAC:33, IX, 7.708) which prohibit 
discharges of produced water to fresh water areas characterized as 
``upland'' after July 1, 1992. The Louisiana regulation defines 
``upland'' as ``any land not normally inundated with water and that 
would not, under normal circumstances, be characterized as swamp of 
fresh, intermediate, brackish or saline marsh''. The regulation does, 
however, allow discharges of produced water to a major deltaic pass of 
the Mississippi River or to the Atchafalaya River below Morgan City. 
The same regulation also requires that discharges inland of the inner 
boundary of the Territorial Seas into intermediate, brackish or saline 
waters must either cease discharges or comply with a specific set of 
effluent limitations. These requirements must be met within a certain 
time frame, as required in the regulations, but, no later than January 
1997.
    In addition, EPA issued general NPDES permits (60 FR 2387, January 
9, 1995) for production wastes that prohibit discharges of produced 
water in coastal areas of Texas and Louisiana. The permits do not, 
however, apply to produced water derived from the offshore subcategory 
which is discharged into a main pass of the Mississippi River or 
Atchafalaya River below Morgan City. Along with the general permits, 
EPA issued an Administrative Order allowing until January 1997 to 
comply with the zero discharge requirement. Thus, although many coastal 
oil and gas operators are currently discharging produced water, current 
permit requirements and administrative orders indicate that the only 
facilities projected to be discharging by January 1997 would be those 
in Cook Inlet, Alaska, and six facilities discharging to a major 
deltaic pass of the Mississippi River.
    Subsequent to EPA's issuance of the final coastal production 
permits, 82 facilities (as of the date of this writing) in Texas have 
applied to EPA Region 6 for individual NPDES permits authorizing 
discharge of produced water. Additionally, the U.S. Department of 
Energy has provided the State of Louisiana with comments and analyses 
suggesting a change in the Louisiana state law requiring zero discharge 
of produced water to open bays by January 1997.
    The current BPT regulations established for the coastal subcategory 
limit the oil and grease content in the discharged produced water. 
Existing technologies for the removal of oil and grease include gravity 
separation, gas flotation, heat and/or chemical addition to assist oil-
water separation, and filtration. Methods for the discharge or disposal 
of produced water from facilities in the coastal subcategory include 
free fall discharge to surface waters, discharge below the water 
surface, use of channels to convey the discharge to water bodies, and 
injection via regulated Class II Underground Injection Control (UIC) 
wells into underground formations. As an alternative, a number of 
production sites transport produced water by pipeline, truck or barge 
to shore facilities for disposal in UIC Class II wells. At times, this 
transport consists of the gross fluid produced and the oil-water 
separation takes place at the off-site facility.
    While sampling data has indicated quantifiable reductions of 
naphthalene, lead, and ethylbenzene by BPT treatment (i.e., by oil-
water separation technology), this data also demonstrates the presence 
of significant levels of toxic pollutants remaining in the treated 
effluent.
    With regard to treatment, workover, and completion fluids, current 
requirements for the control of discharges from these fluids include 
BPT limitations prohibiting free oil. EPA's final general permits 
applicable to discharges from coastal oil and gas drilling operations 
in Texas and Louisiana further prohibit discharges of treatment, 
workover and completion fluids to freshwater areas. Methods for 
treatment and discharge or disposal include:
    * Treatment and disposal along with the produced water
    * Neutralization for pH control and discharge to surface waters
    * Onshore disposal and/or treatment and discharge in coastal or 
offshore areas.
    In addition, these fluids may in some cases be reused.
    b. Additional Technologies.

[[Page 66099]]

    In developing the regulation, EPA evaluated several treatment 
technologies for application to the produced water and treatment, 
workover, and completion fluid wastestreams. These technologies were 
considered for implementation at the coastal production sites and at 
the shore facilities where much of the produced water is currently 
treated for subsequent discharge to coastal subcategory waters.
    (1) Improved Gas Flotation.
    Gas flotation is a treatment process that separates low-density 
solids and/or liquid particles (e.g., oil and grease) from liquid 
(e.g., water) by introducing small gas (usually air) bubbles into 
wastewater. As minute gas bubbles are released into the wastewater, 
suspended solids or liquid particles are captured by these bubbles, 
causing them to rise to the surface where they are skimmed off.
    EPA considered as an option using gas flotation technology with 
chemical addition as a basis for improving BPT-level performance. This 
option would require all coastal discharges of produced water to comply 
with oil and grease limitations of 29 mg/l monthly average and a daily 
maximum of 42 mg/l. The technology basis for these limitations is 
improved operating performance of gas flotation technology. EPA has 
determined that gas flotation systems could be improved to increase 
removal efficiencies--i.e., the amount of pollutants removed. Specific 
mechanisms include proper sizing of the gas flotation unit to improve 
hydraulic loading (water flow rate through the equipment), adjustment 
and closer monitoring of engineering parameters such as recycle rate 
and shear forces that can affect oil droplet size (the smaller the oil 
droplet, the more difficult the removal), additional maintenance of 
process equipment, and the addition of chemicals to the gas flotation 
unit. (See Offshore Development Document Section IX.)
    The addition of chemicals can be a particularly effective means of 
increasing the amount of pollutants removed. Because the performance of 
gas flotation is highly dependent on ``bubble-particle interaction,'' 
chemicals that enhance that interaction will increase pollutant 
removal.
    Gas flotation is a technology which has been used for many years in 
treating produced water. This technology formed the basis for the BPT 
regulations EPA promulgated in 1979. In developing final effluent 
limitations guidelines and standards for the offshore subcategory (58 
FR 12454; March 4, 1993), EPA evaluated comments and data submitted by 
the industry which strongly urged EPA to select improved gas flotation 
technology as the basis for BAT limits and NSPS, based on data 
presented by the Offshore Operators Committee's (OOC's) 83 Platform 
Composite Study. Industry further noted that chemical additives would 
improve the amount of oil and grease in produced water that could be 
removed. EPA thoroughly reviewed these comments and additional data, 
and agreed with industry that improved gas flotation was the 
appropriate technology for setting BAT limits and NSPS in the offshore 
subcategory.
    In establishing BAT limits and NSPS for produced water in the 
Offshore Subcategory, EPA evaluated the effluent data from the 
platforms in the 83 Platform Composite Study identified as using 
improved gas flotation (e.g., use of gravity separators and chemical 
additives). First, EPA modeled the offshore platform with ``median'' 
oil and grease effluent values--i.e., 50 percent of the platforms in 
the database had oil and grease effluent values above (and 50 percent 
below) the median of the effluent values measured at the median 
platform. Based on the oil and grease measured at the median platform 
after improved gas flotation treatment, and allowing for average 
``within-platform'' variability, EPA set a daily maximum limit on oil 
and grease at 42 mg/l, and a 30-day average of 29 mg/l as the BAT 
limits and NSPS. (See 58 FR 12462, March 4, 1993.)
    Since there are fewer operational constraints for coastal 
facilities than there are for offshore facilities, the BAT and NSPS 
limitations developed for the offshore subcategory, based on improved 
gas flotation technology, are technologically achievable in the coastal 
subcategory.
    (2) Injection. EPA also considered using injection technology as a 
basis for setting a zero discharge requirement under this rule. With 
the exception of Cook Inlet, injection of produced water is widely 
practiced by facilities in the coastal subcategory. Independent of this 
rule, all coastal facilities in Alabama, California, Florida, and the 
North Slope of Alaska are currently practicing zero discharge and, as 
of January 1, 1997, EPA estimates that at least 80% to 99.9% of all 
coastal facilities in Louisiana and Texas will be practicing zero 
discharge. The 80% estimate is based on subtracting the sum of the 6 
facilities discharging into a major deltic pass of the Mississippi, the 
82 facilities discharging to Louisiana open bays, and the 82 facilities 
associated with individual permit applicants in Texas from the 853 
total coastal facilities estimated to exist along the Gulf of Mexico. 
The 99.9% estimate is based on subtracting the number of facilities 
discharging into a major deltic pass of the Mississippi from the total 
number coastal facilities along the Gulf of Mexico. Additionally, using 
a combination of Coastal Survey information and counts of facilities 
known to be discharging, EPA estimated that 62% of coastal facilities 
along the Gulf of Mexico were practicing zero discharge in 1994. For 
the onshore subcategory, injection is the predominant technology used 
to comply with the zero discharge 1979 BPT limitation. Injection 
technology for produced water consists of injecting produced water, 
under pressure, into Class II UIC wells into underground formations. 
This option results in no discharge of produced water to surface 
waters.
4. Other Technologies
    Other technologies considered but rejected are discussed in the 
Coastal Development Document.
5. Options Considered
    EPA considered several options in developing BCT, BAT, NSPS, PSES 
and PSNS limitations for discharges of produced water and treatment, 
workover, and completion fluids by coastal facilities or in coastal 
locations. The bases for these options were gas flotation, improved gas 
flotation, injection, or a combination of injection and improved gas 
flotation. As proposed, implementation of limitations on discharges of 
offshore wastes into the coastal subcategory is accomplished by the 
addition of language describing the applicability of subcategory 
limitations when crossing subcategory boundaries and modification of 
the applicability language for the offshore subcategory. Limitations 
for the Agricultural and Wildlife Water Use Subcategory and the 
reserved status of the Stripper Subcategory are not affected by changes 
in the applicability language.
    The three options selected for final consideration in developing 
BAT and NSPS for control of produced water are listed below with 
limitations associated with the options allowing discharges:

    Option 1--(Zero Discharge; Except Major Deltaic Pass and Cook 
Inlet Based On Improved Gas Flotation): With the exception of 
facilities in Cook Inlet and facilities discharging offshore 
produced water into the coastal subcategory waters of a major 
deltaic pass of the Mississippi River or the Atchafalaya River below 
Morgan City, all coastal oil and gas facilities and all facilities 
discharging offshore produced water into coastal locations would be 
prohibited from discharging produced water and treatment, workover, 
and completion fluids. Coastal facilities in Cook Inlet and 
facilities

[[Page 66100]]

discharging offshore produced water into a major deltaic pass would 
be required to comply with oil and grease limitations of 29 mg/l 
monthly average and 42 mg/l daily maximum based on improved 
performance of gas flotation.
    Option 2--(Zero Discharge; Except Cook Inlet Based On Improved 
Gas Flotation): With the exception of coastal facilities in Cook 
Inlet, all coastal oil and gas facilities would be prohibited from 
discharging produced water and treatment, workover, and completion 
fluids. Discharges of offshore produced water and treatment, 
workover, and completion fluids would be prohibited when the wastes 
are disposed in coastal locations. Coastal facilities in Cook Inlet 
would be required to comply with oil and grease limitations of 29 
mg/l monthly average and 42 mg/l daily maximum based on improved 
performance of gas flotation.
    Option 3--(Zero Discharge All): For all coastal facilities, this 
option would prohibit discharges of produced water and treatment, 
workover, and completion fluids based on injection. Further, 
discharges of offshore produced water and treatment, workover, and 
completion fluids would be prohibited in coastal locations.

    For BCT, BPT and currently applicable permit limitations were 
considered in addition to the three previously mentioned options for 
BAT and NSPS. For produced water, BPT limitations include limitations 
on oil and grease of 48 mg/l for Monthly Average and 72 mg/l for Daily 
Maximum. For treatment, workover, and completion fluids, BPT 
limitations include no discharge of free oil and current permits, where 
applicable, prohibit the discharge of these fluids into fresh waters of 
Texas and Louisiana.
    For PSES and PSNS, the only option considered is zero discharge.
    With regard to options presented at proposal: (1) Options for 
treatment, workover, and completion fluids have been incorporated into 
the options for produced water and (2) one option was added. The option 
that considers allowing the discharge of offshore produced water into a 
major deltaic pass of the Mississippi River was included in response to 
comments. In response to comments, specific alternatives have been 
developed and examined carefully for facilities currently discharging 
offshore produced water into a major deltaic pass of the Mississippi 
River or the Atchafalaya River below Morgan City. EPA has identified 
six facilities with eight outfalls discharging offshore produced water 
into a major deltaic pass of the Mississippi River and no facilities 
discharging offshore produced water into the Atchafalaya River below 
Morgan City.
    The specific alternatives discussed above have been developed for 
Cook Inlet to account for the different operational practices, 
geological situations, and economic considerations that exist in Cook 
Inlet.
4. BAT and NSPS Options
    EPA is selecting ``Option 2--Zero discharge; Except Cook Inlet 
Based On Improved Gas Flotation'' for the BAT and NSPS level of control 
for produced water.
    a. Rationale for Selection of BAT
    (1) Coastal Subcategory (except Cook Inlet)
    EPA is establishing zero discharge as BAT for the coastal 
subcategory (except for Cook Inlet) because it is technically 
available, economically achievable and reflects the appropriate level 
of BAT control.
    Zero discharge of produced water is technically available. Zero 
Discharge of produced water has been required of onshore facilities 
since EPA promulgated BPT regulations for the onshore subcategory of 
the oil and gas industry in 1979. 40 CFR part 435, subpart C (44 FR 
22069; April 13, 1979). With the exception of Cook Inlet, injection of 
produced water is widely practiced by facilities in the coastal 
subcategory. Independent of this rule, all coastal facilities in 
Alabama, California, Florida, and the North Slope of Alaska are 
currently practicing zero discharge and, as of January 1, 1997, EPA 
estimates that at least 80% to 99.9% of all coastal facilities in 
Louisiana and Texas will be practicing zero discharge. The 80% estimate 
is based on subtracting the sum of the 6 facilities discharging into a 
major deltic pass of the Mississippi, the 82 facilities discharging to 
Louisiana open bays, and the 82 facilities associated with individual 
permit applicants in Texas from the 853 total coastal facilities 
estimated to exist along the Gulf of Mexico. The 99.9% estimate is 
based on subtracting the number of facilities discharging into a major 
deltic pass of the Mississippi from the total number of coastal 
facilities along the Gulf of Mexico. Additionally, using a combination 
of Coastal Survey information and counts of facilities known to be 
discharging, EPA estimated that 62% of coastal facilities along the 
Gulf of Mexico were practicing zero discharge in 1994. Some coastal 
operators have voluntarily upgraded to zero discharge technologies 
while other coastal operators have been subject to consent decrees 
requiring zero discharge in citizen suits filed by environmental 
groups. Zero discharge is available to coastal facilities in the Gulf 
of Mexico region because formations appropriate for injection are 
available.
    In response to comments that operators discharging offshore 
produced water into a major deltaic pass of the Mississippi should not 
be subject to zero discharge, EPA closely examined these facilities. 
However, EPA has identified no basis for providing these facilities 
with limitations other than those established for the coastal 
subcategory outside of Cook Inlet. Injection has been widely 
demonstrated in practice as available to coastal facilities in states 
along the Gulf Coast, including facilities discharging coastal produced 
water that are near these facilities discharging offshore produced 
water.
    Zero discharge for the coastal subcategory, except Cook Inlet, is 
economically achievable. As discussed below, EPA conducted the economic 
analysis under two baselines, the current regulatory requirements 
baseline and an alternative baseline. Under the current requirements 
baseline, the only facilities outside of Cook Inlet that are incurring 
costs as a result of this rule are those discharging wastes from the 
offshore subcategory into a ``major deltaic pass.'' Under the 
alternative baseline, facilities outside of Cook Inlet that are 
incurring costs as a result of this rule includes those discharging 
wastes from the offshore subcategory into a ``major deltaic pass,'' 
individual permit applicants in Texas, and Louisiana open bay 
dischargers.
    No closures are projected for the six facilities discharging to a 
major deltaic pass. Major pass facilities incur costs and impacts under 
both the current requirements and the alternative baselines. For major 
pass operations, the lifetime production loss is expected to be up to 
3.4 million total BOE, which is 0.6 percent of estimated lifetime 
production from these facilities. While these losses may be significant 
for these dischargers, in context of the coastal subcategory as a 
whole, this production loss represents 0.3 percent of the coastal 
production along the Gulf of Mexico. Employment losses in both Cook 
Inlet and along the Gulf Coast are acceptable, see section VIII. 
Considering this small percentage loss of BOE and profitability, 
coupled with the determination of no closures, EPA believes that zero 
discharge is economically achievable under the CWA.
    For individual permit applicants in Texas and Louisiana open bay 
dischargers, a total of up to 94 wells may be first year shut-ins under 
zero discharge. Individual permit applicants in Texas and Louisiana 
open bay dischargers are considered to have financial impacts only 
under the alternative baseline. These wells are

[[Page 66101]]

approximately 2 percent of all Gulf of Mexico coastal wells. EPA 
estimates related production losses would be approximately 12.8 million 
BOE. This represents less than one percent of all Gulf coastal 
production, most of which is in compliance with zero discharge 
requirements. A maximum of 1 firm among the Louisiana open bay 
dischargers and 3 firms among the individual permit applicants from 
Texas could fail as a result of the proposed regulatory options. 
However, EPA's modeling tends to overestimate economic impacts and firm 
failures, since these models project that some currently operating 
firms have already failed. These potential failures represent less than 
one percent of all Gulf of Mexico coastal firms. EPA also did a 
facility level analysis, conducted in response to facility-level 
information received from Texas very late in the rulemaking, that shows 
fewer wells are baseline failures and fewer wells fail due to the costs 
of this rule because wells combine efforts for treatment and 
production. EPA views the small percentage loss of BOE and 
profitability, coupled with the determination of a small number of firm 
closures, to meet the definition of economic achievability under the 
CWA.
    The non-water quality environmental impacts of zero discharge, 
discussed in section IX, are acceptable.
    (2) Cook Inlet
    EPA is establishing BAT limitations based on improved gas 
flotation, rather than zero discharge. EPA rejects zero discharge of 
produced water because zero discharge is not economically achievable in 
Cook Inlet.
    EPA considered Cook Inlet separately from other areas in the 
coastal subcategory because Cook Inlet is geographically isolated from 
other areas in the coastal subcategory, zero discharge of produced 
water would have disproportionately adverse economic impact in Cook 
Inlet.
    Unlike states along the Gulf Coast, only the production formation 
is generally available for injection of produced water. Because of 
this, zero discharge would require the additional costs associated with 
piping produced water from existing production facilities to existing 
waterflood injection sites.
    EPA's economic analysis shows a disproportionate impact of zero 
discharge on Cook Inlet as compared with the rest of the coastal 
subcategory. EPA projects that zero discharge requirements for Cook 
Inlet would close 1 of the 13 existing production platforms and result 
in the loss of 108 jobs in the oil and gas industry in Cook Inlet. In 
addition, there are severe economic impacts on two additional platforms 
that were projected to fail at proposal. These disproportionate impacts 
are demonstrated by a loss in net present value in Cook Inlet of 18.5 
percent as compared to only 1.4 percent in the Gulf coast under the 
current requirements baseline. In addition, there are disproportionate 
impacts in Cook Inlet with regard to employment, where Cook Inlet 
already suffers from unemployment higher than the national average and 
higher than the rest of the coastal subcategory. The most recently 
reported (1991) unemployment rate in Cook Inlet is 12.7 percent, as 
compared with the unemployment rate in the Gulf coast of 6.2 to 6.4 
percent and the national unemployment rate of about 5.2 percent). The 
loss of 108 jobs that would occur in Cook Inlet from zero discharge 
would raise the unemployment level in Cook Inlet 0.5 percent, to 13.2 
percent. Thus, zero discharge would worsen the serious unemployment 
situation that exists in Cook Inlet. Because Cook Inlet is economically 
and geographically isolated and the economic effects of zero discharge 
in Cook Inlet are significant and disproportionately worse than they 
are in the rest of the subcategory, EPA rejects zero discharge in Cook 
Inlet as not economically achievable.
    Limitations based on improved gas flotation are technically and 
economically achievable for Cook Inlet facilities. These limitations 
are a Daily Maximum of 42 mg/l and a Monthly Average of 29 mg/l for oil 
and grease. Improved gas flotation technology has been demonstrated in 
the offshore subcategory where the wastestreams and physical 
constraints are similar. No platform closures are expected as a result 
of establishing these limitations. EPA expects the production loss over 
the productive lifetime of these platforms to be approximately 2.4 
million BOE, which is 0.5 percent of the estimated lifetime production 
for the Inlet.
    The non-water quality environmental impacts of these limitations, 
discussed in section IX, are acceptable.
    (3) Pollutant Reductions for the Selected Option
    Assuming the current regulatory requirements baseline, the selected 
BAT option for produced water and treatment, workover, and completion 
fluids is expected to reduce discharges of conventional pollutants by 
2,780,000 lbs. per year, nonconventional pollutants by 1,490,000,000 
lbs. per year, and toxic pollutants by 228,000 lbs. per year.
    Assuming the alternative baseline, the selected BAT option for 
produced water and treatment, workover, and completion fluids is 
expected to reduce discharges of conventional pollutants by 11,300,000 
lbs. per year, nonconventional pollutants by 4,590,000,000 lbs. per 
year, and toxic pollutants by 880,000 lbs. per year.
    b. Rationale for Selection of NSPS
    For NSPS control of produced water and treatment, workover, and 
completion fluid discharges from new sources, EPA is establishing the 
limitations associated with ``Option 2--Zero Discharge; Except Cook 
Inlet Based On Improved Gas Flotation.'' Option 2 is economically 
achievable for the reasons discussed in the economic impact analysis 
and in Section VIII, below. The selected option for NSPS is equal to 
the selected BAT option for produced water and treatment, workover, and 
completion fluids. The BAT option has been demonstrated to be 
technologically available and economically achievable for existing 
structures. Design and construction of pollution control equipment on 
new production facilities is generally less expensive than retrofitting 
existing facilities. Therefore, while the NSPS requirements are equal 
to the BAT requirement, it is less costly for new structures to meet 
these requirements and these costs would not inhibit development of new 
sources.
    In addition, as discussed in Section IX, EPA has determined the 
non-water quality environmental impacts to be acceptable for the 
selected NSPS option for produced water and treatment, workover, and 
completion fluids.
    Zero discharge for Cook Inlet is rejected because of uncertainties 
regarding the availability of geologic formations suitable for 
receiving injected produced water. Information in the record indicates 
that a potential new source in Cook Inlet could be unable to inject 
adequate produced water volumes near the new source. As a result, the 
new source would be faced with piping the produced water to a location 
where suitable geology would be available. Based on information 
available in the record, EPA projects that no new sources will be 
developed in Cook Inlet. Nevertheless, EPA assessed the costs and 
economic impacts incurred by a model new source facility under the zero 
discharge scenario should conditions and future information lead to 
development of new sources in Cook Inlet. For the modeled scenario, EPA 
based costs on injecting produced water near the new source facility. 
However, because of the uncertainties regarding availability of 
formations suitable for injection, it is possible that a new source 
structure would incur some

[[Page 66102]]

unknown cost for piping the produced water to a suitable injection 
location. Since the location and availability of formations for any new 
source in Cook Inlet are unknown, the maximum cost associated with 
piping produced water from the wellhead to the nearest injection well 
cannot be estimated.
5. BCT Methodology and Options Selection
    The methodology to determine the appropriate technology option for 
BCT limitations is previously described in the proposal and the Coastal 
Development Document.
    EPA evaluated the options listed in section VII.B.5 according to 
the BCT cost reasonableness tests. The pollutant parameters used in 
this analysis were total suspended solids and oil and grease. All 
options fail the BCT cost reasonableness test. Thus, EPA establishes 
BCT limitations for produced water equal to BPT. Limitations for 
treatment, workover, and completion fluids are established as zero 
discharge for fresh water in Texas and Louisiana and no free oil 
everywhere else. This option reflects current permit requirements. 
Costs for this option are zero, thus this option passes the BCT cost 
test. A more detailed description of the BCT cost test for produced 
water and treatment, workover, and completion fluids is described in 
the Coastal Development Document. There are no non-water quality 
environmental impacts associated with the BCT limitations because it is 
equal to existing BPT requirements.
6. PSES and PSNS Options Selection
    Based on the 1993 Coastal Oil and Gas Questionnaire and other 
information reviewed as part of this rulemaking, EPA has not identified 
any existing coastal oil and gas facilities which discharge produced 
water or treatment, workover, and completion fluids to POTWs, nor are 
any new facilities projected to direct their produced water discharge 
in such manner. However, because EPA is establishing a limitation 
requiring zero discharge for existing facilities, there is the 
potential that some facilities may consider discharging to POTWs in 
order to circumvent the BAT and/or NSPS limitations. Pretreatment 
standards for produced water and treatment, workover, and completion 
fluids are appropriate because EPA has identified the presence of a 
number of toxic and nonconventional pollutants, many of which are 
incompatible with the biological removal processes at POTWs and would 
result in pass through or interference. Large concentrations of 
dissolved solids in the form of various salts in the produced water 
cause the discharge to POTWs to be incompatible with the biological 
treatment processes because these ``brines'' can be lethal to the 
organisms present in the POTW biological treatment systems. (See the 
Coastal Development Document for detailed information on produced water 
characterization.)
    EPA is establishing pretreatment standards for existing and new 
sources (PSES and PSNS, respectively) that prohibit the discharge of 
produced water and treatment, workover, and completion fluids. Since 
zero discharge to POTWs is the current practice in the coastal oil and 
gas extraction industry, zero discharge is economically and 
technologically achievable for PSES, and has no non-water quality 
environmental impacts. The cost projections for both PSES and PSNS are 
considered to be zero since no existing sources discharge to POTWs and 
there are no known plans for new sources to be installed in locations 
amenable to sewer hookup. Design and construction of pollution control 
equipment on new production facilities is generally less expensive than 
retrofitting existing facilities. Therefore, while the PSNS 
requirements are equal to the PSES requirement, it is less costly for 
new structures to meet these requirements and these costs would not 
inhibit development of new sources. Non-water quality environmental 
impacts would be similar to those for new sources, which EPA has found 
to be acceptable. Thus, EPA has determined that pretreatment standards 
for new sources that are equal to NSPS are economically achievable and 
technologically available for PSNS and that the non-water quality 
environmental impacts are acceptable.

C. Produced Sand

1. Waste Characterization
    Produced sand consists primarily of the slurried particles that 
surface from hydraulic fracturing and the accumulated formation sands 
and other particles (including scale) generated during production. 
Produced sand is generated during oil and gas production by the 
movement of sand particles in producing reservoirs into the wellbore. 
The generation of produced sand usually occurs in reservoirs comprised 
of geologically young, unconsolidated sand formations. The produced 
sand wastestream is considered a solid and consists primarily of sand 
and clay with varying amounts of mineral scale and corrosion products. 
This waste stream may also include sludges generated in the produced 
water treatment system, such as tank bottoms from oil/water separators 
and solids removed in filtration.
    Produced sand is carried from the reservoir to the surface by the 
fluids produced from the well. The well fluids stream consists of 
hydrocarbons (oil or gas), water, and sand. At the surface, the 
production fluids are processed to segregate the specific components. 
The produced sand drops out of the fluids stream during the separation 
process and accumulates at low points in equipment. Produced sand is 
removed primarily during tank cleanouts. Because of its association 
with the hydrocarbon stream during extraction, produced sand is 
generally contaminated with crude oil or gas condensate.
    Additional discussion of produced sand is presented in the Coastal 
Development Document.
2. Selection of Pollutant Parameters
    As proposed, EPA is establishing control of all pollutants present 
in produced sand by prohibiting discharge of this wastestream.
3. Control and Treatment Technologies
    No effluent limitations guidelines have been promulgated for 
discharges of produced sand in the coastal subcategory. The final NPDES 
permits for Texas, Louisiana, and the existing state NPDES permits for 
Alabama contain a zero discharge limit for produced sand.
    Data from the 1993 Coastal Oil and Gas Questionnaire indicate that 
the predominant disposal method for produced sand is landfarming, with 
underground injection, landfilling, and onsite storage also taking 
place to some degree. Because of the cost of sand cleaning, in 
conjunction with the difficulties associated with cleaning some sand 
sufficiently to meet existing permit discharge limitations, operators 
use onshore (onsite or offsite) or downhole disposal. In fact, only one 
operator was identified in the 1993 Coastal Oil and Gas Questionnaire 
as discharging produced sand in the Gulf of Mexico, but this operator 
also stated that it planned to cease its discharge in the near future. 
Cook Inlet operators submitted information stating that no produced 
sand discharges are occurring in this area. No comments on the proposed 
guidelines contained contrary information.
4. Options Considered and Rationale for Options Selection
    EPA has selected zero discharge for control of produced sand. 
Because

[[Page 66103]]

current practice for the coastal subcategory is zero discharge, 
allowing the discharge of produced sand would not represent BAT level 
control. As stated above, EPA's Coastal Oil and Gas Questionnaire 
identified only one discharger of produced sand in the coastal 
subcategory and that discharger reported an intent to cease 
discharging. As stated above, the Region 6 NPDES permits published 
January 9, 1995 prohibit all discharges of produced sand in coastal 
waters of Louisiana and Texas. Because the industry practice is zero 
discharge, the zero discharge limitation will result in no increased 
cost to the industry.
    EPA is establishing BPT, BCT, BAT and NSPS equal to zero discharge 
for produced sand. Zero discharge is established as BPT because it 
reflects the average of the best existing performance by facilities in 
the coastal subcategory. Since BCT is established as equal to BPT, 
there is no cost of BCT incremental to BPT. Therefore, this option 
passes the BCT cost reasonableness tests. EPA has determined that zero 
discharge reflects the BAT level of control because, as it is widely 
practiced throughout the industry, it is both economically achievable 
and technologically available. The selected option for NSPS is equal to 
the selected BAT option for produced sand. Design and construction of 
pollution control equipment on new production facilities is generally 
less expensive than retrofitting existing facilities. Therefore, while 
the NSPS requirements are equal to the BAT requirement, it is less 
costly for new structures to meet these requirements and these costs 
would not inhibit development of new sources. Zero discharge will have 
no economic impacts on the industry. As zero discharge reflects current 
practice, there are no incremental non-water quality environmental 
impacts from this option.
    The technology basis for compliance with PSES and PSNS is the same 
as that for BAT and NSPS. EPA is establishing pretreatment standards 
for produced sands equal to zero discharge because, like drilling 
fluids and drill cuttings, their high solids content would interfere 
with POTW operations. Because EPA is not aware of any coastal operators 
discharging produced sand to POTWs, this requirement is not expected to 
result in operators incurring costs. Zero discharge for PSNS would not 
cause a barrier to entry for the same reasons as discussed above for 
NSPS. There are no additional non-water quality environmental impacts 
associated with this requirement because it reflects current practice.

D. Deck Drainage

1. Waste Characterization
    Deck drainage consists of contaminated site and equipment runoff 
due to storm events and wastewater resulting from spills, drip pans, or 
washdown/cleaning operations, including washwater used to clean working 
areas. Deck drainage is generated during both the drilling and 
production phases of oil and gas operations. Currently, approximately 
11.5 million barrels per year of deck drainage are discharged by 
facilities in the coastal subcategory. EPA estimates that 112,000 
pounds of oil and grease are discharged in this wastestream annually. 
In addition to oil, various other chemicals used in drilling and 
production operations may be present in deck drainage. Limited treated 
effluent data are available for this wastestream, however, EPA has 
identified the presence of organic and metal toxic pollutants in deck 
drainage. EPA's analytical data for deck drainage comes from the data 
acquired during the development of the Offshore Guidelines. EPA 
conducted a three facility sampling program (described in Section V of 
the Offshore Development Document) during which samples were taken of 
untreated deck drainage. Eight of the toxic metals were detected, most 
notably lead (ranging in concentration from 25--352 ug/l) and zinc 
(ranging in concentration from 2970--6980 ug/l). Priority organics were 
also present including benzene, xylene, naphthalene and toluene. Other 
nonconventional pollutants found in deck drainage include aluminum, 
barium, iron, manganese, magnesium and titanium.
    The content and concentrations of pollutants in deck drainage can 
also depend on chemicals used and stored at the oil and gas facility. 
An additional study on deck drainage from Cook Inlet platforms, 
reviewed during development of the Offshore Guidelines and this rule, 
showed that discharges from this wastestream may also include 
paraffins, sodium hydroxide, ethylene glycol, methanol and isopropyl 
alcohol.
2. Selection of Pollutant Parameters
    EPA has selected free oil as the pollutant parameter for control of 
deck drainage. The specific conventional, toxic and nonconventional 
pollutants found to be present in deck drainage are those primarily 
associated with oil, with the conventional pollutant oil and grease 
being the primary constituent. In addition, other chemicals used in the 
drilling and production activities and stored on the structures have 
the potential to be found in deck drainage. EPA believes that an oil 
and grease limitation together with incorporation of site specific Best 
Management Practices, as required under the stormwater program and as 
discussed below, will control the pollutants in this wastestream.
    The specific conventional, toxic, and nonconventional pollutants 
controlled by the prohibition on the discharges of free oil are the 
conventional pollutant oil and grease and the constituents of oil that 
are toxic and nonconventional. Free oil is also an indicator for toxic 
pollutants present in crude oil. These pollutants include benzene, 
toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. EPA has 
determined that it is not technically feasible to control these toxic 
pollutants specifically, and that the limitation on free oil in deck 
drainage reflects control of these toxic pollutants at the BAT and 
BADCT (NSPS) levels.
3. Control and Treatment Technologies
    a. Current Practice. BPT limitations for deck drainage prohibit the 
discharge of free oil. All equipment and deck space exposed to 
stormwater or washwater are surrounded with berms or collars. These 
berms capture the deck drainage where it flows through a drainage 
system leading to a sump tank. Initial oil/water separation takes place 
in the sump tank which is generally located beneath the deck floor or 
underground at land-based operations. Effluent from the sump tank may 
be directed to a skim pile, where additional oil/water separation 
occurs. (The skim pile is essentially a vertical bottomless pipe with 
internal baffles to collect the separated oil.)
    The deck drainage treatment system is a gravity flow process, and 
the treatment tanks generally do not require a power source for 
operation. Thus, deck drainage generated at operations located in 
powerless, remote situations, (such as satellite wellheads) can be 
effectively treated.
    It is sometimes difficult to obtain an appropriate sample of deck 
drainage effluent, due to a submerged location. This precludes the use 
of the static sheen test for this wastestream. Thus, free oil is 
measured by the visual sheen test. Deck drainage treatment is discussed 
in more detail in the Coastal Development Document.
    b. Additional Technologies Considered. At proposal, EPA considered 
commingling deck drainage with produced water or drilling fluids and 
requiring best management practices. Deck drainage could in some 
circumstances be commingled with either produced water or drill fluids 
and

[[Page 66104]]

thus, could become subject to the limitations imposed on these major 
wastestreams. EPA also considered requiring best management practices 
(BMPs) on either a site-specific basis or as part of the Coastal 
Guidelines. However, for the final rule, both of these proposed options 
have been rejected. The commingling of deck drainage with produced 
water or drilling fluids is not a demonstrated technology, as discussed 
below. Promulgating BMPs in this rule would be redundant to the 
requirements of the ``Final National Pollutant Discharge Elimination 
System Storm Water Multi-Sector General Permit for Industrial 
Activities'' (60 FR 50804, September 29, 1995).
    With regard to commingling with produced water, the 1993 Coastal 
Oil and Gas Questionnaire as well as the industry site visits reveal 
that deck drainage is sometimes commingled with produced waters prior 
to discharge or injection. Because of this practice, EPA investigated 
an option requiring capture of the ``first flush'', or most 
contaminated portion of, deck drainage. Depending on whether the deck 
drainage is generated from drilling or production (actual hydrocarbon 
extraction) operations, this first flush would be subject to the same 
limitations as would be imposed on either produced water or drilling 
fluids and drill cuttings based on the assumption that these two 
wastestreams could be commingled.
    EPA has rejected the first flush option for control of deck 
drainage for several reasons primarily relating to whether this option 
is technically available to operators throughout the coastal 
subcategory. Deck drainage is currently captured by drains and flows 
via gravity to separation tanks below the deck floor. However, the 
problems associated with capture and treatment beyond gravity feed, 
power independent systems, are compounded by the possibilities of back-
to-back storms which may cause first flush overflows from an already 
full 500 bbl tank. In addition, tanks the size of 500 barrels are too 
large to be placed under deck floors. Installation of a 500 bbl tank 
would require construction of additional platform space, and the 
installation of large pumps capable of pumping sudden and sometimes 
large flows from a drainage collection system up into the tank. The 
additional deck space would add significantly, especially for water-
based facilities, to the cost of this option. Further, many coastal 
facilities are unmanned and have no power source available to them. 
Deck drainage can be channeled and treated without power under the BPT 
limitations.
    Capturing deck drainage at drilling operations poses additional 
technical difficulties. Drilling operations on land may involve an area 
of approximately 350 square feet. A ring levee is typically excavated 
around the entire perimeter of a drilling operation to contain 
contaminated runoff. This ring levee may have a volume of 6,000 bbls, 
sufficient to contain 500 bbls of the first flush. However, collection 
of these 500 bbls when 6,000 bbls may be present in the ring levee 
would not effectively capture the first flush. Costs to install a 
separate collection system including pumps and tanks, would add 
significantly to the cost of this option.
    While costs are significant, the technological difficulties 
involved with adequately capturing deck drainage at coastal facilities 
are the principal reason why this option was not selected for the final 
rule.
    EPA's final rule does not include best management practices (BMPs) 
for this wastestream. EPA believes that current industry practices, in 
conjunction with the requirements included in the previously mentioned 
general permit for stormwater, are sufficient to minimize the 
introduction of contaminants from this wastestream to the extent 
possible. These stormwater requirements require an oil and gas operator 
to develop and implement a site-specific storm water pollution 
prevention plan consisting of a set of BMPs depending on specific 
sources of pollutants at each site.
4. Options Selection
    For BAT and NSPS, EPA is establishing a limitation of no free oil. 
Since free oil discharges are already prohibited under BPT, there are 
no incremental compliance costs, pollutant removals, or non-water 
quality environmental impacts associated with this control option. 
Since this preferred option limits free oil equal to existing BPT 
standards, it is technologically available and economically achievable.
    EPA is establishing BCT limitations as no free oil. Since ``no free 
oil'' is the BPT limitation, there is no incremental cost and this 
option passes the BCT Cost Tests.
    EPA is establishing PSES and PSNS limits for deck drainage as zero 
discharge. EPA believes that zero discharge for PSES and PSNS is 
appropriate because slugs of deck drainage would be expected to 
interfere with biological treatment processes at POTWs. This is 
discussed further in the Coastal Development Document.

E. Domestic Wastes

    Domestic wastes result from laundries, galleys, showers, and other 
similar activities. Detergents are often part of this wastestream. 
Waste flows may vary from zero for intermittently manned facilities to 
several thousand gallons per day for large facilities.
    The conventional pollutant of concern in domestic waste is floating 
solids. The BPT limitations for domestic wastes prohibit discharges of 
floating solids. To comply with this limit, operators grind the waste 
prior to discharge. As proposed, EPA is establishing BCT and NSPS 
limitations as no floating solids. In addition, EPA is establishing BAT 
and NSPS limitations to prohibit discharges of foam. Foam is a 
nonconventional pollutant and its limitation is intended to control 
discharges that include detergents.
    As proposed, EPA is establishing discharges limitations for garbage 
as included in U.S. Coast Guard regulations at 33 CFR part 151. These 
regulations implement Annex V of the International Treaty to Prevent 
Pollution from Ships (MARPOL) and the Act to Prevent Pollution from 
Ships, 33 U.S.C. 1901 et seq. (The definition of ``garbage'' is 
included in 33 CFR 151.05).
    The pollutant limitations described above for domestic wastes are 
all technologically available and economically achievable and reflect 
the BCT, BAT and NSPS levels of control.
    These limitations are technologically available because, under the 
Coast Guard regulations, discharges of garbage, including plastics, 
from vessels and fixed and floating platforms engaged in the 
exploration, exploitation and associated offshore processing of seabed 
mineral resources are prohibited with one exception. Victual waste (not 
including plastics) may be discharged from fixed or floating platforms 
located beyond 12 nautical miles from nearest land, if such waste is 
passed through a screen with openings no greater than 25 millimeters 
(approximately one inch) in diameter. Because vessels and fixed and 
floating platforms must comply with these limits, EPA believes that all 
coastal facilities are able to comply with this limit. While not all 
coastal facilities are located on platforms, compliance with a no 
garbage standard should be as achievable, if not more so, for shallow 
water or land based facilities that have access to garbage collection 
services. Further, the final drilling permits issued by Region 6 for 
coastal Texas and Louisiana incorporates these Coast Guard regulations.
    No discharge of visible foam is required by the NPDES permit for 
Cook Inlet drilling. No discharge of floating solids is included in the 
Region 10 BPT general permit for Cook Inlet, the Region

[[Page 66105]]

10 drilling permit, and the Region 6 general permits for coastal 
operators.
    These limitations are economically achievable because these BCT, 
BAT and NSPS limitations for domestic waste are already included in 
either existing NPDES permits or Coast Guard regulations, and therefore 
these limitations will not result in any additional compliance cost. 
Also, these limits and standards will have no additional non-water 
quality environmental impacts. There are no incremental costs 
associated with the BCT limitations; therefore, they pass the BCT cost 
reasonableness tests.
    Pretreatment standards are not being developed for domestic wastes 
because domestic wastes are compatible with POTWs.

F. Sanitary Wastes

    Sanitary wastes from coastal oil and gas facilities are comprised 
of human body wastes from toilets and urinals. The volume of these 
wastes vary widely with time, occupancy, and site characteristics. A 
larger facility, such as an offshore platform, typically discharges 
about 35 gallons of sanitary waste daily. Sanitary discharges from 
coastal facilities would be expected to be less than this value since 
the manning levels at most coastal facilities is less than that at 
offshore locations.
    The existing BPT limitation for facilities continuously manned by 
10 or more people requires sanitary effluent to have a minimum residual 
chlorine content of 1 mg/l, with the chlorine concentration to remain 
as close to this level as possible. Facilities intermittently manned or 
continuously manned by fewer than 10 people must comply with a BPT 
prohibition on the discharge of floating solids. EPA Regions 6 and 4 
general permits for coastal facilities also limit the discharge of TSS, 
fecal coliform count, BOD and floating solids. The EPA Region 10 
general permit for Cook Inlet also requires limitations for these same 
parameters in addition to requirements for foam and free oil.
    EPA considered zero discharge of sanitary wastes based on off-site 
disposal to municipal treatment facilities or injection with other oil 
and gas wastes. Off-site disposal would require pump out operations 
that, while available to certain land facilities, are not easily 
available to remote or water-based operations. Because sanitary wastes 
are not accepted for injection into Class II wells, zero discharge 
based on Class II injection was rejected for sanitary wastes.
    EPA is establishing BCT and NSPS as equal to BPT limits for 
sanitary waste discharges. Sanitary waste effluents from facilities 
continuously manned by ten (10) or more persons must contain a minimum 
residual chlorine content of 1 mg/l, with the chlorine level maintained 
as close to this concentration as possible. Coastal facilities 
continuously manned by nine or fewer persons or only intermittently 
manned by any number of persons must comply with a prohibition on the 
discharge of floating solids.
    Since there are no increased control requirements beyond those 
already required by BPT effluent guidelines, there are no incremental 
compliance costs or non-water quality environmental impacts associated 
with BCT and NSPS limitations for sanitary wastes. Since there are no 
incremental costs associated with the BCT limit, it passes the BCT cost 
tests.
    EPA is not establishing BAT effluent limitations for the sanitary 
waste stream because no toxic or nonconventional pollutants of concern 
have been identified in these wastes.
    Pretreatment standards are not being developed for sanitary wastes 
because they are compatible with POTWs.

VIII. Economic Analysis

A. Introduction

    This section describes the capital investment and annualized costs 
of compliance with the Coastal Guidelines, and the potential impacts of 
these compliance costs on current and future operators of coastal oil 
and gas facilities. EPA's economic impact assessment is presented in 
detail in the Economic Impact Analysis of Final Effluent Limitations 
Guidelines and Standards for the Coastal Oil and Gas Subcategory of the 
Oil and Gas Extraction Point Source Category (hereinafter, ``EIA''), 
included in the rulemaking record. The EIA estimates the economic 
effect of compliance costs on federal and state revenues, balance of 
trade considerations, and inflation. In addition, EPA has conducted a 
Regulatory Flexibility Analysis, which estimates effects on small 
entities, and a cost-effectiveness analysis of all evaluated options 
for (1) produced water and treatment, workover, and completion fluids 
and (2) drilling fluids, drill cuttings and dewatering effluent. Except 
where otherwise noted, only the results for selected options are 
presented here. For all other wastestreams, EPA selected options that 
would generate no costs to industry.

B. Economic Impact Methodology

    This section (and, in more detail, the EIA) evaluates several 
measures of economic impacts that result from compliance costs. The 
economic analysis in the EIA has six major components: (1) An 
assessment of the number of facilities that could be affected by this 
rule; (2) an estimate of the annual aggregate (pre-tax) cost for these 
facilities to comply with the rule using facility-level capital and O&M 
costs; (3) use of an economic model to evaluate impacts on the 
production and economic life of coastal facilities; (4) an evaluation 
of impacts on firms' financial health, future oil and gas production, 
Federal and State revenues, balance of trade, employment and other 
secondary effects; (5) an analysis of compliance cost impacts on new 
sources; and (6) an analysis of the effects on small entities.
    Some of the economic impacts reported in this section are provided 
in terms of present value (PV) or net present value (NPV). The NPV of 
project worth is the total stream of production revenues minus all 
costs and taxes over a period of years discounted back to present value 
at the firm or industry borrowing rate, here 7 percent or 8 percent, 
depending on the region under consideration.
    All costs are reported in 1995 dollars, with the exception of cost-
effectiveness results, which, by convention, are reported in 1981 
dollars. Any costs not originally in 1995 dollars have been inflated or 
deflated using the Engineering News Record Construction Cost Index, 
unless otherwise noted in the EIA (see EIA for details). Oil and gas 
prices reported by individual operators are used where available. The 
impacts reported in this analysis are based on the assumption that 
these oil prices will remain constant in real terms over the time frame 
of the analysis. This assumption may overestimate economic impacts, at 
least over the next several years, given industry and government 
forecasts showing small real price increases. Price increases would 
tend to alleviate the economic impacts caused by increased compliance 
costs.
    The economic methodology is nearly identical to the methodology 
used at proposal. Changes include adjustments to costs (noted in 
Section V above), minor refinements to the financial models to more 
precisely reflect tax code and accounting practices, and a change in 
the baseline to which the costs of the rule are compared. The revision 
to the analytical baseline represents a significant departure from the 
1995 proposal analysis, although it is consistent with EPA's stated 
intent at proposal to more fully incorporate the effects of recent 
permit requirements in the analyses for the final rule (see 60 FR 
9430). At proposal, the Region 6 General

[[Page 66106]]

Permits requiring zero discharge of produced water in Texas and 
Louisiana were not yet issued. These permits apply to all coastal oil 
and gas operations in Louisiana and Texas with the exception of certain 
operations discharging offshore produced water into coastal waters of 
the Mississippi major deltaic passes (Major Pass dischargers). 
Therefore, at proposal, EPA counted compliance costs for facilities 
currently covered by these permits as costs of the Coastal Guidelines.
    For the final rule cost analysis, EPA has based costs on the Region 
6 General Permits. As a result, EPA considers facilities' Region 6 
permit compliance costs to be part of the current regulatory 
requirements baseline against which the incremental costs attributable 
to the Coastal Guidelines are measured. Only those facilities not 
covered by the permits are considered to incur costs as a result of 
this rule. The current regulatory requirements baseline analysis also 
considers the effects of the revised guidelines on Cook Inlet 
operators, for whom information on drilling plans and production has 
been updated.
    In response to comments, the Agency also has considered the effects 
of the Coastal Guidelines relative to an alternative baseline, which is 
based on the assumption that Louisiana Open Bay dischargers and 
dischargers who have applied for individual permits in Texas might 
continue to discharge under individual permits in the absence of this 
rule. This alternative baseline analysis estimates effects on these 
dischargers as well as the Major Pass and Cook Inlet operators. 
Specific effects on the Louisiana Open Bay dischargers and Texas 
Individual Permit applicants are also described as a separate part of 
this alternative analysis. Data for many of these dischargers were 
gathered for 1992 in the 1993 Coastal Oil and Gas Questionnaire. To 
EPA's knowledge, responses to the questionnaire provide the most recent 
and complete set of cost, revenue, and production data available to 
date for Louisiana Open Bay and Texas Individual Permit operations. The 
Texas Railroad Commission submitted data to EPA less than one week 
before the date of this rule, which, because of insufficient time 
remaining, could not be fully analyzed.
    To model Cook Inlet and Major Pass operations, EPA used a financial 
model similar to the one used to model Cook Inlet in the EIA for the 
proposed rule. This model uses platforms and/or facilities (rather than 
wells) as the relevant analytical units. Information for the model was 
provided by the affected operators, vendors, and publicly available 
documents, including information from the SEC, the Bureau of the 
Census, and the Bureau of Labor Statistics. In this model, the capital 
and operating costs for pollution control are added to (pre-compliance) 
baseline capital and operating costs to create a post-compliance 
financial scenario that evaluates the incremental effects of compliance 
costs for various options. When operating costs exceed revenues, EPA 
assumes that the well or facility ceases operation. EPA's model then 
calculates lifetime production in barrels of oil equivalent (BOE) and 
associated lifetime revenue (comprised of net income, taxes, and 
royalties). The net impacts of the rule are the changes in production 
and revenue from baseline to post-compliance estimates. These changes 
are the primary impacts of the rule; these in turn affect employment, 
firm financial health and balance of trade.

C. Summary of Costs and Economic Impacts

1. Overview of Economic Impact Analysis
    The EIA focuses first on the costs and economic impacts of the 
rule, assuming current permit requirements to be the baseline to which 
the rule is compared. The analysis addresses costs and economic impacts 
of the BAT and NSPS requirements for drilling fluids, drill cuttings 
and dewatering effluent (Cook Inlet only), and for produced water and 
treatment, workover and completion (TWC) wastes combined (Cook Inlet 
and Major Passes). EPA's analyses are restricted to specific areas of 
the Louisiana Gulf of Mexico coast and Cook Inlet, Alaska; current 
permit requirements are for zero discharge in all other coastal areas. 
As noted in Section VII, no significant costs will be incurred for BAT 
and NSPS for other wastestreams, for which EPA is setting limits equal 
to current practice. Similarly, BPT requirements established by this 
rule are based on current practice and thus are expected to impose 
negligible additional costs. All options for BCT requirements other 
than BPT failed the BCT cost test. As a result, BCT is established 
equal to BPT, with no incremental costs. PSES and PSNS requirements, as 
noted in Section VII, are expected to have negligible impacts for 
coastal oil and gas producers, who do not discharge to POTWs.
2. Total Costs and Impacts of the Regulation
    This section presents the total costs and impacts of the BAT 
limitations and NSPS established by this rule under the current 
regulatory requirements baseline. Results for the alternative baseline 
are presented below in Section VIII(C)(4).
    EPA estimates that there are six facilities (permits), associated 
with eight outfalls, that are not covered by the Region 6 permit and 
that are discharging offshore produced water into one of the major 
passes of the Mississippi River. There are also 13 platforms that 
discharge produced water and may discharge drilling wastes into Cook 
Inlet. Additionally, up to 684 existing wells and 45 new wells per year 
generating TWC wastes (which are not covered by the General Permits for 
produced water) would be affected by BAT and NSPS requirements, 
respectively.
    The six Major Pass facilities discharge some combination of coastal 
and offshore produced water. EPA's evaluation of the costs and impacts 
of BAT options addresses only the offshore portion of these costs, 
because zero discharge of coastal waters is required by the Region 6 
produced water permit.
    Under the current regulatory requirements baseline, BAT limitations 
for drilling fluids, drill cuttings and dewatering effluent (zero 
discharge-Gulf; offshore limits-Cook Inlet) are current practice, and 
thus have no incremental cost. BAT limits for produced water and TWC 
fluids (zero discharge, except for Cook Inlet, where operators would 
have to meet oil and grease limits based on improved gas flotation) 
affect Major Pass dischargers and Cook Inlet dischargers and have total 
annual compliance costs of $15.6 million (Table 2). The only NSPS costs 
incurred under this rule are $600,000 annually for TWC fluids for new 
wells drilled in the Gulf of Mexico.

  Table 2.--Costs of Selected BAT and NSPS Options: Current Regulations 
                             Baseline (1995)                            
------------------------------------------------------------------------
                                                          Annualized    
                                                       compliance costs 
                     Wastestream                        ($ million/yr)  
                                                     -------------------
                                                         BAT      NSPS  
------------------------------------------------------------------------
Produced Water/TWC Option 2 (BAT only)..............      15.6  ........
Drilling Fluids and Cuttings (BAT only).............      0.00      0.00
Treatment, Workover & Completion Fluids (NSPS only).      0.00       0.6
------------------------------------------------------------------------

    a. Impacts from Best Available Technology (BAT). No firms are 
expected to fail as a result of this rule under the Current Regulatory

[[Page 66107]]

Requirements baseline. Implementation of this rule is expected to cause 
a reduction in national employment of 127 jobs annually, which result 
from delays and reduction in oil production. EPA estimates that these 
BAT limitations could reduce the NPV of affected projects' worth by up 
to $63.7 million ($51.8 million from Major Pass facilities and $11.9 
million from Cook Inlet), equivalent to annual impacts of $9.1 million 
per year, or 1.4 percent of all coastal production's net worth. A 
change in project NPV considers the effects of both compliance costs 
and foregone oil and gas revenues on an oil and gas production 
project's, and ultimately, on a producing company's net worth. As a 
firm's net worth declines, its financial position becomes more tenuous 
and the risk of failure increases (see EIA for detailed description). 
Also, the BAT limitations result in $6.1 million in lost state taxes, 
$8.4 million in lost royalties and $20.3 million in lost federal tax 
revenues (all in present value). This represents 0.3 percent (taxes) 
and 0.2 percent (royalties) of the present value of all coastal oil and 
gas revenues received by states (and individuals) and 0.9 percent of 
federal tax revenues from all coastal facilities.
    Table 3 summarizes the BAT impacts discussed above for produced 
water/TWC (the BAT impacts for drilling fluid and drill cuttings are 
negligible).

   Table 3.--Summary of Present Value Impacts of Selected BAT Options   
------------------------------------------------------------------------
                                                              Percent of
                                                 PV impacts    coastal  
                    Impact                      ($ million)    industry 
                                                              (percent) 
------------------------------------------------------------------------
Project NPV lost..............................         63.7          1.4
Federal tax losses............................         20.3          0.9
State tax losses..............................          6.1          0.3
Lost royalties................................          8.4          0.2
                                               -------------------------
    Total losses..............................         98.5  ...........
------------------------------------------------------------------------

    Production losses under the selected BAT options are expected to 
total at most 5.8 million barrels of oil equivalent (BOE) over the 
lifetime of the wells and platforms (average post-compliance lifetime 
is 10 years in Major Pass and 12 years in Cook Inlet operations). In 
Cook Inlet, EPA expects the production loss over the productive 
lifetimes of the platforms to be approximately 2.4 million BOE, which 
is 0.5 percent of the estimated lifetime production for Cook Inlet. For 
Major Pass operations, the lifetime production loss is expected to be 
up to 3.4 million total BOE, which is 0.6 percent of estimated lifetime 
production from these facilities. For the two regions combined, the 
loss in production is 0.5 percent of total nondiscounted lifetime 
production in Cook Inlet and the Major Passes, or 0.2 percent of all 
Coastal oil and gas production. These losses result only from shortened 
economic lifetimes; no platforms or treatment facilities are expected 
to shut-in immediately due to the selected options.
    The rule is not likely to have a significant affect on energy 
prices, international trade, or inflation, and it would have a minimal 
and indeterminate impact on national-level employment. On average, the 
Major Pass facilities shut in 0.4 years earlier than they would without 
the rule (in 9.9 years instead of 10.3 years). In Cook Inlet, platforms 
shut in an average of 0.4 years earlier (in 12.3 years instead of 12.7 
years). These impacts would have a minor effect on regional employment 
because ample time is still available for workers to find alternative 
employment, an effort they would need to undertake within a similar 
time frame without the rule. Based on the predicted economic impacts, 
EPA finds that the costs of the BAT limitations are economically 
achievable for the coastal oil and gas industry.
    b. Impacts from NSPS. EPA does not expect compliance with any of 
the selected NSPS options to have a measurable impact on oil and gas 
income, royalties or taxes. EPA estimates no costs for the NSPS 
requirement for produced water in the Gulf of Mexico, because NSPS are 
the same as BAT and therefore are economically achievable and pose no 
barrier to entry. EPA also estimates no cost for the NSPS requirement 
for drilling wastes in the Gulf, because zero discharge represents the 
current BAT requirements. Therefore, NSPS is economically achievable 
and poses no barrier to entry. In the major passes, EPA estimates zero 
cost for NSPS also because EPA has determined that no new sources are 
planned that will discharge produced water. Costs of NSPS for TWC are 
associated only with 45 new source wells per year projected in the Gulf 
coastal region. Total annual NSPS compliance costs for TWC limits are 
$0.6 million.
    In Cook Inlet, NSPS requirements for produced water/TWC are 
equivalent to BAT requirements, and are therefore economically 
achievable and pose no barriers to entry. Costs for designing in 
compliance equipment to new structures are typically less than those 
for retrofitting the same equipment to existing operations. Based on 
discussions with industry and on EPA's assessment of economic 
conditions given present oil prices and production trends from Cook 
Inlet's aging fields, the Agency expects no new facility (platform) 
construction in Cook Inlet. Therefore, EPA estimates NSPS costs at zero 
for Cook Inlet for all wastestreams. However, if potential revenue did 
support the construction of a new facility in Cook Inlet, NSPS produced 
water compliance costs would increase total capital costs by an 
estimated 2.3 percent. This would not influence a decision to build, as 
profits in Cook Inlet have a ``hurdle rate'' of somewhere around 20 to 
25 percent. The hurdle rate is the estimated rate of return needed to 
interest a investor in undertaking an investment. It is particularly 
high in high-risk ventures such as Cook Inlet oil production. A 2.3 
percent increase in capital costs would not alter the profit margin 
sufficiently to discourage construction of a facility. NSPS 
requirements for drilling waste are also the same as BAT requirements 
and, further, add no costs and thus are economically achievable and 
pose no barriers to entry. As noted above, EPA rejected zero discharge 
of drilling fluids, drill cuttings and dewatering effluent for BAT in 
Cook Inlet primarily for technological reasons; these reasons also 
apply to NSPS.
3. Economic Impacts of Rejected Options
    EPA has determined that zero discharge of all wastestreams is both 
economically achievable and technically feasible in the coastal Gulf of 
Mexico. As stated in Section VII, EPA rejected BAT and NSPS limitations 
requiring zero discharge of produced water in Cook Inlet on the basis 
that this option was not economically achievable, nor was the 
combination of zero discharge of produced water and zero discharge of 
drilling wastes. The economic analysis related to these decisions for 
Cook Inlet is presented in the following section.
    a. Produced Water. EPA rejected zero discharge of produced water in 
Cook Inlet base on a finding that it was not economically achievable, 
as discussed in Section VII(B)(4)(a)(2) above.
    b. Drilling Fluids and Drill Cuttings. In establishing BAT 
limitations and NSPS for drilling fluids, drill cuttings and dewatering 
effluent in Cook Inlet, EPA rejected zero discharge primarily due to 
uncertainty regarding the technical feasibility of reinjection of 
drilling fluids, drill cuttings and dewatering effluent throughout the 
Inlet, as well as the operational problems and non-water quality

[[Page 66108]]

environmental impacts resulting from land disposal in the area. Zero 
discharge of these wastes may be particularly costly in Cook Inlet 
because of the lack of suitable geological formations for injecting 
drilling wastes (see Section VII). EPA estimated the annualized costs 
of zero discharge of drilling fluids, drill cuttings and dewatering 
effluent to be $9.2 million, based on transporting some of these wastes 
to out-of-state landfills. EPA further determined that the combined 
impact of zero discharge of drilling fluids, drill cuttings and 
dewatering effluent and zero discharge of produced water in Cook Inlet 
would result in 4 of 13 platforms closing, which EPA considers to 
indicate economically unachievability.
4. Alternative Analytical Baseline
    In response to comments from the Railroad Commission of Texas 
(RRC), on behalf of certain Texas dischargers who have applied for 
individual permits, and from the U.S. Department of Energy (DOE), on 
behalf of dischargers to open bays in Louisiana, EPA considered what 
the impacts of the Coastal Guidelines would be if EPA Region 6 (Texas) 
or the State of Louisiana were to grant individual permits to these 
dischargers allowing discharge of produced water. The RRC identified 
dischargers in Texas who have applied for individual permits (74 
applicants for 82 facilities at the time of this analysis) and DOE 
identified 82 discharging facilities (outfalls) in Louisiana open bays 
operating under 37 permits.
    EPA estimated effects on Texas Individual Permit applicants and 
Louisiana Open Bay operators at both the well level and at the facility 
level (unlike Cook Inlet and Major Pass operators, who were analyzed 
only at the facility or platform level). The well-level analysis tends 
to overestimate impacts, as each well is assumed to bear costs that are 
often shared by several wells served by a facility. Cost-sharing allows 
lower costs per well and allows more productive wells to support less 
productive ones as long as net present value is maximized. Many of the 
facilities identified by RRC and DOE were already included in EPA's 
Coastal Oil and Gas Questionnaire database. Costs and impacts to the 
remaining facilities were modeled based on operators' reported 
discharges and oil and gas production.
    EPA addressed the effects of zero discharge for combined discharges 
of produced water and TWC in this analysis of Texas Individual Permit 
applicants and Louisiana Open Bay operators. BAT for other wastestreams 
is addressed by Region 6 permits. Section VIII(C)(4)(a) addresses the 
effects of zero discharge only on the Texas Individual Permit 
applicants and Louisiana Open Bay facilities. Section VIII(C)(4)(b) 
assesses the combined effects on these Texas and Louisiana facilities 
together with costs and impacts to Major Pass and Cook Inlet 
dischargers. The impacts on Major Pass dischargers under the 
alternative baseline includes estimated compliance costs for zero 
discharge of produced water from coastal wells. Including coastal 
produced water increases Major Pass dischargers' costs by approximately 
20 percent.
    a. Produced Water BAT Impacts: Texas Individual Permits and 
Louisiana Open Bays. Relative to the alternative baseline, EPA 
estimates total annualized compliance costs for the Texas Individual 
Permit and Louisiana Open Bay dischargers to attain zero discharge of 
produced water to be $34.2 million. EPA estimates related production 
losses would be approximately 12.8 million non-discounted BOE compared 
to the baseline. This represents less than one percent of all Gulf 
coastal production, most of which is already in compliance with zero 
discharge requirements. These losses are associated with declines in 
project NPV of up to $126.7 million, or 3.4 percent of Gulf Coastal 
projects' NPV.
    Production losses result from both first-year shut-ins and 
shortened economic lifetimes. In the well-level analysis, a range of 
284 to 400 baseline shut-ins are estimated to take place before 
compliance costs are incurred, and up to 94 to 119 wells may be first 
year post-compliance shut-ins under the selected options. These 
baseline and first-year shut-ins are likely to be overestimates that 
result from EPA's well-level modeling approach, which EPA addresses in 
sensitivity analyses below and in Chapter 10 of the EIA. The 94 to 119 
first year shut-in wells constitute approximately 1 to 2 percent of all 
Gulf coastal wells. Based on a screening analysis, EPA identified up to 
four potential firm failures, which represent less than one percent of 
all Gulf of Mexico coastal firms. These results are derived from an 
analysis based on well-level impacts, a conservative approach that 
exaggerates both baseline and post-compliance well shut-ins.
    The BAT requirements could result in a present value loss of up to 
$36.7 million in federal tax revenues, or up to $5.2 million, on 
average, annually (1.9 percent of federal revenues from Gulf coastal 
production). Losses to state income and severance tax revenues could 
total $19.8 million, or $2.8 million annually (0.9 percent of revenues 
from Gulf coastal production). The states (and individuals) could also 
lose royalties with an estimated present value of $25.1 million, or 
$3.6 million annually (0.5 percent of revenues from Gulf coastal 
production). These impacts of the Coastal Guidelines are acceptable 
when compared to total federal and state tax revenues and royalties 
collected from all Gulf coastal operators.
    The impacts of the rule on Louisiana Open Bay dischargers and Texas 
Individual Permit applicants are not expected to affect energy prices, 
international trade or inflation, and would have a minimal impact on 
national-level employment. Total national employment losses would be 
expected to be 231 full-time equivalents (FTEs), which is approximately 
2 percent of total Gulf of Mexico coastal oil and gas employment. EPA 
finds that, under the assumptions of the alternative baseline, while 
the economic impacts of the Coastal rule are significant to some 
individual operators, they are economically achievable when compared to 
the Coastal industry as a whole.
    In response to late comments from the state of Texas, EPA has also 
conducted a sensitivity analysis at the facility level for each and 
every well identified as a baseline or first year shut-in among the 
Texas individual permit applicants group, based on actual facility 
level production and costs as reported by the operators of these wells. 
EPA's alternative analysis shows that, in fact, when these wells are 
treated as components of an entire facility, that is, where total 
facility production revenues must exceed facility operating costs in 
order to keep operating, most of these wells do remain open in the 
baseline and do not shut in as a result of compliance. Many of the 
wells do not produce much produced water (which generates compliance 
costs). The production from those wells that do shut-in simply cannot 
support, on a facility basis, the annual operations and maintenance 
costs reported by the operators. In this alternative analysis, the one 
(first year) post-compliance well shut-in that was identified in EPA's 
original well-level analysis does not shut-in during the first year.
    The facility level analysis shows 8 baseline shut-in wells (all in 
Texas) with the Coastal rule causing 16 first year shut-ins only among 
Louisiana Open Bay producers (compared to a total of 94 first year 
shut-ins for both states in the well level analysis). The firm failure 
analysis does not change. EPA concludes that its facility level 
analysis indicates that the effect on Texas and Louisiana operators of 
the

[[Page 66109]]

coastal rule will be even less significant than reported in the well-
level analysis (see Chapter 10 of EIA).

   Table 4.--Economic Impacts of Produced Water/TWC Zero Discharge BAT  
  Options on Texas Individual Permit Applicants and Louisiana Open Bay  
                               Dischargers                              
------------------------------------------------------------------------
                                                              Percent of
                                                  Present        Gulf   
                    Impact                       value  ($     Coastal  
                                                  million)   subcategory
                                                               (percent)
------------------------------------------------------------------------
Project NPV lost..............................        126.7          3.4
Federal tax losses............................         36.7          1.9
State taxes...................................         19.8          0.9
Lost Royalties................................         25.1          0.5
                                               -------------------------
    Total losses..............................        208.4          1.6
------------------------------------------------------------------------

    b. BAT and NSPS Impacts: Alternative Baseline Analysis. The 
analysis of the alternative baseline includes all of the financial 
impacts from the current regulatory requirements baseline and adds the 
impacts of compliance costs on Louisiana Open Bay dischargers, Texas 
Individual Permit applicants and the coastal portion of the Major Pass 
dischargers. For all of these facilities--Major Passes, Cook Inlet, 
Texas Individual Permit applicants and Louisiana Open Bay dischargers--
the total annual BAT and NSPS compliance costs, including produced 
water, TWC, and drilling fluids, drill cuttings and dewatering effluent 
options are $52.9 million relative to the alternative baseline (Table 
5). Under the alternative baseline, produced water compliance costs for 
Major Pass facilities increase by approximately 20 percent, compared to 
the current regulatory requirements baseline, to account for the costs 
of zero discharge of their coastal share of produced water.

   Table 5.--Total Costs of BAT and NSPS Options ($1995)--Alternative   
                                Baseline                                
------------------------------------------------------------------------
                                                          Annualized    
                                                       compliance costs 
                    Wastestream                         ($ million/yr)  
                                                    --------------------
                                                        BAT       NSPS  
------------------------------------------------------------------------
Produced Water/TWC Option 2 (BAT)..................      52.3       0.00
Drilling fluids, drill cuttings and dewatering                          
 effluent..........................................      0.00       0.00
Treatment Workover and Completion fluids (NSPS)....      0.00       0.6 
------------------------------------------------------------------------

    Relative to the alternative baseline, production losses associated 
with the selected BAT options are expected to be approximately 18.6 
million barrels of oil equivalent (BOE) over the lifetime of the 
affected wells, facilities, and platforms. This is approximately 0.6 
percent of total lifetime nondiscounted production in the coastal Gulf 
and Cook Inlet regions combined. Only 3 firms in Texas and one in 
Louisiana would be potential failures, and a maximum of 94 wells (2% of 
total coastal wells) would shut in. Most of these wells would shut in 
only a few years without the rule. Declines in the net present value of 
project worth would be approximately $200 million or $28 million 
annually discounted over 10 years (4.4 percent of total coastal NPV). 
BAT requirements could result in a present value loss of $60 million in 
federal tax revenues, or $8.5 million annually (2.5 percent of federal 
tax revenue from coastal operations). State income and severance tax 
revenues losses associated with BAT requirements would be approximately 
$26.6 million or $3.8 million annually (1.1 percent of all state tax 
revenue from coastal operations). The states and other individuals 
could also lose royalties totaling an estimated present value of $33.6 
million, or $4.8 million annually (0.6 percent of coastal royalties).
    The Coastal rule is not expected to affect energy prices, 
international trade or inflation, and would have a minimal impact on 
national-level employment. National level employment losses would be 
expected to be approximately 375 full-time equivalents (FTEs, or annual 
jobs) Table 6 summarizes the impacts discussed above.
    NSPS compliance costs are the same as under the current regulatory 
requirements baseline, for reasons explained above. Based on the 
impacts predicted, EPA finds that the costs of the BAT limitations and 
NSPS are economically achievable relative to the alternative baseline 
for the Coastal Oil and Gas Industry.

    Table 6.--Summary of Impacts of Selected BAT Options: Alternative   
                                Baseline                                
------------------------------------------------------------------------
                                                              Percent of
                                                  Present      coastal  
                    Impact                         value     subcategory
                                                 ($million)    (percent)
------------------------------------------------------------------------
Project NPV lost..............................          200          4.4
Federal tax losses............................           60          2.5
State taxes...................................         26.6          1.1
Lost Royalties................................         33.6          0.6
                                               -------------------------
    Total losses..............................        319.5          2.1
------------------------------------------------------------------------

D. Cost-Effectiveness Analysis

    In addition to the foregoing analyses, EPA has conducted cost-
effectiveness analyses for all options considered by the Agency. 
Results of these analyses are presented in Cost-Effectiveness Analysis 
for Final Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory of the Oil and Gas Extraction Point Source Category, which 
is included in the rulemaking record. Cost-effectiveness evaluates the 
relative efficiency of options in removing toxic pollutants. Costs 
evaluated include direct compliance costs, such as capital expenditures 
and operations and maintenance costs.
    Cost-effectiveness results are expressed in terms of the 
incremental and average costs per ``pound-equivalent'' removed. A 
pound-equivalent is a measure that addresses differences in the 
toxicity of pollutants removed. Total pound-equivalents are derived by 
taking the number of pounds of a pollutant removed and multiplying this 
number by a toxic weighting factor. EPA calculates the toxic weighting 
factor using ambient water quality criteria and toxicity values. The 
toxic weighting factors are then standardized by relating them to a 
particular pollutant, in this case copper. EPA's standard procedure is 
to rank the options considered for each waste stream in order of 
increasing pounds-equivalent (PE) removed. The Agency calculates 
incremental cost-effectiveness as the ratio of the incremental annual 
costs to the incremental pounds-equivalent removed under each option, 
compared to the previous (less effective) option. Average cost-
effectiveness is calculated for each option as a ratio of total costs 
to total pounds-equivalent removed. EPA reports annual costs for all 
cost-effectiveness analyses in 1981 dollars, to enable limited 
comparisons of the cost-effectiveness among regulated industries.
    At proposal, EPA solicited comment regarding the inclusion of 
indirect costs (e.g., oil and gas production-related losses) in its 
analysis of cost-effectiveness. With previous effluent guidelines, EPA 
has not included indirect costs associated with control technology 
options in cost-effectiveness analyses. While the primary purpose of 
the cost-effectiveness analysis is to compare the removal efficiencies 
of technology options for a given rule, a secondary use has been to 
benchmark the removal efficiency of a rule's selected option in 
comparison to other effluent guidelines. Including additional costs 
that were not considered in other rules makes such comparisons less

[[Page 66110]]

meaningful. In response to comment, however, in this rule, EPA 
addresses cost-effectiveness in two separate analyses: first, EPA 
conducts the conventional analysis, considering only direct capital and 
operations and maintenance costs; and, second, EPA evaluates the cost 
of lost oil/gas production in addition to direct compliance costs. The 
two approaches are compared in Tables 9 and 10.
    Table 7 presents the cost-effectiveness of different options 
considered for produced water/TWC and drilling wastes, for the current 
regulatory requirements baseline. Table 8 provides the produced water/
TWC cost-effectiveness results for the alternative baseline (the cost-
effectiveness of drilling waste options is the same in both baselines). 
Table 7 shows that all considered options for produced water/TWC 
wastes, including zero discharge (with an incremental cost-
effectiveness ratio of $42 per pound-equivalent) are cost-effective.

                    Table 7.--Cost-Effectiveness of All Options: Current Regulatory Baseline                    
----------------------------------------------------------------------------------------------------------------
                                          Total annual               Incremental                                
                                   ---------------------------------------------------- Average  C-  Incremental
              Option                   Lb-Eq         Cost        Lb-Eq         Cost      E  ($/Lb-   C-E  ($/Lb-
                                      removed      ($1981)      removed      ($1981)        Eq)          Eq)    
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:                                                                                             
    Option 1: Zero Discharge, Gulf/                                                                             
     Discharge Limits, Major Pass                                                                               
     & Cook Inlet.................      489,305    2,386,206      489,305    2,386,206            5            5
    Option 2: Zero Discharge, Gulf/                                                                             
     Discharge Limits, Cook Inlet.      712,335   10,081,484      223,030    7,695,278           14           35
    Option 3: Zero Discharge, All.    1,213,725   30,935,664      501,390   20,854,180           25           42
Drilling fluid/cuttings:                                                                                        
    Option 1: Current limits......            0            0            0            0            0            0
    Option 2: Zero Discharge All..        8,536    5,969,728        8,536    5,969,728          699          699
----------------------------------------------------------------------------------------------------------------

    Table 8 shows that the cost-effectiveness analysis for produced 
water using the alternative baseline versus the current regulatory 
requirements baseline does not significantly change the outcome. 
Significant additional pounds of toxics are removed to offset the 
increased costs associated with using the alternative baseline.

                Table 8.--Cost-Effectiveness of Produced Water/TWC Options: Alternative Baseline                
----------------------------------------------------------------------------------------------------------------
                                          Total annual               Incremental                                
                                   ---------------------------------------------------- Average  C-  Incremental
     Produced water/TWC option         Lb-Eq         Cost        Lb-Eq         Cost      E  ($/Lb-    C-E  ($/Lb-
                                      removed      ($1981)      removed      ($1981)        Eq)          Eq)    
----------------------------------------------------------------------------------------------------------------
Option 1: Zero Discharge, Gulf/                                                                                 
 Discharge Limits, Major Pass &                                                                                 
 Cook Inlet.......................    1,091,754   24,502,620    1,091,754   24,502,620           22           22
Option 2: Zero Discharge, Gulf/                                                                                 
 Discharge Limits, Cook Inlet.....    1,314,784   33,781,413      223,030    9,278,983           26           42
Option 3: Zero Discharge, All.....    1,816,174   54,635,592      501,390   20,854,180           30           42
----------------------------------------------------------------------------------------------------------------

    Tables 9 and 10 present the cost-effectiveness of selected produced 
water options, under both baselines, with and without the inclusion of 
production losses, respectively. Incremental and average cost-
effectiveness for zero discharge of produced water under both 
baselines, not including production loss costs (i.e., EPA's standard 
analysis) are shown in Table 9; cost-effectiveness results for zero 
discharge, including the value of production losses are shown in Table 
10. The inclusion of production losses has a relatively minor effect on 
the selected options' cost-effectiveness. In fact, the costs shown, 
including production losses (Table 10), are somewhat less than those in 
Table 9. This is because, in order to avoid double counting, EPA 
assumed no compliance costs associated with baseline and first year 
shut-ins and dry wells. These facilities would not incur compliance 
costs if they immediately shut in. Eliminating these facilities from 
the database used for compliance cost analysis results in lower total 
compliance costs, even though the value of their lost production is 
factored in.

                 Table 9.--Cost-Effectiveness of Selected Options--Direct Compliance Costs Only                 
----------------------------------------------------------------------------------------------------------------
                                                                                                    Incremental 
                                                             Lb-Eq         Cost     Average cost-      cost-    
                       Wastestream                          removed      ($1981)    effectiveness  effectiveness
                                                                                       ($/Lb-Eq)      ($/Lb-Eq) 
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:                                                                                             
    Current Requirements Baseline.......................      712,335   10,081,484            14             35 
    Alternative Baseline................................    1,314,784   33,781,413            26             42 
----------------------------------------------------------------------------------------------------------------


[[Page 66111]]


            Table 10.--Cost-Effectiveness of Selected Options--Compliance Costs and Production Losses           
----------------------------------------------------------------------------------------------------------------
                                                                                                    Incremental 
                                                             Lb-Eq         Cost     Average cost-      cost-    
                       Wastestream                          removed      ($1981)    effectiveness  effectiveness
                                                                                       ($/Lb-Eq)      ($/Lb-Eq) 
----------------------------------------------------------------------------------------------------------------
Produced Water/TWC:                                                                                             
    Current Requirements Baseline.......................      712,335    9,494,585            13             31 
    Alternative Baseline................................    1,314,784   29,817,756            23             37 
----------------------------------------------------------------------------------------------------------------

    Based on the cost-effectiveness results shown in Tables 7 through 
10, EPA has determined that the selected options are cost-effective.

IX. Non-Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution has the 
potential to aggravate other environmental problems. Under sections 
304(b) and 306 of the CWA, EPA is required to consider these non-water 
quality environmental impacts (including energy requirements) in 
developing effluent limitations guidelines and NSPS. In compliance with 
these provisions, EPA has evaluated the effect of these regulations on 
air pollution, solid waste generation and management, consumptive water 
use, and energy consumption. Because the technology basis for the 
limitation on drilling fluids and drill cuttings requires transporting 
the wastes to shore for treatment and/or disposal, adequate onshore 
disposal capacity for this waste is critical in assessing the options. 
Safety, impacts of marine traffic on coastal waterways, and other 
factors related to implementation were also considered. EPA evaluated 
the non-water quality environmental impacts on a regional basis. 
Although not specifically detailed in the discussion below, the non-
water quality environmental impacts that would be associated with 
requirements on future drilling and production activities in regions 
other than the Gulf of Mexico, California, and Alaska are considered 
acceptable because they would be considered to be similar to the 
impacts determined to be acceptable in the Gulf of Mexico, California, 
and Alaska. The non-water quality environmental impacts associated with 
requirements for drilling wastes and produced water are discussed 
below. The limitations and standards being promulgated for the 
remaining wastestreams covered by this rule will result in no 
significant increases in non-water quality environmental impacts.

A. Drilling Fluids, and Cuttings

    The non-water quality environmental impacts quantified for the 
drilling fluids, drill cuttings, and dewatering effluent control 
options are limited to the wastes generated in Cook Inlet. All other 
coastal areas are currently achieving zero discharge of these wastes 
and thus the control options cause no additional impacts. The control 
technology basis for compliance with the drilling waste options 
considered is a combination of product substitution and transportation 
of drilling wastes to shore for treatment and/or disposal. It is 
possible that in certain areas compliance with a zero discharge 
limitation for a portion of the drilling wastes would be achieved of by 
grinding followed by injection in disposal wells. However, EPA is 
unable to determine the degree to which this may be possible. The non-
water quality environmental impacts associated with the treatment and 
control of these wastes from new wells at existing sources are 
summarized in Table 10. No new sources are expected to be developed in 
Cook inlet. Therefore, no non-water quality environmental impacts are 
expected to result from the NSPS requirements for drilling wastes.
    EPA's methodology for calculating non-water quality environmental 
impacts is generally unchanged from the proposal. (See the preamble for 
the proposed rule at 60 FR 9467.) Certain assumptions related to waste 
handling and disposal which affect fuel use and air emissions have been 
updated. These changes are summarized in Section V of the preamble and 
presented in more detail in the Coastal Development Document and the 
record for the final rule.

  Table 10.--Non-Water Quality Environmental Impacts for Drilling Waste 
                             Control Options                            
------------------------------------------------------------------------
                                                                  Air   
                                                     Energy    emissions
                     Options                      consumption    (tons/ 
                                                   (BOE/year)    year)  
------------------------------------------------------------------------
Option 1: Zero discharge all except Cook Inlet..           0           0
Option 2: Zero discharge all....................       5,200          36
------------------------------------------------------------------------

B. Produced Water and Treatment, Workover and Completion Fluids

    The energy requirements and air emissions calculated for produced 
water control options considered for existing sources are presented in 
Table 11. These non-water quality environmental impacts have been 
updated since proposal to address changes in the industry profile which 
have affected the volume of produced water requiring treatment and/or 
disposal. The technology bases used to quantify these impacts are 
improved gas flotation and subsurface injection. Detailed discussions 
of the additional equipment required to comply with the control options 
are included in the Coastal Development Document and the record for the 
final rule. EPA's estimates of the non-water quality environmental 
impacts calculated using the alternative baseline are presented in the 
Coastal Development Document.
    Non-water quality environmental impacts from produced water and 
treatment, workover, and completion fluids NSPS accrue only from 
injection of TWC fluids. This is because for produced water, NSPS 
reflects current requirements, except for main pass dischargers. Thus, 
in the absence of NSPS, dischargers would have to meet BAT, which is 
zero discharge. There are no non-water quality environmental impacts 
for produced water and TWC fluids NSPS in Cook Inlet. There are no non-
water quality environmental impacts for produced water in the main 
passes of the Mississippi River or Atchafalaya River, because no new 
sources are projected in these locations. Elsewhere in the Gulf, where 
new

[[Page 66112]]

sources are projected, existing general permits allow discharge of TWC 
fluids. Thus, EPA estimated the non-water quality environmental impacts 
resulting from injection of TWC fluids at new sources. These impacts 
are an increase in total air emissions by two tons per year and 
approximately 190 BOE per year in additional fuel use. These air 
emissions represent a small portion of the total emissions from coastal 
oil and gas activities along the Gulf Coast.

  Table 11.--Non-Water Quality Environmental Impacts for Produced Water 
           and TWC Fluids Control Options for Existing Sources          
------------------------------------------------------------------------
                                                                  Air   
                                                     Energy    emissions
                     Options                      consumption    (tons/ 
                                                   (BOE/year)    year)  
------------------------------------------------------------------------
Option 1: Zero Discharge; Except Major Deltaic                          
 Pass and Cook Inlet Based On Improved Gas                              
 Flotation......................................       4,800          43
Option 2: Zero Discharge; Except Cook Inlet                             
 Based On Improved Gas Flotation................      93,700       1,110
Option 3: Zero Discharge All....................     188,000       1,260
------------------------------------------------------------------------

X. Environmental Benefits Analysis

A. Introduction

    This section describes results of EPA's environmental benefits 
analysis. EPA's complete environmental benefits analysis is presented 
in the Water Quality Benefits Analysis of Final Effluent Limitation 
Guidelines and Standards for the Coastal Subcategory of the Oil and Gas 
Extraction Point Source Category EPA-821-R-96-024 (hereinafter, WQBA), 
included in the rulemaking record. The WQBA evaluates the effect of 
current discharges on the coastal environment and the benefits of the 
Coastal Guidelines. Two baselines, the current requirements baseline 
and the alternative baseline that are discussed in the preamble above, 
are used in this analysis. In addition, this analysis parallels the 
option selection discussion by distinguishing between Cook Inlet and 
all other coastal locations. For purposes of the WQBA, only the two 
main wastestreams (i.e., produced water and drilling fluids and drill 
cuttings) are evaluated. The analysis was limited to these wastestreams 
because: (1) Treatment, workover, and completion fluids are 
conservatively considered to be a component of the produced water 
wastestream and (2) regulatory options considered for the other 
wastestreams reflect current permit requirements where applicable or 
current practice.
    The WQBA examines potential impacts from current produced water 
discharges in both geographic areas, and from drilling fluids and drill 
cuttings discharges in Cook Inlet. The effects of produced water for 
other coastal areas (i.e., Florida, Alabama, Mississippi, California 
and North Slope, Alaska), and drilling fluids and drill cutting 
discharges in addition to the above coastal areas in Louisiana and 
Texas are not evaluated because they are prohibited by state 
authorities and existing NPDES permits, and EPA has issued no 
individual permits allowing these discharges.
    Under the current requirements baseline, this rule will require 
major deltaic pass dischargers of offshore wastes (Major Pass 
facilities) to meet zero discharge of produced water, and Cook Inlet 
dischargers to meet new oil and grease limits for the discharge of 
produced water and current limits for the discharge of drilling fluids 
and drill cuttings. Under the alternative baseline, EPA investigated 
the impacts of produced water discharges by Texas individual permit 
applicants and Louisiana Open Bay dischargers on the coastal 
environment, and the benefits of zero discharge. Two types of benefits 
are analyzed: quantified (including non-monetized and monetized 
benefits), and non-quantified benefits.
    Coastal waters have diverse ecosystems which: act as spawning 
grounds, nurseries and habitats for important estuarine and marine 
species (finfish and shellfish); support highly valuable commercial and 
recreational fisheries; and provide vital habitat for seabirds, shore 
birds and terrestrial wildlife. A majority of commercial and 
recreational shellfish (oysters, shrimps, and crabs) and many finfishes 
spend significant portion of their life in bays and estuaries. Total 
1994 value of commercial fisheries (including both finfish and 
shellfish) $336 million for Louisiana and $207 million for Texas, for 
total of $543 million. The 1995 value of Cook Inlet commercial 
fisheries (finfish, and shellfish) was $51 million. The estimated Cook 
Inlet recreational fishery is valued at $28 million per year (in 1995 
dollars). In addition, personal use and subsistence fisheries provide a 
food source to the Gulf of Mexico coastal residents and a food source 
and cultural values to Alaskan residents and Alaskan native 
populations. Coastal areas also serve as vital habitats for numerous 
federally designated endangered and threatened species (including 32 in 
coastal areas of Louisiana and Texas), and migrating waterfowl.
    The coastal waters along the Gulf of Mexico are generally shallow, 
where tidal action has limited effect, and dilution and dispersion are 
more limited than offshore waters. Additionally, pollutants can migrate 
much more readily into sediments, where they may have long residence 
times. Consequently, these receiving environments are highly sensitive 
to pollutant discharges compared to open offshore areas. Many of the 
pollutants in coastal oil and gas discharges are either conventional 
pollutants, aquatic toxicants, human carcinogens, or human systemic 
toxicants. The aquatic impact of these pollutants on biota include 
acute toxicity; chronic toxicity; effects on reproductive functions; 
physical destruction of spawning and feeding habitats; and loss of prey 
organisms. In addition, many of these pollutants are persistent, 
resistant to biodegradation and accumulate in sediments and aquatic 
organisms. Chemical contamination of coastal water, sediment and biota 
may also directly or indirectly impact local aquatic and terrestrial 
wildlife and humans consuming exposed biota.
    The five major passes of the Mississippi River receiving produced 
water from offshore operations differ physically in depth, river flows 
and sediment types. Compared to the narrower, more energetic passes 
with hard packed sand, flows in shallower, wider passes are of slower 
velocity, resulting in more organic bottom deposits and thus supporting 
more organic life. All these passes are important nursery grounds for 
both saltwater and freshwater organisms and support recreational and 
commercial fishery. The deltaic region of the Mississippi River ranks 
in the top 10% for productivity of all United States wetland estuaries. 
This region also includes the Delta National Wildlife Refuge (NWR) and 
the Pass a Loutre State Fish and Game Preserve (SFGP), which in turn 
support one of the largest wading bird rookeries in the United States 
and hundreds of thousands of wintering waterfowl. Three major passes 
receiving offshore produced water are connected to this region. Raphael 
Pass winds directly through Delta NWR, while Emeline Pass establishes 
the northern border of this refuge. North Pass is included as part of 
the northern border of Pass a Loutre SFGP.
    Compared to the Gulf of Mexico region, Cook Inlet is an extremely

[[Page 66113]]

dynamic tidal estuarine system and its physical characteristics 
influence the fate and transport of contaminants in its waters. Water 
movement in Cook Inlet is dominated by the tidal cycle and strongly 
influenced by the freshwater inputs from rivers and precipitation.
    Benefits of Coastal Guidelines include elimination or reduction of 
toxic, conventional, and nonconventional pollutants, and elimination or 
reduction of impacts on human health and aquatic life. Potential 
benefits may ultimately include reduction of discharge-related aquatic 
habitat degradation; improved recreational fisheries; improved 
subsistence and personal use fisheries (potentially important to low-
income anglers and Alaska's Native anglers, etc.); improved commercial 
fisheries; improved aesthetic quality of waters; improved recreational 
opportunities; and decreased harm to threatened or endangered species 
in the Gulf of Mexico and Cook Inlet.
    Under the current requirements baseline, the Coastal Guidelines 
would eliminate total of about 1.5 billion pounds of pollutants to the 
coastal receiving waters of states adjacent to the Gulf of Mexico and 
to Alaskan waters. Under the alternative baseline, the Coastal 
Guidelines would eliminate total of 4.6 billion pounds of conventional, 
toxic and nonconventional pollutants (including Gulf of Mexico and Cook 
Inlet) (see Table 12).

                                 Table 12.--Pollutants Removed by Current Permit Requirements and Alternative Baselines                                 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  Removals under the current requirements baseline \1\       Additional removals under the alternative  
                                               ----------------------------------------------------------                    baseline                   
                                                       Produced water          Drilling                  -----------------------------------------------
Pollutants removed by coastal guidelines (lbs/ -----------------------------  fluids and                          Produced water                        
                     year)                                                     cuttings     Total (lbs/  --------------------------------               
                                                 Major deltaic              -------------      year)      Louisiana open                    Total (lbs/ 
                                                    passes       Cook Inlet                                     bay        Texas permit      year) \2\  
                                                                              Cook Inlet                    dischargers     applicants                  
--------------------------------------------------------------------------------------------------------------------------------------------------------
Conventional..................................       1,855,319      855,054            0       2,710,373       7,072,298       1,453,081      11,235,752
Toxic Organics................................         108,018       70,367            0         178,385         450,458          92,551         721,394
Toxic Metals..................................          33,877       14,755            0          48,632          90,535          18,602         157,769
Nonconventional...............................   1,490,602,961      560,011            0   1,491,162,972   2,571,382,167     528,318,780   4,590,863,919
                                               ---------------------------------------------------------------------------------------------------------
    Total Pollutants (lbs/year)...............   1,492,600,175    1,500,187            0   1,494,100,362   2,578,995,458     529,883,014  4,602,978,834 
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Under the current permit requirements baseline, removals (excluding TWC effluent) would result from: zero discharge for Major Pass facilities,      
  discharge limits for Cook Inlet produced water, and current limits for Cook Inlet drilling fluids and drill cuttings.                                 
\2\ Under the alternative baseline, removals (Excluding TWC effluent) would result from zero discharge of produced water for Louisiana open bay and     
  Texas individual permit applicants, in addition to those removals already presented under the baseline for current permit requirements.               

B. Quantitative Estimate of Benefits.

(1) Current Requirements Baseline
    (a) Quantified Non-Monetized Benefits--Gulf of Mexico. The benefits 
associated with zero discharge of produced water under the current 
requirements baseline include only non-monetized benefits (i.e., (i) 
review of case studies of environmental impacts of produced water that 
document adverse chemical and biological impacts resulting from current 
discharges into the Gulf of Mexico coastal area; (ii) modeled water 
quality benefits expressed as elimination in exceedances of human 
health or aquatic life state water quality standards for major deltaic 
pass facilities; and (iii) projected individual cancer risk reduction 
from consumption of seafood contaminated with Ra226 and Ra228 
based on modeled levels for major deltaic pass dischargers. EPA could 
not estimate the potential number of cancer cases avoided and monetize 
benefits for these facilities, however, because the exposed angler 
population could not be determined for major pass facilities alone.
    (i) Documented Case Studies. A comprehensive review of available 
data identified 25 study sites (12 in Louisiana and 13 in Texas) that 
examined impacts of produced water discharges on the coastal 
environment. The detailed description and complete references for these 
studies are presented in the WQBA included in the rulemaking record. 
The majority of evaluated study sites are in water depths less than 3 
meters, and include variable environments (i.e., wetlands, salt 
marshes, and fresh or brackish marshes), and both relatively low and 
high energy areas. The documented impacts show elevated hydrocarbons 
and metals in water column and sediments, and reveal impacts on biota 
(i.e., depressed community structure such as abundance or diversity) 
from the produced water discharge between 800 to 1000 meters in dead-
end canals and effluent dominated creeks or bayous. The salinity 
effects are typically detected up to 300 meters from the discharge, and 
up to 800 meters in dead-end canals. A benthic dead zone (no benthic 
fauna) is documented up to 15 meters and severely depressed benthic 
communities are noted to 150 to 400 meters from produced water 
outfalls.
    (ii) Projected Water Quality Benefits--Major Deltaic Pass 
Facilities. EPA evaluated the effects of toxic pollutants in current 
produced water discharges on receiving water quality. Of the 49 toxic 
and nonconventional produced water pollutants (representing 
subcategory-wide produced water discharge), plume dispersion modeling 
was performed to project in-stream concentrations of 11 toxic 
pollutants with specified water quality standards in Louisiana. (There 
are no specified water quality standards for the other 38 pollutants). 
Pollutant concentrations were projected at the edge of state-prescribed 
mixing zones for acute and chronic aquatic, and human health standards 
for Louisiana. Site-specific cases (including ambient water depth and 
operational data) were developed for five (of six) major deltaic pass 
facilities/dischargers. (The effects of current discharges for one 
discharger was not evaluated because of the lack of site-specific 
ambient data.)
    Of the six major deltaic pass dischargers, all five that were 
evaluated are projected to have discharges that exceed applicable human 
health or aquatic life water quality standards. Five dischargers are 
modeled to exceed the human health standard for benzene and the acute 
standard for copper. One discharger is modeled to exceed the acute 
aquatic life standard for toluene, and another to exceed the chronic 
aquatic life standards for copper and nickel. The final guideline's 
zero

[[Page 66114]]

discharge requirement would eliminate all projected exceedances.
    EPA recognizes that in the absence of this rule, the permit issuing 
authority (the State of Louisiana or EPA in Texas) would be required to 
develop water quality-based effluent limits at the permitting stage. 
This rule would eliminate the need to develop such limits at the 
permitting stage for the pollutants of concern. It may also lessen the 
possibility that the state will in the future have to develop a Total 
Maximum Daily Load for the pollutants under Sec. 303(d) of the CWA.
    EPA recognizes that in the absence of this rule, the permit issuing 
authority (the State of Louisiana or EPA in Texas) would be required to 
develop water quality-based effluent limits at the permitting stage. 
This rule would eliminate the need to develop such limits at the 
permitting stage for the pollutants of concern. It may also lessen the 
possibility that the state will in the future have to develop a Total 
Maximum Daily Load for the pollutants under section 303(d) of the CWA.
    In response to late comments, EPA reevaluated its use of the water 
quality model CORMIX to assess discharges to Major Deltaic Passes. In 
these areas, LADEQ regulations allow the use of other appropriate 
models in addition to the Complete Mix Balance Model (CMBM) specified 
in regulations. EPA used CORMIX because it is technically superior to 
the CMBM as discussed in the record. Nevertheless a sensitivity 
analysis was conducted using the CMBM. Use of CMBM still resulted in 
two of the outfalls exceeding criteria. One of these outfalls was the 
largest Major Deltaic Pass discharger with exceedances for benzene.
    (iii) Projected Individual Cancer Risk Reduction Benefits--Major 
Deltaic Pass Dischargers. Upper bound individual cancer risks from 
consuming fish contaminated with Ra226 and Ra228 from current 
produced water discharges are estimated for recreational and 
subsistence anglers. To estimate Ra226 and Ra228 levels in 
seafood, EPA uses modeled effluent data, i.e., current subcategory-wide 
produced water concentrations of Ra226 and Ra228, plume 
dispersion modeling at site-specific discharge rates and water depths 
for five (of six) major deltaic pass facilities/dischargers with site-
specific ambient data to support modeling. [Using the estimated 
Ra226 and Ra228 concentrations in seafood, EPA estimates 
individual cancer risks assuming two different consumption rates of 
147.3 g/day for subsistence anglers and 15 g/day for recreational 
anglers]. In addition, all individual cancer risks are adjusted by 
factors of 0.2 and 0.75 to account for ingestion of seafood from 
locations which are not contaminated with the Ra226 and Ra228 
in coastal produced water discharges].
    Projected individual cancer risks for 5 evaluated major deltaic 
pass facilities range from 2.4 x 10-5 to 6.3 x 10-4 for 
subsistence anglers and from 1.0 x 10-6 to 2.8 x 10-5 for 
recreational anglers. The Coastal Guidelines' zero discharge 
requirement for produced water will eliminate these estimated cancer 
risks over time.
    EPA could not estimate the potential number of cancer cases avoided 
and monetize benefits for these facilities, however, because the 
exposed angler population could not be determined for major pass 
facilities alone.
    (b) Quantitative Non-Monetized Benefits--Cook Inlet.
    EPA analyzed non-monetized quantitative benefits associated with 
the Coastal Guidelines for produced water in Cook Inlet. These benefits 
include modeled water quality benefits expressed as reduction of mixing 
zone needed for produced water discharges to meet Alaska state water 
quality standards. (Effects of current drilling fluids and drill 
cuttings discharge are also evaluated, however, because this rule does 
not require a change in current practice no benefits are projected.)
Produced Water
    EPA evaluated the effects of toxic pollutants in current produced 
water discharges on receiving water quality and the benefits of the 
final Coastal Guidelines. Site-specific plume dispersion modeling is 
performed to project in-stream concentration of 16 toxic and 
nonconventional pollutants at the edge of mixing zones from eight 
facilities constituting all of Cook Inlet produced water dischargers. 
The in-stream concentrations are then compared to the Alaska's state 
limitations. Unlike the Gulf of Mexico, Alaska state requirements do 
not have spatially-defined mixing zones. (Alaska determines the extent 
of mixing zone needed to achieve compliance with water quality 
standards and evaluates the reasonableness of this calculated mixing 
zone). The water quality assessment for Cook Inlet therefore determines 
the spatial extent of mixing zones needed for each evaluated outfall to 
meet all state standards at current discharge and at the final BAT. For 
the eight outfalls modeled, the distance from each facility where all 
standards are met ranges from within 100 meters to 3,500 meters at 
current level, and from within 100 meters to 1,000 meters for the final 
BAT.
2. Alternative Baseline
    Under the alternative baseline, EPA investigated the impacts that 
Louisiana Open Bay dischargers and Texas individual permit applicants 
have on the coastal environment and projected the benefits associated 
with zero discharge of produced water for these dischargers. The 
projected quantified benefits include both: (a) Non-monetized benefits 
(i.e., (i) reviewed a case study of environmental effects of Louisiana 
open bay produced water dischargers; (ii) modeled water quality 
benefits expressed as elimination in exceedances of human health or 
aquatic life state water quality standards; and (iii) projected 
individual cancer risk reduction from consumption of seafood 
contaminated with Ra226 and Ra228 based on modeled levels; 
and (b) monetized benefits (i.e., (i) estimated avoidance of projected 
cancer cases (from consumption of seafood contaminated with Ra226 
and Ra228 based on modeled levels) from Louisiana open bay and 
Texas permit applicant dischargers); and (ii) estimated ecological 
benefits of a zero discharge requirement for produced water open bay 
dischargers in Louisiana and permit applicants in Texas.
    (a) Quantified Non-Monetized Benefits for Louisiana Open Bay and 
Texas Individual Permit Dischargers.
    (i) The United States Department of Energy (DOE) conducted a study 
entitled Risk Assessment for Produced Water Discharges to Louisiana 
Open Bays, March, 1996 (hereafter, ``DOE study''), included in the 
rulemaking record. This study evaluated potential human health and 
environmental risks from discharges of produced water to Louisiana open 
bays. The DOE study concluded that: ``human health risks from radium in 
produced water appear to be small'', and ``ecological risks from radium 
and other radio nuclides in produced water also appear to be small''. 
The DOE study also concluded that: ``intakes of chemical contaminants 
in fish caught near open bay produced water discharges are expected to 
pose a negligible toxic hazard or carcinogenic risk'', that a 
``potential impacts to benthic biota and fish and crustaceans in the 
water column are possible within the 200 ft mixing zone'', but a 
``permanent damage to populations of organisms and ecosystems are not 
expected because mixing zones represent relatively small volumes and 
animals are not expected to remain continuously in the plume''.
    EPA believes that the study shows that there are impacts from 
coastal discharges, particularly regarding the

[[Page 66115]]

whole effluent toxicity and sediment contamination. Whole effluent 
toxicity risk assessment of Louisiana open bay dischargers conducted by 
the DOE study indicate that at 50 and 200 feet mixing zones 23 percent 
and 18 percent of modeled effluents exceed their respective LC50 values 
for mysids and sheep head minnows, and 57 percent and 56 percent of 
modeled effluents exceed their survival and growth-inhibition NOEL 
values, respectively, for mysids and sheep head minnow at 200 feet 
mixing zone. A sediment toxicity in excess of sediment quality ``Effect 
Range Low'' (ERL) and ``Effect Range Medium'' (ERM) criteria for heavy 
metals and total and individual PAH's is also documented by the study. 
(The measured values above ERL value, but less than ERM value 
``represent a possible-effects range within which effects would 
occasionally occur''. Concentrations at or above the ERM value 
``represent a probable effect range within which effect would 
frequently occur'' (Long, E.R., D.D. Macdonald, S.L. Smith, F.D. 
Calder, 1995, ``Incidence of Adverse Biological Effects Within Ranges 
of Chemical Concentrations in Marine and Estuarine Sediments'', 
Environmental Management 19:81-97).) Metals, arsenic and nickel are 
measured in excess of ERL value up to 500 m and 1000 m from discharge, 
respectively. The total and individual PAH's in excess of ERL are 
measured up to 500 m from discharge. The total PAH's, high molecular 
weight PAH's, and individual PAHs are also measured near discharge.
    (ii) Projected Water Quality Benefits. The effects of toxic 
pollutants in current produced water discharges on receiving water 
quality and benefits associated with the Coastal Guidelines are 
evaluated. Of the 49 produced water pollutants (representing 
subcategory-wide produced water discharge), plume dispersion modeling 
is performed to project in-stream concentrations of 11 toxic pollutants 
with specified state water quality standards in Louisiana and in Texas. 
(There are no specified water quality standards for the other 38 
pollutants in Louisiana and in Texas). Pollutant concentrations are 
projected at the edge of state-prescribed mixing zones for acute and 
chronic aquatic water quality standards, and human health water quality 
standards for Louisiana and Texas.
    Estimated flow-weighted average ambient water depth characteristic 
and operational data are used for 69 Louisiana's open bay outfalls, and 
82 Texas individual permit applicants. A mean discharge rate of 4,780 
bpd and flow-weighted mean depth of 1.73 meters are used for Louisiana 
open bay dischargers, and mean discharge rate of 827 bpd and flow-
weighted mean water depth of 1.66 meters for Texas permit applicants.
    Eighteen of the 69 evaluated Louisiana's open bay outfalls are 
projected to exceed: acute aquatic life standards for two pollutants 
(copper and toluene); chronic aquatic life standards for four 
pollutants (copper, nickel, lead, and toluene); and human health 
standards for one pollutant (benzene). These 18 outfalls represent 79 
percent of Louisiana's open bay total daily discharge flow. In Texas, 
eighteen of the 82 evaluated individual permit applicants are projected 
to exceed the acute and chronic aquatic life standards for silver. 
These 18 applicants represent 84 percent of the total produced water 
flow for the 82 applicants. The final guideline's zero discharge 
requirement would eliminate all projected exceedances.
    EPA recognizes that in the absence of this rule, the permit issuing 
authority (State of Louisiana or EPA in Texas) would be required to 
develop water quality-based effluent limits at the permitting stage. 
This rule would eliminate need to develop such limits at the permitting 
stage for the pollutants of concern. It may also lessen the possibility 
the state will in the future have to develop a Total Maximum Daily Load 
for the pollutants under section 303(d) of the CWA.
    (iii) Projected Individual Cancer Risk Reduction Benefits. Upper 
bound individual cancer risks from consuming fish contaminated with 
Ra226 and Ra228 from current produced water discharges are 
estimated for recreational and subsistence anglers. To estimate 
Ra226 and Ra228 levels in seafood, EPA uses: modeled effluent 
data, i.e., current subcategory-wide produced water concentrations of 
Ra226 and Ra228; plume dispersion modeling at average outfall 
discharge rates and flow-weighted ambient average depths for 69 
Louisiana open bay outfalls and 82 Texas individual permit applicant 
dischargers; and consumption rates as described in the section 
XII.B.1.(a)(iii) of this preamble.
    Projected individual cancer risks from Louisiana open bay 
dischargers range from 2.9 x 10-4 to 1.1 x 10-3 for 
subsistence anglers and from 1.3 x 10-5 to 4.8 x 10-6 for 
recreational anglers. For Texas individual permit applicants, the 
projected individual cancer risks range from 3.7 x 10-5 to 
1.4 x 10-4 for subsistence anglers and from 1.6 x 10-6 to 
6.1 x 10-6 for recreational anglers. The Coastal Guidelines' zero 
discharge requirements for produced water will eliminate these 
estimated cancer risks over time, resulting in projected elimination of 
0.43 to 1.66 cancer cases per year for anglers consuming fish from the 
Louisiana open bay dischargers and Texas individual permit applicant 
dischargers (i.e., 0.35 to 1.34 and 0.08 to 0.32 annual cancer cases in 
Louisiana and Texas, respectively)
    (b) Quantified Monetized Benefits for Louisiana Open Bay and Texas 
Permit Applicant Dischargers.
    (i) Projected Cancer Risk Reduction Benefits by Reducing Exposure 
to Radium in Produced Water. The projected avoidance of 0.43 to 1.66 
cancer cases per year for anglers consuming fish from Louisiana open 
bay dischargers and Texas individual permit applicant dischargers will 
result in combined monetized benefits in $1.1 to $22.3 million per year 
($1995) range (including $0.9 to $18 million per year ($1995) for 
Louisiana open bay dischargers and $0.2 to $4.3 million per year 
($1995) for Texas individual permit applicants).
    The temporal dynamics of both impacts and benefits assessments is 
relevant to the human health risk assessment. For the assessments of 
cancer reduction benefits, the methodology is consistent with 
estimating costs for the rule, using a one-year ``snap-shot'' approach. 
Allocating the full value of annual benefits within one year following 
cessation of produced water discharges may appear to over-estimate 
potential annual benefits in cases where incomplete recovery has 
occurred. However, in such cases where impacts are incompletely 
recovered, a consideration of total impact would need to include any 
impacts expected to occur beyond that year. This analysis does not 
attempt to identify or allocate benefits on a yearly basis, but merely 
averages total benefits so that monetized benefits may be compared to 
costs that are developed using the same approach.
    In response to late comments, EPA revised the population estimate 
of exposed individuals to reflect only coastal counties within 65 miles 
of the coast. The number of resident recreational anglers who only fish 
in state waters was adjusted by the proportion of state residents in 
coastal counties. EPA also received late comments to the effect that it 
should have used the monitoring data from the DOE study rather than 
EPA's modeled data. As is discussed further in the record, EPA 
continued to use the modeled effluent data rather than limited 
monitoring data to estimate risk. Although EPA modeling predicts radium 
concentrations significantly

[[Page 66116]]

higher than those measured in the DOE study, EPA believes it is not 
appropriate to use migratory fish species to represent tissue levels of 
all fish around platforms because EPA has information indicating that 
some resident species in coastal areas spend a significant amount of 
time in coastal waters.
    (ii) Projected Ecological Benefits. A potential ecological benefit 
of zero discharge of produced water in Louisiana open bays and Texas 
individual permit applicants dischargers is projected from a Trinity 
Bay case study. Extrapolating from this case study is only applicable 
to shallow bay ecosystems contiguous with the Gulf of Mexico open bay 
discharge sites that are represented by the Louisiana open bay 
dischargers and the great majority of Texas individual permit applicant 
dischargers. This Trinity Bay study shows that sediment near the 
outfall (within 15 meters) were devoid of biota and that depressions in 
benthic abundance and species richness were not recovered until 
distances between 1.7 and 4 kilometers from the point of discharge. 
(Data on abundance of other species, such as waterfowl were not 
collected). Taking into account an integration of the severity of these 
impacts at different distances, the equivalent acreage affected in this 
case study ranges from 200 to 2,817 acres.
    The analysis of this study is based on naphthalene concentration in 
sediment and extremely tight correlation between sediment naphthalene 
levels and benthic community structure parameters. In response to 
comments, EPA has adjusted the basis for projecting these effects 
because of the pre-BPT effluent quality of this study site and adjusted 
the acreage affected by the proportion between the Trinity Bay effluent 
naphthalene level (300 ppb) and current effluent naphthalene levels 
(184 ppb) to a 123 to 1,727 acres range.
    EPA estimates that the total Louisiana and Texas open bay acreage 
affected by coastal oil and gas produced water discharges ranges from 
6,918 acres to 97,438 acres (i.e., 5,739 to 80,828 acres in Louisiana 
and 1,179 to 16,610 acres in Texas). EPA identifies numerous values for 
an acre of wetland but none are marginal estimates for Texas or 
Louisiana, and some did not subtract the cost of recreational use. 
There may be concern that the value of wetland recovery diminishes as 
the amount of recovered acreage increases and therefore these average 
values would overstate the relevant marginal values by an unknown 
amount. A literature review for wetland value estimates conducted for 
the Mineral Management Service (MMS), Department of Interior in 1991, 
reports that different studies have estimated recreational and 
commercial wetland values for coastal Louisiana ranging from $57 to 
$940 per acre per year (with a median value of $410 per acre per year) 
in 1990 dollars.
    Using this range of values inflated to 1995 dollars, the estimated 
increase of Louisiana and Texas Bay recreational values from zero 
discharge of produced water ranges from $0.48 million to $106.8 million 
per year (i.e., $0.4 to $88.6 million/year in Louisiana and $0.08 to 
$18.2 million/year in Texas).
    These per acre estimates are consistent with the estimated average 
recreational value of the acreage of Galveston Bay, which ranges from 
$336 to $730 per acre. ($1990) (The Galveston Bay estimates do not 
subtract the cost to recreational users of using the resource.) These 
estimates may not be marginal values as they are calculated from the 
total recreational value of Galveston Bay and total acreage of the Bay. 
As these studies use different estimation methods, cover different 
types of wetlands, marshes and coastal waters which may differ from 
those affected by this rule, and generally reflect average values 
rather than the social valuation of small (marginal) changes in 
acreage, EPA at proposal requested data on marginal values of wetlands, 
in particular in Louisiana and Texas. However, EPA did not receive any 
data on wetland values or any comments related to the values used in 
benefit analysis for the proposed rule.
    In response to late comment, EPA performed a sensitivity analysis 
to assess the acreage affected based on the results of Trinity Bay 
study. EPA's approach uses a maximum observed species abundance and 
richness at 1677 and 3963 meters from the platform as a measure of 
background. This range is based on collecting species using two 
different sieve sizes. EPA believes that this is appropriate because a 
true measure of background cannot be determined since oil and gas 
facilities discharges have occurred in this water body for over 40 
years. In late comments, some suggested that EPA instead use the 
average abundance of species richness beyond 686 meters as a 
background. Using this suggested approach substantially reduces the 
impacted area. More details are provided in the record.
    The authors of the Trinity Bay study state that stations beyond 457 
meters or further are unaffected by the platform. Based on the authors 
estimated impact area of 457 meters rather than EPA's estimated range 
of 1677-3963 meters, the estimated average impacted acreage would be 51 
acres. Using this methodology, the total monetized benefits are $0.12--
$1.9 million ($1995) based on wetland values of $66--$1087 ($1995). EPA 
does not believe this is an appropriate impacted area because maximum 
species abundance and richness occurs between 1677 and 3963 meters. 
Furthermore sediment napthalene levels, which can adversely effect 
aquatic species, are the lowest at 4,000 meters. Both stations beyond 
4,000 meters have lower species abundance and richness. Both these 
stations are contaminated with naphthalene at levels that exceed Effect 
Range Median (ERM) for naphthalene. The ERM represents the 
concentrations at which adverse effects are frequently associated.
    (iii) Total Monetized Benefits. EPA estimates that total monetized 
benefits (i.e. combining cancer risk reduction and ecological benefits) 
resulting from zero discharge of produced water for Louisiana open bay 
dischargers and Texas individual permit applicants dischargers range 
from approximately $1.6 million to $129.1 million per year ($1995) 
(i.e., $1.3 to $106.6 million/year in Louisiana and $0.3 to $22.5 
million/year for Texas individual permit operators).

C. Description of Non-Quantified Benefits

    The WQBA attempts to quantify the environmental effects, and 
whenever appropriate, to monetize specific environmental benefits that 
may result from the Coastal Guidelines. However, some of the potential 
benefits could not be quantified or monetized because of the lack of 
data, or because sufficient information to define the causal 
relationship between dischargers covered by the Coastal Guidelines and 
environmental effects is not available. This analysis includes: (1) An 
assessment of potential health risks to the Alaska's Native Populations 
from consumption of Cook Inlet's fish and shellfish and potential link 
between coastal oil and gas discharges and fish consumed by native 
populations; (2) effects on threatened or endangered species and 
migratory waterfowl, and potential benefits of the Coastal Guidelines 
on ecosystem health primarily for coastal areas of Gulf of Mexico and 
to a limited degree for Cook Inlet.
    (1) An Assessment of Health Risks to Cook Inlet's Native 
Populations. EPA received comments from Native Americans concerned 
about coastal oil and gas discharges in Cook Inlet. The Chugachmuit 
Environmental Protection Consortium (CEPC) of Anchorage, Alaska raised 
concerns about the

[[Page 66117]]

impacts that oil and gas exploration and development activities in Cook 
Inlet and Kachemak Bay, Alaska have on the subsistence lifestyle of the 
Native Tribes of Port Graham and Nanwalek, and provided fish 
consumption data. EPA evaluated this data and all other data about the 
environmental impacts of coastal oil and gas discharges in Cook Inlet. 
EPA attempted to assess the potential health risks posed from the high 
subsistence use of Cook Inlet by native populations related to the 
discharges from coastal oil and gas facilities. Although sufficient 
information on the Cook Inlet's native population subsistence patterns 
exists, there is little fish tissue data with which to assess the risks 
from consumption of fish and shellfish from Cook Inlet. Two available 
studies provide some mussels tissue data, but no data on fish or other 
shellfish. One study investigated the occurrence of petroleum 
hydrocarbons, naturally occurring radioactive materials, and trace 
metals in water, sediments, and biota (mussels) in lower Cook Inlet. 
Very low levels of PAHs (including naphthalene) were found in mussel 
samples but the source of the PAHs could not be identified. The authors 
also found no anomalous trends evident from the mussels metals 
concentrations. Another Cook Inlet study, using caged mussels, found 
low levels of hydrocarbons in mussel tissue that were within a range of 
concentrations observed in organisms from unpolluted offshore 
environments. The study was conducted as part of environmental 
monitoring program to determine impacts of oil industry operations in 
Cook Inlet.
    The mussel data may provide an upper bound of contaminant 
concentrations likely to be found in other shellfish. However, the data 
is insufficient to assess risk from consumption of fish. EPA cannot 
predict finfish contaminant concentrations based on mussel data because 
mussels have much higher bioaccumulation rates. Finfish tend to more 
rapidly metabolize and excrete contaminants (e.g., PAHs). In addition, 
mussels and shellfish in general represent only small portion (i.e., 
two to eight percent) of the fish and shellfish subsistence harvest for 
three Cook Inlet's native villages (i.e., Tyonek, Nanwalek and Port 
Graham). Finfish represent 74 to 80 percent of the harvest, (with 
salmon representing 57 to 97 percent of the finfish harvest). The 
finfish harvest data indicate consumption levels could be as high as 
211 g/day, 238 g/day and 298 g/day (with salmon consumption levels of 
121 gpd, 232 gpd, and 180 gpd) in Port Graham, Tyonek and Nanwalek, 
respectively. The shellfish harvest data indicate consumption levels of 
6 g/day, 20 g/day, and 29 g/day in Tyonek, Port Graham, and Nanwalek, 
respectively. These consumption levels are higher then the subsistence 
consumption levels used in this WQBA for the Gulf of Mexico region. 
However, lacking the data on the concentration of pollutants in fish 
tissue, which represent up to 80 percent of the Cook Inlet's native 
population fish and shellfish intake rates, it is difficult to assess 
the human health risks from fish consumption, and to reasonably 
establish the link between coastal oil and gas discharges and human 
health effects from the discharges in Cook Inlet. EPA is, however, 
concerned about the potential for human health effects. Therefore, EPA 
will continue to monitor ongoing sediment, water quality and biological 
studies in Cook Inlet for applicability to future permit actions.
    (2) Effects on Threatened and Endangered Species. The zero 
discharge of produced water may also have beneficial effects on 32 
threatened and endangered species in coastal areas of Texas and 
Louisiana, including open bays and the major deltaic passes of the 
Mississippi River. Such threatened and endangered species include the 
Brown Pelican, Hawksbill Sea Turtle, Leatherback Sea Turtle, Ocelot, 
and others that use these areas as part of their habitat.
    The control of produced water discharges by the Coastal Guidelines 
may also have beneficial effects on Cook Inlet biological resources. 
The Upper Cook Inlet serves as an important pathway for spawning fish 
and non-endangered mammals, provides critical habitat for seabirds, 
shorebirds, and migrating waterfowl, and at least four endangered 
cetacean species and endangered avian species which may occur as 
migrants in or near Cook Inlet.

XI. Related Acts of Congress, Executive Orders, and Agency 
Initiatives

A. Pollution Prevention Act

    In the Pollution Prevention Act of 1990 (PPA) (42 U.S.C. 13101 et 
seq., Pub. L. 101-508, November 5, 1990), Congress declared pollution 
prevention the national policy of the United States. The PPA declares 
that pollution should be prevented or reduced whenever feasible; 
pollution that cannot be prevented or reduced should be recycled or 
reused in an environmentally safe manner wherever feasible; pollution 
that cannot be recycled should be treated in an environmentally safe 
manner wherever feasible; and disposal or release into the environment 
should be chosen only as a last resort.
    Today's rules are consistent with the PPA. EPA developed these 
rules while focused on pollution-preventing technologies. The closed-
loop recycle systems for drilling fluids and the achievement of zero 
discharge for produced water by injection form a substantial basis for 
this rule.

B. Paperwork Reduction Act

    The Coastal Guidelines place no additional information collection 
or record-keeping burden on respondents. Therefore, an information 
collection request has not been prepared for submission to the Office 
of Management and Budget (OMB) under the Paperwork Reduction Act, 44 
U.S.C. 3501 et seq.

C. Regulatory Flexibility Act

    Pursuant to section 605(b) of the Regulatory Flexibility Act, 5 
U.S.C. 605(b), the Administrator certifies that this rule will not have 
a significant economic impact on a substantial number of small 
entities. EPA analyzed the potential impact of the rule on small 
entities under several scenarios. Under the most conservative scenario 
(i.e. the scenario that assumes the largest number of small entities 
potentially affected by the rule), EPA's analysis shows that most small 
entities are already in compliance or are already covered by permit 
requirements equivalent to the rule's discharge requirements. Thus, the 
rule will not have any adverse economic impact on them. Under this same 
scenario, approximately 58 out of 372 small entities might have to take 
some action to achieve compliance. Even a smaller number of entities 
(34) may experience costs greater than one percent of revenues. Based 
on this analysis, EPA believes that the economic impact of the rule 
will not be significant for a substantial number of small entities.
    Under the Regulatory Flexibility Act, an agency is not required to 
prepare a regulatory flexibility analysis for a rule that the agency 
head certifies will not have a significant economic impact on a 
substantial number of small entities. While the Administrator has so 
certified today's rule, the Agency nonetheless prepared a regulatory 
flexibility assessment equivalent to that required by the Regulatory 
Flexibility Act as modified by the Small Business Regulatory 
Enforcement Fairness Act of 1996. The assessment for this rule is 
detailed in the Economic Impact Analysis. Although not required by the 
Regulatory Flexibility Act, EPA also

[[Page 66118]]

analyzed the indirect economic impact of the Coastal rule on small 
communities. Indirect impacts are those impacts felt by entities not 
subject to the rule. Some of the royalty losses caused by the rule may 
be felt at the local level. To determine the significance of this 
indirect impact, EPA assumes that 50 percent of the total royalty 
losses would be borne by local county and parish revenues. In the 
offshore rule, local governments were estimated to receive 
approximately 3 percent of royalties. As a result, EPA considers the 50 
percent assumption a significant overestimation that nonetheless serves 
to underscore the limits of the rule's indirect impact on local 
communities. EPA determined that spreading royalty losses over the 
population of counties and parishes adjacent to affected coastal waters 
would result in a per capita cost of $0.12, or 0.002 percent of per 
capita income in Texas counties, and a per capita cost of $0.44 to 
$1.30 in Louisiana , which represents 0.004 to 0.012 percent of per 
capita income in affected parishes under the regulatory requirements 
and alternative baselines, respectively. EPA thus concludes that the 
indirect impacts of the rule are not significant.

D. Small Business Regulatory Enforcement Fairness Act of 1996 
(Submission to Congress and the General Accounting Office)

    Under 5 U.S.C. 801(a)(1)(A) as added by the Small Business 
Regulatory Enforcement Fairness Act of 1996, EPA submitted a report 
containing this rule and other required information to the U.S. Senate, 
the U.S. House of Representatives and the Comptroller General of the 
General Accounting Office prior to publication of the rule in today's 
Federal Register. This rule is not a ``major rule'' as defined by 5 
U.S.C. 804(2).

E. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 
104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, it must have developed under 
section 203 of the UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, and tribal governments, in the aggregate, or the private 
sector in any one year. While EPA does not believe the rule imposes 
significant or unique effects on small governments, under section 203 
and 205 of the UMRA, EPA has consulted with state governments as 
described in Section XIII. The estimated annual cost of the Coastal 
Guidelines, presented in Section VIII of this preamble, is $16.4 
million when estimated using the current requirements baseline and 
$50.6 million when estimated using the alternative baseline. Thus, 
today's rule is not subject to the requirements of sections 202 and 205 
of the UMRA.

F. Executive Order 12866 (OMB Review)

    Under Executive Order 12866, (58 FR 51735, October 4, 1993) EPA 
must determine whether the regulatory action is ``significant'' and 
therefore subject to OMB review and the requirements of the Executive 
Order. The Order defines ``significant regulatory action'' as one that 
is likely to result in a regulation that may:
    (1) 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,
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency,
    (3) Materially alter the budgetary impact of entitlements, grants 
user fees, or loan programs or the rights and obligations of recipients 
thereof, or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, it has been 
determined that this rule is a ``significant regulatory action'' 
because of novel policy issues raised by the Department of Energy. As 
such, this action was submitted to OMB for review. Changes made in 
response to OMB suggestions or recommendations will be documented in 
the public record.

G. Common Sense Initiative

    On August 19, 1994, the Administrator established the Common Sense 
Initiative (CSI) Council in accordance with the Federal Advisory 
Committee Act (5 U.S.C. Appendix 2, Section 9 (c)) requirements. A 
principal goal of the CSI includes developing recommendations for 
optimal approaches to multimedia controls for industrial sectors 
including Petroleum Refining, Metal Plating and Finishing, Printing, 
Electronics and Computers, Auto Manufacturing, and Iron and Steel 
Manufacturing.
    The Coastal Guidelines were not among the rulemaking efforts 
included in the Common Sense Initiative. However, many oil and gas 
producers (mostly large companies) involved in coastal oil and gas 
extraction activities also have refineries. These companies are 
projected to incur costs associated with the requirements contained in 
this proposal, though these costs are not projected to have an economic 
impact at the firm level. The CSI objectives, described at proposal, 
have been incorporated into the Coastal Guidelines and the Agency 
intends to continue to pursue these objectives. The Agency particularly 
will focus on avenues for giving state and local authorities 
flexibility in implementing this rule, and giving the industry 
flexibility to develop innovative and cost effective compliance 
strategies. In developing this rule, EPA took advantage of several 
opportunities to gain the involvement of various stakeholders. Section 
XIII of this preamble references consultations with state and local 
governments and other parties including the industry. EPA has also 
coordinated among relevant program offices in developing this rule. 
Section XII describes related rulemakings that are being developed by

[[Page 66119]]

EPA's Office of Air Quality, Planning and Standards, Underground 
Injection Control Program, and Spill Prevention, Control and 
Countermeasure Program. EPA will be monitoring these related 
rulemakings to assess their collective costs to the industry. Section 
IX of the preamble describes the non-water quality environmental 
impacts this proposed rule would have on other media including air 
emissions and solid waste disposal.

XII. Related Rulemakings

    In addition to these Coastal Guidelines, EPA is in the process of 
developing other regulations that specifically affect the oil and gas 
industry. These other rulemakings are summarized below. EPA's offices 
are coordinating their efforts with the intent to monitor these related 
rulemakings to assess their collective costs to industry.

A. National Emission Standards for Hazardous Air Pollutants

    National emission standards for hazardous air pollutants are being 
developed for the oil and gas production industry by EPA's Office of 
Air Quality, Planning and Standards (OAQPS), under authority of section 
112 (d) of the Clean Air Act as amended in 1990. Section 112 (d) of the 
Clean Air Act directs the EPA to promulgate regulations establishing 
hazardous air pollutant (HAP) emissions standards for each category of 
major and area sources that has been listed by EPA for regulation under 
section 112 (c). The 189 pollutants that are designated as HAP are 
listed in section 112 (d). For major sources, or facilities which emit 
10 or more tons per year (TPY) of an individual HAP pollutant or 25 or 
more TPY of multiple HAPs, the air emission standards are based on 
``maximum achievable control technology'' or MACT.
    Major sources within the coastal oil and gas subcategory have been 
identified by OAQPS as stand alone glycol dehydrators, tank batteries, 
gas plants, and offshore production platforms. In most cases, OAQPS 
believes that, in order to be a major source, a coastal production 
facility must have glycol dehydrators located on-site. A production 
facility alone may not produce enough emissions to be classified as a 
major source.
    EPA plans to propose MACT standards for the oil and gas industry by 
March 1997. OAQPS estimates that the total annual cost of these 
standards is $16.5 million.

B. Requirements for Injection Wells

    The Safe Drinking Water Act (SDWA) charges EPA with protecting 
underground sources of drinking water (USDW). As part of this mandate, 
EPA developed the Underground Injection Control (UIC) program to 
regulate the underground injection of all fluids, including produced 
water. EPA first promulgated regulations concerning the construction, 
operation, and closure of Class II injection wells for the disposal of 
oil and gas industry wastes in 1980 (45 FR 42500, June, 24, 1980).

C. Spill Prevention, Control, and Countermeasure

    EPA's Oil Pollution Prevention regulation at 40 CFR part 112, which 
requires Spill Prevention, Control, and Countermeasure (SPCC) plans, 
was promulgated in 1973 under section 311 (j) of the CWA. The SPCC 
planning requirement applies to all oil extraction and production 
facilities that have an oil storage capacity above certain thresholds 
(i.e. an overall aboveground oil storage capacity greater than 1,320 
gallons or greater than 660 in a single container, or an underground 
oil storage capacity of greater than 42,000 gallons) and are located 
such that a discharge could reasonably be expected to reach U.S. 
waters. EPA estimates that there are approximately 450,000 SPCC-
regulated facilities. A preliminary estimate indicates that 
approximately 3,000 of these facilities may be either coastal or 
offshore facilities.
    Under part 112, facility owners or operators are required to 
prepare and implement written SPCC plans that discuss conformance with 
procedures, methods, and equipment and other requirements to prevent 
discharges of oil and to contain such discharges.
    On July 1, 1994, (59 FR 34070, July 1, 1994) EPA issued a final 
rule amending part 112 to require certain onshore facilities to 
prepare, submit to EPA, and implement plans to respond to a worst case 
discharge of oil to meet section 4202(a) of the Oil Pollution Act 
(OPA). EPA also intends to develop requirements in 1997 under section 
4202(a) of OPA specifically for coastal facilities. (Note: Coastal and 
offshore facilities in the part 112 program are collectively referred 
to as ``offshore''. However, the intended OPA rulemaking specifically 
applies to facilities landward of the inner boundary of the territorial 
seas, and that are not onshore.) These regulations would, among other 
things, require that owners or operators of coastal facilities prepare 
and submit to the Federal government a plan for responding to a worst 
case discharge of oil.

D. Shore Protection Act Regulations

    EPA, in conjunction with the Department of Transportation, has 
developed proposed regulations that would establish waste handling 
practices for vessels and waste transfer stations for the hauling and 
handling of municipal and commercial wastes. This rule would assure 
that wastes will not be deposited into coastal waters during loading, 
off loading, and transport. The proposal was signed by the 
Administrator on August 19,1994 and published in the Federal Register 
on August 30 (59 FR 44798). Promulgation is planned for March 1997. 
While this regulation will apply to operators of supply vessels used by 
coastal oil and gas extraction facilities, it will not directly impact 
the ability of coastal oil and gas extraction facilities to comply with 
effluent limitations guidelines and standards.

XIII. Summary of Public Participation

    EPA encouraged full public participation in the development of the 
final Coastal Guidelines. Written comments were received on the 1989 
Notice of Information and Request for Comments (54 FR 46919; November 
8, 1989), industry trade associations and the Natural Resources Defense 
Council, Inc. participated in the development of EPA's questionnaire 
for the coastal oil and gas extraction industry, written comments were 
received on the proposed rule (60 FR 9428; February 17, 1995), and 
public meetings were held.
    On July 19, 1994, EPA held a public meeting in New Orleans, 
Louisiana about the content and the status of the proposed regulation. 
The meeting was announced in the Federal Register (59 FR 31186; June 
17, 1994), and information packages were distributed at the meeting. 
The public meeting also gave interested parties an opportunity to 
provide information, data, and ideas to EPA on key issues.
    Additional public meetings were held on March 7, 1995 and March 21, 
1995. The first of these meetings was held in New Orleans, Louisiana 
and the second in Seattle, Washington.
    Meetings have been held with representatives from industry and 
environmental groups, as well as state and other federal agencies. 
These meetings are documented in the record.
    EPA has formally assessed all comments and data received: at the 
July 19, 1994 public meeting, during the public comment period for the 
proposed rule, and as a result of the 1989 Notice of Information. 
Responses to these

[[Page 66120]]

comments are provided in the Comment Response Document for Final 
Effluent Guidelines and Standards for the Coastal Subcategory of the 
Oil and Gas Extraction Category, which is in the record. In addition, 
as time allowed, EPA considered late comments.

XIV. Regulatory Implementation

A. Toxicity Limitation for Drilling Fluids and Drill Cuttings

    EPA is establishing a toxicity limitation for drilling fluids and 
drill cuttings. The toxicity limitation would apply to any periodic 
blowdown of drilling fluid as well as to bulk discharges of drilling 
fluids and drill cuttings systems. The reader is referred to the 
Offshore Guidelines at 58 FR 12454, 12502 (March 4, 1993) for an 
explanation of the regulatory implementation for the toxicity limit.

B. Diesel Prohibition for Drilling Fluids and Drill Cuttings

    Cook Inlet's oil and gas extraction platforms are prohibited from 
discharging diesel oil and drilling fluids and drill cuttings 
contaminated with diesel oil. The reader is referred to the Offshore 
Guidelines (58 FR 12502) for a discussion on the implementation of this 
requirement.

C. Upset and Bypass Provisions

    A recurring issue of concern has been whether industry guidelines 
should include provisions authorizing noncompliance with effluent 
limitations during periods of ``upsets'' or ``bypasses''. The reader is 
referred to the Offshore Guidelines (58 FR 12501) for a discussion on 
upset and bypass provisions.

D. Variances and Modifications

    Once this regulation is in effect, the effluent limitations must be 
applied in all NPDES permits thereafter issued to discharges covered 
under this effluent limitations guideline subcategory. Under the CWA 
certain variances from BAT and BCT limitations are provided for. A 
section 301(n) (Fundamentally Different Factors) variance is applicable 
to the BAT and BCT and pretreatment limits in this rule. The reader is 
referred to the Offshore Guidelines (58 FR 12502) for a discussion on 
the applicability of variances.

E. Synthetic Drilling Fluids

    During the Offshore Guidelines rulemaking and again after the 
Coastal Guidelines proposed rule, several industry commenters noted 
recent developments in formulating synthetic-based drilling fluids as 
substitutes for the traditional water-based and oil-based drilling 
fluids. Synthetic-based drilling fluids or synthetic-based muds (SBM) 
represent a new technology which was developed in response to the oil-
based drilling fluids discharge ban in the North Sea. They were first 
used in the North Sea in 1990, and the first well drilled in the Gulf 
of Mexico using SBM was completed in June 1992. Operators have claimed 
that compared to the discharge of water-based muds (WBM) and cuttings 
and barging/hauling of cuttings from oil-based muds (OBM), the use of 
the synthetics and on-site discharge of associated cuttings presents a 
pollution prevention opportunity.
    In the proposed Coastal Guidelines, the EPA requested additional 
information on the use of synthetic fluids including well logs, 
toxicity, analytical methods testing and in-situ seabed and water 
column physical, chemical and biological testing. EPA received numerous 
comments documenting and supporting environmental and operational 
benefits achieved by SBMs. The commenters contended that in the absence 
of definitions for SBM, NPDES permit restrictions on discharges of oil-
based drilling fluids and inverse emulsions were unintentionally 
providing barriers to the discharge of drill cuttings generated with 
SBM even though such cuttings generally pass the sheen and toxicity 
tests. Based on a review of these comments EPA has identified certain 
environmentally beneficial aspects of using SBM. Improved drilling 
operations allow for smaller diameter holes resulting in less drill 
wastes being generated. Increased solids removal in the closed loop 
solids systems leads to less discharge of drilling fluids. Lower 
toxicity of the drilling fluids, at least in the aqueous or suspended 
particulate phase, leads to a decrease in water column toxicity 
effects, and possibly a decrease in overall toxicity effects.
    In considering use of these drilling fluids EPA is examining the 
use of the current sheen and toxicity tests applied to the discharge of 
cuttings associated with SBM. Although the existence and limited use of 
SBM were known at the start of the Coastal and completion of the 
Offshore rulemakings, sufficient information was not available to 
propose any limitations different from those contained in the Offshore 
rule at this final Coastal rule. Nevertheless, EPA will address the 
concerns related to the sheen and toxicity tests by additional data 
gathering in order to provide guidance to NPDES permit writers about 
the use of alternative tests where the discharge of drilling wastes is 
allowed. The alternative tests are a gas chromatography (GC) test and a 
benthic toxicity test to verify the results of the static sheen and the 
suspended particulate phase (SPP) toxicity testing currently required. 
Other tests for bioaccumulation potential and biodegradation may be 
appropriate for use in evaluating site specific (water quality) effects 
and rates of recovery for sea floor areas covered by cuttings piles. 
Such tests are already applied to SBM cuttings discharges in the North 
Sea.
    EPA recognizes the potential pollution prevention opportunities 
presented by this new technology. Until guidelines can be written for 
this wastestream, EPA is encouraging their further development by 
including definitions in this rule for ``synthetic-based drilling 
fluid'' and the ``synthetic material'' which comprises the SBM. 
Furthermore, one commenter claimed to achieve the environmental and 
performance benefits of a synthetic based drilling fluid with an 
enhanced mineral oil (EMO). Since the EMOs are not synthetic based 
materials and were stated to be different from previously used mineral 
oils, EPA is also providing a definition for EMOs. The definitions are 
as follows:

    The term drilling fluid refers to the circulating fluid (mud) 
used in the rotary drilling of wells to clean and condition the hole 
and to counterbalance formation pressure. The four classes of 
drilling fluids are:
    (a) A water-based drilling fluid has water as its continuous 
phase and the suspending medium for solids, whether or not oil is 
present.
    (b) An oil-based drilling fluid has diesel oil, mineral oil, or 
some other oil, but neither a synthetic material nor enhanced 
mineral oil, as its continuous phase with water as the dispersed 
phase.
    (c) An enhanced mineral oil-based drilling fluid has an enhanced 
mineral oil as its continuous phase with water as the dispersed 
phase.
    (d) A synthetic-based drilling fluid has a synthetic material as 
its continuous phase with water as the dispersed phase.

    EPA is also introducing definitions for the ``synthetic material'' 
and ``enhanced mineral oil'' which comprise the respective drilling 
fluids as follows:

    The term enhanced mineral oil as applied to enhanced mineral 
oil-based drilling fluid means a petroleum distillate which has been 
highly purified and is distinguished from diesel oil and 
conventional mineral oil in having a lower polycyclic aromatic 
hydrocarbon (PAH) content. Typically, conventional mineral oils have 
a PAH content on the order of 0.35 weight percent expressed as 
phenanthrene, whereas enhanced mineral oils typically have a PAH 
content of 0.001 or lower weight percent PAH expressed as 
phenanthrene.
    The term synthetic material as applied to synthetic-based 
drilling fluid means material

[[Page 66121]]

produced by the reaction of specific purified chemical feedstock, as 
opposed to the traditional base fluids such as diesel and mineral 
oil which are derived from crude oil solely through physical 
separation processes. Physical separation processes include 
fractionation and distillation and/or minor chemical reactions such 
as cracking and hydro processing. Since they are synthesized by the 
reaction of purified compounds, synthetic materials suitable for use 
in drilling fluids are typically free of polycyclic aromatic 
hydrocarbons (PAHs) but test sometimes report levels of PAH up to 
0.001 weight percent PAH expressed as phenanthrene. Poly(alpha 
olefins) and vegetable esters are two examples of synthetic 
materials used by the oil and gas extraction industry in formulating 
drilling fluids. Poly(alpha olefins) are synthesized from the 
polymerization (dimerization, trimerization, tetramerization, and 
higher oligomerization) of purified straight-chain hydrocarbons such 
as C 6-C 14 alpha olefins. Vegetable esters are 
synthesized from the acid-catalyzed esterification of vegetable 
fatty acids with various alcohols. The mention of these two 
synthetic fluid base materials is to provide examples, and is not 
meant to exclude other synthetic materials that are either in 
current use or may be used in the future. A synthetic-based drilling 
fluid may include a combination of synthetic materials.

    Since the publication of the Offshore Guidelines in 1993, and 
publication of the proposed Coastal Guidelines in February 1995, data 
have been submitted to document the enhanced operational and 
environmental performance of synthetic fluids. The data for SBMs 
included: well logs, toxicity, analytical methods testing and in-situ 
seabed and water column physical, chemical and biological testing.
    Impacts due to the discharge of drilling fluids and associated 
drill cuttings fall into two main categories: water column and sea 
floor. As detailed in the Coastal Development Document, these data and 
evidence presented in the literature show that use of SBM in place of 
WBM may reduce the adverse environmental impact in the water column 
because of (a) reduction in volume of muds discharged, (b) less 
dispersion of the muds and cuttings in the water, and (c) lower 
toxicity. In addition, the reduction in volume of wastes discharged may 
reduce the effects to the sea floor. Due to decreased washout 
(erosion), drilling of narrower gage holes, and lack of dispersion of 
the cuttings in the SBM, compared to WBM the quantities of muds and 
cuttings waste generated is reduced, reportedly in some cases by as 
much as 70 percent. The greatest reduction seen is for the drilling 
fluids. The SBM offer the opportunity for high recycle rates because 
unlike the WBM the cuttings do not disperse in the fluid and so less 
dilution and additives are required to keep the necessary drilling 
fluid characteristics. In general the only SBM discharged is the amount 
adhered to the cuttings, which ranges from 7 to 12 percent based on dry 
cuttings weight. When WBM is used, the amount of drilling fluid 
discharged is often 5 or 6 times greater that discharged when drilling 
a similar hole with SBM. If the engineering aspects of the 
effectiveness of a drilling fluid are considered as a technology to 
reduce the levels of pollution, then SBM may be viewed as a control 
technology for conventional pollutants.
    Sea floor effects can be separated into two types: Short-term 
burial effects and long-term toxic effects. The adverse impact caused 
by burial can be assumed to be directly proportional to the quantity of 
solids discharged, and will also depend on the dispersion of the 
settling solids. As discussed earlier the synthetics have been shown to 
create a lower volume of drilling wastes. Also, the cuttings which are 
coated with 7-12 percent synthetic material, tend to sink without 
drifting in the water column unlike the particulate matter of the WBM 
which tends to disperse and stay suspended longer. Therefore as 
compared to WBM one would expect the burial footprint from SBM cuttings 
discharge to be smaller and have less solids. The diminished dispersion 
of the SBM has been shown by relating barium concentrations on the sea 
floor.
    In terms of the long-term toxic effects, studies have shown that 
changing the toxicity, biodegradation, and bioaccumulation of the oily 
or hydrophobic constituent of the cuttings has a large effect on the 
recovery of the benthic community. Most germane is a comparison of the 
recolonization of WBM cuttings piles compared to that of SBM cuttings 
piles. While WBM cuttings piles are said to recover ``quickly'' in the 
literature, data have not been found in any source which defines just 
how quickly. Thus, a comparison with the SBM recovery rates is not 
possible without additional study. The recovery of synthetics 
contaminated cuttings piles has been detailed in two instances known to 
EPA, one contaminated with a poly(alpha olefin) (PAO) and one 
contaminated with a vegetable ester. In both cases the PAO or vegetable 
ester organic contamination was found to either biodegrade or otherwise 
disperse to low concentrations at the eight month to one year 
evaluation times. At the one year to 16 months evaluation times, the 
cuttings piles were found to be in a natural state with a normal 
diversity and number of benthic organisms, except at a few stations 
where there was either a dominant population of one organism or 
slightly elevated organic contamination. This is contrasted with the 
relatively large zone of impact and much slower rate of recovery of 
cuttings piles contaminated with oil from OBM.
    While EPA recognizes the potential environmental benefits with the 
use of SBM over WBM, EPA has some concerns about the appropriateness of 
both the static sheen test used to determine compliance with the no 
free oil limitation and the toxicity test associated with the suspended 
particulate phase to determine compliance with the toxicity limitation. 
The sheen and toxicity tests were developed for use on WBM, which 
readily disperse in water, allowing components of the drilling fluid or 
contaminants to rise to the surface to give a sheen or partition to the 
suspended particulate phase (aqueous phase) and show toxicity. 
Conversely, the cuttings from SBM sink to the sea floor with little or 
no dispersion in the water. This is demonstrated in the laboratory 
toxicity test. When WBM drill associated cuttings are stirred in sea 
water as prescribed, the suspended particulate phase (SPP) becomes 
cloudy immediately and typically remains cloudy during the one-hour 
settling period. When stirring SBM or associated cuttings in sea water, 
the aqueous phase typically remains clear indicating little or no 
dispersion of drilling fluid, cuttings, or other components in the 
aqueous phase. For this reason, EPA believes it may be inappropriate to 
measure only the aquatic toxicity as part of the discharge requirement 
to judge the environmental effect of the discharge of these cuttings. 
The measurement of benthic toxicity may be appropriate for use in 
conjunction with the aquatic phase testing as a discharge requirement. 
Additional tests on bioaccumulation and biodegradation rates may be 
more useful for the evaluation of the synthetic material or SBM 
cuttings wastes with respect to environmental impact determinations.
    In addition, previous commenters had identified the sheen test as 
giving false positive results due to discoloration which may occur when 
cuttings containing small amounts of some of the synthetic materials 
are discharged. Recently, these same commenters have endorsed the sheen 
test as viable when using the synthetic-based drilling fluids. In 
general, to pass the sheen test, the sample must be covered until below 
the surface of the water, at which point it can be released. Samples of 
synthetic-based drilling fluids may fail if stirred according to the 
test method.

[[Page 66122]]

Conversely, samples have been shown to pass the static sheen test 
following the addition of various levels of oil, crude oil, diesel oil, 
and mineral oil in a laboratory controlled evaluation. Results of this 
evaluation also showed that the sheen test appears to be more 
subjective and difficult to judge for the synthetics than for the 
water-based drilling fluids, due to the lack of dispersion of the 
synthetics in the aqueous phase which leads to the question of adequate 
stirring, and due to the formation of sheens (or discoloration) which 
are not iridescent.
    There is also concern with the ability of the static sheen test to 
detect formation (crude) oil contamination on the cuttings when SBM is 
used. Since these compounds consist of lipophilic matrices, any oily 
(sheen producing) contaminants could dissolve in these matrices and be 
brought to the sea floor with no observed sheen surface effect. Thus 
the sheen test, which was developed to test for free oil contamination 
in the oil or water-based drilling wastes, which readily disperse in 
water, may not be appropriate. Formation oil contamination in certain 
synthetic fluids has been shown to be clearly identifiable by using gas 
chromatography (GC). Commenters have indicated that GC analysis with 
flame ionization detection (GC/FID) can be practically performed at a 
reasonable cost, and has in some instances been performed on offshore 
platforms. GC/FID as described in method 1663 in document EPA 821-R-92-
008, ``Methods for the Determination of Diesel, Mineral, and Crude Oils 
in Offshore Oil and Gas Industry Discharges,'' can be used to identify 
the presence or increase of n-alkane groups from crude oil 
contamination. Also contained in this document is high performance 
liquid chromatography (HPLC) method 1654A, and the combination of 
methods 1654A and 1663 can be used to differentiate diesel oil, mineral 
oil, crude oil, and synthetic material. Gas chromatography followed in 
series with mass spectroscopy (GC/MS) gives higher resolution and can 
also be used to identify the presence of PAHs, but is also more 
complicated and several times more expensive. Nonetheless, it may be 
beneficial to perform GC/MS analysis to identify the PAHs. Free oil is 
an indicator pollutant for PAHs. Several of the PAHs commonly found in 
crude oil are priority pollutants.
    In the United Kingdom and Norway, discharge requirements of SBM 
drill cuttings follow the Oslo and Paris Commission (PARCOM) guidelines 
for a harmonized chemical notification procedure. These guidelines 
require drilling fluids to undergo marine toxicity, bioaccumulation and 
biodegradation testing, and allow the regulatory authorities to 
calculate the maximum amount of the fluid which can be expected not to 
cause serious adverse environmental effects if lost or discharged to 
the sea. The marine toxicity test evaluates both water-born and benthic 
organisms such as algae (Skeletonema costatum), zooplankton (Acartia 
tonsa), and amphipod crustacean sediment reworker (Corophium 
volutator). EPA believes that tests such as these (or some combination 
of these tests) may be more appropriate as the basis for both the 
environmental assessment and for discharge limitations for the cuttings 
associated with synthetic-based and EMO-based drilling fluids. Other 
static sediment toxicity tests, such as the ASTM E1367-92, may also be 
appropriate. Just recently detailed monitoring at several sites in the 
North Sea has begun to evaluate seven different mud systems and to 
compare the actual sea floor determinations with the laboratory 
determinations. While evaluations in the Gulf of Mexico may prove to be 
different from those in the North Sea due to the differences in 
physical parameters and sea life, EPA intends to follow these sea floor 
evaluations for early indications of appropriate laboratory and field 
evaluation methods.
    The final rule incorporates clarifying definitions of drilling 
fluids for both the offshore and coastal subcategories to better 
differentiate between the types of drilling fluids. At this time, EPA's 
guidance to permit writers needing to write limits for SBMs on a best 
professional judgement (BPJ) basis is to use GC as a confirmation tool 
to assure the absence of free oil in addition to meeting the current no 
free oil (static sheen), toxicity, and barite limits on mercury and 
cadmium. Method 1663 as described in EPA 821-R-92-008 is recommended as 
a GC/FID method to identify an increase in n-alkanes due to crude oil 
contamination of the synthetic materials coating the cuttings to be 
discharged. Additional tests such as benthic toxicity conducted on the 
synthetic material prior to use or whole SBM prior to discharge, may be 
useful in controlling the discharge of cuttings contaminated with 
drilling fluid. One possible level of control is the use of the PARCOM 
protocol for 1000 ppm acute benthic toxicity for Corophium volutator, 
or similar protocol assessing a more appropriate local species as the 
indicator.
    EPA intends to further evaluate the test methods for benthic 
toxicity and may determine an appropriate limitation if this additional 
test is warranted. In addition, test methods and results for 
bioaccumulation and biodegradation, as indications of the rate of 
recovery of the cuttings piles on the sea floor, will be evaluated. It 
is recognized that evaluations of such new testing protocols may be 
beyond the technical expertise of individual permit writers. Thus this 
effort will be coordinated as a continuing effluent guidelines effort. 
Results of this effort may lead to revision of the current effluent 
guidelines discharge limitations or may be useful in the revision or 
reissuance of permits only.
    One commenter claimed the same environmental advantages over WBM as 
SBM with the use of enhanced mineral oil-based drilling fluids. EMO-
based drilling fluids are similar to the SBMs with respect to 
dispersion in water and concerns with applicability of the current 
sheen and toxicity tests. However, while the mysid shrimp water column 
toxicity test may give comparable results for the EMOs and some 
synthetics, several research papers indicate that recovery of cuttings 
piles contaminated with low toxicity mineral oils may not be much 
better than those contaminated with diesel, whereas those contaminated 
by synthetic materials recover significantly faster. In the absence of 
data on EMO contaminated cuttings and data indicating the differences 
between low toxicity mineral oil and EMO, the application of limits on 
the discharge of SBM cuttings according to the mysid shrimp toxicity 
test and the static sheen test confirmed by GC test for no free oil, is 
not applicable to the discharge of EMO cuttings. If the tests of 
benthic toxicity, bioaccumulation, and biodegradation, which are 
indicative of rate of recovery of the cuttings pile, show that the 
performance of EMOs are acceptable, then they may be considered for 
discharge of associated drilling fluids and cuttings. Another 
complication with the use of EMO is that, since EMOs are not a specific 
product as the synthetics are, but an assortment of molecules 
conforming to the distillation cut, their gas chromatograph (GC) 
fingerprint is in certain cases less distinct than that of the 
synthetics. Contamination by formation oil, crude, or diesel, may be 
more difficult to detect in these EMOs.

G. Implementation for NPDES Permit Writers

    EPA received numerous comments from operators in the Gulf of Mexico

[[Page 66123]]

coastal region claiming that they would need additional time to comply 
with the rule's zero discharge requirement for produced water. EPA 
recognizes that it may take some time for operators to determine the 
best and most cost effective mechanism of compliance and to implement 
that mechanism. EPA also recognizes that the NPDES permit issuing 
authority has discretion to use administrative orders to provide the 
requisite additional time to meet zero discharge.
    In making the determination regarding the additional time that may 
be appropriate and interim requirements that will be placed on 
facilities until compliance is achieved, the permit issuing authority 
should consider several factors, including, but not limited to, the 
following. First, operators may wish to do engineering and structural 
analysis of existing pipes and wells in order to make use of existing 
infra-structure. Second, there are several options available to 
facilities on a per-well or per-facility basis to comply with the zero 
discharge requirement, including injection, sending produced water 
offsite to a centralized waste treatment facility, or shutting in 
individual wells. Third, the facility's preferred approach may take 
into consideration the projected productive life of individual wells 
and their relative effect on the overall facility costs and impacts in 
determining the most cost-effective mix of options. Fourth, the permit 
issuing authority has the discretion to consider the relative impact of 
the available options when determining an appropriate compliance 
schedule. Finally, in establishing any interim limitations on 
discharges, the permit issuing authority should consider water quality 
impacts.

XV. Background Documents

    Major support for this regulation is detailed in two documents, 
each of which is supplemented by additional information and analyses in 
the rulemaking record. EPA's engineering foundation for the regulation 
is detailed in the ``Development Document for Final Effluent 
Limitations Guidelines and Standards for the Coastal Subcategory of the 
Oil and Gas Extraction Point Source Category'' EPA-821-R-96-023. EPA's 
economic analysis is presented in the ``Economic Impact Analysis of 
Final Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory of the Oil and Gas Extraction Point Source Category'' EPA-
821-R-96-022. Additionally, detailed responses to the public comments 
received on the proposed regulation and notices of data availability 
are presented in the document entitled ``Response to Public Comments on 
Effluent Limitations Guidelines and Standards for the Coastal 
Subcategory of the Oil and Gas Extraction Point Source Category,'' 
which is available in the public record. The public record for this 
rulemaking is available for review at EPA's Water Docket; 401 M Street, 
SW; Washington, DC. The room number is M2616 and the phone number is 
[phone].

List of Subjects in 40 CFR Part 435

    Environmental protection, Incorporation by reference, Oil and gas 
extraction, Pollution prevention, Waste treatment and disposal, Water 
pollution control.

    Dated: October 31, 1996.
Carol M. Browner,
Administrator.

Appendix A to the Preamble--Abbreviations, Acronyms, and Other Terms 
Used in This Document

Agency--U.S. Environmental Protection Agency
    BADCT--The best available demonstrated control technology, for 
new sources under section 306 of the CWA.
    BAT--The best available technology economically achievable, 
under section 304(b)(2)(B) of the CWA.

bbl--barrel, 42 U.S. gallons
bpd--barrels per day
bph--barrels per hour
bpy--barrels per year
BCT--Best conventional pollutant control technology under section 
304(b)(4)(B).
BMPs--Best management practices under section 304(e) of the CWA.
BOD--Biochemical oxygen demand.
BOE--Barrels of oil equivalent
BPT--Best practicable control technology currently available, under 
section 304(b)(1) of the Clean Water Act.
CFR--Code of Federal Regulations
Clean Water Act--Federal Water Pollution Control Act (33 U.S.C. 1251 
et seq.).
Coastal Development Document--Development Document for Final 
Effluent Limitations Guidelines and New Source Performance Standards 
for the Coastal Subcategory Of the Oil and Gas Extraction Point 
Source Category.
Conventional pollutants--Constituents of wastewater as determined by 
section 304(a)(4) of the Act, including, but not limited to, 
pollutants classified as biochemical oxygen demanding, suspended 
solids, oil and grease, fecal coliform, and pH.
CWA--Clean Water Act
Direct discharger--A facility that discharges or may discharge 
pollutants to waters of the United States.
DOE--U.S. Department of Energy
EIA--Economic Impact Analysis of Final Effluent Limitations 
Guidelines and Standards for the Coastal Subcategory of the Oil and 
Gas Extraction Point Source Category
EPA--U.S. Environmental Protection Agency
Indirect discharger--A facility that introduces wastewater into a 
publicly owned treatment works.
LC50--The estimated concentration of a test material lethal to 50 
percent of test organisms used in a specified type of toxicity test.
mg/l--milligrams per liter
Nonconventional pollutants--Pollutants that have not been designated 
as either conventional pollutants or toxic pollutants.
NORM--Naturally Occurring Radioactive Materials
NPDES--The National Pollutant Discharge Elimination System under 
section 402 of the CWA.
NPV--Net Present Value
NSPS--New source performance standards under section 306 of the CWA.
Offshore Guidelines--Final Effluent Limitations Guidelines and New 
Source Performance Standards for the Offshore Subcategory of the Oil 
and Gas Extraction Point Source Category
Offshore Development Document--Development Document for Effluent 
Limitations Guidelines and New Source Performance Standards for the 
Offshore Subcategory of the Oil and Gas Extraction Point Source 
Category
OMB--Office of Management and Budget
PAH--polynuclear aromatic hydrocarbons
POTW--Publicly Owned Treatment Works
ppm--parts per million
PSES--Pretreatment standards for existing sources of indirect 
discharges, under section 307(b) of the CWA.
PSNS--Pretreatment standards for new sources of indirect discharges, 
under sections 307 (b) and (c) of the CWA.
RRC--Railroad Commission of Texas
SIC--Standard Industrial Classification
SPP--Suspended particulate phase.
Toxic pollutants--A statutory term for the 65 pollutants and classes 
of pollutants designated under section 307(a) of the CWA.
TSS--Total Suspended Solids
UIC--Underground Injection Control program
U.S.C.--United States Code

    For the reasons set forth in the preamble, 40 CFR part 435 is 
amended as follows:

PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY

    1. The authority citation for part 435 continues to read as 
follows:

    Authority: (33 U.S.C. 1311, 1314, 1316, 1317, 1318 and 1361).


Subpart A  [Amended]

    2. Section 435.10 is revised to read as follows:


Sec. 435.10  Applicability; description of the offshore subcategory

    The provisions of this subpart are applicable to those facilities 
engaged in

[[Page 66124]]

field exploration, drilling, well production, and well treatment in the 
oil and gas industry which are located in waters that are seaward of 
the inner boundary of the territorial seas (``offshore'') as defined in 
section 502(g) of the Clean Water Act.
    3. Section 435.11 is revised to read as follows:


Sec. 435.11  Specialized definitions.

    For the purpose of this subpart:
    (a) Except as provided below, the general definitions, 
abbreviations and methods of analysis set forth in 40 CFR part 401 
shall apply to this subpart.
    (b) The term average of daily values for 30 consecutive days shall 
be the average of the daily values obtained during any 30 consecutive 
day period.
    (c) The term daily values as applied to produced water effluent 
limitations and NSPS shall refer to the daily measurements used to 
assess compliance with the maximum for any one day.
    (d) The term deck drainage shall refer to any waste resulting from 
deck washings, spillage, rainwater, and runoff from gutters and drains 
including drip pans and work areas within facilities subject to this 
subpart. Within the definition of deck drainage for the purpose of this 
subpart, the term rainwater for those facilities located on land is 
limited to that precipitation runoff that reasonably has the potential 
to come into contact with process wastewater. Runoff not included in 
the deck drainage definition would be subject to control as storm water 
under 40 CFR 122.26. For structures located over water, all runoff is 
included in the deck drainage definition.
    (e) The term development facility shall mean any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
productive wells.
    (f) The term diesel oil shall refer to the grade of distillate fuel 
oil, as specified in the American Society for Testing and Materials 
Standard Specification for Diesel Fuel Oils D975-91, that is typically 
used as the continuous phase in conventional oil-based drilling fluids. 
This incorporation by reference was approved by the Director of the 
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. 
Copies may be obtained from the American Society for Testing and 
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be 
inspected at the Office of the Federal Register, 800 North Capitol 
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at 
EPA's Water Docket; Room M2616, 401 M Street SW, Washington, DC 20460.
    (g) The term domestic waste shall refer to materials discharged 
from sinks, showers, laundries, safety showers, eye-wash stations, 
hand-wash stations, fish cleaning stations, and galleys located within 
facilities subject to this subpart.
    (h) The term drill cuttings shall refer to the particles generated 
by drilling into subsurface geologic formations and carried to the 
surface with the drilling fluid.
    (i) The term drilling fluid refers to the circulating fluid (mud) 
used in the rotary drilling of wells to clean and condition the hole 
and to counterbalance formation pressure. The four classes of drilling 
fluids are:
    (1) A water-based drilling fluid has water as the continuous phase 
and the suspending medium for solids, whether or not oil is present.
    (2) An oil-based drilling fluid has diesel oil, mineral oil, or 
some other oil, but neither a synthetic material nor enhanced mineral 
oil, as its continuous phase with water as the dispersed phase.
    (3) An enhanced mineral oil-based drilling fluid has an enhanced 
mineral oil as its continuous phase with water as the dispersed phase.
    (4) A synthetic-based drilling fluid has a synthetic material as 
its continuous phase with water as the dispersed phase.
    (j) The term enhanced mineral oil as applied to enhanced mineral 
oil-based drilling fluid means a petroleum distillate which has been 
highly purified and is distinguished from diesel oil and conventional 
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH) 
content. Typically, conventional mineral oils have a PAH content on the 
order of 0.35 weight percent expressed as phenanthrene, whereas 
enhanced mineral oils typically have a PAH content of 0.001 or lower 
weight percent PAH expressed as phenanthrene.
    (k) The term exploratory facility shall mean any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
wells to determine the nature of potential hydrocarbon reservoirs.
    (l) The term maximum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall mean the maximum 
concentration allowed as measured in any single sample of the barite.
    (m) The term maximum for any one day as applied to BPT, BCT and BAT 
effluent limitations and NSPS for oil and grease in produced water 
shall mean the maximum concentration allowed as measured by the average 
of four grab samples collected over a 24-hour period that are analyzed 
separately. Alternatively, for BAT and NSPS the maximum concentration 
allowed may be determined on the basis of physical composition of the 
four grab samples prior to a single analysis.
    (n) The term minimum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of the 
discharged waste stream. The term minimum as applied to BPT and BCT 
effluent limitations and NSPS for sanitary wastes shall mean the 
minimum concentration value allowed as measured in any single sample of 
the discharged waste stream.
    (o) The term M9IM shall mean those offshore facilities continuously 
manned by nine (9) or fewer persons or only intermittently manned by 
any number of persons.
    (p) The term M10 shall mean those offshore facilities continuously 
manned by ten (10) or more persons.
    (q) The term new source means any facility or activity of this 
subcategory that meets the definition of ``new source'' under 40 CFR 
122.2 and meets the criteria for determination of new sources under 40 
CFR 122.29(b) applied consistently with all of the following 
definitions:
    (1) The term water area as used in the term ``site'' in 40 CFR 
122.29 and 122.2 shall mean the water area and ocean floor beneath any 
exploratory, development, or production facility where such facility is 
conducting its exploratory, development or production activities.
    (2) The term significant site preparation work as used in 40 CFR 
122.29 shall mean the process of surveying, clearing or preparing an 
area of the ocean floor for the purpose of constructing or placing a 
development or production facility on or over the site. ``New Source'' 
does not include facilities covered by an existing NPDES permit 
immediately prior to the effective date of these guidelines pending EPA 
issuance of a new source NPDES permit.
    (r) The term no discharge of free oil shall mean that waste streams 
may not be discharged when they would cause a film or sheen upon or a 
discoloration of the surface of the receiving water or fail the static 
sheen test defined in Appendix 1 to 40 CFR part 435, subpart A.
    (s) The term produced sand shall refer to slurried particles used 
in hydraulic fracturing, the accumulated formation sands and scales 
particles generated during production.

[[Page 66125]]

    Produced sand also includes desander discharge from the produced 
water waste stream, and blowdown of the water phase from the produced 
water treating system.
    (t) The term produced water shall refer to the water (brine) 
brought up from the hydrocarbon-bearing strata during the extraction of 
oil and gas, and can include formation water, injection water, and any 
chemicals added downhole or during the oil/water separation process.
    (u) The term production facility shall mean any fixed or mobile 
structure subject to this subpart that is either engaged in well 
completion or used for active recovery of hydrocarbons from producing 
formations.
    (v) The term sanitary waste shall refer to human body waste 
discharged from toilets and urinals located within facilities subject 
to this subpart.
    (w) The term static sheen test shall refer to the standard test 
procedure that has been developed for this industrial subcategory for 
the purpose of demonstrating compliance with the requirement of no 
discharge of free oil. The methodology for performing the static sheen 
test is presented in appendix 1 to 40 CFR part 435, subpart A.
    (x) The term synthetic material as applied to synthetic-based 
drilling fluid means material produced by the reaction of specific 
purified chemical feedstock, as opposed to the traditional base fluids 
such as diesel and mineral oil which are derived from crude oil solely 
through physical separation processes. Physical separation processes 
include fractionation and distillation and/or minor chemical reactions 
such as cracking and hydro processing. Since they are synthesized by 
the reaction of purified compounds, synthetic materials suitable for 
use in drilling fluids are typically free of polycyclic aromatic 
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH 
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha 
olefins) and vegetable esters are two examples of synthetic materials 
used by the oil and gas extraction industry in formulating drilling 
fluids. Poly(alpha olefins) are synthesized from the polymerization 
(dimerization, trimerization, tetramerization, and higher 
oligomerization) of purified straight-chain hydrocarbons such as 
C6-C14 alpha olefins. Vegetable esters are synthesized from 
the acid-catalyzed esterification of vegetable fatty acids with various 
alcohols. The mention of these two branches of synthetic fluid base 
materials is to provide examples, and is not meant to exclude other 
synthetic materials that are either in current use or may be used in 
the future. A synthetic-based drilling fluid may include a combination 
of synthetic materials.
    (y) The term toxicity as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall refer to the bioassay 
test procedure presented in Appendix 2 of 40 CFR part 435, subpart A.
    (z) The term well completion fluids shall refer to salt solutions, 
weighted brines, polymers, and various additives used to prevent damage 
to the well bore during operations which prepare the drilled well for 
hydrocarbon production.
    (aa) The term well treatment fluids shall refer to any fluid used 
to restore or improve productivity by chemically or physically altering 
hydrocarbon-bearing strata after a well has been drilled.
    (bb) The term workover fluids shall refer to salt solutions, 
weighted brines, polymers, or other specialty additives used in a 
producing well to allow for maintenance, repair or abandonment 
procedures.
    (cc) The term 96-hour LC50 shall refer to the concentration (parts 
per million) or percent of the suspended particulate phase (SPP) from a 
sample that is lethal to 50 percent of the test organisms exposed to 
that concentration of the SPP after 96 hours of constant exposure.
    4. Subpart D is revised to read as follows:

Subpart D--Coastal Subcategory

Sec.
435.40  Applicability; description of the coastal subcategory.
435.41  Specialized definitions.
435.42  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).
435.43  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
available technology economically achievable (BAT).
435.44  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
conventional pollutant control technology (BCT).
435.45  Standards of performance for new sources (NSPS).
435.46  Pretreatment Standards of performance for existing sources 
(PSES).
435.47  Pretreatment Standards of performance for new sources 
(PSNS).

Subpart D--Coastal Subcategory


Sec. 435.40  Applicability; description of the coastal subcategory.

    The provisions of this subpart are applicable to those facilities 
engaged in field exploration, drilling, well production, and well 
treatment in the oil and gas industry in areas defined as ``coastal.'' 
The term ``coastal'' shall mean:
    (a) Any location in or on a water of the United States landward of 
the inner boundary of the territorial seas; or
    (b) (1) Any location landward from the inner boundary of the 
territorial seas and bounded on the inland side by the line defined by 
the inner boundary of the territorial seas eastward of the point 
defined by 89 deg.45' West Longitude and 29 deg.46' North Latitude and 
continuing as follows west of that point:

------------------------------------------------------------------------
       Direction to west  longitude         Direction to north  latitude
------------------------------------------------------------------------
West, 89 deg.48'..........................  North, 29 deg.50'.          
West, 90 deg.12'..........................  North, 30 deg.06'.          
West, 90 deg.20'..........................  South, 29 deg.35'.          
West, 90 deg.35'..........................  South, 29 deg.30'.          
West, 90 deg.43'..........................  South, 29 deg.25'.          
West, 90 deg.57'..........................  North, 29 deg.32'.          
West, 91 deg.02'..........................  North, 29 deg.40'.          
West, 91 deg.14'..........................  South, 29 deg.32'.          
West, 91 deg.27'..........................  North, 29 deg.37'.          
West, 91 deg.33'..........................  North, 29 deg.46'.          
West, 91 deg.46'..........................  North, 29 deg.50'.          
West, 91 deg.50'..........................  North, 29 deg.55'.          
West, 91 deg.56'..........................  South, 29 deg.50'.          
West, 92 deg.10'..........................  South, 29 deg.44'.          
West, 92 deg.55'..........................  North, 29 deg.46'.          
West, 93 deg.15'..........................  North, 30 deg.14'.          
West, 93 deg.49'..........................  South, 30 deg.07'.          
West, 94 deg.03'..........................  South, 30 deg.03'.          
West, 94 deg.10'..........................  South, 30 deg.00'.          
West, 94 deg.20'..........................  South, 29 deg.53'.          
West, 95 deg.00'..........................  South, 29 deg.35'.          
West, 95 deg.13'..........................  South, 29 deg.28'.          
East, 95 deg.08'..........................  South, 29 deg.15'.          
West, 95 deg.11'..........................  South, 29 deg.08'.          
West, 95 deg.22'..........................  South, 28 deg.56'.          
West, 95 deg.30'..........................  South, 28 deg.55'.          
West, 95 deg.33'..........................  South, 28 deg.49'.          
West, 95 deg.40'..........................  South, 28 deg.47'.          
West, 96 deg.42'..........................  South, 28 deg.41'.          
East, 96 deg.40'..........................  South, 28 deg.28'.          
West, 96 deg.54'..........................  South, 28 deg.20'.          
West, 97 deg.03'..........................  South, 28 deg.13'.          
West, 97 deg.15'..........................  South, 27 deg.58'.          
West, 97 deg.40'..........................  South, 27 deg.45'.          
West, 97 deg.46'..........................  South, 27 deg.28'.          
West, 97 deg.51'..........................  South, 27 deg.22'.          
East, 97 deg.46'..........................  South, 27 deg.14'.          
East, 97 deg.30'..........................  South, 26 deg.30'.          
East, 97 deg.26'..........................  South, 26 deg.11'.          
------------------------------------------------------------------------

    (2) East to 97 deg.19' West Longitude and Southward to the U.S.-
Mexican border.


Sec. 435.41  Specialized definitions.

    For the purpose of this subpart:
    (a) Except as provided below, the general definitions, 
abbreviations and

[[Page 66126]]

methods of analysis set forth in 40 CFR part 401 shall apply to this 
subpart.
    (b) The term average of daily values for 30 consecutive days shall 
be the average of the daily values obtained during any 30 consecutive 
day period.
    (c) The term ``Cook Inlet'' refers to coastal locations north of 
the line between Cape Douglas on the West and Port Chatham on the east.
    (d) The term daily values as applied to produced water effluent 
limitations and NSPS shall refer to the daily measurements used to 
assess compliance with the maximum for any one day.
    (e) The term deck drainage shall refer to any waste resulting from 
deck washings, spillage, rainwater, and runoff from gutters and drains 
including drip pans and work areas within facilities subject to this 
subpart.
    (f) The term development facility shall mean any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
productive wells.
    (g) The term dewatering effluent means wastewater from drilling 
fluids and drill cuttings dewatering activities (including but not 
limited to reserve pits or other tanks or vessels, and chemical or 
mechanical treatment occurring during the drilling solids separation/
recycle/disposal process).
    (h) The term diesel oil shall refer to the grade of distillate fuel 
oil, as specified in the American Society for Testing and Materials 
Standard Specification for Diesel Fuel Oils D975-91, that is typically 
used as the continuous phase in conventional oil-based drilling fluids. 
This incorporation by reference was approved by the Director of the 
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. 
Copies may be obtained from the American Society for Testing and 
Materials, 1916 Race Street, Philadelphia, PA 19103. Copies may be 
inspected at the Office of the Federal Register, 800 North Capitol 
Street, NW., Suite 700, Washington, DC. A copy may also be inspected at 
EPA's Water Docket; Room M2616, 401 M Street SW., Washington, DC 20460.
    (i) The term domestic waste shall refer to materials discharged 
from sinks, showers, laundries, safety showers, eye-wash stations, 
hand-wash stations, fish cleaning stations, and galleys located within 
facilities subject to this subpart.
    (j) The term drill cuttings shall refer to the particles generated 
by drilling into subsurface geologic formations and carried to the 
surface with the drilling fluid.
    (k) The term drilling fluid refers to the circulating fluid (mud) 
used in the rotary drilling of wells to clean and condition the hole 
and to counterbalance formation pressure. The four classes of drilling 
fluids are:
    (1) A water-based drilling fluid has water as the continuous phase 
and the suspending medium for solids, whether or not oil is present.
    (2) An oil-based drilling fluid has diesel oil, mineral oil, or 
some other oil, but neither a synthetic material nor enhanced mineral 
oil, as its continuous phase with water as the dispersed phase.
    (3) An enhanced mineral oil-based drilling fluid has an enhanced 
mineral oil as its continuous phase with water as the dispersed phase.
    (4) A synthetic-based drilling fluid has a synthetic material as 
its continuous phase with water as the dispersed phase.
    (l) The term enhanced mineral oil as applied to enhanced mineral 
oil-based drilling fluid means a petroleum distillate which has been 
highly purified and is distinguished from diesel oil and conventional 
mineral oil in having a lower polycyclic aromatic hydrocarbon (PAH) 
content. Typically, conventional mineral oils have a PAH content on the 
order of 0.35 weight percent expressed as phenanthrene, whereas 
enhanced mineral oils typically have a PAH content of 0.001 or lower 
weight percent PAH expressed as phenanthrene.
    (m) The term exploratory facility shall mean any fixed or mobile 
structure subject to this subpart that is engaged in the drilling of 
wells to determine the nature of potential hydrocarbon reservoirs.
    (n) The term garbage means all kinds of victual, domestic, and 
operational waste, excluding fresh fish and parts thereof, generated 
during the normal operation of coastal oil and gas facility and liable 
to be disposed of continuously or periodically, except dishwater, 
graywater, and those substances that are defined or listed in other 
Annexes to MARPOL 73/78. A copy of MARPOL may be inspected at EPA's 
Water Docket; Room M2616, 401 M Street SW, Washington, DC 20460.
    (o) The term maximum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall mean the maximum 
concentration allowed as measured in any single sample of the barite.
    (p) The term maximum for any one day as applied to BPT, BCT and BAT 
effluent limitations and NSPS for oil and grease in produced water 
shall mean the maximum concentration allowed as measured by the average 
of four grab samples collected over a 24-hour period that are analyzed 
separately. Alternatively, for BAT and NSPS, the maximum concentration 
allowed may be determined on the basis of physical composition of the 
four grab samples prior to a single analysis.
    (q) The term minimum as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall mean the minimum 96-
hour LC50 value allowed as measured in any single sample of the 
discharged waste stream. The term minimum as applied to BPT and BCT 
effluent limitations and NSPS for sanitary wastes shall mean the 
minimum concentration value allowed as measured in any single sample of 
the discharged waste stream.
    (r) The term M9IM shall mean those coastal facilities continuously 
manned by nine (9) or fewer persons or only intermittently manned by 
any number of persons.
    (s) The term M10 shall mean those coastal facilities continuously 
manned by ten (10) or more persons.
    (t) (1) The term new source means any facility or activity of this 
subcategory that meets the definition of ``new source'' under 40 CFR 
122.2 and meets the criteria for determination of new sources under 40 
CFR 122.29(b) applied consistently with all of the following 
definitions:
    (i) The term water area as used in the term ``site'' in 40 CFR 
122.29 and 122.2 shall mean the water area and water body floor beneath 
any exploratory, development, or production facility where such 
facility is conducting its exploratory, development or production 
activities.
    (ii) The term significant site preparation work as used in 40 CFR 
122.29 shall mean the process of surveying, clearing or preparing an 
area of the water body floor for the purpose of constructing or placing 
a development or production facility on or over the site.
    (2) ``New Source'' does not include facilities covered by an 
existing NPDES permit immediately prior to the effective date of these 
guidelines pending EPA issuance of a new source NPDES permit.
    (u) The term no discharge of free oil shall mean that waste streams 
may not be discharged when they would cause a film or sheen upon or a 
discoloration of the surface of the receiving water or fail the static 
sheen test defined in appendix 1 to 40 CFR part 435, subpart A.
    (v) The term produced sand shall refer to slurried particles used 
in hydraulic fracturing, the accumulated formation sands and scales 
particles generated during production. Produced sand also includes 
desander discharge from the produced water waste stream,

[[Page 66127]]

and blowdown of the water phase from the produced water treating 
system.
    (w) The term produced water shall refer to the water (brine) 
brought up from the hydrocarbon-bearing strata during the extraction of 
oil and gas, and can include formation water, injection water, and any 
chemicals added downhole or during the oil/water separation process.
    (x) The term production facility shall mean any fixed or mobile 
structure subject to this subpart that is either engaged in well 
completion or used for active recovery of hydrocarbons from producing 
formations. It includes facilities that are engaged in hydrocarbon 
fluids separation even if located separately from wellheads.
    (y) The term sanitary waste shall refer to human body waste 
discharged from toilets and urinals located within facilities subject 
to this subpart.
    (y) The term static sheen test shall refer to the standard test 
procedure that has been developed for this industrial subcategory for 
the purpose of demonstrating compliance with the requirement of no 
discharge of free oil. The methodology for performing the static sheen 
test is presented in appendix 1 to 40 CFR part 435, subpart A.
    (z) The term synthetic material as applied to synthetic-based 
drilling fluid means material produced by the reaction of specific 
purified chemical feedstock, as opposed to the traditional base fluids 
such as diesel and mineral oil which are derived from crude oil solely 
through physical separation processes. Physical separation processes 
include fractionation and distillation and/or minor chemical reactions 
such as cracking and hydro processing. Since they are synthesized by 
the reaction of purified compounds, synthetic materials suitable for 
use in drilling fluids are typically free of polycyclic aromatic 
hydrocarbons (PAH's) but are sometimes found to contain levels of PAH 
up to 0.001 weight percent PAH expressed as phenanthrene. Poly(alpha 
olefins) and vegetable esters are two examples of synthetic used by the 
oil and gas extraction industry in formulating drilling fluids. 
Poly(alpha olefins) are synthesized from the polymerization 
(dimerization, trimerization, tetramerization, and higher 
oligomerization) of purified straight-chain hydrocarbons such as 
C6-C14 alpha olefins. Vegetable esters are synthesized from 
the acid-catalyzed esterification of vegetable fatty acids with various 
alcohols. The mention of these two branches of synthetic fluid base 
materials is to provide examples, and is not meant to exclude other 
synthetic materials that are either in current use or may be used in 
the future. A synthetic-based drilling fluid may include a combination 
of synthetic materials.
    (aa) The term toxicity as applied to BAT effluent limitations and 
NSPS for drilling fluids and drill cuttings shall refer to the bioassay 
test procedure presented in appendix 2 of 40 CFR part 435, subpart A.
    (bb) The term well completion fluids shall refer to salt solutions, 
weighted brines, polymers, and various additives used to prevent damage 
to the well bore during operations which prepare the drilled well for 
hydrocarbon production.
    (cc) The term well treatment fluids shall refer to any fluid used 
to restore or improve productivity by chemically or physically altering 
hydrocarbon-bearing strata after a well has been drilled.
    (dd) The term workover fluids shall refer to salt solutions, 
weighted brines, polymers, or other specialty additives used in a 
producing well to allow for maintenance, repair or abandonment 
procedures.
    (ee) The term 96-hour LC50 shall refer to the concentration (parts 
per million) or percent of the suspended particulate phase (SPP) from a 
sample that is lethal to 50 percent of the test organisms exposed to 
that concentration of the SPP after 96 hours of constant exposure.


Sec. 435.42  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).

    Except as provided in 40 CFR 125.30-125.32, any existing point 
source subject to this Subpart must achieve the following effluent 
limitations representing the degree of effluent reduction attainable by 
the application of the best practicable control technology currently 
available.

                                    BPT Effluent Limitations--Oil and Grease                                    
                                            [In milligrams per liter]                                           
----------------------------------------------------------------------------------------------------------------
                                                                                                       Residual 
                                                                         Average of values for 30      chlorine 
   Pollutant parameter waste source         Maximum for any 1 day       consecutive days shall not   minimum for
                                                                                  exceed              any 1 day 
----------------------------------------------------------------------------------------------------------------
Produced water........................  72...........................  48..........................           NA
Deck drainage.........................  (\1\)........................  (\1\).......................           NA
Drilling fluid........................  (\1\)........................  (\1\).......................           NA
Drill cuttings........................  (\1\)........................  (\1\).......................           NA
Well treatment, workover, and           (\1\)........................  (\1\).......................           NA
 completion fluids.                                                                                             
Sanitary:                                                                                                       
    M10...............................  NA...........................  NA..........................        \2\ 1
    M9IM \3\..........................  NA...........................  NA..........................           NA
    Domestic \3\......................  NA...........................  NA..........................           NA
    Produced sand.....................  Zero discharge...............  Zero discharge..............          NA 
----------------------------------------------------------------------------------------------------------------
\1\ No discharge of free oil.                                                                                   
\2\ Minimum of 1 mg/l and maintained as close to this concentration as possible.                                
\3\ There shall be no floating solids as a result of the discharge of these wastes.                             

Sec. 435.43  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best available 
technology economically achievable (BAT).

    Except as provided in 40 CFR 125.30-125.32, any existing point 
source subject to this Subpart must achieve the following effluent 
limitations representing the degree of effluent reduction attainable by 
the application of the best available technology economically 
achievable (BAT):

[[Page 66128]]



                        BAT Effluent Limitations                        
------------------------------------------------------------------------
                                       Pollutant         BAT effluent   
             Stream                    parameter          limitations   
------------------------------------------------------------------------
Produced Water:                                                         
    (A) All coastal areas except  ..................  No discharge.     
     Cook Inlet.                                                        
    (B) Cook Inlet..............  Oil & Grease......  The maximum for   
                                                       any one day shall
                                                       not exceed 42 mg/
                                                       l, and the 30-day
                                                       average shall not
                                                       exceed 29 mg/l.  
Drilling Fluids, Drill Cuttings,                                        
 and Dewatering Effluent: \1\                                           
    (A) All coastal areas except  ..................  No discharge.     
     Cook Inlet.                                                        
                                  Free Oil \2\......  No discharge.     
                                  Diesel Oil........  No discharge.     
    (B) Cook Inlet..............  Mercury...........  1 mg/kg dry weight
                                                       maximum in the   
                                                       stock barite.    
                                  Cadmium...........  3 mg/kg dry weight
                                                       maximum in the   
                                                       stock barite.    
                                  Toxicity..........  Minimum 96-hour   
                                                       LC50 of the SPP  
                                                       shall be 3       
                                                       percent by volume
                                                       \4\.             
Well Treatment, Workover and                                            
 Completion Fluids:                                                     
    (A) All coastal areas except  ..................  No discharge.     
     Cook Inlet.                                                        
    (B) Cook Inlet..............  Oil and Grease....  The maximum for   
                                                       any one day shall
                                                       not exceed 42 mg/
                                                       l, and the 30-day
                                                       average shall not
                                                       exceed 29 mg/l.  
    Produced Sand...............  ..................  No discharge.     
    Deck Drainage...............  Free Oil \3\......  No discharge.     
    Domestic Waste..............  Foam..............  No discharge.     
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable              
  prospectively. BCT limitations in this rule are not applicable to     
  discharges of dewatering effluent from reserve pits which as of the   
  effective date of this rule no longer receive drilling fluids and     
  drill cuttings. Limitations on such discharges shall be determined by 
  the NPDES permit issuing authority.                                   
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR    
  part 435, subpart A).                                                 
\3\ As determined by the presence of a film or sheen upon or a          
  discoloration of the surface of the receiving water (visual sheen).   
\4\ As determined by the toxicity test (see appendix 2 of 40 CFR part   
  435, subpart A).                                                      

Sec. 435.44  Effluent limitations guidelines representing the degree of 
effluent reduction attainable by the application of the best 
conventional pollutant control technology (BCT).

    Except as provided in 40 CFR 125.30-125.32, any existing point 
source subject to this Subpart must achieve the following effluent 
limitations representing the degree of effluent reduction attainable by 
the application of the best conventional pollutant control technology 
(BCT):

                        BCT Effluent Limitations                        
------------------------------------------------------------------------
                                       Pollutant         BCT effluent   
             Stream                    parameter          limitations   
------------------------------------------------------------------------
Produced Water (all facilities).  Oil & Grease......  The maximum for   
                                                       any one day shall
                                                       not exceed 72 mg/
                                                       l and the 30-day 
                                                       average shall not
                                                       exceed 48 mg/l.  
Drilling Fluids and Drill                                               
 Cuttings and Dewatering                                                
 Effluent:\1\                                                           
    All facilities except Cook    ..................  No discharge.     
     Inlet.                                                             
    Cook Inlet..................  Free Oil..........  No discharge.\2\  
Well Treatment, Workover and      Free Oil..........  No discharge.\2\  
 Completion Fluids.                                                     
Produced Sand...................  ..................  No discharge.     
Deck Drainage...................  Free Oil..........  No discharge.\3\  
Sanitary Waste:                                                         
    Sanitary M10................  Residual Chlorine.  Minimum of 1 mg/l 
                                                       maintained as    
                                                       close to this    
                                                       concentration as 
                                                       possible.        
    Sanitary M91M...............  Floating Solids...  No discharge.     
Domestic Waste..................  Floating Solids     No discharge of   
                                   and garbage.        Floating Solids  
                                                       or garbage.\4\   
------------------------------------------------------------------------
\1\ BCT limitations for dewatering effluent are applicable              
  prospectively. BCT limitations in this rule are not applicable to     
  discharges of dewatering effluent from reserve pits which as of the   
  effective date of this rule no longer receive drilling fluids and     
  drill cuttings. Limitations on such discharges shall be determined by 
  the NPDES permit issuing authority.                                   
\2\ As determined by the static sheen test (see appendix 1 to 40 CFR    
  part 435, subpart A).                                                 
\3\ As determined by the presence of a film or sheen upon or a          
  discoloration of the surface of the receiving water (visual sheen).   
\4\ As determined by the toxicity test (see appendix 2 of 40 CFR part   
  435, subpart A).                                                      

Sec. 435.45  Standards of performance for new sources (NSPS).

    Any new source subject to this subpart must achieve the following 
new source performance standards (NSPS):

[[Page 66129]]



                        NSPS Effluent Limitations                       
------------------------------------------------------------------------
                                       Pollutant         NSPS effluent  
             Stream                    parameter          limitations   
------------------------------------------------------------------------
Produced Water (all facilities).  ..................  No discharge.     
Drilling Fluids and Drill                                               
 Cuttings and Dewatering                                                
 Effluent: \1\                                                          
    (A) All coastal areas except  ..................  No discharge.     
     Cook Inlet.                                                        
    (B) Cook Inlet..............  Free Oil \1\......  No discharge.     
                                  Diesel Oil........  No discharge.     
                                  Mercury...........  1 mg/kg dry weight
                                                       maximum in the   
                                                       stock barite; 3  
                                                       mg/kg dry weight 
                                                       maximum in the   
                                                       stock barite.    
                                  Cadmium...........  Minimum 96-hour   
                                                       LC50 of the SPP  
                                                       shall be 3       
                                                       percent by       
                                                       volume.\3\       
                                  Toxicity..........                    
Well Treatment, Workover and                                            
 Completion Fluids:                                                     
    (A) All coastal areas except  ..................  No discharge.     
     Cook Inlet.                                                        
    (B) Cook Inlet..............  Oil and Grease....  The maximum for   
                                                       any one day shall
                                                       not exceed 42 mg/
                                                       l, and the 30-day
                                                       average shall not
                                                       exceed 29 mg/l.  
Produced Sand...................  ..................  No discharge.     
Deck Drainage...................  Free Oil \2\......  No discharge.     
Sanitary Waste:                                                         
    Sanitary M10................  Residual Chlorine.  Minimum of 1 mg/l 
                                                       and maintained as
                                                       close to this    
                                                       concentration as 
                                                       possible.        
    Sanitary M91M...............  Floating Solids...  No discharge.     
Domestic Waste..................  Floating Solids,    No discharge of   
                                   Garbage \4\ and     floating solids  
                                   Foam.               or garbage or    
                                                       foam.            
------------------------------------------------------------------------
\1\ BAT limitations for dewatering effluent are applicable              
  prospectively. BAT limitations in this rule are not applicable to     
  discharges of dewatering effluent from reserve pits which as of the   
  effective date of this rule no longer receive drilling fluids and     
  drill cuttings. Limitations on such discharges shall be determined by 
  the NPDES permit issuing authority.                                   
\2\ As determined by the static sheen test (see Appendix 1 to 40 CFR    
  part 435, subpart A).                                                 
\3\ As determined by the presence of a film or sheen upon or a          
  discoloration of the surface of the receiving water (visual sheen).   
\4\ As determined by the toxicity test (see Appendix 2 of 40 CFR part   
  435, subpart A).                                                      
\5\ As defined in 40 CFR 435.41(1).                                     

Sec. 435.46  Pretreatment Standards of Performance for Existing Sources 
(PSES)

    Except as provided in 40 CFR 403.7 and 403.13, any existing source 
with discharges subject to this subpart that introduces pollutants into 
a publicly owned treatment works must comply with 40 CFR part 403 and 
achieve the following pretreatment standards for existing sources 
(PSES).

                        PSES Effluent Limitations                       
------------------------------------------------------------------------
                                     Pollutant         PSES effluent    
             Stream                  parameter          limitations     
------------------------------------------------------------------------
Produced Water..................  ...............  No discharge.        
Drilling Fluids and Drill                                               
 Cuttings Well Treatment.                                               
Workover and Completion Fluids..  ...............  No discharge.        
Produced Sand...................  ...............  No discharge.        
Deck Drainage...................  ...............  No discharge.        
------------------------------------------------------------------------

Sec. 435.47  Pretreatment Standards of performance for new sources 
(PSNS)

    Except as provided in 40 CFR 403.7 and 403.13, any new source with 
discharges subject to this subpart that introduces pollutants into a 
publicly owned treatment works must comply with 40 CFR part 403 and 
achieve the following pretreatment standards for new sources (PSNS).

                        PSNS Effluent Limitations                       
------------------------------------------------------------------------
                                       Pollutant         PSNS effluent  
             Stream                    parameter          limitations   
------------------------------------------------------------------------
Produced Water (all facilities).  ..................  No discharge.     
Drilling fluids and Drill         ..................  No discharge.     
 Cuttings.                                                              
Well Treatment, Workover and      ..................  No discharge.     
 Completion Fluids.                                                     
Produced Sand...................  ..................  No discharge.     
Deck Drainage...................  ..................  No discharge.     
------------------------------------------------------------------------

    5. Subpart G consisting of Sec. 435.10 is added to read as follows:

Subpart G--General Provisions


Sec. 435.10  Applicability.

    (a) Purpose. This subpart is intended to prevent oil and gas 
facilities, for which effluent limitations guidelines and standards, 
new source performance standards, or pretreatment standards have been 
promulgated under this part, from circumventing the effluent 
limitations guidelines and standards applicable to those facilities by 
moving effluent produced in one subcategory to another subcategory for 
disposal under less stringent requirements than intended by this part.
    (b) Applicability. The effluent limitations and standards 
applicable to an oil and gas facility shall be determined as follows:
    (1) An Oil and Gas facility, operator, or its agent or contractor 
may move its wastewaters from a facility located in one subcategory to 
another subcategory for treatment and return it to a location covered 
by the original subcategory for disposal. In such case, the effluent 
limitations guidelines, new source performance standards, or 
pretreatment standards for the original subcategory apply.
    (2) An Oil and Gas facility, operator, or its agent or contractor 
may move its wastewaters from a facility located in one subcategory to 
another subcategory for disposal or treatment and disposal, provided:
    (i) If an Oil and Gas facility, operator or its agent or contractor 
moves

[[Page 66130]]

wastewaters from a wellhead located in one subcategory to another 
subcategory where oil and gas facilities are governed by less stringent 
effluent limitations guidelines, new source performance standards, or 
pretreatment standards, the more stringent effluent limitations 
guidelines, new source performance standards, or pretreatment standards 
applicable to the subcategory where the wellhead is located shall 
apply.
    (ii) If an Oil and Gas facility, operator or its agent moves 
effluent from a wellhead located in one subcategory to another 
subcategory where oil and gas facilities are governed by more stringent 
effluent limitations guidelines, new source performance standards, or 
pretreatment standards, the more stringent effluent limitations 
guidelines, new source performance standards, or pretreatment standards 
applicable at the point of discharge shall apply.

[FR Doc. 96-28659 Filed 12-13-96; 8:45 am]
BILLING CODE 6560-50-P