§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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CHAPTER CONTENTS

C1-1 Cost Categories . . . . . . . . . . . . . . . . . . . . . . . . . C1-1

C1-1.1 Cost of Installing and Operating

Compliance Technology . . . . . . . . . . . . C1-1

C1-1.2 Administrative Costs for Complying 

Facilities . . . . . . . . . . . . . . . . . . . . . . . . C1-3

C1-2 Key Elements of the Economic Analysis for New

Offshore Oil and Gas Extraction Facilities . . . . C1-7

C1-2.1 Compliance Schedule . . . . . . . . . . . . . . C1-7

C1-2.2 Adjusting Monetary Values to a

Common Time Period of Analysis . . . . C1-8

C1-2.3 Discounting and Annualization – 

Costs to Society or Societal Costs . . . . . C1-9

C1-2.4 Discounting and Annualization – 

Costs to Complying Facilities . . . . . . . C1-11

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C1-13

Chapter C1: Summary of Cost Categories

and Key Analysis Elements for New Offshore

Oil and Gas Extraction Facilities

INTRODUCTION

This chapter presents an overview of the cost

categories and certain elements of the analytic

framework that are common to the economic analyses

of the two major industry segments covered by the

proposed standards for new Offshore Oil and Gas

Extraction facilities: mobile offshore drilling units

(MODUs) and oil and gas production platforms or

structures.

C1-1 COST CATEGORIES

In its analyses of the costs and economic impacts of

the proposed rule on new oil and gas extraction

facilities, EPA considered three categories of costs:

< costs of installing and operating compliance technology,

< administrative costs incurred by complying facilities, and

< administrative costs incurred by permitting authorities.

In contrast to the analysis conducted for the Manufacturing and Electric Generating industry segments (see also

Chapter B1), EPA assumed that no downtime would be associated with installing or maintaining CWIS

technologies for new offshore oil and gas extraction facilities, for two reasons. First, new facilities do not have to

retrofit equipment; the equipment is built to specification and installed before the facility begins operations. 

Second, even the maintenance of CWISs should not result in downtime in the oil and gas industry, since MODUs

are hauled out on a regular basis for other types of maintenance activities, and production platforms are shut in

one to two times per year for other maintenance, making incremental downtime due to CWIS maintenance

unlikely (see the Technical Development Document for the Proposed Section 316(b) Phase III Rule (hereafter

referred to as the “Phase III Technical Development Document”; U.S. EPA, 2004b).

Subsection C1-1.1 provides an overview of the three cost categories included in the analysis for new offshore oil

and gas extraction facilities, addressing those aspects of each category that are relevant to the oil and gas industry. 

Table C1-1 summarizes the type of new offshore oil and gas extraction facility assumed to be subject to Phase III

regulation and the compliance technologies considered for each facility type. Subsection C1-1.2 presents

information on administrative costs incurred by new oil and gas facilities. Additional detail on the costs of

installing and operating compliance technology is provided in the Phase III Technical Development Document.

C1-1.1 Cost of Installing and Operating Compliance Technology

Oil and gas drilling and production facilities would need to implement technologies to reduce impingement

mortality and/or entrainment. The choice of technology varies depending on CWIS diameter and flow rate or

diameter, or type of CWIS (e.g., sea chest or simple pipe). Note that for new MODUs, which EPA assumes will
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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use sea chests, only impingement requirements would apply. EPA determined that entrainment controls on sea

chests are not technically practicable (U.S. EPA, 2004b).

Table C1-1: Technologies for Implementing 316(b) Requirements for New Offshore Oil and Gas

Extraction Facilities

Category CWIS Type Technology Description

Platform Simple Pipe or Caisson Stainless steel wedge wire screen - no air sparge cleaning

Platform Simple Pipe or Caisson Stainless steel wedge wire screen - with air sparge

cleaning

Platform Simple Pipe or Caisson CuNi wedge wire screen - no air sparge cleaning

Platform Simple Pipe or Caisson CuNi wedge wire screen - with air sparge cleaning

Platform Simple Pipe or Caisson Stainless steel and CuNi velocity caps

Jackup Simple Pipe or Caisson Cylindrical wedge wire screen over tower inlet

Jackup Simple Pipe or Caisson Horizontal Flow Modifier

Jackupa Sea Chest Flat panel wedge wire screen over sea chest opening

Jackupa Sea Chest Horizontal Flow Diverter for Side Sea Chests

Jackup Submersible Pumps Cylindrical wedge wire screen over suction pipe inlet

Submersibles, SemiSubmersibles and Drill Shipsa Sea Chests Flat panel wedge wire screen over sea chest

Submersibles, Semisubmersibles and Drill Shipsa Sea Chests Horizontal flow diverter over side sea chest 

Drill Barges Simple Pipes Cylindrical wedge wire screen over simple pipes

Drill Barges Simple Pipes Velocity Cap on the CWIS

a All semi-submersibles and drill ships and most jackups in EPA’s technical database use sea chests. EPA determined that

entrainment controls on sea chests are not technically practicable. New MODUs, which are represented by typical existing

MODUs, are assumed to use sea chests (see U.S. EPA, 2004b).

Source: U.S. EPA, 2004b.

EPA developed technology cost estimates for the proposed rule based on the impingement mortality and

entrainment reduction technologies (as appropriate) projected for each new oil and gas facility. Technology costs

include capital costs and operating and maintenance (O&M) costs. The technology costs developed for the

proposed rule analysis are engineering cost estimates, expressed in July 2002 dollars. These costs were converted

to mid-year 2003 values (see Section C1-2.2 below for a discussion of adjusting monetary values to a common

time period of analysis).

More detailed information on the compliance technologies considered by EPA, on technology costs, and on

EPA’s characterization of baseline technologies already in-place at new offshore oil and gas extraction facilities,

is available in the Phase III Technical Development Document. In addition, Chapter C3: Economic Impact

Analysis for the Offshore Oil and Gas Extraction Industry provides more detail on the engineering costs assumed

for each of the different types of oil and gas facilities analyzed in this report.
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C1-1.2 Administrative Costs for Complying Facilities

Compliance with the standards of the proposed rule requires new offshore oil and gas extraction facilities to carry

out certain administrative functions. For Phase III existing facilities, these administrative functions, which help

them determine their compliance requirements and provide the documentation needed for issuance of their new

National Pollution Discharge Elimination System (NPDES) permits, fall on each facility individually. For oil and

gas facilities, however, General Permits apply. 

There are three General Permits (GPs) that would apply to new offshore oil and gas extraction facilities subject to

Phase III regulation. The Region 6 General Permit applies to the relatively active Western Gulf of Mexico

(GOM) region; the Region 4 General Permit applies to the currently relatively inactive Eastern GOM region, and

the Region 10 General Permit (Cook Inlet permit) applies to Cook Inlet, Alaska. The GPs are expected to be

rewritten to accommodate the requirements of section 316(b) following promulgation of the final rule and as each

GP comes up for renewal at the end of its 5-year cycle.

The current Region 6 permit was effective as of 2002, expired in 2003, and is planned for renewal in 2004. Study

of produced water will reopen in 2007. The likely beginning rounds of the post-promulgation schedule of this

permit is thus 2007 and 2012. The Region 4 permit expired in 2003. It is likely to be renewed in 2004. The

probable post-promulgation GP renewal schedule is considered to be 2009 and 2014. The planned renewal date

of the general permit for Cook Inlet is January 2005 but the permit expires in 2004. The likely post-promulgation

renewal schedule is thus 2009 and 2014.

The rule is scheduled to be promulgated in 2006, with the effective date assumed to be the beginning of 2007. 

Three years of environmental studies are assumed to be required prior to permitting under the section 316(b) rule. 

Thus, the first possible compliance date after the 2007 effective date would be 2010. However, the general

permits may not be able to incorporate section 316(b) requirements during the 2007-2009 repermitting cycles. 

Therefore, EPA assumed that the oil and gas industries would be required to comply starting in 2012 (or 2014 in

the case of Region 4 and 10 permits).

Because the rule becomes effective in 2007, however, EPA is assuming, for both simplicity and to be

conservative, that starting in 2007, new offshore oil and gas extraction facilities would have installed and would

be operating relevant CWIS controls, since they would be relatively inexpensive to install during construction. 

The pre-permitting studies are assumed to start in 2007 (for both Region 6 and Region 4), but other permitting

tasks would not begin until the year prior to when the GPs renewals are finalized (2012 or 2014), or the year prior

to when the facility is assumed to come on line or be launched, whichever is later. Monitoring would only begin

in the year the renewals are finalized or the year in which the facility comes on line or is launched, again,

whichever is later. The timing assumptions for Region 6 and Region 4 permits may overstate costs, since costs

are moved several years earlier in the analysis time frame than they would be if EPA assumed only those facilities

constructed in 2012 or later incur compliance costs. The costs of compliance in this industry, however, are

relatively small overall, so the numerical significance of any overestimation would be small. More specific

details of the timing assumptions of costs incurred are provided in a memorandum to the Rulemaking record

(ERG, 2004).

Because new offshore oil and gas extraction facilities would be subject to Phase III regulation under these GPs,

EPA assumes that certain administrative functions can be shared among new facilities. All MODUs and

platforms expected to be built in the first five years before the revised Region 6 General Permit is issued (2012)

are expected to share the initial costs of certain biological characterization studies that would be required by

section 316(b) under the Region 6 GP. They are also assumed to share the cost of monitoring studies, which must

be performed at a minimum for the first two years of the permit and then at least once per year for each

repermitting cycle. Only MODUs are assumed to share the costs of permitting studies under the Region 4 GP. 

Permitting costs for platforms are assumed to be those incurred under the Region 6 permit. Should platforms be

constructed in Region 4 locations, permitting costs would be similar to Region 6 permitting costs. Since it is not

known which MODUs may operate in the Eastern GOM, all MODUs constructed in 2007 and beyond are
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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assumed to incur permitting costs under a Region 4 GP. This roughly doubles the permitting costs assigned to

MODUs. The assumption may overstate total costs, since not all MODUs may operate in the Eastern Gulf, and

there may be significant costs savings once a Region 6 permit application is completed, since much of the

information required for both permits would most likely be identical. 

Only one Alaska project is anticipated, at most, over the period of analysis (see Chapter C2: Profile of the

Offshore Oil and Gas Extraction Industry), so this project is expected to incur the entire cost of facility

permitting. This project is assumed to go on line in the year the Region 10 permit is finalized (2014). For this

project, EPA assumes that the 3-year studies are performed in the three years prior to start-up (2011-2013). 

The administrative functions associated with incorporating the 316(b) requirements into the applicable General

Permits are either one-time requirements (compilation of information for the initial post-promulgation General

Permits) or recurring requirements (compilation of information for subsequent General Permit renewals; and

monitoring, record keeping, and reporting). More detailed information on the derivation of permitting activities

and costs can be seen in U.S. EPA (2004a).

a. Initial post-promulgation General Permit application

EPA assumes that the proposed rule would encourage firms to pool their resources. Therefore, those firms that

are planning to construct new platforms or MODUs to operate in the GOM within the first 5 years before the

applicable General Permit is reissued with 316(b) requirements in place are assumed to share certain prepermitting costs. EPA expects that these firms will hire a consultant to perform the more general information

gathering tasks required of industry before facilities can be permitted under a GP and also to perform the two

years of monitoring studies required in the first two years of the permit (monitoring costs are assumed shared by

the number facilities permitted in the first or second year of the first permit cycle). Other activities are specific to

each facility and it is assumed each facility will incur the cost of these activities individually. Some of the

permitting activities, however, may not be incremental to existing requirements. Minerals Management Service

(MMS) will be finalizing a rule (possibly mid-August, 2004) that will require some of the same information (U.S.

EPA, 2004a). The MMS rule is, however, not applicable to Cook Inlet. All information submitted would be

consistent with Phase I, Track 1 requirements. Activities and costs associated with the initial permit renewal

application include:

< Start-up activities: reading and understanding the rule; mobilizing and planning; and training staff. This

is a facility-specific activity.

< Permit application activities: identifying source water physical data, velocity information, and cooling

water intake structure data, including description of CWIS operations, flow distribution and water balance

diagram, and drawings and maps to support CWIS descriptions, and maintaining copies of these records. 

These activities are assumed facility-specific, but several of the activities duplicate activities required by

MMS. There are no incremental costs associated with duplicate activities.

< Source waterbody flow and CWIS velocity flow information: Information used to demonstrate that the

facility’s CWIS meets the proportional flow requirements. The CWIS velocity flow information and

demonstration is assumed to be facility-specific, but none of these activities is incremental to MMS

requirements. The waterbody flow calculation activities are only those associated with compiling sitespecific information. Other waterbody characterization activities that can be shared are included in the

biologic characterization study activities.

< Design and construction technology plan: delineation of the hydrologic zone of influence for the CWIS,

description of technologies to be implemented; the basis for technology selection; expected performance

of the technology; and design calculations, drawings and estimates to support the technology description

and performance. These activities are assumed facility-specific. Development of the narrative

description of technologies is considered an MMS requirement, so no costs are assumed incurred for this

activity.
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< Source water baseline biological characterization data: characterization of the biological community in

the region and operation of CWISs; list of species in region; identification and evaluation of primary

period of reproduction, larval recruitment, and period of peak meroplankton abundance for relevant taxa;

and description of the likely impact of CWISs on the biological community due to impingement and

entrainment. This is considered a regional study to be conducted over a 3-year period by a contractor;

costs are assumed to be shared among affected facilities, since the entire monitoring program is assumed

to apply region-wide.

Table C1-2 below lists the estimated costs per facility of each of the initial post-promulgation General Permit

activities described above (permit costs for MODUs in the Eastern GOM are lower in some cases, since MODUs

are assume to use sea chests and are not required to meet entrainment requirements, eliminating any costs

associated with entrainment studies).

Table C1-2: Cost of Initial Post-Promulgation NPDES General Permit Application Activities

(Per Facility, 2003$)

Activity Region 6 Region 4 Region 10

Start-up activitiesa $2,171 $2,171 $2,171

Permit application activitiesb $925 $925 $925

Source waterbody flow informationa $1,416 $1,416 $1,416

CWIS velocity flow informationf $0 $0 $0

Design and construction technology planb $1,282 $1,141 $1,282

Biological characterization studyc,e $63,942 $39,871 $296,564

Total Initial Post-Promulgation NPDES General

Permit Application Costd $69,737 $45,524 $302,358

a The costs for these activities are incurred in 2007 for facilities built in 2007 to 2011 in both Eastern and Western Gulf. For

Alaska, they occur in 2011. b The costs for these activities are incurred in 2011 for facilities built in 2007 to 2012 for both Eastern and Western Gulf. For

Alaska, they occur in 2013. c The costs for these activities are incurred during 2007-2009 in the Eastern and Western Gulf and are shared costs. For Alaska,

these costs are incurred during 2011-2013. d Individual numbers may not add to total due to independent rounding. e Shared study costs. f Measured as incremental to MMS requirements.

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

b. Subsequent NPDES General Permit Renewals

Subsequent General Permit renewals would require collecting and submitting the same type of information

required for the initial permit renewal application. EPA expects that both the facility and the contractor can use

some of the information from the initial studies. Building upon existing information is expected to require less

effort than developing the data the first time, especially in situations where conditions have not changed. The

shared recurring permit costs are assumed to be shared by all new offshore oil and gas extraction facilities built in

the first 5-year cycle plus all new facilities built in the next 5-year cycle, etc., so as time goes on, shared costs are

shared by more and more facilities (except Alaska, where only one project is assumed during the time frame of

the analysis). As facilities go off line or are retired (after 30 years), fewer projects share in these studies.

Table C1-3 lists the estimated costs of each of the NPDES General Permit renewal activities subsequent to the

first round. Since these numbers change slightly as facilities come on or off line, the costs shown are for the first

repermitting cycle following the initial GP renewal.
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Table C1-3: Cost of Subsequent NPDES General Permit Application Activities

(Per Facility, 2003$)

Activity Region 6 Region 4 Region 10

Start-up activitiesa $692 $692 $692

Permit application activitiesa $190 $190 $190

Source waterbody flow informationa $401 $401 $401

CWIS velocity flow informationa $0 $0 $0

Design and construction technology plana $802 $694 $802

Biologic characterization studya $12,005 $7,455 $194,932

Total Recurring NPDES Permit Application Costd $14,090 $9,432 $197,017

a The costs for these activities are incurred during the year of the General Permit renewal. Shared costs shown are for the first

permit renewal period after the initial permit (e.g., 2017); these costs change as the number of permitted facilities change. For

simplicity, all costs for repermitting are assumed to be incurred in one year, rather than spread over several years as was assumed

for the initial round of permitting. 

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

c. Annual monitoring, record keeping, and reporting

Annual monitoring, record keeping, and reporting activities and costs include:

< Biologic monitoring for impingement

< Biologic monitoring for entrainment

< Velocity monitoring

< Preparing and maintaining a yearly status report

Table C1-4 on the following page outlines the associated costs of these activities.

Table C1-4: Cost of Monitoring Activities (Per Facility, 2003$)

Activity Region 6 Region 4 Region 10

Biologic monitoring for impingement $4,350 $1,963 $0

Biologic monitoring for entrainment $2,710 $0 $46,078

Velocity monitoringa $1,004 $453 $6,192

Preparing and maintaining yearly status report $1,775 $801 $10,945

Total Monitoring Cost $9,839 $3,217 $63,215

a The costs for these activities are incurred during the first two years of the initial General Permit renewal (i.e., 2012 or 2014) and

are shared. These costs are incurred for one year in each subsequent permit renewal cycle. Shared costs shown are for the first

permit cycle only (2012 or 2014); these costs change as the number of permitted facilities change over time.

Source: U.S. EPA, 2004a. See also ERG 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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 The costs associated with implementing the requirements for new offshore oil and gas extraction facilities are documented in EPA’s

Information Collection Request (U.S. EPA, 2004a).

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d. Administrative Costs for Permitting Authorities

In addition, permitting authorities have to review the information provided by new offshore oil and gas extraction

facilities and have to issue new general permits that reflect the requirements of the proposed rule. These activities

impose costs on the responsible governmental units. For more details on the specific costs and timing

assumptions for federal administration of new offshore oil and gas extraction facilities, see Chapter D2: UMRA

Analysis. These costs and assumptions are summarized briefly below.

The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination

System (NPDES) permit program. In the case of the oil and gas industry, NPDES permitting is consolidated

under several General Permits, which are administered at the EPA regional level. Unlike the Phase III existing

facilities discussed in Chapter B1: Summary of Cost Categories and Key Analysis Elements for Existing

Facilities, no states are involved in these permitting activities. Thus, three Regions (Region 6, Region 4, and

Region 10) are expected to be the only entities responsible for permitting. Because states are not involved in

permitting, there are no costs associated with Federal oversight as there are for state-administered NPDES

permits. The three Regions would incur three types of costs associated with implementing the requirements of the

proposed rule on a per-facility basis, i.e., for each facility permitted under a GP: (1) start-up activities (considered

not incremental to existing activities; $0 cost) , (2) activities associated with the initial General Permit containing

the new section 316(b) requirements ($12,309 in each region) and subsequent permit renewals ($5,018 in each

region), and (3) annual activities ($1,428 in each region).1

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

basis.

For a detailed discussion of administrative costs for permitting authorities, see Chapter D2: UMRA Analysis,

section D2-1.2.

C1-2 KEY ELEMENTS OF THE ECONOMIC ANALYSIS FOR NEW OFFSHORE OIL AND GAS

EXTRACTION FACILITIES

The economic analysis of regulation of new offshore oil and gas extraction facilities addresses the cost to, and

impact on, the affected industry segments and society generally. Although these analyses differ in important

respects for the individual industry segments – particularly in terms of the analytic models and methods for

assessing the economic/financial impact of the proposed rule on complying parties within the segments – several

elements of the analysis have features common to all new offshore oil and gas extraction facilities. This section

reviews the following key common elements:

< Compliance Schedule

< Adjusting Monetary Values to a Common Time Period of Analysis

< Discounting and Annualization: Costs to Society or Social Costs

< Discounting and Annualization: Costs to Complying Facilities

C1-2.1 Compliance Schedule

For its analysis of the cost and impacts of the proposed rule, EPA developed a profile of the expected compliance

year (year in which the new MODU or platform is launched or comes on line) for each of the types of facilities

considered in the economic analysis. Unlike the analysis for the Phase III existing facilities, the compliance year

is not necessarily the same year as the year in which the facility must comply with the General Permit, since EPA

is assuming that CWIS controls are installed and are operating in new MODUs and platforms starting in 2007,
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even though the first General Permit is assumed to be reissued with 316(b) requirements in 2012. Developing an

explicit profile of compliance years for new offshore oil and gas extraction facilities is important because the

schedule of compliance years determines the timing of outlays by facilities and society in complying with the

regulation, both for the initial outlays and for the ongoing profile of outlays in maintaining compliance with the

regulation. This information is important in properly assessing the present value of the regulation’s costs to

society.

For the analysis, EPA initially assumed that firms planning to build facilities in the first permit cycle (Region 6

General Permit) (2012-2016) would contract to perform the studies necessary for these facilities to be permitted

starting in 2007. The Region 4 permit is assumed not to incorporate 316(b) requirements until 2014, but studies

are started in 2007 as well. Starting in 2014, any new MODUs are assumed to incur the costs of the Region 4

permit as well as the Region 6 permit. No platforms/structures are assumed to incur costs of the Region 4 permit

(they will incur the costs of one permit only, assumed to be issued under the Region 6 General Permit). The next

group of facilities to be launched or come on line in the next permit cycle (2017 or 2019) would need to be

involved only in repermitting activities for the shared studies, and thus, for the shared costs, would share

repermitting costs with each other as well as with operations begun in the first 5-year cycle. These new

operations would, however, incur initial permitting costs among those activities that are facility specific. The

years in which facilities are expected to be completed are specifically spelled out, given the number of facilities

expected to be completed in each year (see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry). 

More information on specific timing assumptions can be seen in ERG (2004) and the 316(b) Oil and Gas

Compliance Cost Model (DCN 7-4018).

C1-2.2 Adjusting Monetary Values to a Common Time Period of Analysis

The various economic information used in the cost and impact analyses were initially provided or estimated in

dollars of different years. For example, facility financial data obtained in the 316(b) survey for the oil and gas

industry are for the years 2000, 2001, and 2002, while the technology costs of regulatory compliance were

estimated in dollars of the year 2002. To support a consistent analysis using these data that were initially

developed in dollars of different years, EPA needed to bring the dollar values to a common analysis year. For this

analysis, EPA adjusted all dollar values to constant dollars of the year 2003 (average or mid-year, depending on

availability) using an appropriate inflation adjustment index. For adjusting compliance costs, EPA used the

Construction Cost Index (CCI) published by the Engineering News-Record.

a. CCI

EPA used the CCI to adjust compliance cost estimates from July 2002 to mid-year 2003. EPA judges the CCI as

generally reflective of the cost of installing and operating process and treatment equipment such as would be

required for compliance with Phase III regulation. Table C1-5, following page, shows CCI values for July, 2002

and June, 2003.

Table C1-5: Construction Cost Index

Year Value % Change

July 2002 6605

June 2003 6694 1.3%

Source: ENR, 2004.

b. GDP Deflator

EPA used the GDP Deflator to adjust 316(b) survey financial data from 2000, 2001, and 2002 to 2003. The GDP

Deflator is a quarterly series that measures the implicit change in prices, over time, of the bundle of goods and

services comprising gross domestic product. Table C1-6 shows GDP Deflator values from 2000 to 2003. From

2000 to 2003, the total change in the deflator series was 5.7% (105.7/100.0). 
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Table C1-6: GDP Deflator Series 

Year Value % Change

2000 100.0

2001 102.4 2.4%

2002 103.9 1.5%

2003 105.7 1.7%

Source: U.S. BEA, 2004.

C1-2.3 Discounting and Annualization – Costs to Society or Social Costs

Discounting refers to the economic conversion of future costs (and benefits) to their present values, accounting for

the fact that society tends to value future costs or benefits less than comparable near-term costs or benefits. 

Discounting is important when the values of costs or benefits occur over a multiple year period and may vary

from year to year. Discounting is also important when the time profiles of costs and benefits are not the same –

which is the case for the regulatory analysis of new oil and facilities. Discounting enables the accumulation of the

cost and benefit values from multiple years at a specified point in time, accounting for the difference in how

society values those costs and benefits depending on the year in which the values are estimated to occur. 

For its analysis of the costs to society, or the social costs, of the proposed rule for new offshore oil and gas

extraction facilities, EPA first developed a profile of the costs expected to be incurred as a result of the regulation

over the period of analysis. EPA defined the analysis period as follows. The analysis period begins in 2007 (5

years before the first of the General Permits is reissued with 316(b) requirements) and includes facilities

constructed over the next 20 years – i.e., to 2026 – plus a period of 30 years in which each newly constructed

facility is assumed to continue compliance. Thus, for the social cost analysis for Phase III new offshore oil and

gas extraction facilities, the analysis period extends to 2055 (see the 316(b) Oil and Gas Compliance Cost Model,

DCN 7-4018). In developing the time profile of costs, EPA assigned costs according to the following schedule:

a. Direct Costs of Regulatory Compliance

< Capital Costs of Compliance Technology: This cost is first incurred in the year that the facility begins

operation. However, the equipment for complying with the regulation is expected to have a useful life of

10 years, or a period shorter than the 30 years of compliance. Accordingly, following the first

installation, facilities are assumed to reinstall, and re-incur the cost of, the compliance equipment at year

11 and year 21 of the facility-specific compliance period.

< Compliance Technology Operation and Maintenance: This cost is assumed to occur in each year of a

facility’s 30-year compliance year period.

b. Administrative Costs Incurred by Complying Facilities

< Biological Characterization Study: This is a three-year study required for all facilities, which is assumed

to be shared by the affected facilities. The cost of this study is incurred over the years immediately

following the effective date of the proposed rule or the years preceding the first post-promulgation GP

(2007-2009 for Eastern and Western Gulf, and 2011-2013 for Alaska).

< Initial Permitting Cost. In addition to incurring a share of the cost of characterization studies, complying

facilities would also incur an initial permitting cost, which is assigned to the year preceding the first year

of a facility’s 30-year compliance period, or in 2007 for facilities launched or coming on line in 2007

through 2011.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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 See Chapter E1: Summary of Social Costs, for further discussion of the framework for analyzing the social costs of the 316(b)

Phase III regulation.

3

 Calculation of the present value assumes that the cost is incurred at the beginning of the year.

C1-10

< Repermitting Costs: As explained above, General Permits are renewed each five years during the period

of compliance. Repermitting costs, both shared and facility-specific, are assumed to recur at years 5, 10,

15, 20, and 25 of the General Permit cycles. For new offshore oil and gas extraction facilities, EPA

assumes that 30 years is the reasonable maximum lifetime of these facilities; thus, no repermitting cost is

incurred in the 30th year of facility operation.

< Annual Monitoring, Record Keeping, and Reporting Activities: These costs are assumed to occur in the

first two years of the initial permit and in each year of the permit renewal year. These costs begin in 2012

or 2014, depending on permit.

c. Administrative Costs Incurred by Permitting Authorities

< One-time Start-up Costs: These costs are assumed to be nonincremental to existing costs of permitting in

the three regions.

< Permit Processing Costs: These costs are assigned to the years in which facilities apply for initial permits

or renewal permits during the compliance period.

< Annual Permit Administration Activities: The cost of these activities is assumed to occur in parallel with

the annual permit-related activities by complying facilities and thus occurs in each year of a facility’s

compliance period. 

EPA assigned costs by facility and governmental unit according to this framework and then summed these costs

on a year-by-year basis over the total time period of analysis. For the social cost analysis, these costs were tallied

on a pre-tax basis, which differs from the treatment of costs for the facility impact analysis as described below. 

These profiles of costs by year were then discounted to the assumed date the final rule would take effect,

beginning of year 2007, at two values of the social discount rate, 3% and 7%. These discount rate values reflect

guidance from the Office of Management and Budget regulatory analysis guidance document, Circular A-4

(OMB, 2003).2

For more detailed information see ERG (2004) and the 316 (b) Oil and Gas Compliance Cost Model (DCN 7-

4018).

EPA used the following formula to calculate the present value of the time stream of costs as of the beginning of

2007:3

where:

Costt = Costs in year t

r = Social discount rate (3% and 7%)

t = Year in which cost is incurred (2007 to 2055)

After calculating the present value of these cost streams, EPA calculated their constant annual equivalent value

(annualized value) using the annualization formula presented below, again using the two values of the social

discount rate, 3% and 7%. Although the analysis period extends from 2007 through 2055, a period of 49 years,
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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inclusive, EPA annualized costs over 30 years, since 30 years is the assumed period of compliance. This same

annualization concept and period of annualization were also followed in the analysis of benefits, although for

benefits the time horizon of analysis for calculating the present value is longer than for costs. Using a 30-year

annualization period for both social costs and benefits allows comparison of constant annual equivalent values of

costs and benefits that have been calculated on a mathematically consistent basis. The annualization formula is as

follows:

where:

r = Social discount rate (3% and 7%)

n = Annualization period, 30 years for the social cost analysis

C1-2.4 Discounting and Annualization – Costs to Complying Facilities

In general, EPA followed similar concepts and procedures in the discounting and annualization required for the

analysis of costs to, and impacts on, complying facilities as those followed for the analysis of social costs. 

However, the analysis of costs to complying facilities differs from that for costs to society in several important

ways, which are described below.

< Consideration of taxes. For understanding the impact of the regulation on complying facilities, the costs

incurred by complying facilities are adjusted for taxes, as relevant, and calculated on an after-tax basis. 

The tax treatment of compliance outlays and income effects (e.g., from installation) shifts part of these

costs to the tax-paying public and reduces the actual cost to private, tax-paying businesses. For this

reason, the after-tax costs of compliance are a more meaningful measure than the pre-tax costs of the

financial burden on complying facilities. In analyzing and reporting the impact of compliance costs on

private facilities, annualized costs are therefore calculated on an after-tax basis. Since most companies

that operate MODUs or platforms are headquartered in states without corporate income taxes, EPA

assumes a state tax rate of 0%. On the Federal level, EPA assumes that the highest marginal corporate tax

rate applies. This rate is 35% (IRS, 2002), so post-tax costs will be 65% of the pre-tax costs. EPA does

this because all platform and MODU owners that are likely to operate in Alaska or the Gulf of Mexico are

large corporations by SBA standards and/or all have earnings in most years that place them in the highest

corporate tax bracket.

< Calculation of present value and annualization of costs at the year of compliance. In the social cost

analysis, costs were summed on a present value basis at the beginning of 2007, the assumed date the final

regulation would take effect. For the analysis of costs to complying facilities, costs were calculated on a

present value basis and annualized at the first year of compliance for each facility (assumed to be the year

the facility is brought on line or launched). The calculation of annualized costs at the first year of

compliance provides more accurate and meaningful insight for assessing financial impact in relation to

the baseline financial performance and conditions of the complying facility than would be achieved if, for

example, costs were further discounted – and reduced numerically – by bringing them to the year the rule

would take effect. The aggregates of annualized cost over facilities for purposes of reporting total cost to

complying facilities and total financial burden are likewise the sum of costs at the initial year of

compliance for each facility, even though those years differ across facilities. These costs are annualized

and used to report the aggregate costs to industry. The costs used to determine impacts are derived

somewhat differently and the method used to incorporate them into the impact analysis varies by type of

facility (MODU or platform) as explained in Chapter C3: Economic Impact Analysis for the Offshore Oil

and Gas Extraction Industry.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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< Use of discount rates in present value and annualization calculations. The discounting and

annualization calculations for the complying facility cost calculations use the same formulas as used for

the social cost calculations. However, the discount rate used in the facility cost calculations generally has

a different interpretation than the rate used for the social cost calculation (even though the numerical

value of the rate may be the same). Instead of being a social discount rate, the discount rate used for the

present value and annualization calculations for complying facility costs represents a cost of capital to the

individual complying facility, which may reasonably differ from the concept of the social discount rate. 

The social discount rate may be derived on several bases, including as an opportunity cost of capital to

society or as a societal inter-temporal preference or indifference rate – i.e., the required rate of change

over time in a value of consumption or outlay at which society would be indifferent to the time period in

which the consumption or outlay occurs. The social discount rates based on these society-level concepts

may reasonably differ from the cost of capital used for assessing costs and financial impacts to the

complying firm.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-13

REFERENCES

Engineering News-Record (ENR). 2004. Construction Cost Index. Available at: 

http://enr.construction.com/features/conEco/costIndexes/constIndexHist.asp.

ERG. 2004. Cost Timing and Cost Sharing Assumptions for Industry Compliance Costs. Memorandum to the

316(b) Phase III Rulemaking Record. October 15, 2004.

Office of Management and Budget (OMB). 2003. Executive Office of the President. Circular A-4, To the Heads

of Executive Agencies and Establishments; Subject: Regulatory Analysis. September 17, 2003.

U.S. Bureau of Economic Analysis (U.S. BEA). 2004. Gross Domestic Product. Table 1.1.9: Implicit Price

Deflators for Gross Domestic Product (GDP). Last Revised on February 27, 2004.

Available at: http://www.bea.doc.gov/bea/dn/nipaweb/TableView.asp#Mid.

U.S. Department of the Treasury. 2002. Internal Revenue Service (IRS). 2002 Instructions for Forms 1120 &

1120-A, page 17 (Federal tax rates).

U.S. Environmental Protection Agency (U.S. EPA). 2004a. Information Collection Request (ICR) for Cooling

Water Intake Structures Phase III Proposed Rule. ICR Number 2169.01. October 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2004b. Technical Development Document for the Proposed

Section 316(b) Phase III Facilities. EPA-821-R-04-015. November 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C1: Summary of Costs

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§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-1

CHAPTER CONTENTS

C2-1 Mobile Offshore Drilling Units (MODUs) . . . . C2-2

C2-1.1 Overview . . . . . . . . . . . . . . . . . . . . . . . C2-2

C2-1.2 Existing MODUs and Their Associated

Firms . . . . . . . . . . . . . . . . . . . . . . . . . . . C2-3

C2-1.3 Existing MODUs with Intake Rates

Meeting Proposed Rule Criteria . . . . . . C2-9

C2-2 Oil and Gas Production Platforms . . . . . . . . . . C2-10

C2-2.1 Overview . . . . . . . . . . . . . . . . . . . . . . C2-10

C2-2.2 Existing Platforms and Their Associated

Firms . . . . . . . . . . . . . . . . . . . . . . . . . . C2-11

C2-2.3 Existing Platforms with Intake

Rates Meeting Proposed Rule Criteria C2-25

C2-3 Total New Oil and Gas Operations . . . . . . . . . C2-30

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C2-31

Chapter C2: Profile of the Offshore Oil and

Gas Extraction Industry

INTRODUCTION

EPA’s proposed 316(b) cooling water intake

rulemaking would affect new construction among

offshore components of the oil and gas industry. The

proposal would affect new offshore oil and gas

extraction facilities only, because EPA has decided

not to regulate existing oil and gas facilities. This

profile compiles and analyzes economic and financial

data for several sectors of the offshore oil and gas

extraction industry that may be affected by certain of

the Phase I 316(b) requirements for new facilities that

are being proposed for new offshore oil and gas

extraction facilities under Phase III. The profile

characterizes the firms and facilities that currently

exist to provide information on the characteristics of

facilities that might be constructed in the future and

the firms that are most likely to construct such facilities. The review of existing facilities that would be subject to

Phase III regulation, if they were newly constructed, is also informative in showing the relatively small number of

facilities that EPA has excluded from coverage by not including existing oil and gas facilities in this proposal.

Two key industry sectors are primarily associated with offshore oil and gas drilling and production, both of which

might intake ambient cooling water from the surrounding oceans or navigable waterways for a wide variety of

cooling needs. EPA also investigated the liquid natural gas (LNG) re-gasification industry, but determined that

all but one new LNG facility currently planned would meet the 316(b) requirement that 25% or more of total

intake flow be used for cooling water purposes (U.S. EPA, 2004). EPA proposes to apply Best Professional

Judgment (BPJ) to this industry. This industry, therefore, is not discussed further.

The two major offshore oil and gas extraction industry users of CWIS are: 

< mobile offshore drilling units (MODUs)

< offshore oil and gas production platforms

The following sections provide a profile for MODUs and production platforms (Sections C2-1 and C2-2). Within

each profile, a brief overview of the industry is provided, including a look at existing facilities and their

associated firms, and the financial conditions of those firms (where firm financial data are publicly available). 

The existing facilities are then discussed in more detail to provide information for the financial modeling of new 

facilities. Also discussed are factors affecting the future of each of these two groups of CWIS users. Finally,

EPA projects the numbers of new MODUs or platforms that might be constructed with CWIS flow rates greater

than 2 MGD, greater than 20 MGD, and greater than 50 MGD during the construction portion of the time frame

of this economic analysis (construction spans the years 2007 to 2026). As discussed in Section C1, EPA decided

to apply a similar regulatory structure to new offshore oil and gas extraction facilities as had been applied to new

facilities for the 316(b) Phase I regulation: impingement and entrainment (I&E) controls are required on all new

offshore oil and gas extraction facilities that have a total CWIS intake flow rate of 2 MGD or more (except for

MODUs using sea chests, which are subject to impingement controls only).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-2

Section C2-3 concludes this chapter with a summary of the estimated total number of new facilities in the offshore

oil and gas extraction industry with at least 2 MGD intake rates by MGD flow rate category.

C2-1 MOBILE OFFSHORE DRILLING UNITS (MODUS)

C2-1.1 Overview

Offshore drilling operations often use MODUs, which are vessels or other sea-going rigs that are used to transport

drilling equipment to the offshore site and from which drilling operations can be undertaken. The MODUs of

interest are active primarily in the State offshore waters of the Gulf of Mexico (GOM). MODUs operating close

to shore in State waters tend to be small barges and submersibles that do not use cooling water at the rates of

concern (significantly less than 2 MGD) (U.S. EPA, 2004).

MODUs provide nearly all of the exploration and delineation drilling in the offshore development of oil and gas

resources. MODUs also provide developmental drilling services. In exploratory drilling, drilling is undertaken to

determine whether oil and gas resources are available near existing fields or in areas where no resources have

been previously found (wildcats). Once an exploratory well has identified the presence of potentially recoverable

oil and gas resources, delineation drilling is undertaken. Delineation entails the drilling of additional wells to

determine the extent and nature of the new field. These two types of drilling often occur at a distance from

existing platforms and thus are usually conducted from a mobile rig.

Drilling of development wells can be done from either a platform or a MODU. The same types of mobile rigs

used to drill exploratory and delineation wells can also be used to drill developmental wells. Once a field has

been delineated and a decision is made to develop the field, a platform is typically constructed and developmental

drilling is initiated to construct wells for producing the field. A discussion of platform-based drilling is presented

below in Section C2-2.

MODUs encompass a variety of vessel or rig types. The two basic groups of MODUs are bottom-supported units

and floating units. Bottom-supported units include submersibles and jackups. Floating units include inland

barge rigs, drill ships, ship-shaped barges, and semi-submersibles. 

Bottom-supported drilling units are typically used when drilling occurs in shallow waters. Types of bottomsupported units include:

< Submersibles–barge-mounted drilling rigs that are towed to the drill site and sunk to the bottom. These

rigs may be either posted barge or bottle type. A posted barge rig consists of a barge hull that rests on the

bottom, with steel posts that rise from the top of the hull and a deck built on top of the posts well above

the water line. These are used in water depths no more than 30 to 35 feet. A bottle type submersible

consists of several steel cylinders or bottles. When the bottles are flooded, the rig submerges and sinks to

the bottom, and when water is removed, they rise to the surface. These rigs can be used in water depths

up to 100 feet.

< Jackup rigs–barge-mounted rigs with extendable legs that are retracted during transport. At the drill site,

the legs are extended to the seafloor. As the legs continue to extend, the barge hull is lifted above the

water. Jackup rigs, which can be used in waters up to 300 feet deep, can be categorized by their leg type:

columnar leg and open-truss leg.

Floating drilling units are typically used when drilling occurs in deep waters and at locations far from shore. 

Types of floating units include:

< Semi-submersible–a type of floating drill unit that can withstand rough seas with minimal rolling

and pitching tendencies, thus they are used for drilling projects in ultra-deep water Gulf regions. 

They are hull-mounted and float on the surface of the water when empty. At the drilling site, the
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

1

 This count includes 53 MODUs currently operating outside of U.S. waters, which EPA is treating as not regulated by the

rulemaking.

C2-3

hulls are flooded and sunk to a certain depth below the surface of the water. When the hulls are

fully submerged, the unit is stable and not susceptible to wave motion due to its low center of

gravity. The unit is moored with anchors to the seafloor. The two types of semi-submersible rigs

are bottle-type (similar in concept to the bottle-type submersible) and column-stabilized.

< Drill ships and ship-shaped barges–vessels that float on the surface of the water equipped with

drilling rigs. These vessels maintain position above the drill site by anchors on the seafloor or the

use of propellers mounted fore, aft, and on both sides of the vessel (dynamic positioning). Drill

ships are the other major drilling rig used in ultra-deep Gulf waters. In these locations, drill ships

typically operate using dynamic positioning. Drill ships and ship-shaped barges are susceptible

to wave motion since they float on the surface of the water, and thus are not suitable for use in

heavy seas.

Of the five basic types of MODUS (submersibles, jackups, semi-submersibles, drill ships, and drill barges), the

drill ships, semi-submersibles, and jackups are the three types that typically intake over 2 MGD of cooling water,

with drill ships having the highest intake rates. Among drill ships with known intake rates above 2 MGD, all

intake more than 50 MGD. Jackups and semi-submersibles do not generally appear to intake more than 20 MGD,

but many intake more than 2 MGD. Submersibles and drill barges generally have cooling water intake below the

2 MGD cutoff. Drilling operations use cooling water for purposes such as cooling engines, compressors,

winches, and pumps (U.S. EPA 2004).

C2-1.2 Existing MODUs and Their Associated Firms

Table C2-1 presents a listing of the existing MODUs’ owners and the number of rigs they are currently operating

in the GOM (as of 2002). These include MODUs that may have CWIS intake rates that do not exceed 2 MGD. 

Most MODUs are held by just a few firms. GlobalSantaFe, Transocean, Rowan Companies, Noble Corp. Parker

Drilling, Pride International, ENSCO International, and Diamond Offshore operate 326 MODUs, 85% of the

total.1

 The firms that own MODUs generally work as contractors to the oil and gas exploration and production

industry. The provision of drilling and related services to U.S. and/or foreign offshore regions is the major focus

of their business.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-4

Table C2-1: Number of Existing MODUs and Parent Firms

Company Number of Rigs

Atwood Oceanics 3

Blake Drilling & Workover 19

Blue Dolphin 1

BSI Drilling 3

Caspian Drilling Company 2

Cyprus Company 1

Diamond Offshore 29

Energy Equipment Resources 1

ENSCO International Inc 30

Global Santa Fe 56

Nabors Industries 15

Newfield Exploration Company 1

Noble Corp. 22

NR Marine 1

Ocean Rig Asa 2

Parker Drilling 37

Pride International 29

Rowan Companies Inc 24

Tetra Technologies 7

Transocean Inc. 99

Workships BV 2

Total Number of Rigs 384

Source: ERG, 2004d; Table C2-2.

Table C2-2 presents the operating companies associated with the parent companies listed in Table C2-1. The total

number of potentially affected parent firms is 21. These affiliations were determined primarily on the basis of

Security and Exchange Commission (SEC) data. SEC maintains an online database (the Edgar Database), on

which all filings of publicly held firms are available. The 10K annual reports and 8K reports are used the most to

collect this information. The 10K annual reports to SEC generally list significant subsidiaries and are the source

of income statement and balance sheet information for characterizing financial conditions at a firm. Subsidiary

lists are used to confirm ownership relationships. The 8-K forms, in which significant changes to the firm must

be announced, are often the source of information on mergers and acquisitions.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-5

Table C2-2: Owners of MODUs Currently Operating in GOM and

Parent Company

Listed Owner Parent Company

Atwood Deep Seas Atwood Oceanics

Atwood Oceanics Atwood Oceanics

Blake Workover & Drilling Blake Workover & Drilling

BSI Drilling BSI Drilling

Caspian Drilling Company Caspian Drilling Company

Chiles Offshore ENSCO International, Inc.

Diamond Offshore Diamond Offshore

Drillmar Blue Dolphin

Energy Equipment Resources Energy Equipment Resources

ENSCO ENSCO International, Inc.

ENSCO Offshore Company ENSCO International ,Inc.

Enserch Exploration Newfield Exploration

Falcon Drilling Company Transocean, Inc.

Global Marine Deepwater GlobalSantaFe

Global Marine Drilling Co. GlobalSantaFe

Global Marine North Sea Inc GlobalSantaFe

GlobalSantaFe GlobalSantaFe

Global Santa Fe/Glomar GlobalSantaFe

Glomar GlobalSantaFe

Hercules Offshore Parker Drilling

Mallard Bay Drilling Parker Drilling

Marine Drilling Companies Pride International

Nabors Nabors Industries

Nabors Offshore Nabors Industries

Noble Noble Corp.

Noble Drilling Corp Noble Corp.

Noble Drilling US Noble Corp.

Noble International Noble Corp.

Noble Mexico Noble Corp.

NR Marine NR Marine

Ocean Rig Asa Ocean Rig Asa

Parker Drilling Parker Drilling
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

Table C2-2: Owners of MODUs Currently Operating in GOM and

Parent Company

Listed Owner Parent Company

C2-6

Pride International Pride International

Pride Offshore Pride International

R&B Falcon Transocean, Inc.

Rowan Rowan Companies

Rowan Companies, Inc Rowan Companies

Rowan/Rowan Companies, Inc. Rowan Companies

Rowan/Rowan Drill, Inc. Rowan Companies

Rowan/Rowan International Inc. Rowan Companies

Seatanker's Management Cyprus Company

Tetra Applied Technology Tetra Technologies

Transocean Transocean, Inc

Transocean Sedco Forex Transocean, Inc

Transocean/Deepwater Drilling LLC Transocean, Inc

Workships BV Workships BV

Source: ERG, 2004d; SEC, 2003.

The identification of corporate parent is critical to determining which firms should be defined as small under SBA

standards. SBA defines the size of the firm to be that of the firm at the highest level of organization. Generally,

EPA characterized a firm at the higher level of organization if it was majority owned by the larger entity. This

approach is consistent with SBA’s definition of affiliation. Small firms that are affiliated (e.g., 51% owned) by

firms defined as large by SBA’s standards (13CFR Part 121) are not considered small for the purposes of

regulatory flexibility analysis (see Section D1 for more details). Affiliated firms can also be firms owned by the

same owners or that have the same corporate officers as another firm.

Another key piece of information needed for classifying firms as small or large is what industry the firm belongs

to. SBA defines small businesses differently for different types of industry and currently uses NAICS to classify

industries. SEC still requires companies to report their SIC code, not the NAICS code. Crosswalks between

NAICS and SIC, however, are available from Bureau of the Census (2004).

Once the parent firms were identified as above and the proper NAICS identified based on the reported SIC code

in the 10K reports and the NAICS crosswalk information, the revenue and employment (or other criteria, as

appropriate) for these parent firms were determined and compared to the SBA definition of small based on their

NAICS classification. Table C2-3 shows the SBA definitions for the industries identified.

It is assumed that all domestic firms that could not be identified as large are small businesses. Also, for the

purposes of this analysis, MODU operators owned by foreign firms are assumed to be large, even when data on

employment could not be found, because SBA defines a small business as one “with a place of business in the

United States, and which operates primarily in the United States or which makes a significant contribution to the

economy” (13 CFR Part 121). Only large businesses in this industry would meet the latter criteria, and few, if

any, foreign firms operate primarily in the United States.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-7

Table C2-3 presents the number of MODU parent companies by NAICS and SIC code, where that information is

available. For the most part, those identified as small may not actually be small but are apparently privately

owned and no information was available to support defining them as large. Eight firms are foreign-owned and

presumed large. Industrial classification data are unavailable for foreign firms. Only two firms are positively

identified as small, out of the 21 total firms operating existing MODUs, but four companies believed to be

domestic could not be identified as small or large, so are presumed to be small. These firms (along with foreignowned firms) are not counted in the number of firms shown in Table C2-3, because their NAICS classifications

are also unknown.

Table C2-3: NAICS Classification of MODU Parent Companies

SIC code NAICS code NAICS Description SBA Definition of Small

Total Number of

Firmsa

Small Large

1311 211111 Crude Petroleum and Natural

Gas Extraction 500 employees 2 0

1381 213111 Drilling Oil and Gas Wells 500 employees 0 6

1389 213112 Support Activities for Oil and

Gas Operations $7.5 million in revenues 0 1

2819 211112 Natural Gas Liquid Extraction 500 employees 0 1

a Does not include seven foreign firms and four unknown firms for which NAICS or SIC codes could not be located in publicly

available data.

Source: SEC, 2003; 13 CFR Part 121.

Table C2-4 presents the financial conditions at the parent firms listed in Table C2-2. A number of parent

companies are privately held or are foreign and do not have financial information available on the SEC database,

so information is not presented for these firms. The financial data shown are from 2002, the base year for the new

offshore oil and gas extraction facility analysis. The total assets of the MODU parent companies range from $8

million to $12.7 billion. The revenues range from $3 million to $2.7 billion. The three financial ratios calculated

in the table are the return on assets, return on equity, and the profit margin. Each of these ratios calculates the net

income as a ratio over the total assets, stockholder’s equity, and total revenues respectively, and are commonly

used measures of financial health in the oil and gas industry. The return on assets percentages range from -29.5%

to 6.8%, and the profit margin ranges from -139% to 21%. 
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C

C2-8

Table C2-4: Financial Condition of MODU Parent Companies (2002)

Firms Size Type No. of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Return on Assets R

Atwood Oceanics Large Other 800 $445,238 $276,133 $149,157 $28,285 6.35% Blake Drilling & Workover Small* OtherBlue Dolphin Small Other 11 $7,775 $5,765 $2,910 BSI Drilling Small* OtherCaspian Drilling Company Large** ForeignDiamond Offshore Large Independent 3,766 $3,258,765 $1,335 $752,561 $62,520 1.92% 

Energy EquipmentResources Small* OtherENSCO International, Inc Large Other 4,300 $3,061,500 $1,967,000 $698,100 $59,300 1.94% GlobalSantaFe Large Foreign 8,800 $5,808,200 $4,234,200 $2,017,700 $277,900 4.78% 

Nabors Industries Large Foreign 15,261 Newfield ExplorationCompany Small Independent 488 $2,315,753 $1,009,231 $661,750 $73,847 3.19% Noble Corp. Large Independent 3,747 $3,065,714 $1,989,210 $986,356 $209,503 6.83% NR Marine Small* OtherOcean Rig Asa Large** ForeignParker Drilling Large Other 2,898 $953,325 $300,626 $389,946 ($114,054) -11.96% Pride International Large Other 10,100 $4,324,995 $1,699,705 $1,269,774 ($8,947) -0.21% Rowan Companies Inc Large Other 5,237 $2,054,504 $1,131,777 $617,258 $86,278 4.20% 

Cyprus Company Large** ForeignTetra Technologies Large Other 1,391 $308,817 $184,152 $242,606 $8,899 2.88% Transocean Inc. Large Foreign 13,200 $12,665,000 $7,141,000 $2,674,000 ($3,732,000) -29.47% Workships BV Large** Foreign* Presumed small due to lack of data.**Presumed large–foreign-owned.Source: Table C2-2; SEC, 2003, U.S. EPA 2000.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

2

 For simplicity, the text refers to operations that meet either of these criteria as not meeting proposed rule criteria, even though the

proposed rule does not apply to existing facilities..

C2-9

C2-1.3 Existing MODUs with Intake Rates Meeting Proposed Rule Criteria

a. Overview of Existing MODUs as Models for New MODUs

To provide information on whether new MODUs might be subject to Phase III regulation, EPA investigated

information obtained from a survey of MODUs undertaken for the Phase III rulemaking decision. Not all of the

MODUs owned by the firms listed above meet the applicability standard (at least 2 MGD design intake flow) and

other criteria of the proposed rule. EPA used a multi-step process to estimate the total number of existing MODUs

that would be regulated under the proposed rule if they were newly constructed (i.e., CWISs with total design

flow of at least 2 MGD or more or less than 25% of intake volume used for cooling water purposes).2

 The

sampling frame used 384 MODUs as shown in Table C2-1). Among these 384 MODUs in this universe, EPA

sampled 30 MODUs in the survey. The survey weights for all MODUs is thus 384 divided by 30, or 12.8.

The following is the status of the economic survey respondents:

< 23 respondents returned surveys

< 8 respondents were determined to have CWISs that meet proposed rule criteria.

< 15 respondents were determined to have CWISs that do not meet proposed rule criteria or were

not operating in U.S. waters 

< 4 surveys were not returned from among a group of MODUs whose CWIS intake rates were

known (based on voluntary data submitted during the 316(b) Phase I rulemaking)

< 3 surveys were not returned among a group of MODUs whose CWIS intake rates were unknown.

Based on the ratio of respondents whose intake rates meet proposed rule criteria to total respondents (8/23), EPA

assumes that among the three MODUs with unknown intake rates, one will have intake rates meeting the

proposed rule’s criteria and two will have intake rates not meeting these criteria. Thus, the total number of

MODUs in the economic survey sample whose intake rates are assumed to meet proposed rule criteria is

estimated to be 13. Multiplying this number by the survey weight of 12.8 yields an estimate of a total of 166

MODUs with intake rates meeting proposed rule criteria. Another six MODUs, originally thought to have intake

rates of less than 2 MGD were determined to have intake rates greater than 2 MGD, and these are added to the

estimate of MODUs with CWISs meeting proposed rule criteria, for a total of 172 MODUs meeting the proposed

rule’s criteria – roughly half of the existing MODUs operating in U.S. waters (331 MODUs or about 52 %). EPA

therefore assumes that approximately half of new MODUs built might meet proposed rule criteria. Of the 172

MODUs meeting proposed rule criteria, EPA estimates that all new semi-submersibles and jackups will have

CWIS flow rates below 20 MGD, based on all surveyed semi-submersibles and jackups having rates below 20

MGD. EPA also estimates that all new drill ships will have rates above 50 MGD, based on all surveyed drill

ships having intake rates of this size. For more information on the estimate of existing MODUs that might meet

proposed rule criteria, see ERG, 2004a.

b. Current Drilling Activity and Trends 

In 2002, 62 wells were drilled offshore in the Gulf of Mexico on Federal offshore leases. Offshore drilling rigs

are extremely capital intensive. Therefore, once a company has invested in a rig, it is in their best interest to keep

the rig in operation. Currently, the utilization of all rigs worldwide stands at 72%, which is down significantly

from 85% in 1998 (Drilling Contractor, 2003a). Trends seem to indicate increased utilization in certain regions

however, such as in the Gulf of Mexico. The jackup market, in particular, has shown pricing improvement in the

GOM. The Bureau of Land Management’s Minerals Management Service (MMS) projects that oil production in

the Gulf of Mexico should be between 1.5 and 2.0 million barrels per day (bpd) by the end of 2005 and gas

production should be between 11 and 17 billion cubic feet per day (bcfd) by the same time period. Deepwater
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-10

exploration and deep exploration in the shallow waters of the GOM are expected to continue to grow. Deepwater

exploration in the Gulf of Mexico is projected to be a significant source of new oil and gas supplies in future

years (Drilling Contractor, Nov/Dec 2001).

c. Estimates of New MODUs To Be Constructed 

The progress report published by Offshore magazine shows that the majority of offshore production investment in

2003 is in the refurbishment of old rigs, however some new rigs are being built. In 2003, the majority of new

offshore construction comprised jackup rigs. Surveys indicate that 14 jackups were completed in 2003, and that

eight additional jackups are to be completed by 2005. Of the eight jackups to be completed, three are being built

with a new Rowan Companies design specifically introduced for deep shelf drilling in the shallow water of the

Gulf of Mexico (Offshore, July 2003). The outlook of the offshore industry shows increased growth in deepwater

drilling. Three companies are reported as having deepwater semi-submersibles completed by 2004. The

projections predict that up to 67% of oil production and 27% of gas production will come from deepwater drilling

by 2005. (Drilling Contractor, Nov/Dec 2001).

Since jackups and semi-submersibles are among the most frequent MODUs to have CWIS intake rates that would

meet proposed rule criteria, EPA focuses on these as an indication of how many MODUs might be built with

CWIS intake rates of concern. Given that 22 jackups are expected to be completed over the time period of 2003-

2005 (three years) (Drilling Contractor, 2003b), EPA assumes seven jackups might be built each year during the

time frame of the economic analysis; of this group (based on the assumption that half of all new MODUs would

meet proposed rule criteria, discussed above) EPA assumes four of these would be affected by the 316(b)

requirements. It is further assumed that about one semi-submersible will be built per year. To be conservative,

EPA assumes each of these semi-submersibles would meet proposed rule criteria. Drill ships may also be

constructed during the time frame of the analysis, but there are currently very few drill ships operating in the

GOM. Only 12 out of a total 384 MODUs operating in the GOM (3%) are drill ships. EPA conservatively

assumes three drill ships might be constructed over the entire 20-year time frame of the analysis, all of which are

assumed to meet proposed rule criteria.

The other two types of MODUs (submersibles and barges) are seldom associated with CWIS intake rates meeting

proposed rule criteria (U.S. EPA, 2004). EPA assumes no submersibles or barges with total design intake rates

meeting proposed rule criteria will be built during the time frame of the analysis. EPA assumes that half the

jackups and semi-submersibles will be built with proposed technologies in place to control intake of aquatic

species under a two MGD cutoff. The drill ships are assumed to be built with 50 MGD or greater intake rates, and

the jackups and semi-submersibles are assumed to be built with intakes having a total intake rate of less than 20

MGD, based on the intake rates of existing MODUs of these types in the survey.

C2-2 OIL AND GAS PRODUCTION PLATFORMS

C2-2.1 Overview

Oil and gas production operations generally take place on platforms or other structures. The primary areas of

offshore oil and gas production activity are the GOM, California, and Alaska. In shallow offshore waters,

platforms are the typical structure used to support the resource extraction activities. These activities may involve

drilling wells, producing oil and gas from wells, separating production streams, gathering and compressing gas,

and working over older wells to increase production. Platforms often support buildings for crews, including in

some cases, long-term living quarters. 

There are several different types of platforms, and non-platform structures used in the GOM. Seven major types

of production systems are used in offshore oil and gas production. 

< The fixed platform is the most commonly used for shallow-water drilling. It is anchored directly

into the seabed with a deck to support living quarters etc. While it is primarily used for shallow

water drilling, it is economically feasible for depths up to 1,650 ft. 
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-11

< The compliant tower is a flexible tower and piled foundation with a conventional deck. The

compliant tower differs from the fixed platform in that it can withstand large lateral forces. 

Therefore, it is effective at greater depths and is typically used in water depths between 1,500 and

3,000 ft. 

< The Seastar platform is a floating mini-tension leg platform used for smaller deepwater reserves. 

It is used in water depths from 600 to 3,500 ft. 

< A floating production system (FPS) is a semi-submersible with drilling and production

equipment. The FPS can be dynamically positioned using rotating thrusters. The FPS is used at

depths from 600 to 6,000 ft. 

< Another type of offshore platform is the Tension Leg platform (TLP). It is connected to he sea

floor with tension tendons. TLPs are used up to depths of 6,000 ft. 

< The Spar platform consists of a large diameter cylinder supporting a deck and is used in water

depths up to 3,000 ft.

< The Subsea system can produce single or multiple wells using manifold pipeline systems. The

Subsea system is used for production at depths greater than 7,000 ft. (U.S. EPA, 2000). In this

system, all well completions are at the seafloor level, with piping leading to production platforms

in shallower water or nearby deepwater structures.

C2-2.2 Existing Platforms and Their Associated Firms

EPA’s primary sources of data on platforms in most of the regions of concern (GOM and California) are from the

Department of the Interior, Minerals Management Service (MMS). MMS collects data on platforms, drilling, and

production from all of the platforms located in Federal waters (3 miles offshore in most locations, but 10 miles

beyond the Texas shoreline). Early investigations by EPA (U.S. EPA, 2004) indicated that water intakes for

cooling waters in near-shore regions of the Gulf (both in the coastal regions and in offshore State waters) appear

to be well below 2 MGD. Thus, EPA has focused only on the operations in Federal waters in the GOM. 

Operations in the coastal subcategory and in State offshore waters of the GOM are therefore considered unlikely

to be affected by the rulemaking and are not discussed further.

a. Platforms in the GOM

Early in the process of identifying existing platforms where cooling water intake rates might be in the size range

of concern, EPA determined that the largest platforms and those in deepwater locations (1,000 feet of water depth

or greater) appeared the likeliest to have CWISs with at least 2 MGD of total flow (ERG, 2003). This finding was

based on voluntary data submissions from industry on a number of platforms operating in the GOM (ERG, 2004a,

DCN 7-3505). Based on this analysis, EPA divided the analysis in the GOM into several groups–platforms in

deep water (in depths of a 1,000 feet of water or more), shallow water platforms (< 1,000 feet) with 20 or more

slots available for wells (considered large platforms), and shallow water platforms with fewer than 20 slots (small

platforms). These groupings were used to stratify EPA’s survey of platforms conducted for the proposed 316(b)

Phase III rulemaking.

Using a database compiled by MMS as of June 2003, EPA created a list of platforms located in the Gulf of

Mexico. The database was downloaded and counts of structures were noted. Abandoned platforms and platforms

without production equipment were eliminated from the platform count. The platforms were then categorized by

deepwater and shallow water, and 20+ wells and <20 wells. The counts are presented in Table C2-5. As the table

shows, the about 90% of platforms in the GOM are small platforms operating in shallow water. Only a very few

structures (generally not the typical fixed platforms) are found in the deepwater regions of the GOM. Currently

(2003 data) only 26 are considered built and operational in the MMS database.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-12

Table C2-5: GOM Platform Count

Category Count

Total Number of Platforms 6,226

Removed Platforms 2,229

Abandoned Platforms 21

Platforms without Production Equipment 1,587

Producing Platforms

Deep Deepwater 26

Shallow

>=20 slots 209

<20 slots 2,194

Total Producing Platforms 2,429

Source: MMS, 2003a.

These platforms are operated by a number of firms of different sizes and types. The potentially affected firms can

be divided into two basic categories. The first category consists of the major integrated oil companies, which are

characterized by a high degree of vertical integration (i.e., their activities encompass both “upstream”

activities—oil exploration, development, and production—and “downstream” activities—transportation, refining,

and marketing). The second category of affected firms consists of independents engaged primarily in exploration,

development, and production of oil and gas and not typically involved in downstream activities. Some

independents are strictly producers of oil and gas, while others maintain some service operations, such as contract

drilling and well servicing.

The major integrated oil companies are generally larger than the independents. As a group, the majors typically

produce more oil and gas, earn significantly more revenue and income, and have considerably more assets and

greater financial resources than most independents. Furthermore, majors tend to be relatively homogeneous in

terms of size and corporate structure. All majors are considered large firms under the Regulatory Flexibility Act

(RFA) guidelines and generally are C corporations (i.e., the corporation pays income taxes). Independents can

vary greatly by size and corporate structure. Larger independents tend to be C corporations; small firms might

also pay corporate taxes, but they also can be organized as S corporations (which elect to be taxed at the

shareholder level rather than the corporate level under subchapter S of the Internal Revenue Code). Small firms

also might be organized as limited partnerships, sole proprietorships, etc., whose owners, not the firms, pay taxes.

The proportions of majors and independents operating in the State offshore in the GOM has been changing over

the last dozen or more years. Except for the deepwater GOM, majors have generally been disinvesting in the

Gulf, selling their platforms to independents. Independents, because of their different cost structures and risk

profiles can often operate marginal platforms far longer than majors. Independents often have lower overheads. 

Furthermore, many independents who operate platforms purchased from majors do not engage as extensively in

exploration, thus they may be tolerant of lower returns, since their risks are lower. 

Table C2-6 summarizes the information developed using the MMS databases, listing the firms operating in the

Federal GOM. To identify parent companies and/or recent changes in ownership, EPA again used SEC’s Edgar

database. Note that EPA’s analysis is based primarily on the status of the industry as of year end 2002, reported
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

3

 Note that all corporate ties could not be identified. Corporate parents are not obliged to list all subsidiaries, only

significant subsidiaries. Where no corporate ties could be identified, EPA assumed the operator listed was at the highest level

of corporate organization.

C2-13

in March 2003 (the date by which most firms must submit their 10K reports). Mergers and acquisitions continue

to occur among this group of firms.3

Table C2-6: Operators and Parent Companies of GOM Platforms

Operator Company Parent Company

AEDC USA Inc AOC Energy Development Company Ltd.

AGIP Petroleum Co Inc AGIP Petroleum Co Inc

AGIP Petroleum Exploration Co Inc AGIP Petroleum Co Inc

Amerada Hess Corporation Amerada Hess Corporation

Anadarko E&P Company LP Anadarko Petroleum Corporation

Anadarko Petroleum Corporation Anadarko Petroleum Corporation

Apache Corporation Apache Corporation

Apex Oil & Gas Inc Apex Oil & Gas Inc

Arena Offshore LLC Arena Resources 

ATP Oil & Gas Corporation ATP Oil & Gas Corporation

B T Operating Co B T Operating Co

Barrett Resources Corporation Williams Companies Inc

BHP Billiton Petroleum (Americas) Inc BHP Billiton Petroleum (Americas) Inc

Bois D'arc Offshore Ltd Bois D'arc Offshore Ltd

BP America Production Company BP PLC

BP Exploration & Production Inc BP PLC

Burlington Resources Offshore Inc Burlington Resources Inc

Cairn Energy USA Inc Cairn Energy USA Inc

Callon Petroleum Operating Company Callon Petroleum Co

Calpine Natural Gas Company Calpine Corp

Century Exploration Company Century Exploration Company

Chevron USA Inc ChevronTexaco

CNG Pipeline Company Dominion Resources Inc

Cockrell Oil Corporation Cockrell Oil Corporation

Comstock Offshore LLC Comstock Resources

Conn Energy Inc Conn Energy Inc

ConocoPhillips Company ConocoPhillips Company

Contour Energy E & P LLC Contour Energy Co
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

Table C2-6: Operators and Parent Companies of GOM Platforms

Operator Company Parent Company

C2-14

Delos Offshore Company LLC El Paso Corp.

Denbury Offshore Inc Denbury Resources

Devon Energy Production Company LP Ocean Energy Inc

Devon SFS Operating Inc Ocean Energy Inc

Dominion Exploration & Production Inc Dominion Resources Inc

Duke Energy Field Services LP Duke Energy Co

Dunhill Resources Inc Dunhill Resources Inc

Dynegy Midstream Services Limited Partnership Dynagy Inc

EEX Corporation Newfield Exploration Company

El Paso Production Company El Paso Corp.

El Paso Production Gom Inc El Paso Corp.

El Paso Production Oil & Gas Company El Paso Corp.

Energy Partners Ltd Energy Partners Ltd

Energy Resource Technology Inc Energy Resource Technology Inc

EOG Resources Inc EOG Resources Inc

Equilon Pipeline Company LLC Equilon Enterprises LLCa

ExxonMobil Corporation Exxon Mobil Corporation

Fairways Specialty Sales & Service Inc Fairways Specialty Sales & Service Inc

Flextrend Development Company LLC El Paso Corp.

Forest Oil Corporation Forest Oil Corporation

Freeport McMoran Sulphur LLC McMoran Exploration Co

Garden Banks Gas Pipeline LLC Garden Banks Gas Pipeline LLC

GOM Shelf LLC GOM Shelf LLC

Gryphon Exploration Company Gryphon Exploration Company

Hall-Houston Oil Company Hall-Houston Oil Company

HC Resources LLC HC Resources LLC

Houston Exploration Company Houston Exploration Company

Hunt Oil Company Hunt Oil Company

Hunt Petroleum (AEC) Inc Hunt Petroleum (AEC) Inc

J M Huber Corporation J M Huber Corporation

J Ray McDermott Technology Inc McDermott International Inc.

Juniper Energy LP Juniper Energy LP

Kerr-McGee Corporation Kerr-McGee Corporation

Kerr-McGee Oil & Gas Corporation Kerr-McGee Corporation
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

Table C2-6: Operators and Parent Companies of GOM Platforms

Operator Company Parent Company

C2-15

Linder Oil Company, a Partnership Linder Oil Company, a Partnership

LLOG Exploration Offshore Inc Amerada Hess Corporation

Louis Dreyfus Natural Gas Corp Dominion Resources Inc

Magnum Hunter Production Inc Magnum Hunter Production Inc

Manta Ray Offshore Gathering Company LLC El Paso Corp.

Marathon Oil Company Marathon Oil Corp

Maritech Resources, Inc Maritech Resources, Inc

Matrix Oil & Gas, Inc Matrix Oil & Gas, Inc

McMoRan Oil & Gas LLC McMoRan Exploration Co

Merit Energy Company Merit Energy Company

Millennium Offshore Group Inc Millennium Offshore Group Inc

Mission Resources Corporation Mission Resources Corporation

Mobil Oil Exploration & Production ExxonMobil Corporation

Murphy Exploration & Production Murphy Oil Corporation

Murphy Exploration & Production Company - USA Murphy Oil Corporation

NCX Company LLC NCX Company LLC

Newfield Exploration Company Newfield Exploration Company

Nexen Petroleum USA Inc Nexen Petroleum USA Inc

Nippon Oil Exploration U S A Nippon Oil Exploration U S A

Ocean Energy Inc Ocean Energy Inc

Offshore Energy I LLC Offshore Energy I LLC

Panaco Inc Panaco Inc

Petro Ventures Inc Petro Ventures Inc

Petrobras America Inc Petrobras America Inc

Petroquest Energy LLC Petroquest Energy LLC

Pioneer Natural Resources USA Inc Pioneer Natural Resources Co

Pogo Producing Company Pogo Producing Company

PRS Offshore LP PRS Offshore LP

Remington Oil and Gas Corporation Remington Oil and Gas Corporation

Samedan Oil Corporation Noble Energy Inc

Scana Petroleum Resources Inc Scana Petroleum Resources Inc

Seagull EnergyE&P Inc Ocean Energy Inc

Seneca Resources Corporation National Fuel Gas Company

Shell Frontier Oil & Gas Inc Royal Dutch/Shell Group
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

Table C2-6: Operators and Parent Companies of GOM Platforms

Operator Company Parent Company

C2-16

Shell Offshore Inc Royal Dutch/Shell Group

Shell Oil Company Royal Dutch/Shell Group

Spinnaker Exploration Company LLC Spinnaker Exploration Company LLC

St Mary Energy Company St Mary Land & Exploration Co

Stone Energy Corporation Stone Energy Corporation

Tarpon Offshore LP Tarpon Offshore LP

Taylor Energy Company Taylor Energy Company

TDC Energy Corporation TDC Energy LLC

TDC Energy LLC TDC Energy LLC

Texaco Exploration and Prod ChevronTexaco

The Louisiana Land and Exploration Company Burlington Resources Inc

Torch Energy Services Inc Torch Offshore

TotalFinaElf E&P USA Inc TotalFinaElf E&P USA Inc

Transcontinental Gas Pipe Line Corporation Transcontinental Gas Pipe Line Corporation

Transworld Exploration and Production Inc Transworld Exploration and Production Inc

Tri-Union Development Corporation Tri-Union Development Corporation

UMC Pipeline Corporation UMC Pipeline Corporation

Union Oil Company of California Unocal Corp.

Unocal Pipeline Company Unocal Corp.

Vastar Resources Inc. BP PLC

Vintage Petroleum Inc Vintage Petroleum Inc

W & T Offshore Inc W & T Offshore Inc

Walter Oil & Gas Corporation Walter Oil & Gas Corporation

Westport Oil and Gas Company LP Westport Oil and Gas Company LP

Westport Resources Corporation Westport Resources Corporation

WFS - Offshore Gathering Company Williams Companies Inc

William G Helis Company LLC William G Helis Company LLC

Williams Field Services - Gulf Coast Company LP Williams Companies Inc

Williams Production RMT Company Williams Companies Inc

a Joint venture between Royal Dutch/Shell Group and Texaco currently operating as Shell Oil Products U.S. Shell

bought Texaco’s interests in 2002 (Alexander’s Oil and Gas Connections, 2002).

Source: MMS, 2003a; SEC, 2003.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

4

 The North American Industry Classification System (NAICS) supercedes the Standard Industrial Classification (SIC)

codes, however, the transition to the new system is still in progress.

C2-17

It is important to note that companies may share ownership of a platform. In general, the company listed as the

operator in the MMS databases is the owner or largest share holder of the platform, but this is not always the case. 

The economic analyses in this report, however, make the simplifying assumption that only one firm owns a

platform. In reality, the impacts from regulatory costs to a platform might be shared by several firms.

The same methodology used to identify small firms in the MODU profile (Section C2-1) is used for this profile. 

Table C2-7 lists the numbers of firms in the GOM by their NAICS definition.4

 Also listed is the SIC code, which

is the identifier used in the 10K reports. In the table, NAICS and SICs are mapped in the key industry sectors

represented by firms operating in the GOM. 

Table C2-7: Count of Firms by SIC and NAICS Code

SIC code NAICS code NAICS Title SBA Size Standard

GOM

Number of Firms

Small Large

1311 211111 Crude Petroleum and Natural

Gas Extraction 500 employees 19 12

1389 213112 Support Activities for Oil and

Gas Operations $7.5 million in revenues 1 1

2911 324110 Petroleum Refineries 1,500 employees 0 8

3443 Several industries 750 employeesa 0 1

4911 221112 Fossil Fuel Electric Power

Generation 4.0 million megawatt hours 0 3

4922 486210 Pipeline Transportation of

Natural Gas $6.0 million in revenues 1 3

4924 221210 Natural Gas Distribution 500 employees 0 1

a

 Highest number of employees defining small among the group of industries that 3443 has been split into.

Note: Does not include 37 firms considered domestic and 10 foreign firms for which NAICS or SIC codes could not be located in

publicly available data.

Source: SEC, 2003, 13 CFR Part 121.

As Table C2-7 shows, the predominant firm types operating in the GOM are those in the oil and gas extraction

NAICS and the refineries NAICS. A total of 21 firms were identified as small. Another 37 non-foreign firms

could not be identified as small or large thus are considered small for purposes of analysis. As was done for

MODU firms, all foreign firms were assumed to be large. Once EPA accounted for these relationships and

transactions, EPA’s count of potentially affected firms in the Gulf of Mexico becomes 96 firms, of which 10 are

listed as majors, and 10 firms are identified as foreign owned (not including Shell Oil, a major that is affiliated

with Royal Dutch/Shell Group, but which reports to SEC). Non-foreign non-majors total 76 firms, including

those not previously identified as majors or independents (U.S. EPA, 2000).

Table C2-8 shows the firms considered potentially affected firms operating in the Federal GOM and their

relevant financial data. These data include number of employees, assets, liabilities, and revenues, along with

several ratios that provide a general indication of financial health. Note that blank lines in Table C2-8 indicate

firms that are likely to be privately held or are foreign and for which no public data have been located.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-18

The ratios used to establish company financial status are profitability ratios, namely: return on assets, return on

equity, and profit margin. As described earlier, these three financial indicators are calculated as the ratio of the

net income to the total assets, stockholders’ equity, and net sales respectively. While individually these ratios

only tell a part of the financial stability of a company, when analyzed together, they give a much clearer picture of

a company’s financial health. 

Of these operators in the Gulf, EPA has identified 58 (60%) that either meet the SBA’s definition of a small

business (which for the oil and gas extraction industry is defined as a business entity with 500 or fewer employees

or for the oil field service industry as a business entity with $5 million or less in annual revenues) or that cannot

be identified as large because their employment or revenue figures are not known. These latter firms might be

privately owned, or they do not file with the SEC as an independent firm but their parent company could not be

identified. Most of these firms, however, are not likely to be involved in constructing new oil and gas platforms

that would be subject to Phase III regulation, as discussed below. Small firms that might be affected by the rule

are discussed in more detail in Chapter D1: Regulatory Flexibility Analysis.

Table C2-8 also presents summary financial ratios for the large and small firms. Among publicly held firms,

median return on assets for the group is 2.65%, median return on equity is 4.89%, and median profit margin (net

income/revenues) is 5.71%, according to 2002 financial data. Among these publicly held firms, 35 out of 48

firms, or 73%, reported positive net income for 2002.

b. California Platforms

California has a total of 33 platforms; 9 located in State waters and 24 in State waters. Six companies operate

platforms in State water off the California shore: Aera Energy LLC, Arguello, Inc., ExxonMobil, Nuevo Energy,

Pacific Operators Offshore, and Venoco Inc. Two deepwater (>1,000 ft.) platforms operate in CA State waters,

both of which are owned by ExxonMobil. Financial information for these companies is presented in Table C2-9 

Aera Energy LLC, ExxonMobil, Nuevo Energy, and Venoco Inc. also operate platforms in State waters along

with two additional companies (Occidental Petroleum Co. and Rincon Island Limited Partnership). The

maximum depth of platform drilling in State waters is 211 ft. The maximum depth in State waters is 1,198 ft. 

ExxonMobil and Shell (owning the majority of the joint venture company, Aera Energy) are the only majors

operating in California State waters. The other companies are all unidentified. Nuevo Energy Company and

Arguello (a subsidiary of Plains Exploration and Production) are the only companies specifically identified as a

small business, with 412 employees and 354 employees (at the parent companies), respectively. Venoco Pacific

Operators, and Rincon Island, LP, are assumed small for lack of data. One of the firms in California is classified

as NAICS 324110 (SIC 2911), Petroleum Refineries, one firm is classified as NAICS 422720 (SIC 5172),

Petroleum and Petroleum Products Wholesale, and two additional firms are listed as NAICS 211111 (SIC 1311),

Crude Petroleum and Natural Gas Extraction. The NAICS classification of the remaining firms is undetermined.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities 

Table C2-8: Financial Conditions Among GOM Firms

Company Name Size Type Number of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Retu

As

AOC Energy DevelopmentCorp. Large** ForeignAGIP Petroleum Co Inc Large** ForeignAmerada Hess Corporation Large Major 11,662 $2,455,425 $1,608,133Anadarko Petroleum Corp. Large Independent 3,800 $1,280,000 $3,860,000 $825,000 64Apache Corporation Large Independent 1,958 $9,459,851 $544,000 $2,559,873 $554,329 5.

Apex Oil & Gas Inc Small* OtherArena Resources Small Independent 5 $6,050 $5,125 $1,657 $403 6.ATP Oil & GasCorporation Small Independent 53 $182,055 $38,547 $94,423 ($4,700) -2B T Operating Co Small* OtherBHP Billiton Petroleum(Americas) Inc Large** Foreign $2,865,000 $2,815,000 $718,000 25

Bois D'arc Offshore Ltd Small* OtherBP PLC Large Major 73,350 $164,090,000 $178,721,000 $10,422,000 6.Burlington ResourcesOffshore Inc Large Independent 2,003 $10,645,000 $3,832,000 $2,964,000 $454,000 4.Cairn Energy USA Inc Large** Foreign 19 $696,100 $70,000 $29,100 4.Callon PetroleumOperating Company Small Independent 100 $410,613 $140,960 $67,108 ($1,671) -0

Calpine Corporation Large Other 3,353 $23,266,992 $7,457,899 $118,618 0.

Century Exploration Co. Small* IndependentChevronTexaco Large Major 53,014 $77,359,000 $31,604,000 $99,049,000 $1,132,000 1.

Cockrell Oil Corporation Small* IndependentComstock Resources Small Independent 62 $683,071 $215,662 Conn Energy Inc Small* OtherConocoPhillips Company Large Major >10,000 $76,836,000 $56,748,000 ($295,000) -0Contour Energy E & P Small Independent 47
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C

Table C2-8: Financial Conditions Among GOM Firms

Company Name Size Type Number of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Return on Assets 

C2-20

LLCDenbury Resources Inc Small Independent 356 $895,292 $366,797 $285,152 $46,795 5.23% Dominion Resources Large Other 17,000 $37,909,000 $10,218,000 $1,362,000 3.59% Duke Energy Co. Large Other 22,000 $60,966,000 $15,663,000 $1,034,000 1.70% Dunhill Resources Inc Small* OtherDynegy Inc. Large Other 1,524 $20,030,000 $2,087,000 $5,553,000 ($1,955,000) -9.76% El Paso Corp. Large Other 11,885 $46,224,000 $8,377,000 $12,194,000 Energy Partners Ltd Small Independent 132 $384,220 $191,922 $134,031 ($8,799) -2.29% Energy ResourceTechnology Inc Small* IndependentEOG Resources Inc Large Major 1,000 $3,814,006 $1,672,395 $1,095,036 $87,173 2.29% 

Equilon Enterprises Large MajorExxonMobil Corporation Large Major 92,500 $153,000,000 $74,597,000 $205,000,000 $11,460,000 7.49% 

Fairways Specialty Sales &Service Inc Small* OtherForest Oil Corporation Small Independent 493 $1,924,681 $921,211 $475,694 Garden Banks Gas PipelineLLC Small* OtherGOM Shelf LLC Small* OtherGryphon ExplorationCompany Small* IndependentHall-Houston Oil Company Small* IndependentHC Resources LLC Small* OtherHouston ExplorationCompany Large Independent 145 $1,138,816 $592,789 $345,381 $70,494 6.19% 

Hunt Oil Company Small* IndependentHunt Petroleum (Aec) Inc Small* IndependentJ M Huber Corporation Small* Independent
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities 

Table C2-8: Financial Conditions Among GOM Firms

Company Name Size Type Number of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Retu

As

Juniper Energy LP Small* OtherKerr-McGee Corporation Large Independent 4,470 $9,909,000 $2,536,000 $2,540,000 ($485,000) -4Linder Oil Company, aPartnership Small* OtherMagnum HunterProduction Inc Small Independent 221 $251,069 $72,152 $48,834 ($3,512) -1

Marathon Oil Company Large Major 28,166 $4,479,000 $5,082,000 $31,720,000 $516,000 11

Maritech Resources Inc Small* OtherMatrix Oil and Gas Small* OtherMcDermott InternationalInc Large Other $128,171 ($416,757) $1,748,681 ($776,394) -605

McMoRan Exploration Co. Small Independent 18 $72,448 ($64,431) $43,768 $17,041 23

Merit Energy Company Large** ForeignMillennium OffshoreGroup Inc Large** Foreign

Mission Resources Corp. Small Independent 90 $342,404 $65,377 $105,464 ($38,484) -11Murphy Oil Company Large Major $3,885,775 $1,593,553 $3,966,516 $111,508 2.

National Fuel GasCompany Large Other

NCX Company LLC Small* IndependentNewfield ExplorationCompany Small Independent 488 $2,315,753 $1,009,231 $661,750 $73,847 3.Nexen Petroleum USA Inc Large** Foreign 1,767 $41,548,000 $1,971,300 $287,200 0.Nippon Oil Exploration US A Large** Foreign $11,076,000 $34,894,000 $269,000 2.

Noble Corp. Large Independent 624 $3,065,714 $1,989,210 $986,356 $209,503 6.Ocean Energy Inc Large Independent 948 $131,613 ($825) $47,483 $2,227 1.Offshore Energy I LLC Small* IndependentPanaco Inc Small Independent 21
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C

Table C2-8: Financial Conditions Among GOM Firms

Company Name Size Type Number of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Return on Assets 

C2-22

Petro Ventures Inc Small* OtherPetrobras America Inc Large** ForeignPetroquest Energy LLC Small Independent 57 $132,063 $97,770 $48,141 $2,307 1.75% Pioneer Natural ResourcesUSA Inc Large Independent 979 $3,455,100 $1,374,900 $717,400 $26,700 0.77% Pogo Producing Company Small Independent 219 $2,426,608 $824,885 $605,500 $87,954 3.62% PRS Offshore LP Small* IndependentRemington Oil and GasCorporation Small Independent 29 $288,993 $193,660 $104,186 $11,332 3.92% 

Royal Dutch/Shell Group Large Major Foreign 111,000 $152,691,000 $235,598,000 $9,419,000 6.17% 

Scana Petroleum ResourcesInc Small* OtherSpinnaker ExplorationCompany LLC Small Independent 65 $842,715 $692,977 $188,326 $31,579 3.75% 

St Mary Energy Company Small Independent 185 $537,139 $299,513 $196,394 $27,560 5.13% 

Stone Energy Corporation Small Independent 210 $1,179,371 $577,488 $377,495 $85,229 7.23% Tarpon Offshore LP Small* OtherTaylor Energy Company Small* IndependentTDC Energy CorporationLLC Small* IndependentTorch Offshore Inc. Small Other 362 $101,904 $79,867 $67,990 $395 0.39% TotalFinaElf E&P USA Inc Large** ForeignTranscontinental Gas PipeLine Corporation Large Other 1,261 $4,969,532 $2,476,513 $1,276,282 $163,041 3.28% 

Transworld Explorationand Production Inc Small* Other $12,665,000 $7,141,000 $2,674,000 ($3,732,000) -29.47% Tri-Union DevelopmentCorporation Small* Independent

UMC Pipeline Corporation Small* Independent
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities 

Table C2-8: Financial Conditions Among GOM Firms

Company Name Size Type Number of Employees Assets ($000) Equity ($000) Revenues ($000) Net Income ($000) Retu

As

Unocal Large Independent 6,615 $10,760,000 $3,298,000 $5,297,000 $331,000 3.

Vintage Petroleum Inc Large Independent 690 $1,775,804 $570,992 $664,263 ($143,664) -8

W & T Offshore Inc Small* IndependentWalter Oil & GasCorporation Small* IndependentWestport Oil and GasCompany LP Small* OtherWestport ResourcesCorporation Small Independent 333 $2,233,451 $1,132,006 $400,398 ($28,566) -1

William G Helis CompanyLLC Small* IndependentWilliams Company Large Other 7,300 $34,988,500 $5,049,000 $5,608,400 ($754,700) -2Note: Other is used if no designation for major or independent is provided in U.S. EPA, 2000.* Presumed small due to lack of data.** Presumed large - Foreign-owned.Source: Table C2-6; SEC, 2003; U.S. EPA, 2000.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-24

Table C2-9: Financial Information for Companies Operating Platforms in California Waters ($000)

Company Name Size Type Employees Total Assets Equity Revenues Net Income

Royal/Dutch Shell

(Aera Energy) Large Major 111,000 $152,691,000 $235,598,000 $9,419,000

Plains Exploration and

Production (Arguello) Small Other 354 $550,880 $173,820 $178,038 $26,237

ExxonMobil Large Major 92,500 $153,000,000 $74,597,000 $205,000,000 $11,460,000

Nuevo Energy

Company Small Independent 412 $855,171 $174,276 $323,056 $12,275

Pacific Operators

Offshore Smalla Other

Venoco, Inc. Smalla Independent

Rincon Island Limited

Partnership Smalla Other

Occidental Petroleum

Corp. Large Major 7,244 $16,548,000 $6,318,000 $7,491,000 $989,000

a

 Presumed small due to lack of data.

Source: ERG, 2004c; SEC, 2003; U.S. EPA, 2000.

c. Alaska Operations

There are two major regions of oil and gas production in Alaska. The first, the North Slope region, operates

generally from onshore locations or on gravel islands. Platforms are not used here.

The second region, Cook Inlet, Alaska, is divided into two regions: Upper Cook Inlet, which is in State waters

and is governed by the Coastal Oil and Gas effluent guidelines; and Lower Cook Inlet, which is considered

Federal OCS waters and is governed by the Offshore Oil and Gas Effluent Guidelines. This section refers

primarily to Upper Cook Inlet. 

There are 16 platforms and 3 onshore production facilities in Cook Inlet, Alaska, of which two platforms have

ceased operation and two platforms have suspended operation. The platforms are owned by five companies:

Forest Oil Corporation, Marathon Oil Corp., ConocoPhillips, XTO Energy, and Unocal Corp. Marathon owns the

two out-of-operation platforms and is not considered a potentially affected firm in Alaska. Unocal Corp. operates

the majority of platforms in the Cook Inlet region, with 10 platforms and 2 onshore treatment facilities. Only one

company operating in Cook Inlet waters, Forest Oil, is an independent and considered a small business. XTO is

also an independent, but is a large business. The remaining operators are all listed as majors, as is the operator

(BP) of the Duck Island structure in the Beaufort Sea (North Slope). Two of the firms in Alaska are listed under

NAICS 324110 (SIC 2911), Petroleum Refineries, and the three additional firms are listed as NAICS 211111

(SIC 1311), Crude Petroleum and Natural Gas Extraction. Financial data for these firms are presented in Table

C2-10

The Department of Fish and Game in Alaska developed a standard lease requirement for all water intake pumps to

be fitted with a screened enclosure. The requirement further States that the water intake at the surface of the

screen enclosure should not exceed 0.1 feet per second. For the purposes of the regulatory analysis, therefore, any

new platforms in the Cook Inlet or the North Slope regions are considered to be potentially affected by the 316(b)

requirements for entrainment, but not impingement, since the Alaska requirement meets or exceeds proposed

316(b) impingement standards.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-25

Table C2-10: Financial Information for Companies Operating Platforms in Alaska ($000)

Company Name Size Type Employees Tot. Assets Equity Revenues Net Income

Forest Oil Small Independent 493 $1,924,681 $921,211 $475,694 $21,276

BP Large Major 73,350 $164,090,000 $178,721,000 $10,422,000

ConocoPhillips Large Major >10,000 $76,836,000 $56,748,000 ($295,000)

XTO Energy Large Independent 867 $2,648,193 $907,786 $810,163 $186,100

Unocal Large Major 6,615 $10,760,000 $3,298,000 $5,297,000 $331,000

Source: ERG, 2004c; SEC, 2003; U.S. EPA, 2000.

C2-2.3 Existing Platforms with Intake Rates Meeting Proposed Rule Criteria

a. Overview of Existing Platforms as Model for New Platforms Subject to Phase III Regulation

Very few existing platforms appear to have CWISs with intake rates that meet the proposed rule’s criteria. Most

of the existing platforms with CWISs of this size are located in the deepwaters of GOM and in California and

Alaska waters (Cook Inlet). Using the same approach as outlined for determining existing MODUs with CWIS

intake rates meeting proposed rule criteria, EPA makes the following estimates, using the survey conducted for

the oil and gas sectors to support this rulemaking and voluntary data submitted by industry. See also ERG

(2004b).

EPA stratified the survey in the GOM into three strata: deepwater, shallow large (20+ slot platforms), and shallow

small (fewer than 20 slots).

The survey universe of deepwater structures was 24 (two structures were removed from the universe prior to the

survey because their CWIS intake rates were known to be less than 2 MGD). For the survey, EPA sampled four

facilities. There were no non-respondents. Only one of the four reported data showing them to have CWIS intake

rates meeting proposed rule criteria. Thus EPA estimated that six deepwater structures would have CWIS intake

rates meeting proposed rule criteria (24 divided by 4 is a weight of 6; with one respondent reporting an intake rate

of 2 MGD or more, this produces an estimate of six total new structures meeting proposed rule criteria). 

However, earlier data (see ERG, 2004a) indicate that eight structures in the deepwater have CWIS intake rates

meeting proposed rule criteria. EPA used the higher number of structures to estimate the proportion of existing

structures with CWISs meeting the proposed rule criteria to total structures in the deepwater. Given eight

structures meeting proposed rule criteria and 24 total structures, EPA believes that about 1/3 of deepwater

structures to be built will be equipped with intakes meeting the proposed rule’s criteria. Only one existing

deepwater structure has a total intake rate of over 20 MGD, and none have a total rate of over 50 MGD. All firms

currently operating multi-well structures in the deepwater GOM with CWIS rates that meet criteria are large.

For shallow water large platforms, EPA determined that existing 206 exluding platforms were either known to

have CWISs with intake rates meeting proposed rule criteria or their intake rates were unknown (an additional 3

platforms were known to have CWIS intake rates less than 2 MGD and were dropped from the sampling frame).

EPA sampled 33 platforms among the large platform group. Three of these were nonrespondents. No additional

platforms with intake rates meeting proposed rule criteria were detected using the survey. The nonrespondents

were thus assumed also to have CWIS intake rates not meeting proposed rule criteria. Four platforms, however,

were known to have CWISs meeting proposed rule criteria based on earlier data (see ERG, 2004a). None of these

were sampled. EPA therefore assumes only these four platforms have intake rates meeting proposed rule criteria. 

These platforms are owned by large firms (ExxonMobil and Marathon). Thus EPA assumes that if any large

platforms with CWIS intake rates meeting proposed rule criteria were to be built, they would be built by large

firms.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-26

For shallow small platforms, EPA determined that 2,194 platforms were in the universe of platforms in the

Federal GOM. The vast majority of these platforms have unknown CWIS intake rates. Four such platforms were

identified prior to EPA’s Phase III Survey as having CWIS intake rates exceeding 2 MGD (ERG, 2004a). None

of these was sampled. A total of 18 platforms with unknown CWIS intake rates were sampled (all responded),

but EPA determined that none of the sampled platforms had total design flow rates meeting proposed rule criteria. 

Although this is a very small sample, this finding is bolstered by EPA’s observations that platforms in State

waters are unlikely to have CWIS with intake rates totaling 2 MGD or more (ERG, 2004a). Platforms in State

waters and small platforms in Federal waters are generally similar structures. EPA therefore assumes that only

four small platforms located in the shallow water GOM have CWIS intakes meeting proposed rule criteria. These

four platforms are owned by ExxonMobil and BP, thus no small firms are estimated likely to build platforms with

greater than 2 MGD intake rates in shallow water.

In the GOM, therefore, EPA estimates that a total of 16 existing platforms have CWIS intake rates meeting

proposed rule criteria. All are owned by large firms, and most operate in the deepwater regions.

In California, EPA determined that 20 platforms either have CWIS intake rates totaling 2 MGD or more or their

CWIS intake rates were unknown (13 platforms with known intake rates were eliminated from the sampling

frame because their total intake was less than 2 MGD). EPA sampled 3 of these 20 platforms. Only one was

found to have an intake rate meeting proposed rule criteria. EPA thus assumes seven existing platforms in

California have total intake rates meeting proposed rule criteria (20 divided by 3 is a weight of 6.7, which yields 7

platforms weighted). A total of six platforms are known from earlier data (see ERG, 2004a) to have intakes rates

meeting proposed rule criteria, including the surveyed platform. Three have intake rates greater than 20 MGD but

less than 50 MGD. Of the six platforms with flow data showing rates meeting proposed rule criteria, three of

these are owned by a small business (Plains Exploration and Production/Arguello). The remainder are owned by

large businesses (Aera Energy, a joint venture between Shell and ExxonMobil, and ExxonMobil). 

In Alaska, EPA determined that 19 platforms/production facilities are in the survey universe (one platform was

known to have a total CWIS intake rate of less than 2 MGD and was dropped from the sampling frame). EPA

sampled two platforms, but only one was determined to have a CWIS intake rate meeting proposed rule criteria. 

EPA therefore estimates that there are 10 platforms in Alaska with intakes that meet proposed rule criteria (19/2 is

a weight of 9.5). Five of these (all located in Cook Inlet) have CWIS data showing them to have CWISs meeting

proposed rule criteria (ERG, 2004a). Of these structures with known CWISs of this size, all are platforms owned

by Unocal. Based on this, EPA might assume no small businesses currently operating would be affected in

Alaska. However, the most recently built platform in Cook Inlet, Osprey, was constructed by a small firm

(Osprey’s CWIS intake rates are unknown). To be conservative, EPA assumes that a small firm, much like Forest

Oil (Osprey’s owner), might be the type of firm to build a new structure in Alaska and such a structure might have

CWIS intake rates meeting proposed rule criteria. However, it is also entirely likely that no such structures will

be built within the time frame of the analysis.

In summary, there are 16 platforms in the GOM, seven platforms in California, and 10 platforms in Alaska, for a

total of 33 existing platforms that meet proposed rule criteria. Of these, three platforms or structures (one in the

deepwater and two in California) have CWIS intake rates greater than 20 MGD, and one platform (California) has

an intake rate greater than 30 MGD. No platforms have CWIS intake rates exceeding 50 MGD. 

b. Current Oil and Gas Production Levels and Trends

In 2002, 555 million bbls of oil and 4.5 million MMcf of gas were produced in the GOM. Fifty nine% of all oil

production in the GOM now comes from deepwater wells (MMS, 2003b). MMS has been using incentives such

as royalty relief to promote drilling of deep gas wells in GOM over the past few years. In recent years, the

drilling of such wells has increased and trends show a continuation of deep gas drilling and exploration in GOM. 

As technology advances and more deep gas wells are drilled, reserve estimates are being revised as more gas is

presumed recoverable. Deep gas wells in the GOM consist of deepwater drilling and deep shelf drilling in

shallow waters. Deep shelf gas production increased by 137 Bcf from 2000 to 2002. Approximately 20% of all

GOM exploration drilling was at greater than 15,000 ft. at the end of 2003. As the industry gains more

experience in deep gas drilling, and the technology continues to advance, experts predict that this trend will
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-27

continue to be a substantial percentage of gas exploration and production in GOM (Drilling Contractor, Jan./Feb. 

2004).

Standard & Poor's annual Report Card of the Oil and Gas industry in 2003 predicted that oil prices would average

approximately $19 per barrel, and that natural gas prices would average $3 per million Btu (MMBtu) (S&P,

2003). These price estimates were conservative, especially in light of the potential volatility in the market caused

by the war in Iraq. S&P stated factors such as rising non-OPEC production, slow economic growth, and the

resumption of Venezuelan operations as potential factors in lowering oil prices. In 2000, OPEC developed a price

band mechanism which would adjust production to keep price baskets within the range of $22/bbl to $28/bbl. 

OPEC has rarely used the mechanism and prices have fluctuated outside of the determined range a number of

times since the band’s inception. OPEC has, however, maintained a stable price of $20-$22 per barrel in recent

years, (Drilling Contractor, Nov/Dec 2003a). Currently, U.S. crude prices for the benchmark Texas Upper Gulf

Coast crude is $27.25 per bbl (OGJ, February 16, 2004). The economic analysis employs long run wellhead oil

and gas prices used by 316(b) survey respondents to project future platform financials. 

S&P also noted that natural gas in North America (onshore and offshore) has shown a 5% annual decline in

production. In 2002, production began well over 20% greater than the 5 year average, but the year ended with

production 15% lower than that same mark (S&P, 2003). Similar production trends in Canada, the most

important source of natural gas imports for the U.S., create speculation of rising natural gas prices. Recently

(February 4, 2004), the Henry Hub gas price (a leading gas benchmark) was $5.20/MMBtu

(http://www.wtrg.com/daily/oilandgasspot.html). Despite the current price level, Drilling Contractor predicts that

prices will decline over the next two years, falling to a range of $3.50 to $4.50 /MMbtu from 2004 to 2006. 

(Drilling Contractor, Nov/Dec 2003a). U.S. oil demand is predicted to increase by 1.5% each year while existing

fields should deplete at the same rate. The demand for natural gas is predicted to increase as well, albeit at a

slower rate (1%). 

c. Estimate of Platforms To Be Built That May Be Affected by the Proposal

In the deepwater region, EPA determined, based on MMS data, that approximately 2 to 4 structures are built each

year (see Figure C2-1 and Table C2-11). EPA assumes that an average of three such deepwater structures are

completed each year. EPA notes that out of 24 total structures in the deepwater as of 2003, 8 are estimated to

meet proposed rule criteria, or about a third of the total. EPA thus assumes that one structure per year out of the

three installed annually might have intakes meeting proposed rule criteria. Because only one structure currently

has a CWIS intake rate of greater than 20 MGD (and none have a CWIS intake rate of more than 30 MGD), EPA

assumes that only one structure out of 10 would be built having a CWIS intake rate of 20 MGD or more. This

would mean that EPA estimates two structures would be built with these intake rates over the 20-year

construction time frame. 

All of these structures are assumed to be constructed by large firms. Only large firms have built structures in the

deepwater GOM, except for a few subsea completions, which have not been identified as associated with intake

rates meeting proposed rule criteria. This scenario is likely to continue, given the resources required to construct

deepsea structures, which sometime exceed $1 billion dollars (U.S. EPA, 2000).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-28

Table C2-11: Count of Platform Installations

Year Deepwater Platforms Platforms in Shallow Water with

Greater than or Equal to 20 Wells

Platforms in Shallow Water

with Less than 20 Wells

1993 0 1 26

1994 2 4 57

1995 0 0 42

1996 2 1 63

1997 1 0 55

1998 4 2 60

1999 3 0 36

2000 2 0 55

2001 4 0 60

2002 2 0 66

2003 0 0 15

Note: 2003 is a partial year only.

Source: MMS, 2003b.

Among large (20+ slot) platforms, EPA determined that few, if any, such platforms might be built during the time

frame of the analysis (see Table C2-11). As the table shows, no platforms of this size have been built over the past

5 years. Given that so few of the existing platforms appear to resemble a new regulated project, EPA assumes no

new platforms of this size and with CWIS meeting proposed rule criteria would be constructed.

Among smaller platforms, EPA determined that although they are installed at a rate of about 50-60 per year (see

Table C2-11), they are unlikely to install CWIS of the size considered to meet proposed rule criteria. EPA

therefore assumes no new smaller platforms constructed in shallow water would be affected by the proposal.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-29

0

10

20

30

40

50

60

70

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Year of Installation

Number of Platforms

Deepwater Platforms

Platforms in Shallow

Water with Greater than

or Equal to 20 Wells

Platforms in Shallow

Water with Less than 20

Wells

Figure C2-1: Platform Installation by Year

Note: 2003 is a partial year only.

Source: MMS, 2003b.

The Federal offshore waters off the coast of California have been subject to a moratorium on lease sales since

1990. No platforms have been constructed since 1994, and no exploration has been undertaken since 1989. 

Currently the moratorium extends to 2012. President Bush has dropped opposition to the moratorium and

currently has no apparent plans to end the moratorium (Environmental News Network, 2003). The State has

indicated to the President that it wishes the moratorium to remain in place, and Governor Schwartzenegger has

been pushing for a “permanent ban on all oil drilling in coastal waters.” (MSNBC, 2003). There are, however, 40

leases off San Luis Obispo and Santa Barbara Counties that are not subject to the moratorium, and a consortium

of oil companies including Aera Energy have announced plans for exploratory drilling. Aera Energy plans to drill

in 2004. Political opposition to these plans is enormous, however (Sneed, 2004). Even if exploratory drilling is

allowed to take place, any platform construction would occur many years later. Given this strong level of

antipathy towards offshore oil and gas development in California, EPA believes that the construction of new

platforms, or any new drilling, in either State or Federal California offshore regions is unlikely in the time frame

of the analysis.

In Cook Inlet, Alaska, only one new platform has been constructed in recent years. Most new exploration and

development in this region takes place from existing infrastructure or from onshore locations using directional

drilling, in which wells are drilled both vertically and horizontally to reach potential reserves, sometimes

thousands of feet from the top-hole locations. No definitive plans appear to be in place for any new platforms in

State waters. In Federal waters, lower Cook Inlet is a source of potential activity, since MMS completed a lease
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-30

bid in April, 2004. However, given the long lead times between lease bid to operation, it may be relatively

unlikely that this lease bid will result in new platforms during the time frame of the analysis in either location. To

be conservative, however, EPA assumes one such platform might be constructed in Upper Cook Inlet (State

waters) and begin operation during the time frame of analysis. In other Federal areas in the Alaska region, little

new activity is underway. BP has dropped plans for its Liberty project in the Beaufort Sea area (Federal Register,

Vol. 67, No. 99 pp. 36020-36022). Although some leases are actively registered in the Beaufort Sea, the time

frame for development, if any is undertaken, could be beyond the time frame of this analysis.

C2-3 TOTAL NEW OIL AND GAS OPERATIONS

Table C2-12 summarizes the number of existing MODUs and platforms that are estimated to meet the proposed

rule’s criteria, had EPA decided to regulate existing oil and gas facilities, as well as new MODUs and platforms

expected to be built over the 20-year analytical period that might be required to install control technologies. Also

presented is an assessment of the number of firms involved that might be small businesses.

Table C2-12 Number of Existing and Future Offshore Oil and Gas Extraction Facilities Estimated or

Assumed To Meet Proposed Rule Criteria over a 20-Year Analysis Time Frame

Type of Oil and

Gas Facility

Existing Facilities New Facilities

No. with

>2 MGD

flows

No. with

>20 MGD

flows

No. with

>50

MGD

flows

No. of

Small

Firms

Potentially

Involveda

No. Built

in 20-Year

Period >2

MGD

No. Built

in 20-Year

Period

>20 MGD

No. Built

in 20-Year

Period

>50 MGD

No. of

Small

Firms

Potentially

Involveda

MODUs 172 12 12 6 103 3 3 0

Deepwater

Platforms (GOM) 8 1 0 0 20 2 0 0

20+ Slot

Platforms (GOM) 4 0 0 0 0 0 0 0

Other GOM

Platforms 4 0 0 0 0 0 0 0

California

Platforms 7 3 0 1 0 0 0 0

Alaska Platforms 10 0 0 1 1 0 0 1

Total 205 16 12 8 124 5 3 1

a

 No small firms are involved if the cutoff is 20 MGD or greater

Source: U.S. EPA Analysis, 2004. See the 316(b) Oil and Gas Compliance Cost Model, DCN 7-4018 and ERG, 2004b.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-31

REFERENCES

Alexanders Oil and Gas Connections. 2002. Shell Oil board elects Philip Watts and Rob Routs. Volume 7, issue

#10 Thursday, May 16, 2002.

Bureau of Census 2004. 1997 NAICS United States Structure, Including Relationship to 1987 U.S. SIC

http://www.census.gov/epcd/www/naicstab.htm

Drilling Contractor. 2003a. Deepwater success results in higher drilling activity. November/December

Drilling Contractor. 2003b. Large jackups are most notable of newbuilt rigs. November/December.

Drilling Contractor. 2004. Gulf deep shelf gas drilling expected to increase. January/February 2004.

Drilling Contractor. 2001. MMS: GOM deepwater activity, production to grow. November/December

Environmental News Network. 2003. Bush won’t challenge ban on new California offshore oil drilling. April 1. 

http://www.een.com/news/2003-04-01/s_3613.asp. Downloaded April 26, 2004.

ERG. 2003. Assessment of Platforms in the Gulf of Mexico That Are Likely To Be In Scope. Memorandum to

George Denning, EPA, from ERG. August 21, 2003.

ERG. 2004a. Non-CBI In-Scope Facility Database. Spreadsheet Submitted to the 316(b) Phase III Rulemaking

Record. DCN 7-3505.

ERG 2004b. Calculation of Weights for Engineering Cost Estimates. Memorandum to the 316(b) Phase III

Rulemaking Record. September 24, 2004.

ERG. 2004c. Expanded Universe of MODUs and Platforms. Spreadsheet Submitted to the 316(b) Phase III

Rulemaking Record. DCN 7-4022.

ERG. 2004d. Final MODU List. Spreadsheet Final MODU list.xls. Submitted to the 316(b) Phase III

Rulemaking Record. DCN 7-4029. 

MMS. 2003a. MMS Platforms Master Database. U.S. Department of the Interior. Minerals Management

Service. Downloaded 6/10/2003. DCN 7-4025.

MMS. 2003b. Deepwater production summary by year. www.gomr.mms.gov/homepg/offshore/

deepwatr/summary.asp downloaded 10/10/2003.

MSNBC. 2003. Will Gov. Schwarzenegger be green? December 12. http://msnbc.msn.com/id/3475222 

Downloaded April 26, 2004.

Oil and Gas Journal. 2004. Statistics: US Crude Prices. 67. February 16, 2004.

Offshore. 2003. Upgrades target deep gas and deepwater. Offshore Magazine. July 2003.

SEC. 2003. Security and Exchange Commission Edgar Database of Corporate Filings. 

http://www.sec.gov/edgar.shtml

S&P (Standard and Poors). 2003. Industry Report Card: Oil and Gas. January, 17, 2003.

Sneed, David. 2004. Oil drilling planned off SLO County in 2007. San Luis Obispo Tribune. April 27, 2004
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-32

U.S. Environmental Protection Agency (U.S. EPA) 2000. Economic Analysis of Final Effluent Limitations

Guidelines and Standards for Synthetic-Based Drilling Fluids and Other Non-Aqueous Drilling Fluids in the Oil

and Gas Extraction Point Source Category. EPA-821-B-98-020. December 2000.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Technical Development Document for the Proposed

Section 316(b) Phase III Rule. EPA-821-R-04-015. November 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-1

CHAPTER CONTENTS

C3-1 MODU Analyses . . . . . . . . . . . . . . . . . . . . . . . C3-2

C3-1.1 Aggregate National After-tax Compliance

Cost Analysis . . . . . . . . . . . . . . . . . . . C3-2

C3-1.2 Vessel-Level Compliance Costs . . . . . C3-3

C3-1.3 Impact Analysis . . . . . . . . . . . . . . . . . C3-5

C3-2 Economic Impact Analysis for Oil and Gas

Production Platforms . . . . . . . . . . . . . . . . . . . . C3-8

C3-2.1 Aggregate National After-tax Compliance

Costs . . . . . . . . . . . . . . . . . . . . . . . . . . C3-9

C3-2.2 Platform-Level Compliance Costs . . C3-10

C3-2.3 Impact Analysis . . . . . . . . . . . . . . . . . C3-12

C3-3 Total Costs and Impacts Among All Affected

Oil and Gas Industry Entities . . . . . . . . . . . . . C3-14

C3-4 Total Costs to Government Entities and Social

Costs of the 316(b) Phase III Rulemaking . . . C3-15

C3-4.1 Total Costs to Government Entities . C3-15

C3-4.2 Total Social Costs . . . . . . . . . . . . . . . C3-15

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C3-17

Chapter C3: Economic Impact Analysis for

the Offshore Oil and Gas Extraction

Industry

INTRODUCTION

The Proposed Section 316(b) Rule for Phase III

Facilities would potentially affect any new MODUs

and oil and gas production structures that use CWISs

with daily design combined intakes totaling at least 2

MGD (and at least 25% of water used for cooling

water purposes). This regulatory structure is the

similar to that applied to new electric generating and

other industrial facilities under the Section 316(b)

Phase I, Track 1 regulation.

This economic impact analysis is divided into four

sections. Section C3-1 presents the analysis of the

316(b) rulemaking on MODUs, Section C3-2 presents

the analysis of offshore oil and gas production

platforms, Section C3-3 summarizes the costs and

impacst on both MODUs and platforms and provides

totals for the combined industry subgroups, and

Section C3-4 presents costs to the Federal government

and total social costs. The first two sections each discuss the aggregate national after-tax compliance cost

estimates for new MODUs and platforms (as well as briefly summarize what these costs would be had existing

MODUs and platforms been covered by the proposed rule). These sections also present vessel-level or platformlevel pre- and after-tax compliance costs, and discuss impacts, both at the vessel/platform level and at the firm

level. The vessel/platform level impacts are assessed using two approaches. The first approach uses the existing

facilities that might represent new facilities and applies a cash-flow/net income-based analysis. The second

approach is a standard barrier-to-entry analysis that investigates the present value of initial permitting costs

(discounted to the assumed year of compliance) plus initial one-time capital/installation costs as a percentage of

the cost to construct a new MODU or platform. The firm-level analysis uses firm revenues at firms that are the

likeliest to construct new facilities. EPA applies a pre-tax and after-tax annualized cost of compliance

(incorporating permitting, monitoring, capital/installation, and O&M costs) for each MODU/platform the firm is

expected to build over the period of analysis. For simplicity and to be conservative, all new MODUs or

platforms/structures a firm is expected to construct during this time frame are assumed to be launched or to come

on line in one year for comparison to one year’s revenues at the potentially affected firms. The ratio of these

costs to revenues is then calculated and assessed as to whether this ratio might indicate the potential for firm-level

impacts. 

The methodologies used in each analysis are presented first in each section, followed by a discussion of the

analytic results.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-2

C3-1 MODU ANALYSES

C3-1.1 Aggregate National After-tax Compliance Cost Analysis

A number of costs must be considered in calculating the aggregate national after-tax compliance costs, each with

distinct timing considerations. Permitting costs are incurred by facilities, but these costs are incurred by facilities

to come under one of three General Permits. EPA assumes costs of studies needed to incorporate permit

requirements under the General Permits can be shared. EPA further assumes that all permitting costs would be

grouped into three general permit regions. These regions are Eastern Gulf of Mexico, Western Gulf of Mexico,

and Alaska. Other permit activities are facility-specific and would fall on each facility affected. The timing of

permitting costs is complex and was discussed in Chapter C1: Summary of Cost Categories and Key Analysis

Elements for New Offshore Oil and Gas Extraction Facilities. More information can also be found in U.S. EPA

(2004a) and ERG (2004a).

EPA assumes that four jackups and 1 semi-submersible will be built each year over the time frame of the analysis. 

EPA also assumes that three drill ships will be built, launched in 2012, 2017, and 2022 for a total of 103 MODUs

over the 20-year period of construction. Permitting costs, therefore, apply to 80 jackups, 20 semi-submersibles

and 3 drill ships. See Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry.

Pre-tax costs of installing and operating control technologies and for various permitting activities are input to a

spreadsheet in the year in which they are assumed to be incurred. Capital costs are assumed to be incurred every

10 years, and repermitting costs occur every 5 years. Each MODU is assumed to operate over a 30-year

compliance period. Costs are discounted to the year of compliance, assumed to be the year the MODU is

launched, and summed to produce the present value of costs in the year of compliance. These costs are then

annualized over 30 years. See Chapter C1: Summary of Cost Categories and Key Analysis Elements for New

Offshore Oil and Gas Extraction Facilities for more details on the cost discounting methodology.

To create after-tax costs, EPA assumes that the highest marginal corporate tax rate applies. This rate is 35% (IRS,

2002), so after-tax costs would be 65% of the pre-tax costs. EPA does this because all MODU owners that are

likely to build MODUs are large corporations by SBA standards and all have earnings in most years that place

them in the highest corporate tax bracket.

Table C3-1 summarizes the national aggregate after-tax compliance costs for MODUs. As the table shows, these

costs are $1.8 million per year over the time frame of the analysis. See ERG (2004a) for a detailed description of

how these costs were calculated. See also the 316(b) Oil and Gas Compliance Cost Model, DCN 7-4018

(hereinafter, Compliance Cost Model.

Had existing MODUs been covered by the proposed rule, the total national cost of the rule would have included

an additional $3.6 million per year (ERG, 2004b).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

1

 In the impact analysis, after-tax costs are applied to existing MODUs, but these are calculated in a more exact way, since the

existing MODUs have known marginal tax rates, and a depreciation schedule is used to more precisely calculate the after-tax cost impact

on cash flow; see Section C3-1 below and ERG, 2004c).

C3-3

Table C3-1: Total Aggregate National After-tax Compliance Costs for MODUs

(2003$)

Type of Cost Present Value

(year of compliance)

Annualized Cost of

Compliance

Permitting (a) $7,111,190 $535,575

Capital/Installation

Semi-submersibles $597,347 $44,989

Jackups $14,373,374 $1,082,522

Drill ships $765,049 $57,619

Total $15,735,770 $1,185,130

Monitoring $1,357,609 $102,247

O&M $0 $0

Total $24,204,569 $1,822,952

Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

C3-1.2 Vessel-Level Compliance Costs

This section addresses costs to each of the three types of new vessels. Again, permitting and monitoring costs are

from U.S. EPA (2004a), and capital/installation costs are from U.S. EPA (2004b). Weighted average costs

reported in the TDD (U.S. EPA, 2004b) and derived for existing facilities are calculated and applied to new

facilities as presented in a spreadsheet located in the rulemaking record (DCN 7-4030) and in the Compliance

Cost Model, DCN 7-4018. Pre-tax costs per vessel are used in the firm-level analysis. After-tax per facility costs

are also presented. After-tax costs are used for comparison to pre-tax costs and in the firm-level analysis, but are

not used directly in the vessel impact analysis.1

 Additional details on how these costs are calculated are presented

in ERG (2004a).

a. Pre-Tax Cost of Compliance for Representative Vessels

The costs shown in Table C3-2 reflect the costs assigned to each vessel, by type of vessel. The representative

vessels are those launched in 2007 (jackups and semi-submersibles) and 2012 (drill ship) for the purposes of

timing assumptions. All costs are discounted to the year of compliance, which is the same as the assumed year of

launching. This date may be prior to the date actual compliance is required for some vessels. Those constructed in

2007-2012 or 2014 (depending on location) are assumed to install and operate compliance equipment

immediately when they are constructed, even though permit requirements may not be in place at that time (see

Chapter C1: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas Extraction

Facilities for more details). The present value costs are calculated by inputting each cost into the year that it is

assumed to be incurred, which includes additional capital costs in years 11 and 21 after initial construction,

repermitting costs every 5 years, and monitoring costs in the appropriate years. The costs are taken out over 30

years, discounted to the year of compliance at the recommended OMB discount rate of 7%, and then summed. 

The present value cost is then annualized using a 30-year time frame assumption and 7% discount rate. Chapter

C1: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas Extraction Facilities

also discusses this process, as does ERG (2004a).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-4

Table C3-2 presents the costs of compliance on an annual basis for the three types of MODUs. As the table

shows, these costs range from $14,938 to $37,638 per year depending on type of vessel. These costs are small in

comparison to revenues associated with drilling even one exploration well in the deepwater GOM. The

construction of these types of wells cost oil and gas production companies about $25 million to $30 million per

well (U.S. EPA, 2000). The major portion of this outlay is paid to the operator of the MODU that drills the well. 

These costs are also small in comparison to typical MODU day rates, which can range from $150,000 to $250,000

per day (Hatton, et al., 2002).

Table C3-2: Per-Vessel Annualized Pre-Tax Cost of Compliance (2003$)

Type of Cost Present Value

(year of compliance)

Annualized Cost of

Compliance

Permitting (a)

Semi-submersibles $128,206 $9,656

Jackups $128,206 $9,656

Drill ships $66,191 $4,985

Capital/Installation 

Semi-submersibles $45,950 $3,461

Jackups $276,411 $20,818

Drill ships $392,333 $29,548

Monitoring

Semi-submersibles $24,189 $1,822

Jackups $24,189 $1,822

Drill ships $33,742 $2,541

O&M $0 $0

Total

Semi-submersibles $198,345 $14,938

Jackups $428,806 $32,295

Drill ships $492,266 $37,075

Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

b. After-tax Costs

After-tax costs are presented here for comparison purposes. After-tax costs are assumed to be lower than the pretax costs by the top marginal corporate tax rate of 35%. Thus the costs calculated are 65% of the pre-tax costs in

Table C3-2 above.

The annual after-tax, annualized, per-vessel compliance costs are $9,710 for semi-submersibles, $20,922 for

jackups, and $24,099 for drill ships, based on the pre-tax costs shown above in Table C3-2.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-5

C3-1.3 Impact Analysis

The impact analysis is conducted at two levels: vessel-level and firm-level. Although the financial condition of

new vessels cannot be known, the financial conditions of a few, representative existing vessels are reflected in

EPA’s 316(b) survey of MODUs. EPA received eight economic surveys from three semi-submersibles, three

jackups, and two drill ships. The financial information from these representative vessels is used for a general

assessment of how well these vessels would do financially if costs of the preferred option applied. The

representative vessels are thus a proxy for new sources subject to Phase III regulation. This analysis provides an

alternative assessment of the potential for barrier to entry.

The second vessel-level analysis is a more typical barrier-to-entry analysis conducted by EPA for new entities,

which looks at the present value of the initial permitting costs (including those associated with start-up activities,

pre-permitting studies and initial permit application activities), discounted to the applicable compliance year, plus

the initial one-time capital/installation costs of required control equipment and compares these costs to the

baseline construction costs for each type of MODU. EPA uses an initial permit cost stream represented by

MODUs expected to be constructed in 2007 (jackups and semi-submersibles) or 2012 (drill ships). See the

Compliance Cost Model (DCN 7-4018).

The firm-level analysis is a revenue test, comparing the revenues of firms likely to construct MODUs with the

annualized compliance costs for representative new vessels, assuming each firm identified as potentially affected

builds a share of the new MODUs expected to be constructed over the time frame of the analysis. For simplicity

and to be conservative, each firm is assumed to launch all their new MODUs in one year for comparison to one

year’s revenues. EPA uses the annualized cost stream for MODUs constructed in 2007 (or the cost stream for a

drill ship constructed in 2012, the first year post-compliance in which a drill ship is assumed to be constructed) to

represent the annualized costs to each potentially affected firm. EPA uses both the pre-tax and after-tax

compliance costs for comparison with revenues.

a. Vessel Impact Analysis Using Survey Vessels

To calculate the impact of the today’s proposal on new MODUs, EPA used two models – a cash flow/net income

model, which computes the estimated present value of after tax cash flow/net income for representative MODUs

(based on survey data) over a 30-year operating period for each new facility, and a post-tax cost calculation

model, which estimates the present value after-tax costs of compliance using engineering and permitting cost

inputs. These two models are used to analyze the effect of after-tax costs on after-tax vessel cash flow or net

income. For additional details on these models, see ERG (2004c) and DCN 7-4020.

Using data provided by surveyed MODU operators, EPA used both the reported after-tax net income and a

calculated cash flow figure for each survey MODU. EPA calculated cash flow using after-tax net income and

adding depreciation, depletion, and amortization (DD&A) back into net income, since DD&A are not cash

expenses. EPA used cash flow as an upper bound estimate of available cash and after-tax net income as a lower

bound estimate. EPA was only able to undertake financial analysis for those MODUs with a positive net income

or cash flow for the three years of financial information provided in the survey. EPA assumes that any MODU

whose cash flow or net income is negative over the three years of financial data availability is unlikely to be a

viable operation in the baseline and cannot be analyzed with respect to compliance costs.

EPA used the cash flow/net income over the three years of data collected to create a moving cycle of cash

flow/net income over the period of analysis. The years of data collected were 2000, 2001, and 2002, with 2002

generally being a poorer year for the industry as a whole. In this way, EPA was able to represent industry

financials in both good and bad years. The 3-year cycle provides a means for projecting the volatile oil and gas

business over each facility’s 30-year operating period, which is expected to include major swings in the prices of

oil and gas, the driving force behind the level of operations, pricing, and thus the financial performance of newly

constructed vessels. EPA assumed that cash flow/net income will be flat on average over the 30 years of analysis

and thus does not apply any factors to increase or decrease cash flow or net income over the years of analysis

within those cyclical movements. The cash flow/net income figures from the survey, therefore, repeat every three
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

2

 Permitting costs to platforms are assumed to be associated with the Western Gulf Permit; use of this assumption avoids potentially

understating the magnitude of shared costs to MODUs in Region 4.

C3-6

years for 30 years. EPA then computes the present value of that stream of cash flow/net income figures and

compares it to the present value of after-tax compliance costs for the preferred option.

EPA used the capital, O&M, and permitting costs to calculate the present value of the after-tax annualized cost of

compliance with the proposed requirements. Each cost is accounted for in the year in which it is assumed to be

incurred. EPA made the simplifying assumption that the existing MODUs would represent new MODUs that are

launched in 2007. Since EPA assumes MODUs launched in this year install and operate compliance equipment at

that time (even though they do not become permitted for compliance with 316(b) requirements until the date of

the first applicable General Permit renewal), EPA considers the date of launching the “compliance year.” 

The first costs to be incurred are the Region 6 and Region 4 pre-permitting costs (the shared study costs) and the

capital costs of installation and incremental O&M costs (O&M costs are estimated to be $0 for all MODUs). 

Costs for permit application activities occur in 2011 for the Region 6 permit and in 2013 for the Region 4 permit.

Only MODUs are assumed to be permitted under the Region 4 permit, since relatively little production activity is

currently underway in the Eastern Gulf.2

 Monitoring costs begin to be incurred in 2012. Repermitting costs enter

in 2017, and every 5 years thereafter. EPA estimated capital costs for each MODU for which a financial survey

response was received (with one exception), as well as many other MODUs for which financial data were not

obtained (all were used to calculate the average costs of compliance for new facilities). In this analysis, however,

only the costs for the eight MODUs with economic survey information were used for developing the costs for this

impact analysis.

EPA’s post-tax compliance cost model determined the marginal tax rate of the owner company based on the

firm’s average taxable earnings over the three years of survey data (which were put on a mid-year 2003 basis to

match the engineering costs, which were also set to 2003 dollars) and used the modified accelerated cost recovery

system (MACRS) to calculate depreciation on the capital outlay. Depreciation was then used to compute a “tax

shield” on the investment (for more information on EPA’s post-tax cost calculation model, see ERG [2004c] and

DCN 7-4020). The post-tax cost calculation model calculates the present value of after-tax compliance costs.

The present value output from the post-tax cost calculation model is then input to the cash flow/net income model

and used to compare with the present value of cash flow/net income of the vessel as discussed above. If the

present value of baseline after-tax cash flow or net income minus the present value of after-tax compliance costs

is greater than $0, EPA assumes that the MODU would be able to continue to operate post-compliance. If the

cash flow value becomes negative, EPA assumes the MODU would no longer continue to operate. If the net

income value becomes negative, EPA assumes the longer term viability of the vessel is potentially jeopardized. In

either case, such a MODU would be counted as a potential “regulatory closure.” This analysis is considered an

alternative assessment of the potential for barrier to entry.

Although many of EPA’s analyses investigate whether costs of compliance can be passed through to customers,

this analysis makes an assumption that costs cannot be passed through. Because existing MODUs would not have

to meet the requirements of the proposal, and new MODUs must compete with these existing MODUs, it is

unlikely that new MODUs would be able to pass through any compliance costs. Assuming zero cost pass-through

provides a realistic estimate of potential economic impacts to new MODUs.

Due to confidential business information (CBI) constraints, EPA is not able to provide detailed impact results on a

MODU-specific level. Detailed results are provided in the CBI portion of the Rulemaking Record (ERG, 2004c,

CBI version, and DCN 7-4020). The general findings of the closure analysis are that no new MODUs would be

regulatory closures, based on an assumption that finances for new MODUs might look like those for existing

MODUs, as a result of the incremental costs of compliance with the preferred option using either a cash flow or

net income approach.

b. Barrier to Entry Analysis (Vessel-Level)
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

3

 R&B Falcon was acquired by Transocean, Inc. (see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry).

C3-7

EPA used the incremental capital/installation costs and the net present value of permitting costs of compliance for

MODUs, as discussed above, using the cost streams associated with vessels launched in 2007 (jackups and semisubmersibles) and 2012 (drill ships), discounted to the compliance year. The sum of these costs (capital and

permitting) were then compared to the costs of constructing new MODUs. If these compliance costs comprised a

small fraction of construction costs, EPA assumed that compliance costs would not have a major impact on future

MODUs and would not have an effect on a decision to build additional MODUs.

EPA estimated the incremental capital costs to install CWISs that meet the requirements of 316(b) Phase I, Track

1. These costs are $26,008 for semi-submersibles, $156,450 for jackups, and $222,062 for drill ships. The present

value of a share of the permit costs is $101,192 for each vessel except those for drill ships, which are $24,521

(because they are assumed not be involved in the initial study cost sharing due to their much later assumed launch

dates). The total incremental initial investment costs, therefore, are $127,200 for semi-submersibles, $257,642 for

jackups, and $246,583 for drill ships). According to Drilling Contractor Magazine (2003), the cost of new

MODUs planned to be built in the next few years average $250 million for semi-submersibles and $125 million

for jackups. A drill ship completed in 1998 (R&B Falcon’s Pathfinder3

) cost approximately $275 million.

Incremental present value of permitting costs plus capital/installation costs are therefore estimated to range from

0.05% to 0.21% of construction costs, regardless of type of MODU. Because this is only a tiny fraction of total

costs of construction (and a tiny fraction of contingency, which typically ranges from 10% to 20% of

capital/installation costs), EPA believes that these costs would not have a material effect on decisions to build new

MODUs.

c. Firm-Level Analysis 

To determine the impact of the proposed rule on firms, EPA uses a revenue test, which compares the annualized

pre-tax and after-tax costs of compliance (calculated as discussed for each representative MODU as discussed

above), with 2002 revenues reported by all firms determined likely to build new MODUs meeting the proposed

rule’s criteria. Because nearly all of these firms (other than foreign-owned) are publicly owned, EPA relied on the

revenue data reported in Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry, which was

compiled from corporate 10K reports downloaded from SEC’s Edgar Database. EPA determined the number of

MODUs likely to be built by each firm under the proposed rule. Only those firms that were identified as currently

owning jackups, semi-submersibles, and drill ships that would meet the proposed rule’s criteria if newly

constructed are considered likely to construct the estimated 103 new MODUs that would be affected by the

proposal. These same firms also generally comprise the firms that are currently building new MODUs (see also

Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry). EPA then assigned a number of potentially

in-scope MODUs to be built by each of the firms and used the average per-MODU compliance costs multiplied

by the number of these potentially in-scope MODUs to calculate the total compliance costs that might be faced by

these firms. 

To calculate costs to revenues, EPA uses the pre-tax and after-tax costs shown in Table C3-2 for the firms

identified as likely to construct new MODUs meeting the proposed rule’s criteria. Each firm is assumed to build

12 jackups or semi-submersibles over the time frame of the analysis (a little over one every other year), except for

GlobalSantaFe and Transocean, which are assumed to build 20 jackups and one drill ship or two drillships,

respectively. For simplicity and to be conservative, EPA assumes that all MODUs estimated to be constructed by

these firms are launched in one year for comparison with one year’s revenues at those firms. EPA uses the higher

cost of a jackup rig to represent the cost of compliance for both jackups and semi-submersibles for simplicity.

Table C3-3 shows all of the MODU owners that are considered likely to build an in-scope MODU. As the table

shows, annualized pre-tax costs per firm range from $0.4 to $0.7 million. The ratio of pre-tax costs to revenues

ranges from 0.03% to 0.06% and after-tax costs to revenue range from 0.02% to 0.04%. Given that the highest

ratio seen is 0.06 percent, EPA concludes that firm-level impacts would be minimal. Furthermore, even if these

costs applied to other firms (among those that own jackups or semi-submersibles with unknown CWIS intake
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

4

 There are several firms owning jackups or semi-submersibles that did not submit voluntary technical data, so EPA is not able to

determine whether they own MODUs that might meet the proposed rule’s criteria were they to be newly constructed. These firms are

Atwood Oceanics, Caspian Drilling Co., Energy Equipment Resources, Nabors Industries, Newfield Exploration, Ocean Rig ASA, Parker

Drilling, Tetra Technologies, and Workships BV. Most of these firms, however, own only one or two such MODUs and are considered far

more likely to purchase MODUs from the firms included in this analysis than to build their own (several of these MODUs have clearly

been purchased from GlobalSantaFe, for example). Had these firms been included in the analysis, however, EPA’s findings would not

have changed. The firm with the lowest revenues in this group among those with publicly available data (Atwood Oceanics, Parker

Drilling, and Newfield Exploration; see Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry) reported 2002 revenues as

$149 million. Applying the same methodology that EPA used for the firms considered likely to build MODUs, EPA would predict that the

cost-to-revenue ratio among these firms considered unlikely to build MODUs would be at most 0.3 percent.

C3-8

rates that are considered unlikely to build new MODUs subject to Phase III regulation), impacts on any firm

would still be estimated to be much less than 1 percent.4

These costs reflect the assumption that all new jackups would be built with sea chests and, therefore, these vessels

would not be required to meet entrainment controls. However, jackups on rare occasions use straight pipes. If

jackups are not built with sea chests, the costs to comply with both impingement and entrainment contros would

result in the annualized per-vessel compliance costs to rise from $32,295 to $39,063. Under this scenario, the

costs to revenue ratios shown in Table C3-3 would be at most 0.08 percent (see DCN 7-4030 and DCN 7-4018).

Table C3-3: Revenue Test for MODU Owners

Name

No. of Likely Inscope Rigs >2

MGD Built in One

Year

Revenues

($millions)

Annualized

Pre-Tax Costs

per Firm

($millions)

Costs to

Revenues

(%)

Annual-ized

After-tax

Costs per

Firm

($millions)

Costs to

Revenues

(%)

Diamond Offshore 12 $753 $0.4 0.05% $0.3 0.03%

ENSCO 12 $698 $0.4 0.06% $0.3 0.04%

GlobalSantaFe 21 $2,018 $0.7 0.03% $0.4 0.02%

Noble 12 $986 $0.4 0.04% $0.3 0.03%

Pride 12 $1,270 $0.4 0.03% $0.3 0.02%

Rowan 12 $617 $0.4 0.06% $0.3 0.04%

Transocean 22 $2,674 $0.7 0.03% $0.5 0.02%

Total/Avg. 103 $9,406 $3.3 0.04% $2.2 0.02%

Source: SEC, 2003; U.S. EPA Analysis, 2004. See Compliance Cost Model, DCN 7-4018.

C3-2 ECONOMIC IMPACT ANALYSIS FOR OIL AND GAS PRODUCTION PLATFORMS

This section presents the aggregate national after-tax compliance costs for new oil and gas production platforms

that will be built in scope. It also presents platform-level compliance costs (in after-tax and pre-tax terms). 

Impacts on platforms are then presented in two sections. The first section uses a model of a new platform to

determine the potential for any effect on production. The second section uses an approach for identifying barriers

to entry for all platforms likely to be built in scope and for assessing impacts on those platforms for which

information was not sufficient to create a detailed economic model. As discussed in Chapter C2: Profile of the

Offshore Oil and Gas Extraction Industry, only 20 in-scope deepwater platforms and one in-scope Alaska

platform are expected to be constructed over the 20 year construction time frame of the analysis under the

proposed rule. 
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-9

C3-2.1 Aggregate National After-tax Compliance Costs

The methodology for calculating the aggregate national after-tax compliance costs are identical to that used for

calculating these same costs for MODUs, although the costs incurred are different. Costs are input in each year in

which they occur over the 30-year time frame of the analysis, including recurring capital replacement costs,

repermitting costs, and O&M. The costs in each year are discounted to the compliance year (assumed the year the

platform comes on line) and summed to calculate the present value of the cost stream. These present value costs

are then annualized. For more details on timing assumptions and annualized and present value cost calculations,

see Chapter C1: Summary of Cost Categories and Key Analysis Elements for New Offshore Oil and Gas

Extraction Facilities and ERG (2004a).

To create after-tax costs, EPA assumes that the highest marginal corporate tax rate applies. This rate is 35 percent

(IRS, 2004), so after-tax costs will be 65 percent of the pre-tax costs. EPA does this because all platform owners

that are likely to build in-scope platforms are large corporations by SBA standards and/or have earnings that place

them in the highest corporate tax bracket (including the one small corporation considered likely to build an Alaska

platform).

Table C3-4 summarizes the national aggregate after-tax compliance costs for production platforms. As the table

shows, these costs are $1.2 million per year over the time frame of the analysis. See ERG (2004a) for a detailed

description of how these costs were calculated. Also see DCN 7-4018.

Had existing platforms been covered by the proposed rule, the total national cost of the rule would have included

an additional $4.5 million per year (ERG, 2004b).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

5

 In the impact analysis, costs are input in the year in which they are assumed to be incurred, and the financial model

internally calculates the tax shield on these costs given depreciation schedules; see Section C3-2.3a below and ERG [2004d]).

C3-10

Table C3-4: Total National Aggregate After-tax Compliance Costs for Platforms

(2003$)

Type of Cost Present Value

(to year of compliance)

Annualized Cost of

Compliance

Permitting (a)

Deepwater $842,324 $63,439

Alaska $481,371 $36,254

Total $1,323,695 $99,693

Capital/Installation

Deepwater $5,227,966 $393,741

Alaska $390,008 $29,373

Total $5,617,974 $423,114

Monitoring

Deepwater $187,012 $14,085

Alaska $190,138 $14,320

Total $377,150 $28,405

O&M

Deepwater $7,703,465 $580,182

Alaska $1,371,845 $103,320

Total $9,075,310 $683,502

Total Compliance Costs

Deepwater $13,960,768 $1,051,447

Alaska $2,433,362 $183,267

Total National Compliance Costs $16,394,129 $1,234,714

Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

C3-2.2 Platform-Level Compliance Costs

This section addresses costs to each of the two types of platforms (deepwater and Alaska). Again, permitting and

monitoring costs are from U.S. EPA (2004a), and capital/installation and O&M costs are from U.S. EPA (2004b),

with the weighted average of the capital and O&M costs applied to new platforms/structures as calculated in DCN

7-4030. Pre-tax costs per platform are used in the firm-level analysis, along with after-tax costs. After-tax costs

are used for comparison to pre-tax costs but are not used directly in the platform impact analysis.5

 See ERG

(2004a) for more detail on how these costs were calculated. Also see DCN 7-4018.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

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a. Pre-Tax Cost of Compliance for Representative Platforms

The costs shown in Table C3-5 reflect the estimated costs incurred by each platform, by type of platform. Costs

are derived as above for computing national aggregate costs, but these costs are for a representative deepwater

platform that comes on line in 2007 (year of compliance assumed 2007) and the representative Cook Inlet

platform coming on line in 2014 (year of compliance). Costs (which are incurred over the full time frame of the

analysis, including recurring capital replacement and repermitting costs) are discounted to the applicable year of

compliance and annualized over 30 years at 7 percent.

Table C3-5 presents the costs of compliance on an annual basis for the two types of platforms. As the table

shows, these costs are $82,338 or $281,949 depending on type of platform.

Table C3-5: Per-Platform Annualized Pre-Tax Cost of Compliance (2003$)

Type of Cost Present Value

(Year of Compliance)

Annualized Cost of

Compliance

Permitting share

Deepwater $80,513 $6,064

Alaska $740,570 $55,776

Capital/Installation

Deepwater $402,151 $30,288

Alaska $600,012 $45,190

Monitoring share

Deepwater $18,021 $1,357

Alaska $292,520 $22,031

O&M

Deepwater $592,574 $44,629

Alaska $2,110,532 $158,953

Total

Deepwater $1,093,259 $82,338

Alaska $3,743,633 $281,949

Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

b. After-tax Costs for Representative Platforms

After-tax costs are presented here for comparison purposes. After-tax costs are assumed to be lower than the pretax costs by the top marginal corporate tax rate of 35 percent (IRS, 2002). Thus the costs calculated are 65 percent

of the pre tax costs in Table C3-5 above.

The annual after-tax per-platform compliance costs are $53,520 for deepwater platforms and $183,267 for the

Alaska platform, based on the pre-tax costs shown above in Table C3-5.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

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C3-2.3 Impact Analysis

The impact analysis for oil and gas production platforms is divided into two types: platform-level and firm-level. 

The platform-level analyses include two approaches to determining the potential for impacts. Although the

financial condition of new platforms cannot be known, the financial conditions of a few, representative existing

platforms are reflected in EPA’s 316(b) survey of production platforms. EPA received economic surveys from

one deepwater platform and one Alaska platform with CWIS intake rates meeting the proposed rule’s

requirements. The financial information from the deepwater platform is used for a general assessment of how

well new deepwater platforms would do financially if the proposed rule’s costs applied. The Alaska platform that

was surveyed, however, is a very old structure and is at the end of its productive life, thus has a production profile

completely different from what would be expected of a new operation. Furthermore, new platforms constructed

in Cook Inlet are far likelier to look like the Osprey platform, which is a departure from the older technology

represented by the other Cook Inlet platforms. The Osprey platform was designed to operate as a MODU until a

productive reservoir was located, at which point the MODU was designed to convert to a stationary production

platform. This design allowed Osprey to be built at a significantly lower cost than the traditional fixed platforms

located in the inlet. EPA does not have sufficient financial information at this time to model an Osprey-type

platform. For these reasons, the potential for impact on a new Alaska platform is assessed only in the second

platform-level analysis, described below.

The second platform-level analysis is a more typical barrier-to-entry analysis used for new entities. It uses the

present value of initial permitting costs (discounted to the year of compliance) plus the capital/installation costs

and compares these costs to the construction costs for each type of platform. This is a typical barrier-to-entry

analysis, which assesses incremental start-up costs associated with compliance to baseline start-up costs. 

The firm-level analysis is a revenue test, comparing the revenues of firms likely to construct platforms whose

CWISs meet the proposed rule’s criteria with the annualized compliance costs for each platform, assuming each

firm considered likely to build a regulated platform in the deepwater builds four platforms/structures over the time

frame of the analysis. For simplicity and to be conservative, EPA assumes the firms bring all platforms on line in

one year for comparison to one year’s revenues. One small firm is assumed the likeliest to build one platform in

Alaska during the time frame of the analysis, and this firm is assigned the cost of the one Alaska platform

assumed to be constructed during the analysis period.

a. Platform Impact Analysis Using Survey Platforms

Oil and gas production platforms are modeled somewhat differently than most other Phase III entities. Because

the surveyed deepwater platform was a relatively new structure in 2002 (the first year of survey data provided),

the model is built using survey data to represent new, later-built structures. 

Generally, the model can show production extending as far out as 30 years. Calculations, such as the after-tax

costs of compliance that are computed outside of the model platform framework (presented earlier in this

Chapter), use a 5 or 10-year time frame over which to annualize costs. The platform model operates somewhat

differently. Pre-tax costs are input into the model in the year in which they occur (including costs incurred in preproduction years). The model calculates after-tax costs, which are then annualized over the modeled production

life, which could be shorter than 30 years. For this reason, repermitting costs are input into the model every five

years and capital costs for CWISs are input every 10 years, until the model shows the platform is uneconomical to

operate.

EPA has developed a model deepwater oil and gas production platform based on information obtained from

EPA’s survey and from other sources of publicly available information, such as that from MMS. ERG (2004d;

non-CBI version) contains additional details on the methodology, non-CBI data, and assumptions on which the

model is based and how the model was constructed. EPA has used the same basic approach a number of times for

analyzing impacts of effluent guidelines on oil and gas facilities (see, for example, U.S. EPA, 2000). Usually, the

only differences are the input variables, such as production rates, that are used to model individual platforms. For

specific details on the values of variables defined by survey information and the detailed impact results, see ERG

(2004d; CBI version).
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

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The model is based on both a cash flow and net income approach. The projected net revenues are compared to

operating costs at each year for each model project. Net revenues (after subtracting royalties and severance,

which are payments to the lease owner and a State, if relevant) are based on an assumed price of oil, current and

projected production of oil and gas, well production decline rates, and severance and royalty rates. Operating

costs are based on a calculated cost per barrel of oil equivalent (BOE) produced. The model runs for 30 years or

is assumed to shut in when operating costs exceed revenues. That is, the economic model can calculate differing

lifetimes according to project characteristics. The model then calculates the lifetime of the project, total

production and the net present value of the operation (net income of the operation over the life of the project in

terms of today’s dollars), which includes the net operating earnings, taxes, expenditures on drilling, other capital

expenditures, etc. A positive net present value means that the project is a good investment. In this case the return

is greater than the discount rate, which represents the opportunity cost of capital. If the net present value is

negative, it means that money would have been better invested elsewhere.

The model is run twice–with and without the change due to the 316(b) Phase III requirements. The incremental

cost to retrofit I&E equipment is input into a capital expenditure line (which is used in both the cash flow and net

income calculations), and additional O&M and permitting costs are input to the cash flow section of the model.

The post-compliance results (including production, project life, and net present value of income) are compared to

those calculated under baseline assumptions. 

There are two ways the increased costs can have an impact on a platform. First, any increase in operating costs

might raise total operating costs enough to cause the operating costs to exceed net revenues earlier than in the

baseline. If the platform life is reduced, there will be a concomitant loss of production. Second, any increase in

costs, whether operating, capital or permitting, could also drive the net present value of a marginal operation

negative. The decision in this case would be to not develop the project rather than build the project with I&E

controls in place, since the project would not be considered a good investment. If the platform has a positive net

present value under baseline conditions but a negative net present value in the post-compliance scenario, EPA

notes an impact on the platform and estimates the production lost as a result.

Due to issues with CBI, the detailed results of the platform-specific impacts are not reported here. See ERG

(2004d; CBI version) in the CBI portion of the Rulemaking Record for detailed information on impacts. 

However, EPA determined that there would be no impacts on deepwater oil and gas development or production

due to the proposed rule’s costs based on model results. Impacts on net present value of projects is expected to be

very small.

b. Barrier to Entry Analysis (Platform Level)

EPA uses the incremental capital costs and present value of initial permitting costs for compliance for new

deepwater and Alaska platforms to compare to the costs of construction of new platforms, identical to the

approach used to measure impacts on MODU owners. If the initial investment costs of compliance are a small

fraction of baseline construction costs, EPA assumes that compliance costs would not have a major impact on

future platforms and would not have an effect on a decision to build additional oil and gas production platforms.

Costs for constructing deepwater platforms are estimated to range from $114 million to $2.3 billion (see U.S.

EPA, 2000). Forest Oil (Forest Oil, 2004) reports that the 2002 capital outlay for the Osprey platform in Cook

Inlet was $120 million (which does not include exploration, delineation, or additional costs to continue to develop

the platform). For deepwater platforms, EPA estimates that a platform coming on line in 2007 would incur costs

of $291,253 (deepwater) and $685,161 (Alaska) in capital/installation costs plus the present value cost of the

initial round of permitting costs. The ratio of incremental compliance costs to construction costs ranges from 0.01

percent to 0.3 percent for deepwater projects and 0.6 percent for an Alaska project. This is a small fraction of

contingency on these projects.

c. Firm Level Impacts

The firms that are considered affected are those identified as currently having platforms or structures in the

deepwater that meet the proposed rule’s criteria. In Alaska, Forest Oil is selected as the likeliest type of firm to

build an Alaska platform during the time frame of the analysis. All the firms considered likely to build a new
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-14

platform/structure subject to the proposed rule have publicly available data on 2002 revenues. Each firm is

expected to bring on line four affected platforms over the period of analysis. For simplicity and to be

conservative, EPA assumes all four platforms are brought on line in the same year for comparison to one year’s

revenues. The costs of compliance are calculated as the cost stream over the compliance lifetime of a

representative deepwater platform constructed in 2007 and an Alaska platform constructed in 2014, discounted to

the year of compliance and annualized (the same approach used for judging impacts on MODU owners). These

costs are then compared to firm-level revenues in a revenue test. Both pre-tax costs, reported in Table C3-5 above,

and after-tax costs are used to compare to revenues. 

Table C3-6 presents the affected firms in both regions of concern (deepwater and Alaska), their annual revenues,

their annualized pre-tax costs of compliance applied to all potentially affected structures they might construct, and

the ratio of their compliance costs to revenues. As the table shows, costs to revenues are 0.012 percent or less for

all affected firms. 

Table C3-6: Revenue Test for Platform Owners

Name No. of

Platforms

Revenues

($millions)

Pre-Tax PV

Costs

($millions)

Pre-Tax

Costs to

Revenues

After-tax

Initial

Investment

Costs

After-tax

Costs to

Revenues

Amerada Hess 4 $3,783 $0.3 0.009% $0.2 0.006%

BP 4 $178,721 $0.3 <0.001% $0.2 <0.001%

ChevronTexaco 4 $56,748 $0.3 0.001% $0.2 <0.001%

ExxonMobil 4 $205,000 $0.3 <0.001% $0.2 <0.001%

Forest Oil 1 $2,450 $0.3 0.012% $0.2 0.007%

Royal Dutch/Shell 4 $235,598 $0.3 <0.001% $0.2 <0.001%

Total 21 $682,300 $1.90 <0.001% $1.3 <0.001%

Source: SEC, 2003; U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

C3-3 TOTAL COSTS AND IMPACTS AMONG ALL AFFECTED OIL AND GAS INDUSTRY

ENTITIES

Table C3-7 on the following page summarizes the total costs and impacts associated with the 316(b) Phase III

Rulemaking on the oil and gas industry.

As the table shows, impacts on new MODUs and platforms and their associated firms are expected to be minimal, 

Aggregate national after-tax compliance costs are also shown in the table. These costs total $1.8 million per year

for MODUs and $1.2 million per year for platforms, which is $3.1 million per year over all affected new oil and

gas operations estimated to be constructed over the period of the analysis. 
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-15

Table C3-7: Total National Aggregate Annualized After-tax Compliance Costs and Impacts

for the Oil and Gas Industry (2003$)

O&G Facility Annualized After-tax Compliance Costs 

(in $millions, discounted to year of compliance) Facility Impacts Firm Impacts

MODUs $1.8 0 0

Platforms $1.2 0 0

Totala $3.1 0 0

a Totals may not sum due to independent rounding.

Source: U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

C3-4 TOTAL COSTS TO GOVERNMENT ENTITIES AND SOCIAL COSTS OF THE 316(B) PHASE III RULEMAKING

C3-4.1 Total Costs to Government Entities

The costs in Table C3-8 reflect those costs to Region 6, Region 4 and Region 10 to administer the costs of the

three General Permits as well as to maintain these permits over time as the number of permittees increases or

decreases. The details of individual cost items and timing assumptions can be seen in Chapter D2: UMRA

Analysis. Costs are arrayed over the time frame of the analysis and discounted at either 3% or 7% to 2007.

Table C3-8: Total Costs to Government Entities (2003$)

Government Entity Present Value Cost (2007) Annualized Cost

3% Discount Rate

EPA Region 6 $4,670,139 $231,327

EPA Region 4 $3,792,250 $187,843

EPA Region 10 $40,778 $2,020

Total government cost $8,503,168 $421,190

7% Discount Rate

EPA Region 6 $2,394,817 $180,364

EPA Region 4 $1,888,682 $142,245

EPA Region 10 $22,602 $1,702

Total government cost $4,306,101 $324,311

Source: U.S. EPA 2004a; U.S. EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.

C3-4.2 Total Social Costs

The total costs to government entities, plus the total pre-tax cost to industry are used as an approximation of total

social cost. There is no lost production of oil and gas calculated and no closures or firm failures are estimated.

Thus no social costs associated with employment dislocations are incurred. A small deadweight loss would occur,
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-16

but this is not calculated. Consumer and producer surplus losses are also not calculated, but they are captured in

the total pre-tax cost to industry. 

Table C3-9 presents the total social costs associated with the 316(b) requirements under the proposed rule. The

annualized social costs of the rule associated with the affected oil and gas industries under the proposed rule is

approximately $3.7 million using the 3 percent social discount rate suggested by OMB and $3.0 million per year

using OMB’s 7 percent discount rate.

Table C3-9: Total Social Costs of the Proposed Rulemaking for Oil and Gas Industries

(in millions, 2003$)

Cost Item Present Value Cost (2007) Annualized Costs

3 % Discount Rate

MODU compliance costs $37.5 $1.9

Platform compliance costs $28.0 $1.4

Total pre-tax compliance costs $65.4 $3.2

Government cost $8.5 $0.4

Total social costs $73.9 $3.7

7 % Discount Rate

MODU compliance costs $21.4 $1.6

Platform compliance costs $14.6 $1.1

Total pre-tax compliance costs $36.0 $2.7

Government costs $4.3 $0.3

Total social costs $40.3 $3.0

Note: Totals may not add due to independent rounding.

Source: EPA Analysis, 2004. See the Compliance Cost Model, DCN 7-4018.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

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REFERENCES

Drilling Contractor. 2003. Large jackups are most notable of newbuilt rigs. November/December.

ERG. 2004a. Cost Timing and Cost Sharing Assumptions for Industry Compliance Costs. Memorandum to the

316(b) Phase III Rulemaking Record. September 24, 2004.

ERG. 2004b. Costs for Existing Oil and Gas Facilities Had These Been Regulated Under 316(b) Phase III. 

Memorandum to the 316(b) Phase III Rulemaking Record. September 24, 2004.

ERG. 2004c. MODU Cost and Impact Calculations. Memorandum to the 316(b) Phase III Rulemaking Record

(Non-CBI version) and CBI Rulemaking Record (CBI version). September 24, 2004.

ERG. 2004d. Detailed Methodology and Results for Oil and Gas Production Platforms. Memorandum to the

316(b) Phase III Rulemaking Record (Non-CBI version) and CBI Rulemaking Record (CBI version). October 7,

2004.

Forest Oil. 2002. Presentation on Forest Oil Corporation given at Banc of America Securities Energy and Power

Conference. June 2002 Available at http://www.forestoil.com/downloads/presentation_bancofamerica_

jun_2002.pdf. 

Hatton, S., H. Howells, and M. Hudson. 2002. Reducing Drilling Costs: A High Pressure Small Bore Drilling

Riser System. 2H Offshore Engineering Ltd. Available at http://www.2hoffshore.com/papers/docs/new/

Paper61.pdf

SEC. 2003. Security and Exchange Commission Edgar Database of Corporate Filings. 

http://www.sec.gov/edgar.shtml

U.S. Department of the Treasury. 2002. Internal Revenue Service (IRS). 2002 Instructions for Forms 1120 &

1120-A, page 17 (Federal tax rates).

U.S. Environmental Protection Agency (U.S. EPA). 2004a. Information Collection Request for Cooling Water

Intake Structures Phase III Proposed Rule. ICR Number 2169.01. October 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2004b. Technical Development Document for the Proposed

Section 316(b) Phase III Facilities. EPA-821-R-04-015. November 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2000. Economic Analysis of Final Effluent Limitations

Guidelines and Standards for Synthetic-Based Drilling Fluids and Other Non-Aqueous Drilling Fluids in the Oil

and Gas Extraction Point Source Category. EPA-821-B-00-012. December 2000.
§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

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§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-1

CHAPTER CONTENTS

D1-1 Analysis of Manufacturers . . . . . . . . . . . . . . . . . . . D1-2

D1-1.1 Small Entity Determination . . . . . . . . . . . D1-2

D1-1.2 Percentage of Small Entities Regulated . . D1-7

D1-1.3 Sales Test for Small Entities . . . . . . . . . . D1-7

D1-2 Analysis of Electric Generating Facilities . . . . . . . D1-7

D1-2.1 Small Entity Determination . . . . . . . . . . . D1-8

D1-2.2 Percentage of Small Entities Regulated . D1-10

D1-2.3 Sales Test for Small Entities . . . . . . . . . D1-11

D1-3 Analysis of New Offshore Oil and Gas Extraction

Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D1-12

D1-3.1 Small Entity Determination . . . . . . . . . . D1-12

D1-3.2 Percentage of Small Entities Regulated . D1-14

D1-3.3 Sales Test for Small Entities . . . . . . . . . D1-14

D1-4 Summary of Regulatory Flexibility Analysis . . . D1-14

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D1-16

Appendix 1 to Chapter D1 . . . . . . . . . . . . . . . . . . . . . . D1A1-1

Appendix 2 to Chapter D1 . . . . . . . . . . . . . . . . . . . . . . D1A2-1

Chapter D1: Regulatory Flexibility Analysis

INTRODUCTION

The Regulatory Flexibility Act (RFA) requires

EPA to consider the economic impact a proposed

rule would have on small entities. The RFA

requires an agency to prepare a regulatory

flexibility analysis for any notice-and-comment

rule it promulgates, unless the Agency certifies

that the rule “will not, if promulgated, have a

significant economic impact on a substantial

number of small entities” (The Regulatory

Flexibility Act, 5 U.S.C. § 605(b)).

Small entities include small businesses, small

organizations, and small governmental

jurisdictions. For assessing the impacts of the

proposed regulation proposal on small entities, a

small entity is defined as: (1) a small business as

defined by the Small Business Administration’s

(SBA) regulations at 13 CFR 121.201; (2) a small

governmental jurisdiction that is a government of a city, county, town, school district or special district with a

population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is

independently owned and operated and is not dominant in its field.

The SBA small business size standards changed from a SIC code-based system to a NAICS code-based system on

October 1, 2000. Since EPA conducted its data collection effort for existing facilities before this change, EPA

performed the small entity analysis for existing facilities based on SIC codes. EPA then conducted a subsequent

analysis to determine whether use of NAICS codes-based size standards would yield different results. This

analysis showed, for the three proposed options as well as for all other evaluated options, that the small entity

determinations and assessments of small entity impacts are the same under both SIC-based and NAICS-based size

standards. Appendix 2 to this chapter presents the findings for the comparison of the SIC-based analysis and the

NAICS-based analysis.

To evaluate the potential impact of this rule on small entities, EPA identified the domestic parent entity of each

facility potentially subject to Phase III regulation, and determined its size. EPA then used a “sales test” to assess

the potential severity of economic impact on small entities. The test compares annualized compliance cost to total

entity sales revenues. This analysis uses three cost-to-revenue ranges to report the estimated number and

percentage of small entities incurring compliance costs: less than 1%; at least 1% but less than 3%; and at least

3%. EPA assumed that small entities with costs of 3% of revenues or more might be significantly impacted as a

result of the proposed rule.

EPA is proposing three options that define which existing facilities would be subject to the national categorical

requirements under the proposed rule: the “50 MGD for All Waterbodies” option (the “50 MGD All” option); the

“200 MGD for All Waterbodies” option (the “200 MGD All” option); and the “100 MGD for Certain

Waterbodies” option (the “100 MGD CWB” option). These options all require the same reduction in

impingement and entrainment (I&E), and differ only by design intake flow (DIF) applicability threshold and

waterbody type. As a result, the number of facilities that would be required to meet the national categorical

requirements varies among the three options: the 50 MGD All option, the proposed option with the broadest

applicability, would apply national categorical requirements to 136 facilities. The 200 MGD All option would

apply national categorical requirements to 25 facilities, while the 100 MGD CWB option would apply national
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

1

 EPA applied sample weights to the 199 facilities to account for non-sampled facilities and facilities that did not respond to the

survey. For more information on EPA’s 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.

EPA, 1999a).

D1-2

categorical requirements to 19 facilities. In addition to the analyses for the three proposed options, the appendix

to this chapter presents analyses for five other options evaluated but not proposed for existing facilities (Option 1,

Option 2, Option 3, Option 4, and Option 6).

EPA is also proposing section 316(b) requirements for new offshore oil and gas extraction facilities (also

abbreviated as “new OOGE facilities”) in Phase III. These proposed requirements are based on a 2 MGD DIF

applicability threshold and would apply to an estimated 124 new offshore oil and gas extraction facilities.

EPA’s analysis found that this proposed rule would not have a significant economic impact on a substantial

number of small entities. This determination is based on the finding that this rule would apply national

categorical requirements to only one small entity (entities that operate facilities subject to permit specifications

based on best professional judgment, BPJ, would not incur incremental compliance costs under this rule and are

excluded from this analysis). In the Manufacturers and Electric Generators industry segments, no small entity is

expected to meet the lowest proposed flow threshold of 50 MGD and therefore, no small entity in these segments

would be subject to the national requirements. In the new offshore oil and gas extraction industry segment, EPA

estimates that the proposed rule would apply national requirements to only one small entity. EPA estimates that

this entity would incur annualized after-tax compliance costs of less than 0.1% of annual sales revenues.

D1-1 ANALYSIS OF MANUFACTURERS

EPA’s 2000 Section 316(b) Detailed Industry Questionnaire (U.S. EPA, 2000) identified 199 facilities in the five

Primary Manufacturing Industries – Paper, Chemicals, Petroleum, Aluminum, and Steel – assessed as potentially

subject to the options considered for Phase III existing facilities. As described in Chapter B3: Economic Impact

Analysis for Manufacturers, these 199 facilities represent 532 facilities in those industries.1

 In addition, this

section also considers the effect of the regulation on facilities in Other Industries that are also expected to be

affected by the regulation. The analysis of facilities in Other Industries is restricted to a sample of 22 facilities for

which EPA received surveys but which are not part of the statistically valid sample. EPA estimates that 30 of the

199 sampled facilities in the five Primary Manufacturing Industries, representing 76 facilities industry-wide, and

four of the 22 known facilities in Other Industries are baseline closures; these facilities are excluded from this

analysis (see Chapter B3: Economic Impact Analysis for Manufacturers for more information). The remainder of

the small entity analysis for Manufacturers therefore discusses research done for the 169 sample facilities in

Primary Manufacturing Industries, representing 456 facilities that are open in the baseline, and an additional 18

known facilities in Other Industries that are open in the baseline.

Although EPA’s sample-based data for the Primary Manufacturing Industries support specific estimates of the

number of small entity-owned facilities, these data do not support a specific estimate of the number of small

entities that own these facilities. As a result, EPA estimated the number of small entities owning facilities in the

Primary Manufacturing Industries as a range, based on alternative assumptions about the ownership of regulated

manufacturing facilities by small entities.

D1-1.1 Small Entity Determination

The small entity determination for Manufacturers facilities was conducted in two steps:

< Identify the domestic parent entity of the 169 sample facilities in the Primary Manufacturing Industries

and the 18 additional known facilities in Other Industries.

< Determine the size of the entities owning the 169 sample facilities in the Primary Manufacturing

Industries and the 18 additional known facilities in Other Industries.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

2

 The SBA website provides the most recent size thresholds at http://www.sba.gov/regulations/siccodes. 

3

 For a comparison of the small entity determination using SIC codes and NAICS codes, respectively, see Appendix 2 to this chapter.

D1-3

a. Identification of Domestic Parent Entities

The RFA analysis is conducted at the highest level of domestic ownership, referred to as the “domestic parent

entity” or “domestic parent firm.” EPA gathered information on the domestic parent firm in the Detailed Industry

Questionnaire. In instances where a response was not provided, EPA used several other data sources to determine

the domestic parent firm including the Screener Questionnaire, corporate websites, and Dun & Bradstreet data

(D&B, 2003). EPA determined that 100 unique entities own the 169 facilities in the Primary Manufacturing

Industries. One known facility in the Other Industries was also found to be owned by a firm that owns facilities in

the Primary Manufacturing Industries. Therefore, the 100 unique entities own 170 sample facilities. The

remaining 17 facilities in Other Industries were found to be owned by 14 unique entities.

b. Size Determination of Domestic Parent Entities

EPA identified the size of each entity owning a potentially regulated Manufacturers facility using Small Business

Administration (SBA) size threshold guidelines.2

 These thresholds define the minimum firm-level employment or

revenue size, by industry (four-digit SIC codes), below which a business qualifies as a small business under SBA

guidelines.3

 To determine the entity size, EPA used data from the Detailed Industry Questionnaire, as well as the

Screener Questionnaire, corporate websites, the U.S. Securities and Exchange Commision’s (SEC) FreeEdgar

database, corporate websites, and Dun & Bradstreet data (SEC, 2004; D&B, 2003).

Table D1-1 presents the unique firm-level 4-digit SIC codes and corresponding SBA size standards used to

determine the size of entities that own Manufacturers facilities potentially subject to Phase III regulation.

Table D1-1: Unique 4-Digit Firm-Level SIC Codes and SBA Size Standards for Manufacturers a

SIC Code SIC Description SBA Size Standard

0133 Sugarcane and Sugar Beets $0.5 Million

1011 Iron Ores 500 Employees

1311 Crude Petroleum and Natural Gas 500 Employees

2011 Meat Packing Plants 500 Employees

2046 Wet Corn Milling 750 Employees

2061 Cane Sugar, Except Refining 500 Employees

2062 Cane Sugar Refining 750 Employees

2063 Beet Sugar 750 Employees

2075 Soybean Oil Mills 500 Employees

2211 Broadwoven Fabric Mills, Cotton 1,000 Employees

2421 Sawmills and Planing Mills, General 500 Employees

2611 Pulp Mills 750 Employees

2621 Paper Mills 750 Employees

2631 Paperboard Mills 750 Employees

2653 Corrugated and Solid Fiber Boxes 500 Employees

2673 Plastics, Foil, and Coated Paper Bags 500 Employees
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

Table D1-1: Unique 4-Digit Firm-Level SIC Codes and SBA Size Standards for Manufacturers a

SIC Code SIC Description SBA Size Standard

D1-4

2679 Converted Paper and Paperboard Products, NEC 500 Employees

2711 Newspapers: Publishing, or Publishing and Printing 500 Employees

2812 Alkalies and Chlorine 1,000 Employees

2813 Industrial Gases 1,000 Employees

2819 Industrial Inorganic Chemicals, NEC 1,000 Employees

2821 Plastics Material and Synthetic Resins, and Nonvulcanizable Elastomers 750 Employees

2824 Manmade Organic Fibers, Except Cellulosic 1,000 Employees

2833 Medicinal Chemicals and Botanical Products 750 Employees

2834 Pharmaceutical Preparations 750 Employees

2851 Paints, Varnishes, Lacquers, Enamels, and Allied Products 500 Employees

2869 Industrial Organic Chemicals, NEC 1,000 Employees

2873 Nitrogenous Fertilizers 1,000 Employees

2874 Phosphatic Fertilizers 500 Employees

2891 Adhesives and Sealants 500 Employees

2899 Chemicals and Chemical Preparations, NEC 500 Employees

2911 Petroleum Refining 1,500 Employees

3312 Steel Works, Blast Furnaces (Including Coke Ovens), and Rolling Mills 1,000 Employees

3313 Electrometallurgical Products, Except Steel 750 Employees

3315 Steel Wiredrawing and Steel Nails and Spikes 1,000 Employees

3316 Cold-Rolled Steel Sheet, Strip, and Bars 1,000 Employees

3317 Steel Pipe and Tubes 1,000 Employees

3334 Primary Production of Aluminum 1,000 Employees

3353 Aluminum Sheet, Plate, and Foil 750 Employees

3421 Cutlery 500 Employees

3714 Motor Vehicle Parts and Accessories 750 Employees

3728 Aircraft Parts and Auxiliary Equipment, NEC 1,000 Employees

3999 Manufacturing Industries, NEC 500 Employees

5153 Grain and Field Beans 100 Employees

5171 Petroleum Bulk Stations and Terminals 100 Employees

6141 Personal Credit Institutions $5.0 Million

6719 Offices of Holding Companies, NEC $5.0 Million

Source: U.S. SBA, 2000.

As discussed earlier, EPA estimated the number of small entities owning facilities in the manufacturing industries

as a range, based on alternative assumptions about the possible ownership of potentially regulated manufacturing

facilities by small entities. EPA considered two cases based on the sample weights developed from the facility

survey. These cases provide a range of estimates for (1) the number of firms incurring compliance costs and (2)
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-5

the costs incurred by any firm owning a regulated facility. Chapter B3: Economic Impact Analysis for

Manufacturers provides a more detailed description of these cases.

Case 1: Upper bound estimate of number of firms owning facilities that face requirements under the

regulation; lower bound estimate of total compliance costs that a firm may incur. 

For this case, EPA assumed (1) that a firm owns only the regulated sample facility(ies) that it is known to own

from the sample analysis and (2) that this pattern of ownership, observed for sampled facilities and their owning

firms, extends over the facility population represented by the sample facilities. This case minimizes the

possibility of multi-facility ownership by a single firm and thus maximizes the count of affected firms, but also

minimizes the potential cost burden to any single firm. 

Case 2: Lower bound estimate of number of firms owning facilities that face requirements under the

regulation; upper bound estimate of total compliance costs that a firm may incur.

For this case, EPA inverted the prior assumption and assumed that any firm owning a regulated sample

facility(ies) owns the known sample facility(ies) and all of the sample weight associated with the sample

facility(ies). This case minimizes the count of affected firms, while tending to maximize the potential cost burden

to any single firm.

Data in the rest of this section are presented by the industry sector of the firm. EPA determined firm sector based

on the sample facilities owned by the firm. If all of the sampled facilities owned by the firm are in the same

industry sector, then that industry sector was assigned to the firm. If sample facilities owned by the firm are in

more than one industry sector, then the firm was assigned to the “multiple industries” firm sector. As discussed

earlier, one known facility in the Other Industries group was found to be owned by a firm that owns facilities in

the Primary Manufacturing Industries. This firm is included in the data reported for multiple industries. The

remaining 14 entities that were found to own 17 facilities in Other Industries are presented separately.

The number of entities in Primary Manufacturing Industries that would be required to meet the national

categorical requirements set by the proposed options varies by option based on the DIF applicability threshold and

waterbody type specified in the option. Under the 50 MGD All option, between 46 (Case 2 estimate) and 105

(Case 1 estimate) firms would potentially be subject to Phase III regulation. Under the 200 MGD All option, the

number of firms potentially regulated is between 14 (Case 2) and 21 (Case 1). Finally, the 100 MGD CWB

option would potentially regulate between 12 (Case 2) and 21 (Case 1) entities. EPA determined that no firms

owning regulated 316(b) manufacturing facilities would be small.

Table D1-2 on the following page presents the total number of firms with facilities subject to the national

categorical requirements, as well as the number and percentage of those firms determined to be small. The data

are shown for the two ownership cases for the three proposed options.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-6

Table D1-2: Number of Firms by Firm Sector and Size (assuming two different ownership cases)

Firm Sector

Case 1: Upper bound estimate of number

of firms owning facilities that face

requirements under the regulation

Case 2: Lower bound estimate of number

of firms owning facilities that face

requirements under the regulation

Total

Number of

Firms

Number of

Small

Firms

Percentage

of Firms that

are Small

Total

Number of

Firms

Number of

Small

Firms

Percentage

of Firms that

are Small

50 MGD All Option

Paper 26 - 0.0% 13 - 0.0%

Chemicals 42 - 0.0% 12 - 0.0%

Petroleum 11 - 0.0% 9 - 0.0%

Steel 15 - 0.0% 7 - 0.0%

Aluminum 3 - 0.0% 1 - 0.0%

Multiple Industries 8 - 0.0% 4 - 0.0%

Firms that own facilities in Primary

Manufacturing Industriesa,b 105 - 0.0% 46 - 0.0%

Additional firms that own known

facilities in Other Industriesa 4 - 0.0% 4 - 0.0%

200 MGD All Option

Paper 3 - 0.0% 2 - 0.0%

Chemicals 4 - 0.0% 3 - 0.0%

Petroleum 3 - 0.0% 3 - 0.0%

Steel 7 - 0.0% 2 - 0.0%

Aluminum 0 - 0.0% 0 - 0.0%

Multiple Industries 5 - 0.0% 4 - 0.0%

Firms that own facilities in Primary

Manufacturing Industriesa,b 21 - 0.0% 14 - 0.0%

Additional firms that own known

facilities in Other Industriesa 1 - 0.0% 1 - 0.0%

100 MGD CWB Option

Paper 2 - 0.0% 1 - 0.0%

Chemicals 7 - 0.0% 3 - 0.0%

Petroleum 5 - 0.0% 4 - 0.0%

Steel 3 - 0.0% 1 - 0.0%

Aluminum 0 - 0.0% 0 - 0.0%

Multiple Industries 4 - 0.0% 3 - 0.0%

Firms that own facilities in Primary

Manufacturing Industriesa,b 21 - 0.0% 12 - 0.0%

Additional firms that own known

facilities in Other Industriesa 1 - 0.0% 1 - 0.0%

a Excludes firms whose only sample facilities close in the baseline. b Individual numbers may not add up to totals due to independent rounding.

Source: U.S. EPA Analysis, 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-7

D1-1.2 Percentage of Small Entities Regulated

As part of its assessment of the small entity impact of the proposed rule on Manufacturers, EPA estimated the

percentage of all small entities in the Primary Manufacturing Industries that would be expected to be subject to

the national requirements for each of the three proposed options. Because the analysis of facilities in Other

Industries is not based on a statistically valid sample, EPA could not estimate the number of entities in Other

Industries that would be subject to the regulatory requirements of the proposed options, nor the percentage that

are small entities. From its prior analysis of the use of cooling water in industries other than the electric power

industry, EPA judges the overall effect and coverage of Phase III regulation in the Other Industries to be minor in

relation to the effect and coverage in the five Primary Manufacturing Industries. 

EPA used the Statistics of U.S. Businesses (SUSB) published by the Small Business Administration to estimate

the total number of manufacturing establishments owned by small firms in each of the five Primary

Manufacturing Industries. EPA included all of the SIC industry groups with a sample facility in the five Primary

Manufacturing Industries. Based on the SUSB reporting framework, EPA considered all establishments owned

by a firm with 500 or fewer employees to be a small entity-owned establishment. This assumption will tend to

underestimate the number of small entity-owned establishments in these industry groups because the SBA small

entity size criterion is greater than 500 employees for some SIC codes. Underestimating the total number of small

entities would result in an overestimate of the percentage of small entities in these industries that subject to Phase

III regulation.

EPA estimated that 5,113 entities within the five Primary Manufacturing Industries are small. However, since no

small entity is expected to be subject to national requirements under the three proposed options, the percentage of

all small entities subject to Phase III regulation is zero.

D1-1.3 Sales Test for Small Entities

In addition to considering the fraction of small entities in each of the affected Manufacturers industries that would

be subject to Phase III regulation, EPA also assessed the extent of economic/financial impact on small entities by

comparing estimated compliance costs to estimated entity revenue (also referred to as the “sales test”). The

analysis is based on the ratio of estimated annualized after-tax compliance costs to annual revenue of the entity. 

For this analysis, EPA judges that entities for which annualized compliance costs equal or exceed 3% of revenue,

might experience a significant economic/financial impact as a result of the regulatory requirements under the three

proposed options.

EPA included the following compliance cost categories in this analysis: pilot study capital costs; one-time

technology costs of complying with the regulatory requirements; one-time costs of installation downtime; annual

operating and maintenance costs; and permitting costs (initial permit costs, annual monitoring costs, and permit

reissuance costs). A detailed summary of how these costs were developed is presented in Chapter B1: Summary

of Cost Categories and Key Analysis Elements for Existing Facilities and Chapter B3: Economic Impact Analysis

for Manufacturers. EPA collected revenue data for the small entities in EPA’s Detailed Industry Questionnaire.

In the Manufacturers segment, EPA determined that no small entities would face regulatory requirements under

the three proposed options; therefore, no small entities would incur compliance costs or significant economic

impact under these options.

D1-2 ANALYSIS OF ELECTRIC GENERATING FACILITIES

EPA’s 2000 Section 316(b) Detailed Industry Questionnaire (U.S. EPA, 2000) identified 113 Electric Generating

facilities potentially subject to Phase III regulation. EPA estimates that three of the 113 sample facilities are

baseline closures; these facilities are excluded from this analysis (see Chapter B5: Economic Impact Analysis for

Electric Generators for more information). The remaining 110 sample facilities represent 114 facilities in the
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

4

 EPA applied sample weights to the 113 facilities to account for non-sampled facilities and facilities that did not respond to the

survey. For more information on EPA’s 2000 Section 316(b) Industry Survey, please refer to the Information Collection Request (U.S.

EPA, 1999a).

5

 No political subdivisions were found to be subject to the national categorical requirements under any of the evaluated options. 

Political subdivisions are therefore not discussed in this chapter.

D1-8

industry.4 It is impossible, however, to determine the parent entities of extrapolated facilities. The remainder of

the small entity analysis for Electric Generators therefore discusses research done for the 110 sample facilities

only.

D1-2.1 Small Entity Determination

Similar to the analysis for Manufacturers, the small entity determination for Electric Generators was conducted in

two steps:

< Identify the domestic parent entity of the 110 sample facilities.

< Determine the size of the entities owning the 110 sample facilities.

a. Identification of Domestic Parent Entities

As previously described for Manufacturers, the RFA analysis is conducted at the highest level of domestic

ownership, referred to as the “domestic parent entity.” EPA first identified the immediate owner of the 110

sample Phase III Generators using the 2001 Form EIA-860 (U.S. DOE, 2001a). The immediate owners of power

plants can be classified into one of the following seven categories: investor-owned utility (IOU), nonutility,

Federal utility, State authority, municipality, political subdivision, or rural electric cooperative. IOUs and

nonutilities are private businesses; Federal utilities, State authorities, municipalities, and political subdivisions are

public sector entities; and rural electric cooperatives are not-for-profit enterprises.5

 EPA conducted research to

determine changes in facility- and entity-level ownership in order to identify the correct domestic parent entity of

each potential Phase III Electric Generator. EPA incorporated known ownership changes through the 2002

calendar year, but did not incorporate changes in facility/entity ownership that occurred after 2002 to maintain

consistency in its analyses.

Public sector entities and electric cooperatives are generally not owned by other entities. EPA therefore assumed

that these entities are the domestic parents of the facilities that they own. IOUs and nonutilities, on the other

hand, are often owned by holding companies. A holding company is defined by the U.S. Census Bureau as being

“primarily engaged in holding the securities of (or equity interests in) companies and enterprises for the purpose

of owning a controlling interest or influencing the management decisions of these firms” (Census, 2002). To

determine the domestic parent entity for potential Phase III Generators owned by an IOU or a nonutility, EPA

used several publicly available data sources, including data from the Department of Energy’s (DOE) Energy

Information Administration, 2001 Form EIA-860; 10-K filings available through the U.S. Securities and

Exchange Commission’s (SEC) FreeEdgar database; corporate websites; and Dun and Bradstreet data (U.S.

DOE, 2001a; SEC, 2004; D&B, 2003).

EPA determined that 72 unique domestic parent entities own the 110 sample Electric Generators.

b. Size Determination of Domestic Parent Entities

Different size thresholds apply to different types of entity (i.e., private businesses, public sector entities, and notfor-profit enterprises). Therefore, EPA used multiple data sources to determine the sizes of the Phase III domestic

parent entities:
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

6

 For a comparison of the small entity determination using SIC codes and NAICS codes, respectively, see Appendix 2 to this chapter.

D1-9

< For private businesses (including IOUs and nonutilities), the small entity size is defined based on the

parent entity’s SIC code and the related size standard set by the Small Business Administration (SBA).6

The SBA standards are based on employment, sales revenue, or total electric output (in megawatt hours,

MWh), by 4-digit SIC code. EPA used Dun and Bradstreet data, as well as the following publicly

available data sources, to obtain the information necessary to determine the entity size for private

businesses: 10-K filings available through the U.S. Securities and Exchange Commission’s (SEC)

FreeEdgar database, 1999 - 2001 EIA Form-860, U.S. Census Data, and company websites (D&B, 2003;

SEC, 2004; U.S. DOE, 2001a; Census, 2003). Table D1-5 presents the unique firm-level SIC codes and

the corresponding SBA size standards for Electric Generators that were used to determine the size of

privately-owned entities.

< All Federal and State governments are considered large for the purpose of the RFA analysis (U.S. EPA,

1999b).

< Municipalities are considered public sector entities. Public sector entities are defined as small if they

serve a population of less than 50,000. Population data for these entities were obtained from the U.S.

Census Bureau (Census, 2003).

< The SBA threshold for SIC 4911 (4 million MWh of total electric output) was used for the size

determination of rural electric cooperatives. The size determination was based on data from the 1999 -

2001 Form EIA-861 (U.S. DOE, 2001b).

Table D1-3 presents the unique firm-level 4-digit SIC codes and corresponding SBA size standards that were used

to determine the size of the entities that own Electric Generating facilities potentially subject to Phase III

regulation

Table D1-3: Unique 4-Digit Firm-Level SIC Codes and SBA Size Standards for

Electric Generators

SIC Code SIC Description SBA Size Standard

1311 Crude Petroleum and Natural Gas 500 Employees

1542 General Contractors – Nonresidential Buildings, Other than Industrial Buildings

and Warehouses $27.5 Million

2621 Paper Mills 750 Employees

4911 Electric Services 4 million MWh

4924 Natural Gas Distribution 500 Employees

4925 Mixed, Manufactured, or Liquefied Petroleum Gas Production and/or

Distribution $5.0 Million

4932 Gas and Other Services Combined $5.0 Million

4953 Refuse Systems $10.0 Million

6211 Security Brokers, Dealers and Flotation Companies $5.0 Million

9111 Executive Offices 50,000 Population

Source: U.S. SBA, 2000.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

7

 EPA used information on small IOUs from both Phase II (five) and Phase III (two) to adjust the number of small IOUs in the

Electric Generating industry.

8

 EPA used information on small in-scope municipalities from both Phase II (30) and Phase III (14) to adjust the number of small

municipalities in the Electric Generating industry.

D1-10

Based on these size thresholds, EPA determined that 13 out of the 72 parent entities owning the 110 sample

facilities are small entities. Nine of the 13 small entities are municipalities, two are nonutilities, and two are rural

cooperatives.

Under the proposed options, the minimum applicability threshold for national categorical requirements is 50

MGD or greater. Since Electric Generators with a DIF of 50 MGD or greater were covered by Phase II

regulation, no Phase III Generator would be subject to the national categorical requirements under any of the

proposed options.

D1-2.2 Percentage of Small Entities Regulated

As part of its assessment of the small entity impact of the proposed rule on Electric Generators, EPA compared

the number of small entities potentially subject to Phase III regulation to the number of small entities in the entire

industry. While no small entities would be subject to the national categorical requirements under any of the

proposed options, some of the other evaluated options would regulate small entities. This analytical step is

therefore relevant to the other evaluated options only.

EPA estimated the total number of small entities in the United States using information collected by the Energy

Information Administration (EIA). Based on Form EIA-861, 858 unique IOUs, Federal utilities, State authorities,

municipalities, and rural electric cooperatives operated electric power plants in the United States in 2001. In

addition, there were 2,127 nonutilities in 2001 (U.S. DOE, 2001a). EPA determined the entity sizes for rural

electric cooperatives based on their total electricity sales for 2001, as reported in Form EIA-861. All Federal

utilities and State authorities are assumed to be large. As described above, EPA researched holding company

information for Phase III IOUs and nonutilities, and population data for Phase III municipalities. It was not

feasible to conduct the same research for all those types of entities in the entire industry. EPA therefore used a

combination of methods to estimate the number of small IOUs, nonutilities, and municipalities operating in the

Electric Generating industry:

< Investor-owned entities: EPA determined which IOUs would be considered small based on the electric

output threshold of 4 million MWh, using the 2001 Form EIA-861. However, EPA’s analysis of the

domestic parent entity size of Section 316(b) IOUs (both for Phases II and III) showed that the small

entity determination based on the 4 million MWh threshold is not always the same as that based on the

holding company’s SIC code. EPA identified seven IOU-owned Phase II and Phase III Generators that

would qualify as small entities based on the 4 million MWh total electric output threshold.7

 However,

EPA’s holding company research showed that only one of these seven IOUs, or 14%, would also be

considered small at the holding company level. EPA therefore estimates that industry-wide only 14% of

private entities that are small at the IOU level would also be small at the holding company level. 

Accordingly, EPA reduced the industry-wide number of privately-owned small utilities (based on Form

EIA-861) by a factor of 86%. Using this method, EPA estimates that six investor-owned entities in the

Electric Generating industry are small.

< Municipalities: EPA determined which municipalities would be considered small based on the electric

output threshold of 4 million MWh, using the 2001 Form EIA-861 data. As with IOUs, EPA’s analysis

of Section 316(b) municipalities (both for Phases II and III) showed that the small entity determination

based on the 4 million MWh threshold is not always the same as that based on population. EPA’s

research of municipalities owning facilities potentially subject to Phase III regulation, showed that 44

municipalities would be small based on the 4 million MWh size standard.8

 Of these 44 entities, 26, or

59%, would also be considered small when using the population threshold. EPA therefore estimates,
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

9

 The 26 nonutilities are the immediate owners of the 31 Phase III nonutility facilities. These 26 nonutilities are owned by the 21

entities presented in Table D1-6.

D1-11

industry-wide, that only 59% of small municipalities, based on electric output, would also be small based

on population size. Accordingly, EPA reduced the industry-wide number of small municipalities (based

on Form EIA-861) by a factor of 41%. Using this method, EPA estimates that 302 municipalities in the

Electric Generating industry are small.

The adjustments made to IOU and municipality size determinations are based on the assumption that Section

316(b) IOUs and municipalities are representative of the EIA universe of electric utilities (for IOUs in terms of

their respective sizes at the utility level and the holding company level; for municipalities in terms of their

respective sizes based on electric output and population). If this is not the case, the industry-wide estimate of

small IOUs and municipalities may be over- or underestimated.

< Nonutilities: Electric output data or other information to determine the entity sizes of nonutilities are not

available from the EIA or other public data sources. As a result, EPA estimated a range of the number of

small nonutilities based on two methods: (1) EPA assumed that the proportion of small nonutilities in the

industry as a whole is the same as the proportion of small nonutilities potentially subject to Phase III

regulation (i.e., two out of 26, or 7.7%);9

 and (2) EPA assumed that the proportion of small nonutilities in

the industry as a whole is the same as the proportion of total IOUs, municipalities, political subdivisions,

and rural electric cooperatives estimated to be small based on electric output (i.e., 412 of 817, or 50.4%). 

Using these two methods, EPA estimates that between 132 and 866 nonutilities within the entire Electric

Generating industry are small.

EPA estimates that the total number of small entities in the Electric Generating industry is between 544 and 1,278. 

However, since no small entities would be subject to the national categorical requirements under any of the

proposed options, the percentage of all small entities subject to Phase III regulation is zero.

D1-2.3 Sales Test for Small Entities

As previously described for Manufacturers, the final step in the RFA analysis consists of analyzing the cost-torevenue ratio of each small entity subject to Phase III regulation (also referred to as the “sales test”). The analysis

is based on the ratio of each parent entity’s aggregated after-tax compliance costs (summed over each facility

owned by the parent entity and subject to the national categorical requirements) to its total sales revenue. EPA

used a threshold of 3% to determine entities that might experience a significant economic impact as a result of

Phase III regulation.

The estimated annualized after-tax compliance costs include all direct costs incurred by facilities: pilot study

capital costs; one-time technology costs of complying with the Phase III regulation; one-time costs of installation

downtime; annual operating and maintenance costs; and permitting costs (initial permit costs, annual monitoring

costs, and permit reissuance costs). A detailed summary of how these costs were developed is presented in

Chapter B1: Summary of Cost Categories and Key Analysis Elements for Existing Facilities and Chapter B5:

Economic Impact Analysis for Electric Generators. None of the small entities that own facilities potentially

subject regulation owns more than one Electric Generating facility. Therefore, no small entity would be expected

to incur compliance costs for more than one facility under any of the evaluated options.

EPA collected revenue data for the small entities with potentially regulated Phase III Electric Generators from one

of several sources, listed in order of preference: (1) Dun and Bradstreet, (2) average utility revenue (1999-2001)

from Form EIA-861, and (3) other sources such as company annual reports or websites (D&B, 2003; U.S. DOE,

2001b).

As previously noted, Electric Generating facilities with a DIF of 50 MGD or greater, the minimum DIF

applicability threshold of the three proposed options, were covered under the final Section 316(b) Phase II rule. 

Therefore, no Electric Generators are regulated or incur compliance costs under any of the proposed options.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-12

D1-3 ANALYSIS OF NEW OFFSHORE OIL AND GAS EXTRACTION FACILITIES

This section discusses EPA’s analysis of potential small entity impacts of the proposed rule on the new offshore

oil and gas extraction industry segment. The proposed Phase III regulation for new offshore oil and gas extraction

facilities is based on a 2 MGD DIF applicability threshold and would regulate an estimated 124 new offshore oil

and gas extraction facilities.

D1-3.1 Small Entity Determination

EPA used the information on existing small entities in the offshore oil and gas extraction industry to estimate the

number of small entities associated with new facilities. EPA identified 24 small entities currently operating

mobile offshore drilling units or platforms that could potentially be regulated by the proposed option for new

facilities, should they construct new MODUs or platforms similar to those currently in operation.

a. Mobile Offshore Drilling Units (MODUs)

EPA first identified the operating companies of existing MODUs operating in the Gulf of Mexico and the number

of rigs owned by each company. EPA then linked these operating companies to their domestic parent companies. 

EPA identified 21 parent firms potentially affected by the proposed rule for new facilities (see Table C2-2 in

Chapter C2: Profile of the Offshore Oil and Gas Extraction Industry). These affiliations were determined

primarily on the basis of Security and Exchange Commission (SEC) data using the FreeEdgar database, on which

all filings of publicly held firms are available (SEC, 2004). The 10-K and 8-K reports were the primary sources

used to collect this information. The 10-K annual reports generally list significant subsidiaries of the parent

company and are the source of income statement and balance sheet information used for characterizing financial

conditions at a firm. The subsidiary lists were used to confirm ownership relationships. The 8-K forms, in which

significant changes to the firm must be announced, are often the source of information on mergers and

acquisitions. 

EPA identified the NAICS code for each of the domestic parent companies currently operating a MODU in the

Gulf of Mexico and the SBA size standard for each code. Table D1-4 shows that of the 21 parent entities

operating MODUs in the Gulf of Mexico, only two entities could be identified as small. These companies own

approximately 0.5% of all MODUs operating in the Gulf of Mexico.

Table D1-4: Unique 4-Digit Firm-Level SIC Codes, NAICS Classification, and SBA Size Standards for

Mobile Offshore Drilling Units

SIC Code NAICS Code NAICS Title SBA Size Standard

Total Number of

Firmsa

Small Large

1311 211111 Crude Petroleum and Natural

Gas Extraction 500 employees 2 -

1381 213111 Drilling Oil and Gas Wells 500 employees - 6

1389 213112 Support Activities for Oil and

Gas Operations $7.5 million in revenues - 1

2819 211112 Natural Gas Liquid Extraction 500 employees - 1

a Does not include seven foreign firms and four unknown firms for which NAICS or SIC codes could not be located in publicly

available data.

Source: SEC Edgar Database; 10K filings; 13 CFR Part 121.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-13

EPA estimates that 80 jack-up MODUs, 20 semi-submersible MODU, and three drillships will be built during the

entire 20-year period of analysis, for a total of 103 new sources (see Chapter C2: Profile of the Offshore Oil and

Gas Extraction Industry for a detailed discussion of the estimated number of new MODUs). Given that large

companies currently operate approximately 99.5% of the existing facilities, EPA estimates that no small entities

will be building new MODUs potentially subject to Phase III regulation.

b. Platforms

 ̃ Gulf of Mexico

EPA determined, based on data from the Bureau of Land Management’s Minerals Management Service (MMS),

that, on average, one potentially regulated structure is built per year in the deepwater portion of the Gulf of

Mexico. EPA therefore estimates that 20 structures will be constructed over the time frame of the analysis. With

the exception of a few subsea completions, which do not operate potentially regulated CWIS, only large firms

have built structures in the deepwater Gulf of Mexico. This trend is likely to continue, given the resources

required to construct deepsea structures, which sometimes exceed $1 billion dollars (EPA 821-B-00-012). 

Therefore, all of these structures are assumed to be constructed by large firms. 

 ̃ California

EPA does not project any platforms off the California coast to be constructed during the time period of evaluation. 

Therefore, no small entities owning platforms in this area would be affected by this rule.

 ̃ Alaska

In Cook Inlet, Alaska, only one new platform has been constructed in the last 16 years. Most new exploration and

development in this region takes place from existing infrastructure or from onshore locations. No definitive plans

appear to be in place for any new platforms in State waters. In Federal waters, lower Cook Inlet is a source of

potential activity, since MMS completed a lease bid in April, 2004. However, given the long lead times between

lease bid to operation, it may be unlikely that this lease bid will result in new platforms during the time frame of

the analysis. To be conservative, however, EPA assumes that one such platform might be constructed in either

Federal or State waters and begin operation in 2014. In other Federal areas in the Alaska region, little new

activity is underway. BP has dropped plans for its Liberty project in the Beaufort Sea area. Although some leases

are actively registered in the Beaufort Sea, the time frame for development, if any is undertaken, is likely to be

beyond the time frame of this analysis. Because the most recently installed platform in Cook Inlet was built by a

small entity, EPA projects that one small entity in Alaska would potentially be affected by the rule. This platform

is estimated to have a DIF of greater than 2 MGD.

In summary, EPA projects that 20 new deepwater platforms in the Gulf of Mexico and one new platform in Cook

Inlet would be potentially regulated under the proposed rule. All new platforms expected to be built in the Gulf

of Mexico are assumed to be owned by large entities. The one new platform expected to be built in Cook Inlet is

assumed to be owned by a small entity. For more information on oil and gas platforms, including profiles and

projections for the number and type of new facilities estimated to begin operation, see Chapter C2: Profile of the

Offshore Oil and Gas Extraction Industry.

D1-3.2 Percentage of Small Entities Regulated

Due to the capital requirements for constructing a new MODU or platform with a DIF of 2 MGD or more, very

few small businesses are expected to be affected by the proposed rule. For existing offshore oil and gas extraction

facilities, EPA identified two small businesses operating MODUs, 21 small businesses operating platforms in the

Federal Gulf of Mexico waters, and one small business operating a platform in Cook Inlet, Alaska for a total of 24

small businesses (four MODU owners and 37 platform owners could not be identified as small or large, since no

financial data on these firms were publicly available). EPA estimates one small entity would potentially be

subject to the proposed rule for new offshore oil and gas extraction facilities. Therefore, one of 24 identified

small entities in the offshore oil and gas extraction industry (4%) is estimated to be subject to Phase III regulation.

D1-3.3 Sales Test for Small Entities
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-14

There are no small entities projected to build new MODUs or deepwater platforms in the Gulf of Mexico that are

potentially subject to the proposed rule. In Alaska, Forest Oil is considered the likeliest type of firm to build an

Alaska platform during the time frame of the analysis. In 2002, Forest Oil reported revenues of $2,450 million. 

The annualized pre-tax costs of compliance applied to all known affected or potentially affected structures owned

by Forest Oil are $0.28 million and the annualized after-tax costs are $0.21 million. The cost-to-revenue ratio for

the one small entity projected to be in scope of the proposed rule is therefore approximately 0.012% pre-tax or

0.008% after-tax.

D1-4 SUMMARY OF REGULATORY FLEXIBILITY ANALYSIS

The RFA analysis, conducted in developing this proposed rule, is summarized in Table D1-5 on the following

page. No small entity would be subject to the national categorical requirements for existing facilities under any of

the three proposed options. Only one small entity would be subject to the national categorical requirements for

new offshore oil and gas extraction facilities under the proposed rule. This small entity is estimated to incur

compliance costs of less than 0.1% of annual revenues. As a result of this analysis, EPA concluded that the

proposed rule would not have a significant economic impact on a substantial number of small entities

Table D1-5: Summary of Small Entity Impact Ratio Ranges by Sector

Industry Total Number of

Small Entities

Number of Small

Entities Owning

Facilities

Potentially Subject

to Regulation

Percentage of

Small Entities

Subject to

Regulation

Compliance Cost/Annual

Revenues

0-1% 1-3% >3%

Proposed Options for Existing Facilities / 2 MGD Option for New OOGE Facilities

Manufacturers 5,113 - 0.0% - - -

Electric Generators 543 - 1,295 - 0.0% - - -

New OOGE Facilities 24 1 4.2% 1 - -

Total 5,680 - 6,432 1 0.0% 1 0 0

Source: U.S. EPA Analysis, 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-15

REFERENCES

Dun and Bradstreet (D&B). 2003. Data extracted from D&B Webspectrum over 2002 and 2003.

Regulatory Flexibility Act. Pub. L. 96-354, Sept. 19, 1980, 94 Stat. 1164 (Title 5, Sec. 601 et seq.). 

U.S. Census Bureau, Population Division (Census). 2003. National Population Dataset. Accessed September

2003. Available at: http://eire.census.gov/popest/estimates_dataset.php

U.S. Census Bureau (Census). 2002. 1997 NAICS Definitions: 551 Management of Companies and Enterprises.

Available at: http://www.census.gov/epcd/naics/NDEF551.HTM 

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

U.S. Department of Energy (U.S. DOE). 2001b. Form EIA-861. Annual Electric Power Industry Report.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Technical Development Document for the Proposed

Section 316(b) Rule for Phase III Facilities. EPA-821-R-04-015. November 2004.

U.S. Environmental Protection Agency (U.S. EPA). 2000. Detailed Industry Questionnaire: Phase II Cooling

Water Intake Structures.

U.S. Environmental Protection Agency (U.S. EPA). 1999a. Information Collection Request (ICR), Detailed

Industry Questionnaires: Phase II Cooling Water Intake Structures & Watershed Case Study Short

Questionnaire. August 1999.

U.S. Environmental Protection Agency (U.S. EPA). 1999b. Revised Interim Guidance for EPA Rulewriters:

Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act. March 29,

1999.

U.S. Securities and Exchange Commission (SEC). 2004. FreeEdgar Database. Accessed between 1999 and

2004. Available at: www.freeedgar.com.

U.S. Small Business Administration (U.S. SBA). 2000. Small Business Size Standards. 13 CFR §121.201.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 1 to Chapter D1

D1A1-1

Appendix 1 to Chapter D1:

Summary of Results for Alternative Options

This appendix presents the results of the RFA analysis for the other options for existing facilities which were

evaluated in developing the proposed rule. For all options, facility counts and other results only include those

Phase III existing facilities that are (1) non-baseline closures and (2) subject to national categorical requirements

under the option. See Chapter B3: Economic Impact Analysis for Manufacturers and Chapter B5:Economic

Impact Analysis for Electric Generators for more information on baseline closures and counts of facilities subject

to national categorical requirements under each option. See the main body of this chapter for a description of data

sources and methodologies used in these analyses.

In Table D1A-1 below, the other evaluated options for existing facilities are presented in order of increasing

stringency and/or applicability (e.g., the largest number of facilities would be subject to the national requirements

under Option 6, compared to any of the other evaluated options). As discussed in the main chapter, the estimates

of the total number of regulated small entities and the percentage of all small entities subject to Phase III

regulation exclude consideration of entities in Other Industries within the Manufacturers segment (see section D1-

1.2). However, the estimated number of small entities incurring costs in the three cost-to-revenue ranges include

the known number of small entities owning known facilities in Other Industries.

Table D1A-1: Summary of Small Entity Impact Ratio Ranges for Existing Facilities by Sector

Industry Total Number of

Small Entities

Number of Small

Entities Owning

Facilities

Potentially

Subject to

Regulation

Percentage of

Small Entities

Subject to

Regulation

Compliance Cost/Annual

Revenues

0-1% 1-3% >3%

Option 3

Manufacturersa,b 5,113 3 0.1% 4 - -

Electric Generators 543 - 1,295 9 0.7% - 1.7% 6 3 -

Totalc 5,656 - 6,408 12 0.2% 10 3 -

Option 4

Manufacturersa,b 5,113 1 0.0% 1 - -

Electric Generators 543 - 1,295 2 0.2% - 0.4% - 1 1

Totalc 5,656 - 6,408 3 0.0%-0.1%111

Option 2

Manufacturersa,b 5,113 3 0.1% 4 - -

Electric Generators 543 - 1,295 9 0.7% - 1.7% 5 3 1

Totalc 5,656 - 6,408 12 0.2% 9 3 1

Option 1

Manufacturersa,b 5,113 3 0.1% 4 - -

Electric Generators 543 - 1,295 9 0.7% - 1.7% 4 4 1

Totalc 5,656 - 6,408 12 0.2% 8 4 1
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 1 to Chapter D1

Table D1A-1: Summary of Small Entity Impact Ratio Ranges for Existing Facilities by Sector

Industry Total Number of

Small Entities

Number of Small

Entities Owning

Facilities

Potentially

Subject to

Regulation

Percentage of

Small Entities

Subject to

Regulation

Compliance Cost/Annual

Revenues

0-1% 1-3% >3%

D1A1-2

Option 6

Manufacturersa,b 5,113 10 0.2% 12 1 -

Electric Generators 543 - 1,295 13 1.0% - 2.4% 7 5 1

Totalc 5,656 - 6,408 23 0.4% 19 6 1

a For Manufacturers, the more conservative cost analysis (Case 2 estimate) is presented, which is likely to overstate the compliance

costs that would be incurred by any single small entity but may understate the number of small entities incurring compliance costs. b For Manufacturers, the “Total Number of Small Entities” and the “Number of Small Entities Owning Facilities Potentially Subject

to Regulation” exclude entities in Other Industries; the numbers presented in the cost-to-revenue ranges include known entities in

Other Industries. c Individual numbers may not sum to reported totals due to independent rounding.

Source: U.S. EPA Analysis, 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

1

 Two different bridges are available from Census. One provides a bridge based on the processes/activities performed and the other

bridge is based on establishment classifications. This analysis uses the bridge based on establishment classifications (Census, 2000).

D1A2-1

CHAPTER CONTENTS

D1A2-1 Identifying NAICS Codes and

Thresholds . . . . . . . . . . . . . . . . . . . . . . D1A2-1

D1A2-2 Differences in NAICS-Based and

SIC-Based Size Thresholds . . . . . . . . . D1A2-7

D1A2-3 Results . . . . . . . . . . . . . . . . . . . . . . . . . D1A2-9

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . D1A2-10

Appendix 2 to Chapter D1:

Small Business Determinations Based on

NAICS Codes

INTRODUCTION

As discussed in Chapter D1, the SBA small business

size standards changed from a SIC code-based system

to a NAICS code-based system on October 1, 2000. 

Because EPA conducted its data collection effort for

existing facilities before this change, EPA performed

the small entity analysis for existing facilities based on

SIC codes. This appendix presents an analysis to

determine whether use of NAICS code-based size standards would affect the results of the small entity analysis.

D1A2-1 IDENTIFYING NAICS CODES AND THRESHOLDS

EPA started with the unique firm-level 4-digit SIC codes for firms that own existing facilities potentially subject

to Phase III regulation (see Tables D1-1 and D1-3). EPA used information from the Economic Census, 1997

Economic Census: Bridge Between NAICS and SIC, to determine 1997 NAICS Codes classifications for these

firms.1

 EPA also used an additional Economic Census publication/dataset, 1997 NAICS Matched to 2002 NAICS,

to bring the data forward to NAICS 2002 so that the most current small business thresholds could be used

(Census, 2003). Table D1A2-1 presents firm-level SIC codes, SIC code descriptions, SIC code-based small

business thresholds, as well as the corresponding NAICS codes, NAICS code descriptions, and NAICS codebased small business thresholds. For ease of reference, gray shading is used to highlight SIC codes with

corresponding NAICS code that have a different size standard.

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

0133 Sugarcane and Sugar

Beets $0.5 111991 Sugar Beet Farming $0.75

111930 Sugarcane Farming $0.75

1011 Iron Ores 500 212210 Iron Ore Mining 500

1311 Crude Petroleum and

Natural Gas. 500 211111 Crude Petroleum and Natural

Gas Extraction 500

1542

General Contractors –

Nonresidential

Buildings, Other than

Industrial Buildings and

Warehouses 

$27.5 236220 Commercial and Institutional

Building Construction $28.50

2011 Meat Packing Plants 500 311611 Animal (except Poultry) 500
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-2

Slaughtering

2046 Wet Corn Milling 750 311221 Wet Corn Milling 750

2061 Cane Sugar, Except

Refining 500 311311 Sugarcane Mills 500

2062 Cane Sugar Refining 750 311312 Cane Sugar Refining 750

2063 Beet Sugar 750 311313 Beet Sugar Manufacturing 750

2075 Soybean Oil Mills 500

311222 Soybean Processing 500

311225 Fats and Oils Refining and

Blending 1,000

2211 Broadwoven Fabric

Mills, Cotton 1,000 313210 Broadwoven Fabric Mills 1,000

2421 Sawmills and Planing

Mills, General 500

321113 Sawmills 500

321912 Cut Stock, Resawing Lumber,

and Planing 500

321918 Other Millwork(including

Flooring) 500

321999 All Other Miscellaneous

Wood Product Manufacturing 500

2611 Pulp Mills 750 322110 Pulp Mills 750

2621 Paper Mills 

750 322121 Paper (except

Newsprint)Mills 750

750 322122 Newsprint Mills 750

2631 Paperboard Mills 750 322130 Paperboard Mills 750

2653 Corrugated and Solid

Fiber Boxes 500 322211 Corrugated and Solid Fiber

Box Manufacturing 500

2673 Plastics, Foil, and

Coated Paper Bags 500

322223 Plastics, Foil, and Coated

Paper Bag Manufacturing 500

326111 Unsupported Plastics Bag

Manufacturing 500

2679

Converted Paper and

Paperboard Products,

N.E.C. 

500

322222 Coated and Laminated Paper

Manufacturing 500

322231

Die-Cut Paper and

Paperboard Office Supplies

Manufacturing

500

322299 All Other Converted Paper

Product Manufacturing 500

2711

Newspapers: Publishing,

or Publishing and

Printing

500 516110 Internet Publishing and

Broadcasting 500

2812 Alkalies and Chlorine 1,000 325181 Alkalis and Chlorine

Manufacturing 1,000

2813 Industrial Gases 1,000 325120 Industrial Gas Manufacturing 1,000
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-3

2819 Industrial Inorganic

Chemicals, N.E.C. 1,000

325131 Inorganic Dye and Pigment

Manufacturing 1,000

325188 All Other Basic Inorganic

Chemical Manufacturing 1,000

325998

All Other Miscellaneous

Chemical Product and

Preparation Manufacturing

500

331311 Alumina Refining 1,000

2821

Plastics Materials,

Synthetic Resins, and

Nonvulcanizable

Elastomers 

750 325211 Plastics Material and Resin

Manufacturing 750

2824

Manmade Organic

Fibers, Except

Cellulosic 

1,000 325222 Noncellulosic Organic Fiber

Manufacturing 1,000

2833 Medicinal Chemicals

and Botanical Products 750 325411 Medicinal and Botanical

Manufacturing 750

2834 Pharmaceutical

Preparations 750 325412 Pharmaceutical Preparation

Manufacturing 750

2851

Paints, Varnishes,

Lacquers, Enamels, and

Allied Products 

500 325510 Paint and Coating

Manufacturing 500

2869 Industrial Organic

Chemicals, N.E.C. 1,000

325110 Petrochemical Manufacturing 1,000

325120 Industrial Gas Manufacturing 1,000

325188 All Other Basic Inorganic

Chemical Manufacturing 1,000

325193 Ethyl Alcohol Manufacturing 1,000

325199 All Other Basic Organic

Chemical Manufacturing 1,000

2873 Nitrogenous Fertilizers 1,000 325311 Nitrogenous Fertilizer

Manufacturing 1,000

2874 Phosphatic Fertilizers 500 325312 Phosphatic Fertilizer

Manufacturing 500

2891 Adhesives and Sealants 500 325520 Adhesive Manufacturing 500

2899 Chemicals and Chemical

Preparations, N.E.C. 500

311942 Spice and Extract

Manufacturing 500

325199 All Other Basic Organic

Chemical Manufacturing 1,000

325510 Paint and Coating

Manufacturing 500

325998

All Other Miscellaneous

Chemical Product and

Preparation Manufacturing

500

2911 Petroleum Refining 1,500 324110 Petroleum Refineries 1,500a

3312

Steel Works, Blast

Furnaces (Including

Coke Ovens), and

Rolling Mills 

1,000

324199 All Other Petroleum and Coal

Products Manufacturing 500

331111 Iron and Steel Mills 1,000
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-4

3313 Electrometallurgical

Products, Except Steel 750

331112

Electrometallurgical

Ferroalloy Product

Manufacturing

750

331492

Secondary Smelting,

Refining, and Alloying of

Nonferrous Metal (except

Copper and Aluminum)

750

3315 Steel Wiredrawing and

Steel Nails and Spikes 1,000

331222 Steel Wire Drawing 1,000

332618 Other Fabricated Wire

Product Manufacturing 500

3316 Cold-Rolled Steel Sheet,

Strip, and Bars 1,000 331221 Cold-Rolled Steel Shape

Manufacturing 1,000

3317 Steel Pipe and Tubes 1,000 331210

Iron and Steel Pipe and Tube

Manufacturing from

Purchased Steel

1,000

3334 Primary Production of

Aluminum 1,000 331312 Primary Aluminum

Production 1,000

3339

Primary Smelting and

Refining of Nonferrous

metals, Except Copper

and Aluminum 

750 331419

Primary Smelting and

Refining of Nonferrous Metal

(except Copper and

Aluminum)

750

3353 Aluminum Sheet, Plate,

and Foil 750

331315 Aluminum Sheet, Plate and

Foil Manufacturing 750

332996 Fabricated Pipe and Pipe

Fitting Manufacturing 500

3421 Cutlery 500 332211 Cutlery and Flatware (except

Precious) Manufacturing 500

3714 Motor Vehicle Parts and

Accessories 750

336211 Motor Vehicle Body

Manufacturing 1,000

336312 Gasoline Engine and Engine

Parts Manufacturing 750

336322

Other Motor Vehicle

Electrical and Electronic

Equipment Manufacturing

750

336330

Motor Vehicle Steering and

Suspension Components

(except Spring)

Manufacturing

750

336340 Motor Vehicle Brake System

Manufacturing 750

336350

Motor Vehicle Transmission

and Power Train Parts

Manufacturing

750

336399 All Other Motor Vehicle

Parts Manufacturing 750
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-5

3728

Aircraft Parts and

Auxiliary Equipment,

N.E.C. 

1,000

332912 Fluid Power Valve and Hose

Fitting Manufacturing 500

333995 Fluid Power Cylinder and

Actuator Manufacturing 500

333996 Fluid Power Pump and Motor

Manufacturing 500

336413

Other Aircraft Part and

Auxiliary Equipment

Manufacturing

1,000b

3861 Photographic Equipment

and Supplies 500

325992

Photographic Film, Paper,

Plate and Chemical

Manufacturing

500

333315

Photographic and

Photocopying Equipment

Manufacturing

500

3999 Manufacturing

Industries, N.E.C. 500

314999 All Other Miscellaneous

Textile Product Mills 500

316110 Leather and Hide Tanning

and Finishing 500

321999 All Other Miscellaneous

Wood Product Manufacturing 500

322299 All Other Converted Paper

Product Manufacturing 500

323110 Commercial Lithographic

Printing 500

323111 Commercial Gravure Printing 500

323112 Commercial Flexographic

Printing 500

323113 Commercial Screen Printing 500

323119 Other Commercial Printing 500

325998

All Other Miscellaneous

Chemical Product and

Preparation Manufacturing

500

326199 All Other Plastics Product

Manufacturing 500

332212 Hand and Edge Tool

Manufacturing 500

332999

All Other Miscellaneous

Fabricated Metal Product

Manufacturing

500

335121 Residential Electric Lighting

Fixture Manufacturing 500

337127 Institutional Furniture

Manufacturing 500

339999 All Other Miscellaneous

Manufacturing 500
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-6

4911 Electric Services 4 million megawatt hrs.

221111 Hydroelectric Power

Generation1 4 million megawatt hrs.c

221112 Fossil Fuel Power

Generation1 4 million megawatt hrs.c

221113 Nuclear Electric Power

Generation1 4 million megawatt hrs.c

221119 Other Electric Power

Generation1 4 million megawatt hrs.c

221121 Electric Bulk Power

Transmission and Control 4 million megawatt hrs.c

221122 Electric Power Distribution 4 million megawatt hrs.c

4924 Natural Gas Distribution 500 221210 Natural Gas Distribution 500

4925

Mixed, Manufactured, or

Liquefied Petroleum Gas

Production and/or

Distribution 

$5 221210 Natural Gas Distribution 500

4932 Gas and Other Services

Combined $5 221210 Natural Gas Distribution 500

4953 Refuse Systems $10

562920 Materials Recovery Facilities $10.50

562211 Hazardous Waste Treatment

and Disposal $10.50

562212 Solid Waste Landfill $10.50

562213 Solid Waste Combustors and

Incinerators $10.50

562219 Other Nonhazardous Waste

Treatment and Disposal $10.50

5153 Grain and Field Beans 100

425120 Wholesale Trade Agents and

Brokers 100

424510 Grain and Field Bean

Merchant Wholesalers 100

425110 Business to Business

Electronic Markets 100

5171 Petroleum Bulk Stations

and Terminals 100

424710 Petroleum Bulk Stations and

Terminals 100

454311 Heating Oil Dealers $10.50

454312 Liquefied Petroleum Gas

(Bottled Gas) Dealers $6.00

6141 Personal Credit

Institutions $5

522120 Savings Institutions $150 million in assetsd

522210 Credit Card Issuing $150 million in assetsd

522220 Sales Financing $6.00

522291 Consumer Lending $6.00
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

Table D1A2-1: Small Business Thresholds Based on SIC Codes and NAICS Codes

SIC

Code SIC Code Description SIC Size Standards

(employees/ $millions)

NAICS

Code NAICS Code Description NAICS Size Standards

(employees/ $millions)

D1A2-7

6211

Security Brokers,

Dealers and Flotation

Companies

$5

523110 Investment Banking and

Securities Dealing $6.00

523120 Securities Brokerage $6.00

523910 Miscellaneous Intermediation $6.00

523999 Miscellaneous Financial

Investment Activities $6.00

6719 Offices of Holding

Companies, N.E.C. $5 551112 Offices of Other Holding

Companies $6.00

9111 Executive Offices 50,000 Population 921110 Executive Offices 50,000 Population

Notes (from source SBA publications):

a

 For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor

more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned

or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or a

throughput. The total product to be delivered under the contract must be at least 90 percent refined by the successful bidder from

either crude oil or bona fide feedstocks.

b

 Contracts for the rebuilding or overhaul of aircraft ground support equipment on a contract basis are classified under NAICS code

336413.

c

 A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of electric

energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours.

d

 A financial institution's assets are determined by averaging the assets reported on its four quarterly financial statements for the

preceding year. "Assets" for the purposes of this size standard means the assets defined according to the Federal Financial

Institutions Examination Council 034 call report form.

Source: U.S. SBA, 2000; U.S. SBA, 2002.

D1A2-2 DIFFERENCES IN NAICS-BASED AND SIC-BASED SIZE THRESHOLDS

As a second step, EPA identified all potential Phase III firms whose SIC code-based small business threshold

differs from the NAICS code-based one. There are two possible cases:

(1) the NAICS threshold is greater than the SIC threshold, which could lead to additional firms being

classified as small businesses, and

(2) the NAICS threshold is less than the SIC threshold, which could lead to fewer firms being classified

as small businesses.

For each such firm, EPA examined whether the firm’s initial business size classification, based on the SIC codebased criteria, would change under the NAICS code-based criteria.

Table D1A2-2 lists SIC codes for which the NAICS threshold exceeds the SIC threshold and therefore could

potentially lead to additional facilities being classified as small. The table shows that there are 13 potentially

affected firms, in 11 SIC codes, that fall into that category. Table D1A2-3 lists SIC codes for which the NAICS

threshold is less than the SIC threshold and therefore could potentially lead to fewer facilities being classified as

small. The table shows that there are 17 potentially affected firms, in six SIC codes, that fall into that category.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

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Table D1A2-2: NAICS Thresholds Exceed SIC Thresholds

Additional Firms May Be Classified as Small

SIC Code SIC Code Threshold NAICS Code(s) NAICS Code Threshold

Number of

Potentially Affected

Firms

0133 $0.5 million 111991; 111930 $0.75 million 1

1542 $27.5 million 236220 $28.5 million 1

2075 500 Employees 311225 1,000 Employees 1

2899 500 Employees 325199 1,000 Employees 1

3714 750 Employees 336211 1,000 Employees 1

4925 $5.0 million 221210 500 Employees 1

4932 $5.0 million 221210 500 Employees 2

4953 $10.0 million

562920; 562211;

562212; 562213;

562219

$10.5 million 2

6141 $5.0 million

522220; 522291 $6.0 million

1

522120; 522210 $150 million in assets

6211 $5.0 million 523110; 523120;

523910; 523999 $6.0 million 1

6719 $5.0 million 551112 $6.0 million 1

Total 13

Source: U.S. EPA Analysis, 2004.

Table D1A2-3: NAICS thresholds Are Less than SIC Thresholds 

Fewer Firms May Be Classified as Small

SIC Code SIC Code Threshold NAICS Code(s) NAICS Code Threshold

Number of

Potentially Affected

Firms

2819 1,000 Employees 325998 500 Employees 1

3312 1,000 Employees 324199 500 Employees 11

3315 1,000 Employees 332618 500 Employees 1

3353 750 Employees 332996 500 Employees 1

3728 1,000 Employees 332912; 333995;

333996 500 Employees 1

5171 100 Employees

454311 $10.5 million

2

454312 $6.0 million

Total 17

Source: U.S. EPA Analysis, 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

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D1A2-3 RESULTS

During the final step of this comparison, EPA analyzed firms for which the SIC code-based business size

threshold differs from the NAICS code-based threshold. For all but one firm, this analysis found that the SICbased and NAICS-based business size determinations were unambiguously the same: based on the firm’s

employment, revenue, or electric output, no previously determined small business is large, and no previously

determined large businesses is small, under the NAICS-based threshold. However, for one firm, in SIC Code

3312, EPA’s initial finding of potential change in business size classification was ambiguous because the SIC

Code in which the firm is classified, mapped to more than one NAICS code, and the NAICS code-based size

thresholds were not the same: for one of the corresponding NAICS codes (324199), the firm’s business size

determination would change while for the other NAICS code (331111), the determination would not change (see

also Table D1A2-1). For this firm, EPA used information from the Dun and Bradstreet business database to

identify the firm’s NAICS code as 331111, which has the same small business threshold of 1,000 employees as

SIC code 3312. Therefore, this analysis found no difference in small entity determinations, and therefore no

change in small entity impacts, as a result of using NAICS-based size standards instead of SIC-based size

standards, for the small business determination.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses Appendix 2 to Chapter D1

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REFERENCES

U.S. Census Bureau (Census). 2000. 1997 Economic Census: Bridge Between NAICS and SIC. June 2000.

Available at: http://www.census.gov/epcd/ec97brdg/ (Table 2).

U.S. Census Bureau (Census). 2003. 1997 NAICS Matched to 2002 NAICS. May 2003.

Available at: http://www.census.gov/epcd/naics02/NAICS97toNAICS02.xls.

U.S. Small Business Administration (U.S. SBA). 2000. Effective until September 30, 2000. Small Business Size

Standards. Available at: http://www.sba.gov/regulations/siccodes/.

U.S. Small Business Administration (U.S. SBA). 2002. Effective October 1, 2002. Small Business Size

Standards. Available at: http://www.sba.gov/size/indextableofsize.html.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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CHAPTER CONTENTS

D2-1 Analysis of Impacts on Government Entities . . D2-2

D2-1.1 Compliance Costs for Government-Owned

Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . D2-2

D2-1.2 Administrative Costs for Existing

Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . D2-3

D2-1.3 Administrative Costs for New Offshore 

Oil and Gas Extraction Facilities . . . . . . . D2-8

D2-1.4 Impacts on Small Governments . . . . . . . D2-11

D2-2 Compliance Costs for the Private Sector . . . . D2-11

D2-3 Summary of UMRA Analysis . . . . . . . . . . . . D2-12

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D2-14

Appendix to Chapter D2 . . . . . . . . . . . . . . . . . . . . . . D2A-1

Chapter D2: UMRA Analysis

INTRODUCTION

Title II of the Unfunded Mandates Reform Act of

1995, Pub. L. 104-4, establishes requirements for

Federal agencies to assess the effects of their

regulatory actions on State, local, and Tribal

governments and the private sector. Under UMRA

section 202, EPA generally must prepare a written

statement, including a cost-benefit analysis, for

proposed and final rules with “Federal mandates”

that might result in expenditures by State, local, and

Tribal governments, in the aggregate, or by the

private sector, of $100 million or more in any one

year.

Before promulgating a regulation for which a written statement is needed, UMRA section 205 generally requires

EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most

cost-effective, or least burdensome alternative that achieves the objectives of the rule. The provisions of section

205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an

alternative other than the least costly, most cost-effective, or least burdensome alternative if the Administrator

publishes with the rule an explanation why that alternative was not adopted. Before EPA establishes any

regulatory requirements that might significantly or uniquely affect small governments, including Tribal

governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan

must provide for notifying potentially affected small governments, enabling officials of affected small

governments to have meaningful and timely input in the development of EPA regulatory proposals with

significant intergovernmental mandates, and informing, educating, and advising small governments on

compliance with regulatory requirements.

EPA is proposing three options that define which existing facilities would be subject to the national categorical

requirements under the proposed rule: the “50 MGD for All Waterbodies” option (the “50 MGD All”option); the

“200 MGD for All Waterbodies” option (the “200 MGD All” option); and the “100 MGD for Certain

Waterbodies” option (the “100 MGD CWB” option). These options all require the same reduction in

impingement and entrainment (I&E), and differ only by applicability criteria defined on the basis of design intake

flow (DIF) and waterbody type. As a result, the number of facilities that would be required to meet the national

categorical requirements varies among the three options. EPA is also proposing section 316(b) requirements for

new offshore oil and gas extraction facilities (also abbreviated as “new OOGE facilities”) in Phase III. These

proposed requirements are based on a 2 MGD DIF applicability threshold and would apply to an estimated 124

new offshore oil and gas extraction facilities.

< 50 MGD for All Waterbodies option for existing facilities and proposed option for new offshore oil and

gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance for this option

to be $44.8 million (2003$). All of these direct facility costs are incurred by the private sector (including

136 manufacturing facilities and 124 new offshore oil and gas extraction facilities). No facility owned by

State and local governments would be subject to the national categorical requirements under this proposed

option. Additionally, State and local permitting authorities are estimated to incur $0.5 million annually to

administer this option, including labor costs to write permits and to conduct compliance monitoring and

enforcement activities. EPA estimates that the highest undiscounted after-tax cost incurred by the private

sector in any one year is approximately $280 million in 2011.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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< 200 MGD for All Waterbodies option for existing facilities and proposed option for new offshore oil

and gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance for this

option to be $21.4 million (2003$). All of these direct facility costs are incurred by the private sector

(including 25 manufacturing facilities and 124 new offshore oil and gas extraction facilities). No facility

owned by State and local governments would be subject to the national categorical requirements under

this proposed option. Additionally, State and local permitting authorities are estimated to incur $0.1

million annually to administer this option, including labor costs to write permits and to conduct

compliance monitoring and enforcement activities. EPA estimates that the highest undiscounted after-tax

cost incurred by the private sector in any one year is approximately $91 million in 2010.

< 100 MGD for Certain Waterbodies option for existing facilities and proposed option for new offshore

oil and gas extraction facilities: EPA estimates the total annualized after-tax costs of compliance for this

option to be $17.4 million (2003$). All of these direct facility costs are incurred by the private sector

(including 19 manufacturing facilities and 124 new offshore oil and gas extraction facilities). No facility

owned by State and local governments would be subject to the national categorical requirements under

this proposed option. Additionally, State and local permitting authorities are estimated to incur $0.2

million annually to administer this option, including labor costs to write permits and to conduct

compliance monitoring and enforcement activities. EPA estimates that the highest undiscounted after-tax

cost incurred by the private sector in any one year is approximately $236 million in 2011.

Given these findings, EPA has determined that this rule contains a Federal mandate that may result in

expenditures of $100 million or more in any one year, for State, local, and Tribal governments, in the aggregate,

or the private sector. Accordingly, under §202 of the UMRA, EPA has prepared a written statement, presented in

the preamble to the proposed rule, that includes (1) a cost-benefit analysis; (2) an analysis of macroeconomic

effects; (3) a summary of State, local, and Tribal input; (4) a discussion related to the least burdensome option

requirement; and (5) an analysis of small government burden. This chapter contains additional information to

support that statement, including information on compliance and administrative costs, and on impacts on small

governments. In addition, the appendix to this chapter presents summary results for five other options evaluated

for existing facilities (Option 1, Option 2, Option 3, Option 4, and Option 6).

D2-1 ANALYSIS OF IMPACTS ON GOVERNMENT ENTITIES

Governments may incur two types of costs as a result of this proposed rule:

< direct costs to comply with the rule for facilities owned by government entities, and

< administrative costs to implement the rule.

Both types of costs are discussed on the following pages.

D2-1.1 Compliance Costs for Government-Owned Facilities

The Electric Generating Industry is the only industry segment potentially subject to Phase III regulation with

government-owned facilities. No facilities in the Manufacturers or new offshore oil and gas extraction facility

segment are owned by a government. EPA has determined that no government-owned facility has a DIF that

exceeds 50 MGD (the minimum applicability threshold of the proposed options). Therefore, no governmentowned facility would incur compliance costs under any of the proposed options.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

1

 The costs associated with implementing Phase III requirements are documented in EPA’s Information Collection Request (U.S.

EPA, 2003).

D2-3

D2-1.2 Administrative Costs for Existing Facilities

The requirements of section 316(b) are implemented through the National Pollutant Discharge Elimination

System (NPDES) permit program. Forty-five States and one Territory currently have NPDES permitting

authority under section 402(c) of the Clean Water Act (CWA). EPA estimates that States and Territories would

incur three types of costs associated with implementing the requirements of the proposed rule: (1) start-up

activities, (2) permitting activities associated with the initial NPDES permit containing the new section 316(b)

requirements and subsequent permit renewals, and (3) annual activities.1

 EPA estimates that the total costs for

these activities under the three proposed options would be between $0.1 million and $0.5 million, annualized over

30 years at a 7% discount rate. Table D2-1 presents the estimated annualized costs of the three major

administrative activities for each of the proposed options.

Table D2-1: Annualized Government Administrative Costs (in millions, 2003$)

Activity 50 MGD All Option 200 MGD All Option 100 MGD CWB Option

Start-Up Activities $0.01 $0.01 $0.01

Permitting Activities $0.39 $0.08 $0.11

Annual Activities $0.15 $0.03 $0.03

Total $0.55 $0.12 $0.15

Source: U.S. EPA Analysis, 2004.

Based on the specific permitting requirements of each facility (see Chapter B1: Summary of Cost Categories and

Key Analysis Elements for Existing Facilities), EPA calculated total government costs of implementing the

proposed rule by adding the cost of start-up activities to the aggregate costs for each facility’s first postpromulgation permit, repermitting activities, and annual activities. The maximum one-year undiscounted

implementation cost incurred by governments under the three proposed options is approximately $2.0 million in

2011 (50 MGD All option). EPA notes that the annualized cost of administrative activities depends on when they

are incurred. If facilities reach compliance later than assumed in this analysis, permitting authorities’

administrative activities would also occur in later years. As a result, the annualized costs of the rule to permitting

authorities would be lower because administrative costs incurred in later years have lower present values.

a. Start-Up Activities

Forty-five States and one Territory with NPDES permitting authority are expected to undertake start-up activities

to prepare for administering the proposed rule. Start-up activities include reading and understanding the rule,

mobilization and planning of the resources required to address the rule’s requirements, and training technical staff

on how to review materials submitted by facilities and make determinations on the proposed Phase III

requirements for each facility’s NPDES permit. In addition, permitting authorities are expected to incur other

direct costs, e.g., for purchasing supplies and copying. Table D2-2 shows the total start-up costs EPA estimated

permitting authorities to incur. Each permitting authority is estimated to incur start-up costs of $4,000 as a result

of the proposed rule. EPA assumes that the initial start-up activities would be incurred by all permitting

authorities at the beginning of 2007, the year the Phase III requirements would take effect.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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 For an explanation of how the compliance years were assigned to facilities subject to Phase III regulation, see Chapter B1.

3

 EPA is not including this site-specific determination as a direct cost for complying facilities because this is an optional activity that

the facility would choose only in cases where the cost of the alternative technology plus the cost of the site-specific determination is less

than the cost of the technology otherwise required by the proposed rule. However, the site-specific determination costs for permitting

authorities are not optional, and thus are included in EPA’s estimates of total cost.

D2-4

Table D2-2: Government Costs of Start-Up Activities 

(per Permitting Authority; 2003$)

Start-Up Activity Start-Up Costs

Read and Understand Rule $977

Mobilization/Planning $1,698

Training $1,219

Other Direct Costs $50

Total $3,944

Source: U.S. EPA, 2004.

b. Initial Post-Promulgation Permitting and Repermitting Activities

The permitting authorities would be required to implement the proposed Phase III requirements by adding

compliance requirements to each facility’s NPDES permit. Permitting activities include incorporating section

316(b) requirements into the first post-promulgation permit and making modifications, if necessary, to each

subsequent permit. For this analysis, EPA assumed that each complying facility’s first permit containing the new

section 316(b) requirements would be issued between 2010 and 2014.2

 Repermitting activities would take place

every five years after initial permitting.

The proposed rule requires facilities to submit the same type of information for their initial post-promulgation

permit and for each permit renewal application. Therefore, the type of administrative activities required by the

initial post-promulgation and each subsequent permit are similar. EPA identified the following major activities

associated with State permitting activities: reviewing submitted documents and supporting materials, verifying

data sources, consulting with facilities and the interested public, determining specific permit requirements, and

issuing the permit. Table D2-3 presents the State permitting activities and associated costs, on a per permit basis. 

The permitting costs do not vary by type of facility to be permitted (however, the costs associated with permitting

facilities with (a) a recirculating system or a wedgewire screen in the baseline or (b) a facility installing a new

wedgewire screen are less). The burden of repermitting is expected to be smaller than the burden of initial

permitting because the permitting authority is already familiar with the facility’s case and the type of information

the facility would provide.

Two of the permitting activities presented within Table D2-3 pertain only to facilities opting for a site-specific

determination of best technology available (BTA). An authorized State is able to permit a facility to opt for a sitespecific determination if it can demonstrate that the proposed technology would result in environmental

performance within a watershed that is comparable to the reductions in impingement and entrainment mortality

that would otherwise be achieved under the proposed rule. EPA estimates that under the proposed rule, 50

facilities would apply for a site-specific determination.3
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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Table D2-3: Government Permitting Costs (per Permit; 2003$)

Activity First Post-Promulgation

Permit Repermitting

Review Source Water Physical Data $290 $113

Review CWIS Data $871 $259

Review CWS Operation Narrative $871 $259

Review Proposal for Collection of Information for Comprehensive

Demonstration Study $1,302 $407

Review Source Water Body Flow Information $290 $113

Review Design and Construction Technology Plan $1,443 $410

Review Impingement Mortality Monitoring Results $4,279 $1,284

Review Entrainment Characterization Monitoring Results $4,279 $1,284

Review Baseline Characterization Monitoring Results and Study Findings $12,678 $3,819

Review Pilot Study for New Impingement & Entrainment Technology $1,302 $407

Review Restoration Measuresa $2,299 $690

Review Technology Installation and Operation Plan & Verification

Monitoring Plan $1,047 $311

Determine Monitoring Frequency $290 $113

Determine Record Keeping and Reporting Frequency $290 $113

Considering Public Comments $1,302 $407

Issuing Permit $265 $64

Permit Record Keeping $130 $24

Other Direct Costs $310 $310

Total Cost (without site specific determination)b $33,541 $10,387

Review Information to Support Site-Specific Determination of BTA $45,980 $13,794

Establish Requirements for Site-Specific Technology $1,162 $322

Site-Specific Costsc $47,142 $14,116

Total Cost (with site specific determination)b $80,683 $24,503

a

 Assumed to apply to only 10% of facilities. Only 10% of the per permit costs of $22,990 and $6,897 is accounted for in this

framework. b

 Individual numbers may not add up to total due to independent rounding. c

 Cost incurred only for permits of facilities conducting site-specific demonstrations.

Source: U.S. EPA, 2004.

As shown in Table D2-3, initial post-promulgation permits that do not require a site-specific determination of

BTA are expected to impose an average per permit cost of $34,000 on the issuing permitting authority. For initial

post-promulgation permits that include a site-specific determination, the State administrative costs associated with

the site-specific determination are estimated to increase by $47,000, resulting in total per permit costs of

approximately $81,000.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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The State administrative cost for a permit renewal that does not include a site-specific determination is $10,000. 

For facilities that conduct a site-specific determination, the cost per permit imposed on the permitting authority

increases by $14,000, resulting in an average repermitting cost of almost $25,000.

Permitting authorities also incur costs associated with review of verification studies conducted at facilities. In

addition to reviewing the studies, permitting authorities must modify permits in case of unfavorable study results. 

In total, verification study review is expected to cost permitting authorities $800 per permit. Table D2-4 lists the

components of verification study review.

Table D2-4: Government Costs of Verification Study Review

(per Permit; 2003$)

Activity Post-Promulgation Permit Costs

Review of Verification Studies $227

Permit Modification Due to Unfavorable Results $517

Recordkeeping $24

Other Direct Costs $10

Total $778

Source: U.S. EPA, 2004.

Finally, State governments may incur costs associated with alternative regulatory requirements. States may adopt

in their NPDES programs, alternative regulatory requirements to reduce impingement mortality and entrainment

within a watershed. If these States demonstrate to the Administrator that the reductions are comparable to what

would otherwise be achieved under rule, the Administrator would approve these alternative regulatory

requirements. For the final Phase II rule, EPA estimated that 10 regulatory permitting authorities would incur

costs associated with alternative regulatory requirements. For this analysis, EPA assumed that those States

interested in adopting alternative regulatory requirements would have done so under the Phase II rule. As a result,

EPA assumes that these States would incur no additional costs for establishing alternative regulatory requirements

under this proposed rule. Table D2-5 reports the cost of each component of establishing alternative regulatory

requirements.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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Table D2-5: Government Costs of Alternative Regulatory Requirements

(per Permitting Authority; 2003$)

Activity Post-Promulgation Permit Costs

Document Alternative Regulatory Requirements $1,360

Document Environmental Conditions within Watershed $1,813

Include Supporting Historical Studies, Calculations, and Analyses $3,542

Submit Documentation $97

Recordkeeping $138

Other Direct Costs $100

Totala $7,049

a

 Individual numbers may not add up to total due to independent rounding.

Source: U.S. EPA, 2004.

c. Annual activities

In addition to the start-up and permitting activities discussed above, permitting authorities would have to perform

certain annual activities to ensure the continued implementation of the requirements of the proposed rule. These

annual activities include reviewing biannual status reports, tracking compliance, making determinations on

monitoring frequency reduction, and record keeping.

Table D2-6 outlines the annual activities necessary for each permit, along with their estimated costs. These costs

begin with the issuance of the first permit following promulgation of the rule. A total cost of approximately

$1,500 is estimated for each permit per year.

Table D2-6: Government Costs for Annual Activities

(per Permit; 2003$)

Annual Activity Annual Costs

Review of Biannual Status Reporta $340

Compliance Tracking $581

Determination of Monitoring Frequency Reduction $453

Record Keeping $138

Other Direct Costs $30

Totalb $1,541

a

 This is a cost that is incurred once every two years. Therefore, only half of the total review cost of $680

is accounted for in this annual framework. b Individual numbers may not sum to total due to independent rounding.

Source: U.S. EPA, 2004.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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The Federal government is likely to incur costs for reviewing and validating proper implementation of the section

316(b) elements of States’ NPDES permits that are issued after promulgation of the rule. Table D2-7 outlines the

annual activities associated with reviewing a permit issued after promulgation of the rule, along with the

estimated cost of each activity. EPA estimates a cost of approximately $2,300 per permit for post-promulgation

review. Costs incurred by the Federal government are not part of the UMRA analysis but are part of the social

cost analysis presented in Chapter E1 of this EA.

Table D2-7: Federal Government Permit Program Oversight Activities (per Permit; 2003$)

Annual Activity Post-Promulgation Permit Costs

Review Source Water Physical Data $145

Review CWIS Data $113

Review CWS Operation Narrative $113

Review Proposal for Collection of Information for Comprehensive Demonstration Study $113

Review Source Water Body Flow Information $113

Review Design and Construction Technology Plan $145

Review Impingement Mortality Study and/or Entrainment Characterization Study $340

Review Pilot Study for New Impingement & Entrainment Technology $113

Review Restoration Measuresa $34

Review Technology Installation and Operation Plan & Verification Monitoring Plan $145

Review the Monitoring Frequency $113

Permit Record Keeping $130

Other Direct Costs $50

Total Cost (without site specific determination)b $1,699

Review Information to Support Site-Specific Determination of BTA $680

Review the Established Requirements for Site-Specific Technology $145

Site-Specific Costsc $825

Total Cost (with site specific determination)b $2,494

a Assumed to apply to only 10% of facilities. Only 10% of the per permit cost of $340 is accounted for in this framework. b Applies only to certain facilities, according to site specific determination of BTA Compliance Schedule. c Individual numbers may not add up to total due to independent rounding.

Source: U.S. EPA, 2004.

D2-1.3 Administrative Costs for New Offshore Oil and Gas Extraction Facilities

For new facilities in the offshore oil and gas extraction industry, NPDES permitting is consolidated under General

Permits, which are administered by EPA Regional offices. No States are involved in these permitting activities. 

Thus, unlike for existing facilities, States would incur no costs for new facility permitting. Three EPA Regions

(Region 6, Region 4, and Region 10) are expected to be the only entities responsible for permitting. Because

States are not involved in the section 316(b) permitting for new offshore oil and gas extraction facilities, the

Federal government would incur no costs for State oversight, which again differs from the existing facilities case. 

The affected EPA Regions would incur three types of costs for implementing the proposed rule: (1) start-up
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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activities, (2) activities associated with the initial General Permit containing the new section 316(b) requirements

and subsequent permit renewals, and (3) annual activities. These activities and their timing assumptions are

discussed below. The timing of these costs and how they are discounted and annualized are documented in the

Oil and Gas 316(b) Compliance Cost Model (see DCN 7-4018). For more information on the methods used for

discounting and cost annualization, see Chapter C1: Summary of Cost Categories and Key Analysis Elements for

New Offshore Oil and Gas Extraction Facilities.

It should be noted that costs incurred by the Federal government are not part of the UMRA analysis, but are part

of the social cost analysis presented in Chapter E1: Summary of Social Costs and Chapter C3: Economic Impact

Analysis for the Offshore Oil and Gas Extraction Industry of this EA.

a. Start-Up Activities

Start-up activities are not considered incremental to existing Regional permitting activities (U.S. EPA, 2004).

b. Initial Post-Promulgation Permitting and Repermitting Activities

Initial permitting and repermitting activities relate to the review of data collected for the regional studies and the

individual data submitted by facilities that plan to be permitted (or re-permitted) under the General Permits in the

three EPA Regions. Tables D2-8 and D2-9 present the individual activities and their costs for Regions 4, 6, and

10. These costs are on a per facility basis, i.e., the regions incur these costs for each facility that is permitted

under their general permits (see DCN 7-4018, which illustrates how these costs are aggregated and assigned to the

regions).

Table D2-8 presents the permit issuance activities and their related costs. The per facility initial permitting cost of

approximately $12,000 would be incurred in 2012 for facilities brought on-line or launched between 2007 and

2012 (Region 6) and in 2014 for facilities brought on-line or launched between 2007 and 2014 (Region 4 and 10). 

In later years, these costs are assumed to be incurred in the year of compliance of each new facility. The burden

of repermitting is expected to be smaller than the burden of initial permitting, approximately $3,200 per facility,

because the permitting authority is already familiar with the facility’s case and the type of information the facility

would provide. Repermitting costs are incurred in 5-year intervals after the initial post-promulgation permit.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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Table D2-8: Federal Government Costs for Permit Issuance Activities

(Per Facility Permitted under General Permits; 2003$)

Activity First PostPromulgation Permit Repermitting

Review Source Water Physical Data $290 $113

Review CWIS Data $871 $259

Review Source Water Body Flow Information $290 $113

Review CWIS Velocity Information $1,302 $407

Review Design and Construction Technology Plan $1,443 $410

Review Regional Monitoring Study Design and Sampling Plans $1,443 n/a

Review Regional Monitoring Study $2,778 n/a

Review Source Water Baseline Biological Characterization Study $1,302 $849

Determine Monitoring Frequency $290 $113

Determine Record Keeping and Reporting Frequency $290 $113

Consider Public Comments $1,302 $407

Issue Permit $265 $64

Permit Record Keeping $130 $24

ODCs Lump Sum $310 $310

Totala $12,309 $3,183

a Individual numbers may not add up to total due to independent rounding.

Source: U.S. EPA, 2004.

c. Annual activities

Annual costs are associated with the activities that must be undertaken by the regions each year for each active

facility operating under the applicable General Permit. These activities also include a one-time cost for

determining monitoring frequency reduction. This cost is assigned only to facilities operating at the time the

decision about monitoring frequency reduction is made (assumed to occur at the end of the initial two years of

monitoring, which is 2013 for the Region 6 permit and 2015 for the Region 4 and Region 10 permits). Table D2-

9 outlines these activities and their associated costs.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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Table D2-9: Federal Government Costs for Annual Activities

(Per Facility Permitted under General Permits; 2003$)

Activity Annual Costs

Review of Yearly Status Report $680

Compliance Tracking $581

Determination on Monitoring Frequency Reductiona $0

Record Keeping $138

ODCs Lump Sum $30

Totalb $1,428

a One-time cost of $453 incurred only by those facilities operating in 2013 (Region 6) or

2014 (Regions 4 and 10). b Individual numbers may not sum to total due to independent rounding.

Source: U.S. EPA, 2004.

D2-1.4 Impacts on Small Governments

EPA’s analysis also considered whether the proposed rule may significantly or uniquely affect small governments

(i.e., governments with a population of less than 50,000). As described earlier, the Electric Generating Industry is

the only industry segment with government-owned facilities; governments own no facilities in either the

Manufacturers or new offshore oil and gas extraction facility segments. No government-owned facility exceeds

the 50 MGD DIF applicability threshold (the smallest DIF applicability threshold of the three proposed options). 

Therefore, no government-owned facility would incur compliance costs under any of the three proposed options. 

As no facilities owned by small governments are subject to national requirements under the proposed options,

EPA has determined that the three proposed options would contain no regulatory requirements that might

significantly or uniquely affect small governments.

D2-2 COMPLIANCE COSTS FOR THE PRIVATE SECTOR

The only compliance costs incurred by the private sector result from facilities complying with the proposed

options. These options all require the same reduction in impingement and entrainment (I&E), and differ only by

applicability threshold, which is based on the facilities’ design intake flow and waterbody type. These direct

facility costs already include the cost to facilities of obtaining their NPDES permits. The methodology for

determining compliance costs for Phase III existing facilities is presented in Chapter B1: Summary of Cost

Categories and Key Analysis Elements for Existing Facilities of this EA; the methodology for Phase III new

offshore oil and gas extraction facilities is presented in Chapter C1: Summary of Cost Categories and Key

Analysis Elements for New Offshore Oil and Gas Extraction Facilities. EPA identified all facilities subject to

national categorical requirements under the three proposed options to be owned by a private entity.

Private sector costs for the proposed option for Phase III new facilities and for the three proposed options for

Phase III existing facilities are as follows (discounted at a 7% rate):

< Under the 50 MGD for All Waterbodies option for existing facilities and the proposed option for new

offshore oil and gas extraction facilities, 260 facilities are estimated to incur annualized compliance

costs of $44.8 million and a maximum one year cost of $280.3 million in 2011.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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< Under the 200 MGD for All Waterbodies option for existing facilities and the proposed option for new

offshore oil and gas extraction facilities, 149 privately-owned facilities are estimated to incur annualized

compliance costs of $21.4 million and a maximum one year cost, in 2010, of $90.8 million.

< Under the 100 MGD for Certain Waterbodies option for existing facilities and the proposed option for

new offshore oil and gas extraction facilities, 143 privately-owned facilities are estimated to incur

annualized compliance costs of $17.4 million and a maximum one year cost, in 2011, of $235.6 million.

D2-3 SUMMARY OF UMRA ANALYSIS

EPA estimates that the proposed rule would result in expenditures of $100 million or greater for State and local

governments, in the aggregate, or for the private sector in any one year. Table D2-10 summarizes the after-tax

compliance costs for facilities, and the costs to implement the rule for permitting authorities, under the proposed

options.

Table D2-10: Summary of UMRA Costs (in millions, 2003$)

Sector

Total Annualized Cost Maximum One-Year Cost

Facility

Compliance

Costs

Government

Implementation

Costs

Total

Facility

Compliance

Costs

Government

Implementation

Costs

Total

50 MGD for All Waterbodies Option for Existing Facilities / Proposed Option for New OOGE Facilities

Government Sector 

(excl. Federal) $0.0 $0.5 $0.5 $0.0 $2.0 $2.0

Private Sector $44.8 n/a $44.8 $280.3 n/a $280.3

200 MGD for All Waterbodies Option for Existing Facilities / Proposed Option for New OOGE Facilities

Government Sector 

(excl. Federal) $0.0 $0.1 $0.1 $0.0 $0.4 $0.4

Private Sector $21.4 n/a $21.4 $90.8 n/a $90.8

100 MGD for Certain Waterbodies Option for Existing Facilities / Proposed Option for New OOGE Facilities

Government Sector 

(excl. Federal) $0.0 $0.2 $0.2 $0.0 $0.8 $0.8

Private Sector $17.4 n/a $17.4 $235.6 n/a $235.6

Source: U.S. EPA Analysis, 2004.

Costs for new offshore oil and gas extraction facilities and the three proposed options for Phase III existing

facilities are as follows:

< The 50 MGD for All Waterbodies option for existing facilities and the proposed option for new offshore

oil and gas extraction facilities would impose annual costs of $0.5 million on State and local

governments (in implementation costs only), and $44.8 million on the private sector. Maximum one year

costs under this option are estimated to be approximately $2.0 million for government entities, and $280.3

million for the private sector. Both of these maximum annual cost values are estimated to occur in 2011.

< The 200 MGD for All Waterbodies option for existing facilities and the proposed option for new

offshore oil and gas extraction facilities would impose annual costs of $0.1 million on State and local
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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governments (in implementation costs only), and $21.4 million on the private sector. Maximum one year

costs under this option are approximately $0.4 million for government entities in 2011, and $90.8 million

for the private sector in 2010.

< The 100 MGD for Certain Waterbodies option for existing facilities and the proposed option for new

offshore oil and gas extraction facilities would impose annual costs of $0.2 million on State and local

governments (in implementation costs only), and $17.4 million on the private sector. Maximum one year

costs under this option are approximately $0.8 million for government entities and $235.6 million for the

private sector, both of which are estimated to occur in 2011.
§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D2: UMRA Analysis

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REFERENCES

U.S. Environmental Protection Agency (U.S. EPA). 2004. Information Collection Request (ICR) for Cooling

Water Intake Structures Phase III Proposed Rule. ICR Number 2169.01. October 2004.