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

C1-1 

### C HAPTER 

### C ONTENTS 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

I NTRODUCTION 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 C OST 

### C ATEGORIES 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 Manufact uring 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 specificati on and installed before the facility begins operations. Second, even the maintenance of CWISs should not resu lt 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, ma king incremental downtime due to CWIS maintenance unlikely (see the Technical Development Document for th e 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 cat egory 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 o il 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 technol ogy 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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-2 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 Sta inless steel and CuNi velocity caps Jackup Simple Pipe or Caisson Cylindri cal wedge wire screen over tower inlet Jackup Simple Pipe or Cai sson Horizontal Flow Modifier Jackup a Sea Chest Flat panel wedge wire screen over sea chest opening Jackup a Sea Chest Horizontal Flow Diverter for Side Sea Chests Jackup Submersible Pumps Cylindrical wedge wire screen over suction pipe inletSubmersibles, SemiSubmersibles and Drill Ships a Sea Chests Flat panel wedge wire screen over sea chest
Submersibles, Semisubmersibles and Drill Ships a Sea Chests Horizontal flow diverter over side sea chest Drill Barges Simple Pipes Cylindrical we dge 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 ches ts 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 technologi es 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 a nd gas facilities analyzed in this report.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-3 C1-1.2 Administrative Costs for Complying Facilities Compliance with the standards of the proposed rule requi res new offshore oil and gas extraction facilities to carry out certain administrative functions. For Phase III exis ting 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 appli es to the relatively active Western Gulf of Mexico (GOM) region; the Region 4 General Permit applies to th e 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, expi red in 2003, and is planned for renewal in 2004. Study of produced water will reopen in 2007. The likely begi nning rounds of the post-promulgation schedule of this permit is thus 2007 and 2012. The Regi on 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 e ffective 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 GP s renewals are finalized (2012 or 2014), or the year prior to when the facility is assumed to come on line or be la unched, 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. Th e 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 w ould 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 biol ogical characterization studies that would be required by section 316(b) under the Region 6 GP. They are also assume d 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, perm itting costs would be similar to Region 6 permitting costs. Since it is not known which MODUs may operate in the Eastern GOM , all MODUs constructe d in 2007 and beyond are§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-4 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 pe rmit 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 perform ed in the three years prior to start-up (2011-2013). The administrative functions associated with incorporati ng 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 info rmation for subsequent Ge neral Permit renewals; and monitoring, record keeping, and reporting). More de tailed 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 ope rate 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 y ears 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 th e cost of these activities individually. Some of the permitting activities, however, may not be incremental to existing requirements. Mine rals 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. Activ ities and costs associated with the initial permit renewal application include:

< Start-up activities: reading and understanding the rule; mobilizi ng 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 dist ribution and water balance diagram, and drawings and maps to support CWIS d escriptions, and maintaining copies of these records. These activities are assumed facility-specific, but sever al of the activities duplicate activities required by MMS. There are no incremental cost s 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 requireme nts. 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 activ ities are only those associated with compiling sitespecific information. Other waterbody characterizati on 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 fac ility-specific. Development of the narrative description of technologies is considered an MMS re quirement, so no costs are assumed incurred for this activity.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-5 < 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 peri od of peak meroplankton a bundance 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 fac ilities, 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 m eet entrainment requirements, eliminating any costs associated with entrainment studies).

Table C1-2: Cost of Initial Post-Promulgatio n NPDES General Permit Application Activities (Per Facility, 2003$) Activity Region 6 Region 4 Region 10 Start-up activities a $2,171 $2,171 $2,171 Permit application activities b $925 $925 $925 Source waterbody flow information a $1,416 $1,416 $1,416 CWIS velocity flow information f $0 $0 $0 Design and construction technology plan b $1,282 $1,141 $1,282 Biological characterization study c,e $63,942 $39,871 $296,564 Total Initial Post-Promulgation NPDES General Permit Application Cost d $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 facilitie s built in 2007 to 2012 for both Eastern and Western Gulf. Fo r Alaska, they occur in 2013.

c The costs for these activities are incurred during 2007-2009 in the East ern 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 e xpects that both the facility and the contractor can use some of the information from the initial studies. Buildi ng 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 NP DES General Permit renewal ac tivities subsequent to the first round. Since these numbers change slightly as faciliti es come on or off line, the costs shown are for the first repermitting cycle following the initial GP renewal.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-6 Table C1-3: Cost of Subsequent NPDES General Permit Application Activities (Per Facility, 2003$) Activity Region 6 Region 4 Region 10 Start-up activities a $692 $692 $692 Permit application activities a $190 $190 $190 Source waterbody flow information a $401 $401 $401 CWIS velocity flow information a $0 $0 $0 Design and construction technology plan a $802 $694 $802 Biologic characterization study a $12,005 $7,455 $194,932 Total Recurring NPDES Permit Application Cost d $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 firs t 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 ass umed 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 monitoring a $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 tw o years of the initial General Permit renewal (i.e., 2012 or 201 4) and are shared. These costs are incurred for one year in each subse quent permit renewal cycle. Shared costs shown are for the fir st 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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

1 The costs associated with implementing the requirements fo r new offshore oil and gas extraction facilities are documented in EPA’s Information Collection Request (U.S. EPA, 2004a).

C1-7 d. Administrative Costs for Permitting Authorities In addition, permitting authorities have to review the in formation provided by new offshore oil and gas extraction facilities and have to issue new general permits that refl ect 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 th rough the National Pollutant Discharge Elimination System (NPDES) permit program. In the case of the o il 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 co sts associated with implementing the requirements of the proposed rule on a per-facility basis, i.e., for each fac ility permitted under a GP: (1) start-up activities (considered not incremental to existing activities; $0 cost) , (2) activ ities associated with the initial General Permit containing the new section 316(b) requirements ($12,309 in each regi on) and subsequent perm it 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 K EY 

### E LEMENTS OF THE 

### E CONOMIC 

### A NALYSIS 

### F OR 

### N EW 

### O FFSHORE 

### O IL AND 

### G AS 

### E XTRACTION 

### F ACILITIES The economic analysis of regulation of new offshore o il 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 ru le on complying parties within the segments – several elements of the analysis have features common to all ne w 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 launc hed or comes on line) for each of the types of facilities considered in the economic analysis. Unlike the analys is 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 ar e operating in new MODUs and platforms starting in 2007,§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-8 even though the first General Permit is assumed to be re issued with 316(b) requirements in 2012. Developing an explicit profile of compliance years for new offshore o il and gas extraction facilities is important because the schedule of compliance years determines the timing of ou tlays by facilities and society in complying with the regulation, both for the initial outlays and for the ongoing pr ofile of outlays in maintaining compliance with the regulation. This information is important in prope rly 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/stru ctures 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 st udies, and thus, for the shared costs, would share repermitting costs with each other as well as with opera tions 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 Offsho re 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 financ ial 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 c onsistent 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 do llars of the year 2003 (avera ge or mid-year, depending on availability) using an appropriate inflation adjustment index. For adjusting compliance costs, EPA used the Construction Cost Index (CCI) publishe d by the Engineering News-Record.
a. CCI EPA used the CCI to adjust complia nce cost estimates from July 2002 to mid-year 2003. EPA judges the CCI as generally reflective of the cost of installing and ope rating process and treatment equipment such as would be required for compliance with Phase III regulation. Tabl e 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 implic it 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).§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-9 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 conve rsion of future costs (and benefits) to their present values, accounting for the fact that society tends to value future costs or be nefits 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 specifi ed 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 co sts 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 re issued 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 th e social cost analysis fo r 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, wh ich 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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

2 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 f acility-specific, are assumed to recur at years 5, 10, 15, 20, and 25 of the General Permit cycles. Fo r 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 30 th 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 assu med to occur in parallel with the annual permit-related activities by complying fac ilities and thus occurs in each year of a facility’s compliance period. EPA assigned costs by facility and governmental unit accord ing 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 co sts for the facility impact an alysis 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 disc ount rate, 3% and 7%. These discount rate values reflect guidance from the Office of Management and Budget re gulatory 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 va lue of the time stream of costs as of the beginning of 2007: 3

where: Cost t = 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 presen ted below, again using the two values of the social discount rate, 3% and 7%. Although the analysis pe riod extends from 2007 through 2055, a period of 49 years,§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-11 inclusive, EPA annualized costs over 30 years, since 30 years is the assumed period of compliance. This same annualization concept and period of a nnualization were also followed in th e 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 a llows comparison of constant annual equivalent values of costs and benefits that have been calculated on a mathema tically 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 proce dures in the discounting and annualization required for the analysis of costs to, and impacts on, complying faciliti es as those followed for the an alysis of social costs. However, the analysis of costs to complying facilities di ffers 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 e ffects (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 analyz ing and reporting the impact of compliance costs on private facilities, annualized costs are therefore calcula ted 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 likel y 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 annualiza tion 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 co sts 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 cal culation 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 th e 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 incorporat e 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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-12 < Use of discount rates in present va lue 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 complyi ng facility costs represents a cost of capital to the individual complying facility, which may reasonably di ffer 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 indi fference rate – i.e., the required rate of change over time in a value of consumption or outlay at whic h 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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-13 

### R EFERENCES Engineering News-Record (ENR). 2004. C onstruction Cost Index. Available at: http://enr.construction.com/features/c onEco/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 Anal ysis for Phase III New OOGE Facilities C1: Summary of Costs

C1-14 

### T HIS 

### P AGE 

### I NTENTIONALLY 

### L EFT 

### B LANK§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-1 

### C HAPTER 

### C ONTENTS 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 in cluding existing oil and gas facilities in this proposal. Two key industry sectors are primarily associated with o ffshore 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 natura l 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 i ndustry, 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 pr oduction platforms (Sections C2-1 and C2-2). Within each profile, a brief overview of the industry is provi ded, including a look at existing facilities and their associated firms, and the financial conditions of those fi rms (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 year s 2007 to 2026). As discussed in Section C1, EPA decided to apply a similar regulatory structure to new offshore o il and gas extraction facilities as had been applied to new facilities for the 316(b) Phase I regulation: impingement a nd 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 Analys is 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 M OBILE 

### O FFSHORE 

### D RILLING 

### U NITS 

### (MODU S 

### )
C2-1.1 Overview Offshore drilling operations often use MODUs, which are vessel s or other sea-going rigs that are used to transport drilling equipment to the offshore site and from whic h 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 s ubmersibles 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 delinea tion drilling in the offshore development of oil and gas resources. MODUs also provide developmental drilling ser vices. In exploratory drilling, drilling is undertaken to determine whether oil and gas resources are available n ear 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 fiel d, 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 towe d to the drill site and sunk to the bottom. These rigs may be either posted barge or bottle type. A posted barge rig consis ts 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 mo re 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 c ontinue 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 occu rs 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 Analys is 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 su sceptible 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 bo ttle-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 th e 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 ty pes that typically intake over 2 MGD of cooling water, with drill ships having the highest intake rates. Am ong 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 dr ill barges generally have coo ling 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. GlobalS antaFe, Transocean, Rowan Comp anies, 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 cont ractors 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 Analys is 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 compan ies associated with the parent compan ies listed in Table C2-1. The total number of potentially affected parent firms is 21. Th ese affiliations were determined primarily on the basis of Security and Exchange Commission (SEC) data. SEC ma intains 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 ch aracterizing financial conditions at a firm. Subsidiary lists are used to confirm ownership re lationships. The 8-K forms, in which significant changes to the firm must be announced, are often the source of in formation on mergers and acquisitions.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is 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 Analys is 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 de termining 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 organiza tion if it was majority owned by the larger entity. This approach is consistent with SBA’s de finition of affiliation. Small firms th at are affiliated (e.g., 51% owned) by firms defined as large by SBA’s standards (13CFR Pa rt 121) are not considered small for the purposes of regulatory flexibility analysis (see Section D1 for more deta ils). 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 fi rms 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 thei r 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 th e proper NAICS identified based on the reported SIC code in the 10K reports and the NAICS crosswalk informati on, 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 forei gn 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 Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-7 Table C2-3 presents the number of MODU parent compani es 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 availabl e to support defining them as large. Eight firms are foreign-owned and presumed large. Industrial classification data are unavaila ble for foreign firms. Only two firms are positively identified as small, out of the 21 total firms operati ng existing MODUs, but four companies believed to be domestic could not be identified as small or large, so ar e 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 Classificati on of MODU Parent Companies

SIC code NAICS code NAICS Descript ion SBA Definition of Small Total Number of Firms a 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 a nd 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 pa rent 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 fina ncial 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 equ ity, and total revenues respectively, and are commonly used measures of financial health in the oil and gas i ndustry. 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 C2: Profile of OOGE IndustryC2-8Table C2-4: Financial Condition of MODU Parent Companies (2002)Firms Size TypeNo. ofEmployeesAssets($000)Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginAtwood Oceanics Large Other 800 $445,238 $276,133 $149,157 $28,285 6.35% 10.24% 18.96%Blake Drilling & Workover Small* OtherBlue Dolphin Small Other 11 $7,775 $5,765 $2,910BSI Drilling Small* OtherCaspian Drilling Company Large** ForeignDiamond Offshore Large Independent 3,766$3,258,765 $1,335 $752,561 $62,520 1.92% 4683.15% 8.31%Energy EquipmentResourcesSmall* OtherENSCO International, Inc Large Other 4,300 $3,061,500 $1,967,000 $698,100 $59,300 1.94% 3.01% 8.49%GlobalSantaFe Large Foreign 8,800 $5,808,200 $4,234,200 $2,017,700 $277,900 4.78% 6.56% 13.77%Nabors Industries Large Foreign 15,261Newfield ExplorationCompanySmall Independent 488 $2,315,753 $1,009,231 $661,750 $73,847 3.19% 7.32% 11.16%Noble Corp. Large Independent 3,747 $3,065,714 $1,989,210 $986,356 $209,503 6.83% 10.53% 21.24%NR Marine Small* OtherOcean Rig Asa Large** ForeignParker Drilling Large Other 2,898 $953,325$300,626 $389,946 ($114,054) -11.96% -37.94% -29.25%Pride International Large Other 10,100 $4,324,995 $1,699,705 $1,269,774 ($8,947)-0.21% -0.53% -0.70%Rowan Companies Inc Large Other 5,237$2,054,504 $1,131,777 $617,258$86,278 4.20% 7.62% 13.98%Cyprus Company Large** ForeignTetra Technologies Large Other 1,391$308,817 $184,152 $242,606 $8,899 2.88% 4.83% 3.67%Transocean Inc. Large Foreign 13,200 $12,665,000 $7,141,000 $2,674,000 ($3,732,000)-29.47% -52.26% -139.57%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 Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

2 For simplicity, the text refers to operati ons that meet either of th ese criteria as not meeting pr oposed rule criteria, even though the proposed rule does not apply to existing facilities..

C2-9 C2-1.3 Existing MODUs with Intake Ra tes 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 applicab ility standard (at least 2 MGD design intake flow) and other criteria of the proposed rule. EPA used a multi-st ep 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 th at 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 surv ey 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 inta ke 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 ope rating 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 info rmation 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. Therefor e, 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 mark et, in particular, has shown pricing improvement in the GOM. The Bureau of Land Management’s Minerals Ma nagement Service (MMS) projects that oil production in the Gulf of Mexico should be between 1.5 and 2.0 m illion barrels per day (bpd) by the end of 2005 and gas production should be between 11 and 17 b illion cubic feet per day (bcfd) by the same time period. Deepwater§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-10 exploration and deep exploration in th e shallow waters of the GOM are expect ed 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 ne w rigs are being built. In 2003, the majority of new offshore construction comprised jackup rigs. Surveys i ndicate 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 th e 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 a nd 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 fre quent 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 th ere 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 entir e 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 s ubmersibles or barges with total design intake rates meeting proposed rule criteria will be built during the tim e 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 w ith intakes having a total intake rate of less than 20 MGD, based on the intake rates of exis ting MODUs of these types in the survey.



### C2-2 O IL AND 

### G AS 

### P RODUCTION 

### P LATFORMS
C2-2.1 Overview Oil and gas production operations genera lly take place on platforms or other structures. The primary areas of offshore oil and gas production activity are the GOM, Calif ornia, and Alaska. In shallow offshore waters, platforms are the typical structure used to support th e resource extraction activities. These activities may involve drilling wells, producing oil and gas from wells, separati ng production streams, gathering and compressing gas, and working over older wells to increase production. Pl atforms often support buildings for crews, including in some cases, long-term living quarters. There are several different types of platforms, and non-pl atform 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 quarter s 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 Analys is 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 le g 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 th e 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 wa ters (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 onl y on the operations in Federal waters in the GOM. Operations in the coastal subcategory and in State offs hore 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 wher e cooling water intake rates might be in the size range of concern, EPA determined that the largest platforms a nd 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 an alysis 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), a nd 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 stru ctures were noted. Abandoned platforms and platforms without production equipment were eliminated from the plat form count. The platforms were then categorized by deepwater and shallow water, and 20+ wells and <20 wells. The counts are pr esented 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 Analys is 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 c onsists 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 producti on—and “downstream” activities—transportation, refining, and marketing). The second category of affected firms cons ists of independents engage d 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. Fu rthermore, 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 organi zed as S corporations (which elect to be taxed at the shareholder level rather than the corporate level under subc hapter S of the Internal Revenue Code). Small firms also might be organized as limited partnerships, sole propr ietorships, etc., whose owners, not the firms, pay taxes. The proportions of majors and indepe ndents operating in the State offshore in the GOM has been changing over the last dozen or more years. Ex cept for the deepwater GOM, majors have generally been disinvesting in the Gulf, selling their platforms to independents. Independe nts, 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 platform s purchased from majors do not engage as extensively in exploration, thus they may be tolerant of lower returns, since th eir 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 recen t 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 Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

3 Note that all corporate ties could not be identified. Cor porate parents are not obliged to list all subsidiaries, only significant subsidiaries. Where no corporate ties could be iden tified, EPA assumed the operator listed was at the highest leve l of corporate organization.

C2-13 in March 2003 (the date by which most firms must subm it 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 B HP 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 Analys is 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 D unhill Resources Inc Dynegy Midstream Services Li mited 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 LLC a ExxonMobil Corporation Exxon Mobil Corporation Fairways Specialty Sales & Service Inc F airways 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 H ouston 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 Analys is 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 L inder Oil Company, a Partnership LLOG Exploration Offshore In c 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 N ewfield Exploration Company Nexen Petroleum USA Inc N exen Petroleum USA Inc Nippon Oil Exploration U S A N ippon 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 R emington 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 Analys is 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 T ranscontinental Gas Pipe Line Corporation Transworld Exploration and Production Inc T ransworld Exploration and Production Inc Tri-Union Development Corporation T ri-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 W estport 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 (Alexa nder’s Oil and Gas Connections, 2002). Source: MMS, 2003a; SEC, 2003.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is 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 ownershi p 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 cost s 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 tabl e, 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 employees a 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 th e 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 opera ting in the GOM are those in the oil and gas extraction NAICS and the refineries NAICS. A total of 21 firms we re identified as small. Another 37 non-foreign firms could not be identified as small or large thus are cons idered small for purposes of analysis. As was done for MODU firms, all foreign firms were assumed to be la rge. 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 owne d (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 ma jors or independents (U.S. EPA, 2000). Table C2-8 shows the firms considered potentially aff ected 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 financia l health. Note that blank lines in Table C2-8 indicate firms that are likely to be privately held or are fo reign and for which no public data have been located.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-18 The ratios used to establish company financial status ar e profitability ratios, namely: return on assets, return on equity, and profit margin. As described earlier, these thr ee financial indicators are calculated as the ratio of the net income to the total assets, stockholders’ equity, a nd 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 be low. 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 retu rn 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 Stat e waters and 24 in State waters. Six companies operate platforms in State water off the California shore: Ae ra Energy LLC, Arguello, Inc., ExxonMobil, Nuevo Energy, Pacific Operators Offshore, and Venoco Inc. Two deepwa ter (>1,000 ft.) platforms operate in CA State waters, both of which are owned by ExxonMobil. Financial info rmation 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 Petroleu m Co. and Rincon Island Lim ited 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 join t venture company, Aera Energy) are the only majors operating in California State waters. The other compan ies are all unidentified. Nuevo Energy Company and Arguello (a subsidiary of Plains E xploration 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 tw o 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 C2: Profile of OOGE IndustryC2-19Table C2-8: Financial Conditions Among GOM FirmsCompany Name Size TypeNumber ofEmployeesAssets ($000) Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginAOC 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 64.45% 21.37%Apache Corporation Large Independent 1,958 $9,459,851 $544,000 $2,559,873$554,329 5.86% 101.90% 21.65%Apex Oil & Gas Inc Small* OtherArena Resources Small Independent5 $6,050 $5,125 $1,657 $403 6.66% 7.86% 24.32%ATP Oil & GasCorporationSmall Independent 53 $182,055 $38,547 $94,423 ($4,700) -2.58% -12.19% -4.98%B T Operating Co Small* OtherBHP Billiton Petroleum(Americas) IncLarge** Foreign $2,865,000$2,815,000 $718,000 25.06% 25.51%Bois D'arc Offshore Ltd Small* OtherBP PLC Large Major 73,350 $164,090,000 $178,721,000 $10,422,000 6.35% 5.83%Burlington ResourcesOffshore IncLarge Independent 2,003 $10,645,000 $3,832,000 $2,964,000 $454,000 4.26% 11.85% 15.32%Cairn Energy USA Inc Large** Foreign 19 $696,100 $70,000 $29,100 4.18% 41.57%Callon PetroleumOperating CompanySmall Independent 100 $410,613 $140,960 $67,108 ($1,671) -0.41% -1.19% -2.49%Calpine Corporation Large Other 3,353 $23,266,992 $7,457,899 $118,618 0.51% 1.59%Century Exploration Co. Small* IndependentChevronTexaco Large Major 53,014 $77,359,000$31,604,000 $99,049,000 $1,132,000 1.46% 3.58% 1.14%Cockrell Oil Corporation Small* IndependentComstock Resources Small Independent 62 $683,071 $215,662Conn Energy Inc Small* OtherConocoPhillips Company Large Major >10,000 $76,836,000 $56,748,000 ($295,000) -0.38% -0.52%Contour Energy E & P Small Independent 47§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE IndustryTable C2-8: Financial Conditions Among GOM FirmsCompany Name Size TypeNumber ofEmployeesAssets ($000) Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginC2-20LLCDenbury Resources Inc Small Independent 356 $895,292 $366,797 $285,152$46,795 5.23% 12.76% 16.41%Dominion Resources Large Other 17,000 $37,909,000 $10,218,000$1,362,000 3.59% 13.33%Duke Energy Co. Large Other 22,000 $60,966,000 $15,663,000$1,034,000 1.70% 6.60%Dunhill Resources Inc Small* OtherDynegy Inc. Large Other 1,524 $20,030,000 $2,087,000 $5,553,000 ($1,955,000) -9.76% -93.68% -35.21%El Paso Corp. Large Other 11,885 $46,224,000 $8,377,000 $12,194,000Energy Partners Ltd Small Independent 132$384,220 $191,922 $134,031 ($8,799) -2.29% -4.58% -6.56%Energy ResourceTechnology IncSmall* IndependentEOG Resources Inc Large Major 1,000 $3,814,006 $1,672,395 $1,095,036$87,173 2.29% 5.21% 7.96%Equilon Enterprises Large MajorExxonMobil Corporation Large Major 92,500 $153,000,000 $74,597,000 $205,000,000 $11,460,000 7.49% 15.36% 5.59%Fairways Specialty Sales &Service IncSmall* OtherForest Oil Corporation Small Independent 493 $1,924,681 $921,211 $475,694Garden Banks Gas PipelineLLCSmall* OtherGOM Shelf LLC Small* OtherGryphon ExplorationCompanySmall* IndependentHall-Houston Oil Company Small* IndependentHC Resources LLC Small* OtherHouston ExplorationCompanyLarge Independent 145 $1,138,816 $592,789 $345,381 $70,494 6.19% 11.89% 20.41%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 C2: Profile of OOGE IndustryTable C2-8: Financial Conditions Among GOM FirmsCompany Name Size TypeNumber ofEmployeesAssets ($000) Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginC2-21Juniper Energy LP Small* OtherKerr-McGee Corporation Large Independent 4,470 $9,909,000 $2,536,000 $2,540,000 ($485,000) -4.89% -19.12% -19.09%Linder Oil Company, aPartnershipSmall* OtherMagnum HunterProduction IncSmall Independent 221 $251,069 $72,152 $48,834 ($3,512) -1.40% -4.87% -7.19%Marathon Oil Company Large Major 28,166$4,479,000 $5,082,000 $31,720,000$516,000 11.52% 10.15% 1.63%Maritech Resources Inc Small* OtherMatrix Oil and Gas Small* OtherMcDermott InternationalIncLarge Other $128,171 ($416,757) $1,748,681 ($776,394) -605.75% 186.29% -44.40%McMoRan Exploration Co. Small Independent 18 $72,448 ($64,431) $43,768$17,041 23.52% -26.45% 38.93%Merit Energy Company Large** ForeignMillennium OffshoreGroup IncLarge** ForeignMission Resources Corp. Small Independent 90$342,404 $65,377 $105,464 ($38,484) -11.24% -58.86% -36.49%Murphy Oil Company Large Major $3,885,775 $1,593,553 $3,966,516$111,508 2.87% 7.00% 2.81%National Fuel GasCompanyLarge OtherNCX Company LLC Small* IndependentNewfield ExplorationCompanySmall Independent 488 $2,315,753 $1,009,231 $661,750 $73,847 3.19% 7.32% 11.16%Nexen Petroleum USA Inc Large** Foreign 1,767 $41,548,000 $1,971,300 $287,200 0.69% 14.57%Nippon Oil Exploration US ALarge** Foreign $11,076,000$34,894,000 $269,000 2.43% 0.77%Noble Corp. Large Independent 624 $3,065,714 $1,989,210 $986,356 $209,503 6.83% 10.53% 21.24%Ocean Energy Inc Large Independent948 $131,613 ($825) $47,483 $2,227 1.69% -269.94% 4.69%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 C2: Profile of OOGE IndustryTable C2-8: Financial Conditions Among GOM FirmsCompany Name Size TypeNumber ofEmployeesAssets ($000) Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginC2-22Petro Ventures Inc Small* OtherPetrobras America Inc Large** ForeignPetroquest Energy LLC Small Independent 57 $132,063 $97,770 $48,141 $2,307 1.75% 2.36% 4.79%Pioneer Natural ResourcesUSA IncLarge Independent 979 $3,455,100 $1,374,900 $717,400 $26,700 0.77% 1.94% 3.72%Pogo Producing Company Small Independent219 $2,426,608 $824,885 $605,500$87,954 3.62% 10.66% 14.53%PRS Offshore LP Small* IndependentRemington Oil and GasCorporationSmall Independent 29 $288,993 $193,660 $104,186 $11,332 3.92% 5.85% 10.88%Royal Dutch/Shell Group LargeMajorForeign111,000 $152,691,000 $235,598,000$9,419,000 6.17% 4.00%Scana Petroleum ResourcesIncSmall* OtherSpinnaker ExplorationCompany LLCSmall Independent 65 $842,715 $692,977 $188,326 $31,579 3.75% 4.56% 16.77%St Mary Energy Company Small Independent 185 $537,139 $299,513 $196,394$27,560 5.13% 9.20% 14.03%Stone Energy Corporation Small Independent 210 $1,179,371 $577,488 $377,495 $85,229 7.23% 14.76% 22.58%Tarpon Offshore LP Small* OtherTaylor Energy Company Small* IndependentTDC Energy CorporationLLCSmall* IndependentTorch Offshore Inc. Small Other362 $101,904 $79,867 $67,990 $395 0.39% 0.49% 0.58%TotalFinaElf E&P USA Inc Large** ForeignTranscontinental Gas PipeLine CorporationLarge Other 1,261 $4,969,532 $2,476,513 $1,276,282 $163,041 3.28% 6.58% 12.77%Transworld Explorationand Production IncSmall* Other $12,665,000 $7,141,000 $2,674,000 ($3,732,000) -29.47% -52.26% -139.57%Tri-Union DevelopmentCorporationSmall* IndependentUMC Pipeline Corporation Small* Independent§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analysis of Phase III New OOGE Facilities C2: Profile of OOGE IndustryTable C2-8: Financial Conditions Among GOM FirmsCompany Name Size TypeNumber ofEmployeesAssets ($000) Equity($000)Revenues($000)Net Income($000)Return onAssetsReturn onEquityProfitMarginC2-23Unocal Large Independent 6,615 $10,760,000$3,298,000 $5,297,000 $331,000 3.08% 10.04% 6.25%Vintage Petroleum Inc Large Independent 690$1,775,804 $570,992 $664,263 ($143,664)-8.09% -25.16% -21.63%W & T Offshore Inc Small* IndependentWalter Oil & GasCorporationSmall* IndependentWestport Oil and GasCompany LPSmall* OtherWestport ResourcesCorporationSmall Independent 333 $2,233,451 $1,132,006$400,398 ($28,566) -1.28% -2.52% -7.13%William G Helis CompanyLLCSmall* IndependentWilliams Company Large Other 7,300 $34,988,500$5,049,000 $5,608,400 ($754,700)-2.16% -14.95% -13.46%Note: Other is used if no designation for majoror 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 Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-24 Table C2-9: Financial Information for Compani es 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 Small a Other
Venoco, Inc. Small a Independent Rincon Island Limited Partnership Small a 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 tw o 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., ConocoPhillip s, XTO Energy, and Unocal Corp. Marathon owns the two out-of-operation platforms and is not considered a poten tially 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 remain ing operators are all listed as majors, as is the operator (BP) of the Duck Island structure in the Beaufort Sea (N orth Slope). Two of the firms in Alaska are listed under NAICS 324110 (SIC 2911), Petroleum Refineries, and th e 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 fu rther States that the water intake at the surface of the screen enclosure should not exceed 0.1 feet per second. Fo r 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 Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-25 Table C2-10: Financial Information for Co mpanies Operating Platforms in Alaska ($000) Company Name Size Type Employees Tot. Assets Equity Revenues Net Income Forest Oil Small Independe nt 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 Mode l for New Platforms Subject to Phase III Regulation Very few existing platforms appear to have CWISs with in take rates that meet the proposed rule’s criteria. Most of the existing platforms with CWISs of this size are lo cated 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 mak es 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: d eepwater, 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 th e 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 res pondent 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 num ber of structures to estimate the proportion of existing structures with CWISs meeting the proposed rule criteri a to total structures in the deepwater. Given eight structures meeting proposed rule criteria and 24 total st ructures, EPA believes that about 1/3 of deepwater structures to be built will be equipped with intakes mee ting 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 th at existing 206 exluding platforms were either known to have CWISs with intake rates meeting proposed rule cr iteria or their intake rat es were unknown (an additional 3 platforms were known to have CWIS intake rates l ess 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 crite ria 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 criteri a based on earlier data (see ERG, 2004a). None of these were sampled. EPA therefore assumes only these four platform s 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 Analys is 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 CW IS 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 ha d total design flow rates meeting proposed rule criteria. Although this is a very small sample, this finding is bol stered by EPA’s observations that platforms in State waters are unlikely to have CWIS with intake rates to taling 2 MGD or more (ERG, 2004a). Platforms in State waters and small platforms in Federal waters are genera lly similar structures. EPA therefore assumes that only four small platforms located in the shallow water GOM ha ve 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 fi rms, and most operate in the deepwater regions. In California, EPA determined that 20 platforms either ha ve 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 mee ting proposed rule criteria. EPA thus assumes seven existing platforms in California have total intake rates meeting proposed rule crite ria (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 plat form. 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 be tween Shell and ExxonMobil, and ExxonMobil). In Alaska, EPA determined that 19 platforms/production f acilities are in the survey universe (one platform was known to have a total CWIS intake rate of less th an 2 MGD and was dropped from the sampling frame). EPA sampled two platforms, but only one was determined to ha ve a CWIS intake rate meeting proposed rule criteria. EPA therefore estimates that there are 10 platforms in Alask a with intakes that meet proposed rule criteria (19/2 is a weight of 9.5). Five of these (all located in Cook Inle t) have CWIS data showing them to have CWISs meeting proposed rule criteria (ERG, 2004a). Of these structures w ith known CWISs of this size, all are platforms owned by Unocal. Based on this, EPA might assume no sma ll 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 conser vative, 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. Howeve r, 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 plat forms in California, and 10 platforms in Alaska, for a total of 33 existing platforms that meet proposed rule criteri a. 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 plat forms 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 c ontinuation of deep gas drilling and exploration in GOM. As technology advances and more deep gas wells are dr illed, 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 conti nues to advance, experts predict that this trend will§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-27 continue to be a substantial percen tage of gas exploration and production in GOM (Drilling Contractor, Jan./Feb. 2004). Standard & Poor's annual Report Card of the Oil and G as 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 ri sing 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 fl uctuated outside of the determined range a number of times since the band’s inception. OPEC has, however, ma intained 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 we ll 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 st ructures 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 pr oposed 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 larg e 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 lik ely to continue, given the r esources 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 Analys is 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 fe w, if any, such platforms might be built during the time frame of the analysis (see Table C2-11). As the table show s, 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 mee ting 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 th e 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 Analys is 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 InstallationNumber 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. Preside nt 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 G overnor 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 plan s 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 Fede ral California offshore regions is unlikely in the time frame of the analysis. In Cook Inlet, Alaska, only one new platform has been c onstructed in recent years. Most new exploration and development in this region takes place from existing infr astructure or from onshore locations using directional drilling, in which wells are drilled both vertically a nd horizontally to reach potential reserves, sometimes thousands of feet from the top-hole locations. No defin itive plans appear to be in place for any new platforms in State waters. In Federal waters, lo wer Cook Inlet is a source of potential activity, since MMS completed a lease§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Analys is of Phase III New OOGE Facilities C2: Profile of OOGE Industry

C2-30 bid in April, 2004. However, given the long lead tim es between lease bid to operation, it may be relatively unlikely that this lease bid will result in new platforms duri ng the time frame of the analysis in either location. To be conservative, however, EPA assumes one such platfo rm might be constructed in Upper Cook Inlet (State waters) and begin operation during the time frame of anal ysis. In other Federal areas in the Alaska region, little new activity is underway. BP has dropped plans for its Libe rty 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, c ould be beyond the time frame of this analysis.



### C2-3 T OTAL 

### N EW 

### O IL AND 

### G AS 

### O PERATIONS 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 o il 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 Offsho re 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 Involved a 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 Involved a 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 Analys is 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 Engineeri ng 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 Analys is 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 Flui ds 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-1 

### C HAPTER 

### C ONTENTS 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 brie fly 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 im pacts, 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 appli es 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-l evel 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 dur ing 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 fi rst in each section, followed by a discussion of the analytic results.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-2 

### C3-1 MODU A NALYSES C3-1.1 Aggregate National After-tax Compliance Cost Analysis A number of costs must be considered in calculating th e aggregate national after-tax compliance costs, each with distinct timing considerations. Permitting costs are incu rred by facilities, but these costs are incurred by facilities to come under one of three General Permits. EPA assu mes 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 ar e 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 Offsho re Oil and Gas Extraction Industry

. Pre-tax costs of installing and operating control technol ogies 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 cost s 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 ra te applies. This rate is 35% (IRS, 2002), so after-tax costs would be 65% of the pre-tax co sts. EPA does this because all MODU owners that are likely to build MODUs are large corporations by SBA st andards 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 co mpliance 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, th e 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

1 In the impact analysis, after-tax cost s are applied to existing MODUs, but these ar e calculated in a more exact way, since th e existing MODUs have known marginal tax rates, and a depreciation schedule is used to mo re precisely calculate the after-tax cos t 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 ar e 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 assigne d to each vessel, by type of vessel. The representative vessels are those launched in 2007 (jackups and semi-s ubmersibles) 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 co mpliance 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 Analysi s Elements for New Offshore Oil and Gas Extraction Facilities for more details). The present value costs are calcula ted by inputting each cost into the year that it is assumed to be incurred, which includes additional capita l 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 Elemen ts 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-4 Table C3-2 presents the costs of compliance on an annua l 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 g as 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 complian ce 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 Anal ysis 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-l evel 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 informati on 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 subj ect 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 barri er-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 require d 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 a nd semi-submersibles) or 2012 (drill ships). See the Compliance Cost Model (DCN 7-4018). The firm-level analysis is a revenue test, comparing th e revenues of firms likely to construct MODUs with the annualized compliance costs for repr esentative new vessels, assuming each firm identified as potentially affected builds a share of the new MODUs expected to be constr ucted 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 fo r MODUs constructed in 2007 (or the cost stream for a drill ship constructed in 2012, the first year post-complian ce in which a drill ship is assumed to be constructed) to represent the annualized costs to each potentially aff ected 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 ne w 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 cost s 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 th ese 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 financia l analysis for those MODUs with a positive net income or cash flow for the three years of financial informa tion provided in the survey. EPA assumes that any MODU whose cash flow or net income is negative over the three y ears 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 y ears 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 cycl e 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 operati ons, pricing, and thus the fi nancial performance of newly constructed vessels. EPA assumed that cash flow/net inco me will be flat on average over the 30 years of analysis and thus does not apply any factors to increase or decr ease cash flow or net income over the years of analysis within those cyclical movements. The cash flow/net inco me figures from the survey, therefore, repeat every three§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

2 Permitting costs to platforms are assumed to be associated w ith the Western Gulf Permit; use of this assumption avoids potent ially 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 calcula te 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 th e existing MODUs would represent new MODUs that are launched in 2007. Since EPA assumes MODUs launched in th is 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 c onsiders 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 Regi on 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 fo r which a financial survey response was received (with one exception), as well as ma ny 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 ma rginal 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 ou tlay. 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 calcula tes the present value of after-tax compliance costs. The present value output from the post-tax cost calculation m odel is then input to the cash flow/net income model and used to compare with the present value of cash fl ow/net income of the vessel as discussed above. If the present value of baseline after-tax cash flow or net inco me 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 M ODU would no longer continue to operate. If the net income value becomes negative, EPA assumes the longer te rm viability of the vessel is potentially jeopardized. In either case, such a MODU would be counted as a potential “r egulatory closure.” This analysis is considered an alternative assessment of the potential for barrier to entry. Although many of EPA’s analyses investigate whether co sts 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 fina nces 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 Anal ysis 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 Offs hore Oil and Gas Extraction Industry ).

C3-7 EPA used the incremental capital/installation costs and th e net present value of permitting costs of compliance for MODUs, as discussed above, using the cost streams associ ated 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 cons tructing new MODUs. If these compliance costs comprised a small fraction of construction costs, EPA assumed that co mpliance 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 CW ISs 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 cost s, therefore, are $127,200 for semi-submersibles, $257,642 for jackups, and $246,583 for drill ships). According to Drilli ng 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 complete d in 1998 (R&B Falcon’s Pathfinder 3 ) cost approximately $275 million. Incremental present value of permitting costs plus capital/in stallation 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 conti ngency, 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 firm s, EPA uses a revenue test, which compares the annualized pre-tax and after-tax costs of compliance (calcu lated 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 public ly owned, EPA relied on the revenue data reported in Chapter C2: Profile of the Offsho re 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 ru le. 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 es timated 103 new MODUs that would be affected by the proposal. These same firms also generally comprise the fi rms that are currently building new MODUs (see also Chapter C2: Profile of the Offsho re Oil and Gas Extraction Industry ). EPA then assigned a number of potentially in-scope MODUs to be built by each of the firms a nd used the average per-MODU compliance costs multiplied by the number of these potentially in-scope MODUs to calcu late the total compliance costs that might be faced by these firms. To calculate costs to revenues, EPA uses the pre-tax a nd after-tax costs shown in Table C3-2 for the firms identified as likely to construct new MODUs meeting the pr oposed 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 bu ild 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 consid ered 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 reve nue 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 Anal ysis 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 volunt ary technical data, so EPA is not able to determine whether they own MODUs that might meet the proposed rule’s crite ria were they to be newly constructed. These firms a re Atwood Oceanics, Caspian Drilling Co., Energy Equipment Resources, Nabors Industries, Newf ield Exploration, Ocean Rig ASA, Park er Drilling, Tetra Technologies, and Workships BV. Most of these fi rms, however, own only one or tw o such MODUs and are considere d far more likely to purchase MODUs from the firms in cluded in this analysis than to build th eir own (several of these MODUs have cle arly been purchased from GlobalSantaFe, for example). Had these firm s been included in the analysis , however, EPA’s findings would not have changed. The firm with the lowest revenues in this gr oup among those with publicly availa ble data (Atwood Oceanics, Parke r Drilling, and Newfield Exploration; see Chapter C2: Profile of the Offs hore Oil and Gas Extraction Industry ) reported 2002 revenues as $149 million. Applying the same methodology that EPA used for th e firms considered likely to bu ild MODUs, EPA would predict th at the cost-to-revenue ratio among these firm s considered unlikely to build MODUs would be at most 0.3 percent.

C3-8 rates that are considered unlikely to build new M ODUs 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 w ould be built with sea chests and, therefore, these vessels would not be required to meet entrainment controls. Ho wever, 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 E CONOMIC 

### I MPACT 

### A NALYSIS FOR 

### O IL AND 

### G AS 

### P RODUCTION 

### P LATFORMS This section presents the aggregate national after-tax co mpliance costs for new oil and gas production platforms that will be built in scope. It also presents platform-l evel 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. Th e second section uses an approach for identifying barriers to entry for all platforms likely to be built in sc ope 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 Anal ysis 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-t ax compliance costs are iden tical to that used for calculating these same costs for MODUs, although the costs incu rred are different. Costs are input in each year in which they occur over the 30-year time frame of th e 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 presen t value of the cost stream. These present value costs are then annualized. For more details on timing assumpti ons and annualized and present value cost calculations, see Chapter C1: Summary of Cost Categories and Key A nalysis 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 pr e-tax costs. EPA does this because all platform owners that are likely to build in-scope plat forms 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 co mpliance 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 Anal ysis 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 de preciation schedules; see Section C3-2.3a below and ERG [2004d]).

C3-10 Table C3-4: Total National Aggregate A fter-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 capita l/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-lev el 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-11 a. Pre-Tax Cost of Complian ce 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 co sts, but these costs are fo r a representative deepwater platform that comes on line in 2007 (year of comp liance assumed 2007) and the representative Cook Inlet platform coming on line in 2014 (year of compliance). Cost s (which are incurred over the full time frame of the analysis, including recurring capital replacement and repermitti ng 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-12 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, th e 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 w ith CWIS intake rates meeting the proposed rule’s requirements. The financial information from the deep water 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 Os prey 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 si gnificantly lower cost than the traditional fixed platforms located in the inlet. EPA does not have sufficient fina ncial 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 barri er-to-entry analysis used fo r 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 ty pe of platform. This is a typical barrier-to-entry analysis, which assesses incremental start-up costs associat ed with compliance to baseline start-up costs. The firm-level analysis is a revenue test, comparing th e revenues of firms likely to construct platforms whose CWISs meet the proposed rule’s criteria with the a nnualized 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 conser vative, EPA assumes the firms bring all platforms on line in one year for comparison to one year’s revenues. One sma ll 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 th e 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 r eason, 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 pr oduction platform based on information obtained from EPA’s survey and from other sources of publicly availa ble information, such as that from MMS. ERG (2004d; non-CBI version) contains additiona l 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 ra tes, that are used to model individual platforms. For specific details on the values of variables defined by su rvey information and the detailed impact results, see ERG (2004d; CBI version).§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-13 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 re levant) are based on an assumed price of oil, current and projected production of oil and gas, well production declin e rates, and severance and royalty rates. Operating costs are based on a calculated cost per barrel of oil e quivalent (BOE) produced. The model runs for 30 years or is assumed to shut in when operating costs exceed revenu es. That is, the economic model can calculate differing lifetimes according to project characteristics. The mode l 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 opera ting 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 ha ve 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 expe nditure line (which is used in both the cash flow and net income calculations), and additional O&M and permitting co sts 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 imp act on a platform. First, any increase in operating costs might raise total operating costs enough to cause the opera ting 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 al so drive the net present value of a marginal operation negative. The decision in this case would be to not deve lop the project rather than build the project with I&E controls in place, since the project would not be consid ered 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 plat form-specific impacts are not reported here. See ERG (2004d; CBI version) in the CBI portion of the Rule making Record for detailed information on impacts. However, EPA determined that there would be no imp acts 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 valu e of initial permitting costs for compliance for new deepwater and Alaska platforms to comp are 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 d ecision 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, de lineation, 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/insta llation costs plus the present value cost of the initial round of permitting costs. The ratio of incrementa l compliance costs to construction costs ranges from 0.01 percent to 0.3 percent for deepwater projects and 0.6 per cent for an Alaska project. This is a small fraction of contingency on these projects. c. Firm Level Impacts The firms that are considered affect ed are those identified as currently ha ving 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 anal ysis. All the firms considered likely to build a new§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis 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 appr oach used for judging impacts on MODU owners). These costs are then compared to firm-level revenues in a revenue test. Both pre-ta x 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 T OTAL 

### C OSTS AND 

### I MPACTS 

### A MONG 

### A LL 

### A FFECTED 

### O IL AND 

### G AS 

### I NDUSTRY 

### E NTITIES 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 a nd their associated firms are expected to be minimal, Aggregate national after-tax compliance costs are also s hown 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 constr ucted over the period of the analysis.§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-15 Table C3-7: Total National Aggregate Annualiz ed 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 Total a $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 T OTAL C OSTS TO G OVERNMENT E NTITIES AND S OCIAL C OSTS OF THE 316( B ) P HASE III R ULEMAKING 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 Va lue 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-ta x 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 disloca tions are incurred. A small deadweight loss would occur,§ 316(b) Proposed Rule: Phase III – EA, Part C: Economic Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-16 but this is not calculated. Consumer and producer surp lus 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 di scount 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 Prop osed 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-17 

### R EFERENCES 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 R ecord (CBI version). September 24, 2004. ERG. 2004d. Detailed Methodology and Results for O il and Gas Production Platforms. Memorandum to the 316(b) Phase III Rulemaking Record (Non-CBI version) a nd 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. Reduc ing 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 Flui ds 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 Anal ysis for Phase III New OOGE Facilities C3: EIA for OOGE Facilities

C3-18 

### T HIS 

### P AGE 

### I NTENTIONALLY 

### L EFT 

### B LANK§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Economic Analyses for Existing and New Facilities D1: RFA

D1-1 

### C HAPTER 

### C ONTENTS 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

I NTRODUCTION 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, c ounty, town, school district or special district with a population of less than 50,000; and (3) a small organi zation that is any not-for-profit enterprise which is independently owned a nd 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 exis ting facilities before this change, EPA performed the small entity analysis for existing faciliti es based on SIC codes. EPA then conducted a subsequent analysis to determine whether use of NAICS codes-b ased 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 impact s are the same under both SIC-based and NAICS-based size standards. Appendix 2 to this chapter presents the findi ngs for the comparison of the SIC-based analysis and the NAICS-based analysis. To evaluate the potential impact of this rule on sma ll entities, EPA identified the domestic parent entity of each facility potentially subject to Phase III regulation, and dete rmined 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: l ess 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 existi ng facilities would be subject to the national categorical requirements under the proposed rule: the “50 MGD for A ll Waterbodies” option (the “50 MGD All” option); the “200 MGD for All Waterbodies” option (the “200 M GD 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 th at 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 require ments to 136 facilities. The 200 MGD All option would apply national categorical requirements to 25 faciliti es, 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) Industr y 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 estim ated 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 (entiti es that operate facilities subject to permit specifications based on best professional judgment, BPJ, would not incu r 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 th e new offshore oil and gas extraction industry segment, EPA estimates that the proposed rule would apply national re quirements to only one small entity. EPA estimates that this entity would incur annualized after-tax complian ce costs of less than 0.1% of annual sales revenues.



### D1-1 A NALYSIS OF 

### M ANUFACTURERS 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 Ph ase 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 fac ilities 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 theref ore 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 estim ated the number of small entities owning facilities in the Primary Manufacturing Industries as a range, based on alte rnative 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 th resholds at http://www.sba. gov/regulations/siccodes.

3 For a comparison of the small entity determination using SIC c odes and NAICS codes, respectively, see Appendix 2 to this chap ter.

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 we re 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), be low 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 Paper board 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 Synt hetic 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, En amels, 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 Pr eparations, 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 po ssible 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 th e 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 a nd 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 fi rms, while tending to maximize the potential cost burden to any single firm. Data in the rest of this section are presented by the indus try 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 assigne d to the “multiple industries” firm sector. As discussed earlier, one known facility in the Other Industries group w as found to be owned by a firm that owns facilities in the Primary Manufacturing Industries. This firm is incl uded 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 Industr ies that would be required to meet the national categorical requirements set by the proposed options vari es by option based on the DIF applicability threshold and waterbody type specified in the option. Under th e 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 num ber 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 Industries a,b 105 - 0.0% 46 - 0.0% Additional firms that own known facilities in Other Industries a 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 Industries a,b 21 - 0.0% 14 - 0.0% Additional firms that own known facilities in Other Industries a 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 Industries a,b 21 - 0.0% 12 - 0.0% Additional firms that own known facilities in Other Industries a 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 Manufacturi ng 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 requi rements 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) publis hed 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 i ndustry 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 establis hments 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 requi rements 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 ex tent 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 af ter-tax compliance costs to annual revenue of the entity. For this analysis, EPA judges that entities for which annua lized 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 require ments; one-time costs of installation downtime; annual operating and maintenance costs; and permitting costs (in itial 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 entiti es would incur compliance costs or significant economic impact under these options.



### D1-2 A NALYSIS OF 

### E LECTRIC 

### G ENERATING 

### F ACILITIES 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) Industr y Survey, please refer to the Information Collection Request (U.S. EPA, 1999a).

5 No political subdivisions were found to be subject to the na tional categorical requirements under any of the evaluated option s. 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 th erefore discusses research done for the 110 sample facilities only. D1-2.1 Small Entity Determination Similar to the analysis for Manufacturers, the small en tity 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 an alysis is conducted at the highest level of domestic ownership, referred to as the “domes tic 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 s ubdivision, 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 in corporated known ownership changes through the 2002 calendar year, but did not incorporate changes in fac ility/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 faciliti es that they own. IOUs and nonutilities, on the other hand, are often owned by holding companies. A holding co mpany 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 ma nagement decisions of these firms” (Census, 2002). To determine the domestic parent entity for potential Ph ase 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 c odes and NAICS codes, respectively, see Appendix 2 to this chap ter.

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 standa rd 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 a nd Bradstreet data, as well as the following publicly available data sources, to obtain the informati on 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. Ce nsus 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 Genera tors that were used to determine the size of privately-owned entities.

< All Federal and State governments are considered large for th e 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 Elect ric 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 Bu ildings, 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 fro m 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 smal l 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 th reshold 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 w ould 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 EI A-861, 858 unique IOUs, Federal utilities, State authorities, municipalities, and rural electric cooperatives operated el ectric 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 sal es 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 sm all 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 thres hold 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 w ould 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 Ph ase III nonutility facilities. These 26 nonutilities are owned by t he 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 de terminations 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 holdi ng 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 sma ll 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 regul ation (also referred to as the “sales test”). The analysis is based on the ratio of each parent entity’s aggregat ed 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 mi ght experience a significant economic impact as a result of Phase III regulation.
The estimated annualized after-tax co mpliance 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 summa ry 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 Generati ng 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 comp any 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, we re covered under the final Section 316(b) Phase II rule. Therefore, no Electric Generators are regulated or in cur 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 A NALYSIS OF 

### N EW 

### O FFSHORE 

### O IL AND 

### G AS 

### E XTRACTION 

### F ACILITIES This section discusses EPA’s analysis of potential small en tity impacts of the proposed rule on the new offshore oil and gas extraction industry segment. The proposed Ph ase III regulation for new offshore oil and gas extraction facilities is based on a 2 MGD DIF applicability threshol d 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 pl atforms 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 Offsho re 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 re ports generally list significant subsidiaries of the parent company and are the source of income statement and bala nce 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 c ode. Table D1-4 shows that of the 21 parent entities operating MODUs in the Gulf of Mexico, only two entiti es 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 Firms a 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 a nd 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-submersibl e 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 th e 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 La nd 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 cons tructed in the last 16 years. Most new exploration and development in this region takes place from existing infrast ructure or from onshore locations. No definitive plans appear to be in place for any new platforms in State wa ters. In Federal waters, lo wer Cook Inlet is a source of potential activity, since MMS completed a lease bid in Ap ril, 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 th at 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 Libert y 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 w ould 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. Th e 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 ne w 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 pr oposed 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 g as 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 a ll 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 pr oposed rule is therefore approximately 0.012% pre-tax or 0.008% after-tax.



### D1-4 S UMMARY OF 

### R EGULATORY 

### F LEXIBILITY 

### A NALYSIS 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 nationa l 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 propo sed 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 Enti ty 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 Existi ng 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 

### R EFERENCES 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.censu s.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 Sma ll 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: A dditional 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 opti ons, 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 fo r 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 op tions). As discussed in the main chapter, the estimates of the total number of regulated small entities and th e 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 entiti es incurring costs in the th ree 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 Manufacturers a,b 5,113 3 0.1% 4 - - Electric Generators 543 - 1,295 9 0.7% - 1.7% 6 3 - Total c 5,656 - 6,408 12 0.2% 10 3 - Option 4 Manufacturers a,b 5,113 1 0.0% 1 - - Electric Generators 543 - 1,295 2 0.2% - 0.4% - 1 1 Total c 5,656 - 6,408 3 0.0%-0.1 %111 Option 2 Manufacturers a,b 5,113 3 0.1% 4 - - Electric Generators 543 - 1,295 9 0.7% - 1.7% 5 3 1 Total c 5,656 - 6,408 12 0.2% 9 3 1 Option 1 Manufacturers a,b 5,113 3 0.1% 4 - - Electric Generators 543 - 1,295 9 0.7% - 1.7% 4 4 1 Total c 5,656 - 6,408 12 0.2% 8 4 1§ 316(b) Proposed Rule: Phase III – EA, Part D: A dditional 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

Manufacturers a,b 5,113 10 0.2% 12 1 - Electric Generators 543 - 1,295 13 1.0% - 2.4% 7 5 1 Total c 5,656 - 6,408 23 0.4% 19 6 1

a For Manufacturers, the more conservative cost analysis (Case 2 es timate) is presented, which is likely to overstate the complia nce costs that would be incurred by any single small entity but may understate the number of small entities incurring compliance co sts. 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 repor ted totals due to independent rounding. Source: U.S. EPA Analysis, 2004.§ 316(b) Proposed Rule: Phase III – EA, Part D: A dditional Economic Analyses Appendix 2 to Chapter D1

1 Two different bridges are available from Census. One provide s a bridge based on the processes/activities performed and the o ther bridge is based on establishment classifica tions. This analysis uses the bridge based on estab lishment classifications (Census , 2000).

D1A2-1 

### C HAPTER 

### C ONTENTS 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

I NTRODUCTION 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 I DENTIFYING 

### NAICS C ODES AND 

### T HRESHOLDS EPA started with the unique firm-level 4-digit SIC cod es 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 SI C codes, SIC code descriptions, SIC code-based small business thresholds, as well as the corresponding NAICS c odes, 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: A dditional 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 Indus trial Gas Manufacturing 1,000§ 316(b) Proposed Rule: Phase III – EA, Part D: A dditional 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 1,500 a

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: A dditional 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: A dditional 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 1,000 b

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: A dditional 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 assets d 522210 Credit Card Issuing $150 million in assets d 522220 Sales Financing $6.00 522291 Consumer Lending $6.00§ 316(b) Proposed Rule: Phase III – EA, Part D: A dditional 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 refine r must be a concern that has no more than 1,500 employees nor more than 125,000 barrels per calendar day total Operable Atmos pheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities unde r 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 s upport equipment on a contract basis are classified under NAICS c ode 336413.

c A firm is small if, including its affiliates, it is primarily e ngaged in the generation, transm ission, and/or distribution of electric energy for sale and its total electric output for the pr eceding fiscal year did not exceed 4 million megawatt hours.

d A financial institution's assets are determined by averaging th e assets reported on its four quarterly financial statements fo r 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 D IFFERENCES IN 

### NAICS-B ASED AND 

### SIC-B ASED 

### S IZE 

### T HRESHOLDS 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 thr eshold, which could lead to additional firms being classified as small businesses, and (2) the NAICS threshold is less than the SIC threshol d, 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 th reshold 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 cat egory. Table D1A2-3 lists SIC codes for which the NAICS threshold is less than the SIC threshold and therefore c ould 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: A dditional Economic Analyses Appendix 2 to Chapter D1

D1A2-8 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: A dditional Economic Analyses Appendix 2 to Chapter D1

D1A2-9 

### D1A2-3 R ESULTS During the final step of this comparison, EPA anal yzed 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 determina tion would not change (see also Table D1A2-1). For this firm, EPA used info rmation 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 diffe rence in small entity determinations, and therefore no change in small entity impacts, as a result of usi ng NAICS-based size standards instead of SIC-based size standards, for the small business determination.§ 316(b) Proposed Rule: Phase III – EA, Part D: A dditional Economic Analyses Appendix 2 to Chapter D1

D1A2-10 

### R EFERENCES 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-1 

### C HAPTER 

### C ONTENTS 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

I NTRODUCTION
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 st atement is needed, UMRA section 205 generally requires EPA to identify and consider a reasonable number of re gulatory alternatives and adopt the least costly, most cost-effective, or least burdensome alternative that achie ves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with appli cable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effectiv e, or least burdensome alternative if the Administrator publishes with the rule an explanation why that alte rnative 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 inform ing, educating, and advising small governments on compliance with regulatory requirements. EPA is proposing three options that define which existi ng 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 M GD 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 a pplicability 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 a bbreviated as “new OOGE facilities”) in Phase III. These proposed requirements are based on a 2 MGD DIF applicab ility threshold and would apply to an estimated 124 new offshore oil and gas extraction facilities.

< 50 MGD for All Waterbodies option for existing fac ilities and proposed option for new offshore oil and gas extraction facilities: EPA estimates the total annualized after-t ax 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 th e 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 wr ite 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-2 < 200 MGD for All Waterbodies option for existing fa cilities and proposed option for new offshore oil and gas extraction facilities: EPA estimates the total annualized af ter-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 offshor e oil and gas extraction facilities). No facility owned by State and local governments would be subj ect 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, incl uding 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 existin g facilities and proposed option for new offshore oil and gas extraction facilities: EPA estimates the total annualized af ter-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 offshor e oil and gas extraction facilities). No facility owned by State and local governments would be subj ect 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, incl uding 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 ru le 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 UM RA, 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 i nput; (4) a discussion related to the least burdensome option requirement; and (5) an analysis of small government bur den. This chapter contains additional information to support that statement, including information on complia nce 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 A NALYSIS OF 

### I MPACTS ON 

### G OVERNMENT 

### E NTITIES Governments may incur two types of co sts as a result of this proposed rule:

< direct costs to comply with the rule fo r facilities owned by government entities, and

< administrative costs to implement the rule. Both types of costs are di scussed on the following pages. D2-1.1 Compliance Costs for G overnment-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 Manuf acturers or new offshore oil and gas extraction facility segment are owned by a government. EPA has determin ed that no government-owned facility has a DIF thatexceeds 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

1 The costs associated with implementing Phase III requirements are documented in EPA’s Inform ation Collection Request (U.S. EPA, 2003).

D2-3 D2-1.2 Administrative Costs for Existing Facilities The requirements of section 316(b) are implemented th rough 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 (C WA). 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 th e 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 a nnual activities. The maximum one-year undiscounted implementation cost incurred by governments under the th ree 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 th an 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 cost s incurred in later years have lower present values. a. Start-Up Activities Forty-five States and one Territory with NPDES permitti ng authority are expected to undertake start-up activities to prepare for administering the proposed rule. Star t-up activities include reading and understanding the rule, mobilization and planning of the resources required to addr ess 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 add ition, 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

2 For an explanation of how the compliance years were assigne d to facilities subject to Phase III regulation, see Chapter B1.

3 EPA is not including this site-specific determination as a direct cost for comply ing facilities because this is an optional a ctivity that the facility would choose only in cases where the cost of the alternative technology plus the cost of the site-specific determi nation is less than the cost of the technology otherwise required by the proposed rule. However, the site-sp ecific determination costs for pe rmitting authorities are not optional, and thus are in cluded 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 Permi tting 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 perm it. 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 ty pe of information for their initial post-promulgation permit and for each permit renewal application. Therefor e, 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 s ubmitted documents and supporting materials, verifying data sources, consulting with facilities and the interest ed public, determining specific permit requirements, and issuing the permit. Table D2-3 presents the State perm itting 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 familia r 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 author ized State is able to permit a facility to opt for a sitespecific determination if it can demonstrate that th e 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-5 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 Construc tion Technology Plan $1,443 $410 Review Impingement Mortality Monitoring Results $4,279 $1,284 Review Entrainment Characteri zation Monitoring Results $4,279 $1,284 Review Baseline Characterization Monito ring Results and Study Findings $12,678 $3,819 Review Pilot Study for New Impinge ment & Entrainment Technology $1,302 $407 Review Restoration Measures a $2,299 $690 Review Technology Installation a nd 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 S upport Site-Specific Determination of BTA $45,980 $13,794 Establish Requirements for S ite-Specific Technology $1,162 $322 Site-Specific Costs c $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 facilitie s conducting site-specific demonstrations. Source: U.S. EPA, 2004.

As shown in Table D2-3, initial post- promulgation permits that do not requi re 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 dete rmination, the State admini strative costs associated with the site-specific determination are estimated to in crease by $47,000, resulting in total per permit costs of approximately $81,000.§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-6 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 re view 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 require ments to reduce impingement mortality and entrainment within a watershed. If these States demonstrate to the Ad ministrator that the reductions are comparable to what would otherwise be achieved under rule, the Admini strator 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 requirement s. For this analysis, EPA assumed that those States interested in adopting alternative regulatory requirement s would have done so under the Phase II rule. As a result, EPA assumes that these States would incur no additional co sts 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-7 Table D2-5: Government Costs of Alternative Regulatory Requirements (per Permitting Authority; 2003$) Activity Post-Promulgation Permit Costs Document Alternative Re gulatory Requirements $1,360
Document Environmental Cond itions within Watershed $1,813 Include Supporting Historical Studies , Calculations, and Analyses $3,542 Submit Documentation $97 Recordkeeping $138 Other Direct Costs $100
Total a $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 discu ssed above, permitting authorities would have to perform certain annual activities to ensure the continued implemen tation of the requirements of the proposed rule. These annual activities include reviewing biannual status re ports, tracking compliance, making determinations on monitoring frequency reduction, and record keeping.
Table D2-6 outlines the annual activities necessary for each permit, along with th eir estimated costs. These costs begin with the issuance of the first permit following prom ulgation of the rule. A total cost of approximately $1,500 is estimated for each permit per year.

Table D2-6: Government Co sts for Annual Activities (per Permit; 2003$) Annual Activity Annual Costs Review of Biannual Status Report a $340 Compliance Tracking $581 Determination of Monitoring Frequency Reduction $453 Record Keeping $138 Other Direct Costs $30
Total b $1,541

a This is a cost that is incurred on ce every two years. Therefore, only ha lf 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-8 The Federal government is likely to incur costs for revi ewing 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 issu ed 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 Informa tion 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 Impi ngement & Entrainment Technology $113 Review Restoration Measures a $34 Review Technology Installation and Opera tion 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 Requireme nts for Site-Specific Technology $145 Site-Specific Costs c $825 Total Cost (with site specific determination) b $2,494

a Assumed to apply to only 10% of facilities. Only 10% of th e 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 Offs hore 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 fo r new offshore oil and gas extraction facilities, the Federal government would incur no costs for State oversi ght, 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-9 activities, (2) activities associated with the initial General Permit containi ng the new section 316(b) requirements and subsequent permit renewals, a nd (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 gove rnment 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 Permi tting and Repermitting Activities Initial permitting and repermitting activities relate to the revi ew of data collected for the regional studies and the individual data submitted by facilities that plan to be pe rmitted (or re-permitted) under the General Permits in the three EPA Regions. Tables D2-8 and D2-9 present the indi vidual activities and their costs for Regions 4, 6, and 10. These costs are on a per facility basis, i.e., the re gions incur these costs for each facility that is permitted under their general permits (see DCN 7-4018, which illustra tes 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 a nd 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 bur den of initial permitting, appr oximately $3,200 per facility, because the permitting authority is already familiar with th e facility’s case and the type of information the facility would provide. Repermitting costs are incurred in 5-y ear intervals after the initial post-promulgation permit.§ 316(b) Proposed Rule: Phase III – EA, Part D: Additional Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-10 Table D2-8: Federal Government Co sts 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 Construc tion 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 Biol ogical 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
Total a $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 ac tivities 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 (assu med 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-11 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 Reduction a $0 Record Keeping $138 ODCs Lump Sum $30
Total b $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 ru le 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 f acilities; governments own no facilities in either the Manufacturers or new offshore oil and gas extraction f acility 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 co mpliance 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 C OMPLIANCE 

### C OSTS FOR THE 

### P RIVATE 

### S ECTOR The only compliance costs incurred by the private sect or 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 pr oposed 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 existin g 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-12 < Under the 200 MGD for All Waterbodies option for existin g 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 ex isting 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 S UMMARY OF 

### UMRA A NALYSIS 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 implem ent 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 Existin g 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 faciliti es and the three proposed options for Phase III existing facilities are as follows:

< The 50 MGD for All Waterbodies option for existing fa cilities 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 approxi mately $2.0 million for government entities, and $280.3 million for the private sector. Both of these maximu m annual cost values are estimated to occur in 2011.

< The 200 MGD for All Waterbodies option for existin g 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-13 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 exis ting 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 Ec onomic Analyses for Existing and New Facilities D2: UMRA Analysis

D2-14 

### R EFERENCES 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.