MA0003654 Determinations Document July 22, 2002

1 The Brayton Point TAC was formally made up of “the active biologists of those regulatory agencies which have responsibility for the aquatic community in Mount Hope Bay,” including those from the U.S. EPA Region 1, the U.S. EPA Narragansett Laboratory, U.S. National Marine Fisheries Service, the Massachusetts Division of Water Pollution Control, the Massachusetts Division of Marine Fisheries, Massachusetts Coastal Zone Management. EPA

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### 2.0 Ecological Setting

2.1 Mount Hope Bay - Physical Setting

Mount Hope Bay is a shallow estuary that is an offshoot of Narragansett Bay (Figure 2.1-1). A portion of the bay is located in the state of Rhode Island, while the rest is in the state of Massachusetts. Several rivers drain into the bay including the Taunton, the Kickamuit, the Cole, the Lee (also known as Lees or Lee’s) and the Quequechen. The bay itself is connected to Narragansett Bay by the Narragansett Bay East Passage and the Sakonnet River. Mount Hope Bay is 7 miles in length along the north-south axis (USGenNE, 2001) and has a surface area of 13.6 mi 2 and a volume of 53 billion gallons at mean low water (Chinman and Nixon, 1985).

In general, the bay is relatively shallow with an average depth of 18.7 ft (Chinman and Nixon, 1985). Most of the northern portion of the bay is shallower than this, as the deeper portions of the bay tend to be in the south, the shipping channel along the east side and the connections to Narragansett Bay. Furthermore, 70% of the bay is less than 6 meters deep at mean low water (NEP, 1998).

2.2 Hydrology

Water circulation in Mount Hope Bay is primarily influenced by tidal flow, wind and freshwater river flow. The Taunton River delivers a significantly greater quantity of water to the bay than the other four rivers combined. The long term average flow of the Taunton is 7,846 gal/sec., while the long term average for the Cole is 214 gal/sec and the long term averages for the Lee, Kickamuit and Quequechen are even less (Ries, 1990).

Tidal currents are generally between 0.3-0.8 ft 3 /sec with a mean tidal range of 4.4 ft (Spaulding and White, 1990). Tides are the primary source of circulation in the bay with 7.9 billion gallons of water being flushed through the bay twice a day (USGenNE, 2001).

2.3 Water Quality

Water quality in Mount Hope Bay has been of great interest to the Technical Advisory Committee (TAC) 1 as it potentially could have direct bearing on fish distributions. WaterMA0003654 Determinations Document July 22, 2002

Fact Sheet for BPS Draft NPDES Permit No. MA003654 (June 11, 1993), p. 10. The TAC grew to include representatives from Rhode Island’s Department of Environmental Management and Coastal Zone Management Office, who also have responsibilities for the aquatic resources of Mount Hope Bay. TAC meetings have also typically included representatives of the permittee and other interested members of the public, such as from interested environmental organizations.

2-2 temperature and dissolved oxygen have been two parameters in particular that have been the focus of a substantial amount of study in the bay. Both of these parameters can have direct effects on fish at the metabolic, individual and population levels. These effects will be discussed in the Section 316(a) portion of this document.

2.4 Temperature

Water temperature in Mount Hope Bay fluctuates greatly with season. The average monthly temperature in February is 35.6 o F, while the average monthly temperature in August is 75.2 o F (USGenNE, 2001). Several researchers have documented a long-term increase in water temperatures across both Mount Hope Bay and Narragansett Bay. This research is discussed in detail below. At the same time, satellite imagery analyzed by Dr. Jack Mustard of Brown University shows that the surface water of Mount Hope Bay is on average 1.5 o F warmer in the summer and fall than comparable shallow parts of Narragansett Bay (Mustard et al., 2001). Thermistor data collected simultaneously with the satellite imagery showed that the satellite was recording the temperature of approximately the top 6 feet of the water column (Mustard et al., 2001). In general, thermistor data showed that water temperatures then declined gradually from the 6 foot depth until the bottom (Turner, 2001).

2.5 Dissolved oxygen

Dissolved oxygen (DO) concentrations in Mount Hope Bay have been measured by numerous investigators with various methodologies over the past 20 years. From 1985 to 1988, the Massachusetts Department of Environmental Protection conducted a series of cruises collecting DO measurements at 24 sampling locations in Mount Hope Bay. DO was measured using a Seacat SBE-19 Profiler to produce a depth profile of DO concentrations at each station. In August 1996, the permittee deployed continuous DO recorders at two locations in Mount Hope Bay for 30 days. Dissolved oxygen concentrations were measured at a meter below the surface and a meter above the bottom. Since 1999, MA CZM has deployed continuous DO recorders in the lower Taunton River and mid-bay at the state line. In addition, the Narragansett Bay project has conducted nighttime Narragansett Baywide DO surveys 2 or 3 times a summer for the past 3 years. This sampling effort is spatially intensive, with over 20 sampling locations within Mount Hope Bay itself. In this survey, instantaneous measurements are taken with a YSI meter to produce a depth profile of DO concentrations at each station.

In general, DO varies seasonally in the bay with minimum values occurring in August andMA0003654 Determinations Document July 22, 2002

2-3 September. Surface DO concentrations are generally greater than concentrations deeper in the water column, though data from the 1996 continuous DO meters show periods where surface DO is depressed relative to DO at depth (Figures 2.5-1 and 2.5-2). The continuous DO meters and the instantaneous profiles taken around Mount Hope Bay have seen periods of extremely low dissolved oxygen (< 2 mg/l) (Figures 2.5-1 and 2.5-2).

Sampling of the benthic community by EPA Narragansett’s lab has revealed that the lower Taunton River and areas around Spar Island have productive benthic communities consisting of ampelisca amphipods (Cinchetti, 2001). These amphipods are very sensitive to low DO and excessive carbon loading and are good indicator organisms. This suggests that the low DO concentrations measured in Mount Hope Bay are not likely severe enough in magnitude or duration to compromise the benthic community, an important foraging resource for many demersal fish species.

2.6 Status of Fish Populations

As a requirement of previous permits, Brayton Point Station has been required to collect finfish abundance data from several fixed trawl stations in Mount Hope Bay. These surveys have been conducted with consistent methodology since 1972. In addition, the University of Rhode Island (URI) and the Rhode Island Division of Fish and Wildlife (RI DFW) also conduct regular trawling surveys in Narragansett Bay, including two stations in Mount Hope Bay. In 1996, Mark Gibson of RI DFW issued a final report which brought information from these three separate sampling efforts together and looked at the historical trends in fish abundance in Mount Hope Bay. Gibson’s report painted a bleak picture of the condition of most of the fish stocks in Mount Hope Bay. In 16 of the 21 species examined, the rate of decline in Mount Hope Bay was greater than in neighboring Narragansett Bay. For winter flounder, windowpane, tautog and hogchoker, the differences in the rate of decline were statistically greater in Mount Hope Bay than in adjacent Narragansett Bay. Winter flounder abundance in Mount Hope Bay declined from an average of approximately 34 fish/tow from 1972 to 1984 to 2 fish/tow from 1985 to 1998 (USGenNE, 1999). Windowpane abundance declined from about 5 fish/tow to about 0.5 fish/tow in the same time period (USGenNE, 1999). Tautog declined from 0.9 fish/tow to 0.14 fish/tow during the same time (USGenNE, 1999). Hogchoker was only sampled from 1979, but declined from 1.4 fish/tow from 1979 to 1984 to 0.28 fish/tow from 1985 to 1998 (USGenNE, 1999). Gibson (1996) states aggregate resource abundance declined significantly in Mount Hope Bay (Figure 2.6-1) and a reduction of species diversity occurred. Gibson (1996) correlates plant coolant flow with finfish abundance in the trawl surveys and shows a dramatic increase in coolant flow starting in 1984 coincides with the dramatic fish abundance decline in Mount Hope Bay (Figure 2.6-2). Gibson (1996) concludes that: “The most parsimonious hypothesis to explain the decline is that the large change in coolant flow has modified environmental conditions in Mt. Hope Bay to the detriment of the fish population.”

Subsequent analysis by Gibson (1996a) shows that the statistical fit between heat rejection from the plant (in trillions of British Thermal Units (BTUs)) and fish abundance is slightly better thanMA0003654 Determinations Document July 22, 2002

2-4 the fit for strictly coolant flow and fish abundance, though the statistical fit for both data sets is excellent (R 2 >0.85). This means that 85% of the variation of observed fish abundance could be explained by coolant flow or heat rejection. Coolant flow and heat rejection are linked and are both direct measures of plant operations. Thus, it would be surprising if they did not have similar statistical fits. While these analyses looked at coolant flow and heat rejection separately, EPA concludes that these two parameters most likely exert a combined effect on fish populations, along with other stressors.

Mark Gibson solicited comments on his report from numerous fishery biologists. EPA asked the Brayton Point TAC and several independent experts to also review the Gibson report. In general, the vast majority of reviewers agreed with the two main points of Gibson’s report: the fish populations in Mount Hope Bay had suffered a sudden and dramatic decline and the increased coolant flow at Brayton Point Station likely triggered this change. Gibson and large numbers of the reviewers point out that this analysis does not scientifically prove cause and effect. Establishing cause and effect in a true scientific fashion would require a complete shut down of the facility, a complete recovery of the fish stocks and then a controlled experiment of starting the plant up again and documenting a second decline. Obviously, this is not practical and other types of analyses have been used as surrogates.

The prior owners of Brayton Point Station (New England Power) did not initially acknowledge a decline in fish abundance in Mount Hope Bay. They attributed changes in fish abundance to sampling gear differences. After some debate, however, they changed their view and acknowledged the existence of a problem with the fish stocks. The current owners of Brayton Point Station (USGenNE) acknowledge the dramatic decline of fish abundance in Mount Hope Bay starting in 1984 (USGenNE, 2001). Thus, the existence of a problem with fish populations in Mount Hope Bay is no longer in debate.MA0003654 Determinations Document July 22, 2002



### 3.0 Permitting History

When considering development of a new NPDES permit for BPS, it is worthwhile to understand something of the facility’s permitting history. Units 1, 2 and 3 at BPS commenced commercial operation in 1963, 1964 and 1969, respectively. See “Variance Request Application and Partial Demonstration Under the Clean Water Act, Section 316(a) and (b)” dated May 24, 2001 (hereinafter, the “May 24, 2001, USGenNE Partial 316(a) and (b) Demonstration”); October 30, 1996 Fax from New England Power Company (stating operations commenced in 1962, 1963 and 1969, respectively). These units, therefore, pre-dated enactment of the CWA of 1972 and its thermal discharge and cooling water intake structure requirements. Units 1, 2 and 3 were constructed with once-through, open-cycle cooling systems and a single cooling water intake structure on the Taunton River.

After enactment of the CWA of 1972, an NPDES permit was required to authorize BPS’s continued discharge of pollutants and operation of a cooling water intake structure. The first NPDES permit was issued to the facility on October 9, 1973. Id .; NPDES Permit No. 0003654 (Oct. 9, 1973) (the “1973 Permit”). Due to concerns over potential impacts to the Mount HopeBay ecosystem, Unit 4, which was under construction, was required to be operated as a closedcycle unit. See Fact Sheet, Draft NPDES Permit No. 0003654, p. 12 (June 11, 1993). The 1973 Permit read as follows:

The circulating water system for the Brayton Point power generating station shall be designed so that unit four shall be operated with a closed cooling cycle, except for bleed-off discharge not to exceed 6,000 gallons per minute, which shall be routed through the discharge canal for the first three units.

This permit also restricted thermal discharges to a maximum temperature of 90° F and a change in temperature from intake to discharge ( ) -T) of 20° F. Further, the permit also imposed other conditions regarding the thermal plume, such as that “the thermal plume shall not block zones of passage ..., interfere with the spawning of fishes . . ., [or] change the balanced indigenous population of Mount Hope Bay or its tributary waters.” NPDES Permit No. 0003654, ConditionsI.B.3, 4, 5 and 7 (Oct. 9, 1973). The maximum temperature limit of 90° F and other temperaturerelated limitations were based on the Massachusetts Water Quality Standards and application of the maximum critical temperature for Atlantic menhaden. See 1973 Permit; February 25, 1976, Letter from Edward J. Conley, EPA, to John F. Kaslow, NEPCO; July 21, 1976, EPA/MA Division of Water Pollution Control “Notice of Determination to Modify a Joint Federal-State Permit” (Federal No. MA0003654, MA No. 41); Fact Sheet, Draft NPDES Permit No. 0003654, p. 11 (June 11, 1993). In addition to the requirement that Unit 4 operate with closed-cycle cooling, the permit provided as follows with respect to the already existing intake structure: “the circulating water intake structure shall employ the best technology available for minimizing the

3-1MA0003654 Determinations Document July 22, 2002 entrainment and entrapment of estuarine organisms into the cooling water system.” 1973 Permit, Condition I.A.4.

Since the original 1973 NPDES permit was issued for BPS, the permittee has pushed for a number of modifications to relax various permit requirements related to thermal discharges and cooling water intake structures. These requests have been the subject of substantial public controversy. See, e.g. , July 27, 1976, Letter from Eric D. Schneider, EPA Narragansett Laboratory, to John A.S. McGlennon, EPA Region 1; July 26, 1977, Letter from Charles Corkin II, Massachusetts Office of the Attorney General, to John Scanlon, Save the Bay (attaching “Agreement for Judgment” to be entered in Suffolk County Superior Court between NEPCO, the Commonwealth, EPA, Save the Bay, and Ecology Action for Rhode Island); July 2, 1976, Memorandum from Russell A. Isaac, MA DEP, to John R. Elwood, “Subject: Brayton Point ­ Permit Modification Hearing at Somerset High School on June 30, 1976.” While not all of the modifications requested by the permittee have been granted, among the most significant ones that were eventually granted and that are now reflected in the current NPDES permit are the following:

(1) in 1979, the maximum temperature limit was raised to 95° F and the ) -T limit was raised to 22° F; 1

1 The record shows that the permit’s maximum temperature and ) -T limits were alternately raised and then returned to the original limits in a series of permit modifications and agreements over the years from 1976 to 1979. See, e.g. , October 30, 1996, Fax from NEPCO to EPA (“Chronology of Brayton Point Station Operations” and “Circulating Water (S/N 001) ­ Permit Limitations”); NPDES Permit No. MA0003654, Modification No. 3, Issued to NEPCO for BPS (July 21, 1976); July 26, 1977, Letter from Charles Corkin II, Massachusetts Office of the Attorney General, to John Scanlon, Save the Bay (attaching “Agreement for Judgment” to be entered in Suffolk County Superior Court between NEPCO, the Commonwealth, EPA, Save the Bay, and Ecology Action for Rhode Island). The company argued that Atlantic menhaden and other fish would not be harmed by discharges up to and beyond 95° F. The permitting agencies eventually, in 1979, increased the maximum temperature limit to 95° F and the ) -T limit to 22° F, where they remain. See, e.g.
, October 30, 1996, Fax from NEPCO to EPA. The permitting agencies approved the higher temperature limits under a CWA § 316(a) variance, concluding that the limitations would not interfere with the protection and propagation of a balanced indigenous population of fish, shellfish and wildlife in and on the receiving water. Fact Sheet, Draft NPDES Permit No. 0003654, p. 11 (June 11, 1993). As discussed elsewhere in this document, the predicted extent of the thermal plume that would result from the variance-based permit conditions was significantly underestimated. In the Fact Sheet issued in 1993 with the current effective NPDES permit, EPA states that the company argued that in the summer, due to high ambient water temperatures, a requirement to meet the lower 90° F temperature limit would result

3-2MA0003654 Determinations Document July 22, 2002
(2) in 1982, Unit 4 was allowed to convert to open cycle operations with a new cooling water intake structure located on the Lee River and fitted with angled traveling screens intended to minimize fish impingement; 2

(3) in 1982, the maximum flow limitation in the permit was increased from 915.8 million gallons per day (MGD) in the 1973 permit to 1009 MGD; and

(4) in 1984, the maximum flow limitation was increased again to the current limit of 1452.5 MGD. 3

It should be noted that when the flow limit was increased to accommodate the conversion of Unit 4 from closed-cycle to open-cycle cooling, this also allowed BPS to discharge more heat (in BTUs) to Mount Hope Bay despite the maximum temperature and ) -T limitations remaining constant. In addition, the current permit condition related to the requirements of CWA § 316(b) states, in pertinent part, that “[i]t has been determined, based on engineering judgment that the circulating water intake structures presently employ the best technology available for minimizing adverse environmental impact.” NPDES Permit No. MA0003654, Condition I.A.1.e (June 16, 1993) (emphasis added).

In late 1996, controversy erupted again over thermal discharges and cooling water intake operations at BPS. This controversy arose out of scientific analyses by Mark Gibson, a fisheries

in “costly reduction in power generation and jeopardize those persons on life support equipment in the power distribution area.” Id . at p. 11. While the former point was likely true, the basis for the latter point is not fully explained and, in any event, it is highly unlikely that the latter point would remain true today given current energy supplies and markets.

2 The permittee pressed for permission to switch Unit 4 to open-cycle cooling because, among other reasons, it was having substantial operational problems with the “spray pod” system it had installed at BPS. See EPA “Determination Regarding Modification of NPDES Permit No. MA0003654 for Brayton Point Station, Somerset, Massachusetts” (October 1982) (the “October 1982 Modification Determination”), pp. 19-20. The company also argued that operation of its proposed alternative cooling water intake system would satisfy the requirements of CWA § 316(b). The regulatory agencies approved this request in the December 1982 permit reissuance, id ., and Unit 4 began operating on a once-through cooling basis in July 1984. See, e.g. , October 30, 1996 Fax from New England Power Company.

3 The maximum flow limit of 1452 MGD in the current permit represents the maximum flow that can be put through the plant. BPS has never reported actually using the full 1452 MGD of cooling water on an average basis, though it may do so intermittently on an instantaneous basis.

3-3MA0003654 Determinations Document July 22, 2002 biologist working for the State of Rhode Island, that indicated a dramatic decline in the health of Mount Hope Bay fish populations coinciding with the conversion of BPS Unit 4 to open-cycle cooling, with the associated increase in thermal discharges and cooling water use by the plant. This paper is discussed above in Section II (“Ecological Setting”). In a letter dated October 22, 1996, the Rhode Island Department of Environmental Management (RI DEM) wrote to EPA and asked that the Agency “expedite such permitting actions as are necessary in order to ensure that operational changes necessary to reverse unprecedented declines in Mount Hope Bay fisheries stocks are underway before the spawning season next spring.” October 22, 1996, Letter from Timothy Keeney, RI DEM, to John DeVillars, U.S. EPA. RI DEM argued that sufficient grounds existed to support either modification or revocation and reissuance of the permit. Id

. This controversy led to intensive negotiations between the regulatory agencies, the permittee, and a number of interested environmental organizations. While the parties ended up agreeing that there appeared to have been a decline in the health of the Mount Hope Bay fishery, the parties could not agree on the role, if any, that BPS operations played in that decline. In an effort to avoid litigation over possible permit modifications or enforcement actions, on February 6, 1997, EPA, the Massachusetts Department of Environmental Protection (MA DEP), the Massachusetts Executive Office of Environmental Affairs (MA EOEA), RI DEM, and the permittee, which at the time was the New England Power Company (NEPCO), entered a voluntary short-term Memorandum of Agreement (MOA I), which was later replaced by a long-term Memorandum of Agreement in early April 1997 (MOA II).

MOA II provides that BPS will abide by a new set of thermal discharge and cooling water volume restrictions. These limitations provide for various monthly and seasonal flow and thermal discharge restrictions that are more stringent than the limitations in the 1993 NPDES permit, which remains in effect. These limits are set forth in the text of MOA II, a copy of which is attached hereto as Appendix C. The limitations in MOA II represent a compromise among the parties intended to avoid litigation and represent an interim step for reducing or limiting the adverse environmental effects of BPS on the Mount Hope Bay ecosystem while careful evaluation proceeded for development of the next reissued permit. MOA II also proposed a plan of research to support development of the new NPDES permit following the scheduled July 1998 expiration of the 1993 Permit. Although the 1993 Permit technically expired in July 1998, it remains in effect until a new permit is issued due to the timely application for permit reissuance filed by the permittee. See 40 C.F.R. § 122.6. Finally, MOA II provided that it would also remain in effect until a new NPDES permit is issued and that any successor in interest to NEPCO at BPS would be required to abide by MOA II. Discharge monitoring reports filed by the permittee indicate that USGenNE has been complying with MOA II since it took over ownership and operations at the plant.

Thus, although Units 1, 2 and 3 have been in operation for nearly 40 years, and Unit 4 has been in operation for more than 25 years, there have been no substantial reductions in thermal discharge

3-4MA0003654 Determinations Document July 22, 2002 or cooling water intake system impacts over that time. Indeed, the company has petitioned for, and been granted, permit changes that have allowed major increases in thermal discharge and cooling water withdrawals during that time. (Of course, MOA II has provided some reductions in the peak levels of thermal discharge and cooling water use allowed by the 1993 Permit.) The permitting agencies now must review this permit in the context of the most recent information to determine the conditions that should be included in the new permit.

3-5MA0003654 Determinations Document July 22, 2002

1 See CWA §§ 301(b)(2) and 304(b)(2), 33 U.S.C. §§ 1321(b)(2) and 1324(b)(2).

2 See Appalachian Power Co. v. Train , 545 F.2d 1351 (4 th Cir. 1976) (EPA required to give further consideration to regulations concerning thermal backfit requirements representing degree of effluent reduction attainable by application of BAT, and barring use of new and existing cooling lakes for closed-cycle cooling).

Heat is defined as a “pollutant” under the CWA in CWA § 502(6), 33 U.S.C. § 1362(6).

3 See In the Matter of Public Service Co. of New Hampshire (Seabrook Station, Units 1 and 2) , NPDES Appeal No. 76-7, 1977 WL 22370, *6 (E.P.A.), 1 E.A.D. 332 (1977) (“The effect of the remand of the steam electric generating guidelines was ... to require the Agency to determine what is [BAT] for existing sources on a case-by-case basis under Section 402(a)(1).”); In Re Central Hudson Gas & Electric Corp. , Decision of General Counsel No. 63, EPA (Jul. 29, 1977), at 376 (after remand of effluent limitations and guidelines for steam electric power plants by Appalachian Power Co. , permit issuing authority could use CWA § 402(a)(1) to impose effluent limitations in permits for four steam electric generating stations discharging into Hudson River); Status of Initial Decision of Regional Administration Where Appeal is Pending , General Counsel Opinion, EPA (Jan. 11, 1977), EPA GCO 77-1, at 1 (“[i]n the wake of Appalachian Power, the Agency has the option of either establishing heat limitations for Seabrook on an ad hoc basis under Section 402(a)(1) of the [CWA] or repromulgating the steam electric regulations”).

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### 4.0 Technology-Based Thermal Discharge Limitations

4.1 Introduction

This section presents the basis for EPA’s establishment of thermal discharge limitations for BPS based on the Best Available Technology Economically Achievable (BAT), in accordance with CWA §§ 301(b)(2) and 304(b)(2). These sections of the Act govern the development and implementation of BAT effluent limits for toxic and non-conventional pollutants. 1 EPA issued regulations establishing national effluent limitations on the discharge of heat from point sources in the steam electric power generating category (such as BPS) in 1974, but those regulations were set aside by the United States Court of Appeals for the Fourth Circuit in 1976. 2 Therefore, EPA has developed the thermal discharge limitations contained in the new Draft NPDES permit for BPS based on Best Professional Judgment (BPJ) pursuant to CWA § 402(a)(1), 33 U.S.C. 1342(a)(1), and 40 C.F.R. § 125.3(c)(2). 3MA0003654 Determinations Document July 22, 2002

4 See CWA § 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B); 40 CFR § 125.3(d)(3).

5 PUD No. 1 of Jefferson County v. Washington Department of Ecology , 511 U.S. 700, 704 (1994).

4-2 CWA § 304(b)(2) and 40 CFR § 125.3(d)(3) require EPA to take the following factors into account in setting BAT limits: the age of the equipment and facilities involved; the manufacturing processes used; the engineering aspects of the application of recommended control technologies, including process changes and in-plant controls; non-water quality environmental impacts, including energy requirements; cost; and such other factors as EPA deems appropriate. 4 This section of this development document addresses these BAT-related factors as well as the 40 C.F.R. § 125.3 requirements for developing a BPJ based decision. Finally, this section sets forth the technology-based discharge limits that are mandated by the results of this BAT Determination.

4.2 Legal Requirements and Context

4.2.1 Overview

The regulations and case law governing EPA’s development and implementation of BAT limits under the CWA should be construed with Congress’s overarching statutory purposes in mind. As the United States Supreme Court has explained,

[t]he Federal Water Pollution Control Act, commonly known as the Clean Water Act, 86 Stat. 816, as amended, 33 U.S.C. § 1251 et seq., is a comprehensive water quality statute designed to “restore and maintain the chemical, physical, and biological integrity of the Nation’s waters.” § 1251(a). The Act also seeks to attain “water quality which provides for the protection and propagation of fish, shellfish, and wildlife.” § 1251(a)(2). 5

To accomplish these purposes, the CWA prohibits the discharge of pollutants to waters of the United States without a NPDES permit unless otherwise authorized. The NPDES permit is the mechanism used to implement effluent limitations and other requirements such as monitoring and reporting. When developing effluent limits for a NPDES permit, a permit writer must consider both limits based on the technology available to treat the pollutants (technology-basedlimits), and limits that are protective of the designated uses of the receiving water (water qualitybased limits).

With regard to technology-based limits, the CWA requires that all discharges at a minimum meet effluent limitations based on the technological capability of dischargers to control pollutants inMA0003654 Determinations Document July 22, 2002

6 See CWA § 301(b), 33 U.S.C. §1311(b); 40 C.F.R. 125.3(a). In addition, CWA § 306, 33 U.S.C. § 1316 requires new sources to meet performance standards based on Best Available Demonstrated Control Technology (BDT).

7 See CWA § 301(b)(2), 33 U.S.C. §1311(b)(2).

8 Permit limits are to be based on water quality standards or other requirements of state law if such limits would be more stringent. See CWA § 301(b)(1)(C), 33 U.S.C. § 1311(b)(1)(C).

9 See U.S. EPA Permit Writers’ Manual (EPA-833-B-96-003) ( Manual) at p. 70 (1996).

10 See 40 CFR Part 423.

4-3 their discharge. The Act directs EPA not merely to promulgate uniform national effluent limitation guidelines (ELGs) for categories of point sources discharging pollutants into waters of the United States, but progressively to institute more stringent effluent limits. For industrial dischargers, CWA § 301(b)(1)(A) required the application of Best Practicable Control Technology Currently Available (BPT) by July 1, 1977. Section 301(b)(2) requires industrial dischargers now to meet more stringent limits based on Best Conventional Pollutant Control Technology (BCT) for conventional pollutants and BAT for toxic and non-conventional pollutants. 6

Particularly, industrial dischargers were required to meet a March 31, 1989 deadline for complying with BAT limits “which will result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants.” 7

The purpose of setting technology-based effluent limits for industrial dischargers is to establish a minimum level of treatment based on currently available technologies while allowing the use of any available control technique to meet the limits, and thereby fostering the required “reasonable further progress toward the national goal of eliminating the discharge of all pollutants.” 8There are two approaches to developing technology-based limits for industrial dischargers: (1) using EPA-promulgated ELGs, and (2) in the absence of ELGs, applying the permit writer’s BPJ on a case-by-case basis. EPA develops ELGs based on the effluent reduction capabilities of identified treatment methods that meet the particular technology standard being applied ( i.e. , BPT, BCT, BAT or BDT) for specific categories of industrial facilities on a nationwide basis. Under CWA § 402(a)(1), permit writers using BPJ apply the same performance-based approach to specific industrial facilities. 9

For the BPS NPDES permit, EPA has developed a technology-based limit for thermal discharges using BPJ because there are no ELG’s for thermal discharges from facilities in the steam electric power generating point source category. 10 Therefore, the discussion below focuses on settingMA0003654 Determinations Document July 22, 2002

11 See 40 C.F.R. § 125.3. See also NRDC v. EPA , 863 F.2d 1420, 1424-25 (9 th Cir. 1988) (environmental group challenge to general permit containing BPJ-based BAT limits for offshore oil and gas drilling industry point sources in Gulf of Mexico); American Petroleum Inst. v. EPA , 787 F.2d 965, 971-72 (5 th Cir. 1986) (industry challenge to two general permits containing BPJ-based BAT limits for offshore oil and gas drilling industry point sources discharging to Alaskan Outer Continental Shelf). See also In re: City of Port St. Joe and Florida Coast Paper Co. , NPDES Appeal Nos. 94-8 and 94-9, 1997 EPA App. LEXIS 12 (1997) (city and discharger petition for review of NPDES permit for city publicly owned treatment works); In the Matter of: Rubicon Inc. , NPDES Appeal No. 85-10, 1988 EPA App. LEXIS 30, 2 E.A.D. 551 (1988) (discharger petition for review regarding denial of request for evidentiary hearing on NPDES permit); In the Matter of AT&T Teletype Corp. , NPDES Appeal No. 85-18, 1986 EPA App. LEXIS 20, 2. E.A.D. 167 (1986) (discharger petition for review regarding denial of request for evidentiary hearing on NPDES permit).

12 NRDC v. EPA , 859 F.2d 156, 199 (D.C. Cir. 1988) (industry and environmental group challenge to 1979 revisions to NPDES regulations, including ban on backsliding from BPJ limits). This court explained,

[i]n what EPA characterizes as a ‘mini-guideline’ process, the permit writer, after full consideration of the factors set forth in section 304(b), 33 U.S.C. § 1314(b), (which are the same factors used in establishing effluent guidelines), establishes the permit conditions ‘necessary to carry out the provisions of [the CWA].’ § 1342(a)(1). These conditions include the appropriate ... BAT effluent limitations for the particular point source. ... [T]he resultant BPJ limitations are as correct and as statutorily supported as permit limits based upon an effluent limitations guideline.

Id. See also Texas Oil & Gas Ass’n v. EPA , 161 F.3d 923, 929 (5 th Cir. 1998) (industry challenge to EPA regulations implementing BPJ-based BAT limits for coastal oil and gas extraction point sources) (“Individual judgments thus take the place of uniform national guidelines, but the technology-based standard remains the same.”).

4-4 technology standards using BPJ.

4.2.2 Best Professional Judgment-Based Effluent Limits

The courts have repeatedly affirmed EPA’s authority to set BAT limits on a case-by-case basis using BPJ. 11 According to one court, such “BPJ limits constitute case-specific determinations of the appropriate technology-based limitations for a particular point source.” 12MA0003654 Determinations Document July 22, 2002

13 CWA § 402(a)(1), 33 U.S.C. 1342(a)(1).

14 See
, e.g. , American Mining Congress v. EPA , 965 F.2d 759, 762 n.3 (9 th Cir. 1992) (“When EPA has not yet issued national effluent guidelines for a category of point sources, the Agency is authorized under CWA § 402(a)(1), 33 U.S.C. § 1342(a)(1), to develop such limitations in an NPDES permit on a case-by-case basis.”) (challenge to stormwater discharge rule), citing NRDC v. Costle , 568 F.2d 1369, 1378-79 (D.C. Cir. 1977); NRDC v. EPA , 859 F.2d at 195 (BPJ limits are “technology-based limitations set, in the absence of a national guideline, according to a permit writer’s best professional judgment, pursuant to § 402(a)(2) of the CWA”); NRDC v. EPA , 822 F.2d 104, 111 (D.C. Cir. 1987) (“If no national standards have been promulgated for a particular category of point sources, the permit writer is authorized to use, on a case-by-case basis, ‘best professional judgment’ to impose ‘such conditions as the permit writer determines are necessary to carry out the provisions of [the Clean Water Act.]”) (citations omitted) (related case regarding industry and environmental group challenge to 1979 revisions to NPDES regulations); American Petroleum Inst. , 787 F.2d at 969 (“Where EPA has not promulgated applicable technology-based effluent limitations guidelines, the permits must incorporate, on a case-by-case method, ‘such conditions as the Administrator determines are necessary to carry out the provisions of the Act.’”) (citations omitted).

15 40 C.F.R. § 125.3(c)(3); Manual at p. 69.

16 See Note 1 and accompanying text.

4-5 EPA’s ability to set permit limits on a case-by-case basis using BPJ is provided by CWA § 402(a)(1), which authorizes the Agency to

issue a permit for the discharge of any pollutant, or combination of pollutants ... upon condition that such discharge will meet either (A) all applicable requirements under sections 1311, 1312, 1316, 1317, 1318, and 1343 of this title, or (B) prior to the taking of necessary implementing actions relating to all such requirements, such conditions as the Administrator determines are necessary to carry out the provisions of this chapter. 13

EPA and the courts have interpreted § 402(a)(1) as allowing the imposition of effluent limits on a case-by-case basis using BPJ where EPA has not yet promulgated ELGs for a particular category of point sources. 14

BPJ limits are also appropriate where ELGs are available for a point source category but do not regulate a particular pollutant of concern discharged by an individual point source in that category. 15Here, 40 C.F.R. Part 423 provides effluent limitations for certain pollutants discharged by the steam electric power generating point source category, but not for heat. 16 Therefore, EPA may use BPJ to set BAT limits for thermal discharges from individualMA0003654 Determinations Document July 22, 2002

17 See In the Matter of Public Service Co. of New Hampshire (Seabrook Station, Units 1 and 2) , NPDES Appeal No. 76-7, 1977 WL 22370, *6 (E.P.A.), 1 E.A.D. 332 (1977); In Re Central Hudson Gas & Electric Corp. , Decision of General Counsel No. 63, EPA (Jul. 29, 1977), at 376; Status of Initial Decision of Regional Administration Where Appeal is Pending
, General Counsel Opinion, EPA (Jan. 11, 1977), EPA GCO 77-1, at 1.

18 CWA § 301(b)(2), 33 U.S.C. § 1311(b)(2) (emphasis added).

19 See CWA §§ 301(b)(2)(A), 304(b)(2)(B), 33 U.S.C. §§ 1311(b)(2)(A), 1314(b)(2)(B). See also BP Exploration & Oil, Inc. v. EPA , 66 F.3d 784, 790 (6 th Cir. 1995) (“Compared to BPT, BAT calls for more stringent control technology that is both technologically available and economically achievable.”); Rybachek v. EPA , 904 F.2d 1276, 1290 (9 th Cir. 1990) (“By definition, BAT limitations must be both technologically available and economically achievable.”) (industry challenge to EPA regulations implementing BAT limits for placer mining point sources); NRDC v. EPA , 863 F.2d at 1426 (“Technology-based limitations under BAT must be both technologically available and economically achievable.”).

4-6 facilities in the steam electric power generating category, which includes BPS. 17

4.2.3 Best Available Technology Economically Achievable-Based Limits

For toxic pollutants and for non-conventional pollutants such as heat, the CWA requires the achievement of

effluent limitations for categories and classes of point sources, other than publicly owned treatment works, which ... shall require application of the best available technology economically achievable for such category or class, which will result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants , as determined in accordance with regulations issued by the [EPA] Administrator pursuant to [CWA § 304(b)(2),] section 1314(b)(2) of this title, which such effluent limitations shall require the elimination of discharges of all pollutants if the Administrator finds, on the basis of information available to him ... that such elimination is technologically and economically achievable for a category or class of point sources as determined in accordance with regulations issued by the [EPA] Administrator pursuant to [CWA § 304(b)(2),] section 1314(b)(2) of this title .... 18

That is, EPA must set limits that represent a minimum level of treatment based on technologies that are technologically available and economically achievable, and that will result in reasonable progress toward the elimination of the discharge of such pollutants. 19MA0003654 Determinations Document July 22, 2002

20 CWA § 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B). See also 40 C.F.R. § 125.3(d)(3).

21 BP Exploration & Oil, Inc. , 66 F.3d at 796, citing Weyerhauser v. Costle , 590 F.2d 1011, 1045 (D.C. Cir. 1978) (citing Senator Muskie’s remarks on CWA § 304(b)(1) factors during debate on CWA). See also EPA v. Nat’l Crushed Stone Ass’n , 449 U.S. 64, 74, 101 S.Ct. 295, 300, 66 L.Ed.2d 268 (1980) (noting with regard to BPT that “[s]imilar directions are given the Administrator for determining effluent reductions attainable from the BAT except that in assessing BAT total cost is no longer to be considered in comparison to effluent reduction benefits”) (industry challenge to EPA regulations implementing BAT limits for point sources in coal mining industry and certain portions of mineral mining and processing industry).

22 Weyerhauser v. Costle , 590 F.2d at 1045 (explaining that CWA § 304(b)(2) lists factors for EPA “consideration” in setting BAT limits, while CWA § 304(b)(1) lists both factors for EPA consideration and factors for EPA “comparison” -- “total cost versus effluent reduction benefits” -- in setting BPT limits).

23 BP Exploration & Oil, Inc. , 66 F.3d at 796, citing Weyerhauser v. Costle , 590 F.2d at 1045.

24 Id. , 66 F.3d at 796, citing American Iron & Steel Inst. v. EPA , 526 F.2d 1027, 1051 (1975), modified in other part , 560 F.2d 589 (3d Cir. 1977), cert. denied , 435 U.S. 914, 98 S.Ct. 1467, 55 L.Ed.2d 505 (1978) (industry challenge to EPA regulations implementing BAT limits for iron and steel industry point sources).

4-7 The CWA requires EPA to “take into account” the following factors when setting BAT limits for a particular point source category or individual discharger:

the age of the equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduction, non-water quality environmental impact (including energy requirements), and such other factors as the Administrator deems appropriate. 20

The statute sets up a loose framework for assessing these factors in setting BAT limits. 21 It does not require their comparison, merely their consideration. 22 Moreover, “[i]n enacting the CWA, ‘Congress did not mandate any particular structure or weight for the many consideration factors. Rather, it left EPA with discretion to decide how to account for the consideration factors, and how much weight to give each factor.’” 23 In sum, when EPA considers the BAT factors in setting BAT limits, it is governed by a standard of reasonableness. 24 It must consider each factor, but it has “considerable discretion in evaluating the relevant factors and determining the weight to beMA0003654 Determinations Document July 22, 2002

25 Texas Oil & Gas Ass’n , 161 F.3d at 928, citing NRDC v. EPA , 863 F.2d at 1426. See also Weyerhauser , 590 F.2d at 1045 (discussing EPA’s discretion in assessing BAT factors, court noted that “[s]o long as EPA pays some attention to the congressionally specified factors, the section [304(b)(2)] on its face lets EPA relate the various factors as it deems necessary”).

Historically, certain factors, such as age, process employed and non-water quality impacts, have assumed lesser importance than the technical and economic feasibility evaluations. Manual at 71.

26 Ass’n of Pacific Fisheries v. EPA , 615 F.2d 794, 818 (9 th Cir. 1980) (industry challenge to EPA regulations implementing BAT limits for seafood processing industry point sources). See also Chemical Manufacturers Ass’n (CMA) v. EPA , 870 F.2d 177, 250 n.320 (5 th Cir. 1989), citingCongressional Research Service, A Legislative History of the Water Pollution Control Act Amendments of 1972 at 170 (1973) (hereinafter “ 1972 Legislative History ”) (in determining BAT, “‘[t]he Administrator will be bound by a test of reasonableness.’”) (industry challenge to EPA regulations implementing BAT limits for organic chemicals, plastics and synthetic fibers industry point sources); NRDC v. EPA , 863 F.2d at 1426 (same); American Iron & Steel Inst. , 526 F.2d at 1051 (same).

27 40 C.F.R. § 125.3(c)(2). See also NRDC v. EPA , 863 F.2d at 1425 (“in issuing permits on a case-by-case basis using its ‘Best Professional Judgment,’ EPA does not have unlimited discretion in establishing permit limitations. EPA’s own regulations implementing [CWA § 402(a)(1)] enumerate the statutory factors that must be considered in writing permits.”).

The Manual

states that BPJ “means the highest quality technical opinion that the permit writer can develop after considering all reasonably available and pertinent data or information forming the basis for the terms and conditions of a NPDES permit.” Manual at p. 68.

4-8 accorded to each in reaching its ultimate BAT determination.” 25One court has succinctly summarized the standard for measuring EPA’s consideration of the BAT factors in setting BAT limits: “[s]o long as the required technology reduces the discharge of pollutants, our inquiry will be limited to whether the Agency considered the cost of technology, along with other statutory factors, and whether its conclusion is reasonable.” 26

When imposing BAT limits using BPJ under § 402(a)(1), a permit writer is required to apply both the statutory BAT factors and the factors specified in 40 C.F.R. § 125.3(d)(3), and to consider both the “appropriate technology for the category of point sources of which the applicant is a member, based on all available information,” and “any unique factors relating to the applicant.” 27 The 40 C.F.R. § 125.3(d)(3) factors are the age of the equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process change, the cost of achieving such effluent reduction, and non-water qualityMA0003654 Determinations Document July 22, 2002

28 40 C.F.R. § 125.3.(d)(3). Compare CWA § 304(b), 33 U.S.C. §1314(b).

29 E.g.
, Texas Oil & Gas Ass’n , 161 F.3d at 929 (under 40 C.F.R. § 125.3, “EPA must determine on a case-by-case basis what effluent limitations represent the BAT level, using its ‘best professional judgment.’ Individual judgments thus take the place of uniform national guidelines, but the technology-based standard remains the same.”) (citation omitted); NRDC v. EPA , 859 F.2d at 201(‘in establishing BPJ limits, EPA considers the same statutory factors used to establish national effluent guidelines. BPJ limits thus represent the level of technology control mandated by the CWA for the particular point source.”); Trustees for Alaska v. EPA , 749 F.2d 549, 553 (9 th

Cir. 1984) (EPA must consider statutorily enumerated factors in its BPJ determination of effluent limits); Manual at p. 70. See also NRDC v. EPA , 863 F.2d at 1425 (“courts reviewing permits issued on a BPJ basis hold EPA to the same factors that must be considered in establishing the national effluent limitations”) (citations omitted).

30 CMA v. EPA , 870 F.2d at 239, citing 1972 Legislative History at 170. See also Texas Oil & Gas Ass’n , 161 F.3d at 928, quoting CMA v. EPA , 870 F.2d at 226; Kennecott v. EPA , 780 F.2d 445, 448 (4 th Cir. 1985) (industry challenge to EPA regulations implementing BAT limits for nonferrous metals manufacturing industry point sources) (“In setting BAT, EPA uses not the average plant, but the optimally operating plant, the pilot plant which acts as a beacon to show what is possible.”); American Meat Inst. v. EPA , 526 F.2d 442, 463 (7 th Cir. 1975)(industry challenge to EPA regulations implementing BAT limits for meat products industry point sources) (BAT “should, at a minimum, be established with reference to the best performer in any industrial category”). According to one court,

[t]he legislative history of the 1983 regulations indicates that regulations establishing BEA [ i.e. , best available technology economically achievable, or BAT] can be based on statistics from a single plant. The House Report states:

It will be sufficient for the purposes of setting the level of control under available technology, that there be one operating facility

4-9 environmental impact (including energy requirements). 28These are the same exact factors used to establish nationwide BAT limits ( i.e. , BAT ELGs) under CWA §§ 301(b)(2) and 304(b)(2). Moreover, as noted above, the permit writer using BPJ to develop BAT limits applies the same performance-based approach to each individual point source that EPA applies to categories and classes of point sources when it develops ELGs. 29

4.2.3a Technological Availability

According to the CWA’s legislative history, “best available” technology refers to the “single best performing plant in an industrial field.” 30 Thus, EPA may set BAT limits that are notMA0003654 Determinations Document July 22, 2002

which demonstrates that the level can be achieved or that there issufficient information and data from a relevant pilot plant or semiworks plant to provide the needed economic and technical justification for such new source.

Ass’n of Pacific Fisheries , 615 F.2d at 816-17, quoting 1972 Legislative History at 170.

31 CMA v. EPA , 870 F.2d at 239, 240.

32 Kennecott , 780 F.2d at 448, citing 1972 Legislative History at 798. See also NRDC v. EPA , 863 F.2d at 1431 (“The BAT standard must establish effluent limitations that utilize the latest technology”).

33 These determinations, arising out of the CWA’s legislative history, have been upheld by the courts. E.g.
, American Petroleum Inst. v. EPA , 858 F.2d 261, 264-65 (5 th Cir. 1988) (challenge to two general permits containing BPJ-based BAT and BAT-level limits for offshore oil and gas drilling industry point sources discharging to Alaskan Outer Continental Shelf); Ass’n of Pacific Fisheries , 615 F.2d at 816-17; BASF Wyandotte Corp. v. Costle , 614 F.2d 21, 22 (1 st Cir. 1980) (industry challenge to EPA regulations implementing BAT limits for organic pesticide industry point sources); American Iron and Steel Inst. , 526 F.2d at 1061; American Meat Inst.
, 526 F.2d at 462

.

See also Kennecott v. EPA , 780 F.2d at 453, citing Reynolds Metals v. EPA , 760 F.2d 549, 562 (4 th

Cir. 1985) (“Congress contemplated that EPA might use technology from other industries to establish the Best Available Technology.”). The Kennecottcourt provides the test for determining whether a technology from one industry may be applied to another industry. See 780 F.2d at 453, citing Tanners’ Council of America, Inc. v. Train , 540 F.2d 1188, 1192 (4 th Cir. 1976).

4-10 technologically achievable by all of the dischargers in a particular point source category, as long as one discharger in the category demonstrates that the limits are achievable. 31 This comports with Congress’s intention that EPA “use the latest scientific research and technology in setting effluent limits, pushing industries toward the goal of zero discharge as quickly as possible.” 32

EPA has determined that “available” technologies include any viable “transfer technologies” (that is, technology from another industry that could be transferred to the industry in question), as well as technologies that have been shown to be viable in research even if not yet implemented at a full-scale facility. 33 When EPA bases BAT limits on such “model” technologies, it is not required to “consider the temporal availability of the model technology to individual plants,” because the BAT factors do not include consideration of an individual plant’s lead time for obtaining andMA0003654 Determinations Document July 22, 2002

34 See CMA v. EPA , 870 F.2d at 243; American Meat Inst. , 526 F.2d at 451.

35 See CMA v. EPA , 870 F.2d at 241.

36 CMA v. EPA , 870 F.2d at 241.

37 BP Exploration & Oil, Inc. , 66 F.3d at 794 (where petitioners challenged technological achievability of BAT limits for produced water discharged by offshore oil and gas extraction facilities on grounds that technology that EPA identified as BAT, improved gas flotation, removes only dispersed oil from produced water, court upheld BAT limits because EPA relied on “empirical data” presented in studies demonstrating that improved gas flotation is effective technique for removing dissolved as well as dispersed oil from produced water). Compare Ass’n of Pacific Fisheries , 615 F.2d at 819 (in challenge to EPA regulations implementing BAT limits for seafood processing industry point sources, regulations remanded because EPA based BAT limit on study that failed to demonstrate effectiveness of technology identified as BAT).

38 See American Iron & Steel Inst. , 526 F.2d at 1048.

4-11 installing the technology. 34

EPA must articulate the reasons for its determination that the technology it has identified as BAT is technologically achievable. Courts have construed the CWA as not requiring EPA to identify the specific technology or technologies a plant must install to meet BAT limits. 35The Agency must nonetheless demonstrate that the technology used to estimate BAT limit costs is a “reasonable approximation of the type and cost of technology that must be used to meet the limitations.” 36

It may do this by several methods, including relying on a study that demonstrates the effectiveness of the required technology. 37

Age of Equipment and Facilities Involved. Among the BAT factors that EPA must consider in developing BAT limits are the age of the equipment and facility or facilities involved. Age by itself is not relevant to the type of treatment technology to be installed to achieve BAT limits. The type of treatment technology to be applied is primarily a function of the pollutants present in a facility’s effluent and thus is a function of the type of operation conducted, not the facility’s age. However, age does have a bearing on the cost and feasibility of retrofitting existing plants to meet BAT limits. 38As one court explained,

[w]hile all the plants in a certain older subcategory ... may require the same technological processes to reduce effluent discharges, the fact that all the plants within that subcategory were built long before plants in another subcategory may present special problems in installing anti-pollution devices. Similarly, in aMA0003654 Determinations Document July 22, 2002

39 Id.

40 Id.

41 Texas Oil & Gas Ass’n , 161 F.3d at 935. This holds true for all of the BAT factors. Id.

42 Id.

4-12 subcategory where there is considerable variation in age, the fact that processes are similar may mean that the same type of control technology can be installed, but it does not necessarily mean that the ease with which that technology can be installed, or the ability to comply with effluent limitations once it has been installed, is not affected by age. 39

In that case, the court remanded EPA regulations implementing BAT limits for iron and steel point sources on the grounds that the Agency had failed to consider the BAT factor of age as it affected the cost and feasibility of retrofitting certain older steel mills to meet the BAT limits. 40

When considering the age factor under CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3(d)(3), EPA may proceed on the basis of “‘imperfect’ information ... unless ‘there is simply no rational relationship’ between the means used to account for any imperfections and the situation to which those means are applied.” 41 For example, the Agency properly designated reinjection as BAT for produced water generated by coastal oil and gas drilling facilities even though it had excluded pre-1980 oil and gas wells from its CWA § 308 survey of known coastal operators, on which it relied heavily in its economic impact analysis, because its extrapolation of data from the survey to estimate the economic impacts on pre-1980 facilities was reasonable. More particularly, to support this extrapolation of data, EPA determined that the only relevant distinction between pre-1980 and post-1980 wells was that pre-1980 wells were primarily “marginal producers” ( i.e. , they produced ten barrels a day or less), pre-1980 marginal producers did not differ significantly from post-1980 marginal producers, and post-1980 marginal producers were well-represented in the survey. 42

In sum, to set a BPJ-based BAT limit for thermal discharges from BPS in accordance with CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3(d)(3), EPA considered the age of the electric power generation units comprising the facility and their cooling system components as it had a bearing on both the costs of retrofitting one or more those units with the available treatment technologies that the Agency was evaluating as BAT, and the feasibility of such retrofitting.

Process Employed/Engineering Aspects of the Application of Various Types of Control Techniques/Process Changes. The factors that EPA must consider in developing BAT limitsMA0003654 Determinations Document July 22, 2002

43 Id. at 928, citing NRDC v. EPA , 863 F.2d at 1426. See also Kennecott v. EPA
, 780 F.2d at 448, citingCWA § 304(b)(2), 33.U.S.C. § 1314(b)(2).

44 BP Exploration & Oil, Inc. v. EPA , 66 F.3d at 796 (in establishing BAT limits for produced waters discharged by offshore oil and gas extraction facilities, EPA did not improperly weigh BAT factors in determining that while reinjection may be technologically feasible, “loss of production resulting from reinjection,” in combination with high cost and adverse environmental impacts, was valid basis for rejecting reinjection as BAT).

45 Texas Oil & Gas Ass’n , 161 F.3d at 928. See also CWA § 301(b)(2), 33 U.S.C. § 1311(b)(2) (BAT limits “shall require the elimination of discharges of all pollutants if the Administrator finds, on the basis of information available to him ... that such elimination is ... economically achievable”); CWA § 304(b)(2), 33 U.S.C. § 1314(b)(2) (when assessing BAT for particular point source category or individual discharger, EPA must take “cost of achieving such effluent reduction” into account); 40 C.F.R. § 125.3(d)(3) (same).

4-13 also include the process or processes employed by the point source category or subcategory or the individual discharger for which the BAT limits are being developed; engineering aspects of the treatment technologies that are being evaluated as BAT; and the changes to the point source process or processes that will result from application of the treatment technology in question.

As noted above, EPA has “considerable discretion in evaluating the relevant factors and determining the weight to be accorded to each in reaching its ultimate BAT determination.” 43 For example, the Agency can determine that the use of a particular technology is feasible and will achieve a level of effluent reduction, but that the technology cannot be designated as BAT in part because its use will result in a significant loss in production. 44

In setting the BPJ-based BAT limit for thermal discharges from BPS, EPA considered the steam electric power generation processes currently employed by BPS; engineering concerns relating to the application of the treatment technologies evaluated as BAT to these processes; and the types of process changes that would result. These factors are related to the age factor discussed above insofar as they relate to the feasibility of retrofitting the existing facility to achieve BAT.

4.2.3b Economic Achievability

CWA §§ 301(b)(2) and 304(b)(2) require “EPA to set discharge limits that reflect the amount of pollutant that would be discharged by a point source employing the best available technology that the EPA determines to be economically feasible ....” 45The United States Supreme Court has read these sections to mean that BAT should “represent ‘a commitment of the maximumMA0003654 Determinations Document July 22, 2002

46 Nat’l Crushed Stone Ass’n , 449 U.S. 64, 74, 101 S.Ct. at 302, 66 L.Ed.2d 268. See also BP Exploration & Oil, Inc. , 66 F.3d at 790 (“BAT represents, at a minimum, the best economically achievable performance in the industrial category or subcategory.”), citing NRDC
, 863 F.2d at 1426 (citing Nat’l Crushed Stone Ass’n ).

47 NRDC v. EPA , 863 F.2d at 1426, citing American Iron & Steel Inst. , 526 F.2d at 1052.

48 BP Exploration & Oil, Inc. , 66 F.3d at 803. This court stated that

[a]ccording to EPA, the CWA not only gives the agency broad discretion in determining BAT, the Act merely requires the agency to consider whether the cost of the technology is reasonable. EPA is correct that the CWA does not require a precise calculation of BAT costs.

Id.
, citing NRDC v. EPA , 863 F.2d at 1426.

49 NRDC v. EPA , 863 F.2d at 1426. See also Rybachek , 904 F.2d at 1290-91 (citing NRDC v. EPA ); CMA v. EPA , 870 F.2d at 237-38 (same).

Among the costs EPA may consider are the costs of BAT compliance and their economic impact. This may include estimating plant production and capacity and computing probable revenues, and then comparing compliance costs to revenues; or calculating changes in cost of production, increase in price and changes in return on investment, and then comparing compliance investment costs to average capital expenditures. E.g.
, Kennecott , 780 F.2d at 456- 57. It also may include estimating the costs of construction, labor, power, chemicals and fuel needed to build and operate a new treatment system. E.g.
, Ass’n of Pacific Fisheries , 615 F.2d at 818. Where appropriate, EPA may analyze the cost of acquiring and clearing land required to build treatment systems, but it is not required to do so when developing ELGs, in part because these costs can be considered site-specific. E.g.
, CMA v. EPA , 870 F.2d at 241-242; Ass’n of Pacific Fisheries , 615 F.2d at 818, 819-20; American Iron & Steel Inst. , 526 F.2d at 1053.

4-14 resources economically possible to the ultimate goal of eliminating all polluting discharges.” 46

The Act gives EPA “considerable discretion” in determining what is economically achievable. 47It does not require a precise calculation of the costs of complying with BAT limits. 48Rather, EPA “need make only a reasonable cost estimate in setting BAT,” meaning that it must “develop no more than a rough idea of the costs the industry would incur.” 49Moreover, CWA § 301(b)(2) does not specify any special method of evaluating the costs of compliance with BAT limits or state how those costs should be considered in relation to the other BAT factors. It only directs EPA to consider whether the costs associated with pollutant reduction are “economicallyMA0003654 Determinations Document July 22, 2002

50 CMA v. EPA , 870 F.2d at 250, citingCWA § 301(b)(2)(A), 33 U.S.C. § 1311(b)(2)(A).

51 See CWA § 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B). See also Reynolds Metals Co. , 760 F.2d at 565 (in setting BAT limits, “no balancing is required -- only that costs be considered along with the other factors discussed previously”), citing Nat’l Ass’n Metal Finishers v. EPA , 719 F.2d 624, 662-63 (3 rd Cir. 1983); Ass’n of Pacific Fisheries , 615 F.2d at 818 (in setting BAT limits, “the EPA must ‘take into account ... the cost of achieving such effluent reduction,’ along with various other factors. Section 304(b)(2)(B).”).

Stated differently, rather than invalidate effluent limitations on the basis of cost alone, courts should look to determine whether EPA has properly weighed all of the BAT factors in setting BAT limits for a particular point source category or point source. See CMA v. EPA
, 870 F.2d at 252 (“In light of Congress’ judgment that society must bear such costs as the price of achieving the long-term benefits of eliminating pollutants from our nation’s waters, courts have been exceedingly reluctant to invalidate environmental regulations on grounds of cost ....”). See also BP Exploration & Oil, Inc. , 66 F.3d at 796 (in establishing BAT limits for produced waters discharged by offshore oil and gas extraction facilities, EPA did not improperly weigh BAT factors in determining that reinjection may be technologically feasible, but “extraordinary cost” of implementation, in combination with resulting loss of production and adverse environmental impacts, was valid basis for rejecting reinjection as BAT).

52 E.g.
, Nat’l Crushed Stone Ass’n , 449 U.S. 64, 101 S.Ct. at 300, 66 L.Ed.2d 268 (“Similar directions [to those for assessing BPT under CWA § 304(b)(1)(B)] are given the Administrator for determining effluent reductions attainable from the BAT except that in assessing BAT total cost is no longer to be considered in comparison to effluent reduction benefits.”) (footnote omitted); Texas Oil & Gas Ass’n , 161 F.3d at 936 n.9 (petitioners asked court “to reverse years of precedent and to hold that the clear language of the CWA (specifically, 33 U.S.C. § 1314(b)(2)(B)) requires the EPA to perform a cost-benefit analysis in determining BAT. We find nothing in the language or history of the CWA that compels such a result”).

4-15 achievable.” 50

Similarly, CWA § 304(b)(2)(B) only requires EPA to “take into account” the costs of BAT along with the other BAT factors. 51

Courts including the United States Supreme Court have consistently read the statute and its legislative history as indicating Congress’s intention that while EPA should consider costs in setting BAT limits, it is not required to perform a cost-benefit analysis or any other type of balancing test. 52

More than one court has pointed to the 1972 House-Senate conference report for the Act, which states that

[w]hile cost should be a factor in the Administrator’s judgment, no balancing testMA0003654 Determinations Document July 22, 2002

53 E.g.
, Ass’n of Pacific Fisheries , 615 F.2d at 817, quoting1972 Leg. Hist. at 170; CMA v. EPA , 870 F.2d at 250 n.320 (same); NRDC v. EPA , 863 F.2d at 1426 (same); American Iron & Steel Inst. , 526 F.2d at 1051-52 (same).

In addition, more than one court has compared EPA’s assessment of cost in setting BAT limits with its assessment of cost in setting BPT limits, and concluded that while setting BPT limits involves a limited comparison of technology costs and effluent reduction benefits, setting BAT limits involves even less. E.g.
, American Iron & Steel Institute , 526 F.2d at 1051. As the American Iron & Steel Institute court explained, “for ‘BATEA’ [ i.e. , BAT] standards, cost was to be less important than for the ‘BPCTCA’ [ i.e. , BPT] standards, and that for even the ‘BPCTCA’ standards, cost was not to be given primary importance.” 526 F.2d at 1052 n.51.

54 Appalachian Power Co. , 545 F.2d at 1361, citingCWA § 301(b)(2)(A), 33 U.S.C. § 1311(b)(2)(A).

4-16 will be required. The Administrator will be bound by a test of reasonableness. In this case, the reasonableness of what is ‘economically achievable’ should reflect an evaluation of what needs to be done to move toward the elimination of the discharge of pollutants and what is achievable through the application of available technology – without regard to cost. 53

One federal appeals court has nonetheless held that in setting BAT limits, EPA must compare the cost of a particular technology to the non-monetary environmental benefits of using that technology to determine whether the technology’s cost is “reasonable.” In remanding the ELGs that EPA had promulgated for the steam electric power generating point source category in 1974, the Fourth Circuit in Appalachian Power Co. rejected the petitioners’ contention that under CWA §§ 301(b)(2) or 304(b)(2), “benefits derived from a particular level of effluent reduction must be quantified in monetary terms.” It found, however, that

[n]evertheless, EPA is under a statutory duty to determine whether, in fact, its regulations for 1983 will ‘result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants ....’ 33 U.S.C. s 1311(b)(2)(A). Accordingly, the agency must consider the benefits derived from the application of its effluent reduction requirements in relation to the associated costs in order to determine whether, in fact, the resulting progress is ‘economically achievable,’ and whether the progress is ‘reasonable.’ 54

Subsequently, two other federal appeals courts – the Fifth and the Ninth Circuits – have referred
to Appalachian Power Co. for support in dicta questioning the reach of the “reasonableness” testMA0003654 Determinations Document July 22, 2002

55 Ass’n of Pacific Fisheries , 615 F.2d at 818 (“at some point extremely costly more refined treatment will have a de minimis effect on the receiving waters”); American Petroleum Inst. , 787 F.2d at 972 (“Indeed, EPA would disserve its mandate were it to tilt at windmills by imposing BAT limitations which removed de minimis amounts of polluting agents from our nation’s waters, while imposing possibly disabling costs upon the regulated industry.”).

56 See Ass’n of Pacific Fisheries , 615 F.2d at 817 (citing 1972 House-Senate conference report language regarding “test of reasonableness,” court held that “EPA must consider the economic consequences of the 1983 regulations, along with the other factors mentioned in section 304(b)(2)(B),” but that “the language of the statute indicates that the EPA’s consideration of costs in determining BPT and BEA [ i.e. , BAT] was to be different,” and that “[t]he conspicuous absence [in CWA § 304(b)(2)(B)] of the comparative language contained in section 304(b)(1)(B) leads us to the conclusion that Congress did not intend the Agency or this court to engage in marginal cost-benefit comparisons”) (citations omitted); American Petroleum Inst. , 787 F.2d at 972 (“Unlike §§ 304(b)(1) and 304(b)(4), which define the criteria for BPT and BCT, respectively, § 304(b)(2) does not expressly direct that the Administrator compare costs with effluent reduction benefits in determining BAT limitations.”) (footnote omitted).

In other words, Congress has directed that courts may not invalidate BAT limits on the basis of cost alone, but rather must determine whether EPA has properly weighed all the BAT factors in setting the limits in question. The courts have generally followed Congress’s direction. See CMA v. EPA , 870 F.2d at 252 (“In light of Congress’ judgment that society must bear such costs as the price of achieving the long-term benefits of eliminating pollutants from our nation’s waters, courts have been exceedingly reluctant to invalidate environmental regulations on grounds of cost ....”).

57 E.g.
, Nat’l Crushed Stone Ass’n , 449 U.S. 64, 101 S.Ct. at 300 n.10, 66 L.Ed.2d 268 (unlike CWA § 301(b)(1)(B), which governs BPT standards, CWA § 304(b)(2)(B) “does not state that costs shall be considered in relation to effluent reduction”); Texas Oil & Gas Ass’n
, 161 F.3d at 936 (“In applying the BAT standard, the EPA is not obligated to evaluate the reasonableness of the relationship between costs and benefits.”); Rybachek , 904 F.2d at 1290-91 (“In determining the economic achievability of a technology, the EPA must consider the ‘cost’ of meeting BAT limitations, but need not compare such cost with the benefits of effluent

4-17 that guides EPA’s consideration of cost in setting BAT limits. 55However, these courts affirmedEPA’s use of the test, explicitly holding that the Agency is not required to undertake any costbenefit analysis or otherwise balance a technology’s environmental benefits against its associated costs when setting BAT limits. 56

Overall, the vast majority of courts have held that the CWA bars a direct comparison of the costs and benefits of pollutant reduction in the BAT limit-setting process. 57As one court conciselyMA0003654 Determinations Document July 22, 2002

reduction.”) (citing Nat’l Crushed Stone Ass’n and Ass’n of Pacific Fisheries ); CMA v. EPA , 870 F.2d at 250 (“[b]oth Congress and the Supreme Court have made clear that in setting BAT, the EPA is not required to compare the costs against the benefits of pollution reduction in the same manner as the EPA is required to do in setting BPT standards.”) (citing Nat’l Crushed Stone Ass’n ); Reynolds Metals Co. , 760 F.2d at 565 (“For BPT there must be a ‘limited balancing’ of costs against benefits, but as regards BAT ... no balancing is required – only that costs be considered along with those factors discussed previously.”); Ass’n of Pacific Fisheries , 615 F.2d at 818 (with regard to CWA § 304(b)(2)(B), “Congress did not intend the Agency or this court to engage in marginal cost-benefit comparisons”); American Petroleum Inst. , 787 F.2d at 972 (“§ 304(b)(2) does not expressly direct that the Administrator compare costs with effluent reduction benefits in determining BAT limitations”); American Iron & Steel Inst. , 526 F.2d at 1051 (“With respect to the 1983 ‘BATEA’ [ i.e. , BAT] standards, Senator Muskie intended that the type of assessment should be basically the same [as the BPT standards], except that there should be no cost-benefit analysis.”); American Meat Inst. , 526 F.2d at 462-63 (“No formal cost-benefit analysis is required in determining the ‘best available’ technology, although the Administrator is to take cost into consideration.”).

58 Texas Oil & Gas Ass’n , 161 F.3d at 936. In rejecting the petitioners’ challenges to a study that EPA had used to estimate the “pollution reduction benefits” that would result from use of a particular technology as BAT, the Texas Oil & Gas Ass’ncourt held that “[w]hatever value such benefit estimates may have, they are not a required part of the BAT determination. In applying the BAT standard, the EPA is not obligated to evaluate the reasonableness of the relationship between costs and benefits.” Id.
, citing Nat’l Crushed Stone Ass’n , 449 U.S. 64, 101 S.Ct. at 300, 66 L.Ed.2d 268.

See also American Petroleum Inst. , 858 F.2d at 265 n.5 (where petitioners claimed that BAT limits would have “‘infinitesimal’ impact at a ‘monumental’ cost,” court held that “BAT limitations properly may require industry, regardless of a discharge’s effect on water quality, to employ defined levels of technology to meet effluent limitations; a direct cost-benefit correlation is not required, so even minimal environmental impact can be regulated, so long as the prescribed alternative is ‘technologically and economically achievable”) (citing 4 Leg. History of the Clean Water Act of 1977: A Continuation of the Leg. History of the Fed. Water Pollution Control Act , 95 th

Cong., 2d Sess. 1469-70 (1978)); BP Exploration & Oil, Inc. , 66 F.3d at 800

4-18 stated,

[t]he benefit to be achieved from adopting a particular pollution control technology is not an element of that technology’s cost. The cost of complying with a BAT-based regulation can be gauged by reference to the cost of the technology itself, even if the benefits of using that technology are unclear. 58MA0003654 Determinations Document July 22, 2002

(where industry petitioners claimed that BAT limits for offshore oil and gas extraction point sources discharging within three miles of shore were improperly promulgated because “environmental benefits” of limits were “negligible,” court affirmed EPA’s position that in setting BAT limits, Agency “need only find that the technology is technologically and economically achievable and that the cost of the technology is reasonable”).

59 American Petroleum Inst. , 858 F.2d at 265.

60 Ass’n of Pacific Fisheries , 615 F.2d at 818.

61 Kennecott , 780 F.2d at 456, citing Ass’n of Pacific Fisheries , 615 F.2d at 820.

62 See
, e.g. , American Petroleum Inst. , 858 F.2d at 265-266 (“Because the basic requirement for BAT effluent limitations is only that they be technologically and economically achievable, the impact of a particular discharge upon the receiving water is not an issue to be considered in setting technology-based limitations.”).

63 See
, e.g. , BP Exploration & Oil, Inc. , 66 F.3d at 796 (in establishing BAT limits for produced waters discharged by offshore oil and gas extraction facilities, EPA properly weighed BAT factors in determining that while reinjection was technologically feasible, combination of

4-19 In sum, the CWA provides that “even minimal environmental impact can be regulated” as long as the BAT limits in question are ‘technologically and economically achievable.” 59When a court reviews EPA’s BAT determination for a specific point source category or individual discharger, “[s]o long as the required technology reduces the discharge of pollutants, [the court’s] inquiry will be limited to whether the Agency considered the cost of technology, along with other statutory factors, and whether its conclusion is reasonable.’” 60 EPA’s obligation is to meet its “duty to explain its cost analysis fully.” 61

Therefore, in setting the BPJ-based BAT limit for thermal discharges from BPS, EPA considered the costs of particular technologies that could be used as BAT at the plant, the economic impact of these costs on the permittee and ratepayers, and the reasonableness of these costs and impacts in light of the CWA’s ultimate goal of eliminating the discharge of all pollutants.

4.2.3c Non-Water Quality Environmental Impacts

EPA is not required to consider water quality impacts in setting BAT limits. 62 It is, however, required under CWA § 304(b)(2) and 40 C.F.R. § 125.3(d)(3) to consider environmental impacts that are not water quality-related. In fact, EPA may determine that a particular technology is technologically available and economically achievable but should not be the basis for BAT limits because of unacceptably high non-water quality environmental impacts. 63MA0003654 Determinations Document July 22, 2002

“negative impact reinjection would have on air emissions,” high cost, and resulting loss of production was valid basis for rejecting it as BAT); id. at 800 (while zero discharge of drilling fluids and cuttings was technologically available and economically achievable for all offshore drilling platforms in Gulf of Mexico, including drilling platforms beyond three miles from shore, lack of landfill capacity in region was “unacceptably high nonwater quality environmental impact[]” and thus proper basis for establishing three-mile zero discharge limit); id. at 801 (while zero discharge was technologically available and economically achievable for all offshore drilling platforms in California, including drilling platforms beyond three miles from shore, zero discharge option’s “serious impact on air pollution” was, in EPA’s view, “unacceptably high nonwater quality environmental impact[]” and thus proper basis for establishing three-mile zero discharge limit). See also Weyerhauser , 590 F.2d at 1045 (discussing EPA’s discretion in assessing BAT factors, court noted that “[s]o long as EPA pays some attention to the congressionally specified factors, the section [304(b)(2)] on its face lets EPA relate the various factors as it deems necessary”).

64 Rybachek , 904 F.2d at 1297 (discussing evaluation of nonwater quality environmental impacts under CWA § 304 in context of challenge to EPA regulations establishing BAT limits for placer mining industry point sources), citing Weyerhauser , 590 F.2d at 1049-53 (discussing evaluation of nonwater quality environmental impacts under CWA § 304 in context of challenge to EPA regulations establishing BPT limits for pulp and paper industry point sources).

65 See BP Exploration & Oil, Inc. , 66 F.3d at 801 (EPA was within its discretion in deciding that increased air emissions that would result from barging all drilling wastes from offshore oil and gas extraction platforms to coast of California “vastly outweighed” benefit of imposing zero discharge limitation to platforms beyond three miles from shore).

66 See
, e.g. , BP Exploration & Oil, Inc. , 66 F.3d at 800 (record supported EPA’s determination that zero discharge is BAT for drilling wastes discharged by offshore oil and gas extraction facilities within three miles of shore in Gulf of Mexico by showing that EPA not only properly estimated both projected volume of waste from certain drilling platforms and availability of landfill capacity, but also “continuously reevaluated data and collected comments”and

4-20 The CWA gives EPA broad discretion in deciding how to evaluate non-water quality environmental impacts and weigh them against the other BAT factors. 64 EPA does not need, for example, to demonstrate that the non-water quality environmental impacts of a particular technology are “‘wholly disproportionate’ to the possible pollution reduction” that would result from applying the technology to set BAT limits. 65 Rather, the Agency must apply its discretion and expertise to the relevant information at hand regarding the “relative impact of two different environmental harms,” and demonstrate on the record that it has considered this information in light of all the BAT factors. 66MA0003654 Determinations Document July 22, 2002

“revis[ed] its information” to keep it up to date); Rybachek , 904 F.2d at 1297 (record demonstrates that EPA determined that placer mining industry compliance with BAT requirements would require certain specified number of gallons of fuel per year, and further demonstrates how EPA reached determination and considered it in establishing BAT requirements); American Iron & Steel Inst. , 526 F.2d at 1049 (record demonstrates that in setting BAT limits for iron and steel industry point sources, EPA “considered both the problems of air pollution and solid waste disposal, as well as the problem of additional energy requirements caused by installation of the necessary anti-pollution devices”). See also Weyerhauser , 590 F.2d at 1045 (discussing EPA’s discretion in assessing BAT factors, court noted that “[s]o long as EPA pays some attention to the congressionally specified factors, the section [304(b)(2)] on its face lets EPA relate the various factors as it deems necessary”).

67 E.g.
, BP Exploration & Oil, Inc. , 66 F.3d at 804; Reynolds Metals Co. , 760 F.2d at 565.

68 Reynolds Metals Co. , 760 F.2d at 559, quoting Hercules, Inc. v. EPA , 598 F.2d 91, 107 (D.C.Cir. 1978).

69 See BP Exploration & Oil, Inc. , 66 F.3d at 804, citing Reynolds Metals Co. , 760 F.2d at 565, and American Petroleum Inst. v. EPA , 540 F.2d 1023, 1035-36 (10 th Cir. 1976), cert. denied , 430 U.S. 922, 97 S.Ct. 1340, 51 L.Ed.2d 601 (1977).

70 CMA v. EPA , 870 F.2d at 228, citing BASF Wyandotte , 598 F.2d at 656.

4-21 4.2.3d Other Factors EPA Deems Appropriate

i. EPA’s Use of Data

In establishing BAT limits, EPA has broad discretion in its selection of data and in its methods of calculation. 67Its conclusions with respect to data and analysis “need only fall within a ‘zone of reasonableness.’” 68

For example, where the Agency relies on scientific data from several sources, one of those sources may be a data set that is not complete without several years of data, which are unavailable. 69In addition, EPA may “borrow” data where direct data is not available, as long as its assumptions are logical and there is nothing in the record to establish that they led to scientifically inaccurate results. 70 For example, where for a particular pollutant it does not have sufficient plant variability data to calculate a variability factor that reflects the observed variations in treatment performance experienced by plants attempting to remove that pollutant from their discharge, EPA may use the average of those variability factors that it has established for pollutants exhibiting similar chemical structure and characteristics, or the average of theMA0003654 Determinations Document July 22, 2002

71 Id.

72 E.g.
, id. , 870 F.2d at 228; BASF Wyandotte , 598 F.2d at 655.

73 CMA v. EPA , 870 F.2d at 227-28.

74 CWA § 301(b)(2), 33 U.S.C. § 1311(b)(2).

4-22 variability factors for all the other pollutants that it found to be treatable by the same technology. 71

EPA similarly has discretion in its choice of statistical methods. 72 For example, in establishing BAT limits, it may average over a long term the amount of a pollutant discharged by the best plant or plants in a point source category using BAT technology, and then use weighted averaging - multiplying the long-term average by a variability factor greater than one - to account for the variation from that average that could be expected by the best plant or plants. 73

4.3 The Technological Availability of Cooling System Options for Reducing Thermal Discharges from BPS

4.3.1 Background

As stated above, the goal of this section is to establish thermal load limitations based on BAT for BPS in accordance with CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3(d)(3). The section first considers a range of potential technological options for reducing thermal discharges from the plant. Several of these potential options are screened out based on factors that EPA believes indicate they would not be preferred over the alternatives that are retained for detailed evaluation of whether they are BAT for reducing thermal discharges from BPS. The section thenpresents these detailed evaluations, which consider technological, economic, non-water qualityrelated environmental and energy-related aspects of each of the preferred options. Finally, the section presents EPA’s conclusions regarding the degree to which each preferred option meets the Act’s requirements that it be both technologically available and economically achievable and result in “reasonable further progress toward the national goal of eliminating the discharge of all pollutants.” 74

Based on these conclusions, EPA presents the BAT limit for the discharge of heat from BPS.

Because BPS is an existing plant, EPA must evaluate what constitutes BAT for reducing thermal discharges from the plant keeping in mind that the technology or combination of technologies on which BPS’s BPJ-based BAT limit would be based would be a retrofit. EPA recognizes that BPS may have less flexibility in designing and locating cooling water system components, and may incur higher compliance costs, than a new plant. EPA also recognizes that retrofittingMA0003654 Determinations Document July 22, 2002

75 See 65 Fed. Reg. 49064 (August 10, 2000).

4-23 technologies at BPS may require brief shutdown periods during which the plant would lose both production and revenues, and that certain retrofits could decrease the plant’s thermal efficiency. Finally, EPA recognizes that BPS may have certain site limitations, such as a lack of undeveloped space, that may make certain technologies infeasible. 75

Nonetheless, it should be clearly understood that technologies exist that generate electricity with little or no discharge of heated cooling water. Indeed, these technologies, including wet cooling towers and dry cooling towers, have been in widespread use for many years and generally result in few or no adverse environmental impacts. None of these technologies is automatically considered BAT under the current case-by-case approach to reducing thermal discharges from new or existing steam electric power plants. Rather, each technology’s availability and economic achievability must be addressed on a site-specific basis. As explained above, for BPS, this involves consideration of (1) each technology’s availability for use at BPS; (2) the technology’s costs, including the economic impact of these costs on the permittee and ratepayers, and the reasonableness of these costs and impacts in light of the CWA’s goal of eliminating all pollutant discharges; and (3) the technology’s performance in terms of non-water quality-related environmental and energy impacts and other impacts that EPA deems appropriate.

In evaluating technology alternatives for reducing the thermal load discharged from BPS into Mount Hope Bay, EPA has considered both the material submitted by the permittee and other materials, such as EPA’s own expert engineering analyses, relevant guidance documents, information regarding experience at other power plants, and information from equipment manufacturers.

As part of its permit application, and in response to EPA information requests, the permittee has submitted a significant amount of information related to potential thermal load (and flow) reduction technologies. Since issuance of the current NPDES permit in 1993, the permittee has submitted several major documents to the permitting agencies addressing technologies to support the next permit reissuance. The permittee has also made several smaller submissions and a number of presentations at meetings on this topic.

In late 1996, EPA sent the New England Power Company (NEPCO), then the permittee and owner and operator of BPS, an information request letter under CWA § 308. This request sought, among other things, information related to alternative technologies that might be used at BPS to reduce the effects of the plant’s thermal discharge to Mount Hope Bay and the adverse environmental impacts from both the entrainment and impingement of marine life by its cooling water intake structures (CWISs). NEPCO contracted Stone and Webster Engineering Company (Stone & Webster) to describe and compare alternatives. NEPCO then submitted to EPA a StoneMA0003654 Determinations Document July 22, 2002

76 The baseline heat load to Mount Hope Bay from BPS currently peaks around 4x10 12 [trillion] BTUs per month. See “Clean Water Act Section 316(a) and (b) Demonstration, Brayton Point Station Permit Renewal Application” (November 2001) (hereinafter “December 2001 USGenNE 316(a) and (b) Demonstration”), Vol. III, App. G, Tab: USGenNE § 308 Response of September 10, 2001, Table B-2.

4-24 & Webster report entitled "Feasibility Study of Cooling Water System Alternatives for Brayton Point Generating Station" (January, 1997) (the “January 1997 NEPCO Report”).

In September, 1998, NEPCO sold BPS to USGenNE, which continued the Section 316(b) alternative technology analyses. On February 22, 2001, USGenNE submitted a report entitled, “NPDES Renewal: USGen New England, Inc., Brayton Point Station, Somerset, Massachusetts” to EPA New England and MA DEP. This report attached a February 2001 report entitled “Summary of Cooling System Alternatives Analysis for Reducing Thermal Discharge and Entrainment and Impingement at Brayton Point Station.” It stated that it summarized and condensed certain new information on “Cooling System Alternatives” provided by Stone & Webster, but also indicated that Stone & Webster was still doing additional work for USGenNE. Subsequently, USGenNE submitted the May 24, 2001 Partial 316(a) and (b) Demonstration. On September 10, 2001, in response to another EPA information request letter, USGenNE submitted a document entitled “A Response to Section 308 Information Request dated August 10, 2001.” The latter document also evaluates certain technological alternatives for reducing BPS’s thermal discharges and the volume of water withdrawn through its CWISs.

Then, on December 7, 2001, the permittee made a new submission to EPA and MA DEP entitled “Clean Water Act Section 316(a) and (b) Demonstration, Brayton Point Station Permit Renewal Application” (November 2001) (hereinafter, the “December 2001 USGenNE 316(a) and (b) Demonstration”). This submission includes five large volumes with thousands of pages of material, including a 67-page “Executive Summary.” Certain portions of this material had been submitted previously by the permittee, while other portions had not. Such a late submission of this voluminous, complex package by the permittee – the permittee’s application for permit renewal was due, and was originally filed by the permittee, in January 1998 – created a challenge for the regulatory agencies, but the agencies have endeavored to carefully review and consider the material in the December 2001 USGenNE 316(a) and (b) Demonstration.

A significant point must be made regarding the above-mentioned submissions by the permittee: that in preparing these materials, the permittee imposed certain conceptual limitations on its analyses of cooling water system technologies that may be used for thermal load reduction at BPS. For example, the January 1997 NEPCO Report considered only thermal load reduction alternatives that reduce the average monthly thermal loading by a maximum of approximately 2x10 12 (trillion) BTUs. 76

EPA was not aware of these limitations on the permittee’s analysis priorMA0003654 Determinations Document July 22, 2002

77 “Summary of Cooling System Alternatives Analysis for Reducing Thermal Discharge and Entrainment and Impingement at Brayton Point Station” (February 2001) (attached to “NPDES Renewal: USGen New England, Inc., Brayton Point Station, Somerset, Massachusetts” dated February 22, 2001), p. 7.

78 See June 19, 2001 letter from David Webster, EPA, to Meredith Simas, PG&E/NEG.

79 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, § 4.4.

80 Id. , Vol. IV, App. H, at 1-6.

4-25 to receiving the January 1997 NEPCO Report, and it neither approved them nor otherwise indicated that an evaluation of thermal load reduction technologies based on such limitations would suffice under the CWA.

Similarly, the permittee’s February 2001 submittal states that “[t]he focus of the ongoing cooling system alternatives analysis is to identify alternatives and combinations of alterations that could (a) reduce the station’s thermal discharge to levels that existed before Unit 4 started discharging heat into Mt. Hope Bay and (b) reduces circulation water flows to levels equivalent to Units 1, 2 and 3 only.” 77In a June 19, 2001 letter, EPA explained to the permittee that EPA and the States have not adopted these plant performance criteria for their own evaluations of what constitutes adequate performance, and that they would instead look to the criteria provided in federal and state environmental laws. The letter also noted that EPA and the States had explained to the permittee at several meetings that they had not determined whether rolling back the plant’s thermal discharge and cooling water intake profile to the levels observed before Unit 4 was converted to once-through cooling would be sufficient to meet the environmental standards of applicable laws. 78Nevertheless, the permittee continued to use this criterion for judging alternatives in the December 2001 USGenNE 316(a) and (b) Demonstration. 79

Finally, the permittee’s analysis of thermal load reduction alternatives in App. H of the December 2001 USGenNE 316(a) and (b) Demonstration is similarly limited. In that report, the permittee judged technological alternatives by whether or not they could “(a) reduce the station’s thermal discharge to levels below MOA II and below levels that existed before Unit 4 started discharging heat into Mt. Hope Bay and (b) reduce circulating water flows to levels below MOA II and below historical flows associated with Units 1, 2, and 3 only.” 80 The BAT analysis presented in this determination document is not limited by this constraint, i.e. , EPA has not evaluated only those alternatives that could reduce BPS’s thermal discharge to pre-Unit 4 levels.

4.3.2 Cooling System Options for Reducing Thermal Discharges from Steam Electric Power Generating PlantsMA0003654 Determinations Document July 22, 2002

81 Technical Development Document for the Final Regulations Addressing Cooling Water Intake Structures for New Facilities (EPA-821-R-01-036) (November 2001) (hereinafter “EPA TDD 2001 - New Facilities”), Chapter 4, p. 1. See also 66 Fed. Reg. 65282 (Dec. 18, 2001); EPA Office of Water, “Economic and Engineering Analysis of the Proposed § 316(b) New Facility Rule) (August 2000), App. A, p. 14 (hereinafter “EPA Economic and Engineering Analysis”).

82 See
, e.g. , 66 Fed. Reg. 65282-83 (Dec. 18, 2001).

83 Wet/dry cooling towers combine dry heat exchange surfaces with standard wet cooling towers. This technology would be less expensive than dry cooling but more expensive than a wet cooling tower system. See 65 Fed. Reg. 49081 (August 10, 2000) (discussion of wet/dry towers); Science Applications International Corporation (SAIC), “Review of USGen New England Brayton Point Station Section 316 Demonstration Report” (March 15, 2002) (hereinafter “SAIC Report (March 15, 2002)”), Table 5. The permittee did not evaluate the retrofitting or use of wet/dry cooling towers at BPS. EPA will not establish BAT limits for BPS based on the wet/dry cooling tower technology, but the permittee may use this technology to

4-26 Generally, steam electric powerplants employ one of four basic types of circulating water cooling systems to reject waste heat. These systems are (1) “once-through” or open-cycle cooling (which is presently used at BPS), (2) once-through cooling with supplemental cooling on the discharge,(3) recirculating or “closed-cycle” cooling, and (4) a combination of these three systems. A oncethrough system discharges the entire amount of cooling water, and thus the entire amount of the waste heat discharged by the plant, to the receiving water body. A once-through system with supplemental cooling ( e.g. , from “helper” cooling towers) removes a portion of the waste heat from the plant effluent before discharge to the receiving water and transfers this energy to the atmosphere. A closed-cycle or recirculating system employs a cooling device that withdraws the plant’s waste energy from the cooling water and releases it directly to the atmosphere, thus enabling the plant to recirculate and reuse the cooling water.

There is another type of cooling system that does not use cooling water. This type of system employs “dry cooling” towers, which use a natural or a mechanical air draft to transfer heat from condenser tubes to the atmosphere without the evaporative loss of water. There are two types of dry cooling systems for power plant applications: direct dry cooling and indirect dry cooling. Direct dry cooling systems utilize air to directly condense steam, while indirect dry cooling systems utilize a closed cycle water cooling system to condense steam, and the heated water is then air cooled. 81 Dry cooling tower (or air-cooled condenser) systems are regarded to be substantially more expensive than wet cooling tower systems. 82

Also worthy of note is the “hybrid” (or “wet/dry”) system, which combines principles of wet and dry cooling tower operations. 83 For the most common type of hybrid system, exhaust steamMA0003654 Determinations Document July 22, 2002

meet the final permit requirements if it chooses.

84 EPA TDD 2001 - New Facilities, Chapter 4, p. 1.

85 See 65 Fed. Reg. 49081 (August 10, 2000) (discussion of wet/dry tower); December 10, 2001 telephone memorandum from Sharon Zaya, EPA, regarding call with Gary Mirsky, P.E. Hamon Cooling Towers, N.J.; January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding call with Ken Daledda, Bergen Station, New Jersey; 39 Fed. Reg. 36192 (October 8, 1974); EPA Economic and Engineering Analysis, App. A, p. 14; SAIC Report (March 15, 2002), Table 5.

86 See
, e.g. , 65 Fed. Reg. 49080-81 (August 10, 2000); 1996 EPA Supplement to Background Paper No. 3, p. A-3; 41 Fed. Reg. 17388 (April 26, 1976); 1976 Draft EPA CWA § 316(b) Guidance, p. 13; EPA 1976 Development Document (April 1976), pp. 149-57, 191; 39 Fed. Reg. 36192 (October 8, 1974).

87 See 65 Fed. Reg. 49080-81 (August 10, 2000); November 6, 2000 Letter from Vern Lang (US F&WS) to EPA Proposed Rule Comment Clerk, p. 3 (comments on EPA’s proposed regulations under CWA § 316(b) for new power plants listing number of plants currently operating, under construction, or recently approved for air (or “dry”) cooling); EPA Economic and Engineering Analysis, App. A, p. 14.

88 See
, e.g. , 65 Fed. Reg. 49080-81 (August 10, 2000); EPA Economic and Engineering Analysis, App. A, pp. 14-15; 39 Fed. Reg. 36192 (October 8, 1974); Literature from Marley Cooling Tower Company; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating

4-27 flows through smooth tubes, where it is condensed by a mixture of cascading water and air. The water and air move in a downward direction across the tube bundles and the air is forced upward for discharge to the atmosphere. The falling water is collected and recirculated, similarly to a wet cooling tower. 84

This technology typically has greater capital costs than basic wet cooling towers but can eliminate costs attributable to outages or mitigation related to water vapor plumes from wet mechanical draft cooling towers. 85In addition, a plant may use generation curtailment, which involves curtailing electricity generation to a level that would enable the plant to reduce the amount of cooling water it discharges.

There is no question that as a general matter, wet, dry and wet/dry cooling towers are technologically available for use at power plants. Wet cooling towers have been widely used at power plants for many years. 86 Air cooling is also a viable technology. In fact, air cooling systems have recently been proposed for installation for new units at the Mystic and Fore River Stations in Massachusetts. 87In addition, a number of plants use wet/dry cooling towers. 88MA0003654 Determinations Document July 22, 2002

Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary.

89 It is nonetheless noteworthy that between 1955 and 1997, the number of new steam electric power plants using closed-cycle cooling water systems increased from 25 percent to 75 percent, with a corresponding decrease in plants using once-through systems. Between 1975 and 1984, the number of steam electric power plants using closed-cycle recirculating systems increased 31 percent. This trend toward the use of closed-cycle recirculating systems is projected to continue as new plants are built. Of the seven new generating plants that would potentially be covered by the recently proposed CWA § 316(b) rule and for which EPA has planning information, all seven plan to use closed-cycle recirculating cooling water systems. See 65 Fed. Reg. 49072 and n.5 (August 10, 2000). EPA estimates that 84 percent of existing steam electric generating plants started operation between 1955 and 1985. An additional 7 percent of these plants started operation between 1985 and 1997. Id.

90 See 1994 EPA Background Paper No. 3, p. 2-3.

4-28 Nonetheless, to establish BPJ-based BAT limitations on thermal discharges from BPS inaccordance with CWA §§ 301(b)2) and 304(b)(2), EPA must determine which of these closedcycle cooling technologies, if any, is available for retrofittingspecifically at BPS

. 89

Moreover, as discussed above, EPA must consider other factors, including non-water quality environmental and energy-related impacts, in determining whether the thermal discharge reductions achievable from one of these technologies is BAT for BPS under the CWA. For example, cooling towers can be tall, though not necessarily as tall as other power plant facilities, such as air emission stacks. As a result, EPA must consider not only logistical issues, such as available space for installing the towers, but also potential visual impacts. For wet cooling tower systems, EPA must consider whether there are any concerns related to the emission of mist or water vapor that may travel from the plant onto nearby receptors. For wet mechanical draft and dry cooling tower systems, EPA must consider potential noise impacts from the fans used in the cooling process. In addition, the use of a closed-cycle cooling technology can result in a marginal loss of plant efficiency and lead to increased energy usage and air emissions. EPA must consider all of these factors in evaluating the costs of each technology alternative and the environmental significance of potential increased fuel consumption and air pollution.

It is important to note that a power plant can combine the use of closed-cycle and open-cycle cooling technologies to reduce overall thermal discharges to a predetermined level or to prevent going above a specified cost threshold. 90 Such “combination options” could make particular sense at existing plants being considered for retrofit technology changes, because it could be easier and less expensive for an existing plant to retrofit to partially closed-cycle cooling instead of completely closed-cycle cooling. Indeed, the permittee’s “Enhanced Multi-Mode” proposal,MA0003654 Determinations Document July 22, 2002

91 Cooling ponds and lakes are similar in principle to open, once-through systems but are closed inasmuch as no significant thermal discharge occurs beyond the confines of the pond or lake. Appalachian Power Co. , 545 F.2d at 1358, 1368 and n.44.

92 See 1994 EPA Background Paper No. 3, pp. 2-3 to 2-5 (general discussion of cooling towers); 66 Fed. Reg. 65282 (Dec. 18, 2001).

93 See 65 Fed. Reg. 49081 (August 10, 2000).

94 EPA Economic and Engineering Analysis, App. A, p. 14.

4-29 which is discussed below, is a sort of combination option. Accordingly, EPA has considered alternatives for BPS that involve partially shifting the plant to closed-cycle cooling while also allowing some open-cycle cooling to remain.

4.3.2a Closed-Cycle Cooling/Cooling Tower Options

There are two basic methods of heat rejection through a closed-cycle cooling system. The first uses cooling ponds or lakes. These typically consist of artificially constructed bodies of water built by damming a natural watershed. The condenser water is fed into the cooling pond or lake, cooled through evaporation and then recycled to the condenser. 91 The permittee did not evaluate the retrofitting or use of cooling ponds or lakes at BPS. EPA will not establish BAT limits for BPS based on the technological alternative of cooling ponds/cooling lakes, but the permittee may use this alternative to meet the final permit requirements if it chooses.

The second basic closed-cycle cooling method is wet (or evaporative) cooling using wet cooling
towers. 92 In systems that employ conventional wet cooling towers, water that has been used to cool the condensers is pumped to the top of a cooling tower; as the heated water falls, it cools through an evaporative process, and the tower emits warm, moist air. 93 More specifically, wet cooling towers reduce the temperature of the water by bringing it directly into contact with large amounts of air. Through this process, heat is transferred from the water to the air, which is then discharged into the atmosphere. Part of the water evaporates through this process, thereby having a cooling effect on the rest of the water. This water then exits the cooling tower at a temperature approaching the wet bulb temperature of the air. 94

i. Mechanical Draft versus Natural Draft Wet Cooling Towers

There are two principal types of wet cooling towers used in closed-cycle systems: natural draft towers and mechanical draft towers. Natural draft towers have no mechanical device to create airMA0003654 Determinations Document July 22, 2002

95 See 1994 EPA Background Paper No. 3, p. 2-4.

96 See id. , p. 2-4; EPA Economic and Engineering Analysis, p. 11-2 to 11-3; App. A, p. 14.

97 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-1.

98 February 22, 2001 Letter from Meredith M. Simas, PG&E/NEG, to David Webster, EPA, and Edward P. Kunce, MA DEP, Attachment 1, p. 4. See also December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, at 1-3; January 1997 NEPCO Report, Table 6-1.

99 See EPA Economic and Engineering Analysis, App. A, p. 14.

100 See January 1997 NEPCO Report, pp. 3-13, 3-19.

4-30 flow through the tower and are usually applied in very small or very large applications. 95They induce natural air flow by the chimney effect produced by the height and shape of the tower. Mechanical draft towers use fans in the cooling process. 96 They reject waste heat by the evaporation of a small percentage of the heated discharge water inside cells that are supplied with air flows induced by large fans. 97For towers of similar capacity, natural draft towers typically require significantly less land area and have lower power costs, because fans to induce air flow are not needed; however, they also typically have higher initial costs, particularly because they need to be taller than mechanical draft towers.

The permittee evaluated the use of both natural draft and mechanical draft cooling towers for thermal load and flow reduction at BPS and concluded that natural draft cooling towers should be dropped from consideration. The reason for this decision was the permittee’s determination that although the two technologies offer equivalent reductions in heat rejection (and in flow), natural draft towers are significantly more expensive to construct and pose more serious adverse visual impacts because they are much taller. 98

EPA concurs with the permittee’s decision to drop natural draft cooling towers from further consideration, and focuses on mechanical draft cooling tower-based alternatives in its evaluation of BAT alternatives for reducing the thermal load from BPS. Although EPA has not performed a detailed review of the costs predicted by the permittee for natural draft towers, our research indicates that the relative costs that the permittee has predicted for the two types of towers are approximately accurate, i.e. , that natural draft towers are likely to cost significantly more than mechanical draft towers while achieving the same level of thermal discharge reductions. 99In addition, the visual/aesthetic impacts are more severe for natural draft towers because of their great height (approximately six times as high on average as mechanical draft towers). 100MA0003654 Determinations Document July 22, 2002

101 See January 1997 NEPCO Report, pp. 3-15, 3-21, 3-22; EPA Economic and Engineering Analysis, App. A, p. 14.

102 See EPA Economic and Engineering Analysis, App. A, p. 14.

103 Compare 39 Fed. Reg. 36189, 36192 (Oct. 8, 1974) withEPA TDD 2001 - New Facilities, p. 3-33; January 9, 2002 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA Region 1; December 12, 2001 memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); January 1997 NEPCO Report, p. 3-15.

4-31 EPA notes that mechanical draft towers are likely to be somewhat noisier and more costly to operate than natural draft towers, because of the fans and the energy needed to run them. 101 The Agency has determined, however, that these issues are not so significant as to enjoin the use of mechanical draft towers. EPA believes that any noise effects from the operation of mechanical draft towers can be sufficiently mitigated/controlled to meet applicable noise standards. 102 (Noise is discussed further below.) Moreover, the Agency believes that the difference in the energy use and operation and maintenance costs between the two technologies is not large enough to be a significant issue and would be offset by the increased capital costs for the natural draft towers. (Energy and cost issues at BPS are discussed further below.)

It should also be noted that although natural draft towers may emit less mist or water vapor than mechanical draft towers, this advantage is likely to be more than offset by the fact that any plumes will travel farther from the taller natural draft towers than they would from the shorter mechanical draft towers. 103 While it may not be entirely clear which technology would be preferable from this perspective, even if natural draft towers had a marginal advantage, EPA still agrees with the permittee’s decision to focus on mechanical draft towers for the following reasons: we do not believe the plume problems to be particularly significant, and we believe that there are means to address any such problems, and that at this site the advantages of mechanical draft towers ( i.e. , lower cost, fewer visual/aesthetic impacts) outweigh any marginal advantage that natural draft towers might have in this regard. Mechanical draft towers are a widely used technology at power plants in the United States and abroad, clearly indicating that their impacts are generally not unacceptable.

ii. General Applicability of Mechanical Draft Cooling Towers at BPS

As a general matter, mechanical draft cooling towers appear to be technologically available for retrofitting at BPS. Such cooling towers have been designed and installed to work effectively inMA0003654 Determinations Document July 22, 2002

104 See, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-2 (“[s]ince the 1970s, a large number of successful, reliable salt water cooling towers have been installed,” mostly in southern and western United States); Technical Development Document for the Proposed Section 316(b) Phase II Existing Facilities Rule (EPA 821-R-02-003) (April 2002) (hereinafter “EPA TDD 2002 - Existing Facilities”), p. 4-1; December 20, 2001 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA Region 1.

105 See SAIC Report (March 15, 2002), Attachment A (Case 4); Memorandum from Nick Prodany and Mark Stein to Brayton Point NPDES Permit File, “Notes on Telephone Call with Engineer at Canadys Station power plant in South Carolina;” December 12, 2001 memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); January 1997 NEPCO Report, p. 3-6; December 18, 2001 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA Region 1.

106 EPA acknowledges that the permittee has pointed to a number of detriments for retrofitting closed-cycle mechanical draft cooling towers at BPS, and has reached the opinion that retrofitting the entire facility to closed-cycle cooling towers would be “unsuitable” for a variety of economic, engineering and environmental reasons. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Executive Summary, p. 8, n.7. The company has, however, proposed the installation of its “Enhanced Multi-Mode” system, which utilizes a 20-cell mechanical draft wet cooling tower.

4-32 cooling systems using salt or brackish water, as BPS’s existing cooling system does. 104 Moreover, experience at other plants has shown that closed-cycle mechanical draft cooling towers can be retrofitted to an existing once-through power plant. 105Indeed, the permittee has not argued that such a retrofit would be unfeasible. 106

The permittee has submitted information regarding its views of the engineering requirements and capital and operating costs that would be involved in retrofitting closed-cycle cooling at BPS. It has also submitted information indicating that retrofitting all or some of the units at BPS with closed-cycle mechanical draft cooling towers could cause adverse noise, visual/aesthetic, fogging and icing impacts and likely would result in a marginal decrease in electricity generated for sale by the plant due to an “efficiency penalty” and an “auxiliary power penalty”: a decrease thatwould represent a cost to the permittee. Moreover, according to the permittee, shifting to closedcycle cooling potentially could lead to marginal increases in air pollution if the plant were to burn more fuel in an effort to generate more electricity to offset the lost electrical generation. EPA agrees that retrofitting cooling towers for all or some of the generating units at BPS would be a complicated construction project involving significant costs. Nonetheless, the Agency does not believe based on current information that any of these issues presents a clear fatal flaw with regard to the installation of mechanical draft cooling towers as a retrofit at BPS.MA0003654 Determinations Document July 22, 2002

107 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-4.

108 See February 8, 2002 telephone memorandum by Sharon Zaya, EPA (“Phone Call to Drew Seidel, Plant Manager at Victoria Power Station, TX”); February 8, 2002 telephone memorandum by Sharon Zaya, EPA (“Phone Call to Tom Shusko, Plant Manager at Albright Power Station, WV”); January 24, 2002 memorandum from Mark Stein, EPA, to Brayton Point NPDES Permit File (“Notes on Telephone Conversation with Gary Kolle of Prairie Island Nuclear Generating Station in Minnesota”); January 23, 2002 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA; January 11, 2002 e-mail from Michael Moe, SAIC, to Mark Stein, EPA;

109 See generally PG&E/NEG § 308 Response of September 10, 2001; December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H.

4-33 Therefore, EPA evaluates below whether closed-cycle cooling for the entire BPS plant, i.e.
, retrofitting a mechanical draft cooling tower at each of the plant’s four generating units, would be BAT for controlling thermal discharges from BPS. The conclusions of this detailed evaluation, including an independent analysis of the costs and whether those costs are reasonable, are presented below. EPA also evaluates alternatives for partial closed-cycle cooling at BPS using mechanical draft cooling towers: shifting Unit 3 only to closed-cycle cooling, or shifting Units 1 or 2 and Unit 3 to closed-cycle cooling. These alternatives are the subject for detailed BAT evaluation because each could achieve major incremental reductions in thermal loading short of that which would be achieved by installing mechanical draft cooling towers for the entire plant. EPA’s conclusions regarding these partial closed-cycle cooling alternatives are also presented below.

The Agency notes that these three closed-cycle alternatives use wet cooling towers that are engineered to work only with specific generating units. The permittee has indicated that if such a unit-specific cooling tower needed to be shut down ( e.g. , due to a safety hazard from any water vapor plume), then the associated generating unit would also have to be shut down. 107EPA has learned through its own research, however, that a number of power plants around the United States have wet cooling towers that are used part of the time ( e.g. , to accommodate seasonal environmental concerns about once-through cooling operations) and by-passed at other times, allowing the facility to operate in once-through mode. 108Therefore, in the detailed BAT analysis below, EPA considers this “by-pass” concept as a variation on the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options.

EPA also evaluates another alternative that takes advantage of mechanical draft cooling towertechnology. The permittee has proposed this alternative, which it calls “Enhanced MultiMode.” 109EPA believes the permittee has demonstrated technological ingenuity in developingMA0003654 Determinations Document July 22, 2002

110 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.1-1 and Tables 3.1-1 and 3.1-2.

111 See id. , p. 3.1-10.

112 See id. , Vol. I, Executive Summary, p. 1.

The permittee also proposed a “Basic Multi-Mode” cooling system alternative. See id. , Vol. IV, App. H, § 3.1.2. EPA believes that it is not necessary to evaluate this alternative to determine whether it may be BAT for reducing thermal discharges from BPS, because the Enhanced Multi-Mode alternative achieves greater thermal discharge reductions at a similar cost. More particularly, the Enhanced Multi-Mode alternative would “achieve further flow and heat reduction compared to the basic multi-mode system by utilizing additional piping ... at a cost of approximately $9 million.” It would “allow[] both Units 3 and 4 to operate in a closed-cycle mode” and “would also be capable of cooling the discharge of Units 1 and 2 in a helper cooling tower mode.” Id ., p. 3.1-15. With the Basic Multi-Mode option, only Unit 4 would be capable of operating in a closed-cycle mode. Compare id ., Table 3.1-1, with id. , Table 3.1-2.

4-34 the Enhanced Multi-Mode proposal, and that the proposal warrants detailed evaluation by EPA.

As conceived by the permittee, the Enhanced Multi-Mode system would use mechanical draft cooling towers that could operate in either closed-cycle, helper or piggyback mode to maximize thermal discharge reductions while giving the power plant greater operational flexibility and minimizing costs. Through a major reconfiguration of the piping components within the plant, each of these multi-mode cooling towers would not manage heated effluent solely from a specific, associated generating unit. Rather, each tower would draw heated effluent from the discharge canal, cool it, and recycle the cooled water back to individual units. As a result, these towers would be able to provide thermal discharge and cooling water flow reductions even if particular generating units are not in operation, by cooling the hot water from those units that are in operation. A unit-specific cooling tower would provide no such benefit when its associated generating unit is not operating. In other words, beyond the thermal discharge and flowreductions that would occur when a particular generating unit is off-line, the Enhanced MultiMode system would provide an additional benefit because it could be used to address the heat from other units that are operating, i.e. , as helper towers. 110

Another key aspect of the permittee’s Enhanced Multi-Mode proposal is that it would enable cooling towers to be bypassed, and generating units to remain in production, if necessary to abate water vapor plumes (as discussed in detail below). 111 In the permittee’s view, the system would avoid plume abatement outages related to roadway icing and reduce potentially costly construction-related outages. Finally, the Enhanced Multi-Mode alternative is the permittee’s preferred option. 112MA0003654 Determinations Document July 22, 2002

113 See EPA Economic and Engineering Analysis, App. A, p. 14; 66 Fed. Reg. 65282- 84, 65304-06 (Dec. 18, 2001) (various estimates put costs of dry cooling as from 1.75 to three times more than cost of wet cooling); January 1997 NEPCO Report, Table 6-1 (preliminary capital cost estimate of $63.4 for dry cooling for Unit 4 versus $27.8 for mechanical draft wet cooling for Unit 4). See also SAIC Report (March 15, 2002), Table 5 (costs for hybrid wet/dry cooling towers approximately 2.5 times that of plain wet towers).

The costs in the January 1997 NEPCO Report only address options that provide closed-cycle cooling only for Unit 4. It should also be noted that the more detailed cost analyses conducted by the permittee for the December 2001 USGenNE 316(a) and (b) Demonstration have resulted in substantially higher cost estimates. Compare January 1997 NEPCO Report, Table 6-1 (capital costs for mechanical draft cooling tower for Unit 4 estimated at $27.8 million), withDecember 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3-18 (capital costs for mechanical draft cooling tower for Unit 4 estimated at $48 million). Thus, it is fair to assume the permittee’s estimates for dry cooling would also increase substantially, though the permittee provided no cost estimate for converting any or all of the BPS units to dry cooling in its December 2001 USGenNE 316(a) and (b) Demonstration.

114 See EPA TDD 2001 - New Facilities, § 4.2.2; EPA Economic and Engineering Analysis, App. A, p. 14.

4-35 The technological alternatives discussed above utilize mechanical draft cooling towers in full closed-cycle, partial closed-cycle and “multi-mode” cooling systems. Taken together, they represent a reasonable and appropriate range of alternatives for significantly reducing thermal discharges from BPS.

4.3.2b Non-Closed-Cycle Cooling/Cooling Tower Options

i

. Dry Cooling Towers

The use of air or dry cooling towers would yield the maximum reduction in thermal loading to Mount Hope Bay from BPS by essentially eliminating the use of water for cooling. In dry cooling towers, the water does not come in direct contact with the air but instead travels in closed pipes through the tower. Air going through the tower flows along the outside of the pipe walls and absorbs heat from the pipe walls, which absorb heat from the water in the pipes.

In general, dry cooling towers tend to be much larger and more costly than wet towers since the dry cooling process is less efficient. 113 Also, the effluent water temperature is warmer since it only approaches the dry bulb temperature of the air (not the cooler wet bulb temperature). 114 Nonetheless, dry cooling towers have several advantages over wet cooling towers. They do notMA0003654 Determinations Document July 22, 2002

115 65 Fed. Reg. 49081 (August 10, 2000).

116 See January 1997 NEPCO Report, pp. 3-6 to 3-9; December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 1-3.

117 See January 1997 NEPCO Report, pp. 3-8 to 3-9.

118 Id ., p. 3-8.

119 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 1-3. This does not appear to be a fully accurate representation of the January 1997 NEPCO report’s conclusions.

4-36 consume water through evaporation, they have no wastewater discharge to affect water quality, they do not cause the drift of salt or other minerals, they do not require the use and subsequent treatment of water conditioning chemicals or biocides, and they do not create a vapor plume. Moreover, because plants employing dry cooling systems have no cooling water needs, they can be located near or in cities and other areas with great demand for electricity irrespective of the availability of large supplies of cooling water, thereby reducing costs and power losses associated with transmitting electricity over long distances. 115

The permittee looked at a dry cooling alternative for Unit 4 only in the January 1997 NEPCO Report but did not carry this alternative forward for further detailed analysis. 116 According to the report, the dry cooling alternative would be “marginally feasible” but was a poor alternative due to its greater cost (more than twice as expensive), greater size (potentially posing space constraints), greater noise and greater diminishment of plant power generation capacity. 117The report also noted that because a retrofit from once-through to dry cooling had never been completed, to the permittee’s knowledge, it would be inherently difficult and require especially complicated and expensive engineering and design work. 118In the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee stated that dry cooling “was determined to be infeasible because this technology has never been retrofitted to an existing station and thus has significant risk of operating failure.” 119

EPA does not agree that retrofitting some or all the generating units at BPS to dry cooling has been demonstrated to be “infeasible.” While the Agency is not aware of any examples of plants that have switched from once-through cooling to dry cooling, such a conversion is not necessarily infeasible just because it may not have been completed in the past. Indeed, the January 1997 NEPCO Report stated that dry cooling was “marginally feasible” for Unit 4.

EPA nonetheless shares the permittee’s view that the absence of a track record of such conversions must be cause for serious caution and concern, and that this caution must grow asMA0003654 Determinations Document July 22, 2002

120 See 65 Fed. Reg. 49081 (August 10, 2000).

121 See EPA TDD 2001 - New Facilities, Chapter 3 (entitled “Energy Penalties, Air Emissions, and Cooling Tower Side-Effects”).

122 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, § 3.2.

4-37 more units are considered for conversion. As a result, like the permittee, EPA has also decided drop dry cooling towers from further consideration for retrofitting at BPS for a combination of reasons. First, although the Agency has not performed an independent review of the costs predicted by the permittee for this alternative, based on our research we believe that the permittee’s assertion that this technology would be more expensive is correct. As noted above, EPA has determined that a dry cooling system generally can cost up to three times more to install than a comparable wet cooling system. 120 Second, dry cooling may impose a greater energy penalty. 121 Third, there is substantially more uncertainty about the feasibility (or difficulty) of retrofitting open-cycle generating units to dry cooling than there is with respect to wet cooling, and this uncertainty grows as more units are considered for conversion. In other words, for cooling system options that would address more than one of BPS’s generating units, and that therefore could achieve greater thermal discharge reductions than cooling system options that would address only one of BPS’s generating units, the feasibility of converting to wet cooling towers is clear, whereas the feasibility of the dry cooling options is not.

In sum, because EPA is evaluating several wet mechanical draft cooling tower options for retrofitting at BPS -- including an option that would address all four generating units -- EPA does not believe that further evaluation of dry cooling at BPS is necessary at this time.

ii. Helper Cooling Towers

Helper cooling towers are another technological alternative for reducing a plant’s thermal discharges. These towers supplement an open-cycle cooling system by removing a portion of the heat energy discharged in a plant’s effluent and transferring it directly to the atmosphere.

The permittee evaluated the use of helper mechanical draft cooling towers with eight cells, 18 cells, 24 cells, 30 cells and 48 cells for both thermal load and flow reduction at BPS. 122 EPA has selected the permittee’s 48-cell helper cooling tower option for detailed evaluation to determine whether it is BAT for controlling thermal discharges from BPS. The conclusions of this evaluation, including an independent analysis of the costs and their reasonableness, is presented below.

iii

. “Piggyback” CoolingMA0003654 Determinations Document July 22, 2002

123 See id. , § 3.4.

124 Id ., p. 3.4-1.

125 Id.

126 See January 1997 NEPCO Report, § 4.4.

4-38 The permittee evaluated two “piggyback” cooling options in the January 1997 NEPCO Report and then reevaluated them in the December 2001 USGenNE 316(a) and (b) Demonstration. 123

According to the permittee, the first piggyback cooling option – “simple” or “conventional” piggyback operation – would involve “routing a portion of the mixed, warm condenser discharge of Units 1, 2, and 3 into the pump bay of Unit 4" for cooling. 124 In other words, this option would transfer the waste heat from Unit 4 to the already heated effluent from Units 1, 2 and 3. Thus, it would not reduce the total heat load discharged to Mount Hope Bay. In fact, under certain conditions, the heated effluent from Unit 4 would exceed current permit limits for maximum temperature and TM -T, especially during the summer. As a result, implementation of year-round piggyback cooling would require either installation of additional thermal discharge reduction technology or substantial cutbacks in operations. 125The second piggyback cooling option evaluated by the permittee is a variation on the first option that would reroute the existing Unit 4 intake flow directly to Unit 3. In this option, the flow drawn from the Taunton River for Unit 3 would be replaced with flow from the Lee River withdrawn through the newer Unit 4 CWIS.

EPA has concluded that neither piggyback option could constitute BAT by itself. As noted above, implementing either piggyback option on a year-round basis would render the plant unable to comply with the permit’s limitations for maximum temperature and TM -T unless the permittee either significantly curtailed generation during the summer or installed substantial additional thermal reduction technology. Such curtailment is likely to be quite expensive and is not preferred by the permittee. More important, there is no added benefit to implementing either piggyback option if the permittee will still need to install additional cooling technologies in order to reduce the overall heat discharged to the bay.

iv. Generation Curtailment

The permittee also evaluated the use of generation curtailment ( i.e. , flow reduction) for thermal load and flow reduction at BPS. 126 According to the permittee, this alternative would involve curtailing the generation of electricity to a level that would enable the plant to reduce flow by 29% ( i.e. , equivalent to eliminating the flow for Unit 4). The permittee indicated that very high energy losses would occur with this alternative on an annual basis, as well as reductions in plant reliability and energy output. Specifically, the permittee asserted that this alternative wouldMA0003654 Determinations Document July 22, 2002

127 Id ., p. 4-7.

128 See id ., pp. 4-7 to 4-8, Table 6-1.

4-39 reduce BPS generation by 300 MW, with a corresponding station energy output reduction by 67,000 MWhr. 127The overall effect on plant energy output would, of course, depend on the extent to which generation was curtailed. 128The permittee also states that such generation curtailment would diminish station reliability. These problems would be especially acute during the high demand summer period.

Given that there are available methods of reducing thermal loading to Mount Hope Bay without making major reductions in electrical generation, EPA does not believe this method would constitute BAT for BPS. Generation curtailment may be a suitable method of meeting a special short-term heat reduction target at a particular time of the year. EPA will not establish BAT limits for BPS based on the generation curtailment alternative, but the permittee may use this alternative to meet the final permit requirements if it chooses.

4.3.3 Unit-Specific and Multi-Mode Cooling Tower-Based Options for Reducing Thermal Discharges from BPS

In Section 4.3.2a of this determination document, EPA identified a range of mechanical draft cooling tower-based options, including options proposed by the permittee, that BPS could implement to dissipate heat to the atmosphere rather than discharging it to Mount Hope Bay. (We note that despite our having considered numerous options, there are additional variations that have not been evaluated either by the permittee or EPA.) The Agency then selected for more detailed evaluation the options with the greatest potential to be BAT for reducing thermal discharges from BPS. These include three unit-specific options and one multi-mode option:

- Partial closed-cycle cooling using a 22-cell wet mechanical draft wet cooling tower for Unit 3 alone (the “ Closed-Cycle Unit 3 " option).

- Partial closed-cycle cooling using a 15-cell wet mechanical draft cooling tower for Unit 1 or 2 and a 22-cell wet mechanical draft cooling tower for Unit 3 (the “ Closed-Cycle Units 1 or 2 & 3 " option).

- Closed-cycle cooling using a 30-cell wet mechanical draft cooling tower for Units 1 and 2, a 22-cell wet mechanical draft cooling tower for Unit 3, and a 20-cell wet mechanical draft cooling tower for Unit 4 (the “ Closed-Cycle Entire Station ” option).

- Partial closed-cycle cooling using once-through cooling with four 12-cell helper wetMA0003654 Determinations Document July 22, 2002

129 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 2-2. Although Unit 4's temperature rise and flow are close to Unit 3's, Unit 3 operates far more frequently than Unit 4. Id. , pp. 2-2, 3.3-28.

130 See SAIC, “Evaluation of Additional Cooling Water Technology Alternatives for USGen New England Brayton Point Station” (March 25, 2002) (hereinafter “SAIC Report (March 25, 2002)”), p. 12.

131 See SAIC Report (March 15, 2002), Table 5.

4-40 mechanical draft cooling towers for Unit 4 (the “ Helper Cooling Tower ” option).

- “Multi-mode” cooling using a 20-cell wet mechanical draft cooling tower in partially closed-cycle, helper and piggyback mode for Units 3 and 4 (the “ Enhanced MultiMode ” option).

EPA believes this range of unit-specific and multi-mode options is reasonable and appropriate in terms of thermal load reduction, cost and overall environmental impact. The unit-specific options would use cooling towers that are engineered to work with particular generating units. They include both single-unit and multiple-unit alternatives. The Closed-Cycle Unit 3 option would provide the greatest thermal discharge reduction of any possible single-unit option because Unit 3 has the highest temperature rise and design flow of the four units at BPS. 129The Closed-Cycle Units 1 or 2 & 3 option would provide an intermediate level of thermal discharge reduction and cost (as well as flow reduction). 130 The Closed-Cycle Entire Station option would offer the greatest thermal load reduction, but it is also the most expensive option and would pose the greatest non-water quality environmental and energy-related impacts. As discussed below, fitting any of these options with the capability to by-pass the cooling towers and run in once-through cooling mode might add cost in terms of piping and pumping, but it would enable the permittee to avoid generating unit outages due to vapor plume-related hazards. 131

The Helper Cooling Tower option would provide a level of thermal discharge reduction similar to that provided by the Enhanced Multi-Mode option ( i.e. , an annual heat load discharge of 28 TBTU for the Helper Cooling Tower option versus 27.2 TBTU for the Enhanced Multi-Mode option). The Enhanced Multi-Mode option would use cooling towers that could operate in either closed-cycle, “helper” or “piggyback” modes. These towers would be able to provide thermal discharge reductions even if particular generating units were not in operation because they could cool the hot water from other units that were in operation; the unit-specific cooling towers would provide no such benefit when the associated generating unit is not operating. EPA believes that the permittee should be commended for developing the Enhanced Multi-Mode option, which is a particularly flexible approach to retrofitting cooling towers to an existing, once-through cooling system. This option provides an additional point on the continuum of thermal load reductionsMA0003654 Determinations Document July 22, 2002

132 See, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-2 (“[s]ince the 1970s, a large number of successful, reliable salt water cooling towers have been installed,” mostly in southern and western United States); EPA TDD 2002 - Existing Facilities, p. 401; December 20, 2001 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA Region 1.

133 See Memorandum from Nick Prodany and Mark Stein to Brayton Point NPDES Permit File, “Notes on Telephone Call with Engineer at Canadys Station power plant in South Carolina;” December 12, 2001 memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); January 1997 NEPCO Report, p. 3-6; December 18, 2001 e-mail from Timothy Connor, EPA Headquarters, to Mark Stein, EPA Region 1.

134 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, §§ 3.3, 3.3.5, 3.3.6 and Figure 3.3-1.

135 See
, e.g. , In the Matter of Public Service Co. of New Hampshire (Seabrook Station, Units 1 and 2) , NPDES Appeal No. 76-7, 1977 WL 22370, *6 (E.P.A.), 1 E.A.D. 332 (1977) (“The effect of the remand of the steam electric generating guidelines was ... to require the

4-41 and costs for the wet mechanical draft cooling tower alternatives.

4.3.4 The Technological Availability of the Unit-Specific and Multi-Mode Cooling Tower-Based Options for Reducing Thermal Discharges from BPS

Based on its own research and analysis and on information submitted by the permittee, EPA has determined that as a general matter, mechanical draft cooling towers are technologically available for retrofitting at BPS. Such cooling towers have been designed and installed to work effectively in cooling systems using salt or brackish water, as BPS’s existing cooling system does. 132 Moreover, experience at other plants has shown that closed-cycle mechanical draft cooling towers can be retrofitted to an existing once-through power plant. 133 Indeed, as noted above, the permittee has not argued that such a retrofit would be unfeasible. Finally, EPA and the permittee agree that there is adequate space at BPS to install a closed-cycle mechanical draft cooling tower system, although space becomes increasingly limited as more cooling tower cells are added. 134 Therefore, the remainder of this determination document presents EPA’s BPJ-based analysis of what mechanical draft cooling tower technology or technologies may constitute BAT under CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3(d)(3) at BPS.

EPA currently uses BPJ to set BAT limits for thermal discharges from individual facilities in the steam electric power generating source category, which includes BPS. 135As discussed in detail inMA0003654 Determinations Document July 22, 2002

Agency to determine what is [BAT] for existing sources on a case-by-case basis under Section 402(a)(1).”).

136 See CWA §§ 301(b)(2)(A), 304(b)(2)(B), 33 U.S.C. §§ 1311(b)(2)(A), 1314(b)(2)(B).

137 CWA § 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B). See also 40 C.F.R. § 125.3(d)(3).

4-42 Section 4.2 above, BAT limits represent the minimum allowable level of treatment for toxic and non-conventional pollutants based on control techniques that are “technologically available” and “economically achievable,” and that will result in “reasonable progress” toward the elimination of the discharge of such pollutants. 136 To determine whether a particular control technique is technologically available, EPA is required to consider “the age of the equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques [and] process changes.” 137

In accordance with the CWA, EPA considers each of these factors below to determine whether one or more of the unit-specific or multi-mode wet cooling tower options described above is technologically available for BPS. It evaluates the electric power generation and existing cooling water intake and discharge processes currently employed at BPS, engineering aspects of implementing each wet cooling tower option at the plant, and the process changes that would be necessary for implementation of each option. It also evaluates how the age of the plant’s electric power generation units and existing cooling system infrastructure affects the cost and feasibility of retrofitting the various wet cooling tower options at the plant.

4.3.4a The Electric Power Generation, Cooling Water Intake and Cooling Water Discharge Processes Currently Employed at BPS

BPS covers approximately 250 acres at the confluence of the Taunton and Lee Rivers. Four fossil-fueled electric power generating units are contained in boiler and turbine houses, which are connected in line to form the power plant. Maintenance facilities, laboratories and administrative offices are attached to the east side of the plant. Three 350-foot stacks for Units 1, 2, and 3, one 500-foot stack for Unit 4, and five fuel oil storage tanks with a combined capacity of 1,386,000 barrels are located south of the plant. A nine-acre, 600,000 ton-capacity coal storage area is located east of the oil storage area. A dredged channel is located along the west side of the coal storage area for ships delivering fuel to the station.

A spray cooling canal for Unit 4 condenser cooling water was built north of the plant but is now mostly filled in with structural fill from the coal units. Within the remains of the cooling canal loop are two wastewater treatment basins. Adjacent to the canal on the west and north sides are wastewater treatment sludge disposal trenches. Also on the north side of the plant and east of theMA0003654 Determinations Document July 22, 2002

4-43 former spray cooling canal are transmission lines, which run northeasterly off the station site onto a company right-of-way.

The four boilers inside the plant (one for each unit) utilize coal, No. 6 fuel oil or gas. Units 1, 2, and 3 were put in service in August 1963, July 1964, and July 1969, respectively. They were originally designed to burn coal but were converted to burn oil in 1969. The units were converted back to burn coal in early 1982. Unit 4, designed to burn oil, was put into service in December 1974, with gas-fired capability added in 1992.

A once-through condenser cooling system with a design flow of 640,000 gpm is currently used for Units 1, 2 and 3. The condenser cooling system for Unit 4, originally closed-cycle, was converted to once-through operation with a design flow of 260,000 gpm beginning in July 1984. An additional once-through flow of 31,000 gpm is currently used by all four units for cooling water and other plant uses ( e.g. , service water).

A cooling water intake embayment for Units 1, 2 and 3 is located on the eastern side of the station and consists of six intake bays (two for each intake). Each intake bay extends to a depth of approximately 20 feet below mean sea level (msl) and is equipped with a trash rack, a traveling screen, a circulating water pump and a conduit through which water is pumped to a condenser. A design flow of 671,000 gpm of salt water (once-through cooling water plus service water) is pumped from the Units 1, 2, and 3 intake basin.

For Unit 4, an angled screen intake consisting of a reinforced concrete structure 145 feet long, with a 111.5-foot entrance width and a 61.5-foot exit width, is located on the northern side of the station. Cooling water enters this structure through eight 11-foot-wide openings that extend from 18.0 feet below msl to the bottom of a curtain wall 4.0 feet below msl, and that are shielded by trash racks. Tied-back sheet pile walls extend from each end of the trash rack faces, preventing any pocket from being formed by the structure and the shoreline that might impede fish movement. A design flow of 273,788 gpm is drawn through the bar racks. About 265,710 gpm is drawn through the screens at varying velocities, with a portion being used for screenwash; the remainder is pumped through the fish by-pass.

Condenser cooling water for each unit and service water for the station are currently discharged on the west side of the plant site and directed through a discharge channel to upper Mount Hope Bay. The 3,200-foot long discharge channel terminates at the southern tip of the plant site at a venturi designed to promote rapid mixing with the surrounding cooler water. A barrier net has been installed near the end of the discharge channel in a sometimes unsuccessful effort to blockMA0003654 Determinations Document July 22, 2002

138 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 2- 1 to 2-7; SAIC Report (March 15, 2002), pp. 2 to 4.

139 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-2.

4-44 fish from entering the channel from Mount Hope Bay. 138

4.3.4b Engineering Aspects of Implementing the Unit-Specific and MultiMode Cooling Tower-Based Options at BPS

In the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee describes the basic design of a mechanical draft cooling tower system that could be implemented to disperse waste heat to the atmosphere at BPS, whether in closed-cycle, helper or multi-mode operation. In this cooling tower design:

- Water from the condenser of each affected generating unit would be pumped to one or more multi-cell induced-draft counter-flow towers, to an elevation of about eight feet above the tower air inlet located on the periphery of the tower cells.

- The heated water would be distributed evenly and dispersed over the top of a heat transfer section in each tower cell. It then would fall by gravity through the heat transfer section into a basin at ground level, where it would be collected and either returned to the condensers or discharged to the discharge canal.

- As the heated water flows down in a film on the surfaces of the heat transfer fill section, it would be cooled by air contact and evaporation of a small portion of the water into the ambient air, which would be simultaneously induced to flow upwards in the opposite direction of the falling water.

- In each cell, this upward airflow would be produced by the action of a large-diameter induced-draft fan situated above the heat transfer section and drift eliminators. A large electrical motor would drive each of the fans.

- After passing through the tower cell’s heat transfer section, the air would move through drift eliminators where almost all of the entrained droplets of circulating water would be removed for return to the tower basin. The air would exhaust from the tower at a temperature slightly below that of the initial condenser discharge. 139

As the permittee explains, it is “[t]he method of piping the cooling tower to the existing circulating water system to receive heated water and discharge cooled water [that] determinesMA0003654 Determinations Document July 22, 2002

140 Id.

141 See id.

4-45 whether it is a conventional closed-cycle tower, a helper tower or a multi-mode tower.” 140 In a full or partial closed-cycle configuration, the cooling tower would be permanently connected to one or more of the generating units at the plant and thus would be an integral operating component of the unit or units; in a helper configuration, rather than being connected to any of the generating units, the same tower would be an add-on at the end of the cooling cycle, while in a multi-mode configuration, the tower would be connected to one or more of the generating units but not in a permanent manner, thus allowing power production even when the tower is shut down. 141

Each of the unit-specific and multi-mode options considered below for BPS incorporates this basic wet cooling tower design.

i. The Closed-Cycle Unit 3 Option

The Closed-Cycle Unit 3 option involves converting Unit 3 to closed-cycle cooling by installing a 22-cell mechanical draft cooling tower. This tower would be arranged in two rows of cells, 11 cells each back to back, and located on the elevated structural fill area north of the generating units and west of the transmission lines. It would be of the induced-draft, counter-flow design described above and would have the following design parameters:

- Flow 280,000 gpm - Water inlet temperature 103.5oF - Water outlet temperature 85oF - Ambient temperature 77oF wet bulb - Sea water Filtered but not chemically treated

The Unit 3 cooling tower circulating water system would operate by gravity from the cooling tower basins, through the condensers to a pumping facility downstream of the condensers that would pump the heated discharge back to the cooling tower fill to be cooled. According to the permittee, the gravity flow configuration would be necessary so as not to exceed design pressures of the condensers and existing circulating water conduit, which would be used to the maximum extent in the converted systems.

The cooling tower fill would be made of polyvinyl chloride (PVC) and be a low-fouling or open type. The circulating water distribution system would be located just above the fill. It would be an array of headers and laterals with spray nozzles designed to evenly distribute heated water to the fill with a minimum hydraulic head loss. The system would be low-pressure, with an openMA0003654 Determinations Document July 22, 2002

4-46 basin, flume-box or several standpipes to avoid overpressurization. The spray nozzles would be large enough to prevent fouling.

The drift eliminator would be located above the circulating water distribution system. It would be a layer of PVC louvers, designed to prevent droplets of hot water from being carried out with the air flow. Above the drift eliminator would be the plenum, roofed by the fan deck. The fan deck would support the fan, fan stack and driving motor. The motor would be located outside of the fan stack on the fan deck and would be mechanically connected to a right-angle gear box at the center of the fan stack on which the fan hub is mounted. The fan would draw the moist air up from the plenum and exhaust it through the stack. The following are key fan data:

- Number of fans: 22 - Fan motor rating: 200 hp - Total fan power: 3,300 kW - Fan diameter: 28 ft - Fan stack discharge diameter: 32 ft - Design fan air flow: 1,365,000 ft3/min per fan

The cool water would flow by gravity from the cooling tower basin to condenser inlet conduits. The required basin curb elevation would be +40 ft msl to provide adequate head for gravity flow through the condenser. The required basin minimum depth would be five feet to provide four feet of working water level depth and one foot of freeboard above maximum level.

Freeze protection for cold weather operation would be provided by a cooling tower by-pass system in the cooling tower. The tower by-pass system would consist of two motor-operated butterfly valves that would allow heated water from the supply headers into the basin without its passing through the water distribution system or fill. In cold weather, natural convection from the basin may provide sufficient cooling to run Unit 3 without the use of the fill and operation of the fans. In addition, the warmth of the natural convection would prevent ice damage in the fill and distribution system.

The plan dimensions of the Unit 3 cooling tower would be approximately 594 feet long by 108 feet wide. The structural fill on which the cooling tower would be built is at grade elevation +30 feet msl. The tower basin would extend ten feet above grade. The height of the tower would be 41 feet from basin curb to fan deck, plus 14 feet for the fan stack. The total cooling tower height would therefore be 65 feet above grade and the top of the fan stack would be at elevation +95 feet msl. Approximately three feet of additional structural fill would be required under the cooling tower basin to support the tower at the required elevation.

Make-up and blow-down flow using salt water are calculated to maintain concentration in theMA0003654 Determinations Document July 22, 2002

142 Closed-cycle cooling towers require the continual addition of “make-up” water to the cooling cycle to replace the water lost to the evaporative cooling process and to maintain water chemistry. According to the permittee, in the case of salt water closed-cycle cooling towers, make-up flow must be three times the maximum predicted evaporation rate to maintain concentration of impurities in the cooling cycle to 1.5 times or less to prevent scale formation in the system. With fresh water or gray water closed-cycle cooling towers, concentrations of impurities can be higher, reducing the volume of make-up water needed. See id. at p. 3.3-1.

The permittee evaluated two potential sources of make-up water for the closedcycle cooling options it evaluated in the December 2001 USGenNE 316(a) and (b) Demonstration: seawater from Mount Hope Bay, and treated sewage effluent (“gray water”) from the Fall River, Massachusetts publicly owned treatment works (POTW). The Fall River POTW discharges an average annual daily flow of approximately 20 MGD to Mount Hope Bay that could be used for cooling water purposes. The POTW is located across the bay, and construction of a pipeline to transport the gray water to the plant would be required. The permittee concluded that such a pipeline would be feasible. See id. , pp.3.3-1, 3.3-20 to 3.3-24. EPA, however, believes it could raise sensitive environmental issues and permitting uncertainties.

The permittee ultimately concluded that while both cooling towers and support facilities for the gray water option could be accommodated in the BPS site layout, the Fall River POTW would not be able to provide enough gray water to support full power, full closed-cycle operation for the entire station in the summer months. It could provide enough gray water during the summer months to support Units 1 and 2 alone closed-cycle, Unit 3 alone closed-cycle, or Unit 4 alone closed-cycle, but not any combination of these cooling options. The permittee concluded that this was a fatal flaw for the gray water make-up water option. In addition, the permittee estimates that this option would add an additional $29 million in capital costs. EPA believes that the gray water option could provide some potential benefits for reducing water withdrawals from Mount Hope Bay. Nevertheless, based on current information, we are not convinced that the option is feasible because of the limited and variable volume of gray water available from the POTW (especially during the summer), and the permitting and environmental issues related to the pipeline crossing of the bay. See id. , pp. 3.3-21 to 3.3-22.

4-47 circulating water at 1.5 cycles of concentration or less. 142 The design meteorological conditions are 77oF and 50% relative humidity. Required make-up water flow would be 15,000 gpm, while required blow-down flow would vary from 10,000 to 15,000 gpm depending on unit load and meteorological conditions.

Unit 3 currently uses 290,000 gpm of cooling and service water from Mount Hope Bay. Most of this water is used for once-through cooling. Converting Unit 3 to closed-cycle cooling using a wet mechanical draft cooling tower as the permittee has described would reduce the total Unit 3MA0003654 Determinations Document July 22, 2002

143 See id. , pp. 3.3-9 to 3.3-14.

144 See SAIC Report (March 25, 2002), pp. 6-7, 9-12 and Figure 3.

145 See id. , p. 19 (Table 8).

146 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3.3-3 to 3.3-8, 3.3-15 to 3.3-19.

The permittee notes that in its proposal for converting the entire station to closedcycle cooling, the closed-cycle cooling system for each unit is designed so that its installation

4-48 intake flow to 25,000 gpm of makeup and service water flow from Mount Hope Bay, which would correspond to a 28% reduction in the total potential station circulating cooling water flow. The permittee estimates that the Closed-Cycle Unit 3 option would reduce the total annual heat discharge from BPS to 23 TBTU , which would constitute a 45% reduction from the current discharge under MOA II. 143

ii . The Closed-Cycle Units 1 or 2 & 3 Option

The Closed-Cycle Units 1 or 2 & 3 option involves installing a 15-cell mechanical draft cooling tower at Unit 1 or 2 and a 22-cell mechanical draft cooling tower at Unit 3.

EPA developed this option with the expert assistance of its consultant SAIC for the purpose of comparing it with the other unit-specific and multi-mode cooling tower-based options under consideration as potential BAT for reducing thermal discharges from BPS. To the greatest extent possible, SAIC used the same design parameters to develop the Closed-Cycle Units 1 or 2 & 3 option that the permittee used to develop the Closed-Cycle Unit 3 option (discussed above) and the Closed-Cycle Entire Station option (discussed below) presented its December 2001 USGenNE 316(a) and (b) Demonstration. 144

Retrofitting Units 1 or 3 and Unit 3 with closed-cycle mechanical draft cooling towers would reduce the total annual heat discharge from BPS to Mount Hope Bay to 14 TBTU , which would constitute a 66% reduction from the current discharge under MOA II. 145

iii. The Closed-Cycle Entire Station Option

The Closed-Cycle Entire Station option involves installing a 30-cell mechanical draft cooling tower at Units 1 and 2, the 22-cell mechanical draft cooling tower described above at Unit 3, and a 20-cell mechanical draft cooling tower at Unit 4. 146MA0003654 Determinations Document July 22, 2002

would not interfere with the conversion of the other units to closed-cycle cooling. See id. , p. 3.3- 25. This one-by-one approach to converting all four units to closed-cycle cooling may increase the costs for such general construction tasks as mobilizing equipment to the site and performing necessary grading work by up to four times, because it does not consider the cost and efficiency savings that could be achieved by mobilizing for and performing all the construction tasks at the same time.

4-49 Units 1 and 2. The Units 1 and 2 tower would be located on the elevated structural fill area north of the generating units and west of the transmission lines. It would be arranged in two rows of cells, 15 cells each back to back; the easterly row of cells would serve Unit 1, and the westerly row would serve Unit 2. The tower would be of the induced-draft, counter-flow design described above and would have the following design parameters:

- Flow 360,000 gpm - Water inlet temperature 97.2oF - Water outlet temperature 85oF - Ambient temperature 77oF wet bulb - Sea water Filtered but not chemically treated

The Units 1 and 2 cooling tower circulating water system would be designed and operated in the same manner as the Unit 3 cooling water circulating system, i.e. , by gravity from the cooling tower basins, through the condensers, to a pumping facility downstream of the condensers that would pump the heated discharge back to the cooling tower fill to be cooled. One exception would be the fans, of which there would be 30 with a total fan power consumption of 4,500 kW. Freeze protection for cold weather operation would be provided by the same type of cooling tower by-pass system as in the Unit 3 cooling tower.

The plan dimensions of the Units 1 and 2 cooling tower would be approximately 810 feet long by 108 feet wide. As with the Unit 3 cooling tower, the total height of the Units 1 and 2 cooling tower would be 65 feet above grade, and the top of the fan stack would be at elevation +95 feet msl.

As with the Unit 3 tower, make-up and blow-down flow using salt water are calculated to maintain concentration in the circulating water at 1.5 cycles of concentration or less. The design meteorological conditions are 77oF and 50% relative humidity. Required make-up water flow would be 4,500 gpm per unit for a total make-up water flow of 9,000 gpm. Required blow-down flow would vary from 3,000 to 4,500 gpm per unit depending on unit load and meteorological conditions.

Units 1 and 2 currently use 376,000 gpm of cooling and service water from Mount Hope Bay.MA0003654 Determinations Document July 22, 2002

147 See id. , pp. 3.3-3 to 3.3-4, 3.3-6.

148 Id. , p. 3.3-9.

149 See id. , pp. 3.3-15, 3.3-16 to 3.3-17.

4-50 Most of this water, about 96%, is used for once-through cooling. Converting Units 1 and 2 alone to closed-cycle cooling using a wet mechanical draft cooling tower would reduce the total Units 1 and 2 intake flow to 25,000 gpm of makeup and service water flow from Mount Hope Bay, which would correspond to a 38% reduction in the total potential station circulating cooling water flow. It would reduce the total annual heat discharge from BPS to 25 TBTU , which would constitute a 40% reduction from the current discharge under MOA II. 147

Unit 4. The Unit 4 tower would be arranged in two rows of cells, 10 cells each back to back, and located on the elevated structural fill area north of the generating units and west of the transmission lines. It would be of the induced-draft, counter-flow design described above and would have the following design parameters: 148

- Flow 260,000 gpm - Water inlet temperature 103oF - Water outlet temperature 85oF - Ambient temperature 77oF wet bulb - Sea water Filtered but not chemically treated

The Unit 4 cooling tower circulating water system would be designed and operated in a similar manner as the Unit 1, 2 and 3 cooling water circulating systems. Cool water would flow by gravity from the cooling tower basin into and through the Unit 4 circulating water system andcondenser, and then be discharged into the Units 1-2-3 discharge canal to the east of the tribridge; this heated discharge would then be recirculated under tri-bridge arm B through the cooling channel and to the intake for the cooling tower pumping facility, which would pump it back to the cooling tower fill to be cooled. One difference between the Unit 4 cooling tower and the Units 1, 2 and 3 towers would be the fans, of which there would be 20 with a total fan power consumption of 3,000 kW. In addition, the existing Unit 4 circulating water pump structure would be used; however, the installation of new pumps with higher head would be required to pump the heated water up to the cooling tower fill. Freeze protection for cold weather operation would be provided by the same type of cooling tower by-pass system as in the Units 1, 2 and 3 cooling towers. 149

The plan dimensions of the Unit 4 cooling tower would be approximately 540 feet long by 108 feet wide. As with the Units 1, 2 and 3 cooling towers, the total height of the Unit 4 cooling tower would be 65 feet above grade, and the top of the fan stack would be at elevation +95 feet msl.MA0003654 Determinations Document July 22, 2002

150 Id. , pp. 3.3-3 to 3.3-4, 3.3-6.

151 Id. , p. 3.3-25.

4-51 As with the Units 1, 2 and 3 towers, make-up and blow-down flow using salt water are calculated to maintain concentration in the circulating water at 1.5 cycles of concentration or less. The design meteorological conditions are 77oF and 50% relative humidity. Required make-up water flow would be 15,000 gpm, while required blow-down flow would vary from 10,000 to 15,000 gpm per unit depending on unit load and meteorological conditions.

Unit 4 currently uses a maximum of 260,000 gpm of cooling and service water from Mount Hope Bay. Converting Unit 4 alone to closed-cycle cooling using a wet mechanical draft cooling tower would reduce the total Unit 4 intake flow to 25,000 gpm of makeup and service water flow from Mount Hope Bay, which would correspond to a 26% reduction in the total potential station circulating cooling water flow. It would reduce the total annual heat discharge from BPS to 36.6 TBTU , which would constitute a 13% reduction from the current discharge under MOA II. 150

Entire Station . Retrofitting the entire station with closed-cycle mechanical draft cooling towers would reduce the total BPS intake flow from 931,000 gpm to 39,000 gpm, or a 96% reduction in the total potential station circulating cooling water flow. It would nearly eliminate the total annual heat discharge from BPS to Mount Hope Bay, reducing it to 0.8 TBTU at a maximum temperature of 85 °F , which would constitute approximately a 98% reduction from the current discharge of 42 TBTU allowed under MOA II. 151

iv. The Helper Cooling Tower Option

The Helper Cooling Tower option involves installing a 48-cell mechanical-draft cooling tower complex both to “help” in cooling the discharge of Units 1, 2 and 3 and to precool the discharge water supplying the Unit 4 condenser. The tower complex would remove about 69% of the total potential station circulating water flow discharge from the discharge canal, cool it through an approximate 16oF temperature increase range, and return it to the discharge canal.

The Helper Cooling Tower complex would consist of four back-to-back fiberglass mechanicaldraft towers, with both a shoreline and a Unit 4 pumphouse. The tower would be of the induceddraft, counter-flow design described above and would be located in a nine-acre area south of the plant. There would be 48 fans with a total fan power consumption of 7,160 kW. Freezeprotection for cold weather operation would be provided by the same type of cooling tower bypass system that would be used for Unit 4 in the Closed-Cycle Entire Station option.

Each tower would be 110 feet wide by 325 feet long, with a fan deck elevation of 40 feet and aMA0003654 Determinations Document July 22, 2002

152 See id. , pp. 3.2-15, 3.2-17, 3.2-18.

4-52 fan stack height of ten feet. All four towers would be located behind an earthen berm back from the eastern shore of the existing discharge canal. Because the average elevation of this area is about 35 feet, approximately 250,000 cubic yards of earth would have to be removed in order to locate the towers at the required elevation of approximate grade elevation 18.0 feet. This earth would be used to create the earthen berm as well as other barriers or roadways that would aid in visually blocking the towers. In addition, the permittee would construct double casing siding on the western face of the towers and a low noise attenuation wall atop the berm to mitigate the visual presence of the towers from the Swansea shore.

Retrofitting the Helper Cooling Tower option at BPS would reduce the total station intake flow by 374.5 mgd, which would be a 29% reduction in the total potential station circulating cooling water flow (or equivalent to eliminating the flow of the Unit 4 circulating water system). It would reduce the total annual heat discharge from BPS to Mount Hope Bay to 27.2 TBTU , which would constitute a 35% reduction from the current discharge under MOA II. 152

v. The Enhanced Multi-Mode Option

The Enhanced Multi-Mode option involves installing a 20-cell fiberglass mechanical draft cooling tower and connecting circulating water piping that would operate together either as a closed-cycle tower for Unit 4 and helper tower for Units 1 and 2, or as a closed-cycle tower for all or part load on Unit 3 when Unit 4 is not operating or is operating at reduced load.

The 20-cell tower would be arranged in two rows of ten cells each and located on the structural fill area north of the generating units and west of the transmission lines. It would be of the induced-draft, counter-flow design described above and would have the following design parameters:

- Flow 260,000 gpm - Water inlet temperature 107oF - Water outlet temperature 85oF - Helper flow 40,000 gpm - Ambient temperature 77oF wet bulb - Sea water Filtered but not chemically treated - Sea water salinity 30,000 parts per million (ppm) or less

The fans would be similar to those used in the unit-specific closed-cycle options, except that there would be 20 of them, with a total fan power consumption of 4,000 kW. The total cooling tower height would be 68 feet above grade, and the top of the fan stack would be at elevation +98MA0003654 Determinations Document July 22, 2002

153 See id. , pp. 3.1-1 to 3.1-2, 3.1-15 to 3.1-16.

154 See SAIC Report (March 15, 2002), Table 3.

4-53 feet msl. The plan dimensions of the cooling tower would be approximately 540 feet long by 108 feet wide. 153

The Enhanced Multi-Mode option would allow for system operation in several different modes:

- Effectively closed loop on Unit 4 (Modes 1A and 1C).

- Effectively closed loop on Unit 3 (Mode 1B).

- Helper Cooling on Units 1 and 2 (Mode 1D).

- Piggyback Operation on Unit 4 (Modes 2 and 3).

- Once-through cooling for units operating (Modes 3 and 4).

The following table summarizes these operating modes: 154

Table 4.3 -1: Enhanced Multi-Mode Option -- Modes of Operation

Mode Tower

Operational Unit 4

Operational Unit 3

Operational Unit 4

Closedcycle ClosedCycle Unit 3 Units 1 & 2

Helper Unit 4

Piggy Back Unit 4 Intake

Operational

1A X X X X

1B X X X
1C X X X

1D X X

2 X X
3 X X X X

4 X X X X X

In Mode 1, the cooling tower would be fully operational in either closed-cycle or helper mode. In Mode 2, the cooling tower would not operate, and Unit 4 would operate in piggyback mode using the cooling water discharge from Units 1, 2 and 3. In Mode 3, the cooling tower would not operate, and the Unit 4 intake would operate to limit the discharge temperature. In Mode 4, the tower and the Unit 4 intake would both operate. The plant would operate most of the time inMA0003654 Determinations Document July 22, 2002

155 Id. , pp. 6 to 7.

156 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3.1-17 to 3.1-19.

157 See SAIC Report (March 15, 2002), p. 7.

158 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3.1-1, 3.1-16 to 3.1-18.

159 Details about necessary piping, duct-line, cable trays and grading for the Enhanced Multi-Mode option are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.1-4 to 3.1-5. In addition, the permittee proposes construction of a

4-54 Mode 1, with the other modes being used only infrequently. 155In closed-cycle tower mode, the cooling tower would receive 260,000 gpm of heated water that could be completely from Unit 4, completely from Unit 3, or a combination of the discharge from both Unit 3 and Unit 4. When Unit 3 and Unit 4 are not operating, the cooling tower could receive a portion of Unit 1 and Unit 2's heated discharge in helper mode. 156

More particularly, the Enhanced Multi-Mode option follows a hierarchy in which cooling water from the cooling tower would be used to cool Unit 4, and would only be used to cool Unit 3 if Unit 4 was not operating or was not utilizing the full cooling capacity of the cooling tower. Thus, it would not be feasible for both Units 3 and 4 to operate in closed-cycle at the same time. The Unit 4 intake would only be operational when both Units 3 and 4 are operational and either the cooling tower is not operating (Mode 3) or Unit 4 is not operating in piggy-back mode (Mode 4). It should be noted that according to the permittee, operation of the Unit 4 intake in Mode 3 is necessary only when the total plant effluent exceeds thermal limits. Operation in Modes 3 and 4 is estimated to occur infrequently (<500 hours/year). 157

According to the permittee, the Enhanced Multi-Mode option achieves operational flexibility by providing not only this ability to operate in different cooling modes, but also both the ability to shut down the cooling tower and still allow BPS to continue generate power, and the ability to operate the cooling tower as a cooling system for the entire station and not just a particular unit, as in a conventional closed-cycle design. 158

In all modes of operation provided by the Enhanced Multi-Mode option, the cooling tower inlet water would come from a common area in the discharge canal. The tower would operate in an “open loop,” so that the salinity in the tower would be only slightly above the salinity of the once-through cooling water, so no make-up water system would be required. The permittee proposes the use of conventional construction materials suitable for seawater conditions. 159MA0003654 Determinations Document July 22, 2002

new road for cooling tower access, which would also serve as a dike or berm to contain spillover from the cooling tower basin. See id. , p. 3.1-5.

160 See id. , p. 3.2-15, 3.2-17, 3.2-18.

4-55 USGenNE estimates that the Enhanced Multi-Mode option would reduce annual thermal discharge to 28 TBTU per year, which would constitute a 33% reduction from the current discharge under MOA II. 160

The chart below presents a comparison of the unit-specific and multi-mode cooling tower-based options that EPA believes warrant further detailed consideration. It also presents the existing NPDES permit and MOA II for the sake of comparison. The chart looks only at the annual thermal rejection to Mount Hope Bay associated with each option. Ultimately, the permit may also address these parameters with daily, monthly, and/or seasonal limitations. Nevertheless, this chart provides a useful gross comparison.

Table 4.3-2: Flow Rate and Heat Load Comparison Chart Operating Scenario Flow Rate (MGD) Annual Heat Load Discharge (TBTU)

Current Permit 1452 97

MOA II 977 42 Closed-Cycle Unit 3 654 22.9
Closed-Cycle Units 1 or 2 & 3 350 14

Closed-Cycle Entire Station (Units 1, 2, 3 and 4) 56 (Intake) 0.8

Helper Cooling Tower 925 (summer) 27.2
Enhanced Multi-Mode (20- cell cooling tower) 650 (annual) (750(summer)/600 (winter)) 28

4.3.4c Age of the Equipment and Facilities Involved in Implementing the Unit-Specific and Multi-Mode Cooling Tower-Based Options at BPS

The permittee’s 1997 feasibility report concluded that retrofitting closed-cycle cooling at BPS would be a “difficult engineering, design, scheduling, and construction effort due to itsMA0003654 Determinations Document July 22, 2002

161 Id. , p. 3.3-1.

162 Id.

163 See SAIC Report (March 15, 2002), p. 26 and Attachment A.

4-56 incompatibility with the original station design.” 161 The permittee identified several primary reasons for the complexity of such a retrofit project, including:

- The permanence of existing site features and structures.

- The “fundamental technical differences and incompatibilities” between closed-cycle cooling systems and BPS’s existing once-through cooling system, e.g. , the existing condensers having a maximum design pressure of about 25 psig and closed-cycle condensers having a design pressure of 80 to 90 psig.

- The “difficult canal construction work that would be necessary to accommodate the plant operational requirements.”

- The complexity and cost of construction access and flow of job site erection materials due to the “very limited open space” available at BPS and “the topography in the vicinity of the area” proposed for siting the wet cooling towers. 162

All of these considerations arguably relate to the age of the plant ( i.e. , “the equipment and facilities involved”) in that they need to be addressed because BPS is an existing plant that would require retrofitting, not a new plant at which any potential difficulties could be resolved during the planning process and prior to construction. As the permittee points out, the fact that BPS is already built means that any retrofit project there would need to take into account not only the once-through cooling system components that are already in place and in use at the site, but also the other site structures and features that already exist there, and the limited open space available at the site as a result of those structures and features that are already present.

EPA agrees with the permittee’s observation that retrofitting the Closed-Cycle Unit 3 and ClosedCycle Entire Station options at BPS would be a “difficult engineering, design, scheduling, and construction effort due to [their] incompatibility with the original station design.” EPA notes, however, that the permittee does not assert that such a retrofitting project would be infeasible due to any of these considerations. Moreover, in its research for the CWA § 316(b) Phase II Existing Facility proposed rule, EPA identified several other large power plants that have converted from once-through cooling to closed-cycle mechanical draft towers. 163

4.3.4d Process Changes Required to Implement the Unit-Specific and Multi-MA0003654 Determinations Document July 22, 2002

164 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3- 9.

165 See id. , pp. 3.3-10 to 3.3-11. Details about circulating water pump house construction and piping for the Closed-Cycle Unit 3 option are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.3-11 to 3.3-12.

4-57 Mode Cooling Tower-Based Options at BPS

i. The Closed-Cycle Unit 3 Option

As noted above, a 22-cell mechanical draft cooling tower would be required to convert Unit 3 to closed-cycle cooling. Aside from the installation of the tower itself, the primary process change that would be required for the Closed-Cycle Unit 3 option would be the construction of a newcirculating water pumping structure downstream of the unit’s existing condenser. The ClosedCycle Unit 3 cooling tower circulating water system would operate by gravity from the cooling tower basin through the condenser to this pumping structure, which would pump the heated discharge back to the cooling tower fill to be cooled. According to the permittee, this gravity flow configuration would be necessary in order not to exceed design pressures of the unit’s existing condensers and circulating water conduits. 164

As the permittee explained in the December 2001 USGenNE 316(a) and (b) Demonstration, in a standard cooling tower circulating water system, the circulating water pumps are located at the cooling tower basin and pump cooled water from the basin through the condenser and back up to the cooling tower fill. However, retrofitting a closed-cycle configuration at Unit 3 would require much more pump head than currently exists with the unit’s once-through siphon systems. That is, Unit 3's existing circulating water system and condenser are not designed for the higher pressures that would be generated in this closed-cycle configuration.

For the Closed-Cycle Unit 3 option, therefore, the permittee has proposed to construct new cooling tower pumphouses downstream of the existing condensers, to the north of the turbine buildings in the vicinity of the seal pits. This would require only the new piping from the pumps to the cooling tower, and not the existing circulating water conduits, piping and condenser, to be designed to withstand the higher pressures generated by the new cooling tower pumps. The seal pits would be demolished, because they would not serve any function in the closed-cycle cooling system, and they would be in the way of the new suction piping to the circulating water pumps. 165

ii . The Closed-Cycle Units 1 or 2 & 3 Option

As noted above, the Closed-Cycle Units 1 or 2 & 3 option would require installation of a 15-cell mechanical draft cooling tower at Unit 1 or 2 and a 22-cell mechanical draft cooling tower at UnitMA0003654 Determinations Document July 22, 2002

166 See SAIC Report (March 25, 2002), pp. 6-7, 9-12 and Figure 3.

167 See id. , pp. 3.3-3 to 3.3-8, 3.3-15 to 3.3-19.

168 See id. , pp. 3.3-4 to 3.3-5. Details about circulating water pump structure construction and piping for Units 1 and 2 are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.3-5 to 3.3-6.

4-58 3. To the greatest extent possible, SAIC used the same design parameters in developing this option that the permittee used to develop the Closed-Cycle Unit 3 option and the Closed-Cycle Entire Station option presented its December 2001 USGenNE 316(a) and (b) Demonstration. 166 Therefore, the process changes required to implement this option at BPS are the same as the process changes that would be required for the Closed-Cycle Unit 3 option (discussed above) and the Unit 1 or Unit 2 portion of the Closed-Cycle Entire Station option (discussed below).

iii. The Closed-Cycle Entire Station Option

The Closed-Cycle Entire Station option involves installing a 30-cell mechanical draft cooling tower at Units 1 and 2, the 22-cell mechanical draft cooling tower described above at Unit 3, and a 20-cell wet mechanical draft cooling tower at Unit 4. 167

As with Unit 3, the primary process change that would be required to retrofit Units 1 and 2 with closed-cycle cooling, aside from installation of the 30-cell wet cooling tower, would be the construction of new circulating water pumping structures downstream of the units’ existing condensers. This is because, as with Unit 3, operating retrofitted closed-cycle cooling at Units 1 and 2 would require more pump head than currently exists with the two units’ once-through siphon systems, and the units’ existing circulating water systems and condensers are not designed for the higher pressures that would result from this closed-cycle configuration. The new pumping structures would be constructed in the same area as the new Unit 3 pumping structure, downstream of the existing condensers, to the north of the turbine buildings near the seal pits. 168

A similar process change would be necessary to retrofit Unit 4 with closed-cycle cooling, with the installation of new circulating water pumps with higher head required to pump the heated water up to the cooling tower fill; however, the existing Unit 4 circulating water pumping structure would be used instead of building an entirely new pumping structure. New vertical wet-pit-type circulating water pumps would replace the existing Unit 4 pumps to provide the required additional head; the existing Unit 4 inlet conduits would be blocked at the pumping structure, and connections between the existing supply conduits to the condenser and a new return header fromMA0003654 Determinations Document July 22, 2002

169 See id. , pp. 3.3-15, 3.3-16. Details about circulating water pump house construction and piping for Unit 4 are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.3-16 to 3.3-17.

170 Id. , p. 3.3-17.

171 Id. , pp. 3.2-15, 3.2-17, 3.2-18.

4-59 the cooling tower basin would be made downstream of these blocks. 169According to the permittee, minimal modifications to the existing Unit 4 pumping structure would be required. 170

iv

. The Helper Cooling Tower Option

The Helper Cooling Tower option involves installing four back-to-back fiberglass mechanicaldraft towers, a shoreline pumphouse to “help” in cooling the discharge of Units 1, 2 and 3, and a Unit 4 pumphouse to precool the discharge water supplying the Unit 4 condenser. 171

The four cooling towers would be located centrally to the shoreline pumphouse along the plant side of the existing discharge channel. This pumphouse would be designed to draw 620,000 gpm of heated water from the discharge channel and convey it to the cooling towers by means of four vertical wet-pit pumps. The basins of the towers would all be interconnected, either directly or by flumes. This would enable the cooled water from all the tower basins to flow to the southerly tower and be discharged back into the existing discharge channel via a common open channel flume at the south end of the most southerly tower. There, the cooled water would mix with and cool the 280,000 gpm remaining warm circulating water flow from the plant condensers before all the water exited from the discharge channel into Mount Hope Bay.

According to the permittee, the mixing of these two temperature streams and the cooling of the plant discharge would be assured for three reasons: the turbulence of the open channel flume as it intercepts the main plant flow; the lesser buoyancy of the colder cooling tower stream, which would inherently promote instability and mixing; and the length of the remaining run of discharge channel, which would provide a relatively long residence time for the combined flows before their discharge into the bay.

In addition, the basin of the northerly tower would be connected and supply cooled water to theUnit 4 condenser. A pumphouse at the end of the most northerly tower would contain two wetpit circulating water pumps with two discharges, which would be routed to tie into the separate lines that currently serve each condenser box. The northern two towers would discharge 260,000 gpm of their total 310,000 gpm flow into this new pumphouse, from which the flow then would be pumped to Unit 4. To accomplish this, two new fiberglass circulating water lines would be installed from the pumphouse and extend about 400 feet to a new reinforced concrete box tunnelMA0003654 Determinations Document July 22, 2002

172 See id. , pp. 3.2-15 to 3.2-16. Details about the cooling tower pumps and piping system for the Helper Cooling Tower option are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.2-16 to 3.2-17.

173 See id. , p. 3.1-1.

174 Id. , p. 3.1-19.

4-60 that would tie in to the existing Unit 4 box tunnel. The existing Unit 4 box tunnel would be capped and sealed in the vicinity of the new tie-in to prevent water and/or soil intrusion. 172

v. The Enhanced Multi-Mode Option

The Enhanced Multi-Mode option involves installing a 20-cell fiberglass mechanical draft cooling tower and connecting circulating water piping that would operate together either as a closed-cycle tower for Unit 4 and helper tower for Units 1 and 2, or as a closed-cycle tower for all or part load on Unit 3 when Unit 4 is not operating or is operating at reduced load. 173

When either Unit 3 or Unit 4 operates in closed-cycle mode, the cooling tower would receive 260,000 gpm of heated water delivered by the new cooling tower pumps from the eastern section of the cooling canal. Heated water entering this section of the cooling canal could be all from Unit 4, all from Unit 3, or a combination of the discharges of Units 3 and 4. Moreover, when Units 3 and 4 are not operating, a portion of the heated discharge from Units 1 and 2 could be drawn to the cooling tower pumps, passed through the cooling tower operating in helper mode, and discharged to the discharge canal at the existing Unit 3 and/or Unit 4 discharge structure. The heated discharge then would recirculate under tri-bridge arm B, through the eastern section of the inlet channel, and to the intake for the cooling tower pumps. Extending the Units 1 and 2 discharge piping would reduce the mixing of the heated discharge from Unit 3 and/or Unit 4 with the Units 1 and 2 discharge to a minimum. 174

The following provides more detail: In the Enhanced Multi-Mode option, cooled water would flow by gravity through the existing Unit 3 and/or Unit 4 circulating water system. According to the permittee, the discharge channel would be subject to tide level fluctuations, which in turn would affect the system hydraulic gradient back to the cooling tower basin and require the basin depth and water surface elevation to accommodate these varying hydraulic conditions. As a result, the cooling tower basin depth would have to be 12 feet to accommodate the eight-foot tidal range in the discharge channel, three feet of water in the basin at extreme low tide and one foot of freeboard in the basin at extreme high tide. The basin water surface elevation thus would be +41 feet to provide adequate head to drive the design flow of 260,000 gpm through Unit 4 at high tide (+3.0 feet msl). The total cooling tower height would be 68 feet above grade, and theMA0003654 Determinations Document July 22, 2002

175 Id. , p. 3.1-3.

176 See id. , pp. 3.1-18 to 3.1-19.

177 See id. , pp. 3.1-18 to 3.1-19.

4-61 top of the fan stack would be at elevation +98 feet msl. 175

The existing Unit 4 circulating water pumps would be replaced with new cooling tower pumps, which would be located in the existing Unit 4 pumping structure. New piping would be installed to carry the flow from the new cooling tower pumps to the cooling tower fill distribution system, and the existing Unit 4 inlet conduits would be blocked at the pumping structure. New piping from the cooling tower basin would connect to both the Unit 3 and the Unit 4 condenser inlet conduits; valves would be installed in the piping system from the cooling tower basin to allow cooled water from the cooling tower basin to be directed totally to Unit 3, totally to Unit 4, or a portion to each unit. 176

The Enhanced Multi-Mode option would require the conversion of the western channel of the existing Unit 4 intake canal into a mixing basin. This would both support the Unit 4 intake pump operation and accommodate discharge flows when the cooling tower is operating in helper mode. The design includes installation of new Unit 4 intake pumps, construction of a new dam into which to place these intake pumps and a discharge flume, and modification of the existing Unit 4 intake canal divider wall. In addition, the existing stop-logs in tri-bridge arm A would be removed to allow intake pump flows to discharge through the canal, and to allow discharge flows to the canal when the cooling tower is operating in helper mode.

The eastern channel of the existing Unit 4 intake canal, which is currently used for recirculation when Unit 4 is operating in piggyback mode, would continue to be used for recirculation when Unit 4 is operated in closed-cycle, helper or piggyback mode. It would also be used as the inlet canal for the new Unit 4 cooling tower pumps. The existing stoplogs in tribridge arm B would be replaced by a sliding gate of about half the total height of the stoplogs; this gate would be used to switch operations between closed-cycle mode and piggyback mode.

The existing Unit 4 discharge, south of tri-bridge arm B, would continue in use. The Unit 4 discharge to the discharge channel for Units 1, 2 and 3 would be stratified to allow withdrawal of the warmest water for cooling. The Units 1 and 2 discharge piping would be extended about 460feet along the bottom of the discharge channel to a point just east of the southern arm of the tribridge. This would allow the heated discharge from Unit 3 to flow north through the east arm of the tri-bridge and to the cooling tower pumps without significant mixing with the Units 1 and 2 discharge. 177The existing discharge channel bottom would be dredged for the conduit, to allowMA0003654 Determinations Document July 22, 2002

178 Details relating to cooling tower pumps and necessary piping, duct-line, cable trays and grading for the Enhanced Multi-Mode option are provided in the December 2001 USGenNE 316(a) and (b) Demonstration. See id. , pp. 3.1-3 to 3.1-5, 3.1-19 to 3.1-20. In addition, the permittee proposes construction of a new road for cooling tower access, which would also serve as a dike or berm to contain spillover from the cooling tower basin. See id. , p. 3.1-5.

179 See id. , p. 3.1-4.

180 Id. , p. 1-16.

4-62 passage of the Unit 3 discharge. 178

As noted above, in all modes of operation, the cooling tower inlet water would come from a common area in the discharge canal. The tower would operate in an open loop, so that the salinity in the tower would be only slightly above the salinity of the once-through cooling water. Conventional construction materials suitable for seawater conditions could be used, and there would be no need for a make-up water system. 179

4.4 The Economic Achievability of the Unit-Specific and Multi-Mode Cooling TowerBased Options for Reducing Thermal Discharges from BPS

4.4.1 Background

The permittee has submitted substantial information regarding its estimates of the capital, operation and maintenance (O&M), and other direct and indirect costs of retrofitting closed-cycle and multi-mode cooling at BPS. EPA, based on this information and on its own research and analysis, agrees with the permittee that retrofitting wet cooling towers for all or some of the generating units at BPS would be a complicated construction project involving substantial cost. The complexity and cost would be greatest for retrofitting the entire plant with closed-cycle cooling and correspondingly less for the partial closed-cycle and multi-mode retrofit options.

In particular, the permittee has identified several specific issues relating to the economic impacts of retrofitting wet cooling towers for all or some of the generating units at BPS. First, according to the permittee, converting BPS to closed-cycle cooling from open-cycle cooling would result in “lost annual generation,” which refers to “the quantity of additional energy that the pumps and fans and other operating equipment require to power the components of cooling technology.” 180 EPA agrees that switching BPS from open-cycle cooling to closed-cycle cooling would marginally decrease the generating efficiency of each converted unit, resulting in a so-called “efficiency penalty.” EPA also agrees that the amount of electricity that a converted unit would generate for sale would be further reduced because a certain amount of energy would have to beMA0003654 Determinations Document July 22, 2002

181 See EPA TDD 2001 - New Facilities, pp. 3-9 to 3-21 and Table 3-2.

182 See 39 Fed. Reg. 36192 (October 8, 1974).

183 See
, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3.

4-63 used to run the fans and pumps utilized in the related mechanical draft cooling tower, resulting in a so-called “auxiliary power penalty.” 181 Each of these penalties would be proportionally less if less than the entire plant were converted to closed-cycle cooling. The permittee has attributed a cost to these penalties, and EPA has considered these components of the cost of retrofitting wet cooling towers at BPS in its economic achievability evaluation.

Second, the permittee asserts, BPS would have to incur a certain amount of downtime for the construction of each of the different wet cooling tower options under consideration. As with the above-described “penalties,” the permittee has attributed a cost to these “construction outages,” and EPA has considered this component of the cost of retrofitting wet cooling towers at BPS in its economic achievability evaluation. Third, as the permittee correctly notes, wet cooling towers can emit water vapor (as opposed to mist) that after leaving the tower can under certain meteorological conditions condense into water and freeze, causing fog and/or icing concerns on area roadways. In most cases, any icing conditions would be expected to occur only a short distance from the tower, typically on-site. 182 A site-specific analysis by the permittee, however, concludes that cooling towers at BPS would emit a plume of water vapor that under certain meteorological conditions could freeze on a nearby highway, requiring the permittee to shut down the affected units to ensure traffic safety. 183 The permittee has also attributed a cost to these “plume outages,” and EPA also considered this component of the cost of retrofitting wet cooling towers at BPS its economic achievability evaluation.

This determination document first presents the permittee’s estimates of the capital, O&M,efficiency and auxiliary power penalty, and construction outage costs associated with the ClosedCycle Entire Station, Closed-Cycle Unit 3 and Enhanced Multi-Mode options. (Plume outages and projected associated costs are discussed further below.) It then presents EPA’s independent analysis of these cost estimates, which the permittee provided in the December 2001 USGenNE 316(a) and (b) Demonstration. It also presents EPA’s cost estimates for the Closed-Cycle Units 1 or 2 & 3 option and for two variations on the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options: the addition of either by-pass technology to allow operation in once-through mode, or plume abatement technology. Finally, this document presents EPA’s determination of the economic achievability of the unit-specific and multi-mode wet cooling tower options under consideration.

4.4.2 The Permittee’s Estimated Costs of the Unit-Specific and Multi-ModeMA0003654 Determinations Document July 22, 2002

184 See id. , p. 3.3-13. According to SAIC, the 10% allowance for indeterminate costs and 10% contingency appear to be somewhat high but not unreasonable. Typically, contingency allowances for heavy industrial projects range between 4% and 7%. However, site-specific factors may increase these factors. See SAIC Report (March 15, 2002), p. 7.

185 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3.3-12 to 3.3-14.

186 See SAIC Report (March 15, 2002), p. 8. This calculation is based on an annual average generation of 8,633,051 MW-hr/yr for the entire station, and 4,318,412 MW-hr/yr for Unit 3, from 1997 through 1999. See id.

187 See id.

4-64 Cooling Tower-Based Options for Reducing Thermal Discharges from BPS

4.4.2a The Permittee’s Estimated Costs of the Closed-Cycle Unit 3 Option
The permittee estimates the capital cost for the Closed-Cycle Unit 3 option to be $56.4 million, including a 10% allowance for indeterminate costs and a 10% contingency. 184 Estimated annual combined maintenance costs, which include fan maintenance, cooling tower basin cleaning, cooling tower fill cleaning and maintenance and pump maintenance costs, are $155,000 per year.

In addition, the permittee estimates the combined lost annual generation from implementing the Closed-Cycle Unit 3 option to be 119,000 MW-hr/yr. This consists of 55,000 MW-hr/year of additional auxiliary power consumption and 64,000 MW-hr/year of steam turbine operating penalties. 185According to EPA calculations, the 119,000 MW-hr/yr in lost annual generation is approximately 2.8% of Unit 3 output and 1.4% of BPS output; the 55,000 MW-hr/yr in additional auxiliary power consumption is about 1.3% of Unit 3 output and <1% of BPS output, and the 64,000 MW-hr/yr in steam turbine operating penalties is about 1.5% of Unit 3 output and <1% of BPS output. 186

EPA notes that auxiliary power consumption for this option would be lower than for the Enhanced Multi-Mode option, although the operating penalty is greater. Operating a unit in closed-cycle mode causes an increase in temperature and pressure, which results in lower electricity generation. On the other hand, the Enhanced Multi-Mode option requires increased pumping, which utilizes more power. 187

Under the permittee’s proposed schedule, implementation of the Closed-Cycle Unit 3 option would take about 29 months, with one year required for permitting and engineering commencing eight months into the permitting cycle. A minimum eight-month construction outage starting 20 months into the schedule would be required, and according to the permittee, a replacement would be required for the lost generation of Unit 3 for the period when the plant is shut down forMA0003654 Determinations Document July 22, 2002

188 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3-14.

189 See id. , p. 3.3-26.

190 See SAIC Report (March 15, 2002), pp. 4, 13 (referring to EPA TDD 2001 - New Facilities).

191 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3-26.

192 See SAIC Report (March 15, 2002), p. 9. This calculation is based on an annual average generation of 8,633,051 MW-hr/yr for the entire station from 1997 through 1999. See id.

193 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3-26.

4-65 construction of the cooling tower and circulating water pumphouse. 188

4.4.2b The Permittee’s Estimated Costs of the Closed-Cycle Entire Station Option
The permittee estimates the capital cost for the Closed-Cycle Entire Station option to be $177 million, including a 10% allowance for indeterminate costs and a 10% contingency. 189It arrivedat this estimate by adding the estimated costs of converting the four individual units to closedcycle mode. As a result, the permittee likely overestimates the capital costs of the Closed-Cycle Entire Station option, because it fails to consider the economy of scale that would result from combining the component unit-specific options that make up this option. In its economic achievability analysis, which is described in detail below, EPA estimated an economy of scale of approximately 6% based on the costing methodology used in the development of the CWA § 316(b) Phase I New Facility final rule and Phase II Existing Facility proposed rule. 190

Estimated annual combined maintenance costs are $475,000 per year. In addition, the permittee estimates the combined lost annual generation to be 286,000 MW-hr/yr. 191 According to EPA calculations, this is approximately 6.6% of average annual generation. 192

Under the permittee’s proposed schedule, overall implementation of the Closed-Cycle Entire Station option would take about 47 months, with one year required for permitting and engineering commencing eight months into the permitting cycle. 193

4.4.2c The Permittee’s Estimated Costs of the Helper Cooling Tower OptionMA0003654 Determinations Document July 22, 2002

194 Id. , p. 3.2-18.

195 See id. , p. 3.1-22.

196 See SAIC Report (March 15, 2002), p. 7. This calculation is based on an annual average output of 8,633,051 MW-hr/yr for 1997 through 1999. See id.

197 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.1- 22.

198 See id. , p. 3.1-4.

4-66 The permittee estimates the capital cost for the Helper Cooling Tower option to be $98.9 million, including a 10% allowance for indeterminate costs and a 10% contingency. Estimated annual maintenance costs are $300,000 per year. In addition, the permittee estimates combined lost annual generation to be 152,148 MW-hr/year. This consists of 112,875 MW-hr/yr off additional auxiliary power consumption and 39,275 MW-hr/yr of steam turbine operating penalties.

Under the permittee’s proposed schedule, implementation of the Helper Cooling Tower option could take about 35 months, with one year required for permitting and engineering commencing seven months into the permitting cycle. Construction would commence 14 months into the schedule. Only two one-month construction outages would be required. According to the permittee, most of the required construction would not interfere with station operation. 194

4.4.2d The Permittee’s Estimated Costs of the Enhanced Multi-Mode Option
The permittee estimates the capital cost for the Enhanced Multi-Mode option to be $57.4 million, including a 10% allowance for indeterminate costs and a 10% contingency. Estimated annual maintenance costs are $240,000 per year. In addition, the permittee estimates combined lost annual generation to be 97,900 MW-hr/yr. This consists of 72,600 MW-hr/year of additional auxiliary power consumption and 25,300 MW-hr/year of steam turbine operating penalties. 195 According to EPA calculations, this is approximately 1% of average annual generation. 196

Under the permittee’s proposed schedule, implementation of the Enhanced Multi-Mode option could take about 31 months, with one year required for permitting and engineering commencing seven months into the permitting cycle. Construction would commence 15 months into the schedule. A construction outage of approximately four months duration for Unit 4, starting 27 months into the schedule, and shorter construction outages of two to three weeks for Units 1 and 2 at 19 months into the schedule and for Unit 3 at 24 months, would also be required. 197 system. 198MA0003654 Determinations Document July 22, 2002

199 See SAIC Report (March 15, 2002), p. 2.

4-67 4.4.3 EPA’s Independent Evaluation of the Permittee’s Estimated Costs of the Unit-Specific and Multi-Mode Cooling Tower-Based Options for Reducing Thermal Discharges from BPS

EPA hired two contractors, Science Applications International Corporation (SAIC) and Abt Associates, Inc. (Abt), to provide expert analysis in support of the Agency’s independent evaluation of the estimated costs of the cooling tower-based options under consideration to be BAT for reducing thermal discharges from BPS into Mount Hope Bay. These contractors addressed issues relating to what EPA has labeled the “engineering aspects” and “financial aspects” of the economic achievability analysis required under the CWA to establish BAT limits.

First, EPA retained SAIC, under subcontract to Tetra Tech, Inc., to assess “engineering aspects” of the estimated costs of the unit-specific and multi-mode cooling tower-based options under consideration. These include the capital and annual costs of each option, with annual costs including O&M costs, the cost of any reduction in electrical generation efficiency resulting from implementation of the particular option ( i.e. , the “efficiency penalty” associated with the option), and the cost of the auxiliary power needed to run the option ( i.e. , the “auxiliary power penalty” associated with the option). SAIC reviewed and evaluated the permittee’s capital and annual cost estimates for its Closed-Cycle Unit 3, Closed-Cycle Entire Station and Enhanced Multi-Mode options and compared them against published capital and O&M costs available from industry and construction standards, vendor quotes, information collected and developed in support of the 316(b) Phase I New Facility final rule and 316(b) Phase II Existing Facility proposed rule, and knowledge of experienced personnel. 199Then, SAIC developed its own independent engineering cost estimates for the permittee’s Closed-Cycle Unit 3, Closed-Cycle Entire Station and Enhanced Multi-Mode options. Finally, SAIC estimated the capital costs of equipping the cooling towers associated with the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options with the pumping and piping that would allow them to be by-passed, so that the generating units could be run in once-through mode (thus eliminating any need for generating unit shutdowns), and with plume abatement technology (based on traditional wet/dry hybrid cooling) instead of multi-mode technology.

The “engineering aspects” of the costs of the various cooling tower-based options also include the extent to which one-time power generation unit outages could be necessary to enable installation of particular cooling options ( i.e. , the “construction outage” associated with the option). SAIC evaluated this aspect of the options’ costs because the permittee’s cost estimates include the cost of the power generation lost as the result of such construction outages. Finally, SAIC evaluated the likely construction schedule for each option on the grounds that scheduling has a direct bearing on cost.MA0003654 Determinations Document July 22, 2002

200 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G (Tab: Dynamic Cost Analysis). EPA and the permittee have agreed that this type of analysis is the most accurate way to assess the cost to the permittee of each option, as opposed to, for example, the “static cost analysis” approach that the permittee had used in several submissions prior to the December 2001 USGenNE 316(a) and (b) Demonstration.

201 To generate its own independent cost estimates for EPA, Abt used “engineering cost” data from the reports that SAIC prepared. Where SAIC either did not develop an independent value or determined that the permittee’s data appeared reasonable, Abt used inputs based on the permittee’s analysis. All of this is described in detail in the Abt report. See Abt, “Cost Analysis of Alternative Technology Options for Management of Thermal Discharge and Cooling Water Intake for Brayton Point Station (April 5, 2002) (hereinafter “Abt Report”).

202 In particular, in evaluating the cost issues EPA and the contractors considered Volume III, App. G (Tab: Dynamic Cost Analysis) and Volumes IV, V and I (Executive Summary) of the December 2001 USGenNE 316(a) and (b) Demonstration.

4-68 Second, EPA retained Abt to assess “financial aspects” of the estimated costs of the unit-specific and multi-mode cooling tower-based options under consideration for BPS. In performing this assessment, Abt developed a model to determine three financially significant elements of each option: the cost to the permittee over time, the net present value of this multi-year cost, and the equivalent annualized cost. This analytical approach mirrors that which the permittee used in its “Dynamic Cost Analysis.” 200 Thus, the results of Abt’s analysis can be meaningfully compared with the results of the permittee’s analysis. 201

Abt’s analysis not only considered the capital costs and annual O&M costs for the cooling towerbased options under consideration, but also determined the cost of each of these options to thepermittee in terms of lost revenue due to reduced electrical generation. These lost generationrelated costs include both construction outages and annual losses resulting from efficiency and auxiliary power penalties. In addition, Abt’s analysis took into account the cost to the permitteeof generating unit outages that the permittee predicts would be required to address vapor plumerelated icing and fogging safety issues ( i.e. , the “plume outages” potentially associated with each option). Finally, Abt’s analysis considered the increasedrevenues that the permittee would be able to obtain based on the extent to which each option would enable increased hours of operation during peak summer demand periods as a result of reduced discharge temperatures.

With SAIC and Abt’s expert assistance, EPA carefully considered the economic analyses that the permittee presented in the December 2001 USGenNE 316(a) and (b) Demonstration. 202 We and the contractors also considered a substantial amount of additional information earlier submitted by the permittee, including, without limitation, the January 1997 NEPCO Report; various meeting handouts from the permittee, and materials submitted by the permittee in response to EPA CWAMA0003654 Determinations Document July 22, 2002

203 It should be noted that the permittee’s analysis of the cost of various cooling options has changed significantly over time. For example, the January 1997 NEPCO report estimated that the option of closed-cycle mechanical draft wet cooling towers for Unit 4 would have a capital cost of $27.8 million and result in an annual loss of 12,000 MW-hrs of electricity, whereas the December 2001 USGenNE 316(a) and (b) Demonstration estimated the capital costs for this option to be $48 million with lost annual generation of 25,000 MW-hrs.

204 Actually, Abt uncovered two calculation errors in the permittee’s Dynamic Cost Analysis. One error incorrectly reduced costs, but this reduction was more than offset by the second error, which incorrectly increased costs. Abt’s analysis corrected both errors. See Abt Report (April 5, 2002), pp. 39-40.

4-69 § 308 information request letters. 203 The latter materials include data submitted by the permittee from Resource Data International as well as information submitted with an October 16, 2001 letter from the permittee’s counsel, Wendy Jacobs of Foley, Hoag & Eliot, LLP, to Mark Stein of EPA. In addition, EPA and the contractors had several meetings and conference calls with the permittee and its consultants to discuss factual and analytical issues related to the assessment of the costs of the options. Finally, the contractors did substantial research using a variety of sources of data independent from the permittee. These independent sources are described and referenced in the contractors’ reports.

EPA has independently reviewed the reports submitted by SAIC and Abt and determined them to contain reasonable and appropriate analyses. As explained in the reports, these analyses are conservative in many important respects ( e.g. , both SAIC and Abt structured their analyses so as to produce higher cost estimates). Therefore, EPA adopts the analyses contained in the SAIC and Abt reports and incorporates these reports by reference into this BAT determination. The SAIC and Abt reports are available in the administrative record.

In general, EPA has concluded that the permittee has substantially overestimated the likely costs of the various closed-cycle and multi-mode cooling tower-based options. The primary driver for this overestimation is the permittee’s inflated capital cost predictions, but the permittee’s excessive predictions regarding construction outages, energy efficiency penalties and plume outages also materially contribute to the total overestimate. In addition, the permittee’s overestimate of the costs of the options is affected by other aspects of its financial analysis, such as its choice of discount rate, certain inappropriate tax treatments, 204 and its unrealistic use of 2001 as the starting date for construction of new facilities. Key points and conclusions from EPA’s independent evaluation are presented below.

4.4.3a “Engineering Aspects”

i. Capital CostsMA0003654 Determinations Document July 22, 2002

205 See SAIC Report (March 15, 2002), pp. 9-12.

4-70SAIC conducted an independent assessment of the capital costs of the unit-specific and multimode cooling tower-based options under consideration as BAT for reducing thermal discharges from BPS. To do this, it conducted two separate analyses. Each analysis is discussed below, and their respective results are presented in a table along with the permittee’s numbers.

SAIC’s first analysis generated independent capital cost estimates for each cooling tower-based BAT option by comparing the permittee’s detailed cost spreadsheets with an independent source of construction cost data (the “Independent Line Item Analysis”). 205SAIC analyzed the capital cost estimates, , which were submitted in detailed cost spreadsheets included in Volume V of the December 2001 USGenNE 316(a) and (b) Demonstration, and discussed in Volume IV of the December 2001 submission. It then identified similar cost items in an independent data source, the RS Means Cost Works database for the third quarter 2001.

Because the Costs Works database is a construction cost estimating resource for general construction throughout the United States, many of the specific unit cost items in the permittee’s spreadsheets could not be matched with similar cost items in Costs Works; however, for each item that could be matched, SAIC used the Cost Works value in its analysis. In other words, SAIC did not selectively use some matching items and disregard others; it used all matching items. Depending on the BAT option being considered, SAIC was able to match between 16% and 23% of the cost items in the permittee’s spreadsheets with cost items in the Cost Works data. Some of the Cost Works items were lower in cost, while others were higher.

In addition, SAIC took advantage of the Cost Works database feature that allows the use of cost factors to reflect specific regions of the country. In developing its independent cost estimates, SAIC chose data that represented the highest union labor rates for Boston, which is the most costly region in Massachusetts. These adjusted costs take into consideration regional costs for materials and labor, including the effects of using unionized labor.

For each cooling tower-based BAT option, SAIC compared the matched independent estimate line item costs to the permittee’s line item costs for each cooling tower-based BAT option. This comparison indicated overall that the independent, Cost Works-based capital cost estimates were significantly less than the permittee’s capital cost estimates. The ratio of the total of independent estimate line item costs to the total of the corresponding permittee line item costs indicated the relative extent to which the independent estimates were less than the permittee’s estimates for each option (and inversely, the extent to which the permittee’s estimates appear to have overestimated capital costs). Assuming that the comparative relationship observed for the matched items is representative of all of the cost items, multiplying this ratio by the corresponding total of permittee costs for a particular cooling tower-based BAT option yields an independent estimate of capital costs that is significantly lower than the permittee’s estimate ofMA0003654 Determinations Document July 22, 2002

206 See id. , pp. 13-15.

207 SAIC and Tetra Tech are working on the 316(b) rulemaking effort for EPA and thus are well-versed in the Agency’s 316(b) costing approaches. The 316(b) Rule costing methodology and costing equations are described in detail in the Technical Development Document for the 316(b) New Facility Rule (EPA 2001). Id. , p. 14. This document can be found on EPA’s website at http://www.epa.gov/ost/316b/.

4-71 capital costs.

Although there is some uncertainty, EPA believes that this assumption is not unreasonable. As noted above, SAIC did not pick and choose among the matching cost items; all matching items were used. Moreover, as SAIC points out, most of the difference between the independent estimates and the permittee’s estimates appear to be attributable to differences in labor rates and man hours for the matching line items. In most cases, the Cost Works labor rate and man hour estimates are much lower than the permittee’s estimates and, as SAIC points out, these types of differences can be expected for other line items. Finally, as mentioned above, SAIC used the Cost Works data for the third quarter of 2001 and for the Boston area, the most expensive area for Massachusetts. Thus, EPA believes SAIC's approach is unbiased, reasonable and appropriately conservative.

In its second analysis, SAIC derived capital cost estimates for each cooling tower-based BAT option under consideration using the costing methodology that EPA employed for estimating facility-level costs in the development of the CWA § 316(b) regulations (which the Agency recently promulgated for new facilities and proposed for large existing power plants) (the “316(b) Rule-Based Analysis”). 206 SAIC adjusted the results produced by the cost equations that EPA developed for new facilities; it did so by applying the relevant cost factors that EPA used to account for retrofitting technology to existing facilities, using salt water (which is more corrosive than fresh water and necessitates the use of more expensive materials and better drift control) as cooling water, and using fiberglass cooling towers (as proposed by the permittee) rather than redwood towers (which is the base case for the 316(b) Rule cost analysis). 207

SAIC noted that the permittee estimated the capital costs of converting more than one generating unit to closed-cycle cooling by first estimating the cost of converting each individual unit and then adding all of these costs together. For example, the permittee calculated the cost of the Closed-Cycle Entire Station option simply by summing the costs of separately converting Units 1, 2, 3 and 4. According to SAIC, this approach likely overestimated costs because it did not take into account the “economy of scale” benefit that would result from converting more than one unit at a time to closed-cycle cooling. Therefore, in the 316(b) Rule-Based Analysis, SAIC followed the permittee’s approach but made the appropriate adjustment for economy of scale. (As a result, for example, it estimated the total economy of scale benefit for the Closed-CycleMA0003654 Determinations Document July 22, 2002

208 Id. , p. 14. For comparison purposes, the 316(b) Rule-based cost estimates for retrofitting such towers with plume abatement technology indicate that the addition of plume abatement technology would roughly double these independent cost estimates, yielding costs that are within roughly 18% to 33% above the permittee’s cost estimates. Id.

4-72 Entire Station option to be approximately 6%.) SAIC also noted that the permittee increased the capital cost of each option by 10% to account for “contingencies” (as well as by an additional 10% to account for “indeterminate costs”). According to SAIC, the permittee’s contingency adjustment appears high because typical contingency allowances for heavy construction projects are more typically in the range of 4% to 7%. It concluded, however, that a 10% factor might not be unreasonable due to site-specific factors. Therefore, it used the permittee’s 10% factor for both contingencies and indeterminate costs in its analysis.

In addition, because of the permittee’s concern that the use of cooling towers at BPS wouldcause fog/ice hazards that would require generating unit shutdowns for the unit-specific closedcycle cooling options, SAIC estimated costs for system modifications that would obviate any need for such generating unit shutdowns. First, it adjusted the permittee’s capital cost estimates to reflect the installation of pumping and piping that would be necessary to allow unit-specific cooling towers to function in multi-mode fashion. In other words, it determined the capital cost of equipping the cooling towers so that they could be by-passed to allow the generating units to be run in once-through mode, thus eliminating any need for generating unit shutdowns. Second, SAIC determined the capital cost of outfitting the cooling towers with plume abatement technology ( i.e. , based on traditional wet/dry hybrid cooling), instead of with multi-mode capability.

As SAIC explains, the costing methodology used for the 316(b) Rule represents a conservative approach to estimating costs ( i.e. , it tends to err on the side of higher cost estimates). Although the methodology was developed for a national, industry-wide cost assessment and therefore could fail to account for site-specific factors at a given plant, such as BPS, SAIC and EPA believe that the results of the 316(b) Rule-Based analysis are reasonable and conservative for BPS because SAIC’s more site-specific Independent Line Item Analysis generated even lower capital cost estimates for retrofitting each of the BAT options under consideration. 208

The capital cost estimates computed by the permittee, the EPA/SAIC Independent Line Item Analysis, and the EPA/SAIC 316(b) Rule-Based Analysis are presented in the table below.

Table 4.4-1: Capital Cost EstimatesMA0003654 Determinations Document July 22, 2002

4-73 Technology Option Permittee’s Cost Estimates EPA/SAIC

Independent Line Item Analysis Cost Estimates EPA/SAIC 316(b)

Rule-Based Analysis Cost Estimates

“Enhanced MultiMode”* $57.4 million $18.8 million $29.3 million

Closed-Cycle Unit 3* $56.4 million $19.8 million $27.0 million
Closed-Cycle Unit 3* (with Multi-Mode) X X $31.3 million

Closed-Cycle Unit 3* (with wet/dry for Plume Abatement) X X $68.3 million

Closed-Cycle Units 1 or 2 & 3* X X $50.8 million

Closed-Cycle Entire Station* $176.7 million $63.9 million $80.7 million

Closed-Cycle EntireStation* (with MultiMode) X X $93.8 million

Closed-Cycle Entire Station* (with wet/dry for Plume Abatement) X X $202.3 million

* Assumes retrofitting to the existing facility, use of fiberglass towers and equipped for use with salt water.

“X” indicates that no value was calculated for that cell of the Table.

In order to be more conservative in our economic achievability analysis, EPA chose to proceed using the capital cost estimate values derived from SAIC’s 316(b) Rule-Based Analysis ( i.e. , the far right-hand column of Table 4.4-1) for the unit-specific and multi-mode cooling tower options under consideration as BAT for reducing thermal discharges from BPS. Therefore, EPA instructed Abt to use these values in its evaluation of the “financial aspects” of the costs of these BAT options.MA0003654 Determinations Document July 22, 2002

209 See id. , pp. 16-20.

210 See id. , pp. 23-24 and Table 12.

4-74

ii. Annual Auxiliary Power Costs

SAIC independently estimated annual auxiliary power costs (principally to run pumps and fans necessary for the cooling tower systems) as part of its analysis of annual O&M expenses for the various cooling tower-based BAT options for BPS.

It determined likely hours of operation and capacity for the plant’s generating units based on various data from the permittee. It also evaluated fan and pump power needs based on values from technical analyses supporting EPA’s 316(b) rulemaking, noting that the resulting figures could be “something of an overestimate” because in practice, a system likely would turn off fans for some percentage of its cooling tower cells, or reduce their speed, if possible, during cold weather. There were certain inconsistencies in the auxiliary power figures provided in various submissions by the permittee, which SAIC and EPA agreed to resolve by using the figures from the permittee’s Dynamic Cost Analysis, which were the permittee’s most recent figures. The auxiliary power consumption penalty estimate that SAIC derived by this approach was somewhat less than that predicted by the permittee for the Enhanced Multi-Mode option, but was higher than that predicted by the permittee for the unit-specific closed-cycle options. As a result, SAIC concluded that the permittee’s auxiliary power estimates were reasonable and could be used in EPA’s independent analysis. 209

SAIC also estimated overall annual O&M costs, including annual auxiliary power costs, using the cost equations that EPA used to estimate O&M costs on a national basis for the 316(b) Rule. The independent O&M cost estimates that SAIC developed using the 316(b) Rule cost equations include material, labor and equipment necessary to keep the units operational ( i.e. , preventive maintenance, overhaul maintenance and auxiliary power requirements, but not energy efficiency penalties due to the effects of cooling water temperature on condenser and turbine performance); they have been verified with field data and are considered to be conservative.

To compare these 316(b) Rule-based cost estimates with the permittee’s estimates, SAIC had to subtract estimated energy efficiency values that the permittee had combined with its estimated auxiliary power and O&M values. Under this 316(b) Rule-based approach, SAIC’s overall annual O&M cost estimates, including auxiliary power cost estimates, were slightly less for the Enhanced Multi-Mode option and significantly higher for the unit-specific closed-cycle options. On the basis of this analysis, SAIC concluded that the permittee’s annual O&M and auxiliary power cost estimates were reasonable and could be used in EPA’s independent analysis. 210

EPA agreed with SAIC that the permittee’s cost estimates for annual O&M and auxiliary powerMA0003654 Determinations Document July 22, 2002

211 See id. , pp. 20-24.

4-75 needs are not unreasonable, and directed Abt to use the permittee’s cost estimate values in its economic analysis. These values are presented in the following table:

Table 4.4-2: Permittee’s Annual Maintenance and Auxiliary Power Costs Technology Option Maintenance Expense Auxiliary Power Expense*

Enhanced Multi-Mode $240,000/year $2,542,610/year
Closed-Cycle Unit 3 $155,000/year $1,923,005/year
Closed-Cycle Entire Station $500,000/year $5,632,550/year

* Figures derived from Table 12 in SAIC Report (March 15, 2002).

iii. Annual Costs from Energy Efficiency Penalties

Retrofitting cooling towers to an existing power plant will result in a marginal loss of electrical generation efficiency. This lost generation has a cost, and the permittee included this cost in its assessment of the costs of the various cooling tower options. SAIC independently assessed the cost that the permittee would incur in energy efficiency penalties.

On the basis of its review, SAIC concluded that the permittee has significantly overestimated the efficiency losses likely to result from installing cooling towers at BPS. SAIC conducted its analysis by applying the method that EPA to calculate cooling tower efficiency losses for the Boston area for the recently promulgated CWA § 316(b) regulations for new facilities. SAIC then made the following adjustments to tailor the analysis to the particular circumstances of BPS: (1) it used monthly average intake temperatures for the Taunton River for Units 1, 2 and 3, and for the Lee River for Unit 4; (2) it used time-weighted wet bulb temperatures for the 9:00 am to 4:00 pm time period from Providence/T.F. Green Airport historical weather data (the permittee has used T.F. Green weather data for certain of its analyses); and (3) for Unit 4, it made adjustments to reflect eight months of piggyback operations as currently practiced under MOA II. Using wet bulb temperatures from the hours of 9:00 am to 4:00 pm, rather than an average over a full 24-hour day, will tend to produce a higher efficiency penalty ( i.e. , be more conservative economically). In addition, SAIC based its calculations on a design approach of 10° F, rather than the 8° F used in the permittee’s design, which will also tend to produce slightly higher efficiency penalty estimates. SAIC carried out calculations for both the 100% and 67% load cases, and then applied the results to the various BAT options based on the plant operating data presented earlier in its report (based on information obtained from the permittee). 211MA0003654 Determinations Document July 22, 2002

4-76 The results of SAIC’s analysis, along with the permittee’s values, are presented in the tables below.

Table 4.4-3: Wet Tower Annual Efficiency Losses Units 1, 2 and 3 Unit 4 (Piggyback)

100% Load 0.29% 0.09%

67% Load 0.75% 0.18%

Table 4.4-4: Annual Efficiency Penalty Estimates by Permittee and SAIC/EPA Technology Option Permittee

Efficiency Penalty Estimate (MW-Hrs/year) SAIC/EPA

Independent Efficiency Penalty Estimate (MW-Hrs/year) Percent

Difference in Permittee and SAIC/EPA MW-Hr/year Estimates SAIC/EPA

Independent Efficiency Penalty Estimate Converted to $/year*

Enhanced MultiMode 25,278 10,673 - 58% $373,555

Closed-Cycle Unit 3 64,108 16,629 -74% $582,015

Closed-Cycle Entire Station 124,715 31,779 -75% $1,112,265

* Figures derived for illustrative purposes only by EPA using SAIC efficiency penalty estimate and the permittee figure of $35.00 per MW-Hr. The analysis conducted by Abt for EPA estimates more specifically what the actual cost of the efficiency penalty is likely to be over time taking into account the changes in cost of generation and price received over time.MA0003654 Determinations Document July 22, 2002

212 See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, App. H, p. 3.3-29.

4-77 It should be remembered that BPS is expected to experience certain annual economic gains as a result of being able to generate more electricity during the peak demand hot weather periods during the summer. Depending on the BAT option being analyzed and the conclusions regarding certain other considerations, these gains are likely to either substantially offset, or more than offset, the auxiliary power and efficiency losses presented above. The issue of increased electrical generation allowed by cooling towers during hot weather periods is discussed further below.

iv. Costs from Generating Unit Construction Outages

The permittee has indicated that it believes that disconnection of the existing once-through cooling system and construction and connection of any one of the cooling tower-based options under consideration will necessitate certain generating unit outages. The permittee has agreed with EPA that these outages should be scheduled to coincide with regular annual maintenance outages as much as possible, but the permittee has also concluded that generating unit outagesextending beyond the duration of annual maintenance outages will be necessary for the unitspecific cooling tower options (though not for the Enhanced Multi-Mode option). As a result, the permittee has added a cost for this one-time loss of electrical generation from construction outages to the overall cost of the unit-specific options.

Specifically, the permittee determined that an eight-month outage would be required for installing unit-specific closed-cycle cooling towers for Units 1, 2 and 3, and a three-month outage would be required for such a tower for installing Unit 4. These outages would run consecutively ( i.e. , backto-back) for unit-specific cooling tower options for multiple units. In other words, downtime for converting the entire station to closed-cycle cooling would entail 27 unit-months. 212 Since these outages would run concurrently with the one-month annual maintenance outage for each unit, the cost of these outages in the permittee’s Dynamic Cost Analysis are based on seven months of outages for Units 1, 2 and 3; no cost was attributed to the outage for Unit 4 because it is not typically on-line anyway.

SAIC evaluated the permittee’s construction outage estimates and, on the basis of a conservative analysis, concluded that they appear to be excessive. SAIC determined that the principal reason for the relatively lengthy construction outages estimated by the permittee is the permittee’s “decision to install an entirely new set of pumping stations for the recirculation pumps for Units 1, 2 and 3 in a manner that interferes with the current once-through operation.” According to SAIC, “[t]his decision is based in part on the conclusion that the current pumps, piping and condenser may not be capable of handling the additional hydraulic pressure that would occur with the system if the condenser outlet were to be simply re-routed to the top of the new coolingMA0003654 Determinations Document July 22, 2002

213 SAIC Report (March 15, 2002), p. 25.

214 See id. , Attachment A.

215 I d ., p. 26.

4-78 towers.” 213

In evaluating the permittee’s approach, SAIC accepted the permittee’s concerns about piping and condenser pressure as valid. In addition, it reviewed four case studies involving large power plants that converted from once-through cooling to cooling with closed-cycle mechanical draft cooling towers (one plant uses the towers in a helper mode). 214 The conversions in these case studies were undertaken with either no outages or far shorter outages than those estimated by the permittee, such as the 27 unit-months of outage that the permittee estimates for the Closed-Cycle Entire Station option. As SAIC explained, these other plants have “mostly been able to incorporate the existing pumps and pump stations, the existing condensers and much of the existing piping into the closed cycle systems.” All but one of the four case study facilities were able to retain the existing once-through cooling water pumps and pumphouses and incorporate them into the wet cooling tower recirculation system, while the remaining facility kept the downtime “brief by installing a separate new pumphouse and piping in a manner that did not interfere with the existing system while under construction.” As a result, this facility only required downtime to “disconnect the existing once-through cooling water pipes and reconnect the new cooling water system pipes.” SAIC concluded that it is likely that either approach would be feasible for Units 1, 2 and 3. 215

Nevertheless, SAIC took a conservative approach and assumed that Unit 1, 2 and 3's current once-through pumps would require replacement. Even still, it concluded that unit outage time could be shortened by retaining the existing pumphouse, replacing the existing pumps and then connecting the discharge pipe to the cooling towers. SAIC explained that:

[a]s with USGenNE’s proposed engineering design, water would flow by gravity through the condensers but would then be piped back to the intake wet well of the existing intake pumping station. Such a pump and pipe configuration would require the closing off of the individual intake bays for each unit, the replacement of the intake pumps, installation of the cooling water return piping from the condenser, replacement of electrical and control equipment, and tie-in of the new pump outlet pipe to the cooling tower. Without more detailed information regarding the intake structure configuration, it cannot be determined what other modification to the intakes might be necessary. However, the savings in construction costs for replacing the pumphouse should more than offset anyMA0003654 Determinations Document July 22, 2002

216 Id. , p. 27.

217 See id. , pp. 28-29.

4-79 modification costs. Certainly, the case study facilities came to that conclusion. 216

To account for the constraints of working within the existing pumphouses, SAIC added back in two weeks of construction time. Ultimately, it concluded that the construction outage necessary for the installation of cooling-tower based technologies at BPS could conservatively be reduced to four months. Indeed, SAIC felt that it might be possible to reduce the outages for Units 1, 2 and 3 each to the three-month figure that the permittee estimated for Unit 4, but due to uncertainties about possible intake differences between the Unit 4 intake and the intake for Units 1, 2 and 3, it retained the four-month estimate for each unit. SAIC prepared a detailed construction-related unit downtime estimate for Unit 1 specifically, but concluded that the same approach and outage reductions could be achieved for Units 2 and 3 as well. 217

Table 4.4-5: Permittee and Independent Construction Outage Estimates Technology Option Permittee

Construction Outage Estimate(total unitmonths) Permittee

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage) EPA/SAIC

Construction Outage Estimate(total unitmonths) EPA/SAIC

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage)

Enhanced MultiMode 5.5 (broken into

different periods for individual units) 0 5.5 (broken into different periods for individual units) 0MA0003654 Determinations Document July 22, 2002

Technology Option Permittee

Construction Outage Estimate(total unitmonths) Permittee

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage) EPA/SAIC

Construction Outage Estimate(total unitmonths) EPA/SAIC

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage)

218 See id. , p. 29.

4-80 Closed-Cycle Unit 3 8 (for Unit 3) 7 (for Unit 3) 4 (for Unit 3) 3 (for Unit 3)

Closed-Cycle Entire Station 27 (made up of

separate 8- month periods for Units 1, 2 & 3, and 3 months for Unit 4) 21 (made up of

separate 7- month periods for Units 1, 2 & 3) 15 (made up of

separate 4- month periods for Units 1, 2 & 3, and 3 months for Unit 4) 9 (made up of

separate 3- month periods for Units 1, 2 & 3)

On the basis of the SAIC analysis, supported by the case studies, EPA believes the generating unit outage period of four months ( i.e. , three months in excess of the one-month annual maintenance outage) for Units 1, 2 and 3 are reasonable and conservative, and it directed that these figures be used in Abt’s economic analysis.

v. Period for Constructing the Closed-Cycle Entire Station Option

The permittee estimated that it would take a total of 47 months to construct the Closed-CycleEntire Station option. Assessing this proposed construction period in light of the abovedescribed reduced estimates for constructing the individual unit-specific cooling tower systems, SAIC concluded that the Closed-Cycle Entire Station construction period could be shortened from the permittee’s estimated 47 months to an estimated 39 months. It could not reasonably be reduced by the full amount of the reduction for each individual unit because of the necessary sequencing of various tasks for bringing each unit on-line. EPA instructed Abt to use this 39- month construction period estimate in its economic analysis. 218

4.4.3b “Financial Aspects”MA0003654 Determinations Document July 22, 2002

4-81 Abt conducted a multi-faceted independent analysis of the cost of the various unit-specific and multi-mode cooling tower-based options to the permittee over time. This analysis takes into account capital costs, the cost of one-time construction outages, various annual costs (e.g., O&M costs, auxiliary power cost penalties, reduced generation efficiency penalties, alleged vapor plume abatement outage penalties), and taxes. It presents the overall accumulated costs over the specified time period both as a total present value, after-tax cash flow total cost and as an equivalent annual

present value, after-tax cash flow cost.

There are numerous complexities involved in undertaking this type of financial/economic analysis. For example, determining the cost of the reduction in electrical generation that would be associated with each cooling tower-based option (as the result of, for example, construction outages or auxiliary power penalties) requires estimation of the additional profits that the permittee could have made over time if generation had not been reduced. This in turn requires estimation of the costs of producing the electricity over time, and subtraction of those estimated production costs from the estimated prices at which the permittee could have sold the electricity over time. Despite these complexities, the permittee, EPA and the MA DEP all agreed that this type of analysis was the most appropriate way to assess the cost to the permittee of the various options. (All the parties agreed this approach was a more accurate way of assessing costs than the “static cost analysis” that the permittee initially presented to the regulatory agencies in June 2001.) Thus, the permittee also conducted this type of analysis in its “Dynamic Cost Analysis,” which it submitted to EPA as part of the December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. III, App. G (Tab: Dynamic Cost Analysis). Abt’s analysis and the permittee’s Dynamic Cost Analysis undertake equivalent assessments, and their results can be meaningfully compared with each other.

The first step in Abt’s analysis was essentially to re-create the Dynamic Cost Analysis financial assessment model. Abt did this to ensure that it correctly understood the permittee’s analysis, to assess the validity of the permittee’s approach, and to determine whether the permittee’s results were accurate based on the model used and the inputs to it. As Abt stated, this represented a “due diligence” review.

Abt then went on to vary inputs to the financial assessment model as it deemed appropriate based on its independent expert opinion on financial/economic issues, and as directed by EPA on the basis of EPA’s and SAIC’s independent expert opinions on engineering issues. (An example of such a financial/economic issue is use of a discount rate different than that used by the permittee; an example of such an engineering issue is use of different capital costs than those used by the permittee.) For a number of factors, Abt analyzed a variety of alternative scenarios in order both to ensure that it considered issues from more than one perspective, and to discern the overall effect on the results of the choices made with respect to these factors. For example, as discussed below, Abt looked at overall costs over both a 20-year and a 30-year equipment operating life.MA0003654 Determinations Document July 22, 2002

219 Abt Report (April 5, 2002), pp. 39-40.

4-82 The financial/economic analysis conducted by Abt is quite complex, and it is explained in detail in the report attached hereto as App. C and incorporated herein by reference. EPA does not repeat the analysis in detail here. We do, however, present its key results and discuss the principal factors that went into it.

i. Abt’s Replication of the Permittee’s Dynamic Cost Analysis Model

In order to analyze the unit-specific and multi-mode cooling tower-based options under consideration for BPS, Abt developed an analytic framework that essentially replicates the permittee’s analysis. Apart from presentation differences, Abt’s analytic framework differs materially from the permittee’s framework only in including the ability to adjust the time period of analysis and recognize explicitly the estimated schedule requirements for installation of capital equipment and subsequent operating periods for technology equipment. By constructing this analytic framework and validating the permittee’s analysis, Abt was able to replicate the analyses presented in the Dynamic Cost Analysis in virtually all respects, including the electricity price and input fuel cost schedules used in the permittee’s analysis.

However, while Abt was able to replicate the growth rates of the electricity price and input fuel cost schedules going forward in time, based on the electricity price and fuel cost forecasts developed by Resource Data International (RDI) and submitted to EPA by the permittee (including those that depend on a blending of on- and off-peak price schedules), Abt was not able to independently verify the first-year values of electricity prices and input fuel costs for these schedules. These first-year values are reported by the permittee to be the current (presumed 2001) values observed in operation of BPS. Accordingly, while the projections of future electricity prices and input fuel costs track the RDI projections in terms of change over time, the absolute numerical values in these schedules depend on the permittee’s reported baseline values. Again, Abt was not able to independently validate these baseline values, which provide the “seed” for the future projection schedules. As a result, it used them in its analysis.

In addition, Abt’s replication of the permittee’s analysis revealed the following two calculation errors by the permittee that materially affect the results of the Dynamic Cost Analysis: 219

1. Improper referencing of certain spreadsheet cells in the calculations . In the permittee’s model for the Closed-Cycle Entire Station option, the spreadsheet row labeled “After-Tax Annual Cost” is improperly calculated. Specifically, the spreadsheet row titled “Tax Cost (Savings)” is added to the row labeled “Total Cost of Plume Abatement” instead of the proper row “Annual Cost” for the calculation of “After-Tax Annual Cost.” As a result, total after-tax annual costs are understatedin all years of the analysis, and theMA0003654 Determinations Document July 22, 2002

4-83 subsequent calculations of present value and equivalent annual cost carry forward this error. When corrected, the total present value of cost for this option under the permittee’s 15% discount rate increases by $15.7 million. The permittee does not make this error in its analysis of the Enhanced Multi-Mode and Closed-Cycle Unit 3 options.

2. Failure to account for the tax treatment of the construction outage income loss. In its analysis of the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options, the permittee does not account for the tax treatment of the income loss during construction outages: the construction outage causes a reduction in income, which in turn reduces the permittee’s tax liability during that operating period. This treatment is inconsistent with the permittee’s proper recognition of the tax treatment of other revenue and cost effects from installation and operation of technology equipment. As a result, the permittee’s analysis overstates the cost of the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options by $21.3 million and $39.1 million, respectively. This error is irrelevant to the permittee’s analysis of the Enhanced Multi-Mode option, because the permittee anticipates no construction outage income loss from this option.

The net effect of these errors is that within its own framework of calculations and cost estimates, the permittee’s analysis overstates the total present value of cost. In the permittee’s 15%discount rate case, it overstates the total present value of cost by $21.3 million for the ClosedCycle Unit 3 option and by $23.4 million for the Closed-Cycle Entire Station option. These errors are material in the permittee’s analysis, representing approximately 17% of the permittee’s total present value of cost for the Closed-Cycle Unit 3 option and approximately 15 % of the permittee’s total present value of cost for the Closed-Cycle Entire Station option.

In response to these two errors, when Abt presented the permittee’s cost estimates for the purpose of comparing them with its independent cost estimates, it corrected the permittee’s numbers to fix the two errors. As a result, Abt’s re-estimates of the permittee’s cost and cost effectiveness values for the Closed-Cycle Unit 3 and Closed-Cycle Entire Station options are somewhat lower than the values actually reported by the permittee in the Dynamic Cost Analysis.

Finally, Abt’s calculations yielded other small differences from the permittee’s Dynamic Cost Analysis values and interpreted them to arise from rounding. Abt indicated that these differences amounted to no more than a few thousand dollars in any given instance, and it concluded that the differences were inconsequential in the aggregate.

ii. Elements of Abt’s Independent Financial/Economic Analysis

Some of the key aspects of Abt’s independent financial/economic analysis are discussed below.MA0003654 Determinations Document July 22, 2002

4-84 Capital Costs. Abt used the capital costs from SAIC’s independent CWA § 316(b) Rule costing methodology-based analysis. As explained above, EPA directed Abt to use these figures rather than the figures from SAIC’s Independent Line Item Analysis, because the former were higher and would therefore result in a more conservative analysis.

Duration of Construction Outage. As discussed above, Abt used the construction outage figures calculated by SAIC.

Date for Commencement of Construction; Timing of Construction Outage. The time when one assumes construction would begin (and end) and the timing of the construction outages both impact the results of the financial/economic analysis. The permittee’s Dynamic Cost Analysis assumed that construction began and ended in 2001 and valued the construction outage based on the “spark spread price” from 2001. Given that it was already early 2002 when Abt was working on its analysis, it is indisputable that construction could not begin and end in 2001. Therefore, EPA and Abt agreed to use mid-2002 as the time for construction to start. In addition, Abt assumed that construction outages would occur at the end of the construction period and, therefore, valued the outages based on the spark spread price estimated for those times.

Construction Duration. As discussed above, the timing of construction and any outages affects the financial/economic analysis. Abt used the construction duration calculated by SAIC for the Closed-Cycle Unit 3 option and the Closed-Cycle Entire Station option, but consistent with SAIC’s recommendation, used the permittee’s construction duration estimate for the Enhanced Multi-Mode option.

O&M. Consistent with SAIC’s recommendation, EPA directed Abt to use the annual O&M expenses developed by the permittee.

Auxiliary power Cost Penalties. Consistent with SAIC’s recommendation, EPA directed Abt to use the annual auxiliary power penalties (in MWHrs) developed by the permittee. Like the permittee, Abt valued these penalties on the basis of lost revenue.

Energy Efficiency Cost Penalties. As discussed above, EPA directed Abt to use the annual energy efficiency penalty figures (in MWHrs) developed by SAIC. Like the permittee, Abt valued these penalties on the basis of lost revenue.

Economic Gain from “Avoided Load Loss.” As discussed above, the permittee acknowledges that the cooling tower-based options would offer an economic benefit because they would enable greater electrical generation during certain peak demand (and therefore peak sales price) hot weather periods during which the permittee currently must curtail (or cap) generation to avoid violating the 95° F maximum temperature discharge limit presently in its NPDES permit. Abt has referred to this benefit as the “avoided load loss.” This benefit would occur because summerMA0003654 Determinations Document July 22, 2002

4-85 intake water temperatures can get high enough that heat added to the water by the power plant can push the discharge temperature over 95° F, but cooling towers could minimize this problem by rejecting heat to the atmosphere rather than back to Mount Hope Bay in the cooling water.

In its calculations, Abt used the permittee’s estimate of the extent of avoided load loss events, which was based in part on permittee historical data from 1989 to 1999. In light of data (discussed elsewhere in this document) indicating an upward, long-term trend in the temperature of the waters of Mount Hope Bay (and Narragansett Bay), EPA notes that using the 1989-1999 data is likely to result in a relatively conservative estimate of avoided load loss events going forward. Further, Abt noted that if the permittee had used data that included the very warm summer of 2001, then its estimated value of the avoided load loss also would have been higher. While acknowledging the avoided load loss benefit, the permittee determined that if it discharged more heat during peak periods, then in order to remain within its overall permit limits it would have to offset the increases by reducing generation during off-peak (and therefore lower sales price) periods. Abt followed the permittee’s approach to handling and estimating the value of this offset.

In addition, the permittee estimated that the Enhanced Multi-Mode and Closed-Cycle Entire Station options would be able to capture all (100%) of the potential avoided load loss, but that the Closed-Cycle Unit 3 option would only be able to capture part (48.6%) of the potential benefit. The permittee did not clearly explain how it came up with this 48.6% figure, and Abt was unable to independently verify it. With no clear basis for an alternative figure, EPA and Abt decided to take the conservative approach of using the permittee’s figures.

Placing a dollar value on avoided load losses requires calculating the profits that would have been lost to generating load curtailment. This is done by determining baseline figures for the fuel cost for producing the electricity and for the price at which that electricity could have been sold. Working from these baseline figures, future changes in electricity prices and fuel costs must then be estimated to determine the future value of the net loss in operating income to the permittee from the predicted curtailment in generation that would have occurred in the absence of a particular cooling tower option.

In reviewing both the permittee’s July 2001 “static economic analysis” and the Dynamic Cost Analysis that the permittee submitted to EPA in December 2001, Abt found that the permittee used different baseline spark spread price schedules in the two analyses. In its July 2001 analysis, the permittee used a schedule based on wholesale electricity prices from the summer of 1999. In the Dynamic Cost Analysis, however, it used a baseline price schedule reportedly based on price data from 1999 and 2000, but not from the very warm summer of 2001. The schedule in the Dynamic Cost Analysis substantially reduced the price schedule from the July 2001 range of $20.00 to $400.00 per MWHr to a new range of $35.66 to $78.13 per MWHr. Abt found that this substantially reduces the value of the avoided load loss benefit (e.g., a 28% reduction in theMA0003654 Determinations Document July 22, 2002

4-86 baseline year). Abt also found that the permittee did not provide any data supporting a cap on the spark spread price at $78.13 per MWHr. Therefore, Abt conducted an independent analysis to judge the reasonableness of the spark spread price schedule by reviewing energy clearing price (ECP) data for the summers of 1999, 2000 and 2001 from Independent System Operator-New England (ISO). Abt found that values ranged as high as $1000 per MWHr, with a maximum average for a given temperature of $409.06 per MWHr. Therefore, Abt concluded that it could not justify the $78.13 cap on the spark spread price schedule used in the Dynamic Cost Analysis, and that the baseline schedule from the permittee’s July 2001 static analysis appeared to be more reasonable. As a result, in assessing the avoided load loss benefit for the independent financial/economic analysis, Abt used the baseline spark spread price schedule from the permittee’s July 2001 static analysis.

Building off the baseline spark spread price schedule, the permittee’s Dynamic Cost Analysis estimated the operating effects over time of the avoided load loss benefit based on a forecast of year-to-year changes in on-peak wholesale electricity prices, fuel costs, and spark spread prices developed by RDI. Abt concluded that this approach was reasonable. Therefore, Abt used the “implied growth rates” from the Dynamic Cost Analysis to project future spark spread price values from the permittee’s July 2001 static cost analysis baseline schedule.

Unit Outages to Abate Alleged Hazard from Cooling Tower Water Vapor Plumes. As discussed elsewhere in this document, the permittee has concluded that generating unit outages will be necessary for the unit-specific cooling tower options in order to abate potential fog and/or ice hazards from cooling tower water vapor plumes. Although a very small number of hours of potential cooling tower-induced fog or ice were predicted by its model, the permittee’s analysis concluded that hundreds of hours of outage would be needed to prevent these few hours of predicted tower-induced fog and/or ice. The cost of these outages is a significant element in the permittee’s economic analysis. The permittee estimates that no such outages will be needed for the Enhanced Multi-Mode option because the cooling towers can be bypassed.

EPA has explained its skepticism about the permittee’s conclusions elsewhere in this document. Given this skepticism, EPA asked Abt to assess the financial ramifications of several different scenarios. First, we asked Abt to evaluate the matter assuming no plume abatement unit outages. For this scenario, however, we instructed Abt to use the SAIC capital cost estimates that include an upward adjustment for the cost of adding piping and pumping to enable the unit-specific option to be operated in a multi-mode fashion so that the cooling towers could be bypassed if necessary. Abt’s analysis showed that these increased capital costs would be more than offset by the economic benefit of avoiding the permittee’s predicted unit outages. Second, we asked Abt to evaluate costs assuming that 100% of the permittee’s predicted outages would, in fact, be necessary. Third, we asked Abt to evaluate costs assuming that 50% of the permittee’s predicted outages would be necessary. For the latter two scenarios, Abt used SAIC’s estimated capital costs for the unit-specific options without the cost adjustment for modifications to operate in aMA0003654 Determinations Document July 22, 2002

4-87 multi-mode fashion. In order to determine the cost to the company of the outages, Abt followed the permittee’s approach, including the use of RDI data to determine the future revenue losses due to the outages.

Life of Capital Equipment; Time Horizon for Economic Analysis. The permittee assumed a 20-year life for the capital equipment. It also assumed that construction began and ended in 2001, and did its present value calculations at 2001.

EPA, SAIC and Abt concluded that 20 years might underestimate the reasonable life of the capital equipment, including the likely remaining life of the major components of the entire BPS, and concluded that 30 years might be a more reasonable figure. Indeed, for the CWA § 316(b) rulemaking, EPA has assumed a 30-year life for this equipment. Therefore, Abt did its analyses for two scenarios: one assuming a 20-year life and one assuming a 30-year life. As discussed above, Abt assumed that construction began in mid-2002, determined the first year of operation based on the particular option’s construction schedule, and did its present value calculations back to mid-2002.

Depreciation. The permittee’s Dynamic Cost Analysis used a 20-year straight-line depreciation schedule, with no depreciation recorded in the first year of operation (i.e., only 19 years of depreciation were included). Abt concluded that it was not reasonable to omit the first year of depreciation and, as a result, recorded a full year of depreciation in the first operating year. Abt noted that its approach yielded a lesser depreciation tax benefit than that which would have accrued if a Modified Accelerated Cost Recovery Schedule (MACRS) had been used instead of the 20-year straight-line approach. It also noted that a MACRS approach probably would be appropriate in this case. EPA agrees that Abt’s decision to use a 20-year straight-line schedule, but to include depreciation in the first operating year, is a reasonable and conservative approach.

Discount Rate. The permittee did not want to reveal its internal company discount rate/cost of capital, which it regards as highly confidential business information. As a result, the permittee used a range of discount rates that it stated would encompass the rate it would use in its assessment of investment opportunities. The permittee then conducted its Dynamic Cost Analysis for two scenarios: one using a discount rate of 15% and one using a discount rate of 20%.

In order to test the reasonableness of the permittee’s figures, Abt undertook a cost-of-capital analysis for six comparable merchant power producers. From this analysis, Abt estimated a market capitalization-weighted cost-of-capital of 11.8%. Abt then used this figure as the discount rate for its analyses.MA0003654 Determinations Document July 22, 2002

4-88 iii. Comparison of Abt’s Independent Financial/Economic Analysis and the Permittee’s Dynamic Cost Analysis

Abt’s financial/economic analysis yielded costs that were substantially lower than the costs indicated by the permittee’s analysis. A number of factors played into this result, but the most important was the difference in capital cost inputs, followed (in no particular order) by efficiency penalty inputs, treatment of the water vapor plume abatement issue, construction outage inputs and avoided load loss inputs. It should be noted that under Abt’s 30-year cost assessment, the Enhanced Multi-Mode option would actually earn money for the permittee due to the combination of the avoided load loss benefit over time and the other factors previously mentioned. As described above, Abt also evaluated a number of different scenarios by varying certain elements in the analysis. The several tables below present a comparison of some of the key conclusions of Abt’s analysis with those of the permittee’s analysis.

Table 4.4-6: Comparison of Selected Permittee and EPA/Abt Cost Scenarios Technology Option Permittee 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 30 years)

Enhanced Multi-Mode Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $38.233 Million

$6.108 Million $1.077 Million

$142 Thousand - $909 Thousand*

- $111 Thousand*MA0003654 Determinations Document July 22, 2002

Technology Option Permittee 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 30 years)

4-89 Closed-Cycle Unit 3 0% plume abatement 2 Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

50% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 4

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

Not Calculated

Not Calculated

$104.949 Million

$16.767 Million $23.574 Million

$3.117 Million

$29.710 Million

$3.928 Million

$38.861 Million

$5.138 Million $23.031 Million

$2.817 Million

$30.337 Million

$3.710 Million

$40.658 Million

$4.973 MillionMA0003654 Determinations Document July 22, 2002

Technology Option Permittee 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 30 years)

4-90 Closed-Cycle Entire Station Units

0% plume abatement 2 Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

50% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 4

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

Not Calculated

Not Calculated

$254.485 Million

$40.657 Million $68.385 Million

$9.041 Million

$71.685 Million

$9.477 Million

$83.269 Million

$11.009 Million $67.975 Million

$8.314 Million

$72.747 Million

$8.898 Million

$85.803 Million

$10.494 Million

* Negative numbers indicate the permittee is gaining the indicated amount of money.

1 The permittee figures for Closed-Cycle Unit 3 and Closed-Cycle Entire Station Units reflect the permittee’s capital costs and its assumptions for generating unit outages for water vapor plume abatement.

2 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid generating unit outages for plume abatement.

3 The Abt/EPA “50% plume abatement” numbers reflect calculations including 50% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.

4 The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.MA0003654 Determinations Document July 22, 2002

4-91 Table 4.4-7: Permittee Total & Annual Equivalent Costs (with & without Calculation Errors Corrected by Abt) Technology Option Permittee Figures (15% Discount Rate/over 20 years) w/o Calculation Correction Permittee Figures

(20% Discount Rate/over 20 years) w/o Calculation Correction Abt-Replicated

Permittee Figures w/ calculation Correction (15% Discount Rate/over 20 years) Abt-Replicated

Permittee Figures w/ calculation Correction (20% Discount Rate/over 20 years)

Enhanced MultiMode

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $38,226,000

$6,107,000 $41,981,000

$8,621,000 $38,228,000

$6,107,000 $41,983,000

$8,621,000

Closed-Cycle Unit 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $126,289,000

$20,176,000 $122,688,000

$25,195,000 $104,964,000

$16,769,000 $101,366,000

$20,816,000
Closed-Cycle Entire Station Units

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $267,294,000

$42,703,000 $268,717,000

$55,183,000 $254,768,000

$40,702,000 $250,638,000

$51,470,000MA0003654 Determinations Document July 22, 2002

4-92 Table 4.4-8: Abt/EPA Cost Estimates Over 20- and 30-Year Periods Technology Option (& Plume Abatement Assumption) Abt/EPA

Total After-Tax Cash Flow Cost, Present Value (20-Year Period) Abt/EPA Annual Equivalent Cost (20-Year Period) Abt/EPA

Total After-Tax Cash Flow Cost, Present Value (30-Year Period) Abt/EPA

Annual Equivalent Cost (30-Year Period)

Enhanced Multi-Mode

(No Plume Abatement) 2 $1.077 Million $142 Thousand - $909 Thousand 1 - $111 Thousand 1

Closed-Cycle Unit 3

0% Plume Abatement 3

50% Plume Abatement 4

100% Plume Abatement 5 $23.574 Million

$29.710 Million

$38.861 Million $3.117 Million

$3.928 Million

$5.138 Million $23.031 Million

$30.337 Million

$40.658 Million $2.817 Million

$3.710 Million

$4.973 Million

Closed-Cycle Entire Station

0% Plume Abatement 3

50% Plume Abatement 4

100% Plume Abatement 5 $68.385 Million

$71.685 Million

$83.269 Million $9.041 Million

$9.477 Million

$11.009 Million $67.975 Million

$72.747 Million

$85.803 Million $8.314 Million

$8.898 Million

$10.494 Million

1 Negative numbers indicate the permittee is gaining the indicated amount of money.

2 The permittee has concluded no plume abatement generating outages are needed for the Enhanced Multi-Mode option. EPA/Abt adopted this assumption as well.

3 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid generating unit outages for plume abatement.

4 The Abt/EPA “50% plume abatement” numbers reflect calculations including 50% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.

5The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.MA0003654 Determinations Document July 22, 2002

4-93 Table 4.4-9: Detailed Permittee and EPA/Abt Costs for Enhanced Multi-Mode Option

Parameter Permittee

(15% Discount Rate) (w/ Calculation Errors Corrected by Abt) (20-Year Period) EPA/Abt (using 11.8% Discount Rate and other Independent Elements) (20 Years) EPA/Abt (using 11.8%

Discount Rate and other Independent Elements) (30 Years)

Capital Costs $57.406 Million $24.054 Million $24.054 Million
Construction Outage Cost $0 $0 $0
Total Initial Cost, Net Depreciation Tax Benefit $50.112 Million $20.324 Million $20.324 Million

Maintenance $1.186 Million $1.070 Million $1.207 Million
Auxiliary power and Efficiency Penalties $13.775 Million $9.896 Million $10.965 Million

Avoided Load Loss Benefit - $26.840 Million 1 - $30.212 Million 1 - $33.405 Million 1

Cost of Plume Abatement $0 $0 $0

Total of Annual Expenses, After Tax -$11.879 Million 1 - $19.246 Million 1 - $21.232 Million 1

Present Value Total After-Tax Cash Flow $38.233 Million $1.077 Million - $909 Thousand 1
Equivalent Annual Cost $6.108 Million $142 Thousand - $111 Thousand 1

1 Negative numbers indicate the permittee is gaining the indicated amount of money.MA0003654 Determinations Document July 22, 2002

4-94 Table 4.4-10: Detailed Permittee and EPA/Abt Costs for Closed-Cycle Unit 3 Option

Parameter Permittee

(20 Years) 100% Plume* 1 EPA/Abt

(20 Years) 0% Plume* 2 EPA/Abt

(20 Years) 50% Plume* 2 EPA/Abt

(20 Years) 100% Plume* 2 EPA/Abt

(30 Years) 0% Plume* 2 EPA/Abt

(30 Years) 50% Plume* 2 EPA/Abt

(30 Years) 100% Plume* 2
Capital Costs $56.4

Million $25.692

Million $22.123

Million $22.123

Million $25.692

Million $22.123

Million $22.123

Million

Construction Outage Cost $30.688

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million

Total Initial Cost, Net Depreciation $79.921

Million $29.057

Million $26.042

Million $26.042

Million $29.057

Million $26.042

Million $26.042

Million

Maintenance $0.766

Million $0.691

Million $0.691

Million $0.691

Million $0.780

Million $0.780

Million $0.780

Million
Aux. Energy & Efficiency Penalties $16.747

Million $8.501

Million $8.501

Million $8.501

Million $9.419

Million $9.419

Million $9.419

Million

Avoided Load Loss Benefit - $13.036

Million3 - $14.674

Million3 - $14.674

Million3 - $14.674

Million3 - $16.225

Million3 - $16.225

Million3 - $16.225

Million3

Cost of Plume Abatement $20.566

Million $0 $9.151 Million $18.302

Million $0 $10.321 Million $20.642

Million

Total Annual Expenses, After Tax $25.043

Million - $5.482

Million3 $3.669

Million $12.819

Million - $6.026

Million3 $4.295

Million $14.616

Million

Present ValueTotal AfterTax Cash Flow $104.964

Million $23.574

Million $29.710

Million $38.861

Million $23.031

Million $30.337

Million $40.658

Million

Equivalent Annual Cost $16.769

Million $3.117

Million $3.928

Million $5.138

Million $2.817

Million $3.710

Million $4.973

Million

* The permittee figures for the Closed-Cycle Unit 3 option reflect the permittee’s capital cost estimates and predicted generating unit outages for water vapor plume abatement. Abt/EPA figures for the “0% Plume” case reflect

no unit outages for plume abatement, but do reflect the SAIC estimates of capital costs that were increased to reflect piping and pumping to equip the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid any plume abatement outage. Abt/EPA figures for the “50% Plume” and “100% Plume” reflect the stated percentage of the permittee’s predicted plume abatement outages, but also reflect the SAIC capital cost estimates that were not adjusted for multi-mode capacity.
1 The permittee figures reflect its analysis using a 15% discount rate, with calculation errors corrected by Abt.
2 Abt/EPA figures reflect a discount rate of 11.8%, as explained above.
3 Negative numbers indicate the permittee is gaining the indicated amount of money.MA0003654 Determinations Document July 22, 2002

4-95 Table 4.4-11: Detailed Permittee and EPA/Abt Costs for Closed-Cycle Entire Station Units Option

Parameter Permittee

(20 Years) 100% Plume* 1 EPA/Abt

(20 Years) 0% Plume* 2 EPA/Abt

(20 Years) 50% Plume* 2 EPA/Abt

(20 Years) 100% Plume* 2 EPA/Abt

(30 Years) 0% Plume* 2 EPA/Abt

(30 Years) 50% Plume* 2 EPA/Abt

(30 Years) 100% Plume* 2
Capital Costs $176.676

Million $70.592

Million $60.788

Million $60.788

Million $70.592

Million $60.788

Million $60.788

Million

Construction Outage Cost $56.290

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million

Total Initial Cost, Net Depreciation $210.517

Million $72.971

Million $64.686

Million $64.686

Million $72.971

Million $64.686

Million $64.686

Million

Maintenance $2.347

Million $1.945

Million $1.945

Million $1.945

Million $2.195

Million $2.195

Million $2.195

Million
Aux. Energy & Efficiency Penalties $40.182

Million $20.805

Million $20.805

Million $20.805

Million $23.055

Million $23.055

Million $23.055

Million

Avoided Load Loss Benefit - $26.840

Million3 - $27.336

Million3 - $27.336

Million3 - $27.336

Million3 - $30.245

Million3 - $30.245

Million3 - $30.245

Million3

Cost of Plume Abatement $28.278

Million $0 $11.584 Million $23.169

Million $0 $13.056 Million $26.112

Million

Total Annual Expenses, After Tax $43.968

Million - $4.586

Million3 $6.998

Million $18.583

Million - $4.995

Million3 $8.061

Million $21.117

Million

Present ValueTotal AfterTax Cash Flow $254.485

Million $68.385

Million $71.685

Million $83.269

Million $67.975

Million $72.747

Million $85.803

Million

Equivalent Annual Cost $40.657

Million $9.041

Million $9.477

Million $11.009

Million $8.314

Million $8.898

Million $10.494

Million

* The permittee figures for the Closed-Cycle Unit 3 option reflect the permittee’s capital cost estimates and predicted generating unit outages for water vapor plume abatement. Abt/EPA figures for the “0% Plume” case reflect

no unit outages for plume abatement, but do reflect the SAIC estimates of capital costs that were increased to reflect piping and pumping to equip the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid any plume abatement outage. Abt/EPA figures for the “50% Plume” and “100% Plume” reflect the stated percentage of the permittee’s predicted plume abatement outages, but also reflect the SAIC capital cost estimates that were not adjusted for multi-mode capacity.
1 The permittee figures reflect its analysis using a 15% discount rate, with calculation errors corrected by Abt.
2 Abt/EPA figures reflect a discount rate of 11.8%, as explained above.

3 Negative numbers indicate the permittee is gaining the indicated amount of money

.MA0003654 Determinations Document July 22, 2002

220 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H., p. 4-4.

221 See id. , Vol. III, App. G, (Tab: Dynamic Cost Analysis at 4). See also EPA TDD 2001 - New Facilities, pp. 3-31 to 3-33.

4-96 4.5 Consideration of Other Remaining Factors Under CWA § 304

4.5.1 Non-Water Quality-Related Environmental Impacts (Including Energy Impacts)

There are several non-water quality-related environmental issues to consider with respect to a potential cooling tower retrofit at BPS. For example, shifting to closed-cycle cooling would result in a marginal decrease in the amount of electricity generated for sale by the plant due to the energy efficiency and auxiliary power penalties discussed in Section 4.4 above and Section 4.5.1e below. This marginal decrease in power generation could in turn contribute to marginal increases in air pollution if BPS were to try to offset the lost generation by burning more fuel to generate more electricity. In addition, according to the permittee, retrofitting all or some of the units at BPS with wet mechanical draft cooling towers could have adverse noise, visual/aesthetic and salt drift impacts. EPA does not believe that any of these issues presents a fatal flaw for a retrofit of mechanical draft wet cooling towers at BPS.

Each of the unit-specific and multi-mode wet cooling tower options raise the same issues concerning potential non-water quality environmental and energy impacts. 220 Therefore, this determination document discusses these issues together. Nonetheless, wherever important distinctions can be drawn between the options, these distinctions are identified and addressed. EPA notes that while as a general matter, the more cooling tower cells an option involves, the greater the magnitude of the potential impacts is, this does not necessarily mean that any such impacts are significant.

4.5.1a Air Pollutant Emissions

One issue that must be addressed is the possibility that due to lost efficiency as a result of installing cooling towers, a power plant would burn more fuel in an effort to make up for lost electricity generation and thus produce increased air emissions. This should not be an issue at BPS, however, because the permittee has indicated that due to the fixed steam capacity of the boilers at BPS, the plant cannot actually burn more fuel to make more steam and generate more electricity in response to efficiency losses due to cooling towers. 221 Instead, any needed lost megawatt-hours from BPS due to cooling tower-related penalties would be replaced by generation at other plants. It is more than likely that these other plants will be similar or cleaner burning facilities, given that BPS is an old coal burning plant. Therefore, the marginal penaltiesMA0003654 Determinations Document July 22, 2002

222 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G, (Tab: Dynamic Cost Analysis, at 4).

223 See 310 CMR 7.29.

224 See EPA TDD 2001 - New Facilities, p. 3-35.

225 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, Figures 3.3-1, 2.2-1; NEPCO January 15, 1998 NPDES Permit Application, Figure 1.

226 See Figure 7.3-1, “Brayton Point, Somerset, MA, Distances from Proposed Cooling Towers to Sensitive Receptors (EPA, January 24, 2002).

4-97 discussed above are likely, in turn, to lead to no changes in air pollutant emissions at BPS and only very marginal changes across the Region. 222

Moreover, it must be understood that any emission increases would be limited by applicable air pollution standards. Since the MA DEP has recently promulgated new air pollution standards that apply to BPS and will require significantly reduced air emissions from the plant (and several other major, older power plants), the overall air emissions from this plant will be substantially reduced compared to current levels regardless of whether the plant burned marginally more fuel to make up for efficiency losses due to cooling towers. 223 In addition, these new regulations will also lead to substantial overall emission reductions in Massachusetts. EPA reiterates that any new cooling towers will be subject to air permitting requirements and will obviously need to satisfy all applicable air pollution standards (e.g., standards for particulate emissions). Moreover, it is more than likely that these other plants will be similar or cleaner burning facilities, given that BPS is an old coal burning plant. Therefore, the marginal efficiency and auxiliary power penalties discussed above are likely to lead to no changes in air pollutant emissions at BPS and only very marginal changes across the region.

4.5.1b Noise

Noise could be a concern if retrofitted wet mechanical draft cooling towers are located very near to sensitive receptors ( e.g. , residences). Noise comes principally from the fans and possibly from water falling within the towers. 224

BPS is essentially surrounded on three sides by water and on the fourth side by part of the Town of Somerset. The permittee indicates that it would locate any cooling towers in a north-central area of the site. 225The nearest residences to this north-central area are approximately 1900 feet to the east in Somerset and approximately 1900 feet to the west across the Lee River in Gardners Neck in Swansea. 226

Before installing and operating any mechanical draft cooling towers, theMA0003654 Determinations Document July 22, 2002

227 See
, e.g , December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3; id. , Vol. I, Executive Summary, p. 8 n.7; EPA Economic and Engineering Analysis, App. A, p. 14; Nuclear Regulatory Commission, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (NUREG-1437 Vol. 1), § 4.3.7 (December 14, 2001); EPA TDD 2001 - New Facilities, p. 3-35.

228 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, p. 3.3-27.

229 See id. at pp. 3.3-27, 4-2, 4-5, 3.3-3. Moreover, the permittee did not explain why some or all of the cooling towers could not be built on the southwest portion of the site near the discharge canal, and further from the nearest residences, that the permittee has identified would be used for the helper cooling tower option if it were selected. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, Figure 3.2-23. The permittee was asked this question at the January 29, 2002 meeting, and the permittee indicated that doing so would be significantly more expensive due to the need for lengthier “piping runs.” See January 30, 2002 email from Mark Stein, EPA, to David Webster, EPA, et al. (“Subject: Brayton - FYI”). In any event, if noise were a problem, locating the towers further south might be another way to mitigate those impacts, though apparently at some cost.

230 See id.

4-98 permittee would be required to conduct an appropriate noise analysis to ensure compliance with any applicable State and/or local noise standards. (There are no applicable Federal noise standards.) That being said, EPA believes based on current information that the site configuration and the availability of various types of noise mitigation ( e.g. , low noise fans, trees), if any is needed, should enable retrofitting of mechanical draft cooling towers at BPS while achieving compliance with applicable regulatory standards to prevent unacceptable impacts to the nearest receptors. 227If any special noise mitigation measures were required, it could increase the cost of cooling towers but not likely by a particularly significant degree.

The amount of noise generated is essentially proportional to the number of cooling cells and fans required for the options. Thus, the most noise undoubtedly would result from a conversion of all four units to closed-cycle cooling using mechanical draft cooling towers, as that would involve 72 cooling tower cells and fans. Noise from the conversion of Units 2 and 3 (37 cells) or just Unit 3 (22 cells and fans) and from the Enhanced Multi-Mode option (20 cells and fans) would be proportionately less. 228In fact, the Unit 3 Closed-Cycle and Enhanced Multi-Mode options would yield similar noise based on the similar number of cooling tower cells and fans required. 229 None of this is to say that any noise issues cannot be controlled, and the permittee does not argue that noise presents a “fatal flaw” for any unit-specific or multi-mode cooling tower option. 230

4.5.1c Visual/Aesthetic ImpactsMA0003654 Determinations Document July 22, 2002

231 See Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. 6.

232 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, pp. 3.3-4, 3.3-10.

233 Id ., pp. 3.3-3, 4-5.

4-99 With respect to visual and aesthetic impacts, it cannot be denied that adding wet mechanical draft cooling towers will add additional visible industrial facilities to BPS; however, EPA does not believe that this ultimately should be regarded as a significant unacceptable impact when the environmental benefits of retrofitting such cooling towers are considered. In addition, the permittee has not argued that such impacts should be viewed as unacceptable.

BPS is already a huge industrial facility with large buildings, tall smoke stacks and electrical transmission lines on the site. Thus, mechanical draft cooling towers would not be out of character with the surroundings at the plant. 231 The cooling towers included as part of the ClosedCycle Unit 3 and Closed-Cycle Entire Station options would be built on fill at grade elevation +30 feet msl and are expected to be 65 feet above grade, with the top of the tower at around +95 feet msl). This would be shorter than the three existing 350-foot smoke stacks, the one existing 500- foot smoke stack, and the largest building on the site. 232 The cooling towers included as part of the Enhanced Multi-Mode option would be slightly taller, at 67 feet above grade, with the top of the tower at +97 msl. The four towers included as part of the Helper Cooling Tower option would be located behind an earthen berm back from the eastern shore of the existing discharge canal; approximately 250,000 cubic yards of earth that would have to be removed in order to locate the towers at the required elevation of approximate grade elevation 18.0 feet would be used to create the earthen berm as well as other barriers or roadways that would aid in visually blocking the towers.

The permittee does not contend that any of these options would present an unacceptable visual impact. EPA agrees with the permittee on this point. The mechanical draft cooling towers associated with each of the unit-specific and multi-mode cooling tower options should not have the sort of dramatic adverse visual impact that would be associated with conventional natural draft cooling towers, which typically are much taller than mechanical draft towers. That being said, EPA also agrees with the permittee that somewhat greater visual impacts might be imposed by the Closed-Cycle Entire Station option because more cooling tower cells mean additional visible facilities. 233

In addition, it is possible that under certain meteorological conditions, mechanical draft cooling towers would emit a visible plume into the air or create fog that could constitute an adverse visualMA0003654 Determinations Document July 22, 2002

234 See EPA TDD 2001 - New Facilities, p. 3-33; Badger Power EIS, at 54; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. 6; “AES Londonderry Highlights” (AES, Inc., January 18, 2002), p. 6.

235 See October 1982 Permit Modification Determination, pp. 19-20.

236 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974).

237 See March 4, 2002 memorandum from Mark Stein, EPA, to Brayton Point NPDES Permit File (“Memorandum to File re 2/21/02 Visit to Brayton Point Station for Meeting”).

4-100 impact. (The possible plume effects on traffic safety are discussed further below.) This could occur when ambient air temperatures are low, as compared to plume temperatures, and ambient humidity levels are high. The former condition promotes plume cooling and condensation, whereas the latter condition inhibits evaporation of the water in the plume. The direction and persistence of the plume would be determined by a number of factors including wind speed and direction, relative temperatures and humidity, the time needed for evaporation and dispersion, and the design of the cooling towers in question. Typically, a vapor plume will not be visible to off-site observers and or will dissipate after traveling a short distance due to dispersion and evaporation. 234

With respect to potential visual impacts from a visible plume from mechanical draft wet cooling towers at BPS, EPA notes that while our October 1982 Permit Modification Determination indicated that salt drift was the primary problem with the former Unit 4 spray pod cooling system, which sprayed warm water directly into the air for cooling, EPA stated that the system also created fog that was an undesirable impact for the local community. 235EPA believes that any fogging from new mechanical draft cooling towers would be either nonexistent or much less than was experienced with the old spray pod system. Mechanical draft towers, which are under consideration as BAT for reducing thermal discharges from BPS, do not throw the water directly into the air. Moreover, the permittee proposes that at BPS, these towers would be equipped with drift eliminators that would remove water droplets and reduce drift to a rate of .0005%. 236 This would mean a vastly reduced tendency to create visible fog as compared to the spray pod system and should reduce the density of any visible plume. Moreover, any fogging that did occur would typically be most severe on the plant site close to the towers. Finally, during at least some of the conditions when cooling tower fog might occur, naturally occurring fog would also be likely to occur in the coastal environment of BPS. 237Under such conditions, fogging from the coolingMA0003654 Determinations Document July 22, 2002

238 USGenNE’s plume modeling analysis predicts that, on average, over the course of a year, a 20-cell cooling tower would yield six hours of “plume-induced” fog at nearby receptors as compared to 336 hours of natural “background fog” ( i.e. , a less than 2 % increase). See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), App. B, p. 1 (Table: Hours of Plume Induced Fogging and Icing Summary). While this analysis was performed for a different purpose, it gives an idea of the relatively small marginal effect of the cooling towers on fog.

239 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974).

240 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3. See also EPA TDD 2001 - New Facilities, pp. 3-34 and 3-35; January 1997 NEPCO Report, p. 3- 21.

4-101 towers would present only a small marginal increase over background conditions. 238

In sum, EPA does not believe that the visible plume or any fogging from the cooling towers should be regarding as imposing an unacceptable adverse visual/aesthetic impact. In any event, the permittee would be required to satisfy all applicable air emission standards.

4.5.1d Salt Drift

With any salt water cooling tower, one must consider the issue of salt emissions from the towers. This should not be a significant problem at BPS, however, because the towers can be equipped with drift eliminators that reduce drift to 0.0005%. As the permittee has indicated, this would produce a rate of drift “several orders of magnitude lower than the total emissions from the past operation of the Unit 4 spray canal.” 239It would also produce “salt deposition and saline air concentrations that represent only a slight increase over ambient coastal conditions.” 240 However, to the extent that residential icing caused by salt drift is actually an issue, the concern would be greater from the options that involve more cooling towers and the placement of the cooling towers at the site. Any cooling towers that are installed and operated at BPS will have to comply with all applicable air emissions requirements ( e.g. , particulate emissions).

4.5.1e Energy

As discussed in Section 4.4, one detriment of switching BPS from open-cycle cooling to closedcycle cooling is that the change would marginally decrease the generating efficiency of eachMA0003654 Determinations Document July 22, 2002

241 See EPA TDD 2001 - New Facilities, § 3.3.2.

242 See id. , § 3.3.3.

243 See SAIC Report (March 15, 2002), Table 9. See also EPA TDD 2001 - New Facilities, Table 3-14.

244 See SAIC Report (March 15, 2002), Table 9. See also EPA TDD 2001 - New Facilities, Table 3-15.

245 See EPA TDD 2001 - New Facilities, p. 3-10.

246 See SAIC Report (March 15, 2002), p. 21.

247 Id ., Table 10.

248 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, p. 4-4. See also id. , Table 4-1.

4-102 converted unit (“efficiency penalty”). 241 In addition, the amount of electricity that a converted unit generates for sale would be further reduced because a certain amount of energy would have to be used to run the fans and pumps utilized in a mechanical draft cooling tower (“auxiliary power penalty”). 242

EPA estimates that as a result of conversion to wet mechanical draft cooling towers, assuming a 100% load factor, the annual efficiency losses for BPS would be approximately 0.29% for Units 1, 2 and 3, and 0.09% for Unit 4 (assuming current levels of piggyback operations). 243 These efficiency losses would increase to 0.75% for Units 1, 2 and 3, and 0.18% for Unit 4, assuming a load factor of 67%. 244

Since Units 1, 2 and 3 are base-load units with a capacity factor of approximately 80%, the penalties are expected to be in between the two sets of figures. 245 Because Unit 4 has a much lower capacity factor of around 20%, its penalty figures would likely be somewhat higher than those for the 67% load factor; however, because Unit 4 operates less often than the other three units, the efficiency penalty for that unit would have a relatively smaller effect on the overall efficiency of the plant. 246 It should be noted that EPA’s estimated efficiency penalties for the Enhanced Multi-Mode, Closed-Cycle Unit 3, and Closed-Cycle Entire Station options range from 58% to 77% lower than those predicted by the permittee. 247

The permittee also predicts that the unit-specific cooling options will result in greater lost generation than its Enhanced Multi-Mode option, because the multi-mode system has “more flexibility to operate at a higher performance relative to the structure’s size under a greater variety of atmospheric conditions than any of the other cooling tower alternatives.” 248This relates, at least in part, to the permittee’s predictions of plume outages for the unit-specific options but notMA0003654 Determinations Document July 22, 2002

249 See SAIC Report (March 15, 2002), p. 30.

250 See id. , Table 7. See also EPA TDD 2001 - New Facilities, pp. 3-22 to 3-30, Table 3-20.

251 Compare December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G (Tab: Dynamic Cost Analysis) withAbt Report (April 5, 2002), pp. 21-22.

252 See
, e.g. , EPA-New England, Energy Fact Sheet (February 12, 2001); “NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission, 2001 - 2010 (ISO-NE: April 1, 2001), pp. 1-2 (Section I Summaries, Summer and Winter System Capabilities and Peak Load Forecasts).

253 See SAIC Report (March 15, 2002), Tables 6, 7, 9, 10 and 11 (permittee and SAIC independent estimates of reduction in energy produced for sale by BPS due to Closed-Cycle Entire Station option are 3.3% and 2.6%, respectively). See also EPA TDD 2001 - New Facilities,

4-103 for the multi-mode options. As discussed in this determination document, however, EPA has concluded both that it is uncertain that the plume-related problems will be as significant as the permittee predicts, and that there are other methods for controlling any such problems than resorting to unit outages.

In light of our consultant’s analysis, EPA believes the permittee’s estimates of the auxiliary power penalties that it would incur are reasonable. 249For certain of the cooling options, the Agency’s estimates are lower, whereas for others, its estimates are higher. 250

On one level, these efficiency and auxiliary power penalties represent an economic issue ( i.e. , lost revenues due to reduced sales of electricity). Therefore, the company considered them in its economic evaluation of the alternatives, and EPA has done the same. 251 On another level, these penalties raise energy supply issues that should be considered. Having done so, however, EPA does not believe that these penalties are significant from an energy perspective, especially when considered in light of the major reduction in adverse impacts from thermal discharges that could be provided by a closed-cycle cooling system.

With regard to energy supply, EPA’s research indicates that New England has an adequate power supply at present and is predicted to have an adequate supply moving into the future, in part because of the construction and proposal of new power plants that have added, and will continue to add, generating capacity to the supply inventory in the Region. 252 Therefore, neither the small marginal loss in efficiency nor the small marginal increase in energy use that would result from converting to closed-cycle cooling at BPS would present a significant problem for the Region’s energy supply. 253 Moreover, as new, more efficient plants continue to come on line, the overallMA0003654 Determinations Document July 22, 2002

Tables 3-1, 3-2, 3-14, 3-15, 3-20.

254 See EPA TDD 2001 - New Facilities, p. 3-8.

255 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G, (Tab: Dynamic Cost Analysis, p. 4).

256 See Abt Report (April 5, 2002), pp. 12, 23-24.

257 See EPA TDD 2001 - New Facilities, p. 3-9.

4-104 efficiency of the Region’s energy supply will increase even if BPS has a marginal loss of efficiency due to shifting entirely or partially to closed-cycle cooling. For example, the proliferation of new, combined-cycle power plants will significantly increase the overallefficiency of the Region’s power supply and more than offset any lost efficiency from closedcycle cooling at BPS. 254

In addition, there is at least one potentially significant energy benefit provided by shifting to closed-cycle cooling. The permittee has determined that improved cooling would enable it to operate more at peak demand times during the hottest days of the year – assuming compliance with applicable air pollution standards – because the plant would less frequently threaten to exceed the permit’s current maximum temperature limit of 95° F. 255This not only would enable the plant to sell more electricity during the peak pricing period, which would benefit the permittee economically, but it also might benefit the Region’s overall power supply because that supply is most likely to be overstretched, if ever, during the hottest days of the year when peak demand

occurs. 256 With retrofitted wet cooling towers, BPS would be able to generate more power to help meet this peak demand. (It should also be noted, however, that this benefit could be marginally offset by the fact that efficiency penalties are likely to be somewhat greater during the hot summer days.) 257

4.5.2 Other Impacts

4.5.2a Traffic Safety (Fogging, Icing)

Another issue that EPA must consider in determining whether any of the unit-specific or multimode wet cooling tower options are BAT for reducing thermal discharges from BPS is whether there would be emissions of mist ( i.e. , water droplets) or water vapor that could cause a traffic hazard on nearby roadways due to fogging or icing. Protecting public health and safety is at the top of the priority list for EPA and the other involved state and federal agencies. Therefore, we take this issue seriously and have evaluated it from several perspectives.MA0003654 Determinations Document July 22, 2002

258 See
, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3.

259 See id. , pp. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974).

260 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3-3 n.7.

4-105 The permittee has stated that it believes that wet cooling towers at BPS would emit a vapor plume that could cause a fogging/icing traffic safety concern on nearby portions of Route 195 and the Braga Bridge. The permittee also has stated that it would have to shut down the cooling towers during these periods to eliminate this potential hazard. 258According to the permittee, this would substantially increase the cost of the unit-specific options because shutting down the cooling towers would also require shutting down the associated generating units. The permittee also states, however, that these increased costs could be avoided for the Enhanced Multi-Mode option, because multi-mode cooling towers could be bypassed if necessary to prevent fog or ice, and the generating units could continue to operate. This contributes to the permittee’s preference for the Enhanced Multi-Mode option from the perspective of cost and operational flexibility.

Based on current information, EPA’s conclusion with regard to the fogging/icing traffic safety issue is that it is uncertain whether this problem would occur to a significant degree if wet cooling towers are installed at BPS, but that there are several ways to eliminate the problem if it does occur. Methods for managing this potential problem are discussed below, along with the uncertainties surrounding the magnitude of the problem. Following that discussion, reasons for uncertainty regarding the likely extent of any problem are presented.

Mechanical draft cooling towers can be equipped with highly efficient mist (or “drift”) eliminators that can nearly eliminate the emission of water droplets (and salt) by the tower. As the permittee explains, such drift eliminators can achieve a drift rate of .0005%, which would represent only a very small marginal increase over the moisture naturally in the air in a coastal environment such as that around BPS. 259Thus, with the use of drift eliminators, the permittee should be able effectively to prevent mist emissions from any mechanical draft cooling towers retrofitted at BPS, and mist emissions should not significantly contribute to any fogging or icing in the vicinity of the Station.

As the permittee notes, however, mechanical draft wet cooling towers also emit water vapor (as opposed to mist ), which under certain meteorological conditions can condense and cause fog and/or ice on road surfaces. 260 The permittee has conducted a site-specific analysis, based on a 20-cell cooling tower, that predicts that a mechanical draft cooling tower at BPS would emit a plume of water vapor that under certain meteorological conditions could cause fogging or icingMA0003654 Determinations Document July 22, 2002

261 See id. , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001).

262 Id ., p. 3-3.

263 Id. , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), p. 9 and App. B, p. 1 (Table entitled “Hours of Plume Induced Fogging and Icing Summary”).

264 Id

.

265 Id ., p. 8.

266 See id. , Vol. IV, App. H, pp. 3-3, 3-4, 4-6; id. , Vol. III, App. G (Dynamic Cost Analysis, at 7).

4-106 on certain nearby “receptors. 261 In addition, the permittee has concluded that this fogging or icing could cause a traffic safety problem on Route 195 and the Braga Bridge. 262

The permittee’s analysis is based on a “CALPUFF” modeling analysis that uses among other things, meteorological data from the T.F. Green Airport in Providence, Rhode Island, from 1989 to 1993. This analysis estimates that in an average year, there are 343 hours of “background fog and ice” (336 hours of fog and seven hours of ice) near the plant, and that the cooling tower would add seven hours of “plume-induced fog and ice” (six hours of fog and one hour of ice). This represents only a two percent (2%) increase over background conditions. In addition, the analysis predicts that only four of these plant-added hours of fog or ice would actually “impact the highway and bridge.” 263

Nevertheless, the permittee’s modeling analysis also concludes that this vapor plume-induced fogging or icing threat to the highway or bridge would require cooling tower “plume outages” an average of 54 times a year for an average total duration during the year of 166 hours. 264 This is more than 41 times the number of predicted hours of plume-induced fog or ice at the highway and bridge (4 x 41.5 = 166). The permittee explains that this is because in order to prevent fog or ice beforeit occurs, the permittee would have to shut down the tower and generating unit whenever certain meteorological conditions occur that might lead to fog and ice, and that such conditions occur more frequently than actual fog or ice and may persist for several hours at a time. 265The permittee adds that the problem would be more severe if more than 20 cooling tower cells were utilized at the power plant. 266

The permittee also states that generating unit outages would be made even longer due to the fiveMA0003654 Determinations Document July 22, 2002

267 See id. , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01), Attachment A, p. 10.

268 Id ., Vol. III (Tab: Dynamic Cost Analysis), Unit 3 Conventional Closed Cycle Spread Sheet, p. 3.

269 See id. , Vol. IV, App. H, pp. 3-4 and 4-4, Table 4-1; Vol. III, App. G (Tab: Dynamic Cost Analysis, pp. 7-8; Tab: Section 308 Information Request Submittal - 9/10/01, p. 4).

4-107 to 12 hours necessary to get a generating unit back on-line after it has been taken off-line. 267 Indeed, in the permittee’s Dynamic Cost Analysis, the permittee assumes that 648 hours of generating unit outages per year would occur for the Closed-Cycle Unit 3 option, based on 54 outages and 12 hours of unit restart time, and that 486 hours per year of outage for Units 1, 2 and 3 would occur for the Closed-Cycle Entire Station option based on 54 outages with nine hours of restart time per unit. 268The 648 and 486 hours of predicted outage are 162 and 121 times more than the four hours of additional fog or ice actually predicted by the permittee’s model to affect the highway and bridge in the average year.

Based on its conclusion that water vapor plumes would require cooling tower shutdowns and associated generating unit shutdowns for the unit-specific cooling tower options, the permittee has included a substantial cost for hundreds of hours of “plume outages” for these options. The cost of these outages reflects lost profits due to the outages. 269The permittee has not included such costs for the Enhanced Multi-Mode option because that option allows for cooling tower bypass.

EPA has evaluated the plume/safety issue from a number of perspectives. Most importantly, EPA has concluded that to the extent a traffic safety issue may arise, there would be several means of adequately controlling it. First, as the permittee has indicated, if necessary, a cooling tower and associated generating unit could be shut down for a short period to avoid a safety issue. The permittee states that it would expect to undertake such shutdowns if necessary. With the multi-mode options, of course, the permittee could shut down the cooling towers but continue to operate the generating units. Likewise, EPA believes that the unit-specific options could be engineered to allow the cooling towers to be bypassed so that the generating units could be operated in once-through mode during the period of any plume-related safety hazard. As discussed above, EPA has learned that a number of power plants around the United States have cooling towers that are only used some of the time. Thus, it is clear that this is a practicable approach. Indeed, this ability to bypass the cooling towers is one key aspect of the multi-mode cooling tower operations. This approach may add some cost, due to piping or pumping needs, but any such costs would most likely be less expensive than the permittee’s predicted generating unit outages. EPA’s evaluation estimated what these costs might be and found them to be lessMA0003654 Determinations Document July 22, 2002

270 See SAIC Report (March 15, 2002), p. 13, Table 5; Abt Report (April 5, 2002), p. 8.

271 April 9, 2002 memorandum by Damien Houlihan, EPA (“Re: Record of 4/9/04 Conference Call with MA DEP and Massachusetts Highway Department”).

272 See EPA TDD 2001 - New Facilities, at p. 3-33; January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding Call with Ken Daledda, Bergen Station, New Jersey; Materials obtained from Marley Cooling Technologies, Inc.; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. xii; “AES Londonderry Highlights” (p. 6 of 7) (AES, Inc., 1/18/02).

273 SAIC Report (March 15, 2002), p. 14, Table 5. See also 66 Fed. Reg. 65283 (Dec. 18, 2001) (costs of dry cooling compared to costs of hybrid cooling and wet cooling); January 31, 2002 e-mail from Richard Scogland, Marley Cooling Technologies, to Sharon Zaya, EPA (“Subject: Cost Estimate for Marley’s Clearflow”); February 1, 2002 e-mail from Kenneth Detmer, Wisconsin Public Service Commission, to Mark Stein, EPA (“Subject: Cooling

4-108 than the cost of the outages. 270 (Costs are discussed more fully above.) Of course, the plant would still need to operate within its permit limits for flow, maximum-temperature, Œ -T, and Btu loadings, but this is also true for the multi-mode options.

Second, it might be feasible to develop an early warning system. When it is predicted that potentially hazardous fog or ice conditions might occur as a result of the cooling towers, instead of shutting the towers down, the permittee would notify the Massachusetts Highway Department in order to initiate icing controls ( e.g. , salting of roads) or activate lighted cautionary signs warning of potential fog conditions. As discussed above, the permittee’s analysis predicts only a small marginal increase in fog and ice conditions from background, and the Massachusetts Highway Department already has programs in place for dealing with these background conditions. 271

Third, there are plume abatement technologies that can be utilized with mechanical draft cooling towers to substantially reduce or eliminate vapor plume effects. Described above in Section 4.3.2, these technologies are generally referred to as “wet/dry” or “hybrid” cooling towers. 272 Switching to hybrid cooling towers, however, would significantly increase the capital cost of the equipment as compared to retrofitting wet mechanical draft cooling towers, and reduce electrical generation efficiency somewhat more than the use of wet cooling towers would. EPA’s consultants estimate that adding plume abatement could approximately double the capital cost of the cooling towers without plume abatement. 273MA0003654 Determinations Document July 22, 2002

Towers”); January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding Call with Ken Daledda, Bergen Station, New Jersey.

274 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G (Tab: Section 308 Information Request Submittal - 9/10/01, at 6).

4-109 Ultimately, of course, the permittee may choose whichever method it wants from the several practicable approaches should the need for plume abatement arise. The choice of method would most likely be determined by the cost and the permittee’s operational preferences. At present, the permittee indicates that it prefers the Enhanced Multi-Mode option because, among other things, the cooling towers could be shut down to avoid plume hazards without requiring generating unit outages. This option, however, would achieve lower thermal discharge reductions than any of the unit-specific options. For these options, the permittee indicates that it would engage in generating unit shutdowns to prevent plume-related hazards, but that these outages would result in substantial cost to the company. EPA has concluded, however, that engineering a “bypass” of the cooling towers would likely be a less expensive, more practicable alternative in the long run. Alternatively, an early warning system in conjunction with the Massachusetts Highway Department might be sufficient to avoid either outages or cooling tower bypasses. This would require further consultation and coordination between the Department, the permittee, EPA and the MA DEP. A more expensive option, but one that would maximize operational flexibility and the thermal discharge and flow reductions achievable by the unit-specific options, would be to install hybrid cooling. (The company also might want to consider, at a minimum, installing cooling towers that are amenable to retrofitting with plume abatement technology at a later date.)

Having addressed the issue of how to abate any plume hazards, EPA must state that based on current information, we believe it is uncertain that cooling towers at BPS would emit a vapor plume that would become a traffic hazard on the highway or bridge. It is also uncertain whether the hours of potential hazard predicted by the permittee would actually require generating units using cooling towers to be shut down for hundreds of hours per year in order to achieve our clear priority of ensuring public safety. (EPA recognizes, however, that if plume hazards are a problem, this problem could be worse for the Closed-Cycle Entire Station option. 274 )

There are several reasons why EPA believes that there is substantial uncertainty regarding whether the plume problem will be as severe as the permittee asserts. First, EPA has reviewed the permittee’s air modeling analysis and has a number of concerns and questions about it. While the CALPUFF model used by the permittee is certainly acceptable for certain air modeling purposes, there is a significant question as to whether the model and the pre- and post-processors used with the model were appropriate for the purpose of assessing the plume issue in this case, especially when compared to other models that have been developed more specifically forMA0003654 Determinations Document July 22, 2002

275 See February 1, 2002 e-mail from Kenneth Detmer, Wisconsin Public Service Commission, to Mark Stein, EPA (“Subject: Cooling Towers”) (expressing opinion that CALPUFF model works for wet/dry cooling tower evaluations, but uncertain about using it for traditional wet towers); January 3, 2002 memorandum from Brian Hennessey, EPA, to Mark Stein, EPA (“Air Impact Analysis of Evaporative Cooling for Brayton Point Generating Station (Somerset, Massachusetts)”); December 11, 2002 e-mail from John Irwin, EPA, to Warren Peters, EPA, et al. (cc: Brian Hennessey, EPA, et al.); December 5, 2002 e-mail from Warren Peters, EPA, to Brian Hennessey, EPA (cc: Joe Touma, EPA, John Irwin, EPA, et al.); January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding Call with Ken Daledda, Bergen Station, New Jersey.

276 January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding Call with Ken Daledda, Bergen Station, New Jersey; December 12, 2001 memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); 39 Fed. Reg. 36192 (October 8, 1974).

277 January 4, 2002 telephone memorandum from Sharon Zaya, EPA, regarding Call with Ken Daledda, Bergen Station, New Jersey.

278 January 1997 NEPCO Report, p. 3-21.

4-110 modeling cooling tower plumes (such as the SACTI model developed by EPRI). 275EPA does not presently believe that the permittee has established the reasonableness of its modeling analysis.

Second, experience of other plants does not appear to corroborate the threat suggested by the permittee. EPA spoke with representatives of two power plants that use wet mechanical draft cooling towers, and learned that any icing concerns that do exist at these plants are limited to areas very close to the cooling towers (within a few hundred feet) and have not affected roadways or bridges within relatively short distances from the towers (in one case, within approximately a half-mile, and in another case, within about 700 feet). 276 Neither icing nor fogging appeared to create a problem in any of the situations referenced above. One plant did install a wet/dry system to enable it to remove a visible plume due to initial concerns over potential highway icing or fogging, but this plant reported to EPA that the plume did not turn out to pose a fogging/icing hazard in practice. This plant only uses the “dry components” to mitigate an aesthetic issue related to a periodically visible plume of fog during humid conditions. 277

Third, EPA notes that in the January 1997 NEPCO Report, the permittee predicted that although “incidence of ground fog can occur during periods of high relative humidity, cool weather, moderate to low winds and inversions or some combination thereof ... [,i]t is unlikely however that the fog would extend further than 500 to 1,000 feet downwind of the towers.” 278No concernMA0003654 Determinations Document July 22, 2002

279 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, pp. 3-1, 3.2-1, 3.2-19.

280 See Figure 7.3-1, “Brayton Point, Somerset, MA, Distances from Proposed Cooling Towers to Sensitive Receptors (EPA, Jan. 24, 2002).

281 See id.

282 See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, Figures 3.2-19, 3.2-23.

4-111 was expressed about off-site icing. Furthermore, in the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee explained that the helper towers are identical to the mechanical draft cooling towers, and that even for the 48-cell helper tower, “[f]ogging during cool wet weather, and when temperatures are cold enough, icing are expected to rarely be an issue with the helper tower design since these are local effects and the helper towers are located near thedischarge canal and further away from the highway and bridge than the multi-mode or closedcycle alternatives.” 279The area near the discharge canal appears to be only about 500 feet or less further from the highway and bridge. 280

Although the permittee expresses particular concern over fogging and icing impacts to Route 195 and the Braga Bridge, the bridge appears to be approximately 5000 feet (0.95 miles) from where the cooling towers would be located, while the nearest point on Route 195 is approximately 2164 feet away (0.41 miles), and the nearest residential streets are approximately 1900 feet away (0.36 miles). 281 Moreover, moving the unit-specific cooling towers further to the south on the site, into the area where the permittee suggests the Helper Cooling Tower option could be located, would add even more distance and make any potential problems even less likely. 282

Fourth, as a matter of common sense, it does not seem that the problem should be severe enough to require hundreds of hours of generating unit outages. The permittee’s own analysis confirms that the roads and highways in the coastal environment of Mount Hope Bay periodically experience icing and fogging from natural conditions that is managed by local highway safety programs. The permittee’s analysis predicts that a 20-cell cooling tower would add only a small marginal increase in fogging and icing (around 2%) over background conditions in an average year. This average increase is well within the range of natural fluctuation in backgroundconditions. Again, the permittee predicted that in an average year only one hour of “plumeinduced ice”and only six hours of “plume-induced fog” would occur, as compared to 343 hours of “background fog and ice” (a 2 % increase). Only four of these hours of plume-induced fog or ice were predicted to “impact the highway and bridge.” In response to this, the permittee predicts that literally hundreds of hours of unit outages per year would be needed to eliminate thisMA0003654 Determinations Document July 22, 2002

283 See id. , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), p. 9 (of 13) and App. B, p. 1 (Table: Hours of Plume Induced Fogging and Icing Summary).

284 It is worth noting that Badger Generating Company, LLC, an affiliate of PG&E operating in Wisconsin, proposed a new combined-cycle natural gas electric generating plant in the village of Pleasant Prairie, WI that would use hybrid wet/dry cooling towers to control any threat of fogging or icing on roadways surrounding the facility. With the hybrid cooling towers, the analysis concluded that only a few hours per year of fogging and/or icing would result on certain roads immediately surrounding the plant. There was no suggestion, however, that these few hours of predicted fog or ice required many times more hours of generating unit outages, or indeed any outages at all, to eliminate all possibility of any fog or ice. In addition, the company argued that “[o]n days of rain, fog, snowfall, or blowing snow . . . plant-induced fogging and icing would not be important, since there might already be fog and ice on Pleasant Prairie roads and drivers would already be more cautious.” The Public Service Commission and the Department of Natural Resources of the State of Wisconsin considered the potential for additional fogging and icing to be a concern but were satisfied with the few hours that would be left after the installation of hybrid cooling. Thus, the State approved the facility recognizing the small number of hours of plant-induced fogging and/or icing that might occur. See Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), pp. xi, 73-74, 137-138.

4-112 potential plume effect. 283 As discussed above, this seems unrealistic based on common sense and experience at other plants, and we are not yet persuaded of the validity of the permittee’s modeling analysis. 284

Nevertheless, as stated above, the permittee proposes to address possible plume hazards from the unit-specific options by shutting down generating units and their associated cooling towers during conditions when it believes the risk exists. As a result, the permittee includes the cost of such outages in the costs of these closed-cycle cooling tower options. Because of EPA’s uncertainty about the likely need for these outages, EPA has evaluated the costs of these options under the following three scenarios: (a) accepting the permittee’s estimate of plume outages, (b) assuming half the plume outages predicted by the permittee, and (c) assuming no plume outages.

4.5.2b Plant Reliability, Operational Flexibility and Construction-Related Outages

The permittee argues that the unit-specific cooling tower options, but not the Enhanced MultiMode option, reduce plant reliability because of the potential for plume-related outages in theMA0003654 Determinations Document July 22, 2002

285 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 4-3.

286 Id. , p. 4-5.

287 See id. , p. 4-4 and Table 4-1 ( e.g. , 5.5 months for Enhanced Multi-Mode option; 8 months for Closed-Cycle Unit 3 option).

4-113 winter attributed to fogging/icing problems. 285Any problem in this regard would be more severe for the options using more cooling tower cells. As explained above, however, EPA believes that plume-related hazards of the magnitude suggested by the permittee are uncertain, and that there are methods of controlling any such hazards without generating unit outages.

Nevertheless, if such temporary outages were to occur, as predicted by the permittee, it would ultimately represent an economic issue to the permittee rather than an energy supply problem to the region. It is unlikely that any such temporary, intermittent outages would jeopardize the adequacy of the region’s power supply because that supply is constituted and managed to respond to occasional scheduled and unscheduled outages while maintaining adequate power. Any plume-related outages would similarly be managed without supply shortfalls. In addition, as discussed above, adding cooling tower technology is expected to enable BPS to generate somewhat more electricity during peak summer demand periods. This may help the regional power supply at the time it is most stressed.

For the installation of any of the closed-cycle cooling tower options at BPS, the permittee also predicts generating unit outages “for the tie into ... the generating units ... [to] complete the cooling system conversion.” 286 Unlike plume outages, construction outages are one-time events. Although any such outages would be sequenced to coincide with regularly scheduled maintenance outages, the permittee predicts that the construction outages would exceed the duration of the regular maintenance outages and, therefore, represent additional downtime for theunits involved. The permittee predicts that these outages will be somewhat greater for the unitspecific options than the Enhanced Multi-Mode option. 287

There is no reason to expect that these one-time outages should endanger the region’s power supply. The regional power supply is already managed to accommodate periodic scheduled and unscheduled outages without a shortfall in capacity. There is nothing to suggest that the type of outages discussed here could not be handled in this manner. These outages could also, if necessary, be scheduled and sequenced to avoid peak demand periods. Ultimately, any such outages represent an economic issue for the permittee, and both EPA and the permittee have evaluated such outages in our economic analyses. It should also be noted here that EPA believes as an engineering matter that the permittee has overestimated the necessary construction outagesbased on research concerning other plants that have converted their cooling systems from oncethrough to closed-cycle cooling towers.MA0003654 Determinations Document July 22, 2002

288 Id. , p. 4-4.

289 Given that fuel is currently barged to the plant, it may also be feasible to bring some materials to the site by water so as to minimize truck traffic on streets surrounding BPS.

290 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, Table 4-1; Vol. V, App. B (Tabs B6, B7, B13, B15 and B16).

4-114 4.5.2c Construction Effects

As the permittee states, all of the cooling tower options raise the likelihood of some “moderate” noise and truck traffic effects from construction activities. 288It should also be noted that construction for new air pollution control equipment will be occurring during a similar timeframe. Ultimately, some construction effects cannot be avoided if improvements are to be made to reduce the plant’s adverse water and air impacts on the environment; however, no filling of wetlands or tidelands should be needed for any of the construction. Moreover, the industrial nature of the site and existing facilities, as well as the large size and buffering capacity of the site, should moderate the impacts of construction. Any effects would be further reduced if the facilities were constructed in areas farther from local residences. Compliance with all local traffic and noise ordinances will be required. 289

The single-unit and multi-mode cooling tower options have roughly similar construction periods of 13 months for the Unit 3 option and 16 months for the multi-mode options, whereas the Closed-Cycle Entire Station option has a longer construction period of 32 months. 290 Thus, construction effects would undoubtedly increase as more units are converted to new cooling systems.

4.6 Determination of Technology-Based Discharge Limits

Section 4.6 discusses the analyses presented above, evaluates whether any of the unit-specific or multi-mode cooling tower-based options under consideration is the Best Available Technology Economically Achievable ( i.e. , BAT) for reducing thermal discharges from BPS, and presents EPA’s determination regarding the necessary NPDES permit requirements for BPS under CWA §§ 301(b)(2) and 304(b)(2). To the extent that this section reiterates matters that have been discussed and documented in earlier sections of this document, supporting references will not be repeated here.

In short, EPA evaluated numerous cooling system options to determine what might constitute BAT for reducing thermal discharges from BPS. Based on its own research and analysis as well as on information submitted by the permittee, EPA has concluded that the thermal discharge limits for BPS should be based on the discharge commensurate with converting Units 1, 2, 3 andMA0003654 Determinations Document July 22, 2002

291 See Abt Associates, Inc., “Impact of Thermal Discharge Management and Air Pollution Control Options for Brayton Point Station on New England Electricity Market and Consumer Rates,” p. 3 (May 8, 2002).

4-115 4 to closed-cycle cooling using mechanical draft wet cooling towers ( i.e. , the Closed-Cycle Entire Station option). Retrofitting the entire station with closed-cycle mechanical draft cooling towers would greatly reduce the total annual heat discharge from BPS to Mount Hope Bay, shrinking it to 0.8 TBTU from the 42 TBTU currently allowed under MOA II (a reduction of approximately 98%).

4.6.1 Introduction

BPS is the largest fossil fuel burning power plant in New England. With an operating capacity of approximately 1500 MW – approximately 1100 MW from coal-burning Units 1, 2 and 3, and 400 MW from oil/natural gas-burning Unit 4 – BPS produces about six percent of the electricity consumed by New England (at 2001 consumption levels). 291 As such, it is clearly an important contributor to New England’s power supply at the present time.

The facility covers approximately 250 acres at the confluence of the Taunton and Lee Rivers. The four fossil-fueled electric power generating units are contained in boiler and turbine houses, which are connected in line to form the power plant. Maintenance facilities, laboratories and administrative offices are attached to the east side of the plant. Three 350-foot stacks for Units 1, 2, and 3, one 500-foot stack for Unit 4, and five fuel oil storage tanks with a combined capacity of 1,386,000 barrels are located south of the plant. A nine-acre, 600,000 ton-capacity coal storage area is located east of the oil storage area. A dredged channel is located along the west side of the coal storage area for ships delivering fuel to the station.

A spray cooling canal for Unit 4 condenser cooling water was built north of the plant but is now mostly filled in with structural fill from the coal units. Within the remains of the cooling canal loop are two wastewater treatment basins. Adjacent to the canal on the west and north sides are wastewater treatment sludge disposal trenches. Also on the north side of the plant and east of the former spray cooling canal are transmission lines, which run northeasterly off the station site onto a company right-of-way.

The four boilers inside the plant (one for each power generating unit) utilize coal, No. 6 fuel oil or gas. Units 1, 2, and 3 were put in service in August 1963, July 1964, and July 1969, respectively. They were originally designed to burn coal but were converted to burn oil in 1969. The units were converted back to burn coal in early 1982. Unit 4, designed to burn oil, was put into service in December 1974, with gas-fired capability added in 1992.MA0003654 Determinations Document July 22, 2002

292 CWA § 301(b)(2), 33 U.S.C. § 1311(b)(2) (emphasis added).

4-116 A once-through condenser cooling system with a design flow of 640,000 gpm is currently used for Units 1, 2 and 3. The condenser cooling system for Unit 4, originally closed-cycle, was converted to once-through operation with a design flow of 260,000 gpm beginning in July 1984. An additional once-through flow of 31,000 gpm is currently used by all four units for cooling water and other plant uses ( e.g. , service water). Condenser cooling water for each unit and service water for the station are currently discharged on the west side of the plant site and directed through a discharge channel to upper Mount Hope Bay. The 3,200-foot long discharge channel terminates at the southern tip of the plant site at a venturi designed to promote rapid mixing with the surrounding cooler water.

4.6.2 Brief Reiteration of Legal Standards

CWA §§ 301(b)(2) and 304(b)(2) require EPA to establish permit limits for thermal discharges based on the degree of control attainable by the Best Available Technology Economically Achievable ( i.e. , BAT). For point sources in the steam electric power generating point source category, such as BPS, EPA develops technology-based thermal discharge limits based on BAT using Best Professional Judgment (BPJ) under CWA § 402(a)(1), because there is no national effluent limitation guideline on the discharge of heat from these point sources.

For heat and other non-conventional pollutants, as well as for toxic pollutants, the CWA requires the achievement of

effluent limitations for categories and classes of point sources, other than publicly owned treatment works, which ... shall require application of the best available technology economically achievable for such category or class, which will result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants , as determined in accordance with regulations issued by the [EPA] Administrator pursuant to [CWA § 304(b)(2),] section 1314(b)(2) of this title, which such effluent limitations shall require the elimination of discharges of all pollutants if the Administrator finds, on the basis of information available to him ... that such elimination is technologically and economically achievable for a category or class of point sources as determined in accordance with regulations issued by the [EPA] Administrator pursuant to [CWA § 304(b)(2),] section 1314(b)(2) of this title .... 292

This means that EPA must set limits that (1) represent a minimum level of treatment based on technologies that are technologically available and economically achievable, and (2) will result in reasonable progress toward the elimination of the discharge of such pollutants. Such limits are BAT limits.MA0003654 Determinations Document July 22, 2002

293 See CWA § 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B). See also 40 CFR § 125.3(d)(3).

294 Ass’n of Pacific Fisheries v. EPA , 615 F.2d at 818.

4-117 CWA § 304(b)(2) requires EPA to take into account the following factors -- referred to in this document as BAT factors -- when it sets BAT limits: the age of the equipment and facilities involved; the manufacturing processes used; the engineering aspects of the application of recommended control technologies, including process changes and in-plant controls; non-water quality environmental impacts, including energy requirements; cost; and such other factors as EPA deems appropriate. 293

Significantly, the statute sets up a loose framework for EPA’s evaluation of the BAT factors in setting BAT limits. It requires not that EPA compare the factors, but rather only that it consider them. Moreover, it does not specify any particular process by which the Agency is to consider the BAT factors, and it does not assign a particular weight to one or more of the factors. Instead, the Act gives EPA discretion to decide how to account for these factors and how much weight to give each factor. In sum, Congress mandated that when EPA considers the BAT factors in setting BAT limits, it be governed solely by a standard of reasonableness. That is, EPA must consider each factor, but it has considerable discretion in identifying and evaluating the more relevant factors and determining the weight to be accorded to each in reaching its ultimate BAT determination. One court has succinctly summarized the standard for measuring EPA’s consideration of the BAT factors in setting BAT limits: “[s]o long as the required technology reduces the discharge of pollutants, our inquiry will be limited to whether the Agency considered the cost of technology, along with other statutory factors, and whether its conclusion is reasonable.’” 294

Technological Availability. “Best available” technology refers not only to the best performing plant in a given industry, but also to any viable transfer technologies ( i.e. , technology from another industry that could be transferred to the industry in question), including technologies that have been shown to be viable in research even if not yet implemented at a full-scale facility.

EPA must articulate the reasons for its determination that the technology it has identified as BAT is technologically available. Courts have construed the CWA as not requiring EPA to identify the specific technology or technologies a plant must install to meet BAT limits. The Agency merely has to demonstrate that the technology it used to estimate BAT limit costs is a reasonable approximation of the type and cost of technology that must be used to meet the limitations.

The BAT factors that bear on technological availability include the age of the equipment and facility involved. Age by itself is not relevant to the type of treatment technology to be installed to achieve BAT limits. The type of treatment technology to be applied is primarily a function ofMA0003654 Determinations Document July 22, 2002

4-118 the pollutants present in a facility’s effluent and thus is a function of the type of operation conducted, not the facility’s age. However, age does have a bearing on the cost and feasibility of retrofitting existing plants to meet BAT limits. Therefore, to set a BPJ-based BAT limit for thermal discharges from BPS in accordance with CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3(d)(3), EPA considered the age of the electric power generation units comprising the facility and their cooling system components as it had a bearing on both the costs of retrofitting one or more those units with the available treatment technologies that the Agency was evaluating as BAT, and the feasibility of such retrofitting.

The factors that EPA must consider in developing BAT limits also include (1) the process or processes employed by the point source category or subcategory or the individual discharger for which the BAT limits are being developed, (2) engineering aspects of the treatment technologies that are being evaluated as BAT, and (3) the changes to the point source process or processes that will result from application of the treatment technology in question. As noted above, EPA has considerable discretion in evaluating the more relevant factors and determining the weight to be accorded to each in reaching its ultimate BAT determination. For example, the Agency can determine that a technology is feasible and will achieve a level of effluent reduction but cannot be designated as BAT in part because its use will result in a significant loss in production. In setting the BPJ-based BAT limit for thermal discharges from BPS, EPA considered (1) the steam electric power generation processes currently employed by BPS; (2) engineering concerns relating to the application of the treatment technologies evaluated as BAT to these processes; and (3) the types of process changes that would result. These factors are related to the age factor insofar as they relate to the feasibility of retrofitting an existing facility to achieve BAT.

Economic Achievability. It is well established that the CWA gives EPA considerable discretion in determining what is economically achievable. CWA § 301(b)(2) neither specifies any special method of evaluating the costs of compliance with BAT limits nor states how those costs should be considered in relation to the other BAT factors. It only directs EPA to consider whether the costs associated with pollutant reduction are “economically achievable.” Similarly, CWA § 304(b)(2)(B) only requires EPA to “take into account” the costs of BAT along with the other BAT factors. In sum, the Act does not require EPA to undertake a precise calculation of the costs that would be incurred to comply with BAT limits. Rather, the Agency need make only a reasonable cost estimate in setting those limits.

The courts, including the United States Supreme Court, have consistently read the CWA and its legislative history as indicating Congress’s intention that while EPA should consider costs in setting BAT limits, it is not required to perform a cost-benefit analysis or any other kind of balancing test, and that cost is not a factor of primary importance. When a court reviews EPA’s BAT determination for a specific point source category or individual discharger, as long as the required technology reduces the discharge of pollutants, the court’s inquiry will be limited to whether the Agency considered the cost of technology, along with other statutory factors, andMA0003654 Determinations Document July 22, 2002

4-119 whether its conclusion is reasonable.

Non-Water Quality Environmental Impacts. EPA is not required to consider water quality impacts in setting BAT limits, but it must consider environmental impacts that are not water quality-related. In fact, EPA may determine that a particular technology is technologically available and economically achievable but should not be the basis for BAT limits because of unacceptably high non-water quality environmental impacts.

The CWA gives EPA broad discretion in deciding how to evaluate non-water quality environmental impacts and weigh them against the other BAT factors. The Agency does not need, for example, to demonstrate that the non-water quality environmental impacts of a particular technology are wholly disproportionate to the possible pollution reduction that would result from applying the technology to set BAT limits. Rather, it must apply its discretion and expertise to the relevant information at hand regarding the relative impact of two different environmental harms, and demonstrate on the record that it has considered this information in light of all the BAT factors.

Other Impacts.

CWA § 304(b)(2) also allows EPA to take into account such other factors as the Agency deems appropriate when setting BAT limits.

4.6.3 The Technological Availability of the Closed-Cycle Entire Station Option

EPA evaluated a number of cooling system options, including the Closed-Cycle Entire Station option. For example, we assessed and rejected dry cooling technology on the grounds that it costs roughly three times as much as wet mechanical draft cooling tower technology, and as far as we or the permittee could learn, no large existing power plant has been retrofitted to dry cooling. In the Agency’s detailed review of the cooling-tower based options we determined to have the most potential to be BAT for reducing thermal discharges from BPS, we evaluated partial closed-cycle cooling options that would involve retrofitting wet mechanical draft cooling tower technology at fewer than all of BPS’s generating units ( e.g. , the Closed-Cycle Unit 3 option). In addition, we assessed the 48-cell Helper Tower option proposed by the permittee.

Finally, EPA carefully evaluated the permittee’s Enhanced Multi-Mode option. This option would utilize closed-cycle cooling with wet mechanical draft cooling towers configured in such a way that the towers could be by-passed or could cool water from different units under different circumstances. Again, EPA commends the permittee for developing and proposing the Enhanced Multi-Mode option. Indeed, we believe that the Closed-Cycle Entire Station cooling system should be designed and constructed with the ability to by-pass cooling towers that the Enhanced Multi-Mode option includes. Such cooling tower by-pass capability has been used atother existing power plants. Ultimately, however, EPA determined that the Enhanced MultiMode option could not be the “best” available technology because it achieves far lower thermalMA0003654 Determinations Document July 22, 2002

295 Ass’n of Pacific Fisheries , 615 F.2d at 818.

4-120 discharge reductions than the Closed-Cycle Entire Station option.

EPA has concluded that closed-cycle mechanical draft cooling towers are technologically available for retrofitting at Units 1, 2, 3 and 4 at BPS ( i.e. , the Closed-Cycle Entire Station option). This conclusion is based on the Agency’s careful consideration of the BAT factors relevant to technological availability: the age of the plant and its operating systems, the processes the plant uses, and the changes that would be necessary to the plant and its operating systems and processes in order to install and operate closed-cycle mechanical draft cooling towers.

The permittee has contended that retrofitting closed-cycle cooling at BPS would pose design, engineering and construction difficulties because of incompatibility between the Closed-Cycle Entire Station option and the existing station. According to the permittee, the fact that BPS is already built means that any retrofit project there would need to take into account not only the once-through cooling system components that are already in place and in use at the site, but also the other site structures and features that already exist there, and the limited open space available at the site as a result of those structures and features that are already present.

EPA agrees with the permittee that retrofitting the Closed-Cycle Entire Station option at BPS would be complicated because of these considerations. The Agency notes, however, that the permittee has not asserted that such a retrofitting project would be infeasible due to any of these considerations. Moreover, in its research for the CWA § 316(b) Phase II Existing Facility proposed rule, EPA identified several other large power plants that have successfully converted from once-through cooling to closed-cycle mechanical draft cooling towers. These towers have been designed and installed to work effectively in cooling systems using salt or brackish water, as BPS’s existing cooling system does. Finally, the permittee itself has confirmed the technological availability of the Closed-Cycle Entire Station option: in the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee presents preliminary design specifications, a site layout and a proposed construction schedule for the Closed-Cycle Entire Station option, and explains in detail both how this closed-cycle mechanical draft cooling tower system would be retrofitted at BPS’s four steam-electric generating units and how it would operate once installed.

4.6.4 The Economic Achievability of the Closed-Cycle Entire Station Option

As discussed in detail above, the CWA provides that even minimal environmental impact can be regulated as long as the BAT limits in question are technologically and economically achievable. The courts have agreed that when they review EPA’s BAT determination for a particular point source category or individual discharger, “[s]o long as the required technology reduces the discharge of pollutants, [their] inquiry will be limited to whether the Agency considered the cost of technology, along with other statutory factors, and whether its conclusion is reasonable.’” 295MA0003654 Determinations Document July 22, 2002

4-121 Therefore, in setting the BPJ-based BAT limit for thermal discharges from BPS, EPA considered the costs of the various technologies that could be used as BAT at the plant, the economic impact of these costs on the permittee and ratepayers, and the reasonableness of these costs and impacts in light of the CWA’s ultimate goal of eliminating the discharge of all pollutants. Based on all these considerations required by CWA §§ 301(b)(2) and 304(b)(2), we have concluded that retrofitting closed-cycle mechanical draft cooling towers at Units 1, 2, 3 and 4 at BPS ( i.e. , the Closed-Cycle Entire Station option) is economically achievable for the permittee.

Both the permittee and EPA prepared detailed estimates of the potential costs to the permittee of implementing the unit-specific and multi-mode cooling tower-based options under consideration to be BAT for reducing thermal discharges from BPS. Despite the parties’ efforts to narrow areas of disagreement, our respective cost estimates vary considerably. Nonetheless, EPA believes its cost estimates are reasonable and appropriate in light of the CWA’s ultimate goal of eliminating the discharge of all pollutants.

EPA’s cost estimates are reasonably conservative and based on sound, careful evaluation (the Agency’s cost analyses having been conducted in conjunction with expert consultants). Capital costs represent the largest source of variation in the estimates developed by EPA and the permittee. In fact, EPA conducted two different, independent analyses to develop capital cost estimates, and both yielded far lower figures than those estimated by the permittee. EPA used the higher of our two independent capital cost estimates in our subsequent analyses.

Apart from capital costs, there were other areas of difference between EPA’s and the permittee’s cost estimates. These include the magnitude of the efficiency and auxiliary power penalties that the permittee would incur to operate various cooling system options, the length of generating unit outages that would be necessary for cooling tower construction, and the discount rates used in the calculations. Again, EPA believes its analyses and their conclusions are reasonable and appropriate. These factors are discussed in more detail earlier in this document. In the table below, we have set forth certain relevant figures from EPA’s and the permittee’s respective analyses related to the Closed-Cycle Entire Station option.MA0003654 Determinations Document July 22, 2002

4-122 Table 4.6-1: Comparison of Selected Permittee and EPA/Abt Cost Scenarios

Technology Option Permittee 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 30 years)
Closed-Cycle Entire Station

0% plume abatement 2 Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

$254.485 Million

$40.657 Million $68.385 Million

$9.041 Million

$83.269 Million

$11.009 Million $67.975 Million

$8.314 Million

$85.803 Million

$10.494 Million

1 The permittee’s figures for the Closed-Cycle Entire Station option reflect its capital costs and its assumptions for generating unit outages for water vapor plume abatement.

2 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed if necessary to avoid generating unit outages for plume abatement.

3 The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multimode/bypass functioning.MA0003654 Determinations Document July 22, 2002

4-123 Assuming a twenty-year equipment life, the permittee estimated the Total After-Tax Cash Flow Cost, Present Value costs for the Closed-Cycle Entire Station option to be approximately $254 million, with an equivalent annual cost of approximately $41 million. However, also assuming a twenty-year equipment life, EPA estimated the Total After-Tax Cash Flow Cost, Present Value costs for the Closed-Cycle Entire Station option, assuming no plume abatement outages and increased capital costs to allow for bypass capability of the cooling towers, to be approximately $68 million, with an annual equivalent cost of approximately $9 million. Assuming a thirty-year equipment life, which EPA believes is more likely, the total costs are still approximately $68 million, but the equivalent annual cost drops to $8 million.

In sum, based on the information available to us to date, EPA has concluded that the cost of implementing the Closed-Cycle Entire Station option at BPS is reasonable, and that, therefore, the Closed-Cycle Entire Station option is economically achievable for the permittee. We believe this to be the case whether one considers the EPA costs with the zero percent or the 100 percent plume abatement economic effects scenario (and we believe the zero percent scenario is more likely), as well as whether one considers EPA’s cost estimates or the permittee’s cost estimates (although we believe EPA’s estimates are more reasonable and should be used). Indeed, the permittee has not presented an economic inachievability argument to the regulatory agencies. EPA understands that the expenditures contemplated are significant and will cut into the permittee’s profits. Nevertheless, BPS has long been a very profitable plant, and it will remain so after the improvements associated with the Closed-Cycle Entire Station option are installed.

4.6.5 Non-Water Quality Environmental Impacts

EPA considered the various environmental and energy issues that are raised by a proposed conversion from once-through cooling to the Closed-Cycle Entire Station option. We believe that the environmental issues that the permittee has raised in its submissions to the regulatory agencies are either insignificant or can be managed. As discussed in detail above, neither noise, air emissions, aesthetic concerns, salt drift nor any other issue raises a problem that renders modernizing the BPS cooling system by retrofitting wet mechanical draft cooling towers infeasible or inappropriate. Obviously, the facility would need to comply with federal, state and local requirements for noise and air emissions.

4.6.6 Other Impacts

The permittee has raised the issue of whether traffic safety problems could result from cooling tower vapor plumes causing fog or ice affecting Route 195 or the Braga Bridge. The permittee indicates it could alleviate any such problem by instituting periodic generating unit shutdowns, but asserts that such shutdowns would be very expensive.

EPA has examined this issue in depth because it raises the possibility of a public safety concern.MA0003654 Determinations Document July 22, 2002

296 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, App. H, p. 3.3-25.

4-124 Our research on the vapor plume fog/ice issue at other plants indicates that it is unlikely that cooling tower plumes would create fog or ice that would pose significant traffic safety problems at Route 195 or the Braga Bridge and require generating unit shutdowns. Indeed, the permittee’s analysis – about which EPA has many questions and reservations – suggested only a small marginal potential increase in fog or ice over existing background conditions, and this possible increase was well within the range of natural variability in the background conditions. Nevertheless, EPA also believes there are a number of potential ways to deal with any problem that does emerge. These range from coordinating extra safety measures with the Massachusetts Highway Department (MHD) ( e.g. , deployment of extra fog warning signs, extra road sanding/salting crews, as EPA and the MA DEP have discussed with the MHD), to engineering the cooling towers so that they can be by-passed ( i.e. , shifted to temporary once-through cooling operations) if necessary to protect traffic safety, to undertaking cooling tower and generating unit shutdowns if absolutely necessary to ensure public safety. However, EPA does not believe the last situation is likely to occur. The permittee could install hybrid (wet/dry) cooling towers to further reduce any threat of vapor plume problems, but the likely extent of the potential problem does not appear to warrant the increased expense of this technology.

4.6.7 Conclusion

In light of its analysis in accordance with CWA §§ 301(b)(2) and 304(b)(2) and 40 C.F.R. § 125.3, and based on Best Professional Judgment ( i.e. , BPJ) under CWA § 402(a)(1), EPA concludes that the Closed-Cycle Entire Station option is technologically available and economically achievable, and will result in reasonable progress toward the elimination of the discharge of all pollutants. See CWA §§ 301(b)(2)(A), 304(b)(2)(B), 33 U.S.C. §§ 1311(b)(2)(A), 1314(b)(2)(B). EPA therefore concludes that a thermal discharge limitation based on the Closed-Cycle Entire Station option, i.e. , an annual heat load discharge limit of 0.8 TBTU with a maximum temperature of 85 °F 296 , reflects the Best Available Technology Economically Achievable ( i.e. , BAT) for reducing thermal discharges from BPS and should be the annual heat load discharge limit for BPS under CWA § 301(b)(2) and in accordance with CWA § 304(b)(2) and 40 C.F.R. § 125.3.MA0003654 Determinations Document July 22, 2002

1 EPA regulations do allow a State to “remove a designated use” (though not an “existing use”) of a water body specified in State water quality standards if various conditions are met, including that imposing controls more stringent than standards under CWA §§ 301(b) and 306 would result in “substantial and widespread economic and social impact.” 40 C.F.R. § 131.10(g)(6).

5-1 

### 5.0 Thermal Discharge Standards Based on State Water Quality Standards or Other Requirements of State Law

5.1 Introduction

BPS discharges thermal effluent into Massachusetts waters. These discharges may also adversely affect Rhode Island waters. As a result the water quality requirements of both States must be considered in the development of the new NPDES permit for BPS. The legal requirements and context related to the potential for thermal discharge limits based on State requirements is set forth below. This discussion is followed by a description and explanation of any State requirement-based permit limitations that have, in fact, been included in the Draft permit.

5.2 Legal Requirements and Context

As discussed above, CWA §§ 301 and 402(a) require NPDES permits to include effluent limitations based on applicable technology standards. CWA §§ 301(b)(1)(C) and 402(a) require that permits also include “any more stringent limitation, including those necessary to meet water quality standards, treatment standards, or schedules of compliance, established pursuant to any State law or regulations (under authority of section 1370 of this title [(i.e., CWA § 510)]) . . ., or required to implement any applicable water quality standard established pursuant to this chapter.” 33 U.S.C. § 1311(b)(1)(C). Section 301(b)(1)(C)’s mandate applies regardless of whether EPA or a State is the permit issuing authority and, for an EPA-issued permit, applies regardless of whether the State expressly demands that such conditions be placed in the permit. These statutory requirements are also embodied in EPA regulations at 40 C.F.R. §§ 122.4(d) and 122.44(d)(1), (2) and (5). See PUD No. 1 of Jefferson County v. Washington Department of Ecology , 511 U.S. 700, 705 (1994) (“The Act also allows States to impose more stringent water quality controls. See 33 U.S.C. §§ 1311(b)(1)(C), 1370.”); Arkansas v. Oklahoma , 503 U.S. 91, 106 (1992) (“§ 301(b)(1)(C) expressly identifies the achievement of state water quality standards as one of the Act’s central objectives.”). As dictated by the statute, the cost of compliance is not to be considered in setting limits to ensure that the State’s water quality standards are satisfied. 1

In addition, the CWA clearly authorizes States to impose more stringent water pollution control standards than dictated by the federal statute, at least where the statute does not expressly forbidMA0003654 Determinations Document July 22, 2002

5-2 such tougher State standards. CWA § 510 provides that:

[e]xcept as expressly provided in this chapter, nothing in this chapter shall (1) preclude or deny the right of any State . . . to adopt or enforce (A) any standard or limitation respecting discharges or pollutants, or (B) any requirement respecting control or abatement of pollution; except that if an effluent limitation . . . is in effect under this chapter, such State . . . may not adopt or enforce any effluent limitation . . . which is less stringent than the effluent limitation . . . under this chapter . . ..

Thus, CWA § 510 plainly states that “[e]xcept as expressly provided in this chapter,” States may adopt or enforce standards or effluent limits under state law that are more stringent than Federal requirements, but not less stringent. See PUD No. 1 of Jefferson County v. Washington Department of Ecology , 511 U.S. 700, 705 (1994) (citing 40 C.F.R. § 131.4(a)’s reference to CWA § 510 and its support for States’ authority to adopt water quality standards more stringent than federal standards); Arkansas v. Oklahoma , 503 U.S. 91, 107 (1992) (“§ 510 allows States to adopt more demanding pollution-control standards than those established under the Act”).

Following the provisions of the statute, EPA’s regulations also dictate that States may adopt and enforce more stringent standards than imposed by the Federal law. In the regulations governing the development of water quality standards, 40 C.F.R. § 131.4(a) states that, “[a]s recognized by section 510 of the Clean Water Act, States may develop water quality standards more stringent than required by this regulation.” The Supreme Court in PUD No. 1 , 511 U.S. at 705, cited to this regulation in support of the view that States could adopt water quality requirements more stringent than federal requirements. See also 40 C.F.R. § 123.25(a) and Note (regulations regarding State NPDES programs indicating that States may impose more stringent requirements).

It should also be recognized, however, that the CWA contains certain provisions that pertain specifically to State water quality standards for heat. CWA § 303(h) provides that “[f]or the purposes of this chapter the term ‘water quality standards’ includes thermal water quality standards.” In addition, CWA § 303(g) provides that “[w]ater quality standards relating to heat shall be consistent with the requirements of section 1326 of this title [(i.e., CWA § 316)].” CWA § 303(g) expressly addresses State water quality standards related to heat, as opposed to other possible types of State law requirements related to heat. CWA § 303(g) requires, at a minimum, that State water quality standards be at least sufficient to ensure the “protection and propagation of a balanced indigenous population of fish, shellfish, and wildlife in and on the receiving water,” as required by CWA § 316(a). Reading CWA §§ 510, 303(g), and 316(a) together, the statute indicates that State requirements could be more stringent than standards necessary to ensure the protection and propagation of a balanced indigenous population of fish, shellfish, and wildlife in and on the receiving water and still be “consistent” with the requirements of § 316(a), but theMA0003654 Determinations Document July 22, 2002

5-3 state water cannot be less stringent. Once approved by EPA, the State’s water quality standards become the applicable water quality standards for the waters of that State.

State water quality standards “shall consist of the designated uses of the navigable waters involved and the water quality criteria for such waters based upon such uses.” PUD No. 1 , 511 U.S. at 704 (quoting 33 U.S.C. § 1313(c)(2)(A)). Discharges must satisfy both the “criteria” and the “designated uses” of the waters in question. Id . at 714-15. Enforceable criteria in State water quality standards may be expressed either in numeric or “broad, narrative” form. Id . at 715-18. EPA regulations also dictate that permits should contain any conditions necessary to achieve water quality standards, including narrative criteria for water quality. 40 C.F.R. § 122.44(d)(1).

NPDES permits for thermal discharges are also subject to the requirements of CWA § 401, which governs the State certification process. CWA § 401(a)(1) provides, in pertinent part, that:

Any applicant for a Federal license or permit to conduct any activity . . . which may result in any discharge into the navigable waters, shall provide the licensing or permitting agency a certification from the State in which the discharge originates . . . that any such discharge will comply withthe applicable provisions of sections 1311, 1312, 1313, 1316 and 1317 of this title . . .. No license or permit shall be granted until the certification required by this section has been obtained or has been waived . . .. No license or permit shall be granted if certification has been denied by the State

. . .. 33 U.S.C. § 1341(a)(1) (emphasis added). The plain language of § 401(a) clearly states that unless certification has been waived, no EPA NPDES permit may be issued without a certification from the State. See PUD No. 1 , 511 U.S. at 707. Further, it states that denial of certification by the State bars issuance of the Federal permit or license. EPA regulations reiterate these commands. See 40 C.F.R. §§ 122.4(b), 124.53(a), 124.55(a). Neither the statute nor the regulations identify any exceptions to the certification requirement. A State denial of certification could, of course, be challenged by the permittee through State legal proceedings. See, e.g. , 40 C.F.R. § 124.55(e); Dubois v. U.S.D.A. , 102 F.3d 1273 (1 st Cir. 1996).

In addition, CWA § 401(d) provides, in pertinent part, that:

[a]ny certification provided under this section shall set forth any effluent limitations and other limitations and monitoring requirements necessary to assure that any applicant for a Federal license or permit will comply with any applicable effluent limitations and other limitations, under section 1311 or 1312 of this title, . . . and with any other appropriate requirement of State law set forth in suchMA0003654 Determinations Document July 22, 2002

5-4 certification, and shall become a condition on any Federal license or permit subject to the provisions of this section

. 33 U.S.C. § 1341(d) (emphasis added). The plain language of § 401(d) makes clear that the State’s § 401 certification must contain any limitations needed to ensure compliance with CWA § 301, including § 301(b)(1)(C), and any appropriate requirement of State law, and that such limitations imposed in a certification must be included as conditions in the Federal permit. PUD No. 1 , 511 U.S. at 707-08. EPA regulations repeat these commands from the statute. 40 C.F.R. §§ 124.53(e)(1), 124.55(a)(2), 122.44(d)(3), 121.2(a)(3). See also 40 C.F.R. § 122.4(d). Permit limitations based on State certification conditions can be challenged in State legal proceedings. 40 C.F.R. § 124.55(e). See also Roosevelt Campobello Int’l Park Comm’n v. United States Environmental Protection Agency , 684 F.2d 1041, 1055-56 (1 st Cir. 1982).

The Supreme Court has also held that once the CWA § 401 State certification process has been triggered by the existence of a discharge, then the certification may impose conditions and limitations on the activity as a whole , not merely on the discharge, to the extent needed to ensure compliance with State water quality standards or other applicable requirements of State law. Thus, the Court stated:

The text [of CWA § 401d)] refers to the compliance of the applicant, not the discharge. Section 401(d) thus allows the State to impose “other limitations” on the project in general to assure compliance with various provisions of the Clean Water Act and with “any other appropriate requirement of State law.” . . . Section 401(a)(1) identifies the category of activities subject to certification – namely, those with discharges. And § 401(d) is most reasonably read as authorizing additional conditions and limitations on the activity as a whole once the threshold condition, the existence of a discharge, is satisfied.

PUD No. 1 , 511 U.S. at 711-12. Thus, for example, a State could impose certification conditions related to cooling water intake structures on a permit for a facility with a discharge if those conditions were necessary to assure compliance with a requirement of State law, such as State water quality standards. See Id . at 713. This also helps to confirm that in setting discharge conditions to achieve water quality standards, a State can and should take account of the effects of other aspects of the activity that may influence the discharge conditions that will be needed to attain water quality standards.

A “mixing zone” is a permitting concept or tool under State water quality standards that may be used in applying those standards. 40 C.F.R. 131.13. See also Marathon Oil Company v. Environmental Protection Agency , 830 F.2d 1346, 1349 (5 th Cir. 1987); EPA Decision of the General Counsel, In re Sierra Pacific Power Company , EPA GCO 31 (October 13, 1975). For EPA to include limitations in a permit to establish compliance with State water quality standardsMA0003654 Determinations Document July 22, 2002

5-5 based on the use of a mixing zone, the State’s mixing zone policy must be properly applied so as to comply with the State’s standards and the State must certify such limits under CWA § 401 (or waive certification). See EPA Guidance on Application of State Mixing Zone Policies in EPAIssued NPDES Permits , pp. 1-2 (August 1996). Both Massachusetts and Rhode Island water quality standards provide for the use of mixing zones under certain conditions. Interestingly, although mixing zones are a tool and concept typically used in applying water quality standards, the mixing zone concept can also be used “as a mechanism for dealing with thermal discharges pursuant to section 316(a) of the Act.” U.S. EPA, Decision of the General Counsel, In Re Sierra Pacific Power Company, EPA GCO 31 (October 14, 1975). The legislative history of CWA § 316(a) indicates that Congress felt “mixing zones” could be used in designing permit limitations based on a CWA § 316(a) variance from applicable technology standards. Id . In this context, in order to satisfy § 316(a), compliance with the mixing zone would need to ensure the protection and propagation of the BIP. The same mixing zone might also establish compliance with applicable State water quality standards, or State standards and § 316(a) might demand different “mixing zones.”

It should also be understood that EPA generally defers to the State’s application of its own standards as reflected in its certification under CWA § 401. The EPA Environmental Appeals Board (EAB) has ruled that:

It is well established that the Agency may not “look behind” a State certification issued pursuant to section 401 of the Clean Water Act, for the purpose of relaxing a requirement of that certification. In such circumstances, the person seeking a relaxation of the requirement must look to the State for relief.

In the matter of Lone Star Steel Company

, 3 E.A.D. 713, 715 (1991). Accord In the Matter of General Electric Company, Hookset, New Hampshire ,4 E.A.D. 468, 470 (1993) (“Challenges to permit limitations and conditions attributable to State certification will not be considered by the Agency . . . [and instead] must be made through applicable State procedures.”). Nevertheless, although EPA may not generally “look behind” State certification conditions, if EPA believes that a State has committed “clear error” by failing to include more stringent conditions required by the State’s own standards, then EPA must include the more stringent conditions in order to comply with CWA § 301(b)(1)(C). In re Ina Road Water Pollution Control Facility, Pima County, Arizona , NPDES Appeal 84-12 (Nov. 6, 1985), at 3. See also In re American Cyanamid Col., Santa Rosa Plant , NPDES Appeal No. 92-18 (EAB Sept. 27, 1993), at 14; In re City of Jacksonville, District II Wastewater Treatment Plant , NPDES Appeal No. 91-19 (EAB Aug. 4, 1992) at 16.

The discharges of pollutants from BPS originate from the Commonwealth of Massachusetts and it is clear, as a result, that Massachusetts is the certifying State under CWA § 401(a)(1). TheMA0003654 Determinations Document July 22, 2002

5-6 discharges from BPS may also affect the water quality of the State of Rhode Island, however, and the CWA provides that discharges must be limited so that a downstream affected State’s water quality requirements are also complied with. Specifically, CWA § 401(a)(2), in pertinent part, commands that:

. . . [the permitting agency] shall condition such license or permit in such manner as may be necessary to insure compliance with applicable water quality requirements [of the downstream affected State]. If the imposition of conditions cannot insure such compliance such agency shall not issue such license or permit

. 33 U.S.C. § 1341(a)(2). Thus, Congress clearly stated that even for downstream affected States –which do not have direct certification authority under CWA § 401 – if permit conditions cannot be developed to ensure compliance with the downstream state’s standards, then no permit may be issued. Accord Arkansas v. Oklahoma , 503 U.S. at 103 (“Section 401(a)(2) appears to prohibit the issuance of any federal license or permit over the objection of an affected State unless compliance with the State’s water quality requirements can be ensured.”). Accordingly, EPA’s regulations require that permits contain conditions sufficient to ensure compliance with the water quality requirements of “all affected States.” 40 C.F.R. § 122.4(d). See also 40 C.F.R. § 122.44(d)(4). Arkansas v. Oklahoma , 503 U.S. at 104-07.

5.3 Limits Required by Massachusetts Water Quality Standards

The Massachusetts Department of Environmental Protection (MA DEP) has primary responsibility for determining what permit limitations are necessary to achieve compliance with Massachusetts water quality standards and other requirements of state law. EPA anticipates receiving a certification from the MA DEP under CWA § 401(a)(1), 33 U.S.C. § 1341(a)(1), addressing these requirements. Prior to issuance of that certification, however, EPA requested that the MA DEP determine what thermal discharge limitations would be necessary for Brayton Point Station to satisfy the state’s water quality standards. The state’s analysis is discussed below.

5.3.1 Summary of Massachusetts Mixing Zone Requirements

Consistent with the Massachusetts Surface Water Quality Standards promulgated at 314 CMR 4.00 and MA DEP guidance documents, MA DEP decided that it would exercise its discretion to set water quality-based thermal discharge standards based on a “mixing zone.” MA DEP developed its thermal mixing zone and related thermal discharge standards for the BPS cooling water discharge and transmitted it to EPA. The MA DEP’s mixing zone document in its entirety is attached hereto as Appendix A.

Generally, mixing zones are areas in which exceedance of numerical state water qualityMA0003654 Determinations Document July 22, 2002

5-7 standards may be allowed, provided that, among other things, these exceedances do not result in acute toxicity and that the mixing zone will still be protective of the narrative requirements of the water quality standards. In addition, mixing zones cannot be disproportionately large so as to interfere with attainment of the designated uses assigned to the water body segment by the state water quality standards. All applicable numeric water quality criteria must be met at the edge of the mixing zone. Requirements of state mixing zone policies must also be satisfied.

In the mixing zone prepared for Brayton Point Station by the MA DEP, protection of designated uses and satisfaction of water quality criteria and state mixing zone policies are addressed in a direct manner. Specific provisions are outlined in the mixing zone to meet these requirements. For example, the mixing zone requires a sufficient zone of passage for anadromous fish in the Lee River, requires that normal migration of striped bass be maintained, and imposes specific temperature requirements for instream water quality. In addition, the mixing zone addresses the proliferation of nuisance species. Each of these specific requirements is explained in more detail below.

5.3.1a Lee River Zone of Passage

MA DEP’s mixing zone protects anadromous fish movement into and out of the Lee River by requiring that specific target ambient temperatures for the mouth of the Lee River be met. The permittee would be required to measure ambient water temperatures to demonstrate compliance with this mixing zone. The permittee would not be allowed to exceed these temperature limits either bank-to-bank or over 50% of the cross-sectional area of the river. The specific water temperature limits are defined as follows:

1. April1- May 14: water temperature maximum shall not equal or exceed an hourly average of 18.3 o C (65 o F);

2. May 15 - May 31: water temperature maximum shall not equal or exceed an hourly average of 20 o C (68 o F);

3. June 1 - June 7: water temperature maximum shall not equal or exceed an hourly average of 21.1 o C (70 o F);

4. June 8 - June 23: water temperature maximum shall not equal or exceed an hourly average of 26.7 o C (80 o F);

5. June 24 - July 7: water temperature maximum shall not equal or exceed an hourly average of 27.9 o C (82.2 o F);

6. July 8 - October 31: water temperature maximum shall not equal or exceed an hourly average of 28.9 o C (84.1 o F).MA0003654 Determinations Document July 22, 2002

5-8 5.3.1b Requirements for Striped Bass Migration

During October/November, the normal time for striped bass migration out of New England coastal waters, MA DEP requires the permittee to dissipate its thermal plume to an extent and duration that will allow for the normal movement of striped bass. At present, the plant’s thermal discharge plume acts as an attractant interfering with normal migration and ultimately subjecting the overwintering fish to heightened risk of disease as a result of circumstances associated with being “trapped” in the thermal plume.

5.3.1c Requirements for Benthic Layer Monitoring and Temperature Compliance

MA DEP selected target temperatures for the benthic layer that the permittee must meet to be in compliance with the proposed mixing zone. From February 12 to April 23, the facility’s discharge must not contribute to benthic layer water temperatures exceeding 5 o C. For the rest of the year the facility’s discharge must not contribute to benthic layer water temperatures exceeding 24 o C. These temperatures were selected based on critical temperatures for the most sensitive resident fish species. MA DEP is requiring the permittee to place thermistors along three transects that are two kilometers long. The thermistors will be placed every 200 hundred meters and the plant will be considered out of compliance with the mixing zone when it is discharging heat to the bay and the average of all the thermistors along the transect line exceed the applicable target temperature. The target temperatures are defined as one-hour averages.

5.3.1d Proliferation of Nuisance Species

MA DEP has included a clause in the mixing zone that requires Brayton Point Station to reduce its thermal discharge in response to the appearance of nuisance species. Examples of nuisance species listed by the DEP include blue-green algal blooms or the appearance of comb jellies in the winter. In both of these cases, there is scientific peer-reviewed literature that show that the proliferation of these species is correlated with elevated water temperatures.

5.3.1e Monthly Thermal Discharge Cap

In addition to all the specific biological criteria, MA DEP has included a monthly thermal discharge limit of 1.2 TBTU as a discharge cap or “backstop.” It is anticipated that generation at Brayton Point Station would not reach this monthly discharge limit due to the other applicable limitations. However, this figure represents a maximum value that shall not be exceeded under any circumstance. In other words, MA DEP anticipates that the biological criteria will typically restrict the monthly thermal discharge.

5.3.2 Comparison of MA DEP Mixing Zone and EPA CWA § 316(a) DeterminationMA0003654 Determinations Document July 22, 2002

2 The temperature criteria for Class SA and SB waters in the Massachusetts water quality standards provide as follows: “any determinations concerning thermal discharge limitations in accordance with 33 U.S.C. 1251 § 316(a) will be considered site-specific limitations in compliance with 314 CMR 4.00.” 314 CMR 4.05(4)(a)(2)(c) and 4.05(4)(b)(2)(c).

5-9 MA DEP, in the construction of its mixing zone, must assure that the thermal discharge will be protective of “excellent” fish habitat in the SA portion of Mount Hope Bay. The state’s mixing zone analysis, however, considers the impacts of the thermal discharge apart from the effects of other stressors in Mount Hope Bay. EPA’s CWA § 316(a) determination seeks to meet the environmental standard of ensuring the protection and propagation of a balanced indigenous population (BIP) of organisms in the receiving water. In doing so, EPA must consider other stressors on the BIP in addition to the thermal discharge, including the effects of entrainment and impingement. Thus, EPA’s § 316(a) determination is based on a broader analysis than the MA DEP’s thermal discharge mixing zone analysis.

EPA anticipates that the MA DEP will consider entrainment and impingement effects in developing its CWA § 401(a)(1) water quality certification and determine whether additional requirements are needed to satisfy state water quality standards or other state requirements. In addition, the state will evaluate EPA’s § 316(a) variance determination and decide whether or not the variance-based limitations should be made “site-specific limitations” under the state’s water quality standards. 2

5.4 Limits Required by Rhode Island Water Quality Standards

In developing the limitations for the Brayton Point Station permit, EPA has endeavored to consider, and ensure compliance with, applicable Rhode Island water quality standards. However, Section 401(a)(2) of the CWA, 33 U.S.C. § 1341(a)(2), requires that when a CWA NPDES permit is to be issued to a facility in one state, if the permit “may affect, as determined by the Administrator, the quality of the waters of any other State, the Administrator . . . shall so notify such other State, the licensing or permitting agency, and the applicant.” Therefore, EPA sent a letter to the Rhode Island Department of Environmental Management (RI DEM) providing notice that the activities to be authorized by the NPDES permit to be issued to Brayton Point may affect the quality of Rhode Island waters. As required, copies of this notice letter will also be sent to the MA DEP and USGenNE. EPA will then consider any response received from the RI DEM in determining whether or not any additional limitations are needed to ensure compliance with applicable Rhode Island water quality standards.MA0003654 Determinations Document July 22, 2002

1 See
, e.g. , October 30, 1996, Fax from NEPCO to EPA (“Chronology of Brayton Point Station Operations” and “Circulating Water (S/N 001) - Permit Limitations”); NPDES Permit No. MA0003654, Modification No. 3, Issued to NEPCO for BPS (July 21, 1976); July 26, 1977, Letter from Charles Corkin II, Massachusetts Office of the Attorney General, to John Scanlon, Save the Bay (attaching “Agreement for Judgment” to be entered in Suffolk County Superior Court between NEPCO, the Commonwealth, EPA, Save the Bay, and Ecology Action for Rhode Island). 6-1 

### 6.0 CWA § 316(a) - Determination In Response to USGenNE’s Variance Application

6.1 Introduction

This section of the NPDES permit development package for BPS presents EPA’s determination in response to USGenNE’s application for alternative thermal discharge limitations under CWA § 316(a) (commonly referred to as “a § 316(a) variance application”).

As discussed in the Permitting History section of this document, the thermal discharge limits included in the original October 1973 NPDES permit for BPS were based on Massachusetts Water Quality Standards rather than a § 316(a) variance. This permit included a maximum temperature limitation of 90° F and a ) -T limitation of 20° F. The permittee subsequently sought relaxation of those limitations under a § 316(a) variance. The record shows this request to have been extremely controversial. The permit’s maximum temperature and ) -T limits were alternately raised and then returned to the original limits in a series of permit modifications and agreements over the years from 1976 to 1979. 1

In 1979, a new permit was issued by EPA and MA DEP on the basis of a CWA § 316(a) variance. This permit raised the maximum temperature and ) -T limits to 95° F and 22° F, respectively. These limits remain in place in the current permit with certain conditions. See EPA Fact Sheet for BPS Draft NPDES Permit No. MA003654 (June 11, 1993), p. 11. In 1982, although the maximum temperature and ) -T limits of 95° F and 22° F remained constant, BPS was nevertheless effectively authorized to discharge more heat (in BTUs) to Mount Hope Bay when another permit change allowed the plant to discharge an increased volume of cooling water flow due to the conversion of Unit 4 from closed-cycle to open-cycle cooling.

As required by applicable regulations, the permittee applied for permit reissuance on January 15, 1998, at least 6 months prior to the existing permit’s expiration date of July 16, 1998. The permittee did not, however, indicate in its application that it was requesting a renewal of its CWA § 316(a) variance and did not submit a § 316(a) variance demonstration. Instead, the permittee indicated to the regulatory agencies that it was seeking a permit based on water quality standards, including limits based on approval of a mixing zone. See June 19, 2001, Letter from David Webster (EPA) to Meredith Simas (USGenNE); January 15, 1998, Letter from Andrew H.MA0003654 Determinations Document July 22, 2002

2 The papers submitted by the permittee on July 3, 2002, are as follows: Hilborn, Ray and Andre Punt, “Analysis of Brayton Point Station’s Impact on the Mt. Hope Bay Population of Winter Flounder” (June 29, 2002); DeAlteris, Joseph, “Trends in the Abundance of Five Fish Species in Mount Hope Bay: A Response to M. Gibson’s Assessment of the Effect of Brayton Point Station on Fish Stocks in Mount Hope Bay” (July 1, 2002); and Hilborn, Ray and Andre Punt, “Calculation of Power Plant Impact on the Winter Flounder Population in Mt. Hope Bay Using Survey Data” (July 2, 2002).

6-2 Aitken, Vice President, NEPCO, to Jane Downing, EPA, and David Johnston, MA DEP, p. 3. The regulatory agencies and the permittee proceeded on that basis in their efforts to develop appropriate permit limitations for BPS.

Early in 2001, however, USGenNE indicated to the regulatory agencies that it intended to seek a CWA § 316(a) variance after all. See June 19, 2001, Letter from David Webster (EPA) to Meredith Simas (USGenNE). The permittee then submitted its “Variance Request Application and Partial

Demonstration Under the Clean Water Act, Section 316(a) and (b)” dated May 24, 2001 (emphasis added) (hereinafter, the “May 24 2001, USGenNE Partial 316(a) and (b) Demonstration”). See also June 19, 2001, Letter from David Webster (EPA) to Meredith Simas (USGenNE). Then on December 7, 2001, USGenNE finally submitted its full variance application entitled, “Clean Water Act Section 316(a) and (b) Demonstration, Brayton Point Station Permit Renewal Application” (November 2001) (hereinafter, the “December 2001 USGenNE 316(a) and (b) Demonstration”). This submission includes five large volumes with thousands of pages of material, including a 67-page “Executive Summary.” Some of this material had been submitted previously by the permittee, while other portions had not. Such a late submission of this voluminous, complex package by the permittee – the permittee’s application for permit renewal was due, and was originally filed by the permittee, in January 1998 – created a challenge for the regulatory agencies, but the agencies have endeavored to carefully review and consider the material in the December 2001 USGenNE § 316(a) and (b) Demonstration.

EPA has also considered material submitted by the permittee subsequent to the December 2001 submission, but we note that on July 3, 2002, the permittee submitted three new papers presenting biological analyses by its hired contractors. 2 As a result of the very late date of this submission, EPA was not able to consider the new studies prior to issuance of the draft permit. EPA does, however, look forward to giving these analyses careful evaluation during the public comment period, along with any other public comments and/or new information that may be submitted.

6.2 Legal Requirements and ContextMA0003654 Determinations Document July 22, 2002

6-3 6.2.1 CWA § 316(a)

NPDES permits generally must include the more stringent of any effluent limitations derived from technology-based and/or water quality-based requirements. CWA § 316(a) provides, however, that the regulatory agencies may put alternative, less stringent thermal discharge limitations in an NPDES permit if certain criteria are met. Specifically, CWA § 316(a) provides, in pertinent part, as follows:

[w]ith respect to any point source otherwise subject to the provisions of section . . . [301 or section 306 of the CWA], whenever the owner or operator of any such source, after opportunity for public hearing, can demonstrate to the satisfaction of the Administrator (or, if appropriate, the State) that any effluent limitation proposed for the control of the thermal component of any discharge from such source will require effluent limitations more stringent than necessary to assure the pro[t]ection and propagation of a balanced indigenous population of shellfish, fish, and wildlife in and on the body of water into which the discharge is to be made, the Administrator (or, if appropriate, the State) may impose an effluent limitation under such sections for such plant, with respect to the thermal component of such discharge (taking into account the interaction of such thermal component with other pollutants), that will assure the protection and propagation of a balanced, indigenous population of shellfish, fish, and wildlife in and on that body of water.

33 U.S.C. § 1326(a). See also 40 C.F.R. § 125.70. A determination to approve alternative limitations under this statutory provision is commonly referred to as a “CWA § 316(a) variance.” See 40 C.F.R. § 125.71(a) and 125.72 (heading).

6.2.2 Criteria for Assessing § 316(a) Variance Applications

CWA § 316(a) authorizes alternative thermal discharge limits when it is demonstrated to EPA that the limits “will assure the protection and propagation of a balanced, indigenous population of shellfish, fish and wildlife in and on that body of water” (sometimes referred to herein as the “BIP”). This criterion is reiterated in EPA regulations promulgated at 40 C.F.R. § 125.73(a).

The terms “protection” and “propagation” are not defined in the statute or regulations. However, the American Heritage Dictionary (2d College Ed. 1982) defines “protection,” in pertinent part, as “[t]he act of protecting . . . [or t]he condition of being protected,” while it defines “protect” as “[t]o keep from harm, attack, or injury; guard.” In addition, it defines “propagation” as theMA0003654 Determinations Document July 22, 2002

3 In the legislative history of the 1977 CWA Amendments, Senator Muskie also discussed the meaning of the phrase “balanced indigenous population of fish, shellfish and wildlife” as used in the “interim [national] water quality standard.” He explained that:

6-4 “[i]ncrease or spread, as by natural reproduction.” Thus, thermal discharge limits based on a CWA § 316(a) variance must “assure” that the receiving water’s BIP will be safe from harm or injury from the thermal discharge, and that the thermal discharge will not interfere with the BIP’s ability to increase or spread naturally within the receiving water.

The CWA also does not define the term “balanced indigenous population.” Some clarification of Congress’ intent is provided, however, in the CWA’s legislative history. The Report of the Conference Committee on S. 2770, the bill that was enacted as the Clean Water Act of 1972 and originated the current § 316(a), stated the following:

THERMAL DISCHARGES [Section 316]

* * * It is not the intent of this provision to permit modification of effluent limits required pursuant to Section 301 or Section 306 where existing or past pollution has eliminated or altered what would otherwise be an indigenous fish, shellfish and wildlife population. The owner or operator must show, to the satisfaction of the Administrator, that a “balanced indigenous population of fish, shellfish and wildlife” could exist even with a modified 301 or 306 effluent limit. Additionally, such owner or operator would have to show that elements of the aquatic ecosystems which are essential to support a “balanced indigenous population of fish, shellfish and wildlife” would be protected.

Congressional Research Service, “ A Legislative History of the Water Pollution Control Act Amendments of 1972, Vol. 1, ” 93d Cong., 1 st Session

, p. 175 (cited hereinafter as the “1972 Legislative History”) (Senate Consideration of the Report of the Conference Committee (October 4, 1972)). See also December 27, 1977, Letter from EPA Region 1 Regional Administrator William R. Adams, Jr., to Edward A. Plumley, Vice President, NEPCO, p. 2 (“the indigenous community is . . . the community that would exist absent man-induced environmental changes.”). This indicates that Congress did not intend that a thermal discharger would be able to “take advantage” of prior pollution-induced harm that eliminated the BIP to justify alternative thermal discharge limitations under § 316(a) that would themselves be insufficient to protect the BIP. It also makes clear that Congress intended that elements of the aquatic ecosystem necessary to support the protection and propagation of the BIP would also be protected under § 316(a). 3MA0003654 Determinations Document July 22, 2002

As in 1972, it was intended that the interim water quality standard be that condition of aquatic life which existed in the absence of pollution. There is no question that man’s activities have radically altered receiving water ecosystems in this country and that alteration is continuing at an accelerated pace in many areas. Restoration of aquatic ecosystems which existed prior to the introduction of pollution from man’s activities is an important element of the restoration and maintenance of the biological, physical, and chemical integrity of receiving waters. It is an essential aspect of assuring that future generations will have an adequate supply of basic life support resources. The concept of indigenous does not anticipate the removal of structures from waterways. It does not anticipate the existence of ecosystems which existed in the absence of those structures. But it does fully anticipate the analysis of aquatic populations in terms of man’s activities prior to, and subsequent to, pollution.

L. History 1977, p. 448.

6-5 Consistent with Congressional intent, EPA regulations define “balanced indigenous population” in the following manner:

The term balanced indigenous community is synonymous with the term balanced, indigenous population in the Act and means a biotic community typically characterized by diversity, the capacity to sustain itself through cyclic seasonal changes, presence of necessary food chain species and by a lack of domination by pollution tolerant species. Such a community may include historically non-native species introduced in connection with a program of wildlife management and species whose presence or abundance results from substantial, irreversible environmental modifications. Normally, however, such a community will not include species whose presence or abundance is attributable to the introduction of pollutants that will be eliminated by compliance by all sources with section 301(b)(2) of the Act [i.e., technology standards]; and may not include species whose presence or abundance is attributable to alternative effluent limitations imposed pursuant to section 316(a).

40 C.F.R.§ 125.71(c) (emphasis in original). It is clear under this definition that a satisfactory BIPMA0003654 Determinations Document July 22, 2002

6-6 under § 316(a) need not in all circumstances match some sort of estimated aboriginal assemblage of organisms. At the same time, however, the BIP must satisfy the listed indicia of an ecologically healthy community of organisms, including that it cannot be dominated by pollution tolerant species, or species whose presence or abundance is attributable to § 316(a)-variance based permit limitations, or include pollutant discharges that will be eliminated pursuant to technology-based effluent limitations under § 301(b)(2). See 44 Fed. Reg. 32894 (June 7, 1979) (Preamble to Revised 40 C.F.R. Part 125 Subpart H); see also 39 Fed. Reg. 36178 (October 8, 1974) (preamble to earlier version of EPA regulation containing substantially similar definition).

EPA provided further clarification regarding the meaning of BIP under § 316(a) in the case of In the Matter of: Public Service Company of Indiana, Inc., Wabash River Generating Station , 1979 EPA App. LEXIS 4, 1 E.A.D. 590 (November 29, 1979). In Wabash , EPA made clear that in assessing the BIP, EPA must look not only at the community as a whole but also at the effects on individual species of fish that should be part of that community. 1970 EPA App. LEXIS at 21 (“it is clear that both individual [species] and community considerations are relevant”). EPA explained that:

. . . in attempting to judge whether the effects of a particular

thermal discharge are causing the system to become imbalanced, it is necessary to focus on the magnitude of the changes in the community as a whole and in individual species; i.e., whether the changes are “appreciable.”

Id . at 22. Finally, EPA also made clear that it is not acceptable that a particular discharge will allow the propagation of some community of fish with a certain degree of diversity and abundance; the thermal discharge limits must be sufficient to protect the BIP that ought to be present in the particular receiving water consistent with the regulations. As EPA explained :

Section 316(a) must, like any other provision of the Act, be read in a manner which is consistent with the Act’s general purposes. Consequently, § 316(a) cannot be read to mean that a balanced indigenous population is maintained where the species composition, for example, shifts from a riverine to a lake community or, as in this case, from thermally sensitive to thermally tolerant species. Such shifts are at war with the notion of “restoring” and “maintaining” the biological integrity of the Nations’ waters. Thus, even though it may be difficult or even impossible to define what the precise balanced indigenous population would be in the absence of heat, it is generally sufficient, as the regulations provide, that it “will not include species whose presence or abundance is attributable to theMA0003654 Determinations Document July 22, 2002

4 It should be noted that in the situation described in the quotation a proposed discharge might satisfy numeric thermal water quality criteria but fail to satisfy § 316(a). In such a case, thermal discharge standards would need to be based on either technology standards or perhaps more stringent water quality-based limits necessary to protect designated uses.

6-7 introduction of pollutants,” such as heat, and that it should be characterized by “non-domination of pollution tolerant species.”

Wabash
, id . at 28-29 (citation omitted).

Another step in applying CWA § 316(a) is to define “the body of water into which the discharge is to be made” and whose BIP is to be protected. Obviously, many water bodies connect to other water bodies –e.g., a river or bay flowing into the ocean– and a point of reference must be selected for analysis. Neither the statute nor regulations dictate how this should be done. EPA has made this determination on a case-by-case basis appropriately shaping the approach to the facts of each case. In different cases EPA has focused on discrete water bodies, water body segments, or even sub-areas within a water body segment, that may be influenced by the thermal discharge in question. In Appalachian Power Company v. Train , the court described (and upheld) EPA’s reasoning as follows:

EPA points out that state water quality standards typically apply to an entire waterway or a relatively large segment of it. By way of contrast, EPA views § 316(a) as providing for consideration of specific site conditions in the setting of thermal limitations for individual power plants. Thus, while a greater level of thermal effluent by a generating unit might well fall within the general requirements of an approved state standard, EPA takes the position that such discharges might nevertheless cause serious harm to a particular spawning ground, for example, located just below the plant’s discharge point. It is such specific site conditions to which EPA contends § 316(a) is directed.

545 F.2d 1351, 1372 (4 th

Cir. 1976). 4 See also 39 Fed. Reg. 36177 (October 8, 1974). Accord In re Public Service Company of New Hampshire , 10 ERC 1257, 1265 (June 10, 1977) (Permit Appeal Decision by Administrator of EPA) (for a discharge into the North Atlantic Ocean, EPA stated that “. . . in order to give effect to Section 316 it is necessary to look at smaller portions of the coastal waters where human use or enjoyment of the marine resource may be affected”). This approach makes ecological sense and is consistent with the CWA’s overall purpose of restoring and maintaining the chemical, physical and biological integrity of the Nation’s waters.MA0003654 Determinations Document July 22, 2002

6-8 The statute and regulations are also clear that in applying CWA § 316(a), the permitting agency must take account of the cumulative effects of other stresses to the BIP. First, CWA § 316(a) states that the permitting authority may impose variance-based thermal discharge limitations, “(taking into account the interaction of such thermal component with other pollutants), that will assure the protection and propagation of a balanced, indigenous population . . ..” Second, EPA regulations promulgated at 40 C.F.R. § 125.73(a) (emphasis added) state that a discharger’s request for a § 316(a) variance “must show that the alternative effluent limitations desired by the discharger, considering the cumulative impact of its thermal discharge together with all other significant impacts on the species affected , will assure the protection and propagation of” the BIP. See also 40 C.F.R. § 125.73(c)(1)(i). In the preamble to 40 C.F.R. Part 125 Subpart H, EPA stated:

Several commenters argued that applicants should not be required

to analyze cumulative effects of thermal discharges together with other sources of impact upon the affected species as required by proposed § 125.47 (now 125.72(a)). This issue was addressed in the Administrator’s first Seabrook decision which concluded that analysis of cumulative effects is required.

44 Fed. Reg. 32894 (June 7, 1979).

In the Seabrook permit appeal decision referenced above, EPA’s Administrator stated the following:

The RA [(i.e., the Regional Administrator)] ruled that a

determination of the effect of the thermal discharge cannot be made without considering all other effects on the environment, including the effects of the intake (i.e., entrainment and entrapment); the applicant must persuade the RA that the incremental effects of the thermal discharge will not cause the aggregate of all relevant stresses (including entrainment and entrapment by the intake structure) to exceed the 316(a) threshold. I believe this is the correct interpretation of Section 316(a). The effect of the discharge must be determined not by considering its impact on some hypothetical unstressed environment, but by considering its impact on the environment into which the discharge will be made; this environment will necessarily be impacted by the intake. When Congress has so clearly set the requirement that the discharge not interfere with a balanced indigenous population, it would be wrong for the Agency to put blinders on and ignore the effect of the intake in determining whether the discharge wouldMA0003654 Determinations Document July 22, 2002

6-9 comply with that requirement.

In re Public Service Company of New Hampshire , 10 ERC at 1261-62. Thus, discharge limits imposed under CWA § 316(a) must be sufficient to ensure the protection and propagation of the BIP, taking into account other environmental stresses on that population.

Another point worth mentioning here is that “mixing zones” may be used “as a mechanism for dealing with thermal discharges pursuant to section 316(a) of the Act.” EPA Decision of the General Counsel, In re Sierra Pacific Power Company , EPA GCO 31 (October 13, 1975). Although a “mixing zone” is a permitting concept or tool generally used in applying State water quality standards, the legislative history of CWA § 316(a) indicates that Congress felt mixing zones could also be used in designing permit limitations based on a CWA § 316(a) variance from applicable technology standards. Id . This also makes common sense. Cf

. January 15, 1998, Letter from Andrew H. Aitken, Vice President, NEPCO, to Jane Downing, EPA, and David Johnston, MA DEP, p. 3. Of course, to satisfy § 316(a), a mixing zone would need to be designed to ensure the protection and propagation of the BIP. See 39 Fed. Reg. 36178 (October 8, 1974) (Preamble to EPA’s earlier § 316(a)-related regulations).

In applying CWA § 316(a), cost or economic issues are not a consideration. The plain language of § 316(a) makes clear that variance decisions are to be based on a determination of the limits needed to ensure the protection and propagation of the BIP. No mention is made of cost considerations being brought to bear. The legislative history also indicates that Congress did not intend costs to be considered in applying § 316(a). 1972 Legislative History, p. 175. Similarly, EPA’s regulations clearly do not provide for costs to be a consideration in making a CWA § 316(a) variance determination. See 40 C.F.R. § 125.73. EPA has also interpreted CWA § 316(a) in this manner in practice. See In the Matter of: Public Service Company of Indiana, Inc., Wabash River Generating Station , 1979 EPA App. LEXIS 4,[*41] - [*43], 1 E.A.D. 590 (November 29, 1979). Thus, while costs are to be considered in developing technology-based standards for thermal discharges, which must be based on the Best Available Technology economically achievable (BAT) standard under CWA §§ 301(b)(2) and 304(b)(2), costs are not to be considered in determining whether to grant a variance from such limits under § 316(a).

6.2.3 “Burden of Proof,” Level of Evidence Required, and Different Types of § 316(a) Demonstrations

The statute plainly places the “burden of proof” in justifying alternative thermal discharge limitations under a CWA § 316(a) variance on the permit applicant. The statute provides that the permitting authority may impose such alternative thermal discharge limits, “ whenever the owner or operator of any such source . . . can demonstrate to the satisfaction of the Administrator (or, if appropriate, the State) that any effluent limitation proposed [under CWA §§ 301 or 306] for the control of the thermal component of any discharge from such source will require effluentMA0003654 Determinations Document July 22, 2002

5Senator Muskie’s comments from the legislative history have been given great weight by the courts in interpreting the CWA because he was the “principal Senate sponsor of the Act ....” Environmental Protection Agency v. National Crushed Stone Association , 449 U.S. 64, 71 n. 10 (1980). Accord
, e.g. , Natural Resources Defense Council v. Costle , 568 F.2d 1369, 1374 (D.C. Cir. 1977); American Iron and Steel Association v. Environmental Protection Agency , 526 F. 2d 1027, 1041 (3d Cir. 1975); American Meat Institute v. Environmental Protection Agency , 526 F.2d 442, 451 (7 th

Cir. 1975).

6-10 limitations more stringent than necessary to assure the pro[t]ection and propagation of” the BIP. 33 U.S.C. § 1326(a) (emphasis added). The legislative history underlying § 316(a) confirms the plain meaning of the statutory language. The Report of the Conference Committee on the Clean Water Act of 1972 stated the following, in pertinent part, with regard to § 316(a), “[u]nder the conference agreement thermal pollutants will be regulated as any other pollutant unless an owner or operator can prove that a modified thermal limit can be applied which will assure ‘protection and propagation’ of . . . [the BIP].” 1972 Legislative History, p. 175 (emphasis added).

EPA’s regulations further confirm that the burden is on the permit applicant to persuade the permitting authority that the non-variance limits are more stringent than is needed and that an alternative set of limitations will be sufficient to protect the BIP. 40 C.F.R. § 125.73(a). Moreover, in the Seabrook permit appeal decision quoted above, EPA’s Administrator also clearly stated that the burden of proof under § 316(a) lay with the permit applicant. In re Public Service Co. of New Hampshire , 10 ERC at 1261, 1263.

Moreover, it is also clear that “the burden of proof in a 316(a) case is a stringent one.” Id . at 1264. CWA § 316(a) states that the applicant must demonstrate to the permitting authority’s satisfaction that the applicable non-variance-based permit limitations are more stringent than necessary to assure the protection and propagation of the BIP. In the legislative history of the Clean Water Act Amendments of 1977, Senator Muskie 5stated the following with respect to § 316(a):

[t]he Congress intended that there be a very limited waiver for

those major sources of thermal effluents which could establish beyond any question the lack of relationship between federally established effluent limitations and that water quality which assures the protection of public water supplies and the protection and propagation of a balanced, indigenous population of fish, shellfish, and wildlife, and allows recreational activities, in and on the water.

L. History 1977, p. 642; see also p. 457.MA0003654 Determinations Document July 22, 2002

6-11 Although the § 316(a) standard is extremely rigorous, EPA has not interpreted § 316(a) to require absolute certainty before a variance could be granted. In re Public Service Company of New Hampshire , 10 ERC at 1265. In reality, achieving absolute certainty about a § 316(a) determination is likely to be impossible. See Id . EPA has stated, however, that “[t]he greater the risk, the greater the degree of certainty that should be required.” Id . at 1265. See also 44 Fed. Reg. 32894 (June 7, 1979).

The above material suggests that EPA should take a rigorous and conservative approach to granting and reissuing variances in order to meet the CWA’s standard of assuring the protection and propagation of the BIP. Such an approach is appropriate in light of the fact that the applicant for a § 316(a) variance is seeking to be excused from otherwise applicable limitations, and in light of the CWA’s overarching goals of restoring and maintaining the “biological integrity of the Nation’s waters, [and attaining] “water quality which provides for the protection and propagation of fish, shellfish and wildlife.” 33 U.S.C. § 1251(a) and (a)(2). EPA’s NPDES permit decisions are, of course, subject to the “arbitrary and capricious” standard of review under the Administrative Procedures Act. 5 U.S.C. §§ 701 -706. In other words, EPA’s decisions regarding whether the permit applicant has carried its burden in seeking a § 316(a) variance, and in setting the thermal discharge limitations that are ultimately included in the permit, must have a rational basis and be consistent with applicable law.

With respect to the question of how much evidence is needed to support a § 316(a) variance, EPA has explained that, “[n]o hard and fast rule can be made as to the amount of data that must be furnished . . . [and m]uch depends on the circumstances of the particular discharge and receiving waters.” In re Public Service Company of New Hampshire , 10 ERC at 1264. At the same time, information requirements are likely to increase to the extent that there is greater reason for concern over the protection and propagation of the BIP. As EPA stated in the preamble to its § 316(a)-related regulations in 40 C.F.R. Part 125 Subpart H:

Section 125.72 accordingly gives the Director the flexibility to require substantially less information in the case of renewal requests. This does not mean, however, that the Director may not require a full demonstration for a renewal in cases where he has reason to believe that circumstances have changed, that the initial variance may have been improperly granted, or that some adjustment in the terms of the initial variance may be warranted.

44 Fed. Reg. 32894 (June 7, 1979). See also 39 C.F.R. 36177 (October 8, 1977). EPA has also stated that it “‘must make decisions on the basis of the best information reasonably attainable.’” In re Public Service Company of New Hampshire , 10 ERC at 1265 (quoting 1974 EPA Draft § 316(a) Guidance). At the same time, the Agency has explained that it “may not speculate as to matters for which evidence is lacking,” id . at 1264, and that if “‘deficiencies in information are soMA0003654 Determinations Document July 22, 2002

6-12 critical as to preclude reasonable assurance, then alternative effluent limitations should be denied.’” Id . at 1265 (quoting 1974 Draft EPA § 316(a) Guidance). See also In the Matter of: Public Service Company of Indiana, Inc., Wabash River Generating Station , 1979 EPA App. LEXIS 4, [*34] - [*40], 1 E.A.D. 590 (November 29, 1979) (Administrator remanded permit to Regional Administrator where Region had decided to grant variance-based thermal discharge limitations despite lack of data regarding thermal effects under worst case, low flow conditions). The question is what “an informed scientific judgment,” In re Public Service Company of New Hampshire , 10 ERC at 1265, would be in light of the data in the record and absent from the record.

The regulations and guidance provide for several different types of § 316(a) demonstrations. These demonstrations may be structured to utilize existing information and minimize the amount of new information that must be collected. The required demonstrations will likely vary to some extent depending, in part, on whether the variance is sought by a new facility or an existing facility. See 40 C.F.R. § 125.73(c)(1) (two types of demonstrations for existing dischargers); U.S. EPA, “Draft - Interagency 316(a) Technical Guidance Manual and Guide for Thermal Effects Sections of Nuclear Facilities Environmental Impact Statements” (May 1, 1977), p.11 (referred to hereinafter as, “Draft 1977 316(a) Technical Guidance”). See also 39 C.F.R. 36177 (October 8, 1974); In the Matter of: Public Service Company of Indiana, Inc., Wabash River Generating Station , 1979 EPA App. LEXIS 4, [*15], 1 E.A.D. 590 (November 29, 1979).

An existing discharger may base its demonstration on a showing that there has been no “appreciable harm” to the BIP from the thermal discharge “taking into account the interaction of such thermal component [of the discharge] with other pollutants and the additive effect of other thermal sources.” 40 C.F.R. § 125.73(c)(1)(i). Alternatively, an existing discharger can attempt to show that “despite the occurrence of such previous harm, the desired alternative effluent limitations (or appropriate modifications thereof) will nevertheless assure the protection and propagation of . . . [the BIP].” 40 C.F.R. § 125.73(c)(1)(ii). With respect to the appreciable harm test, EPA has explained that proposed thermal discharge limitations fail the § 316(a) variance test if those limitations would, taking into account other stresses upon the BIP, cause appreciable harm to the BIP in the future. Wabash , 1979 EPA App. LEXIS 4, [*16] - [*17], 1 E.A.D. 590 (November 29, 1979). In addition, thermal discharge limitations which caused appreciable harm to the BIP in the past are not to be renewed under a § 316(a) variance unless those limits are modified to prevent future harm or other circumstances are demonstrated to have changed so that appreciable harm will not occur in the future. Id

.

6.2.4 Permit Procedures

NPDES permits are limited to a term of no more than five years. 33 U.S.C. § 1342(b)(1)(B). Thus, NPDES permits expire and require reissuance at least every five years. (Expired permits remain in effect until a new permit is issued as long as the permittee has filed a timely applicationMA0003654 Determinations Document July 22, 2002

6-13 for permit reissuance. 40 C.F.R. § 122.6(a) .) Accordingly, EPA regulations provide that previous § 316(a) variance determinations must be revisited at the time of permit reissuance. See 40 C.F.R. § 125.72(c) and (NOTE); 39 Fed. Reg. 36176 (October 8, 1974) (Preamble to EPA’s earlier § 316(a)-related regulations) (“Continuing monitoring by existing sources will provide opportunity to review their impacts from time to time and to impose more stringent effluent limitations, if necessary, in subsequent permits.”).

With respect to the timing of an application for a CWA § 316(a) variance, 40 C.F.R. § 122.21(m)(6) provides that a request for a § 316(a) variance:

. . . must be filed with a timely application for a permit under this section, except that if thermal effluent limitations are established under CWA section 402(a)(1) or are based on water quality standards the request for a variance may be filed by the close of the comment period under § 124.10.

Thus, if a discharger did not request a variance with its initial permit application and EPA then proposed permit limits based on applicable technology and water quality standards, the discharger could still request a variance as long as it did so by the close of the comment period on the draft NPDES permit. As discussed above, in this case, the permittee did not request a variance at the time of its application for permit reissuance, filed on January 15, 1998. See January 15, 1998, Letter from Andrew H. Aitken, Vice President, NEPCO, to Jane Downing, EPA, and David Johnston, MA DEP, p. 3. Initially, the permittee sought a permit with limits based on water quality standards, including a mixing zone. However, in May 2001, the permittee submitted its first request for a variance. USGenNE National Energy Group, “Variance Request Application and Partial Demonstration Under the Clean Water Act, Section 316(a) and (b)” (May 24, 2001). As discussed above, this variance application was later supplemented with the December 2001 USGenNE § 316(a) and (b) Demonstration

. EPA does not see any strict procedural bar to the company’s filing of its variance application at that time. Indeed, had EPA proposed permit limitations based on technology or water quality standards, the regulations clearly state that the permittee could have requested a variance any time before the close of the comment period on the draft permit. It should also be noted that this is a practical and reasonable approach for EPA to take in light of the fact that the scientific and technical information that the permittee and the regulatory agencies were developing when the company was seeking a permit based on water quality standards and a mixing zone is also pertinent to the § 316(a) variance issues.MA0003654 Determinations Document July 22, 2002

6-14 6.3 Biological Analysis of Thermal Discharge

6.3.1 USGenNE’s Variance Request

USGenNE has requested permit conditions based on a § 316(a) variance. Their preferred technological alternative is the Enhanced Multi-Mode (EMM) option which is described in detail in the permittee’s permit application materials and in EPA’s CWA § 316(b) determination document. Derived from the operating needs and capabilities of the Enhanced Multi-Mode System, USGenNE is requesting a CWA § 316(a) variance-based permit with the following discharge conditions:

EMM Existing (MOA II) Discharge Temperature: 95 o F 95 o F Delta Temperature: 22 o F 22 o /30 o F(under piggyback) Winter Month Heat Load: 3.5 TBTU 4.1 TBTU Winter Season (Oct.-May): 19 TBTU 29 TBTU Summer Month Heat Load: 2.5 TBTU 3.4 TBTU Summer Season (Jun.-Sept.): 9 TBTU 13 TBTU Daily Maximum Flow 1298.5 MGD 1298.5 MGD Winter Seasonal Flow 600 MGD 925 MGD Summer Seasonal Flow 750 MGD 1080 MGD Annual Heat Load 28 TBTU 42 TBTU Annual Flow 650 MGD no annual limit

The limits requested by USGenNE are more stringent than the current permit limits or MOA II, but less stringent than what would be required by technology-based or water quality-based discharge limits.

6.3.2 Outline of § 316(a) Decision Criteria

Under Section 316(a), the effects of the discharge of heat from Brayton Point Station to the “balanced indigenous population” (BIP) of marine organisms in Mount Hope Bay are analyzed. EPA’s 316(a) Technical Guidance Manual (May 1, 1977) uses the term “balanced indigenous community”, which it states is consistent with the term balanced indigenous population in Section 316(a) of the Federal Water Pollution Control Act. EPA regulations at 40 CFR §125.71(c) define the balanced indigenous community in the following way:

“The term balanced indigenous community is synonymous with the term balanced indigenous population in the Act and means a biotic community typically characterized by diversity, the capacity to sustain itself through cyclic seasonal changes, presence of necessary food chain species and by a lack of domination by pollution tolerant species. Such a community may include historically non-native species introduced in connectionMA0003654 Determinations Document July 22, 2002

6-15 with a program of wildlife management and species whose presence or abundance results from substantial, irreversible environmental modifications. Normally, however, such a community will not include species whose presence or abundance is attributable to the introduction of pollutants that will be eliminated by compliance by all sources with section 301(b)(2) of the act; and may not include species whose presence or abundance is attributable to alternative effluent limitations imposed to section 316(a).”

The 316(a) Technical Guidance Manual suggests that an assessment of thermal impacts be done on a community-by-community (i.e., phytoplankton, zooplankton, habitat formers, finfish) basis. EPA followed the framework of the guidance document in the construction of our thermal assessment, because it provides a useful analytical structure. The 316(a) Technical Guidance Manual describes areas of low potential impact from the thermal discharge for each community type based on specific criteria. Communities showing little or no impact from current operation were deemed by EPA to have low potential impact for thermal effects from future operation assuming other stressors stay constant. The 316(a) Technical Guidance Manual details specific criteria or endpoints that are indicative of thermal degradation for each community type. EPA considered these endpoints in its thermal assessment. These decision criteria are detailed below.

6.3.2a Phytoplankton

Phytoplankton are unicellular microscopic plants that are one of the most important sources of primary production for coastal and marine food webs. They are important food items for zooplankton, which include larval fish, filter feeding invertebrates and some species of fish. In addition, nuisance blooms of phytoplankton can cause aesthetic and ecological problems.

i. Low Potential Impact Areas for Phytoplankton (Open Ocean and Most Riverine Ecosystems)

Areas of low potential impact for phytoplankton are defined in the 1977 EPA 316(a) Technical Guidance manual as open ocean areas or systems in which phytoplankton is not the food chain base. Ecosystems in which the food web is based on detrital material; (e.g. embayments bordered by mangrove swamps, salt marshes, freshwater swamps and most rivers and streams) are in this category.

The area will not be considered one of low potential impact if preliminary literature review and/or abbreviated “pilot” field studies reveal that:

1. Phytoplankton contribute a substantial amount of the primary synthetic activity supporting the community;

2. A shift towards nuisance species may be encouraged by the thermal discharge; orMA0003654 Determinations Document July 22, 2002

6-16 3. Operation of the discharge may alter the community from a detrital to a phytoplankton based system.

If a receiving water is determined to be an area of potential impact for phytoplankton, the 1977 EPA 316(a) Technical Guidance Manual directs that the following decision criteria are to be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met:

1. A shift towards nuisance species of phytoplankton is not likely;

2. There is little likelihood that the discharge will alter the indigenous community from a detrital to a phytoplankton based system; or

3. Appreciable harm to the balanced indigenous population is not likely to occur as a result of phytoplankton community changes caused by the heated discharge.

6.3.2b Zooplankton

Zooplankton are microscopic animals that live in the water column. Zooplankton are comprised of two different categories of organisms, holoplankton and meroplankton. Holoplankton spend their entire life cycles as planktonic creatures. Meroplankton, such as fish and crustacean eggs and larvae, only spend a portion of their life cycle as plankton. The zooplankton community is a primary food source for larval fish, shellfish and some species of adult fish.

i. Low Potential Impact Areas for Zooplankton

Areas of low potential impact for zooplankton are defined in the 1977 EPA 316(a) Technical Guidance Manual as those characterized by naturally low concentrations of commercially important species, rare and endangered species, and/or those forms that are important components of the food web or where the thermal discharge will affect a relatively small proportion of the receiving water.

Most estuarine areas will not be considered areas of low potential impact for zooplankton. However, where a logarithmic gradient of zooplankton abundance exists, those areas at the lowest level of abundance may be recognized as low potential impact areas at the discretion ofMA0003654 Determinations Document July 22, 2002

6-17 the Regional Administrator.

If the receiving water is deemed a potential impact area for zooplankton, the 1977 EPA 316(a) Technical Guidance Manual directs that the following decision criteria should be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met:

1. Changes in the zooplankton and meroplankton community in the primary study area that may be caused by the heated discharge will not result in appreciable harm to the balanced indigenous fish and shellfish population;

2. The heated discharge is not likely to alter the standing crop or relative abundance, with respect to natural population fluctuations in the far field study area, from those values typical of the receiving water body segment prior to plant operation; or

3. The thermal plume does not constitute a lethal barrier to the free movement (drift) of zooplankton and meroplankton.

6.3.2c Habitat Formers

Habitat formers are species whose presence provide cover, foraging, spawning or nursery habitat for other species. In the marine environment, these would typically include coral reefs, seagrass meadows, kelp beds and macroalgal stands. These environments tend to be limited resources and many other species utilize these habitats for spawning, nursery areas, foraging and refuge from predation.

i. Low Potential Impact Areas for Habitat Formers

In some situations, the aquatic environment at a site will be devoid of habitat formers. This condition may be caused by low levels of nutrients, inadequate light penetration, sedimentation, scouring stream velocities, substrate character, or toxic materials. Under such conditions the site may be considered a low potential impact area. However, if there is some possibility the limiting factors (especially man-caused limiting factors) may be relieved and habitat formers may be established within the area, the applicant will be required to demonstrate that the heated discharge would not restrict re-establishment. Those sites where there is a possibility that a thermal discharge will impact a threatened or endangered species through adverse impacts on habitat formers will not be considered low potential impact areas.MA0003654 Determinations Document July 22, 2002

6-18 If the receiving water is deemed a potential impact area for habitat formers, the 1977 EPA 316(a) Technical Guidance Manual directs that the following decision criteria should be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met.

1. The heated discharge will not result in any deterioration of the habitat formers community or no appreciable harm to the balanced indigenous population will result from such deteriorations; or

2. The heated discharge will not have an adverse impact on threatened or endangered species as a result of impact upon habitat formers.

6.3.2d Shellfish and Macroinvertebrates

Macroinvertebrate fauna, including shellfish, are important components of aquatic food webs and are directly important to man as a source of food and as bait for sport and commercial fishermen. Their burrowing and feeding activities promote oxygenation of sediments and recycling of important nutrients from the sediments.

ii. Low Potential Impact Areas for Shellfish/Macroinvertebrates

A low potential impact area for shellfish/macroinvertebrates fauna is defined by the 1977 EPA 316(a) Technical Guidance Manual as an area which, within the primary and far field study areas, can meet the following requirements:

1. Shellfish/macroinvertebrate species of existing or potential commercial value do not occur at the site. This requirement can be met if the applicant can show that the occurrence of such species is marginal;

2. Shellfish/macroinvertebrates do not serve as important components of the aquatic community at the site;

3. Threatened or endangered species of shellfish/macroinvertebrates do not occur at the site;

4. The standing crop of shellfish/macroinvertebrates at the time of maximum abundance is less than one gram ash-free dry weight per square meter; and

5. The site does not serve as a spawning or nursery area for the species in 1, 2, orMA0003654 Determinations Document July 22, 2002

6-19 3 above.

If the receiving water is deemed a potential impact area for shellfish and macroinvertebrates, then the 1977 EPA 316(a) Technical Guidance Manual directs that the following decision criteria should be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met:

1. Reductions in the standing crop of shellfish and macroinvertebrates may be cause for denial of a 316(a) waiver unless the applicant can show that such reductions caused no appreciable harm to balanced indigenous populations within the water body segment;

2. Reductions in the components of diversity may be cause for the denial of a 316(a) waiver unless the applicant can show that the critical functions of the macroinvertebrate fauna are being maintained in the water body segment as they existed prior to the introduction of heat; or

3. Areas which serve as spawning and nursery sites for important shellfish and/or macroinvertebrate fauna are considered as zero allowable impact areas and will be excluded from consideration for the discharge of waste heat. Plants sited in locations which would impact these critical functions will not be eligible for a 316(a) waiver. Most estuarine sites will fall into this category.

6.3.2e Fish

Fish are important components of marine ecosystems and are important sources of food for man.

i. Low Potential Impact Area for Fish

According to the 1977 EPA 316(a) Technical Guidance Manual, a discharge may be determined to be in a low potential impact area for fishes within the primary and far field study areas if the following conditions are satisfied:

1. The occurrence of sport and commercial species of fish is marginal;

2. The discharge site is not a spawning or nursery area;MA0003654 Determinations Document July 22, 2002

6-20 3. The thermal plume will not occupy a large portion of the zone of passage which would block or hinder fish migration under the most conservative environmental conditions (based on 7-day, 10-year low flow or water level and maximum water temperature); and

4. The plume configuration will not cause fish to become vulnerable to cold shock or have an adverse impact on threatened or endangered species.

If the receiving water is deemed an area of potential impact for fish, then the 1977 316(a) Technical Guidance Manual directs that the following decision criteria should be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met.

The discharge should not result in:

1. Direct or indirect mortality from cold shocks;

2. Direct or indirect mortality from excess heat;

3. Reduced reproductive success or growth as a result of plant discharges;

4. Exclusion from unacceptably large areas; or

5. Blockage of migration.

6.3.2f Other Vertebrate Wildlife

These include marine mammals, sea turtles and birds that may rely on estuarine and coastal waters for foraging, reproduction and other life functions.

i. Low potential Impact Areas for Other Vertebrate Wildlife

According to the 1977 316(a) Technical Guidance Document, most sites in the United States will be considered ones of low potential impact for other vertebrate wildlife simply because thermal plumes should not generally impact large or unique populations of wildlife. The main exceptions will be sites in cold areas (such as North Central United States) which would be predicted to attract geese and ducks and encourage them to stay through the winter. These would not be considered low potential impact areas unless they could demonstrate that the wildlife would be protected through a wildlife management plan or other methods from theMA0003654 Determinations Document July 22, 2002

6-21 potential sources of harm mentioned in the next section.

Other exceptions to sites classified as low potential impact would be those few sites where the discharge might affect important (or threatened and endangered) wildlife such as manatees or sea turtles.

For most other sites, brief site inspections and literature reviews would supply enough information to enable the applicant to write a brief rationale about why the site should be considered one of low potential impact for other vertebrates.

If the receiving water is deemed an area of potential impact for vertebrate wildlife, then the 1977 EPA 316(a) Technical Guidance Manual directs that the following decision criteria should be used.

ii. Decision Criteria

Depending on the severity of the effect, denial of a 316(a) variance may be warranted if the following decision criteria are not met.

The discharge should not cause:

1. Excess heat or cold shock;

2. Increased disease and parasitism;

3. Reduced growth or reproductive success;

4. Exclusion from unique or large habitat areas; or

5. Interference with migratory pathways.

6.3.3 § 316(a) Community Impact Analysis

6.3.3a Phytoplankton Community

EPA does not consider Mount Hope Bay a low potential impact area for phytoplankton, because:

1. Phytoplankton are the dominant primary producers in Mount Hope Bay, as seagrass and salt marshes have declined over time; andMA0003654 Determinations Document July 22, 2002

6-22 2. The presence of nuisance algal species has been documented in Mount Hope Bay.

i. Nuisance Algal Blooms

To assess potential for nuisance algal blooms in the future, it is useful to review past events. In August 2001, a nuisance blue-green algae, primarily Anacystis auruginosa , was documented in Mount Hope Bay (Scherer, 2002A). It has been well established that blue-green algal blooms are stimulated by high nutrients and warm water temperatures (US EPA, 1985). The bloom was identified from material taken off the intake screens (Scherer, 2002A). The exact geographic extent of this bloom was unknown, but no records of similar blooms were recorded forNarragansett Bay (Deacutis, 2002). Due to the proximity of this bloom to the plant and bluegreen algae’s affinity for higher temperatures, it is likely that the thermal plume from Brayton Point Station contributed to this bloom. The Enhanced Multi-Mode option will significantly reduce the flux of heat to Mount Hope Bay, however a substantial quantity of heat will still be discharged and the discharge temperature and ) T limits will not be changed. Therefore, even with the Enhanced Multi-Mode option, there is a reasonable probability based on current information, that blue-green algal blooms will continue to appear in Mount Hope Bay.

ii. Phytoplankton Community Changes

The normal seasonal phytoplankton cycle observed in New England coastal waters is a dramatic increase in phytoplankton abundance in late winter to early spring (Valiela, 1995). Keller et al. (1999) state that in many temperate waters, the winter-spring phytoplankton bloom may deliver up to half of the total annual input of organic carbon to the benthic layer. Carbon entering the benthic layer supports a diverse group of benthic infaunal organisms, many of which serve as prey for winter flounder and other benthic predators.

Very little detailed field collected data is available on phytoplankton communities for Mount Hope Bay. The limited chlorophyll (a surrogate measure for phytoplankton density) data collected by Dr. Mark Berman of NMFS for the last 4 years shows that, in general, chlorophyll concentrations in Mount Hope Bay are slightly higher than most areas of Narragansett Bay, except for the Providence River. During the duration of his sampling, Dr. Berman (2001) has not detected what would be considered the typical winter-spring phytoplankton bloom in Mount Hope Bay.

In predicting impacts of elevated temperature to the phytoplankton community of Narragansett Bay, Keller et al. (1999) conducted a mesocosm experiment examining the response of zooplankton, phytoplankton and blue mussels to an elevated winter water temperature. The warm tanks were held at 0.8 o C greater than the controls. Cool tanks were held at 2 o C less than the controls. The controls were based on the long term monthly average water temperature in Narrangansett Bay from 1977 through 1989. These temperatures declined from 7 o C at theMA0003654 Determinations Document July 22, 2002

6-23 beginning of the experiment in December to 3 o C at the completion in February. Phytoplankton abundance and biomass were reduced in warm tanks compared to controls. A winter-spring phytoplankton bloom did not occur in the warm tanks, but did occur in the controls and the cool tanks. Zooplankton grazing and filtration rates of blue mussels increased in the warm tanks compared to controls. It was thought to have exerted “top-down” control on the phytoplankton population, eliminating the normal winter-spring bloom cycle. The implication of a reduced or totally absent winter-spring bloom is that carbon will enter the food chain through a different mechanism. In a typical year, with a normal winter-spring phytoplankton bloom, the vast majority of carbon resulting from phytoplankton growth enters the benthic food chain via sedimentation. In this mesocosm experiment, as much as 80% of the phytoplankton carbon in the cool tanks was lost via sedimentation. In the warm tanks, sedimentation accounted for only 29-43% of the losses, grazing by zooplankton and blue mussels accounting for an equivalent or greater percentage 29-55%. This represents a change from carbon entering the food web via the benthic layer to entering via the pelagic layer. The implication of reduced carbon available in the benthic layer is that a reduced quantity of prey organisms would be available for winter flounder and other benthic predators.

NASA satellite images analyzed by Mustard et al. (2001) compared water temperature in Mount Hope Bay to surrounding water bodies. They found that Mount Hope Bay surface waters are on average 0.8 o C warmer during the summer and fall than comparable shallow areas of Narragansett Bay. The authors attribute this elevated temperature to the effluent from the plant and states that 35 km 2 (essentially 100% of the bay) are impacted. The plume is less well defined in the winter and spring, because the water column is not stratified and the plume tends to sink. Thus, the plume is less discernible from satellite images at those times of year.

Hydrothermal modeling done by USGenNE’s consultant for the warm summertime condition has shown that under existing operating conditions, over 80% of the bay by volume will experience ) 0.8 o C or more (USGenNE 10/1/01, Section 308 Information Request Response, p.38). USGenNE’s proposed permit conditions would result in over 50% of the bay by volume experiencing a summertime ) 0.8 o C or more (USGenNE 10/1/01, Section 308 Information Request Response, p.38).

Based on the limited field data documenting the lack of a winter-spring bloom, the mesocosm study by Keller et al. (1999) and the satellite images comparing temperatures in Mount Hope Bay with those of surrounding waters, it is likely that elevated water temperatures, due to Brayton Point Station’s discharge, have a reasonable potential to alter normal phytoplankton population dynamics. This change in phytoplankton population dynamics could very likely lead to significant impacts within the trophic dynamics of the food web. Elevated water temperatures in Mount Hope Bay lead to increased grazing by zooplankton and increased filtration rates by shellfish. This increased predation may be responsible for the observed lack of a winter-spring phytoplankton bloom in Mount Hope Bay. Changes in phytoplankton population dynamics can ripple throughout the food web as phytoplankton are the dominantMA0003654 Determinations Document July 22, 2002

6-24 primary producers in Mount Hope Bay. Redirecting carbon away from the benthos and into the pelagic realm, would represent a reduction in prey species for benthic predators such as winter flounder, tautog, hogchoker and windowpane. Therefore, based on the satellite images collected by Mustard, and further supported by computer models run by consultants to USGenNE, the influence of the plume extends over large areas of Mount Hope Bay.

Under USGenNE’s proposed Enhanced Multi-Mode alternative, over half of the bay by volume would still experience a change in temperature significant enough, based on the mesocosm studies, to alter normal phytoplankton population dynamics. This represents a substantial areal change in phytoplankton population dynamics, that could lead to significant changes in food web dynamics for a large part of the bay. Based on this analysis, the phytoplankton Decision Criteria no. 1 and 3, from the 1977 EPA 316(a) Technical Guidance Manual would not be satisfied.

6.3.3b Zooplankton Community

EPA does not consider Mount Hope Bay a low impact area for zooplankton, because it is an estuary that serves as a spawning site for numerous fish and invertebrate species.

i. Zooplankton Community Changes That May Harm Balanced Indigenous Population of Fish and Shellfish

There is not an extensive database available for zooplankton abundance and species composition in Mount Hope Bay. USGenNE compared data that was collected by their consultant Marine Research, Inc. (MRI) from 1972-1985 with data collected in 1997/1998. The timing of zooplankton peaks of high abundance and species assemblage was similar to the historical dataset.

The ctenophore, Mneimiopsis leidyi , historically bloomed in Narragansett Bay in late summer and early fall. Narragansett Bay is the northern extreme of the latitudinal distribution for this species. In recent years, M. leidyihas been appearing in Narragansett Bay and Mount Hope Bay earlier in the calendar year (Sullivan et al., 2001). In 2002, comb jellies, most likely M. leidyi
, overwintered in Mount Hope Bay (Scherer, 2002B; Colarusso, 2002). Ctenophores are voracious plankton eaters and have been implicated in fish declines in the Black Sea (Sullivan et al., 2001). M. leidyican feed on pelagic fish eggs and zooplankton (Sullivan et al., 2001). For species with demersal eggs, such as winter flounder, there is likely little direct predation by M. leidyi , but the ctenophore will compete with fish larvae for zooplankton prey (Sullivan et al., 2001). Jellies are thought to be a good group of organisms to use to track the quality of coastal ecosystems, dramatic increases in their abundance are usually indicative of stressed systems (Pohl, 2002). Increases in water temperatures, increases in nutrients and depletion of fish stocks are thought to be the most important stresses (Pohl, 2002).MA0003654 Determinations Document July 22, 2002

6-25 Sullivan et al. (2001) suggest increases in water temperature are responsible for the expansion of the range and time of year that M. leidyiis found. The authors suggest that long term temperature rise may be responsible for the changes they are observing. In Mount Hope Bay, the incremental quantity of heat being added to the bay as a result of long term temperature rise (assuming that the rise continues at the historical rate of change) is minor compared to the quantity discharged by Brayton Point Station even under the Enhanced Multi-Mode option (Houlihan, 2002). Thus, Brayton Point Station is significantly contributing to the thermal conditions in Mount Hope Bay and potentially facilitating the expansion of the range and time of year distribution of the ctenophore M. leidyi . The expansion of time of abundance of this ctenophore would increase natural mortality rates for species with pelagic eggs and create competition for food resources with species, such as winter flounder, that have pelagic larvae. This increased competition for food resources could result in reduced growth rates and survival for larval winter flounder and other species with pelagic larvae.

Based on this analysis, zooplankton Decision Criteria no.1 and 2 from the 1977 EPA 316(a) Technical Guidance Manual are not satisfied.

6.3.3c Habitat Formers

EPA does not consider Mount Hope Bay a low impact area for habitat formers, because past presence of eelgrass in the bay shows that Mount Hope Bay is a capable of supporting this type of habitat. Extensive improvements made to and planned for the Fall River treatment plant and Combined Sewer Overflow (CSO) collection system, continued incremental improvements from other point source dischargers, such as the Brockton sewage treatment plant, as a result of EPA and MA DEP ongoing permitting efforts, combined with EPA’s and MA DEP’s continued nonpoint source control work should improve water quality in Mount Hope Bay through time. In addition, numerous eelgrass restorations efforts are being or have been attempted around Narragansett Bay. EPA does not deem Mount Hope Bay, a low impact area for Habitat Formers (despite the current lack of eelgrass in Mount Hope Bay), because of the potential for recovery of this habitat in this system.

i. Exclusion of Habitat Formers

Mount Hope Bay at one time, supported extensive eelgrass meadows. In the 1930s, an extensive dieoff of eelgrass occurred along the entire eastern seaboard of the United States (Short et al., 1988). Numerous theories exist as to the cause of this dramatic decline including an episodic disease outbreak, poor water quality and a temperature mediated decline (Short et al., 1988). Although some eelgrass did persist in areas of Mount Hope Bay into the 1940s (http://www.edc.uri.edu/eelgrass), currently, eelgrass is only present in the southern third of Narragansett Bay (http://www.edc.uri.edu/eelgrass). Eelgrass is a coldwater plant that ranges from North Carolina to Canada and grows on predominantly soft bottom substrates (Thayer et al., 1985). A protected (low wave energy) shallow, soft bottom embayment, such as MountMA0003654 Determinations Document July 22, 2002

6-26 Hope Bay, is the ideal physical habitat for eelgrass growth (Thayer et al, 1985). However, the combination of warm water temperatures and low water clarity may prevent its re-establishment.

Marsh et al. (1986) measured the changes in eelgrass photosynthesis and respiration rates at 8 temperatures between 0 to 35 o C. These experiments were carried out at the point of light saturation. In other words, increasing the intensity of light would result in no change in the rate of photosynthesis. Photosynthetic rates increased with temperature as did respiration rates. The temperature with the greatest ratio of photosynthetic rate to respiration rate was 5 o C, thus representing the point of maximum growth. At temperatures above 30 o C, the respiration rate exceeds the rate of photosynthesis, which would lead to negative plant growth and mortality. Thus, in clear waters, where the penetration of light is good, 30 o C may be a reasonable temperature threshold for eelgrass.

However, Mount Hope Bay is a turbid water body, with reduced light penetration (C. Krahforst, 2002). Bulthuis (1987) examined the effect of temperature on seagrass photosynthesis rates at low light levels. He showed that optimum temperature for photosynthesis in Heterozostera tasmanica decreased from 35 o C at light saturation to 5 o C at reduced light levels. Balthuis did not measure respiration rates, but it has been well established that respiration rates in seagrass increase with temperature (Marsh et al., 1986). Thus, in turbid water bodies, where light penetration is reduced, seagrass growth decreases with increased temperature, because photosynthetic rates decrease, and respiration rates increase.

It is quite likely therefore, that the combination of poor water clarity and high water temperature in Mount Hope Bay represent an exclusion zone for eelgrass growth. The Brayton Point Station discharge, which elevates the temperature over significant portions of the bay, contributes to this exclusion zone.

6.6.3d Shellfish and Macroinvertebrates

EPA has determined that Mount Hope Bay is not a low potential impact area for shellfish and macroinvertebrates, because:

1. Shellfish of commercially important species do exist in Mount Hope Bay and they do exist in substantial densities;

2. Shellfish and macroinvertebrates do serve as important components of this ecosystem; and

3. Mount Hope Bay does serve as a spawning and nursery area for shellfish and macroinvertebrates.MA0003654 Determinations Document July 22, 2002

6-27 i. Balanced Indigenous Population of Shellfish and Macroinvertebrates

There is not a large quantity of data on shellfish and macroinvertebrates in Mount Hope Bay. Historically, data on benthic macroinvertebrates was collected by Marine Research, Inc. (MRI) from 1975 to 1992. At the request of the permittee, EPA, with agreement from the Technical Advisory Committee (TAC), ended this permit requirement during the reissuance of the 1993 permit. Another survey was done by MRI in 1997/1998 and found no significant differences in the benthic community compared to the 1975 to 1992.

EPA conducted benthic sampling in 2000 at 10 stations in the Taunton River and 10 stations in the Kickamuit River. They compared those results with samples taken by Diaz and Daughters from 11 stations around Spar Island and a Scientific Applications International Corporation (SAIC) study with 1988 data along a transect in Mount Hope Bay (Cicchetti, 2001). All the studies showed similar results, the surveys did not detect extensive areas that showed indication of sustained hypoxia or anoxia (Cicchetti, 2001). EPA found beds of Ampelisca amphipod tubes, which is not considered to indicative of an enriched or physically disturbed habitat (Cicchetti, 2001). Ampelisca amphipods have been shown to be a substantial percentage of the diet of juvenile winter flounder (Franz and Tanacredi, 1992). EPA has not found substantial evidence of harm to shellfish and macroinvertebrates from the current thermal discharge, thus it is reasonable to expect that any reduction of thermal loading in the future would be acceptable as well.

6.3.3e Fish

EPA has determined that Mount Hope Bay is not a low potential impact area for fish because:

1. Numerous species of recreational and commercially important fish occur in the bay;

2. Mount Hope Bay is a finfish spawning and nursery area; and

3. There is the potential for blockage of normal fish migration.

i. Balanced Indigenous Population of Fish

The analysis of finfish was done in two steps to determine the appropriate thermal discharge limits for Brayton Point station in order to protect finfish populations in Mount Hope Bay. Step 1 was a retrospective examination of total finfish abundance trends in relation to plant operations. This analysis was performed to try to determine the appropriate annual flux of heat into the bay that would be still protective of finfish populations. Step 2 examined specific temperature thresholds for individual species. These thresholds included both acute and chronicMA0003654 Determinations Document July 22, 2002

6-28 mortality and a host of sublethal effects, such as avoidance, cessation of feeding, and impaired swimming or reproduction.

(A) Annual Flux of Heat

USGenNE’s 316(a) Variance Request (December, 2001) asks for an annual mass flux of heat totaling 28 trillion British thermal units (TBTU). To derive a protective quantity of heat that can be discharged to Mount Hope Bay as an annual flux number, EPA looked at past plant annual thermal discharge totals and finfish abundance. It is tempting to focus solely on the dramatic decline in total finfish abundance in 1984-1985, when Unit 4 was converted to once-through cooling, and conclude that the appropriate operating condition would be one that mimicked plant operations prior to that time. Several analyses suggest that this would not be sufficient to protect the BIP.

First, total finfish abundance prior to 1984-85 was certainly significantly greater than it is today, but it was not indicative of a stable balanced community. Dramatic swings in total finfish abundance occurred several times from 1972 to 1984. This boom/bust cycle is indicative of an unstable population that may be prone to collapse. It should be noted that Units 1, 2 and 3 were all operational prior to 1972, thus there is no true baseline (pre-impact) data. One of the experts EPA solicited to review the 1996 Gibson report suggested that based on these population swings, it was likely that finfish populations in Mount Hope Bay were going to collapse even if Unit 4 had not been converted to once through cooling (Hicks, 1996).

Second, recent analysis done by Mark Gibson (2002A) suggests that winter flounder abundance in Mount Hope Bay has been declining since the initiation of data collection in 1972. Gibson did a relatively straightforward analysis of regional factors on winter flounder abundance. He divided the results from each MRI annual otter trawl survey by its counterpart from otter trawl surveys away from the plant. He used the University of Rhode Island Graduate School of Oceanography (URIGSO) survey conducted in the lower west passage of Narragansett Bay and the National Marine Fisheries Service (NMFS) survey conducted in Block Island Sound. Theoretically, all these surveys should integrate the large scale regional factors such as overfishing, water temperature rise and increased predation that may be affecting winter flounder abundance. Thus, by standardizing these datasets, the influence of local stressors can be determined. The results of this analysis (Figure 6.3-1) show a steady downward trend in this standard index, beginning in 1972 and culminating in a collapse in the mid 1980s. The plant had been operational for 9 years (Units 1,2 and 3 came on line in 1963, 1965 and 1969 respectively) before fish abundance data began to be collected in 1972, so it is not possible to estimate what the finfish community was like prior to plant impact.

Third, in an analysis provided by Marine Research, Inc., and New England Power CompanyMA0003654 Determinations Document July 22, 2002

6-29 (former owners of Brayton point Station) entitled Brayton Point Generating Station, Mount Hope Bay, Somerset, Massachusetts, Supporting Document for Cooling Water Discharge Temperature up to 95 o , the authors referring to the period of study from 1972-1978, state that “winter flounder ( P. americanus ), windowpane flounder ( S. aquosus ) and silversides ( Menidia spp.), have noticeably declined in abundance in upper Mount Hope Bay during this period of study...”.

The historic annual heat (in TBTUs) outputs for Brayton Point Station are listed in Table 6.3-1 and finfish abundance is shown in Figure 2.6-1. The average annual heat output for Brayton Point Station for the time period (1970-1983) prior to the collapse of the fishery was 28.26 TBTU. Currently, Brayton Point Station discharges in the high 30 to low 40 TBTUs per year range (Table 6.3-1). The USGenNE Variance Request asks for operating conditions that would essentially return station output to the 1970-1983 level. Fish abundance data exists from 1972 onward and for the reasons detailed above, EPA believes that fish populations were experiencing a steady decline during that period. Thus, historical finfish abundance trends do not support an annual heat flux equaling 28 TBTU as being able to stop or reverse a decline in fish populations. A lower annual value would be more appropriate.MA0003654 Determinations Document July 22, 2002

6-30 Table 6.3-1: Annual Flux of Heat From Brayton Point Station to Mount Hope Bay in TBTUs 1

Year Annual Heat Flux Year Annual Heat Flux

1970 28 1985 35.2

1971 30.5 1986 33.8

1972 30.9 1987 41.1

1973 30.2 1988 48.8

1974 23 1989 49.5

1975 22 1990 47.7

1976 25.9 1991 41.8

1977 28.2 1992 37.5

1978 29.4 1993 38.9

1979 26.7 1994 38.3

1980 30.2 1995 38.6

1981 25.5 1996 38

1982 32.3 1997 41

1983 32.9 1998 38.4

1984 34 1999 39.1

2000 37.4

1 USGenNE 10/01/01 Section 308 Information Response

(B) Temperature Threshold Analysis

This analysis compares predicted water temperatures in the thermal discharge plume from a variety of different operating scenarios compared with critical temperature thresholds for marine organisms as detailed in the scientific literature. A major piece of USGenNE’s 316(a) variance request is a species by species review of critical temperature thresholds.

An essential component of the critical temperature analysis is the ability to accurately predict thermal plume dynamics. Thus, the TAC requested the company to develop a predictiveMA0003654 Determinations Document July 22, 2002

6-31 hydrothermal model for Mount Hope Bay. USGenNE hired Applied Science Associates (ASA) to conduct the modeling. ASA used 2 models to characterize the thermal plume, the Cornell Mixing Zone Expert System (CORMIX) for the near field (within 1,640 ft of discharge canal) and WQMAP, developed by ASA and the University of Rhode Island, for far-field effects. Mount Hope Bay was divided into 11 vertical layers and 3300 cells. The models predicted salinity, velocity and water temperature and were calibrated to field data. Model optimization was done with thermistor data acquired in the bay for summer and winter conditions. After model calibration and optimization, the TAC, and EPA accepted the model as an adequate predictive tool of water temperature dynamics in Mount Hope Bay.

Two temporal periods were considered to be the most biologically sensitive by EPA and the TAC and were the focus of modeling efforts. These were labeled as “winter” (which encompassed March 1 to March 31) and “summer” (which encompassed July 15 to August 15). The March time period was selected as it corresponds with some winter flounder spawning activity and with large numbers of larval planktonic winter flounder being present in the water column. The second time period was selected to assess thermal effects during the warmest time of the year.

Historical environmental data was used to define baseline water temperature conditions for the model. Based on review of the environmental data, a range of baseline conditions were defined as “cool”, “average” and “warm” years. The “average” year was not based an arithmetic mean, but represented conditions that approximate the midpoint between the “cool” and “warm” years. The model predicted ) T (increase over ambient) as well as absolute temperature.

USGenNE analyzed two operating scenarios (MOAII and EMM) in their 316 Partial Demonstration Document (May, 2001). The TAC requested that two additional operating scenarios (Hypothetical A and B) and a “No Plant” alternative be analyzed. The flow and heat load of each scenario is detailed below:

Flow Heat Load (MGD) (TBTU/mo) Scenario Summer Winter Summer Winter Annual MOAII 1,043 925 3.7 4.1 42 EMM 750 600 2.25 2.375 28 Hypothetical A 750 600 1.2 1.2 14.4 Hypothetical B 750 600 1.8 1.8 21.6 No Plant 0 0 0 0 0

Predicted absolute water temperatures and ) T values were used to assess the potential impact of the plant’s thermal discharge on the biota of Mount Hope Bay. The initial approach taken by USGenNE, with agreement from the TAC and EPA, was to review the scientific literature on thermal tolerance of important species present in Mount Hope Bay. A list of RepresentativeMA0003654 Determinations Document July 22, 2002

6-32 Important Species (RIS) had been derived years ago by the TAC. This list was reviewed and approved by the current TAC and includes the following species:

alewife ( Alosa pseudoharengus ) Atlantic menhaden ( Brevoortia tyrannus ) Atlantic silverside (Menidia menidia ) bay anchovy (

Anchoa mitchilli ) hogchoker ( Trinectes maculatus ) rainbow smelt ( Osmerus mordax ) sand lance (

Ammodyte americanus ) seaboard goby ( Gobiosoma ginsburgi ) silver hake (Merluccius bilinearis ) tautog ( Tautoga onitis ) threespine stickleback ( Gasterosteus aculeatus ) weakfish ( Cynoscion regalis ) white perch (Morone americana ) winter flounder ( Pleuronectes americanus ) quahog ( Mercenaria mercenaria ) blue mussel (Mytilus edulis ) eelgrass ( Zostera marina ).

For winter flounder, an additional population level analysis was conducted. Critical temperatures from the literature were taken and used to assess acres of suitable habitat that would be left by different thermal discharge scenarios. This data was then fed into the RAMAS model to predict winter flounder population trajectories. The TAC’s concerns with the RAMAS model are detailed later in this document. The TAC’s major concern with the RAMAS model was its inability to replicate past changes in winter flounder population numbers, thus its ability to accurately predict future changes was questionable. Consequently, EPA has not relied on the RAMAS model results in either the 316(a) or (b) analysis.

In the absence of a proven predictive population model, the potential future effects of the thermal plume on various aquatic organisms were assessed by comparing the hydrothermal model results predicting water temperatures with temperature tolerance numbers taken from the peer-reviewed scientific literature. USGenNE, members of the TAC and consultants hired by EPA did a literature review for thermal tolerances for the RIS. The TAC and USGenNE did not agree on what the appropriate critical temperature values were for many of the species. Examples of these difference of opinions are detailed in a later section below.

As stated above, the hydrothermal model is an 11 layer model, capable of predicting water temperature at 11 different depths in the water column. To assess thermal impacts, results from the hydrothermal model were split into “pelagic” and “benthic” portions. Pelagic was defined as the top 10 layers of the water column as delineated by the hydrothermal model, and benthic wasMA0003654 Determinations Document July 22, 2002

6-33 defined as the bottom layer of the water column as delineated by the hydrothermal model. For the RIS, natural history information was reviewed and various life stages were defined as benthic or pelagic. For example, because winter flounder eggs are demersal, this life stage was classified as benthic. Larval winter flounder are planktonic and as a result were classified as pelagic. Juvenile and adult winter flounder live on the bottom and were classified as benthic. Impacts were then assessed based on a comparison of predicted water temperatures from the hydrothermal model with scientific literature values for specific species.

USGenNE’s biothermal assessment examined the impact of the thermal plume on growth, spawning, egg survival and/or malformation, potential for habitat avoidance, potential blockage of migratory routes, potential for elevated temperature mortality and potential for cold-shock mortality.

In USGenNE’s assessment of thermal impacts on growth rates (May 24, 2001 USGenNE 316(a) and (b) Partial Variance Demonstration), they derived the “optimal” temperatures using a linear relationship incorporating acclimation temperatures. However, USGenNE’s definition of “optimal” temperature is not readily apparent. For example, USGenNE discuss their derivation of optimal temperature for tautog growth citing a study by Olla and Studholme (1975) where fish were held in a tank and the water temperature was gradually increased from 21.1 to 30.2 o C (64-86.4 o F). At 26.9 o C (80.4 o F), feeding and swimming activity decreased. Feeding and swimming activity further decreased at 28.1 o C (82.6 o ) and sharply fell off at 29.3 o C (84.7 o F). USGenNE then chose the midpoint between 28.1 and 29.3 o or 28.7 o C, as the optimal temperature for tautog. Thus, USGenNE did not choose the first temperature, where the researchers first noted thermal effects or the second temperature, where those effects became more pronounced, it chose a temperature that occurred past the pronounced effects, yet before feeding and swimming was completely eliminated, as the “optimal” temperature. Typically, optimal temperatures are selected as points of maximum feeding, growth, or reproduction, but the company chose a temperature that did not correspond to any of these. The tautog example is an important one because 1. tautog are commercially valuable, 2. Mount Hope Bay has been identified as an important spawning area for them (Meng and Powell, 1999), and 3. they are one of the 4 species that RI DEM showed had a statistically significantly different population trajectory in Mount Hope Bay compared to Narragansett Bay (Gibson, 1996).

For a second example, USGenNE selected 35 o C as the “optimal temperature” for hogchoker based on a study by Peters and Boyd (1972). This laboratory study represents what may be a physiologically optimal temperature for hogchoker. However, observations in nature indicate that hogchoker avoid water temperatures above 25 o C, though this may be physiologically less favorable. Thus, as the authors of the study question, the ecological relevance of 35 o C is questionable.

USGenNE in their final Clean Water Act Section 316(a) and (b) Demonstration (December, 2001) conducted an “expanded” biothermal assessment. The “expanded” biothermalMA0003654 Determinations Document July 22, 2002

6-34 assessment allowed for a more “refined” (USGenNE’s description) analysis. The major differences between the permittee’s “expanded” analysis and the biothermal analysis in the partial demonstration document (May, 2001) are that:

1. In the “expanded” analysis, USGenNE looked at predicted temperatures from the hydrothermal model in every cell of the model grid in order to predict biological effects. The prior analysis, attempted to predict biological effects from baywide volumes of water exceeding target temperatures;

2. The “expanded” analysis defined specific habitat areas for different life stages of target species. Prior analysis assumed an equal distribution of organisms throughout the bay;

3. The permittee’s “expanded” analysis uses model predictions for the entire year, while the prior analysis focused in on two biologically critical months of the year;

4. The permittee’s “expanded” analysis relies on abundance of fish, eggs and larvaefrom the MRI monitoring program. The prior analysis relied on the peerreviewed scientific literature to determine the time of year when a specific life stage of a target species was present; and

5. The permittee’s “expanded” analysis represents a slightly more involved examination of temperature thresholds for target species than the prior analysis. USGenNE derived graphs that overlay various temperature thresholds and refers to these graphs as “Temperature Polygons”. Acute and chronic toxicity, avoidance temperatures and growth zones are depicted on these graphs.

EPA and other agencies on the TAC reviewed this most recent modeling approach. Several reviewers, Mark Gibson of RI DEM, Todd Callaghan of MA CZM and Gerry Szal, MA DEP, sent EPA their comments on USGenNE’s “expanded” analysis for the 316(a) variance request (See Appendix A). Their major points of disagreement with USGenNE’s analysis are outlined below:

1. USGenNE relies heavily on the concept of “temperature acclimation” to assess

biothermal thresholds in fish. USGenNE constructs temperature polygons based on an acclimation of 7 days at a lower temperature, so as, theoretically to allow a greater tolerance of higher temperatures. Physiological acclimation does occur in the laboratory, but the extent to which it occurs in nature is uncertain and debatable. Rhode Island DEM submitted data comparing winter flounder abundance with temperature (Reitsma, 2002). The data suggests that flounder response to water temperature is fairly dramatic. Figure 6.3-2 and Figure 6.3-3MA0003654 Determinations Document July 22, 2002

6-35 show that adult flounder abundance drops to nearly zero above 15 o C and juvenile abundance declines in a similar fashion above 24 or 25 o C. The response of these fish are dramatic and indicative of a temperature threshold effect. This field data agrees with reported temperature thresholds found in the scientific literature. Duffy and Luders (1978) and Casterlin and Reynolds (1982), both found that juvenile winter flounder showed avoidance at 24 o C. In a publication submitted to EPA by USGenNE, Olla et al.(1969) conducted a study involving field observations of winter flounder behavior at different temperatures in Great South Bay on Long Island. Responses by these fish were not a result of artificial conditions in a laboratory, and therefore represent a reasonable predictor of their behavior in the environment. Olla et al.(1969) found that winter flounder burrow into the bottom sediments, at temperatures higher than 22.2 o C. This burrowing phenomenon is a form of temperature avoidance, because temperatures measured in the sediments were several degrees cooler than temperatures in the water column. During the burrowing, winter flounder ceased to feed, representing a stressful situation for the fish. Thus, field studies document that behavioral responses in winter flounder begin at 22.2 o C. The above cited laboratory studies, the Rhode Island DEM field data and the field study submitted by USGenNE all support the concept that sublethal temperature effects begin occurring in the low 20s o C and result in complete avoidance of the area by 24 or 25 o C. By using the concept of “acclimation temperatures”, USGenNE predicted “optimal” temperatures above these avoidance values and dramatically reduce the predicted area of impact of the thermal discharge. EPA and the other agency reviewers regard USGenNE’s approach as inappropriate.

2. In addition, USGenNE’s acclimation argument assumes that a fish will stay within the same immediate area of the bay for 7 days to allow for temperature acclimation to occur. Fish are mobile creatures and even the demersal species, which may not move much on an hourly scale, will move significantly within Mount Hope Bay on a weekly scale. Several members of the TAC viewed this as a highly unrealistic assumption and EPA agrees. Therefore, the effect of this assumption is that it in appropriately increases the “growth zone” of the USGenNE’s temperature polygon and as a result underestimates the effect of the thermal discharge.

3. Using the MRI field surveys from 1972 to the present to delineate areas used by fish in the bay should be recognized as an underestimate of actual habitat utilization, due to the fact that fish population numbers have been declining since 1972. As fish abundance declines, the extent of their habitat usage declines as well.

4. Temperature sensitivity varies dramatically from juvenile life stage to adults.MA0003654 Determinations Document July 22, 2002

6-36 USGenNE in their temperature polygons derive their regression lines using data from both adults and juveniles together. Under USGenNE’s approach, these two life stages should have been separated and regression lines done for each one individually. Temperature polygons for both life stages should have been developed by the permittee, because for most species they would have provided very different results. Generally, juvenile life stages tend to be less sensitive than adults. Therefore lumping the stages tends to overestimate habitat for adults.

5. USGenNE did not consider recent research in the construction of the reproduction portion of the winter flounder polygon. Keller and Klein-MacPhee (2000) showed through a mesocosm study that winter flounder egg hatching success was significantly affected by water temperature. Due to activity of predators, which is controlled by water temperature, egg mortality was greatly reduced in mesocosm tanks with water temperature of 5 o C. The permittee has cited this study to support the notion of increased predator activity as helping to cause the collapse of Mount Hope Bay winter flounder, but ignored the study for the purpose of construction of its polygons. Consideration of this study would reduce the habitat area available for reproduction in the winter flounder polygon. The net result is that impacts to winter flounder reproduction due to thermal discharge are underestimated.

6. USGenNE’s variance application presents a biothermal assessment for winter flounder eggs, juveniles and adults, but does not consider impacts to larval stages. Buckley et al. (1990) showed that cold water produced larger larvae in good condition as evidenced by high RNA content. Keller and Klein-MacPhee (2000) found using a mesocosm experiment that colder temperatures reduced predation on larvae and led to higher larval survival though metamorphosis to the young-of-the-year stage. By not considering larvae, USGenNE has done an incomplete thermal analysis of the impacts to winter flounder.

7. Figure 6.3-4 shows USGenNE’s assessment of the chronic mortality to juvenile winter flounder from the thermal discharge. EPA believes that chronic mortality has been underestimated, because of USGenNE’s acclimation assumptions and the use of a 7 day acclimation period.

The greatest point of disagreement with USGenNE on the biothermal assessments has been over the specific temperature thresholds. As a result, EPA contracted with Dr. Charles Coutant and Dr. Mark Bevelhimer of the Oak Ridge National Laboratory to conduct a literature review oftemperature thresholds for the RIS and some additional species covered by the MagnusonStevens Act. Based on this review report, and the TAC’s own review of the scientific literature, the most sensitive species for the pelagic and benthic layers for winter and summer were chosen by the TAC and EPA. In our literature review, EPA identified reasonable, yet protective,MA0003654 Determinations Document July 22, 2002

6-37 temperature values for the most sensitive life stage of the most sensitive species.

In selecting specific temperature thresholds, EPA took a reasonably conservative approach for several important reasons. These reasons are detailed below.

1. Dire condition of the fish stocks in Mount Hope Bay: The magnitude, scope and rapidity of this decline is virtually unprecedented. The restoration of fish stocks, in locations such as Georges Bank, has required dramatic reductions in fish mortality and extended recovery periods.

2. Long term water temperature rise: Keller et al. (1999), Sullivan et al.(2001) and Scherer (2002C) all document a long term rise in water temperatures in Narragansett Bay and Mount Hope Bay (although the absolute temperature of Mount Hope Bay is warmer) at almost identical rates of change. Keller et al. (1999) cite a rate of change of close to 2 o C over the last 40 years in Narragansett Bay. It is likely that any engineering solution that is devised and implemented for Brayton Point Station will be expected to have an operational life of at least 20 years. At the current rate of temperature increase, this would allow for background water temperatures to increase by 1.0 o C or more. If background water temperatures continue to increase, the analysis done here becomes less and less conservative.

3. Inability to predict trophic dynamic effects: Small changes in water temperature can have disproportionately large impacts due to changes in competitive balance between species. Keller et al. (1999) looked at the processes controlling phytoplankton blooms in a series of mesocosms. In mesocosm tanks held at 1 o C above the long term water temperature average, grazing rates of zooplankton and filtration rates of mussels were elevated to the point of eliminating the normal late winter/early spring phytoplankton bloom. In mesocosm tanks held at 1 o C below the long term water temperature average, grazing and filtering were reduced and normal phytoplankton blooms occurred.

A second study by Keller and Klein-MacPhee (2000) looked at the impact of elevated winter water temperature on larval winter flounder survival. Mesocosms were held at 1 o C above (warm) the long term water temperature average and at 2 o C below (cool) the long term water temperature average. Winter flounder egg survival, percent hatch, time to hatch and initial size were statistically significantly greater in cool systems. In addition mortality rates of winter flounder larvae were lower in cooler systems and statistically significantly related to the abundance of active predators. In cool systems, predators of winter flounder larvae tend to be less active allowing the winter flounder a window of time to outgrow their predators. This offset of time is not present in warmer (in this case by just 3 o C) systems and predators dramatically reduce winter flounder larval abundance. We are presently unable to predict or even identify allMA0003654 Determinations Document July 22, 2002

6-38 the trophic dynamic effects that may occur from temperature increases. However, the evidence clearly shows, in general, that winter flounder do better in cooler water temperatures.

EPA selected the warmest year (1999) in the dataset (1990-1999) to represent the ambient water temperatures. The TAC reviewed the scientific literature and selected the most sensitive species for the pelagic and benthic zones in both the winter and summer time frames. These critical temperatures were then compared to hydrothermal model outputs run at various operating conditions. The critical temperature values, with their supporting information, are listed below.

Benthic Layer, Summer time 24 o C : This value was selected based on data from the temperature preferences of juvenile winter flounder. As detailed earlier in this document (See discussion of “temperature acclimation”), several controlled studies document avoidance by winter flounder juveniles at this temperature. Field data collected by RI DEM corroborate these control studies and indicate that the avoidance response is not a gradual one, but a dramatic threshold. Data from Olla et al. (1969) suggest that sublethal effects occur at even lower temperatures around 22 o C. Grace Klein-MacPhee, a flounder expert at the University of Rhode Island, stated that sublethal effects begin at 20 o C (MA DEP, 2002). EPA selected 24 o C, because multiple studies show this is a critical threshold temperature for avoidance. EPA acknowledges that some behavioral changes and sublethal effects may occur at lower temperatures, but the scientific literature is not robust enough to confidently predict the ecological impact of these sublethal effects.

Benthic Layer, Winter time 5 o C : This value was selected based on winter flounder egg viability studies. Rogers (1976) found that eggs incubated at 3 o C resulted in 100% viability of eggs. At 5 o C, egg viability was reduced to 83.5 % and at 10 o C, egg viability was only 50%. Rogers (1976) found no viable eggs at 15 o C. Keller and KleinMacPhee (2000) found an over 90 % hatching rate at an average incubation temperature of 1.86 o C and an approximately 75% hatching rate at an average incubation temperature of 5.11 o C. EPA selected 5 o C as the winter time benthic layer threshold. Though this temperature is not the optimum for winter flounder egg hatching success, it is not possible to predict the ecological significance of the difference between 100% hatching success and 83.5% hatching success. At the same time, EPA believes that the 50% rate of egg viability at 10 o C would be likely to interfere with the recovery of the winter flounder population in Mount Hope Bay. Therefore EPA selected 5 o C as the critical temperature.
Pelagic Layer, Summer time 25 o C : This value was selected based on avoidance responses by sub-adult and adult striped bass. Coutant and Benson (1990) showed that striped bass avoided waters with temperatures above 25 o C.

Pelagic Layer, Winter time 8 o C : This value was selected based on temperature tolerances of larval winter flounder. Grace Klein-MacPhee recommended 8 o C as bestMA0003654 Determinations Document July 22, 2002

6-39 for larval survival and growth for the 3-4 weeks post-hatch (MA DEP, 2002). She stated that some larvae are capable of tolerating up to 12 o C, but their survival and growth is reduced. Given the depleted state of the winter flounder population in Mount Hope Bay, EPA believes the 8 o C temperature value should be used.

Using the information from additional hydrothermal model runs produced by USGenNE (October 1, 2001, Section 308 Response to EPA), EPA estimated the volume of the bay that would exceed these critical threshold temperatures and the duration of the exceedance for various thermal discharge scenarios.

Since daily mean temperature was modeled for this analysis, instantaneous temperatures will periodically exceed the specific 24-hour means shown in the analysis. Much thought has been given to the ecological significance of a 24 hour mean. Obviously, some biological responses, such as a fish’s decision to avoid an excessively warm area, occur on a much shorter time frame than 24 hours. On the other hand, for egg hatching success, a longer term average (> 24 hours) is probably more appropriate. Computing time and data presentation were also considerations. It is useful for the reader to keep in mind that for biological effects such as avoidance, this analysis may underestimate the effects, while impacts to egg hatching rates may be overestimated.

Benthic Layer, Summer : Table 6.3-2 depicts the results of the hydrothermal model runs done for the benthic layer in the summer. USGenNE’s proposal, the Enhanced Multi-Mode, would exceed the juvenile winter flounder avoidance temperature (24 o C) for 62% of the bottom water by volume for some time period equal to or greater than 5 days (out of 30 days). An additional 18% of the bottom water would experience avoidance temperatures for varying periods of time less than 5 days, but greater than zero, while only 20% of the bay bottom water would never get to 24 o C. Thus, with the Enhanced Multi-Mode, over half the bottom water of the bay would be avoided by juvenile winter flounder for greater than 5 days (out of 30 days) and 80% of the bay would experience some level of impairment. Hypothetical A, which represents the lowest thermal load of any of the model runs, resulted in 36% of the bottom water volume exceeding 24 o C for 5 days or more and an additional 22% experiencing some degradation for a duration less than 5 days, but more than zero. Under this alternative 42% of the bottom waters would never reach 24 o C. During the warm summer, all of the modeled scenarios represent significant degradation to juvenile winter flounder in Mount Hope Bay as a result of habitat alteration by Brayton Point Station’s thermal discharge.MA0003654 Determinations Document July 22, 2002

6-40 Table 6.3-2: Percent of Bottom Water Volume Less Than, Equal to or Greater Than a

Daily Mean Temperature of 24 o C in Warm Summer Conditions
Scenario % Volume < 24 o C % Volume > 24 o C 1 to 4 days % Volume > 24 o C

> 5 days

MOA II 1 14 11 75

EMM 2 20 18 62
Hypo B 3 32 13 55 Hypo A 4 42 22 36

No Plant 70 26 4

1 1,043 MGD and 3.7 TBTU

2 750 MGD and 2.25 TBTU

3 750 MGD and 1.8 TBTU

4 750 MGD and 1.2 TBTU

Pelagic Layer Summer : Tables 6.3-3 and 6.3-4 present the percentage of surface water volume and middle water volume that exceed the adult striped bass avoidance temperature of 25 o C. The Enhanced Multi-Mode option exceeds 25 o C in 41% of the surface water volume for 5 days or more. An additional 29% of the surface water volume will experience some level of degradation less than 5 days in duration, but greater than zero. Thirty percent of the surface water volume of the bay would not exceed 25 o C. For Hypothetical A, only 5% of the surface water volume exceeded 25 o C, with an additional 19% experiencing degradation for a duration of less than 5 days, but for varying periods of time greater than zero. Seventy six percent of the surface water volume never exceeded 25 o C. For the middle water volume, the Enhanced Multi-Mode would exceed 25° C for greater than 5 days in 18% of the bay. An additional 17% of the middle water volume would experience some level of degradation less 5 days in duration, but greater than zero. Sixty five percent of the middle water volume would not exceed 25 o C . For Hypothetical A, less than 1% of the middle water volume exceeded 25 o C for 5 days or greater. Approximately 3% of the middle water volume experienced degradation of a duration less than 5 days and 96% of the middle water volume never exceeded 25 o C. Due to the small area of impact in the surface and middle waters, EPA finds Hypothetical A to represent an acceptable area of impact.MA0003654 Determinations Document July 22, 2002

6-41 Table 6.3-3: Percent of Surface Water Volume Less Than, Equal to or Greater Than

Daily Mean Temperature of 25 o C
Scenario % Volume < 25 o C % Volume > 25 o C 1 to 4 days % Volume > 25 o C

> 5 days

MOA II 1 7 17 76

EMM 2 30 29 41
Hypo B 3 53 16 21 Hypo A 4 76 19 5

No Plant 98 2 0

1 1,043 MGD and 3.7 TBTU

2 750 MGD and 2.25 TBTU

3 750 MGD and 1.8 TBTU

4 750 MGD and 1.2 TBTU

Table 6.3-4: Percent of Middle Water Volume Less Than, Equal to or Greater Than a

Daily Mean Temperature of 25 o C in Warm Summer Conditions
Scenario % Volume < 25 o C % Volume > 25 o C 1 to 4 days % Volume > 25 o C

> 5 days

MOA II 1 36 24 40

EMM 2 65 17 18
Hypo B 3 77 14 9 Hypo A 4 96 3+ < 1

No Plant 100 0 0

1 1,043 MGD and 3.7 TBTU

2 750 MGD and 2.25 TBTU

3 750 MGD and 1.8 TBTU

4 750 MGD and 1.2 TBTU

Benthic Layer Winter : During warm winter conditions, essentially 100% of the volume of the bottom water exceeds the critical temperature of 5 o C under all modeling scenarios. Ninety percent of the bay exceeded 5 o C for five days or more with the No Plant scenario (Table 6.3-5). Thus, background conditions represent some level of degradation for winter flounder egg hatching rates under warm winter conditions. This is consistent with work done by Jeffries and Johnson (1974) that correlated winter water temperature with winter flounder abundance. TheyMA0003654 Determinations Document July 22, 2002

6-42 showed that years with cold winters were years of good recruitment to the stock. Additional modeling that could be performed would be to look at the frequency of the 5 o C being exceeded in conditions other than the warm winter. There are a range of baseline conditions from the coldest to warmest winter in the last 10 years. The appropriate modeling question is, how many of those winters exceed the 5 o C threshold with each different operating scenario. The winter operating conditions (2.375 TBTU) for the Enhanced Multi-Mode option increase the heat load over its summer output (2.25 TBTU). Thus, the Enhanced Multi-Mode option is putting out approximately twice as much heat as Hypothetical A (1.2 TBTU) in the winter, assuming both have a flow of 600 MGD. With its greater heat flux and greater ) T, one would expect that the Enhanced Multi-Mode option would exceed the 5 o C threshold with more regularity than Hypothetical A. None of the operating scenarios exceeded 10 o C anywhere in the bay. While the warm winter condition will presumably not occur every year; these conditions are reasonable to use, because they are based on actual data and with long term temperature increase, they can be expected to occur more frequently.

Table 6.3-5: Percent of Bottom Water Less Than, Equal to or Greater Than a Daily

Mean Temperature of 5 o C in Warm Winter Conditions
Scenario % of volume < 5 o C % Volume > 5 o C 1 to 4 days % Volume > 5 o C

> 5 days

MOA II 1 0 0 100

EMM 2 0 0 100
Hypo B 3 0 0 100 Hypo A 4 0 0 100

No Plant 0 10 90

1 925 MGD and 4.1 TBTU

2 600 MGD and 2.375 TBTU

3 600 MGD and 1.8 TBTU

4 600 MGD and 1.2 TBTU

Pelagic Layer Winter : The Enhanced Multi-Mode shows only a small amount of degradation of surface water volume, with less than 10% of the bay exceeding 8 o C (Table 6.3-6). For all other scenarios, essentially 100% of the surface water volume does not exceed 8 o C. For all operating scenarios, virtually 100% of the middle water volume remains below 8 o C (Table 6.3- 7). All operating scenarios represent an acceptable amount of thermal degradation.MA0003654 Determinations Document July 22, 2002

6-43 Table 6.3-6: Percentage of Surface Water Less Than, Equal to or Greater Than a Daily

Mean Temperature of 8 o C in Warm Winter Conditions
Scenario % of volume < 8 o C % Volume > 8 o C 1 to 4 days % Volume > 8 o C

> 5 days

MOA II 1 81 18 1

EMM 2 91 9 0
Hypo B 3 99 1 0 Hypo A 4 100 0 0

No Plant 100 0 0

1 925 MGD and 4.1 TBTU

2 600 MGD and 2.375 TBTU

3 600 MGD and 1.8 TBTU

4 600 MGD and 1.2 TBTU

Table 6.3-7: Percentage of Middle Water Less Than, Equal to or Greater Than a Daily

Mean Temperature of 8 o C in Warm Winter Conditions
Scenario % of volume < 8 o C % Volume > 8 o C 1 to 4 days % Volume > 8 o C

> 5 days

MOA II 1 91 8 1

EMM 2 98 2 0
Hypo B 3 100 0 0 Hypo A 4 100 0 0

No Plant 100 0 0

1 925 MGD and 4.1 TBTU

2 600 MGD and 2.375 TBTU

3 600 MGD and 1.8 TBTU

4 600 MGD and 1.2 TBTU

(C) Other Heat Effects on Fish

USGenNE’s thermal analysis focused solely on the impact of heat as a deterrent, but did not speak to the impact of heat as an attractant. It has been well established that the thermal plume from Brayton Point Station has served as a thermal attractant for large numbers of striped bass and bluefish in the fall and winter. The normal migration of these species has been disrupted byMA0003654 Determinations Document July 22, 2002

6-44 their attraction to the plume. Thousands of these fish crowd into the thermal plume and discharge canal to overwinter. This represents an unhealthy situation for the fish as they become much more prone to disease. Instead of slowing their metabolism and overwintering in a condition similar to hibernation, these fish, due to the water temperature, maintain a high metabolic rate. In addition, there is a very limited food supply for these fish overwintering in the thermal discharge. Thus if they persist, they end up in a greatly weakened physical condition. Placing large numbers of fish in a small area with elevated water temperatures and weakened physical condition makes them especially prone to the transmission of disease, such as lymphocystis. Lymphocystis is commonly found in fish residing in thermal plumes, is highly contagious and frequently fatal. This disease has been observed in striped bass taken from the discharge canal in the past, though the relative prevalence of the disease was not measured, but estimated to be present in 30-50% of the fish (DeHart, 1997). USGenNE ignores this issue and lists striped bass as residing in the bay only for half of the year in their biothermal assessment.

A second phenomenon that may fall into the category of attractant is the appearance in Mount Hope Bay of the smallmouth flounder, Etropus microstomus . The documented range of smallmouth flounder is from Florida to southern New England (Able and Fahay, 1998). In general, an organism is less common on either end of its latitudinal distribution as it is generally transitioning into environments that may be competitively less favorable to it. When an organism becomes more common on the edges of its latitudinal distribution, this signals some environmental change in the system. Smallmouth flounder have become more common in Narragansett Bay and Mount Hope Bay (Scherer, 2002D). Grace Klein-MacPhee (2002) theorizes that the increase in smallmouth flounder has been due to possibly one of two things:

1. The long-term warming of Narragansett Bay and Mount Hope Bay shifting the competitive balance more in favor of smallmouth flounder; or

2. The smallmouth flounder exploiting an empty ecological niche left after the dramatic collapse of fish stocks in Mount Hope Bay.

If the long-term warming of Narragansett Bay and Mount Hope Bay has resulted in a competitive shift, the operation of Brayton Point Station has only accelerated and/or exacerbated this condition. If the increase in the smallmouth flounder is due to an empty niche left after the collapse of fish stocks in Mount Hope Bay, Brayton Point Station is still complicit as EPA believes that Brayton Point Station’s operations contributed to this collapse and are precluding recovery. Shifts to warmer water species does not satisfy the requirement of a balanced indigenous population.

A third example of potential thermal attraction is the recent large fish impingement events this past February (Ketschke, 2002). In 2 separate events, over 35,000 juvenile Atlantic menhaden were impinged on the intake screens of Units 1, 2 and 3. Atlantic menhaden make seasonal migrations in the spring and fall that reportedly coincide with the position of the 10 o C isothermMA0003654 Determinations Document July 22, 2002

6-45 (Able and Fahay, 1998). Brayton Point’s thermal discharge raises the temperature of Mount Hope Bay in relation to neighboring Narragansett Bay. Thus, the thermal discharge likely contributed to the delay in migration of these fish. In addition, as baywide water temperatures cooled into the winter, these fish became trapped and concentrated in the warmest part of the bay, Brayton Point Station’s thermal plume. The presence of the thermal plume affected their relative distribution within the bay during the winter. Fish were pulled closer to the plant by their attraction to the thermal plume, making them more susceptible to impingement. This recent event is not the first large winter impingement event, as another occurred as recently as December of 1999 of 4,000 fish consisting primarily of 6 species (Ketschke, 2000).

Finally, MRI reports that 80% of all winter flounder in the trawl surveys are caught at one station, this is the station in front of the cooling water intake structure. This station is dredged periodically and as a result is one of the deepest points in the bay. Due to its water depth, it also is the coolest water temperature in the bay. Winter flounder are reported to have a wide water depth range (Gray, 1991), thus another factor must be restricting them to a very narrow depth profile in Mount Hope Bay. The deeper water is the only location where the adult winter flounder can find refuge from the warm water temperatures.

6.3.3f Other Vertebrate Wildlife

EPA finds Mount Hope Bay to be an area of low potential impact for vertebrate wildlife. Discussions with National Marine Fisheries Service and Bob Kenny of the University of Rhode Island suggest that Mount Hope Bay is not a significant habitat for marine mammals or sea turtles. Thus, there is no potential for any significant impact to marine mammals or sea turtles from any of the alternatives being considered.

6.3.4 Summary of Thermal Effects

Mount Hope Bay is a system that has experienced and is experiencing numerous thermally related impacts and changes. Some of the more obvious ones, for which there appears to be no disagreement, include:

* Absence of the normal winter-spring phytoplankton bloom;

* Appearance of nuisance algal blooms;

* Overwintering of the ctenophore Mnemiopsis leidyi ;
* Overwintering of striped bass and bluefish in discharge canal;

* Increased abundance of smallmouth flounder in the bay;MA0003654 Determinations Document July 22, 2002

6-46 *Multiple large fish kills as a result of large impingement events in the winter; and

*Thermal avoidance of most of the bay by adult winter flounder.

Brayton Point Station’s current thermal discharge exerts a massive impact on the thermal conditions in the bay dramatically altering what would be the natural thermal regime. USGenNE’s proposed Enhanced Multi-Mode system will not reduce the plant’s thermal discharge into the bay sufficiently to relieve any of the above listed thermal impacts or changes. In addition, impacts predicted for the Enhanced Multi-Mode include:

* Large areas of the bay being avoided by juvenile winter flounder and striped bass during warm summer conditions;

* Extensive areas of the bay experiencing water temperatures resulting in chronic toxicity to juvenile winter flounder;

* Reduced winter flounder egg hatching success for the entire bay for the warmest winter conditions. Of the control options considered, the Enhanced Multi-Mode Option would have the greatest extent of impact, although this has not yet been quantified;

* Increased predation on winter flounder eggs and larvae by sand shrimp; and

* Potential exclusion of eelgrass.

6.3.5 Cumulative Impact Assessment

According to CWA §316(a) and 40 CFR §125.73 (a) and (c), to determine whether the protection and propagation of the balanced indigenous community is being achieved, EPA must consider, not only thermal impacts, but impacts from other stressors as well. Each species is subjected to a wide variety of stressors or sources of mortality (Figure 6.3-5 ). Therefore, the future operation of this facility, in conjunction with the other sources of mortality, must ultimately still allow the existence of a balanced indigenous community.

The cause or causes of the dramatic decline of fish stocks in Mount Hope Bay has been the subject of substantial debate. USGenNE has pointed to a wide variety of stressors on fish populations, winter flounder in particular, as potential explanations for the steep decline in fish abundance since 1985 (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, p. 43). These stressors can be classified as natural (predation by fish, birds, etc.) or anthropogenic (overfishing, entrainment, impingement, etc.). Each population will increase or decline based on the cumulative mortality rate, comprised of both natural and anthropogenic factors. The goal of this permit is to allow the fish populations in Mount Hope Bay the chance to recover. Thus the cumulative mortality rate must result in a positive population trajectory. The greater the naturalMA0003654 Determinations Document July 22, 2002

6-47 mortality rates, the smaller the anthropogenic mortality rates must be to allow for a recovery.

USGenNE particularly focuses on overfishing as the dominant stressor. Without denying that overfishing has also been an important stressor, EPA believes that entrainment, impingement and thermal effects resulting from plant operations are additional critical stressors on fish populations in Mount Hope Bay. Extensive efforts have been made by both the State of Rhode Island (Gibson, 2001) and the Commonwealth of Massachusetts (Lawton, 2001) to restrict fishing mortality in Mount Hope Bay and elsewhere. In addition, the federal government has continued to reduce fishing mortality on groundfish stocks (winter flounder included) by implementing closure areas, restricting days at sea, requiring nets with larger mesh and buying back fishing licenses.

In an effort to discern what effect alternative improved control technologies might have on fish population recoveries, a winter flounder population modeling effort was undertaken by USGenNE at the request, and with the assistance, of the Brayton Point TAC. RAMAS GIS/metapopulation software, utilizing a Leslie matrix, was chosen to simulate winter flounder population changes in response to different control technology/plant operating scenarios. This model incorporated direct losses of winter flounder due to fishing, impingement and entrainment. A separate habitat exclusion model was also developed to try to examine habitat suitability and the results of this model were then fed into the Leslie matrix. Despite this integrated approach, limitations of the analysis were acknowledged at the outset. For example, the approach to habitat suitability was fairly crude, with no ability to consider the interactive effects of various water quality parameters, such as dissolved oxygen. From the beginning of this modeling work, the regulatory agencies agreed that before the model could be considered validated it would, at a minimum, need to be able to replicate past winter flounder population changes.

At present, despite extensive efforts by USGenNE and its consultants, EPA’s consultants (Stratus Consulting), and members of the TAC, the model has not been validated to the satisfaction of EPA or the TAC. The model has been unable to replicate the past winter flounder population changes adequately and, therefore, EPA and the TAC cannot have confidence in any future projections that the model might produce. Two areas, in particular, are of concern to EPA and the TAC: (a) the period from the mid- to late-1970s; and (b) the period from 1996 to the present. In the 1970s, actual abundance data shows multiple swings, up and down, that are not accurately reflected by the model results. Additionally, the model shows a significant recovery of winter flounder in Mount Hope Bay in the late 1990s, but that has not been indicated by the actual trawl data (Figure 6.3-6). Considering all of the above, EPA has concluded that the model cannot be relied upon to produce fair predictions of future winter flounder population numbers under various control regimes. EPA expects that USGenNE, EPA and members of the TAC will continue with efforts to refine the model in hopes of eventually producing a validated predictive model for winter flounder in Mount Hope Bay. It should be noted that by citing the problems with the RAMAS model, EPA in no way intends to criticize the efforts of USGenNE,MA0003654 Determinations Document July 22, 2002

6-48 in this regard. Modeling complex biological systems is a developing area of scientific work that has a long way to go before it will become an easily available and reliable tool for natural resource managers. The number of interacting variables at work in a large natural ecosystem make the task of modeling population fluctuations, of even one species, which is all that was attempted in this case, especially daunting. Therefore, EPA relied on the scientific literature on temperature sensitivities, field data provided by Rhode Island DEM and information submitted by USGenNE.

Outlined below are brief analyses of other sources of mortality to fish in Mount Hope Bay.

6.3.5a Overfishing

EPA recognizes that fish populations are adversely effected by multiple stressors and that direct harvesting or fishing is an important one. However, EPA does not believe that overfishing is the sole significant stressor that has caused the decline of fish populations in Mount Hope Bay.

There is no question that excessive long-term harvesting of fish stocks has occurred for many species in New England waters. Most coastal populations of commercial fish stocks are currently classified as fully exploited or overexploited by the National Marine Fisheries Service (NMFS, 1999). As a result, however, fishing restrictions have been imposed by NMFS on many commercial fish in New England. In Mount Hope Bay, both Massachusetts and Rhode Island have virtually eliminated all commercial and most recreational fishing through regulation (Gibson, 2001, Lawton, 2001).

The permittee suggests that overfishing is the primary cause for the collapse of fish stocks in Mount Hope Bay: “USGenNE believes it can demonstrate that the Station’s historic impacts on the fish population are negligible in relation to the fishing pressure and it is entitled to a [§ 316(a)] variance for that reason alone.” (USGenNE May 2001 Variance Request Application and Partial Demonstration Document under the Clean Water Act Section 316(a) and (b)). After review of USGenNE’s arguments, EPA is not persuaded. Stated below are several reasons that EPA does not accept the permittee’s argument that overfishing is the sole significant stressor on fish stocks in Mount Hope Bay, or that the operation of the BPS CWISs is not one of the significant stressors on these stocks, contributing to their serious decline.

1. Length distribution of winter flounder and windowpane : The classic response of a fish stock to overfishing is a truncating of the size frequency distribution, with the larger adult fish decreasing first, because they are subject to the most intense direct fishing pressure. Small and intermediate size fish decline later after the spawning biomass of the stock and recruitment begins to fail. Figure 6.3-7 and Figure 6.3-8 show the size distribution of winter flounder and windowpane in the mid 1970s prior to the collapse. All size classes are represented. Figure 6.3- 9,and Figure 6.3-10 represent the length frequency distribution of winter flounder and windowpane during the fish decline. Figure 6.3-11 and Figure 6.3-12 show the lengthMA0003654 Determinations Document July 22, 2002

6-49 frequency of windowpane and winter flounder after the decline. The small and intermediate sized fish are almost completely eliminated, leaving only the adults. This is the opposite of what a stock length distribution curve looks like if it is overfished. Finally, Figure 6.3-13 shows the size distribution of fish in Narragansett Bay during the time of the decline in Mount Hope Bay. Comparatively, the Narragansett Bay population shows a very different size structure distribution than the stock in Mount Hope Bay, with fish of all size ranges present in the Narragansett Bay population. The sudden and near complete loss of small and intermediate sized fish in Mount Hope Bay is completely contrary to a decline facilitated principally by overfishing which would target the larger adult fish in the population. Brayton Point Station’s operations have greater effects on the egg, larval and juvenile life stages than the adult stage due
to:

1. Greater susceptibility of subadult lifestages to entrainment and impingement than

adults; and 2. Longer residence time of subadult lifestages in the bay than adult winter flounder.

Thus, impacts associated with Brayton Point Station operation would likely be reflected initially in the smaller size winter flounder and windowpane.

2. Rapidity of decline : Units 1, 2 and 3 began operations in the 1960's, and fishery data suggests declining populations in Mount Hope Bay beginning from 1972 when data collection began. While aggregate fish abundance in Mount Hope Bay was already declining, it dropped dramatically in a 1 year time period between 1985-86. Fish abundance profiles of overexploited areas, such as George’s Bank, do not show such rapid declines (Fogarty and Murawski, 1998). There was also no corresponding increase in fishing rates that would explain such a sudden shift in aggregate fish abundance (Reitsma, 2001). Yet, Brayton Point Station’s thermal discharge and cooling water intake volume increased significantly in July 1984.

3. Multiple species affected : Sixteen of the twenty finfish species in Mount Hope Bay show a similar rate of decline, with a dramatic drop-off in 1985. It is highly unlikely, that sixteen different fish species (which include both pelagic and demersal species) would all decline at the same rate due solely to fishing pressure. For the population trajectories to be identical in all 16 species, the interaction between multiple complicated natural processes (i.e., reproduction, recruitment, predation, etc.) and harvesting rates would need to yield an equivalent result for each species. Impacts from fishing are generally focused on the target species (though there is no question that mortality as a result of bycatch occurs), while the impacts from Brayton Point Station’s operations are indiscriminate.

4. Species replacement : On George’s Bank, overexploitation of target species (groundfish) left their populations at extremely low levels. As a result, other species (primarily skates and dogfish) filled the ecological niche left from the reduction of groundfish (NMFS,MA0003654 Determinations Document July 22, 2002

6 It should also be noted that the tightened thermal discharge and cooling water intake requirements imposed on BPS in MOA II, see above discussion of permitting history, have not resulted in a recovery of the Mount Hope Bay fishery (MRI, 2001). This is not surprising to the regulatory agencies as the limitations in MOA II were the result of a compromise with NEPCO, the previous plant owner and permittee, and were merely an interim step designed to limit or reduce impacts while further study was undertaken to support the development of long-term requirements for a new permit.

6-50 1995; Sherman, 1994). Biomass or aggregate resource abundance did not decline, even under the heaviest exploitation rates. In Mount Hope Bay, however, commercially important species declined, with no apparent subsequent replacement by other species and as a result, a dramatic decline in aggregate resource abundance was experienced (Gibson, 1996). Neighboring Narragansett Bay did experience species replacement, with striped bass, scup, butterfish and sea herring increasing (Gibson, 1996). However, while populations of these four species increased in Narragansett Bay, they continued to decline in Mount Hope Bay (Gibson, 1996).

5. Regional Impacts : Overfishing is a regional phenomenon which would not affect just one embayment. Additionally, it is highly unlikely that overfishing of 16 species would reach a critical point at the same time in one embayment resulting in a dramatic decline in resource abundance. Furthermore, similar shallow water embayments like nearby Greenwich Bay and the estuarine portion of the Providence River have significantly greater fish abundance than Mount Hope Bay and the fishing restrictions for Mount Hope Bay are equivalent if not more stringent than restrictions for those two water bodies.

6. Absence of a recovery : In other systems where overfishing has been the suspected cause of resource decline, reducing harvesting rates has led to a recovery in the resource. Fishing for winter flounder and other species has been severely restricted in both the Massachusetts and Rhode Island segments of Mount Hope Bay. Moreover, exploitation rates of winter flounder have been significantly reduced in Rhode Island waters and region-wide and modest recoveries have been noted in Narragansett Bay and southeastern New England, but no comparable recovery has occurred in Mount Hope Bay (Lynch, 2000; Gibson, 2001). 6 One could make the analogy that Brayton Point Station is a major harvester of fish, fish eggs and larvae and that while commercial and recreational fishing rates have been cut dramatically in recent years (Gibson 2001, Lawton, 2001), the “harvesting” by Brayton Point has increased over the years due to increased cooling water flow and heat rejection from the plant. Link (2002) suggests that there is strong evidence that predation may be a leading factor in limiting or eliminating fish stock recovery, in populations that are severely depressed. The continued harvesting of large quantities of fish eggs and larvae by Brayton Point could serve to limit strong year class recruitment that could fuel a stock recovery.

7. Timing of decline : The only stressor that showed a significant change proximate toMA0003654 Determinations Document July 22, 2002

6-51 the time of the significant decline in the mid 1980s is the change in operation at Brayton Point Station (Figure 2.6-2). Fishing induced mortality did not increase significantly for at least winter flounder in the mid 1980s (Gibson, 2001).

6.3.5b Predators

USGenNE has suggested that perhaps predators have triggered the collapse of fish stocks in Mount Hope Bay. These possible predators include cormorants, green crabs, ctenophores, sand shrimp and a suite of other organisms. Link (2002), in a paper on ecological considerations in fisheries management, states “there is little evidence that predation causes large, persistent stock declines.”

Cormorants : Cormorants are piscivorous birds and have been implicated in finfish declines in other areas (Link, 2002). It is extremely unlikely, however, that cormorants were responsible for the dramatic decline in Mount Hope Bay in the mid 1980s for several reasons:

1. At the time of the fish collapse in Mount Hope Bay, the only nesting cormorants present in Rhode Island were on Sakonnet Point (Meredith Simas, USGenNE to Todd Callaghan, MA CZM, 3/21/02). The Sakonnet Point nesting site is approximately 15 miles away from Mount Hope Bay. There is plenty of nearshore shallow water habitat along Sakonnet Point, so it is unlikely that the cormorants would fly 15 miles to feed in Mount Hope Bay, when they can feed in the general vicinity of their nests;

2. At the time of the finfish collapse in Mount Hope Bay, cormorant abundance was at a third of the level it is today. It is unlikely that the 3,000 cormorants (Meredith Simas, USGenNE to Todd Callaghan, MA CZM, 3/21/02) in Rhode Island at the time could have consumed sufficient numbers of fish to trigger the collapse of multiple species in Mount Hope Bay;

3. Other areas of Rhode Island waters have not collapsed to near zero abundance levels despite the continued increase of cormorants to over 11,000 statewide by 1997 (Meredith Simas, USGenNE to Todd Callaghan, MA CZM, 3/21/02);

4. Survival rates of young-of-the-year winter flounder have varied without obvious trend since 1986 (Reitsma, 2002). If cormorants were responsible for the collapse in fish stocks, survival rates of young-of-the-year winter flounder would decline as cormorant abundance increased; and

5. Stomach content analysis, conducted by Rhode Island Division of Fish and Wildlife on 67 cormorants, sampled from Hope Island and Sakonnet Point,MA0003654 Determinations Document July 22, 2002

6-52 showed that winter flounder comprised only 8.7% of the total contents (Reitsma, 2002).

Green crabs : Green crabs are found predominantly in the intertidal and shallow subtidal zones. They prefer rock and other structure and are rarely found on bare sand substrate where large numbers of juvenile winter flounder reside. There is very limited overlap between green crab’s preferred habitat and that of juvenile winter flounder. This suggests that green crabs are relatively insignificant predators on winter flounder.

Ctenophores : A more detailed discussion on ctenophores is found in the Zooplankton section of this document. In brief, the timing of ctenophore blooms has changed over historical norms. This is generally believed to be a result of changes in water temperature (Sullivan et al., 2001). Brayton Point Station has significant impact on water temperatures in Mount Hope Bay, where the ctenophores overwintered. Direct predation on winter flounder eggs or larvae by this ctenophore is unlikely, but they may become an additional competitor with larval fish for zooplankton prey. Therefore, if increased abundance of ctenophores has resulted in increased mortality rates of winter flounder larvae, Brayton Point Station is indirectly responsible, as its thermal discharge has contributed to changing temperature conditions in Mount Hope Bay.

Sand shrimp : Winter flounder spawn in the late winter to early spring, when water temperatures are generally cold. This provides winter flounder an “escape in time” from benthic predators that are more active in warmer water temperatures. Sand shrimp, Crangon septemspinosa , are one of these important benthic predators. Keller and MacPhee (2000) conducted a mesocosm study examining winter flounder egg and larval survival as a function of winter water temperatures. Winter flounder egg and larval mortality rates were statistically lower in the cool mesocosm tanks. A change in water temperature of just 2 degrees was enough to affect predator activity, hence egg and larvae survival. David Taylor at the University of Rhode Island has shown that Crangon will prey on winter flounder in the field in the winter, so their predation is not simply limited to enclosure studies (Haas, 2002). Similar to ctenophores, increased predation by sand shrimp may be a temperature mediated phenomenon that Brayton Point Station is contributing to significantly.

In addition, it should be noted that USGenNE has suggested these predators as triggering the collapse of the winter flounder population. Tautog, windowpane and hogchoker have different natural history characteristics than winter flounder and thus may have a different suite of predators. USGenNE has not addressed predation on these other species.MA0003654 Determinations Document July 22, 2002

6-53 6.3.5c Water Quality

USGenNE has suggested that poor water quality (specifically high levels of nutrients) has caused the decline of fish stocks in Mount Hope Bay (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I Appendix C, p. 4). Excess nutrient loading in marine systems, primarily nitrogen, stimulates phytoplankton growth, which results in increased organic loading to the system. The organic material is broken down by respiration, which requires oxygen. Areas of high organic loading frequently have low dissolved oxygen concentrations in the water column as a result. Low dissolved oxygen can certainly trigger avoidance and in extreme cases mortality in marine organisms (EPA, 2000). Historically, Mount Hope Bay has experienced periods of extremely low dissolved oxygen (Isaac, 1997). These tend to occur in the warmest time of the year (summer). The spatial extent of the low dissolved oxygen and the frequency of its occurrence are not very well defined. Long term average dissolved oxygen data collected at a limited number of stations shows that May through October dissolved oxygen concentrationsin the bottom waters are lower near the point of the thermal discharge compared to a point midbay near Spar Island (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, p. A190, A-214).

Recent data collected in June and July of 2001 in Mount Hope Bay by Massachusetts Coastal Zone Management (MCZM) show periodic excursions of dissolved oxygen in the bottom water to as low as 2 mg/l for several hours at a time (Rountree et al, 2002).

Temperature affects dissolved oxygen through several mechanisms detailed below:

2. The solubility of oxygen in water decreases as water temperature increases;

2. Photosynthetic rates in phytoplankton are increased with temperature, thus potentially increasing the mass flux of organic material to the benthos; and

3. Respiration rates of organic material is increased with temperature. Respiration is a degradative process of organic material that utilizes oxygen.

Thus, the addition of heat by Brayton Point Station, to a nutrient rich embayment such as Mount Hope Bay, exacerbates any ongoing water quality problems. However, EPA does not believe that low dissolved oxygen was the primary cause of the fish collapse in Mount Hope Bay, for the following reasons:

1. Time of year : Adult winter flounder come into Mount Hope Bay in the winter and early spring to spawn. Dissolved oxygen concentrations are typically at their highest at this time of year. Thus, it is unlikely that low dissolved oxygen triggered avoidance or mortality at this time of year. Thus, the collapse of winter flounder in the mid 1980s cannot be explained by the effects of dissolved oxygen directly; andMA0003654 Determinations Document July 22, 2002

6-54 2. Health of the benthic community : The benthic infaunal community is often used as an indicator of water quality and stress from organic loading, due to its limited mobility and it’s general exposure to the lowest dissolved oxygen concentrations in the water column. The EPA laboratory in Narragansett, as part of a coastal eutrophication study, examined the benthic community from several coastal locations in New England. They observed numerous sample sites in Mount Hope Bay proper and in the lower Taunton River. They did not detect any evidence of extended anoxia or hypoxia. Large areas of the bottom consisted of tube building amphipods, which are considered high quality habitat for juvenile winter flounder (Franz and Tanacredi, 1992). Thus, based on this data, it seems unlikely that water quality, and dissolved oxygen in particular, is the sole or principal cause of the collapse in fish stocks.

6.3.5d Brown Tides

USGenNE has suggested that “brown tides” may have caused the dramatic finfish decline in the mid 1980s (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Appendix C, p. 5). Brown tides are a kind of nuisance algal bloom that in some areas like Peconic Bay have become persistent events. The great quantity of algal cells that comprise these blooms reduce light penetration and thus displace submerged aquatic vegetation. In addition, the cells can clog gills in fish and filter feeding invertebrates leading to their demise. There was a report of a brown tide in Narragansett Bay in the mid-1980s, but there have not been any significant blooms documented since that time (Deacutis, 2002B). Thus, EPA does not believe that brown tides caused the major decline or continued low abundance of fish in Mount Hope Bay.

6.3.5e Entrainment and Impingement

For the complete analysis, please refer to the Section 316(b) portion of this document. Briefly, Brayton Point Station entrains trillions of fish eggs and larvae and impinges tens of thousands of fish from Mount Hope Bay every year (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p F-26, F-27, F-36). These losses represent a substantial percentage of the total population for winter flounder (and likely tautog, windowpane and hogchoker) in Mount Hope Bay.

In summary, in addition to thermal impacts, EPA has considered overfishing, predation, water quality and entrainment and impingement as other sources of fish mortality in Mount Hope Bay. It is unlikely that any of these other sources of mortality, alone, can explain the collapse and lack of recovery of fish populations in Mount Hope Bay. However, these forces in conjunction with the plant’s addition of heat to Mount Hope Bay may be exacerbating fish mortality due to poor water quality and increased predation.MA0003654 Determinations Document July 22, 2002

6-55 6.4 Decision on USGenNE’s Variance Application and Proposed “Alternative Effluent Limitations”

6.4.1 Determination of a Balanced Indigenous Community

USGenNE has suggested that the finfish community has become more balanced through time (December 2001 USGenNE 316(a) and (b) Demonstration, Appendix C, p. 26). USGenNE defines “balanced” as a measure of the distribution of numbers of individuals per each species. Thus, a community that is numerically dominated by 1 or 2 species, would appear more balanced with the decline of the numerical dominants. Several members of the TAC were especially critical of USGenNE’s analysis of finfish diversity (See Appendix A). USGenNE’s analysis negatively biased the diversity index for the samples from the 1972-1986 time frame. Artificially limiting the sample number to 50 fish, out of a sample total much greater than that, in the samples from 1972-1986 reduces the number of species present. This bias was not present in samples after 1986, when only 50 fish were being caught in all of the trawls combined.

The most troubling trend in Mount Hope Bay is the dramatic loss of total finfish abundance and biomass. A greater than 80% reduction in abundance of the nekton community will have a significant impact on other components of the ecosystem as well. Reduction of the nekton community may partially explain the increase in the temporal abundance of the comb jelly, Mnemiopsis leidyi (This may also be partially explained by the increased water temperature in Mount Hope Bay). Even in areas of dramatic overfishing, the aggregate nekton abundance remained constant (Fogarty and Murawski, 1998). It is rare that an entire ecological community is virtually eliminated.

Within the nekton community, 16 of 21 species in Mount Hope Bay have significantly declined with time. Winter flounder, windowpane, tautog and hogchoker continue to persist at extremely low levels in Mount Hope Bay. In Mount Hope Bay, winter flounder and tautog are “commercially extinct” and are likely “ecologically extinct” as well. Thus, their abundances are so low that their populations are no longer filling their ecological niche. It has been theorized that this is one factor that may be contributing to the increase in abundance in the smallmouth flounder (Klein-MacPhee, 2002). EPA does not believe that a balanced indigenous community currently exists in Mount Hope Bay. This is further indicated by the increased prevalence of thermotolerant species, such as ctenophores and fish normally found in warmer waters, such as smallmouth flounder. The increased presence of these species and the absence of the historically dominant species indicates that the balanced indigenous population has not been protected.MA0003654 Determinations Document July 22, 2002

6-56 6.4.2 EPA’s Decision on USGenNE’s § 316(a) Variance Application

In order to receive a § 316(a) variance from water quality and technology standards, an applicant must demonstrate that its thermal discharge will not interfere with the protection and propagation of a balanced indigenous community within the receiving water. Applicants can do this in one of two fashions: they can submit a retrospective analysis or a prospective analysis. A retrospective analysis attempts to prove lack of harm from past operation. If the applicant can demonstrate a lack of harm from past operations, then one may be able to infer no future harm if operations and other stressors are continuing into the future at rates similar to or less than the past. A prospective analysis attempts to predict impacts in the future based solely on future plant operating conditions and other factors. USGenNE submitted a prospective analysis suggesting that their future operations would allow for the recovery of a balanced indigenous community.

The Mount Hope Bay finfish community of 2002 is in dire condition. Winter flounder, windowpane, tautog and hogchoker all exist at an average abundance of less than 1 fish caught per otter trawl sample in trawls conducted by the applicant. For winter flounder, this represents a 100 fold reduction over historical levels. In addition, 80% of the winter flounder caught in trawls conducted by the applicant were from one station, the station in front of the intake (Scherer, 2002E). This station happens to have the deepest water in the upper portion of the bay, so it is likely that it represents the coolest water temperatures in the upper portion of the bay. This likely explains the higher winter flounder catch rates at that site. Normal migration patterns of striped bass, bluefish and possibly menhaden have been disrupted by the plant’s thermal discharge. Not only have Brayton Point Station operations significantly decreased the quantity of fish in Mount Hope Bay, but the thermal plume has restricted the movement of the fish that are left through thermal avoidance or attraction.

Several substantive actions are occurring or have already occurred, which should improve conditions for fish in Mount Hope Bay. The city of Fall River has embarked on a 150 million dollar treatment plant and combined sewer overflow (CSO) upgrade. The States of Massachusetts and Rhode Island have significantly curtailed commercial and recreational fishing in Mount Hope Bay and elsewhere for numerous species including winter flounder (Gibson, 2001; Lawton, 2001). Federal actions have also been taken to reduce overfishing in federal waters. Reduced fishing mortality has spurred a modest recovery of winter flounder stocks in other areas of Narragansett Bay and southeastern New England (Gibson, 2002A). Unfortunately, this recovery has not been seen in Mount Hope Bay, where stocks continue to persist at levels just above zero. Gibson’s (2002A) analysis of regional effects shows that fish stocks are behaving differently in Mount Hope Bay than other comparable areas in Narragansett Bay.

Consistent with EPA’s § 316(a) Technical Guidance Manual (May 1, 1977), an analysis of each community type was completed. Under the station’s current operating conditions, severalMA0003654 Determinations Document July 22, 2002

6-57 ecosystem changes have been noted. For the phytoplankton community, nuisance algal blooms have recently occurred in the bay and normal phytoplankton population dynamics have been altered, likely as the result of elevated water temperature. For the zooplankton community, the expanded presence of ctenophores, which may also be related to elevated water temperature, is likely to have a dramatic impact on normal zooplankton population dynamics. For the fish community, there is a documented blockage of striped bass and bluefish migration due to thermal attraction and an increased abundance of smallmouth flounder (a southern warmwater fish). Moreover, the plant’s thermal discharge results in large areas of the bay having water temperatures that cause avoidance by winter flounder juveniles. The thermal discharge is apparently restricting adult winter flounder to predominantly the deepest portions of the bay. Finally, the entrainment of huge quantities of fish eggs and larvae and the impingement of large numbers of juvenile and adult fish may dampen or eliminate fish stock recovery. EPA believes that the balanced indigenous population of fish has not been maintained in Mount Hope Bay and that the plant’s thermal discharge is a significant contributor to this problem.

USGenNE’s Enhanced Multi-Mode scenario (annual flow of 650 MGD and annual heat load of 28 TBTU) represents an approximately 33% reduction in thermal loading to the bay. EPA’s analysis concludes that this level of reduction is not sufficient to eliminate the above listed thermal impacts. In addition EPA’s analysis predicts significant areal effects to Mount Hope Bay from the thermal discharge under the Enhanced Multi-Mode scenario. These effects include chronic toxicity to juvenile winter flounder, avoidance of large sections of the bay by juvenile flounder and a reduced winter flounder egg hatching rate. In addition, based on the combination of water temperature and water clarity, Mount Hope Bay represents an exclusion zone for the growth of eelgrass. The plant’s thermal discharge serves to directly and indirectly depress dissolved oxygen concentrations in the bay. These impacts in conjunction with the high quantity of impingement and entrainment losses certainly will not allow for the recovery of winter flounder or the wider balanced indigenous community. Thus, EPA denies USGenNE’s Enhanced Multi-Mode Variance Request.

To determine the appropriate protective thermal limit, EPA reviewed the benthic modeling runs for both the summer and winter conditions. It was obvious from the model results, that the area of critical temperature exceedance was greatest in the benthic layer. For summer operating conditions, a second order polynomial was fitted to the thermal output data versus water quality degradation (as % of the bay exceeding 24 o C for more than 5 days per month) (Figure 6.3-14). Using this relationship, EPA determined the condition that would ensure that no more than 10% of the bay exceeds 24° C for more than 5 days per month. This results in a thermal discharge of 0.14 TBTU per month in the summer. Juvenile winter flounder inhabit shallow sandy subtidal areas that predominate in the northern portion of the bay (December 2001 USGenNE § 316(a) and (b) Demonstration, Vol. I, Appendix B, p. B-98). As a result, a large thermal plume would dramatically effect the amount of juvenile habitat available. Thus, EPA has determined that a greater than 10% areal impact of the bay would not preserve sufficient juvenile habitat in the summer to allow for a recovery. Collie and Delong (2001) in their key factor analysis suggestMA0003654 Determinations Document July 22, 2002

6-58 that for winter flounder in Mount Hope Bay, a recruitment bottleneck occurs from Age-1 spring to Age-1 fall. This relationship is different than every other portion of Narragansett Bay, where the bottleneck occurs at a later life stage. This bottleneck occurs in the summer and effects the juvenile life stage. Collie and Delong (2001) found a positive correlation between juvenile mortality rates and water temperature. Thus, higher water temperature led to higher mortality rates in juveniles. In order to restore at least winter flounder in Mount Hope Bay, it is likely that this recruitment bottleneck needs to be relieved. As a result, EPA concludes that no greater than 10% areal impact of elevated temperature is acceptable for the bay in the summer.

Review of the scientific literature suggests that winter is a thermally sensitive time for many ecological processes in Mount Hope Bay. Rogers (1976) found that optimal egg hatching occurred at salinities lower than truly marine waters (35 parts per thousand). Thus, the lower portion of the rivers that feed into Mount Hope Bay are likely important spawning areas for winter flounder in Mount Hope Bay. These spawning locations tend to be in the northern portion of the bay in close proximity to the discharge canal and are susceptible to large thermal plumes. Currently, the lack of the normal winter-spring phytoplankton bloom, the expansion in ctenophore time of occurrence and retention of striped bass and bluefish in the thermal discharge plume show that thermal impacts are already occurring in the winter. In addition, increased predation on winter flounder eggs and larvae may also be occurring due to increased activity of sand shrimp. To minimize thermally mediated changes in the bay, a significant reduction in heat is required for this portion of the year as well. EPA believes that a discharge of 0.14 TBTU is also warranted for the winter months. Therefore, EPA believes a discharge of 0.14 TBTU per month or discharge limit of 1.7 TBTU per year, as proposed in the draft permit, satisfies the requirements of CWA § 316(a).

EPA is continuing the 95 o F discharge limit for Brayton Point Station in the current draft permit. Based on the rapid mixing at the venturi, it is not anticipated that an acute toxicity problem will result from this thermal discharge.

While EPA is rejecting the §316(a) variance-based limits proposed by the permittee because we are not convinced that they are stringent enough for the protection and propagation of the balanced indigenous community in Mount Hope Bay, the thermal limits we propose here are less stringent than what would be required by our case-by-case, Best Professional Judgement (BPJ) determination of a technology-based Best Available Technology (BAT) standard. With regard to the water quality-based thermal limits derived by MA DEP in its mixing zone analysis, EPA concludes that the thermal limit of 1.7 TBTU per year and a maximum discharge temperature of 95 °F will be similarly protective, but potentially somewhat less stringent than the water quality-based limits. Since the state’s water quality-based limits are tied to ambient water temperatures and other factors, the relative stringency of these limits as compared to the § 316(a)-based limits could only be assessed with certainty after a period of plant operations under the water quality-based limits. Given the impracticability of undertaking this confirmatory test, for the purpose of issuing this § 316(a) variance, EPA assumes that itsMA0003654 Determinations Document July 22, 2002

6-59 proposed annual thermal limit of 1.7 TBTU and maximum discharge temperature of 95 °F are less stringent than the water quality-based thermal limits.

Therefore, EPA is proposing to issue a new permit for Brayton Point Station with § 316(a) variance-based thermal discharge limits, but these limits are substantially more stringent than the limits requested by USGenNE. We believe the limits we propose will be sufficient to assure the protection and propagation of a balanced indigenous population of fish, shellfish and wildlife in and on Mount Hope Bay.MA0003654 Determinations Document July 22, 2002



### 7.0 Cooling Water Intake Requirements - CWA § 316(b)

7.1 Introduction

This section presents EPA’s determination with respect to the application of CWA § 316(b), 33 U.S.C. § 1326(b), to the new NPDES permit for Brayton Point Station (BPS). CWA § 316(b) governs requirements related to cooling water intake structures (CWISs) and requires “that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.” The operation of CWISs can cause or contribute to a variety of adverse environmental effects, such as killing or injuring fish larvae and eggs by entraining them in the water withdrawn from a water body and sent through the facility’s cooling system, or by killing or injuring fish and other organisms by impinging them against the intake structure’s

screens.

In the absence of detailed regulations, EPA has for many years made CWA § 316(b) determinations on a case-by-case basis, both for new and for existing facilities with regulated CWISs. EPA recently promulgated new, final § 316(b) regulations providing specific technology standard requirements for

new power plants and other types of new facilities with CWISs. 66 Fed. Reg. 65255 (Dec. 18, 2001) (effective date of the regulations is January 17, 2002). These regulations do not , however, apply to existing facilities such as BPS. EPA is currently in the process of developing regulations to apply CWA § 316(b) to existing facilities, but such regulations have yet to be finalized. As a result, EPA continues to apply § 316(b) on a case-by-case basis to existing facilities. In making determinations under CWA § 316(b), EPA must consider engineering issues, environmental/ecological issues, economic issues related to the costs of implementing CWIS technology options, legal issues, and, ultimately, policy issues regarding the final choice of what level of expenditure is appropriate in seeking to minimize adverse environmental effects. All of these issues are addressed below. In addition, the permit conditions that arise out of our CWA § 316(b) determinations are set forth below.

7.2 Legal Requirements and Context

7.2.1 Statutory Provisions

CWA § 316(b) is the statute’s only provision that directly requires regulation of the withdrawal of water from a water body, as opposed to regulating the discharge of pollutants into water bodies. Rather than addressing all types of water withdrawal, however, this provision addresses only cooling water intake structures and provides that:

[a]ny standard established pursuant to section 301or section 306 of this Act and applicable to a point source shall require that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.MA0003654 Determinations Document July 22, 2002

1 Accord In the Matter of Public Service Company of New Hampshire (Seabrook Station, Units 1 & 2) , 10 ERC 1257, 1262 (U.S. EPA, NPDES Permit Application No. NH 0020338, Case No. 76-7, June 17, 1977); Decision of the General Counsel No. 41 (In Re Brunswick Steam Electric Plant)(June 1, 1976), pp. 200-01.

7-2 7-1 33 U.S.C. § 1326(b). The plain meaning of this language is that Congress wanted EPA to ensure that the best technology available for minimizing adverse environmental impacts from CWISs would be utilized by plants withdrawing cooling water from the Nation’s water bodies. The legislative history related to CWA § 316(b) is relatively sparse, but what there is tends to reinforce the plain meaning of the language used in the statute. In the House Consideration of the Report of the Conference Committee (October 4, 1972) on the final version of the 1972 CWA Amendments, Representative Clausen stated that “Section 316(b) requires the location, design, construction and capacity of cooling water intake structures of steam-electric generating plants to reflect the best technology available for minimizing any adverse environmental impact.” Congressional Research Service, “ A Legislative History of the Water Pollution Control Act Amendments of 1972, Vol. 1, ” 93d Cong., 1 stSession

, p. 264 (cited hereafter as the “1972 Legislative History”). In addition, the Senate Consideration of the Report of the Conference Committee (October 4, 1972) for the final 1972 CWA amendments evidences Congressional awareness of the problem of fish being harmed by power plant CWISs. Id . at pp. 196-99, 202. 1

It should also be remembered that CWA § 316(b), like other provisions of the statute, should be construed with Congress’ ambitious overarching statutory purposes in mind. As the Supreme Court has explained:

[t]he Federal Water Pollution Control Act, commonly known as the

Clean Water Act, 86 Stat. 816, as amended, 33 U.S.C. § 1251 et seq., is a comprehensive water quality statute designed to “restore and maintain the chemical, physical, and biological integrity of the Nation’s waters.” § 1251(a). The Act also seeks to attain “water quality which provides for the protection and propagation of fish, shellfish, and wildlife.” § 1251(a)(2).

PUD No. 1 of Jefferson County v. Washington Department of Ecology , 511 U.S. 700, 704 (1994).

7.2.2 General Aspects of the Application of CWA § 316(b)

The statute neither dictates particular technologies to be used for CWISs nor specifies a particular method by which EPA is to make determinations under § 316(b). Case law and EPA guidance directs that the CWIS requirements of § 316(b) are ultimately to be imposed as part of NPDES permitMA0003654 Determinations Document July 22, 2002

2 See Virginia Electric & Power Corp. v. Costle , 566 F.2d 446, 448-51 (4 thCir. 1977); United States Steel Corp. v. Train , 556 F.2d 822, 850 (7 thCir. 1977); Hudson Riverkeeper Fund, Inc. v. Orange and Rockland Utilities, Inc. , 835 F. Supp. 160, 165 (S.D.N.Y. 1993).

3 See Decision of the General Counsel No. 63 (In re Central Hudson Gas and Electric Corporation, et al.) , pp. 379-80 (July 29, 1977); “Development Document for Best Technology Available for the Location, Design, Construction and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact” (EPA 440/1-76/015-a) (April 1976) (hereinafter, the “EPA 1976 Development Document), p. 193; 41 Fed. Reg. 17388 (April 26, 1976) (Proposed Final CWA § 316(b) Regulations later remanded by federal court and then withdrawn by EPA) (discussing application of § 316(b) requirements to existing facilities).

4EPA has been very clear in the preamble to the new regulations that the requirements developed for new facilities do not apply to existing facilities, and that the new facility requirements should not be used as guidance for developing requirements for existing facilities. 66 Fed. Reg. 65256 (December 18, 2001). EPA stated that “[p]ermit writers should continue to apply best professional judgment in making case-by-case section 316(b) determinations for existing facilities, based on existing guidance and other legal authorities.” Id . EPA explained that because the technology requirements for newfacilities are based in part on economic analyses that might turn out differently for existing facilities, the requirements developed for new facilities should not be applied to existing facilities. 66 Fed. Reg. 65256 (December 18, 2001). Nevertheless, however, it is perfectly appropriate to look to the preambles of the new facility regulation for EPA’s description of the history of the development of § 316(b) regulations and a description of EPA’s method of applying the statute in the absence of regulations. This clearly does not involve application of the new facility requirements to existing facilities.

7-3 discharge limitations, which are developed under CWA §§ 301 or 306. 2The requirements of CWA § 316(b) apply both to existing and new facilities, 3 and § 316(b) determinations must be revisited with each permit reissuance. Permit conditions imposed under § 316(b) must satisfy the statute and may be based either on applicable regulatory guidelines or, in their absence, on case-by-case Best Professional Judgment (BPJ) determinations.

7.2.3 Status of EPA CWA § 316(b) Regulations

Just as the statute does not specify required CWIS technologies or the methods by which EPA must make its determinations under § 316(b), there are also no Federal regulations presently in effect that specify such requirements for existing facilities. As mentioned above, EPA recently promulgated new regulations applicable to new facilities. 66 Fed. Reg. 65255 (Dec. 18, 2001) (effective date of the regulations is January 17, 2002). 4

As also mentioned above, EPA is in the process of developing regulations to apply CWA §316(b)MA0003654 Determinations Document July 22, 2002

5 The 1976 CWA § 316(b) regulations were remanded by the court and subsequently withdrawn by EPA, with the exception that 40 C.F.R. § 401.14 has remained in effect. This provision, however, does little more than repeat the language of CWA § 316(b). It also cross-references to “the provisions of part 402 of this chapter,” but these are the very provisions that were remanded by the court and subsequently withdrawn by EPA. Forty C.F.R. Part 402 is currently “reserved.”

6 The permittee urges that EPA’s 1976 Proposed Final Regulations and their preamble can still be looked to for discerning EPA interpretations of CWA § 316(b) because the court in Appalachian Power did not strike down the substantive aspects of the regulations. USGenNE, “Variance Request Application and Partial Demonstration Under the Clean Water Act, Section 316(a) and (b)” (May 24, 2001), pp. 42-43 (hereinafter, the “May 24 2001, USGenNE Partial 316(a) and (b) Demonstration”); USGenNE, “Clean Water Act Section 316(a) and (b) Demonstration, Brayton Point Station Permit Renewal Application” (November 2001) (submitted to EPA on December 7, 2001), Vol. I, Executive Summary, pp. 63, n. 93 (hereinafter, the “December 2001 USGenNE 316(a) and (b) Demonstration”). We agree, but add the caution that because these regulations did not go into effect and were later withdrawn, the interpretations they represent do not carry the legal force of fully effective regulations and they must be considered along with various other sources of EPA interpretations, such as pertinent guidance documents and permit decisions.

7-4 requirements to existing facilities. As part of that effort, EPA recently published for public review and comment proposed §316(b) regulations for application to existing power plants with flows of 50 million gallons per day or more (so-called “Phase II” facilities). 67 Fed. Reg. 17122 (April 9, 2002). Final Phase II regulations are not slated to be issued until August 2003. In the meantime, EPA has again clearly directed that the proposed regulations undergoing public review are not to be used as guidance in current permit development actions. The preamble to the proposed regulations states that “[b]ecause the Agency is inviting comment on a broad range of alternatives for potential promulgation, today’s proposal is not intended as guidance for determining the best technology available to minimize the adverse environmental impact of cooling water intake structures at potentially regulated Phase II existing facilities.” 67 Fed. Reg. at 17124. Until EPA promulgates final regulations, section 316(b) determinations for existing facilities are to continue being made “on a case-by-case basis applying best professional judgment,” which may be more or less stringent than the requirements of the proposed regulations. Id. EPA and state permitting authorities are directed to use existing guidance and information to form their best professional judgment in issuing permits to existing facilities. 67 Fed. Reg. at 17125.

EPA first issued what were intended to be final regulations to provide national technology standards for cooling water intake structures under CWA § 316(b) in April 1976. See 41 Fed. Reg. 17387 (April 26, 1976). After litigation, however, those regulations were remanded to the Agency in 1977. See Appalachian Power Co. v. Train , 566 F. 2d 451 (4 thCir. 1977) (decision remanding regulations on procedural grounds without reaching the merits of their substantive provisions). EPA later withdrew the regulations. 5
, 6 44 Fed. Reg. 32956 (June 7, 1979); see also66 Fed. Reg. 65261 (Dec. 18, 2001)MA0003654 Determinations Document July 22, 2002

7 United States Steel Corp. v. Train , 556 F.2d 822, 850 (7 thCir. 1977); Hudson Riverkeeper Fund, Inc. v. Orange and Rockland Utilities, Inc. , 835 F. Supp. 160, 165 (S.D.N.Y. 1993); EPA Office of General Counsel “Information Memorandum - Judicial Review of Section 316(b) Regulations– Appalachian Power Co. v. Train and Virginia Electric and Power Co. v. Costle (4 th Circuit),” p. 3. See also40 C.F.R. § 125.3 (relating to development of effluent discharge standards); Texas Oil & Gas Ass’n v. United States EPA , 161 F.3d 923, 928-29 (5 thCir. 1998) (BPJ effluent discharge standards); Natural Resources Defense Council v. U.S. E.P.A. , 859 F.2d 156, 195 (D.C. Cir. 1988) (BPJ effluent discharge standards).

7-5 (Final § 316(b) Regulations for New Facilities; discussion of regulatory history).

7.2.4 CWA § 316(b) Determinations on a Case-by-Case, BPJ Basis

In the absence of regulations specifying national technology guidelines for CWISs, EPA has been applying, and continues to, apply CWA § 316(b) on a case-by-case, Best Professional Judgment (BPJ) basis. This is explained in EPA’s recent final rulemaking for new facilities, see66 Fed. Reg. 65256, 65262 (Dec. 18, 2001) (discussion of past and current approach to applying § 316(b)), and is also indicated in a memorandum from EPA Headquarters directing the EPA Regional offices to continue the case-by-case, BPJ application of § 316(b) in the interim before applicable regulations are completed. See EPA Memorandum from Michael B. Cook, “Implementation of Section 316(b) in National Pollutant Discharge Elimination System Permits,” December 28, 2000. EPA is authorized to develop permit conditions on a case-by-case, BPJ basis by CWA §§ 402(a)(1)(B) and 402(a)(2). 7

The December 28, 2000, EPA Headquarters memorandum cited above also instructed EPA Regional offices to continue using certain specific existing guidance documents in developing their case-by-case, BPJ § 316(b) decisions. Specifically, EPA stated that the May 1, 1977, “Draft: Guidance for Evaluating the Adverse Impact of Cooling Water Intake Structures on the Aquatic Environment: Section 316(b)” (the “May 1977 Draft § 316(b) Guidance”), “continues to be applicable pending EPA’s issuance of final regulations under section 316(b).” Id . p. 1. See also 66 Fed. Reg. 65262 (Dec. 18, 2001). The May 1977 Draft § 316(b) Guidance (at p. 5), in turn, cross-references to the EPA’s “Development Document for Best Technology Available for the Location, Design, Construction and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact,” (EPA 440/1-76/015-a) (April 1976) (the “EPA 1976 Development Document”), for guidance regarding technological issues and additional information regarding intake impacts. See also 66 Fed. Reg. 65261-62 (Dec. 18, 2001). The December 28, 2000, EPA Memorandum also pointed to the following two “background papers” as providing potentially useful information for permit writers: (1) “Preliminary Regulatory Development, Section 316(b) of the Clean Water Act, Background Paper No. 3: Cooling Water Intake Technologies” (1994) (the “1994 EPA Background Paper No. 3"); and (2) “Draft Supplement to Background Paper No. 3: Cooling Water Intake Technologies” (1996) (the “1996 EPA Supplement to Background Paper No. 3"). Finally, the December 28, 2000, EPA Memorandum also instructed that past permit determinations could also be a useful source ofMA0003654 Determinations Document July 22, 2002

8 See also“EPA 1976 Development Document, pp. 175-77, 193.

7-6 information for current permit writers.

While directing permit writers to certain potentially helpful information, EPA Headquarters also cautioned in the December 28, 2000, Memorandum against over-reliance on the past documents. Thus, EPA stated the following (at p. 2) (emphasis added):

[p]lease note that the draft 1977 guidance and the two background papers do not impose legally binding requirements on EPA, the State, or the regulated community, and may not apply in a particular situation based on the circumstances. EPA and State decision-makers retain the discretion to adopt approaches on a case-by-case basis that differ from applicable guidance where appropriate. Any decisions on a particular facility should be based on the requirements of section 316(b).

7.2.5 Factors to Consider in Making CWA § 316(b) Determinations

CWA § 316(b) mandates that the design, location, construction and capacity of a CWIS reflect the Best Technology Available (BTA) for minimizing adverse environmental impact. However, there are no applicable statutory or regulatory definitions of the terms “available,” “Best Technology Available,” “adverse environmental impact,” or “minimize,” as they are used in § 316(b).

7.2.5a “Available” Technologies

In applying the BTA standard under CWA § 316(b), EPA obviously must decide what technologies are “available.” Neither the Act nor current regulations expressly define this term. In addition, EPA guidance under CWA § 316(b) has not identified exactly how to determine when a technology should be considered to be “available.”

Looking to the dictionary definition, “available” is defined in the American Heritage Dictionary (2 ndEd. 1982) as, “accessible for use; at hand.” This suggests that, at a minimum, under CWA § 316(b) any technology that might be either directly required or indirectly required as the result of a flow limitation must be technologically feasible. A particular technology’s feasibility could be demonstrated by an example of its use at another facility. Feasibility also might be established through other means such as,for example, appropriate pilot or bench-scale testing. Thus, in past investigations of potential CWISrelated technologies for minimizing adverse environmental impacts, EPA has evaluated technologies in use or under research for CWISs and technologies being used for other purposes that could be adapted for CWISs. See 1994 EPA Background Paper No. 3, pp. 1-1, 2-1, 2-5, 3-1; 1996 EPA Supplement to Background Paper No. 3, pp. 1-2. 8 EPA has also in the past interpreted CWA § 316(b) to intend an economic “practicability” test for BTAMA0003654 Determinations Document July 22, 2002

9 Consistent with this understanding, the American Heritage Dictionary (2 ndEd.) (1982), defines “practicable” as, “capable of being effected, done or executed; feasible.”

7-7 options. ” Although the CWA § 316(b) makes no mention of considering costs, economic practicability can be understood to be implicit within the meaning of the term “available.” EPA also found support for the conclusion that Congress intended a limited consideration of cost in a single passage from the sparse legislative history of § 316(b). Specifically, in the House Consideration of the Report of the Conference Committee, Representative Clausen stated that:

[t]he reference here [in § 316(b)] to “best technology available” is intended to be interpreted to mean the best technology available commercially at an economically practicable cost

.
1972 Legislative History, p. 264 (emphasis added). Citing to Representative Clausen’s remarks, EPA stated the following in the preamble to the Final CWA § 316(b) regulations issued in 1976:

The brief legislative history of section 316(b) states that the term “best technology available” contemplates the best technology available commercially at an economically practicable cost. As with the statute, this language does not require a formal or informal “cost/benefit” assessment. Rather, the term “available commercially at an economically practicable cost” reflects a Congressional concern that the application of “best technology available” should not impose an impracticable and unbearable economic burden on the operation of anyplant subject to section 316(b). Since the regulations require a caseby-case determination of the best available technology, consideration of the economic practicability of installing that technology must necessarily be conducted on a similarly individualized basis.

41 Fed. Reg. 17388 (April 26, 1976) (Final CWA § 316(b) regulations withdrawn by EPA after remand by federal court). Thus, EPA believed that Congress had intended an economic practicability test to be applied to BTA determinations under § 316(b). Applying such a test to a facility-specific case-by-case determination, as opposed to a national guidelines determination, would mean that the cost of proposed BTA actions should not be financially impossible for a plant to implement and remain in business (i.e., “should not impose an impracticable and unbearable economic burden” on plant operations). 9

7.2.5b “Best” Technology Available

CWA § 316(b) requires that the design, construction, location and capacity of CWISs reflect the “best technology available for minimizing adverse environmental impact.” In the 1976 preamble to theMA0003654 Determinations Document July 22, 2002

10 See, e.g.
, In the Matter of Public Service Company of New Hampshire (Seabrook Station, Units 1 & 2) , 10 ERC 1257, 1261 (Permit Appeal Decision by Administrator of EPA) (June 17, 1977). See also65 Fed. Reg. 49065 (August 10, 2000) (“EPA notes that ‘Best Technology Available’ (BTA) is a distinct standard under the CWA.”).

11 E.g.
, Texas Oil & Gas Ass’n v. United States E.P.A. , 161 F.3d 923, 928 (5 thCir. 1998); Association of Pacific Fisheries v. Environmental Protection Agency , 615 F.2d 794, 816-17 (9 thCir. 1980); American Meat Institute v. E.P.A. , 526 F.2d 442, 462-63 (7 thCir. 1975).

12These determinations, arising out of CWA legislative history, have been upheld by the
courts. E.g.
, American Petroleum Institute v. E.P.A. , 858 F.2d 261, 264-65 (5 thCir. 1988); Pacific Fisheries , 615 F.2d at 816-17; BASF Wyandotte Corp. v. Costle , 614 F.2d 21, 22 (1 stCir. 1980); American Iron and Steel Institute v. E.P.A. , 526 F.2d 1027, 1061 (3d Cir. 1975); American Meat Institute , 526 F.2d at 462-63.

7-8 Proposed Final CWA § 316(b) regulations, EPA explained that this meant that EPA’s “effort must be to select the most effective means of minimizing . . . adverse effects.” 41 Fed. Reg. 17388 (Final CWA § 316(b) regulations later withdrawn by EPA after remand by federal court) (emphasis added). This is consistent with the common meaning of the term “best,” which is defined by the American Heritage Dictionary (2 nd

Ed.) (1982), as “surpassing all others in excellence, achievement, or quality . . ..”

The above-described interpretations of the terms “available” and “best” in CWA § 316(b) are consistent with and supported by analogy to EPA’s application of the “Best Available Technology economically achievable” (BAT) technology standard for the development of effluent guidelines under CWA §§ 301(b)(2)(A) and 304(b)(2)(B). To be sure, the BAT effluent discharge standard is not identical to the BTA standard for cooling water intake structures. 10 Nevertheless, Congress used the same words for both standards, albeit combined in different ways, and it is fair to analogize to the BAT standard in seeking guidance for how to apply the terms “best” and “available” in the BTA standard.

In applying BAT, EPA has determined that it should look to the single “best” performing plant in the industry –in terms of effluent reductions– to determine the “best available” technology. 11 In addition, however, EPA has also determined that it may look to any viable “transfer technologies” (that is, technology from another industry that could be transferred to the industry in question), as well as technologies that have been shown to be viable in research even if not yet implemented at a full-scale facility. 12This is consistent with EPA’s past work under § 316(b) as described above.

Therefore, to determine whether the location, design, construction, and capacity of a particular CWIS reflects the “Best Technology Available” for minimizing adverse environmental impacts, EPA will look to the best-performing CWIS to see what it achieves. Given that BPS is an existing fossil fuel-burningMA0003654 Determinations Document July 22, 2002

13 Although EPA refers to “flow reduction” as a “technology” in the EPA Supplement to Background Paper No. 3, EPA understands that improvements could be made without actually changing technology by simply reducing the amount of cooling water used by BPS. Such reductions without technology changes would, however, require cutbacks in the generation of electricity. Requiring such cutbacks, sometimes on a seasonal basis, has been required in some permits. See, e.g.
, Bulletin, Marine Resources Advisory Council, Vol. IX, No. 4, “Effects of Power Plants on Hudson River Fish,” (requirements for plant included scheduled plant outages); In the Matter of Florida Power Corporation, Crystal River Power Plant, Units 1, 2 and 3, Citrus County, Florida (Findings and Determinations Pursuant to 33 U.S.C. § 1326; NPDES Permit No. FL 0000159), p. 8. Accordingly, the permittee in this case has evaluated flow reductions as a result of various measures including planned outages as a potential alternative means of satisfying CWA § 316(b). See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, Section 3.5.

14In one sense, one can think of a technology used at a newpower plant as a potential “transfer technology” for use at existing plants.

7-9 plant that would require retrofitting to achieve any technologically -driven improvements, 13 EPA will look in this regard to whether any existing fossil fuel-burning plants have undergone technological retrofits to better minimize adverse environmental impacts from their CWISs. In addition, EPA could look to any technologies that can be shown to be feasible for use at BPS, even if they have not previously been used to retrofit an existing facility. For example, in this regard, EPA could look to technologies being used at new power plants to determine if they would be feasible for retrofit at BPS. Indeed, use of a relevant technology at a new plant could well provide as stronger evidence of the feasibility of a technology than technologies “transferred” from another industry or established only at the research or pilot-testing level. 14

Of course, because each CWA § 316(b) decision is made on a case–by-case basis, EPA must also consider whether any particular technology is truly feasible for use at BPS given the particular facts of the BPS situation. For example, while the fact that a technology works at a particular power plant might suggest that it could work at BPS, it still might not actuallybe feasible due to site-specific issues such as, for example, space limitations. If it is not actually feasible at BPS, it would not be the “best technology available” for BPS.

7.2.5c “Adverse Environmental Impact”

The term “adverse environmental impact” (AEI) as used in CWA § 316(b) is not defined in either the statute or existing regulations. As such, neither the statute nor the regulations expressly limit the extent of adverse environmental impacts that may be considered. As mentioned above, the legislative history behind CWA § 316(b) is sparse, but in the House Consideration of the Report of the Conference Committee for the final 1972 CWA Amendments, Representative Clausen stated that “Section 316(b) requires the location, design, construction and capacity of cooling water intake structures of steam-MA0003654 Determinations Document July 22, 2002

15 See also In the Matter of Public Service Company of New Hampshire, et al. (Seabrook Station, Units 1 and 2) , 10 Env’t Rep. Cas. (BNA) 1257, 1262 (EPA June 17, 1977);(CWA § 316(b) standard requiring that CWISs reflect BTA for minimizing adverse environmental impact differs from § 316(a) standard requiring that thermal discharge limitations protect balanced indigenous populations of fish, shellfish and wildlife, and § 316(b) may require further minimization of adverse impacts even if balanced indigenous populations would not be undermined). Accord Decision of the General Counsel No. 63 , p. 371, 382 (July 29, 1977) (In re Central Hudson Gas and Electric Corporation, et al.); Decision of the General Counsel No. 41 , 197, 201-02 (June 1, 1976) (In re Brunswick Steam Electric Plant).

7-10 electric generating plants to reflect the best technology available for minimizing anyadverse environmental impact” (emphasis added). 1972 Legislative History, p. 264. This language suggests that all adverse environmental impacts should be considered and minimized.

Consistent with Representative Clausen’s remarks, EPA’s May 1977 Draft § 316(b) Guidance states as follows (at p. 15):

[a]dverse aquatic environmental impacts occur whenever there would be entrainment or impingement damage as a result of the operation of a specific cooling water intake structure.

The May 1977 Draft § 316(b) Guidance (at p. 15) goes on, however, to state that, “[t]he critical question is the magnitude of any adverse impact.” The guidance document then explains that “[t]he magnitude of an adverse impact should be estimated both in terms of short term and long term impact” with reference to the following factors: (1) “absolute damage;” (2) “percentage damage;” (3) absolute and percentage damage to any endangered species; (4) absolute and percentage damage to any “critical aquatic organism;” (5) absolute and percentage damage to commercially valuable and/or sport fisheries yield; and (6) “whether the impact would endanger (jeopardize) the protection and propagation of a balanced population of shellfish and fish in and on the body of water from which the cooling water is withdrawn (long-term impact).” Thus, the May 1977 Draft § 316(b) Guidance indicates that in assessing the magnitude of the adverse effect, EPA is to consider both the number of individual organisms killed or injured (i.e., “absolute damage”), as well as the percentage of the overall population of species that are damaged (i.e., “percentage damage”). It is also clear that “percentage damage” should be considered at levels below that which would cause the complete collapse of the population. In other words, consideration of “percentage damage” is not limited to cases of 100% damage. 15

The May 1977 Draft § 316(b) Guidance also indicates that in trying to assess adverse impact, permitting agencies should also consider the overall sensitivity of the source water to adverse biological impacts from cooling water intake structures. The Draft Guidance explains (at pp. 11-12) that:MA0003654 Determinations Document July 22, 2002

16 The permittee also argues that “[m]ere hypothetical or potential impact is not sufficient” to constitute AEI. May 24, 2001 Partial 316(a) and (b) Demonstration, p. 33. It is not entirely clear what is meant by this statement but it seems to be without support in the law or any EPA guidance. The permittee’s citation to In re Public Service Company of New Hampshiredoes not support its argument. Since CWA § 316(b) applies to new CWISs as well as to existing ones, EPA is often

7-11 Some general guidance concerning the extent of adverse impacts can be obtained by assessing the relative biological value of the source water body zone of influence for selected species and determining the potential for damage by the intake structure. For a given species, the value of an area is based on the following considerations: 1. principal spawning (breeding) ground; 2. migratory pathways; 3. nursery or feeding areas; 4. numbers of individuals present; and 5. other functions critical during the life history. A once-through system for a power plant utilizes substantially more water from the source water body than a closed recirculation system for a similar plant and thus would tend to have a higher potential impact. A biological value/potential impact decision matrix for best intake technology available could be:

* * * An open system large volume intake in an area of high biological value does not represent best technology available to minimize adverse environmental impact and will generally result in disapproval.

Exceptions to this may be demonstrated on a case by case basis where, despite high biological value and high cooling water flow, involvement of the biota is low or survival of those involved is high, and subsequent reductions of populations is minimal.

In a similar vein, the preamble to the 1976 proposed Final CWA § 316(b) regulations, which were later remanded to EPA by Fourth Circuit Court of Appeals, explained that, “[t]he potential for adverse environmental effects associated with cooling water systems may depend upon such factors as size and type of water body and relative magnitude of flow withdrawn for cooling.” 41 Fed. Reg. 17388 (April 26, 1976). Of course, the general type of water body is only one factor to consider and case-specific analyses of the environmental effects of each particular plant are still required for permit development as explained above. See also41 Fed. Reg. 17388-89 (Final CWA § 316(b) Regulations later withdrawn by EPA after remand by federal court) (assessing adverse effects depends on consideration of multiple factors, including type of water body, number of organisms killed or damaged, and overall damage to the ecosystem).

The permittee argues that no adverse environmental impact should be regarded to have occurred unless the effect is shown to “result in actual substantial harm to populations or communities of biota.” 16 SeeMA0003654 Determinations Document July 22, 2002

necessarily in the position of assessing “potential” or “hypothetical” impacts in making BTA determinations. It is obviously impossible to assess either existing or future population-level effects of CWIS entrainment and impingement with certainty. Therefore, the permittee appears to attempt to foreclose virtually any requirements under CWA § 316(b) by arguing that AEI only exists where there are substantial population-level effects that are absolutely definite (i.e., are not “potential” or “hypothetical”). This is clearly incorrect in light of the EPA guidance documents discussing the need to assess potential future entrainment and impingement effects, both for new and existing facilities. Moreover, the permittee’s position would clearly undermine the CWA § 316(b)’s goal of ensuring the use of the best technology available for minimizing adverse environmental impacts. A permittee or other interested party is, of course, entitled to question whether EPA’s assessment of the “potential” effects in a particular case is reasonable in light of the available information and whether or not EPA has required appropriate steps to minimize any such potential adverse effects.

7-12 December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Executive Summary, pp. 47-48. See alsoMay 24, 2001 USGenNE Partial 316(a) and (b) Demonstration, p. 33. Setting such a high threshold for the existence of AEI, however, is not supported by the statutory language, the legislative history, or the other materials discussed above. While there may be some de minimis threshold level of impacts below which EPA will not consider AEI to have occurred, EPA has not set any such threshold at the level of “substantial harm to populations of biota.” Indeed, as discussed below in the section on “minimization” of adverse impacts, EPA has interpreted the § 316(b) technology standard to require minimization of adverse environmental impacts whether or not they are “significant,” as long as the applicable economic tests are satisfied ( the “wholly disproportionate cost” test is discussed further below).

Moreover, the permittee’s assertion that its “substantial population effect” threshold has been adopted by EPA in guidance as well as in the Seabrook nuclear power plant permit decision by EPA that was upheld by the First Circuit Court of Appeals is simply unfounded. For example, in the preamble to the 1976 Proposed Final CWA § 316(b) Regulations, EPA stated the following:

[s]ome commenters recommended that the Development Document should provide that the proper test for minimizing adverse environmental impact is related to damage to the aquatic ecosystem and not to the number of fish and other aquatic organisms killed or damaged. Section 316(b) requires that the best technology available be used to minimize adverse environmental impacts. As noted in the Development Document, there are many factors that should be considered when determining whether an adverse environmental impact exists or is likely to exist. The factors noted by the commenters are among those to be considered. All pertinent factors, rather than reliance on a single factor, should receive adequate consideration.MA0003654 Determinations Document July 22, 2002

17 The permittee also points to EPA Region I’s October 26, 1999, Draft Information Document to support its argument that only “actual, substantial population-level effects” constitute AEI. This attempt also fails. First, the document cited to is only a Draft regional memorandum and, consistent with the disclaimer at the end of the document, it cannot displace the language of the statute, much less interpretations adopted by EPA in the preambles to regulations, formal permit appeal determination, or national guidance. Second, the Draft Regional memorandum does not support the company’s argument. The Draft Regional memorandum (at p. 19) states that “ a 316(b) Demonstration . . . can be successful if it provides convincing evidence that populations of CAO [, critical aquatic organisms,] will not decline in abundance as a result of the losses of all life stages attributable to entrainment, impingement, or other intake-related effects.” Stating that a § 316(b) determination could be based on a finding that losses would cause no decline in abundance falls far short of a determination that only “actual, substantial population-level” impacts constitute AEI. While the Draft Regional document (at p. 19) does note that “316(b) demonstrations have traditionally focused on population-level effects on the principal species (CAO),” it does not endorse the permittee’s test for AEI. Furthermore, the Draft Regional document (at p. 18) states that impact determinations should evaluate “the nature and intensity of impacts; the spatial and temporal scale of effects; and the potential for recovery from effects. ” It also states (at p. 18) that “logically” a § 316(b) determination should consider factors such as a “substantial decrease of formerly indigenous species,” a “reduction of the successful completion of life cycles of indigenous species, including those of migratory species,” and a “detrimental interaction with other pollutants, discharges or water-use activities.” Finally, the Draft Regional document ( seepp. 4, 19) notes that EPA also applies an economic test in making § 316(b) determinations (i.e., the wholly disproportionate cost test).

7-13 41 Fed. Reg. 17389 (April 26, 1976) (emphasis added). Furthermore, as discussed above, the May 1977 Draft § 316(b) Guidance (at p. 15) clearly indicates that adverse environmental impacts include more than just “substantial population effects.” Thus, EPA has not stated that losses of individuals need not be addressed or that population reductions need not be addressed unless they are “substantial.”

The Draft Guidance does make clear, however, that EPA must assess the magnitudeof the adverse impact. See alsoEPA 1976 Development Document, pp. 13, 175. Moreover, EPA has been clear that the magnitude or seriousness of the adverse impacts should be assessed on a case-by-case basis taking into account the facts related to ecosystem and natural resources in question. See 41 Fed. Reg. 17388 (April 26, 1976); May 1977 Draft § 316(b) Guidance, p. 11-15. Thus, a given level of losses from an otherwise healthy ecosystem or fish population might be less environmentally significant than similar or even smaller losses from a stressed ecosystem or fish population. Having decided that the magnitude of the adverse effects should be assessed, EPA has then taken the approach that more serious adverse impacts warrant more serious expenditures for reductions based on a “wholly disproportionate” cost test, which is discussed below. 17MA0003654 Determinations Document July 22, 2002

18 In support of its proposed “substantial population effects” threshold for discerning AEI, the permittee points to the First Circuit’s affirmation of EPA’s findings in the Seabrook case that entrainment losses would not threaten the viability of various species populations. May 24, 2001 Partial 316(a) and (b) Demonstration, p. 34 (citing Seacoast Anti-Pollution League , 597 F.2d at 309). Yet, EPA was only considering whether the intake would threaten the viability of the populations as oneof the factors to consider in assessing the significance of the AEI. This was consistent with the various factors identified in the May 1977 Draft § 316(b) Guidance (at p. 15). The First Circuit merely affirmed EPA’s fact findings in this regard. Seacoast Anti-Pollution League , 597 F.2d at 309-11. The ultimate decision in the Seabrook case, as discussed above, was not that there was no adverse environmental impact unless populations would be rendered non-viable or suffer substantial harm, and that therefore nothing needed to be done; rather, it was that in light of the magnitude of the adverse environmental impact, the large cost of moving the intake even further offshore would be wholly disproportionate to the benefits that would have been gained (note: the company had already agreed to move the intake out of the estuary at substantial expense). Id . at 311.

7-14 This approach is well illustrated in the Seabrook permit appeal decision, in which the EPA Administrator explained:

. . . the RA [i.e., EPA Regional Administrator] may have meant only that some consideration ought to be given to costs in determining the degree of minimization to be required. I agree that this is so – otherwise the effect would be to require cooling towers at every plant that could afford to install them, regardless of whether or not any significant degree of entrainment or entrapment was anticipated. I do not believe that it is reasonable to interpret Section 316(b) as requiring use of technology whose cost is wholly disproportionate to the environmental benefit to be gained.

In re Public Service Company of New Hampshire , 10 ERC at 1261. Thus, it was the “wholly disproportionate cost” test that prevented an across-the-board cooling tower (or closed-cycle cooling) requirement, and not the argument advocated by the permittee (namely, that no adverse environmental impacts exist and require minimization until substantial harm to entire populations of fish have occurred). The First Circuit subsequently upheld EPA’s application of the wholly disproportionate cost test. Seacoast Anti-Pollution League v. Costle , 597 F.2d 306, 311 (1 stCir. 1979). 18

7.2.5d “Minimizing” Adverse Environmental Impacts

In past decisions, EPA has determined that the term “minimize” should be understood to have its common meaning, which is, “reduce to the smallest possible amount, extent, size, or degree.” American Heritage Dictionary (2 nd

Ed.) (1982). See also41 Fed. Reg. 17387-88 (Proposed Final CWA § 316(b) regulations later remanded to EPA by federal court and withdrawn by EPA) ; Decision of the General Counsel No. 63 (In re Central Hudson Gas and Electric Corporation, et al.) , p. 371, 381 (July 29, 1977); In the Matter of Public Service Company of New Hampshire, et al. (SeabrookMA0003654 Determinations Document July 22, 2002

19 The significance or magnitude of the impacts comes into play, however, when considering whether the cost of undertaking actions to further minimize impacts is justifiable.

7-15 Station, Units 1 and 2) , 10 Env’t Rep. Cas. (BNA) 1257, 1260 (EPA June 17, 1977);Decision of the General Counsel No. 41 (In re Brunswick Steam Electric Plant) , 197, 203 (June 1, 1976). Based on the language and structure of CWA § 316(b), EPA has also determined that CWISs must reflect the BTA for minimizing adverse environmental impacts, whether or not those adverse impacts are considered to be significant. Decision of the General Counsel No. 41 , at 203 (“The [cooling water intake] structures must reflect the best technology available for minimizing . . . adverse environmental impact – significant or otherwise.”)(emphasis in original); Decision of the General Counsel No. 63 , at 381-82 (“Under Section 316(b), EPA may impose the best technology available . . . in order to minimize . . . adverse environmental impacts – significant or otherwise.”). In other words, once adverse impacts are beyond some de minimis level, there is no particular threshold of significance which must be crossed before the adverse impacts must be minimized by the application of BTA. 19

Still, the May 1977 Draft § 316(b) Guidance is clear that EPA does not regard CWA § 316(b) to require the complete elimination of all entrainment or impingement in all cases. The Guidance states (at p. 3):

The extent of fish losses of any given quantity needs to be

considered on a plant-by-plant basis, in that the language of section 316(b) of P.L. 92-500 requires cooling water intakes to “minimize adverse environmental impact.” Regulatory agencies should clearly recognize that some level of intake damage can be acceptable if that damage represents a minimization of environmental impact.

Thus, although EPA has read CWA § 316(b) to intend that greater than de minimis levels of entrainment or impingement may be considered an “adverse impact,” and that such impacts must be reduced to the smallest amount possible (i.e., be “minimized”) through the application of BTA, this may or may not require the elimination of all impacts in any given case. Less than complete elimination of all adverse effects could be appropriate if the effects are considered de minimis , if further reductions are not feasible with available technology, or if the cost of attaining these additional reductions would be wholly disproportionate to the benefits. The role of cost considerations in CWA § 316(b) determinations is discussed below.

7.2.5e Economic Considerations in CWA § 316(b) Determinations

EPA has interpreted CWA § 316(b) to authorize it to consider, to a limited extent, the cost of the options when making determinations of what constitutes BTA for minimizing adverse environmental impacts. First, as discussed in detail above, cost is considered in terms of “practicability.” This can be understood as part of meeting the “availability” component of BTA. Second, as briefly mentionedMA0003654 Determinations Document July 22, 2002

7-16 above, an option’s costs are also to be considered under the wholly disproportionate cost test. This is discussed further below.

The text of CWA § 316(b) makes no express mention of considering costs in any way in determining BTA requirements. Nevertheless, EPA found support for the conclusion that Congress intended a limited consideration of cost in a single passage from the sparse legislative history of § 316(b). Specifically, in the House Consideration of the Report of the Conference Committee on the 1972 CWA Amendments (Oct. 4, 1972), Representative Clausen stated that:

[t]he reference here [in § 316(b)] to “best technology available” is intended to be interpreted to mean the best technology available commercially at an economically practicable cost.

1972 Legislative History, p. 264. This statement reflects Representative Clausen’s belief that economic practicability should be considered but does not, on its face, indicate that a comparison of costs and benefits should determine the result of a § 316(b) determination.

Recognizing the focus of Representative Clausen’s remarks, EPA cited in support of the following conclusions in the preamble to the 1976 proposed Final CWA § 316(b) regulations:

No comparison of monetary costs with the social benefits of minimizing adverse environmental impacts, much less a formal, quantified “cost/benefit” assessment, is required by the terms of Act. The statute directs the Agency to insure that enumerated aspects of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. Once such adverse effects have been identified (or, in the case of new structures, predicted) then the effort must be to select the most effective means of minimizing (i.e., “reducing to the smallest possible amount or degree”) those adverse effects. The brief legislative history of section 316(b) states that the term “best technology available” contemplates the best technology available commercially at an economically practicable cost. As with the statute, this language does not require a formal or informal “cost/benefit” assessment. Rather, the term “available commercially at an economically practicable cost” reflects a Congressional concern that the application of “best technology available” should not impose an impracticable and unbearable economic burden on the operation of anyplant subject to section 316(b). Since the regulations require a caseby-case determination of the best available technology, consideration of the economic practicability of installing that technology must necessarily be conducted on a similarly individualized basis.MA0003654 Determinations Document July 22, 2002

7-17 41 Fed. Reg. 17388 (Final CWA § 316(b) regulations later withdrawn by EPA after remand by federal court). Thus, EPA made clear that it believed that Congress intended an economic practicability test to be applied to BTA determinations under § 316(b), but made equally clear that a cost/benefit analysis was not required.

EPA later adopted a new test involving a limited consideration of costs and benefits. In a permit appeal decision involving the Seabrook, New Hampshire, nuclear power plant, the Administrator of EPA reiterated much of what EPA had stated in the preamble to the regulations regarding both the absence of any cost/benefit analysis requirement and the need for costs to be economically practicable. Significantly, however, the Administrator also affirmed that no measures should be required as BTA “whose cost is wholly disproportionate to the environmental benefit to be gained.” Specifically, the Administrator of EPA stated the following:

. . . the Agency’s position, that cost benefit analysis is not required under Section 316(b), is correct. Section 316(b) provides flatly that cooling water intakes shall “reflect the best technology available for minimizing adverse environmental impact.” Unlike Sections 301 and 304, Section 316(b) determines what the benefits to be achieved are and directs the Agency to require use of “best technology available” to achieve them. There is nothing in Section 316(b) indicating that a cost benefit analysis should be done, whereas with regard to “best practicable control technology currently available” . . . Congress added express qualifiers to the law indicating a requirement for cost/benefit analysis. Indeed, but for one bit of legislative history [citation to Representative Clausen’s remarks omitted], there would be no indication that Congress intended costs to be considered under Section 316(b) at all. I find, therefore, that insofar as the RA’s decision may have implied the requirement of a cost/benefit analysis under Section 316(b), it was incorrect. However, the RA may have meant only that some consideration ought to be given to costs in determining the degree of minimization to be required. I agree that this is so – otherwise the effect would be to require cooling towers at every plant that could afford to install them, regardless of whether any significant degree or entrainment or entrapment was anticipated. I do not believe that it is reasonable to interpret Section 316(b) as requiring the use of technology whose cost is wholly disproportionate to the environmental benefit to be gained.

In re Public Service Company of New Hampshire (Seabrook Station, Units 1 and 2), 10 ERC 1257, 1261 (NPDES Permit Application No. NH 0020338, Case No. 76-7; June 17, 1977) (Decision of the Administrator). In Seacoast Anti-Pollution League v. Costle , 597 F.2d 306, 311 (1 stMA0003654 Determinations Document July 22, 2002

20Again, Congressman Clausen did not actually say anything about applying a “wholly disproportionate cost test;” he only stated that “best technology available” was intended to mean “the best technology available commercially at an economically practicable cost.” 1972 Legislative History, p. 264. In Decision of the General Counsel No. 63 (In re Central Hudson Gas and Electric Corp.) , (July 29, 1977), p. 382, EPA’s General Counsel cited to the Seabrook decision and reiterated EPA’s “wholly disproportionate cost” test. The General Counsel further reiterated that the “this test is a limited one, for the Administrator . . . rejected the notion that a full cost/benefit analysis is required under Section 316(b).”

21 In a July 2001 meeting, EPA noted to the permittee that the Agency would need to consider whether the recent Supreme Court case of Whitman v. American Trucking Association, Inc. , 121 S. Ct. 903 (2001), had any bearing on our interpretation of the proper application of cost considerations under CWA § 316(b). This case addressed the question of whether or not certain language in the Clean Air Act authorized costs to be considered in the development of certain air emissions standards. The Supreme Court held that the Clean Air Act prohibited EPA from considering compliance costs in setting the standards in question because the statute did not grant authority to consider costs and such authority would not be inferred. Given the absence of language regarding cost considerations in CWA § 316(b), it seemed to EPA that the import of this case ought to be considered. The permittee has offered its opinion that for several reasons the case has no bearing on the interpretation of CWA § 316(b). See May 24, 2001 Partial 316(a) and (b) Demonstration, p. 40, n. 24. Although we disagree with certain aspects of the permittee’s analysis, the bottom line is that we are adhering to EPA’s “wholly disproportionate cost” test under CWA § 316(b) because the Agency has not withdrawn this longstanding interpretation in response to American Trucking

.
7-18 Cir. 1979), the First Circuit Court of Appeals noted EPA’s application of the “wholly disproportionate cost” test with approval and cited to Congressman Clausen’s remarks to support the proposition that, “[t]he legislative history clearly makes cost an acceptable consideration in determining whether the intake design reflect[s] the best technology available.” 20
, 21

EPA has not, however, specified any particular method for determining whether an option’s costs are “wholly disproportionate” to its benefits under CWA § 316(b). Whether assessed qualitatively or quantitatively, an option’s costs would have to be substantially greater than its benefits before those costs would be deemed “wholly disproportionate” to the benefits. Where to “draw the line” is a policy judgment left to the sound discretion of EPA in making its case-by-case § 316(b) decisions. The appropriate judgment regarding the point at which the costs of a technology become wholly disproportionate to its benefits might vary from case to case based on the type and extent of the adverse impacts to be addressed and the degree of certainty or uncertainty regarding the costs and benefits.

While there is no exact prescription for how to determine whether an option’s costs are wholly disproportionate to its benefits under § 316(b), some guidance may be found in the EPA’s applicationMA0003654 Determinations Document July 22, 2002

22 See, e.g.
, Chemical Manufacturers Association v. U.S. E.P.A. , 870 F.2d 177, 203-04 (5 th Cir. 1989); Eli Lilly and Company v. Costle , 598 F.2d 638, 656 (1 stCir. 1979).

23 See, e.g.
, Chemical Manufacturers , 870 F.2d at 204-05; Eli Lilly, 598 F.2d at 656.

24 E.g.
, Eli Lilly, 598 F.2d at 656; Weyerhaeuser Company v. Costle , 590 F.2d 1011, 1048 (D.C. Cir. 1978).

25 See, e.g.
, Environmental Protection Agency v. National Crushed Stone Association , 449 U.S. 64, 71 n. 10, 80, 83 (1980); Eli Lilly, 598 F.2d at 656.

7-19 of different “wholly disproportionate cost” test in setting Best Practicable Treatment (BPT) effluent discharge limitations. CWA § 304(b)(1)(B) expressly requires some balancing of costs against benefits in setting BPT standards. 22Nevertheless, legislative history and case law both make clear that under the BPT “wholly disproportionate cost” test, the cost/benefit balancing is to be of a “limited” nature23 and cost is not to be considered a factor of “primary” or “paramount” importance. 24Presumably, therefore, in applying the “wholly disproportionate cost” test under § 316(b), which does not even mention the consideration of cost, costs should also not be a primary or paramount factor. Moreover, the courts have been clear that in developing national standards under the BPT “wholly disproportionate cost” test, environmental controls might be required that would cause some “economic dislocation,” and even plant closures, to achieve the stated environmental objective. 25 Thus, application of the “wholly disproportionate cost” test under the BPT standards confirms that application of the similar test under § 316(b) could countenance significant economic impacts to a facility if the costs would not be wholly disproportionate to the benefits.

In applying the BPT “wholly disproportionate cost” test, the courts have also stated that EPA’s balancing of costs and benefits “is a relatively subsidiary task and need not be precise.” Eli Lilly, 598 F.2d at 656. A reasonable estimate of costs and benefits is sufficient. See, e.g.
, Eli Lilly, 598 F.2d at 656-57; Weyerhaeuser , 590 F.2d at 1049. The courts have also upheld an “overall” cost/benefit comparison and rejected arguments that EPA must do an “incremental” cost/benefit analysis, Weyerhaeuser , 590 F.2d at 1047-48, n. 55, or a “knee of the curve” analysis. Chemical Manufacturers , 870 F.2d at 203-07. In the context of the BPT standard, the courts have also been clear that EPA has broad discretion in determining how to consider costs and benefits and in deciding the point at which costs become “wholly disproportionate” to benefits. E.g.
, Chemical Manufacturers
, 870 F.2d at 207 (“‘The selection of the point of diminishing returns is a matter for agency determination.’” [citation omitted]); Eli Lilly, 598 F.2d at 656-57; American Iron & Steel Institute v. E.P.A. , 568 F.2d 284, 297 (3d Cir. 1977). The courts have also ruled that they should defer to EPA’s decisions applying the wholly disproportionate test unless they are “not reasonable” or are “arbitrary and capricious.” Chemical Manufacturers , 870 F.2d at 206, 207. See also Association of Pacific Fisheries v. E.P.A. , 615 F.2d 794, 809 (9 thCir. 1980) (court review should ensure that decision is the “product of reasoned decision-making, adequately supported by information available to the Agency”).MA0003654 Determinations Document July 22, 2002

26 See, e.g.
, Pacific Fisheries , 615 F.2d at 809; Appalachian Power Company v. Train , 545 F.2d 1351, 1361 (4 thCir. 1977); American Iron and Steel Institute v. E.P.A. , 526 F.2d 1027, 1075 (3d Cir. 1975).

7-20 These principles should also apply to the application and review of application of the wholly disproportionate cost test under CWA § 316(b).

Finally, the courts have noted that one of the reasons that Congress did not require a more precise form of economic analysis in setting effluent discharge standards under the CWA is the impossibility of fully quantifying all the environmental benefits to be obtained from making technological improvements to reduce pollutant discharges. 26 This rationale applies equally to the difficulty of quantifying all the benefits of minimizing the adverse impacts of cooling water intake structures.

7.2.6 Interaction of CWA §§ 316(b) and 316(a) Analyses

CWA §§ 316(a) and (b) impose different standards and address different, though related, concerns. While § 316(a) addresses thermal discharges, § 316(b) addresses the adverse environmental impacts of the operation of CWISs. Section 316(a) authorizes EPA (or the State) to issue a permit with thermal discharge effluent limitations less stringent than otherwise required under §§ 301 and 306, as long as the alternative limits would be sufficient to ensure the protection and propagation of a balanced indigenous population of fish, shellfish and wildlife in and on the receiving water. Section 316(b), on the other hand, requires that the design, location, construction and capacity of CWISs reflect the best technology available for minimizing adverse environmental impacts, subject to the economic tests discussed above. CWA § 316(b) BTA requirements are not excused even if the adverse environmental impacts from the CWIS would not preclude the protection and propagation of the source water body’s balanced indigenous population of fish, shellfish and wildlife. Of course, under the wholly disproportionate cost test, the more serious the adverse impacts, the more significant the costs that would be justified to reduce those impacts. Moreover, in assessing the impact from the CWIS, EPA must consider the impacts from the operation of the CWIS alone as well as its impacts considered in conjunction withother environmental stressors.

EPA has long held the above-stated views on the interaction of CWA §§ 316(a) and (b). For example, in the preamble to the 1976 Proposed Final CWA § 316(b) Regulations, EPA stated:

. . . the conclusion in a 316(a) hearing should not necessarily govern the outcome of 316(b). Certainly, the Agency would not deny a request for less stringent thermal effluent limitations under 316(a) where the necessary statutory showing had been made because of entrainment effects of the plant’s intake structure. Similarly, the Agency should not be precluded from addressing evident entrainment problems simply because the plant’s thermal effluent is not itself environmentally unacceptable. The concerns of the twoMA0003654 Determinations Document July 22, 2002

7-21 sections are different and the legal standards by which compliance with their requirements is to be judged are similarly distinct.

41 Fed. Reg. 17389 (April 26, 1976) (Final CWA § 316(b) Regulations later withdrawn by EPA after remand by federal court). The Administrator of EPA reached a similar conclusion in deciding a permit appeal related to the Seabrook nuclear power plant, but also provided the following more detailed explanation of how §§ 316(a) and (b) interact:

Interdependence of Sections 316(a) and (b). The RA ruled that a determination of the effect of the thermal discharge cannot be made without considering all other effects on the environment, including the effects of the intake (i.e., entrainment and entrapment); the applicant must persuade the RA that the incremental effects of the thermal discharge will not cause the aggregate of all relevant stresses (including entrainment and entrapment by the intake structure) to exceed the 316(a) threshold. I believe this is the correct interpretation of Section 316(a). The effect of the discharge must be determined not by considering its impact on some hypothetical unstressed environment, but by considering its impact on the environment into which the discharge will be made; this environment will necessarily by impacted by the intake. When Congress has so clearly set the requirement that the discharge not interfere with a balanced indigenous population, it would be wrong for the Agency to put blinders on and ignore the effect of the intake in determining whether the discharge would comply with that requirement. The Utilities argue that the Agency recognized the independence of the 316(a) and (b) in the preamble to the regulations, which states that the “concerns of the two sections are different and the legal standards by which compliance with their requirements is to be judged are similarly distinct” (41 F.R. 17389). As SAPL points out, the fact that the legal standards of the two sections are different does not mean that factual aspects of the intake may not be considered in making a legal conclusion about the discharge. * * * Finally, the RA ruled that even if entrainment and entrapment effects would not cause an “imbalance” [in the indigenous population of organisms in the water body,] they must be “minimized.” This is in accord with Agency policy that “the conclusion in a 316(a) hearing should not necessarily govern the outcome of 316(b)” (41 F.R. 17389). Thus, the RA concluded, even if the 316(a) burden were met, an applicant could faceMA0003654 Determinations Document July 22, 2002

27 The term “location” is not defined in either the CWA or current EPA regulations. In the 1976 Proposed Final CWA § 316(b) regulations, EPA proposed defining “location” as the “position or site occupied by the cooling water intake structure.” 41 Fed. Reg. 17390 (April 26, 1976) (proposed 40 C.F.R. § 402.11(b)). As discussed above, however, these regulations were later withdrawn after remand to EPA by a federal court.

7-22

restrictions on intake capacity which could only be met by use of closed cycle cooling. I believe this conclusion is also correct. As mentioned above, some considerations of cost relative to the environmental benefits to be obtained through further minimization would be appropriate.

Public Service Company of New Hampshire , 10 ERC at 1261-62. Accord Decision of the General Counsel No. 63 , pp. 381-83 (“Simply because cooling water could be discharged at a temperature which does not unduly disrupt the aquatic ecosystem does not mean that the withdrawal of the cooling water therefore will not also have an adverse environmental impact.”).

7.2.7 Cumulative Impacts

Consistent with the above discussion regarding the interaction of CWA §§ 316(a) and (b), BTA determinations under § 316(b) must consider any adverse cumulative effects of the operation of the CWIS. EPA cannot determine the adverse effects of the CWIS in insolation from other stresses on the same environment. For example, the loss to a CWIS of a certain number of organisms, or a certain percentage of a population organisms, might be a more serious adverse impact in an environment already suffering from other adverse impacts than it would be in an otherwise healthy ecosystem. As quoted above, “it would be wrong for the Agency to put blinders on.” Public Service Company of New Hampshire , 10 ERC at 1262. In the end, any such cumulative effects must be considered on a case-by-case basis to assess the magnitude of the adverse effects of CWIS operation and the appropriateness of requiring certain expenditures to minimize those impacts.

7.2.8 Aspects of BTA for CWISs

CWA § 316(b) spells out four aspects of a CWIS that must reflect the BTA for minimizing adverse environmental impacts. These are the CWIS’s design, location, construction and capacity. Each of these factors is discussed below.

7.2.8a Location

The term “location” has been interpreted by EPA to refer to the water body or the segment of the water body in which the CWIS is located. 27 The EPA 1976 Development Document (at p. 15) states that, “[t]he most important locational factor influencing the intake design is the nature of the water source from which the supply is taken.” In addition, “location” has been interpreted also toMA0003654 Determinations Document July 22, 2002

28 “Plant siting and the location of the intake structure with respect to the environment can be the most important consideration relevant to applying the best technology available for cooling water intake structures. Care in the location of the intake can significantly minimize adverse environmental impacts.” EPA 1976 Development Document, p. 178.

29 The term “design” is defined in neither the CWA nor current EPA regulations. In the 1976 Proposed Final CWA § 316(b) regulations, EPA proposed defining “design” as “the arrangement of elements that make up the cooling water intake structure.” 41 Fed. Reg. 17390 (April 26, 1976) (proposed 40 C.F.R. § 402.11(c)). However, these regulations were later remanded to EPA by a federal court and the Agency then withdrew the regulations.

7-23 refer to where the intake is located within a particular water body , such as its location within the water column, its location relative to the shore line, its location relative to the point of the thermal discharge, or its location relative to any particularly sensitive areas in the water (e.g., migration routes, spawning areas, etc.). Id . at Section II, pp. 15 - 26, 178-79. See also EPA Background Paper No. 3, p. 2–3; 1977 Draft CWA § 316(b) Guidance, p. 6; Public Service Company of New Hampshire , 10 ERC at 1263-64, 1270-72.

“Location” has sometimes been referred to as the most important factor in minimizing adverse impacts from a CWIS, because many adverse impacts can be avoided simply by not siting the intake in areas of sensitive or important natural resources. 28 However, adjustment of the “location” of a CWIS to minimize adverse environmental impacts is likely to be easier for a new facility than an existing facility. Nevertheless, “location” must be considered for existing facilities because it may be possible in some cases to reduce impacts by replacing an existing CWIS with a new one at a new location. Of course, the cost of such a “retrofit” would need to be considered, as well as any additional adverse environmental impacts that might result from “construction” of the new CWIS. See EPA 1976 Development Document, p. 169.

7.2.8b Design

EPA has interpreted the “design” component of BTA for CWISs to refer to various elements that make up the CWIS itself. 29 These elements include various screening systems ranging from “trash racks” to other screening technologies intended to try to keep fish or even larvae or eggs from being drawn into the plant. Systems to be considered could include physical screening systems as well as “behavioral” screening systems. In addition, various fish bypass and return systems intended to minimize the adverse impacts of impingement could be considered under the design element. Finally, consideration may also be given to various types of pumps and intake technologies, such as velocity caps, that influence the volume and velocity of water drawn into the plant. See EPA 1976 Development Document, pp. 27 - 143. See also EPA 1996 Supplement to Background Paper No. 3. Design elements should be considered for both new and existing facilities, though the technical feasibility and economic considerations may differ for each, especially given that new equipment for an existing facility will require retrofitting. EPA 1976MA0003654 Determinations Document July 22, 2002

30The term “construction” is not defined in either the CWA or current EPA regulations. In the 1976 Proposed Final CWA § 316(b) regulations, EPA proposed defining “construction” as the “process of physically constructing the cooling water intake structure, including site preparation.” 41 Fed. Reg. 17390 (April 26, 1976) (proposed 40 C.F.R. § 402.11(d)). However, these regulations were later withdrawn by EPA after they were remanded by a federal court.

31 The latter consideration obviously overlaps with the consideration of location. EPA has noted that the various aspects of BTA for CWISs listed in CWA § 316(b) can overlap considerably. See EPA 1976 Development Document, p. 15.

32The term “capacity” is defined in neither the CWA nor current EPA regulations. In the 1976 Final CWA § 316(b) regulations, EPA proposed defining “capacity” as the “maximum withdrawal rate of water through the cooling water intake structure.” 41 Fed. Reg. 17390 (April 26, 1976) (proposed 40 C.F.R. § 402.11(e)). The preamble to the regulations explained that “[the] relative magnitude of flow withdrawn for cooling” was one of the key factors to consider in evaluating the adverse impact from a CWIS. It further stated that “entrainment . . . realistically cannot be separated from intake structure capacity and location,” and that “the extent of entrainment and impingement damage is in many cases correlated with the amount of water withdrawn . . ..” Id . at 17388, 17389. Further, in discussing compliance dates, EPA stated that “the available technologies of cooling water intake structures for minimizing adverse environmental impacts . . . are closely related to capacity (volume of flow) . . ..” Id

.
7-24 Development Document, pp. 142-43.

7.2.8c Construction

The term “construction” has been interpreted by EPA to apply to the physical aspects of installing the CWIS. 30EPA review of construction-related CWIS impacts has considered damage to the area of the ecosystem impacted by the process of installing the CWIS and its long-term placement in the ecosystem. 31 EPA has also considered the effects of turbidity generated by construction activities and erosion around the area of the CWIS, as well as any adverse effects from the disposal of material dredged or excavated from the area in which the CWIS will be placed. See EPA 1976 Development Document, pp. 145 - 47. If considering potential retrofits to a CWIS, consideration must also be given to whether construction of the retrofitted equipment will reflect the BTA for minimizing adverse environmental effects.

7.2.8d Capacity

The term “capacity” as used in CWA § 316(b) has been defined to refer to the volume of cooling water drawn through the intake. 32The velocity of the water drawn into the plant may also be considered under this factor (as well as under the design factor). In Decision of the General Counsel No. 41 , at 200 - 01, EPA’s General Counsel stated the following:MA0003654 Determinations Document July 22, 2002

7-25 . . . it seems clear to me that the term “capacity” in § 316(b) means the volume of water withdrawn through a cooling water intake structure. This conclusion is supported by the commonly understood meaning of the term “capacity” [footnote to dictionary definition of “capacity” referring to “cubic contents; volume” omitted], the definition of the term in the regulations [footnote omitted], and the legislative history of the Federal Water Pollution Control Act Amendments of 1972.

In the course of debating the conference report of the Act on October 4, 1972, the Senate was well aware of the dangers posed to aquatic life by the withdrawal of large volumes of water through cooling water intake structures [footnote omitted].

Accord Decision of the General Counsel No. 63 , at p. 381, n. 10; In re Public Service Company of New Hampshire , 10 ERC at 1262 (Decision of Administrator of EPA). See also Supplement to Background Paper No. 3 (September 3, 1996), p. A-3; Background Paper No. 3 (April 4, 1994), p. 2-3; EPA 1976 Development Document, p. 153.

As with the other factors, “capacity” must be considered in making CWA § 316(b) determinations for both new and existing facilities. As EPA stated in Decision of the General Counsel No. 63 , at p. 381, n. 10:

Since the magnitude of entrainment damage is frequently a function

of the amount of water withdrawn, the only way that massive entrainment damage can be minimized in many circumstances is by restricting the volume of water withdrawn or by relocating the intake structure away from the endangered larvae. The latter approach is often not feasible. Thus, in certain cases, the only means of minimizing serious entrainment damage is to restrict the volume of water withdrawn.

See also In re Public Service Company of New Hampshire , 10 ERC at 1264 (Decision of Administrator of EPA); EPA 1976 Development Document, p. 178; EPA Draft CWA § 316(b) Guidance (May 1, 1977), p. 13 (“Reducing cooling water flow is generally an effective means for minimizing potential entrainment impact . . . [and i]n fact, . . . may be the only feasible means . . . where potentially involved organisms are in relatively large concentration and uniformly distributed in the water column”).MA0003654 Determinations Document July 22, 2002

33 See Decision of the General Counsel No. 63 (July 29, 1977), pp. 377-78, 382; In re Public Service Company of New Hampshire , 10 ERC at 1262 (June 17, 1977); Decision of the General Counsel No. 41 (June 1, 1976), pp. 199-203. See also Supplement to Background Paper No. 3 , p. A-3; Background Paper No. 3 , pp. 2-3 to 2-4; Draft EPA CWA § 316(b) Guidance, p. 13; EPA 1976 Development Document (April 1976), pp. 149-57, 191.

34 Compare Decision of the General Counsel No. 41 (June 1, 1976), pp. 203; EPA 1976 Development Document, p. 153, with In re Public Service Company of New Hampshire , 10 ERC at 1262 (June 17, 1977).

35 In setting flow limits based on the feasibility of outages, EPA may consider the fact that a plant may already need to have regular maintenance outages. EPA would have to consider whether additional outages beyond the regular ones would be needed, as well as the feasibility, cost and other ramifications of scheduling those outages at times that would ensure the minimization of adverse environmental impacts from CWIS operation.

7-26

i. Miscellaneous Issues Related to Capacity

(A) Cooling Towers

The question has periodically arisen as to whether EPA has authority under CWA § 316(b) to mandate the installation of cooling towers as BTA to achieve flow (or “capacity”) reductions to minimize adverse environmental impacts. The answer that EPA has consistently given is that the Agency is not

authorized to directlyorder the installation of cooling towers because, although closely related to the CWIS, cooling towers are not considered part of the CWIS itself. At the same time, however, EPA has also consistently concluded that CWA § 316(b) does authorize EPA to impose a capacity (or flow) limit based on the permittee’s ability to meet that limit using technologies such as cooling towers that have been determined to be appropriate at the particular plant. 33 While some have characterized this as indirectly requiring cooling towers, this is not really the case. Rather, such a limit imposes a performance standard for CWIS flow (or “capacity”) which the permittee may meet in any manner it chooses. This could involve installing cooling towers, but it also could involve the company cutting back operations to reduce its flow. 34What EPA needs to determine is whether there is a practicable method of meeting the capacity limit which has costs that are not wholly disproportionate to its benefits.

(B) Plant Outages

Similar to the discussion above pertaining to cooling towers, EPA cannot mandate plant outages
per se under CWA § 316(b). 35 Rather, EPA can require appropriate flow limits which in some cases might require major reductions only at certain times. It would be up to the company to decide whether to meet such limitations by installing closed-cycle cooling technologies or by having periodic plant outages. If EPA is relying on the use of periodic plant outages as aMA0003654 Determinations Document July 22, 2002

36 See also In the Matter of Florida Power Corporation, Crystal River Power Plant, Units 1, 2 and 3, Citrus County, Florida (Findings and Determinations Pursuant to 33 U.S.C. § 1326; NPDES Permit No. FL 0000159), p. 8.

7-27 practicable method of achieving the capacity limit, EPA would need to determine that such outages would be practicable and that their cost would not be wholly disproportionate to their benefits. See Supplement to Background Paper No. 3 , p. A-3 (discussion of scheduling outages during months of maximum impingement); Bulletin, Marine Resources Advisory Council, Vol. IX, No. 4, “Effects of Power Plants on Hudson River Fish,” (requirements for plant included scheduled plant outages); In the Matter of Florida Power Corporation, Crystal River Power Plant, Units 1, 2 and 3, Citrus County, Florida (Findings and Determinations Pursuant to 33 U.S.C. § 1326; NPDES Permit No. FL 0000159), p. 8.

(C) Seasonal or Otherwise Variable CWIS Restrictions

As with effluent discharge limitations, EPA can impose seasonal or otherwise varying requirements under CWA § 316(b). For example, flow limits could be tighter during spawning seasons and less restrictive at other times of the year. See Supplement to Background Paper No. 3 , p. A-3; EPA 1976 Development Document, pp. 2, 153. 36 As always, the practicability of methods for meeting such limits must be determined and the cost of doing so must be found not to be wholly disproportionate to the benefits.

7.2.9 Water Quality Standards

The NPDES permit’s requirements pertaining to CWISs under CWA § 316(b) must also be consistent with applicable State legal requirements, including water quality standards. Determining exactly how to apply water quality standards to CWIS requirements in any given case will depend on the exact nature of the water quality standards and the particular circumstances of the case at hand. The most obvious consideration, however, is whether the CWIS requirements will provide for the protection of the designated uses of the water bodies of concern. For example, the Class SA portion of the Massachusetts section of Mount Hope Bay is designated to be “excellent habitat for fish.” The CWIS-related requirements should not interfere with attaining that use designation.

In PUD No. 1 of Jefferson County v. Washington Department of Ecology , 511 U.S. 700, 711-12 (1994), the Supreme Court explained that while a discharge must exist to trigger the application of the water quality standards certification provisions of CWA § 401 (a)(1), CWA § 401(d) and EPA regulations at 40 C.F.R. § 121.2(a)(3) authorize conditions to be placed on the permit applicant’s activity as a wholeso as to ensure compliance with any applicable effluent limitations under §§ 301, 302, 306 or 307, and any applicable water quality standard or other requirement of State law. The Court stated:MA0003654 Determinations Document July 22, 2002

7-28 Section 401(a)(1) identifies the category of activities subject to certification – namely those with discharges. And § 401(d) is most reasonably read as authorizing additional conditions and limitations on the activity as a whole once the threshold condition, the existence of a discharge, is satisfied.

Id . Furthermore, the Court made clear that narrative provisions related to designated uses included in water quality standards may be enforced through permit conditions. Id . at 713-19. The Court explained:

Under the statute, a water quality standard must “consist of the

designated uses of the navigable waters involved and the water quality criteria for such water based upon such uses.” 33 U.S.C. § 1313(c)(2)(A) (emphasis added). The text makes it plain that water quality standards contain two components. We think the language of § 303 is most naturally read to require that a project be consistent with bothcomponents, namely, the designated use and the water quality criteria. Accordingly, under the literal terms of the statute, a project that does not comply with a designated use of the water does not comply with the applicable water quality standards. Consequently, pursuant to § 401(d) the State may require that a permit applicant comply with both the designated uses and the water quality criteria of the state standards. In granting certification pursuant to § 401(d), the State “shall set forth any ... limitations .... necessary to assure that [the applicant] will comply with any ... limitations under [§ 303] ... and with any other appropriate requirement of State law.” A certification requirement that an applicant operate the project consistently with state water standards –i.e., consistently with the designated uses of the water body and the water quality criteria – is both a “limitation” to assure “compl[iance] with ... limitations” imposed under § 303, and an “appropriate” requirement of State law.

Id . at 714-15.

7.3 Technological Options

7.3.1 Introduction

This section discusses potentially available, practicable technological alternatives for ensuring that the design, construction, location and capacity of the CWISs at BPS reflect the BTA for minimizing adverse environmental impacts, as required by CWA § 316(b). This discussionMA0003654 Determinations Document July 22, 2002

37 In addition to fish impingement, problems have arisen at some facilities, but not BPS, with impingement of lobsters (Schiller Station, NH), seals and diving birds (e.g. , Seabrook Station, NH), and reportedly sea turtles (plants in Florida).

7-29 considers engineering, environmental and, at a general level, economic issues related to these alternatives. In addition, this section presents some preliminary “screening” (i.e., winnowing) of alternatives based on factors that EPA believes establish that the rejected alternatives would not be preferred over the alternatives retained for more detailed analysis. A reasonable range of options is retained for more detailed comparison after this initial screening. Subsequent sections of this report provide a more detailed economic analysis of the remaining alternatives and present EPA’s analysis of whether the cost of particular options would or would not be wholly disproportionate to the benefits they would provide.

As part of its permit application, and in response to EPA information requests, the permittee has submitted a significant amount of information related to potential CWIS-related technologies. In evaluating alternative technologies, EPA has considered both the material submitted by the permittee and other materials, such as EPA’s own (and contractor) expert engineering analysis, relevant guidance documents, information regarding experience at other power plants, and information from equipment manufacturers.

7.3.2 CWIS Technologies for Minimizing Adverse Environmental Impacts - General

The primary adverse environmental impacts of concern from the operation of CWISs at BPS are the entrainment of small marine organisms, such as fish eggs and larvae, and the impingement of larger marine organisms, such as fish. 37 Looked at broadly, and as dictated by CWA § 316(b), there are several major approaches to reducing these adverse impacts from CWISs that must be considered. They include the following: 1) “capacity” (or flow) reduction measures which are considered to yield corresponding reductions in the numbers of organisms entrained and impinged by the CWIS; 2) “design” and “capacity” options to lessen impingement by reducing the velocity of the water drawn into the CWIS so that fish are more likely to be able to swim away from the intake; 3) “design” options for barriers and fish return systems to try to reduce the number of organisms drawn into the CWIS where they are impinged or entrained and to try to return any impinged organisms to the source water body unharmed; and 4) “location” options, which for an existing plant would involve re -locating the CWIS to a new, less biologically productive or sensitive site or part of the water column that would reduce entrainment and/or impingement effects. With any of these options, the adverse environmental impacts of “construction” of the technology must also be considered along with alternatives for minimizing those impacts. For example, moving a cooling water intake to a new location might offer potential reductions in entrainment and impingement, but construction activities could have adverse environmental effects that would also need to be considered in deciding whether to require such a re-location under CWA § 316(b).MA0003654 Determinations Document July 22, 2002

7-30 Within the broad categories described above, there are numerous specific technological options to consider. Indeed, a variety of technologies exist for generating electricity with little or no withdrawal of water from natural water bodies for cooling (e.g., “dry” cooling towers; wet cooling towers; wet/dry cooling towers; or use of gray water for cooling). These technologies have been in use for many years, and they generally result in little or no adverse environmental impacts from CWISs. Many of these options are discussed in EPA’s May 1977 Draft § 316(b) Guidance, the EPA 1976 Development Document, the 1994 EPA Background Paper No. 3, the 1996 EPA Supplement to Background Paper No. 3, and the various past regulatory preambles issued by EPA, including the preambles to the recent proposed and final CWA § 316(b) regulations for new facilities. See, e.g. , 41 Fed. Reg. 17388 (April 26, 1976); 39 Fed. Reg. 36189 (Oct. 8, 1974).

Nevertheless, these technologies are not automatically considered BTA for existing facilities under the current case-by-case approach. For existing facilities, BTA determinations must be made on a site-specific basis taking into account the need to retrofit the technologies to the existing plant. Thus, since BPS is an existing power plant, EPA must evaluate what technologies would constitute BTA under CWA § 316(b) for a retrofit at BPS . This includes an evaluation of the practicability of a retrofit at BPS

. See 41 Fed. Reg. 17388 (April 26, 1976). It also requires an assessment of the technology’s capacity to reduce adverse environmental impacts at BPS , an assessment of the cost of installing and operating the technology at BPS, and an evaluation of whether or not the cost of the technology would be wholly disproportionate to the benefits. See In re Public Service Company of New Hampshire , 10 ERC at 1261 (permit appeal decision by EPA Administrator) (“some consideration ought to be given to costs in determining the degree of minimization to be required . . . – otherwise the effect would be to require cooling towers at every plant that could afford to install them, regardless of whether or not any significant degree of entrainment or entrapment was anticipated”).

7.3.3 Major Submissions by the Permittee

Since issuance of the current NPDES permit in 1993, the permittee has submitted several major documents to the permitting agencies addressing CWIS technologies to support the next permit reissuance. The permittee has also made several smaller submissions and a number of presentations at meetings on this topic.

In late 1996, EPA sent the New England Power Company (NEPCO), then the permittee and owner and operator of BPS, an information request letter under CWA § 308. This request sought, among other things, information related to alternative technologies that might be used at BPS to reduce adverse environmental impacts from both the entrainment and impingement of marine life by the plant’s CWISs and the effects of its thermal discharge to Mount Hope Bay. NEPCO contracted Stone and Webster Engineering Company (Stone & Webster) to describe and compare alternatives. NEPCO then submitted to EPA a Stone & Webster report entitled "Feasibility Study of Cooling Water System Alternatives for Brayton Point Generating Station" (January, 1997) (the “January 1997 NEPCO Report”).MA0003654 Determinations Document July 22, 2002

7-31 In September, 1998, NEPCO sold BPS to USGenNE, which continued the Section 316(b) alternative technology analyses. On February 22, 2001, USGenNE submitted a report entitled, “NPDES Renewal: USGen New England, Inc., Brayton Point Station, Somerset, Massachusetts” to the regulatory agencies (EPA-New England and MA DEP). This report stated that it summarized and condensed certain new information on “Cooling System Alternatives” provided by Stone & Webster, but also indicated that Stone & Webster was still doing additional work for USGenNE on CWIS options. Subsequently, USGenNE submitted the May 24, 2001 Partial 316(a) and (b) Demonstration, which includes additional material related to CWISs. On September 10, 2001, in response to another EPA information request letter, USGenNE submitted a document entitled, “A Response to Section 308 Information Request dated August 10, 2001.” The latter document also evaluates certain technological alternatives for reducing BPS’s thermal discharges and the volume of water withdrawn through its CWISs.

Then, on December 7, 2001, the permittee made a new submission to EPA and DEP entitled, “Clean Water Act Section 316(a) and (b) Demonstration, Brayton Point Station Permit Renewal Application” (November 2001) (hereinafter, the “December 2001 USGenNE 316(a) and (b) Demonstration”). This submission includes five large volumes with thousands of pages of material, including a 67-page “Executive Summary.” Some of this material had been submitted previously by the permittee, while other portions had not. Such a late submission of this voluminous, complex package by the permittee – the permittee’s application for permit renewal was due, and was originally filed by the permittee, in January 1998 – created a challenge for the regulatory agencies, but the agencies have endeavored to carefully review and consider the material in the December 2001 USGenNE 316(a) and (b) Demonstration.

A few points must be made regarding the above-mentioned submissions by the permittee. In the January 1997 NEPCO Report (p. 1-1), the permittee imposed the following constraints on its evaluation of alternatives:

! It would only consider thermal load-reduction alternatives that could reduce the average monthly thermal loading from BPS to Mount Hope Bay by approximately 2x10 12[trillion] BTUs. ( Nb. , The baseline heat load to Mount Hope Bay from BPS currently peaks around 4x10 12[trillion] BTUs per month. See December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. III, App. G, Tab: USGenNE § 308 Response of September 10, 2001, Table B-2.)

! It would only consider intake alternatives which at most would reduce station entrainment to levels consistent with the operation of Units 1[, 2] and 3 only, and which improve impingement survivorship to levels consistent with the angled-intake screens for Unit 4.

EPA was not made aware of these constraints in advance and neither approved them nor otherwise indicated that an evaluation based on such constraints would suffice under CWA § 316(b). Indeed, EPA believes that screening out options based on these constraints would not yield an adequate consideration of alternatives for BTA under CWA § 316(b).MA0003654 Determinations Document July 22, 2002

7-32 A similar issue exists with the alternatives screening criteria used in the permittee’s report of February 22, 2001. This report attached a February 2001 report entitled, “Summary of Cooling System Alternatives Analysis for Reducing Thermal Discharge and Entrainment and Impingement at Brayton Point Station.” The latter report states (at p. 7) that, “[t]he focus of the ongoing cooling system alternatives analysis is to identify alternatives and combinations of alternatives that could (a) reduce the station’s thermal discharge to levels that existed before Unit 4 started discharging heat into Mt. Hope Bay and (b) reduce circulation water flows to levels equivalent to Units 1, 2 and 3 only.” Accordingly, the permittee then set plant performance criteria to meet these goals and used these criteria as a benchmark for evaluating alternatives. In a June 19, 2001, letter, EPA explained to the permittee that the government agencies had not embraced these criteria for their own evaluations of what constitutes adequate performance and that the agencies would instead look to the criteria stated in federal and state environmental laws, such as those found in CWA § 316(b). The letter also noted that EPA and the States had explained to the permittee at a number of meetings that the regulatory agencies had not determined whether or not rolling back the plant’s thermal discharge and cooling water intake profile to the levels observed before Unit 4 was converted to once-through cooling would be sufficient to meet the environmental standards of applicable laws. See June 19, 2001, Letter from David Webster (EPA) to Meredith Simas (USGenNE). Nevertheless, the permittee continued to use this criterion for judging alternatives in the December 2001 USGenNE 316(a) and (b) Demonstration. See Vol. IV, § 4.4.

7.3.4 Options for Ensuring that the Design, Construction, Capacity and Location of the BPS CWIS’s Reflect the BTA for Minimizing Adverse Environmental Impacts

7.3.4a Capacity Reduction Options

As discussed above, EPA has interpreted the term “capacity” in CWA § 316(b) to refer to the volume of flow through the CWIS. As is also discussed above, EPA has indicated in relevant guidance and past decisions that flow reduction measures are in many cases the most significant steps that can be taken to reduce adverse environmental impacts from entrainment and impingement, especially if it is not possible to re-locate the CWIS to an area that is not biologically sensitive or productive. There are numerous ways for power plants to generate electricity while reducing the capacity of (or volume of flow through) their CWISs. Methods considered by EPA for possible application at BPS are discussed below.

i. Closed-Cycle Cooling/Cooling Tower Options

Steam electric power plants can generate electricity while using substantially less water than is required for a once-through cooling system by instead using a “closed-cycle cooling” system. Generally, steam electric powerplants employ one of four basic types of circulating water systems to reject waste heat. These systems are (1) once-through cooling (presently used at BPS), (2) once-through cooling with supplemental cooling on the discharge, (3) entirely closed-cycle orMA0003654 Determinations Document July 22, 2002

7-33recirculating cooling, and (4) combinations of these three systems. In a once-through (or nonrecirculating) system, the entire amount of waste heat is discharged to the receiving water body. A once-through system with supplemental cooling (e.g., from “helper cooling towers”) removes a portion of the plant’s waste heat from the effluent before discharging it to the receiving water and transfers this energy to the atmosphere. This type of system does not, however, offer a reduction in the volume of water used.

Closed-cycle or recirculating cooling water systems employ a cooling device that withdraws the plant’s waste energy from the cooling water and releases it directly to the atmosphere. The facility is then able to recirculate and reuse the previously heated water for additional cooling. There are two basic methods of heat rejection for closed-cycle systems. The first is wet (or evaporative) cooling using cooling towers. See, e.g. , 1994 EPA Background Paper No. 3, pp. 2-3 to 2-5 (general discussion of cooling towers); 66 Fed. Reg. 65282 (Dec. 18, 2001). The second uses cooling ponds or lakes. These two methods dramatically reduce cooling water use, though they do require a much smaller amount of water as makeup.

A third type of cooling system does not use cooling water at all and, instead, employs “dry cooling towers” (“or air-cooled condensers”). This method eliminates the use of cooling water and rejects heat directly to the atmosphere from the surface of the condenser. No evaporation of water is involved. See, e.g. , 66 Fed. Reg. 65282 (Dec. 18, 2001); EPA Office of Water, “Economic and Engineering Analysis of the Proposed § 316(b) New Facility Rule) (August 2000), Appendix A, p. 14 (“EPA Economic and Engineering Analysis”). Dry cooling systems are regarded to be substantially more expensive than wet cooling tower systems. See, e.g. , 66 Fed. Reg. 65282-83 (Dec. 18, 2001).

Another type of closed system worthy of note is the “hybrid” (or “wet/dry”) system which combines principles of both wet and dry tower operations. The advantage of this type of cooling system is that it can be used to reduce and /or eliminate any problematic water vapor plumes from mechanical draft cooling towers. See 65 Fed. Reg. 49081 (August 10, 2000) (discussion of wet/dry tower); December 10, 2001, Phone Memo from Sharon Zaya, EPA, Regarding Call with Gary Mirsky, P.E. Hamon Cooling Towers, N.J.; January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey; 39 Fed. Reg. 36192 (October 8, 1974); EPA Economic and Engineering Analysis, App. A, p. 14. This technology would be less expensive than dry cooling but more expensive than a wet cooling tower system. See 65 Fed. Reg. 49081 (August 10, 2000) (discussion of wet/dry tower); Science Applications International Corporation (SAIC) Report (March 15, 2002), Table 5.

As explained above, EPA has interpreted CWA § 316(b) not to allow it to directly mandate cooling towers because they are not actually part of a CWIS. However, EPA has also interpreted the law to allow it to impose a CWIS capacity (or flow) limit that is reflective of the performance capabilities of cooling tower technologies as BTA. This may indirectly help to push a plant to install cooling towers, but it is up to the plant to decide how to meet the permit’s flow limit.MA0003654 Determinations Document July 22, 2002

7-34 There is no question that as a general matter wet, dry and wet/dry cooling towers are all practicable, available technologies for power plants. Wet cooling towers have been widely used at power plants for many years. See, e.g.
, Id .; 65 Fed. Reg. 49080-81 (August 10, 2000); 1996 EPA Supplement to Background Paper No. 3, p. A-3; 41 Fed. Reg. 17388 (April 26, 1976); 1976 Draft EPA CWA § 316(b) Guidance, p. 13; EPA 1976 Development Document (April 1976), pp. 149-57, 191; 39 Fed. Reg. 36192 (October 8, 1974) . Air cooling is also clearly a viable technology as air cooling systems have been installed or proposed for installation at a number of facilities in the United States, including new units at the Mystic Station and the Fore River Station in Massachusetts

. See also 65 Fed. Reg. 49080-81 (August 10, 2000); November 6, 2000, Letter from Vern Lang (US F&WS) to EPA Proposed Rule Comment Clerk, p. 3 (comments on EPA’s proposed regulations under CWA § 316(b) for new power plants listing a number of facilities currently operating, under construction, or recently approved for dry cooling); EPA Economic and Engineering Analysis, App. A, p. 14. In addition, wet/dry cooling towers are also a practicable technology used at a number of plants. See, e.g. , 65 Fed. Reg. 49080-81 (August 10, 2000); EPA Economic and Engineering Analysis, App. A, p. 14-15; 39 Fed. Reg. 36192 (October 8, 1974); Literature from Marley Cooling Tower Company; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary

. Finally, it is also important to recognize that a single power plant could combine the use of both open-cycle and closed-cycle cooling technologies in order to reduce overall plant flows to some predetermined level or to prevent going above some specified cost threshold. See 1994 EPA Background Paper No. 3, p. 2-3. Such “combination options” should especially be considered for existing plants being considered for possible retrofit technology changes, because it will be easier and less expensive for an existing plant to retrofit to partially closed-cycle cooling than to switch to a completely closed-cycle operation. Indeed, the permittee’s “Enhanced Multi-Mode” proposal, which is discussed below, is a type of “combination option.” Accordingly, a number ofalternatives have been considered for BPS which involve partially shifting the facility to closedcycle cooling while also allowing some open-cycle cooling to remain.

While it is clear that the above technologies are generally available and practicable, in making the case-by-case BPJ determinations for this permit, EPA must determine whether these technologies are available and practicable specifically for retrofitting at BPS . There could, for example, be practicability issues related to the adequacy of space to install cooling towers at a particular site. In addition to practicability, other issues must also be considered in determining whether the capacity reductions achievable from a particular closed-cycle cooling technology should be determined to be BTA at a specific plant. For example, cooling tower facilities could impose certain adverse environmental impacts on local residents and these must be considered. For mechanical draft cooling tower facilities (wet or dry), there are noise emissions that must be considered. For wet cooling tower systems, there may be concerns related to emission of plumes of mist or water vapor. Finally, use of any closed-cycle cooling technology will likely result in a marginal loss of electrical generation efficiency at the plant. This has an economic cost associated with it and could also potentially lead a plant to burn more fossil fuel and emit more air pollution in an effort toMA0003654 Determinations Document July 22, 2002

38 The costs in the January 1997 NEPCO Report only address options that provide closedcycle cooling only for Unit 4. It should also be noted that the more detailed cost analyses conducted by the permittee for the December 2001 USGenNE 316(a) and (b) Demonstration has resulted in substantially higher cost estimates. CompareJanuary 1997 NEPCO Report, Table 6-1 (capital costs for mechanical draft cooling tower for Unit 4 estimated at $27.8 million), with December 2001 USGenNE 316(a) and (b) Demonstration, p. 3.3-18 (capital costs for mechanical draft cooling tower for Unit 4 estimated at $48 million). Thus, it is fair to assume the permittee’s estimates for dry cooling would also increase substantially, though the permittee provided no cost estimate for converting any or all BPS units to dry cooling in its December 2001 USGenNE 316(a) and (b) Demonstration.

7-35 offset the efficiency losses. These kinds of issues are discussed below.

(A) “Air” or “Dry” Cooling Towers

As discussed above, using air (or dry) cooling towers would yield the maximum reduction in flow of any cooling technology by essentially eliminating the use of water for cooling. This option would, however, be substantially more expensive than using wet mechanical draft cooling towers. See EPA Economic and Engineering Analysis, App. A, p. 14; 66 Fed. Reg. 65282-84, 65304-06 (Dec. 18, 2001) (various estimates put the costs of dry cooling as from 1.75 to three times more than the cost of wet cooling); January 1997 NEPCO Report, Table 6-1 (preliminary capital cost estimate of $63.4 for dry cooling for Unit 4vs. $27.8 for mechanical draft wet cooling for Unit 4 ). 38 See also SAIC Report (March 15, 2002), Table 5 (costs for hybrid wet/dry cooling towers approximately 2.5 times that of conventional wet towers).

The permittee looked at a dry cooling alternative for Unit 4 only in the January 1997 NEPCO Report, seepp. 3-6 to 3-9, but did not carry it forward for further detailed analysis. See December 2001 USGenNE 316(a) and (b) Demonstration, p. 1-3. In the January 1997 NEPCO Report, at pp. 3-8 to 3-9, the permittee stated that the dry cooling alternative for Unit 4 would be “marginally feasible” but was considered a poor alternative due to its greater cost (more than twice as expensive), greater size (thus posing possible space constraints), greater noise, and greater diminishment of plant power generation capacity. The permittee also noted that since a retrofit from once-through to dry cooling had never been completed, to its knowledge, it would be inherently difficult and would require especially difficult and expensive engineering and design work. Id . at p. 3-8. In the December 2001 USGenNE 316(a) and (b) Demonstration, at p. 1-3, the permittee stated that dry cooling “was determined to be infeasible because this technology has never been retrofitted to an existing station and thus has significant risk of operating failure.” This does not appear to be an entirely accurate representation of the conclusions from the 1997 NEPCO Report, and the December 2001 submission does not include any new analysis on the subject. Yet, while the permittee may have felt dry cooling was “marginally feasible” for Unit 4 alone, it does not mean that the permittee felt that dry cooling would be even marginally feasible for additional units.MA0003654 Determinations Document July 22, 2002

7-36 EPA does not agree that it has been demonstrated that retrofitting some or all the generating units at BPS with dry cooling has necessarily been demonstrated to be “infeasible” for one or more units at BPS. However, EPA Region I also is not aware of an example of a large, existing plant switching from once-through cooling to dry cooling. EPA does not believe that such a conversion is necessarily infeasible just because it may not have been done in the past – indeed, in the January 1997 NEPCO Report, the permittee stated that dry cooling for at least Unit 4 was “marginally feasible.” However, EPA shares the view of the permittee that the absence of a track record of such conversions must be cause for serious caution and concern, and that this caution must grow as more units are considered for conversion.

As a result, like the permittee, EPA has also decided drop dry cooling towers from further consideration for retrofitting at BPS for a combination of reasons. Wet mechanical draft cooling towers, which will

receive further detailed consideration, can achieve up to a 96% reduction in flow for each converted unit at much lower costs. Therefore, choosing air cooling would involve substantially greater expense for only an additional 4% reduction in flow for each unit that was converted. As mentioned above, costs for dry cooling could be as much as three times the cost of wet cooling towers, and this cost difference would be increased by the fact that dry cooling imposes a somewhat greater energy penalty. Moreover, there is substantially more uncertainty about the feasibility (or difficulty) of retrofitting open-cycle generating units to dry cooling than there is with respect to wet cooling, and this uncertainty grows as more units are considered for conversion. Thus, for the multiple unit options, which will achieve greater flow reductions than single unit options, the feasibility of converting to wet cooling towers is clear, whereas the feasibility of the dry cooling options is not.

Based on current information, EPA does not believe that in this case obtaining the small additional reduction in flow offered by dry cooling over wet cooling warrants the substantial additional cost (including energy penalties), especially in light of the substantial uncertainty regarding the technical feasibility retrofitting multiple units at BPS to dry cooling. Since EPA is evaluating wet mechanical draft cooling towers, including an option that would address all four generating units, EPA does not believe that further evaluation of air cooling at BPS is necessary.

(B) Wet Cooling Towers

Mechanical Draft versus Natural Draft Wet Cooling Towers. There are two principal types of wet cooling towers that are used in closed cycle systems: natural draft and mechanical draft towers. Natural draft towers “have no mechanical device to create air flow through the tower and are usually applied in very small or very large applications.” See 1994 EPA Background Paper No. 3, p. 2-4. Mechanical draft towers use fans in the cooling process. See Id .; EPA Economic and Engineering Analysis, p. 11-2 to 11-3; App. A, p. 14.

The permittee evaluated both natural draft and mechanical draft cooling towers and concluded that natural draft towers should be dropped and further consideration should be given to mechanical draft applications. The reason offered for this decision was that the two technologies offerMA0003654 Determinations Document July 22, 2002

7-37 equivalent reductions in flow (and heat rejection), but natural draft towers are significantly more expensive to construct and pose more serious adverse visual impacts because they are much taller. February 22, 2001, Letter from Meredith M. Simas, USGenNE, to David Webster, EPA, and Edward P. Kunce, MA DEP, Attachment 1, p. 4. See also January 1997 NEPCO Report, Table 6-1.

EPA agrees with the permittee’s decision to focus more detailed review on mechanical draft towers. Although EPA has not done a detailed check of the costs predicted by USGenNE for natural draft towers, the research we have done also indicates that natural draft towers would be more expensive to install than mechanical draft towers while achieving the same level of flow (and thermal discharge) reductions. See EPA Economic and Engineering Analysis, App. A, p. 14. In addition, the visual/aesthetic impacts are clearly far greater for natural draft towers because of their great height (approximately 6 times higher). See January 1997 NEPCO Report, pp. 3-13, 3-19. It should be noted that mechanical draft towers are likely to be somewhat noisier (due to the fans) and somewhat more costly to operate (due to the energy needed to run the fans). See January 1997 NEPCO Report, pp. 3-15, 3-21, 3-22; EPA Economic and Engineering Analysis, App. A, p. 14. EPA does not believe, however, that any of these issues are particularly significant. EPA believes it likely that any noise effects from mechanical draft towers can be sufficiently mitigated/controlled to meet applicable noise standards. Id . (Noise is discussed further below.) Further, EPA also believes that the difference in energy use between the two technologies is not large enough to be a significant issue and would be offset by the increased capital costs for the natural draft towers. (Energy and cost issues at BPS are discussed further below.) Mechanical draft cooling towers are a widely used technology at power plants in the United States and abroad, clearly indicating that their impacts or costs are not unacceptable as a general matter.

It should also be noted that although natural draft towers may emit less mist or water vapor than mechanical draft towers, see39 Fed. Reg. 36189, 36192 (Oct. 8, 1974), this advantage is likely to be more than offset by the fact that any plumes will travel farther from the taller natural draft towers than they would from the shorter mechanical draft towers. See Technical Development Document for the Final Regulations Addressing Cooling Water Intake Structures for New Facilities (EPA-821-R-01-036) (November 2001), p. 3-33 (EPA TDD 2001- New Facilities) ; 1/8/02, Email from Timothy Connor, EPA Headquarters to Mark Stein, EPA Region 1; 12/12/01 Memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); January 1997 NEPCO Report, p. 3-15. While it may not be entirely clear which technology would be preferable from this perspective, even if natural draft towers had a marginal advantage, EPA still agrees with the permittee’s decision to focus on mechanical draft towers because we do not believe the plume problems are likely to be especially significant, there are means to address any such problems, and we believe that at this site the advantages of mechanical draft towers (i.e., less expensive, less visual/aesthetic impacts) outweigh any marginal advantage that natural draft towers might have in this regard.MA0003654 Determinations Document July 22, 2002

39 EPA acknowledges that the permittee has pointed to a number of detriments for retrofitting closed-cycle mechanical draft cooling towers at BPS, and has reached the opinion that retrofitting the entire facility

to closed-cycle cooling towers would be “unsuitable” for a variety of economic, engineering and environmental reasons. See December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. I, Executive Summary, p. 8, n. 7. The company has, however, proposed the installation of its “Enhanced Multi-Mode” system which utilizes a 20-cell mechanical draft wet cooling
tower.

7-38 General Applicability of Mechanical Draft Cooling Towers at BPS. Mechanical draft cooling towers appear to be practicable for use at BPS. Such cooling towers have been designed and installed to work effectively in cooling systems using salt or brackish water. See, e.g.
, December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-2; Technical Development Document for the Proposed Section 316(b) Phase II Existing Facilities Rule (EPA 821-R-02-003) (April 2002), p. 4-1 (EPA TDD 2002- Existing Facilities); 12/20/01 Email from Timothy Connor, EPA, to Mark Stein, EPA. Experience at other plants has also shown that closed-cycle mechanical draft wet cooling towers can be retrofitted to an existing once-through power plant. See SAIC Report (March 15, 2002), Attachment A (Case 4); EPA TDD 2002 - Existing Facilities, Chapter 4; Memorandum from Nick Prodany and Mark Stein to Brayton Point NPDES Permit File, “Notes on Telephone Call with Engineer at Canadys Station power plant in South Carolina;” 12/12/01 Memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); January 1997 NEPCO Report, p. 3-6; 12/18/01 Email from Timothy Connor, EPA, to Mark Stein, EPA. Indeed, the permittee has not argued that such a retrofit would be impracticable. 39 Furthermore, EPA and the permittee agree that there is adequate space at BPS to install closed-cycle mechanical draft wet cooling towers, though space becomes increasingly tight as more cooling tower cells are added. See, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Figures 3.3-1, Sections 3.3, 3.3.5, 3.3.6.

Shifting to closed-cycle cooling with mechanical draft cooling towers at BPS clearly could achieve major reductions in the adverse impacts of entrainment and impingement from the CWISs at the plant by enabling substantial reductions in flow through the plant. The extent of the flow reductions that mechanical draft cooling towers would achieve at BPS depends on whether they would be installed for all or only some of the generating units. For traditional steam electric facilities located on fresh water bodies, closed-cycle (recirculating) cooling water systems can, depending on thequality of the make-up water, reduce water use by 96 to 98 percent from the amount used by a oncethrough cooling water system. Steam electric generating facilities that have closed-cycle (recirculating) cooling water systems using salt water have been estimated to reduce water usage by from approximately 71 to 96 percent depending on drift, blowdown and evaporative losses. See Memorandum from CK Environmental to Martha Seagull, Tetra Tech, Inc. (June 26, 2000). Consistent with these figures, the permittee has estimated that the total water withdrawal rate at BPS could be reduced by approximately 96 percent – from 931,000 gallons per minute (gpm) to 39,000MA0003654 Determinations Document July 22, 2002

7-39 gpm, or from the present permit limit of 1.4 billion gallons per day to 56 million gallons per day – if the entire plant were shifted to closed cycle cooling with wet mechanical draft towers, with correspondingly lesser reductions if only certain units are converted. USGenNE § 308 Response of September 10, 2001, pp. 3.3-2 to 3.3-3; December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.3- 25.

The permittee also evaluated the option of using gray water (treated wastewater effluent) to provide “makeup” water for the closed-cycle cooling tower options. Id . §3.3.4. Specifically, the permittee investigated obtaining wastewater effluent from the Fall River Publicly Owned Treatment Works (POTW). The Fall River POTW discharges an average annual daily flow of approximately 20 MGD to Mount Hope Bay which could be used for cooling water purposes. However, the POTW is located across the bay and a pipeline would be required to be constructed to transport the gray water to the power plant. The permittee concludes that such a pipeline would be feasible, but EPA believes it could raise sensitive environmental issues and permitting uncertainties. Id. at p. 3.3-22. In addition, as the permittee notes, the use of treated sewage as cooling water that will be vaporized and emitted from a cooling tower may raise public health and environmental concerns, such as the spreading of viruses, bacteria or trace contaminants. Although the permittee indicates that there are no cases of health problems attributed to the use of gray water for cooling towers or even from the aerosols generated by wastewater treatment plants, EPA believes this issue would warrant additional analysis if this option is to be pursued. Furthermore, the permittee estimates that this option would add an additional $29 million in capital
costs. Apart from the above concerns, the permittee ultimately concludes that the gray water option is not feasible because the POTW cannot consistently provide enough water to meet the makeup needs of the power plant. Id. at p. 3.3-21. EPA believes that the gray water option could provide some potential benefits for reducing water withdrawals from Mount Hope Bay. Nevertheless, based on current information, we are not convinced that this option is feasible or advisable because of the limited and variable volume of gray water available from the POTW (especially during the summer), the permitting and environmental issues related to the construction of the pipeline crossing the bay, public health concerns involving air emissions, and other issues and uncertainties that would need to be further investigated and resolved. In addition, it is not clear that the small additional reduction in cooling water withdrawal is worth the added environmental impacts.

The permittee has also submitted substantial information concerning its views of the engineering requirements, capital and operating costs, and environmental implications of retrofitting closed-cycle cooling at BPS. EPA agrees with the permittee that retrofitting cooling towers for all or some of the generating units at BPS would involve a complicated construction project involving substantial cost. The complexity and cost would be greatest for retrofitting the entire facility and correspondingly less for the various partial retrofit options. However, none of these options are impracticable. The permittee has also indicated that retrofitting all or some of the units at BPS with closed-cycle mechanical draft wet cooling towers could cause adverse noise, visual/aesthetic, fogging and icing impacts. Furthermore, shifting to closed-cycle cooling will likely result in a marginal decrease in electricity generated for sale by the plant due to an “efficiency penalty” and an “auxiliary energy penalty.” This represents a cost to theMA0003654 Determinations Document July 22, 2002

7-40 permittee. It also potentiallycould lead to marginal increases in air pollution if the facility were to burn more fuel in an effort to generate more electricity to offset the lost electrical generation.

Thus, there are several environmental issues to consider with respect to potential cooling tower retrofitting at BPS. However, EPA does not believe that any of these issues present a fatal flaw for a retrofit of mechanical draft wet cooling towers at BPS in order to comply with CWA § 316(b). Of course, all applicable Federal, State and local requirements (e.g., noise emissions, air emissions) will need to be complied with prior to installation and operation of any new facilities.

“Unit-Specific” and “Multi-Mode” Options. The permittee and EPA have each evaluated a variety of both “unit-specific” and “multi-mode” mechanical draft wet cooling tower options. Despite our having considered numerous options, there could be additional variations that have not been evaluated either by the permittee or EPA.

Unit-Specific Options. Unit-specific options involve conventional cooling towers engineered to work only with particular generating units. The permittee indicates that if one of the unit-specific cooling towers needed to be shut down –for example, due to a safety hazard from a water vapor plume– then the associated generating unit must also be shut down. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-4. EPA has learned, however, that a number of power plants around the country have wet cooling towers that are only used some of the time –for example, to address seasonal environmental concerns– and at other times are “by-passed” allowing the facility to operate in a once-through mode. See February 8, 2002, “Phone Memo” by Sharon Zaya, EPA, “Phone Call to Drew Seidel, Plant Manager at Victoria Power Station, TX;” February 8, 2002, “Phone Memo” by Sharon Zaya, EPA, “Phone Call to Tom Shusko, Plant Manager at Albright Power Station, WV;” 1/23/02 Email from Timothy Connor, EPA, to Mark Stein, EPA; 1/11/02 Email from Michael Moe, SAIC, to Mark Stein, EPA; 1/24/02 Memorandum from Mark Stein, EPA, to Brayton Point NPDES Permit File, “Notes on Telephone Conversation with Gary Kolle of Prairie Island Nuclear Generating Station in Minnesota. ” In effect, the enhanced multimode system proposed by USGenNE is a form of cooling tower “by-pass.” Therefore, EPA has also considered this possibility as a variation on the “unit-specific” options and is discussed under “Multi-Mode” options in this section.

For “unit-specific” options, EPA has considered the following:

S Closed-Cycle cooling with mechanical draft wet cooling towers for the entire facility (i.e., all units at the plant) (flow rate: 56 MGD).

S Closed-Cycle cooling with mechanical draft wet cooling towers for combinations of less than all four units (e.g., Units 1 & 2; Units 3 & 4; Units 1 or 2 & 3) (minimum flow rate: 350 MGD).

S Closed-Cycle cooling with mechanical draft wet cooling towers for Unit 3 alone (flow rate: 654 MGD).MA0003654 Determinations Document July 22, 2002

7-41 EPA believes this is a reasonable and appropriate range of options to consider for unit-specific wet mechanical draft cooling towers. These options include both single-unit and multiple-unit alternatives. Converting the entire facility would achieve the maximum reduction in flow and associated adverse environmental impacts that is available with this technology (also gaining the greatest reduction in thermal discharges). This option, however, would also be most expensive. The Unit 3 alone option would provide the greatest flow (and thermal discharge) reduction of the single-unit options since Unit 3 has the highest design flow and temperature rise of the four units at BPS. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, p. 2-2. Although Unit 4's flow and temperature rise are close to Unit 3's, Unit 3 operates far more often than Unit 4. Id . at pp. 2-2, 3.3-28. Options involving the conversion of less than all four units, but more than a single unit, provide intermediate levels of flow reduction, cost and thermal discharge reduction. As discussed in more detail below, fitting any of these options with the capacity to bypass the cooling towers and run in a once-through cooling mode would likely add some cost in terms of “piping” and pumping, seeSAIC Report (March 15, 2002), Table 5, but would enable the permittee to avoid the generating unit outages due to vapor plume-related hazards that it believes may be necessary.

Multi-Mode Options . Multi-mode options involve an arrangement of cooling towers that can operate in either closed-cycle, “helper” or “piggyback” modes to enhance flow and thermal reductions while giving the power plant greater operational flexibility and minimizing costs. The multi-mode cooling towers are not associated only with specific generating units, but, rather, draw heated effluent from the discharge canal, cool it, and recycle the cooled water back to an individual unit. As a result, they may be able to provide flow and thermal discharge reductions even if particular generating units are not in operation by cooling the hot water from other units that are in operation. The unit-specific cooling towers provide no such benefit when the associated generating unit is not operating. In other words, beyond the thermal discharge and cooling water flow reductions that occur when a particular generating unit is off-line, a multi-mode cooling system provides an additional benefit because it can be used to address the heat from other units that are operating. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, p. 3.1- 1, Tables 3.1-1 and 3.1-2. Another key aspect of the multi-mode options is that they enable the cooling towers to be “bypassed,” and generating units to remain in production, if necessary to abate water vapor plumes (as discussed in detail below). See Id . at p. 3.1-10. EPA commends the permittee for developing the multi-mode options as a operationally flexible approach to potentially retrofitting cooling towers at BPS.

The multi-mode options that EPA has considered include the following:

S The permittee’s “Basic Multi-Mode Option,” utilizing a 20-cell cooling tower;

S The permittee’s “Enhanced Multi-Mode Option,” utilizing a 20-cell cooling tower (flow rate: annual - 650 MGD (summer: 750 MGD & winter: 600 MGD); andMA0003654 Determinations Document July 22, 2002

40 For the Basic and Enhanced Multi-Mode options, the permittee evaluated a 20-cell cooling tower with “a water flow rate through the cooling tower cell of approximately 13,000 gpm." However, for the 24-, 30-, and 38-cell multi-mode cooling tower options earlier evaluated by the permittee, and described in Appendix C to Volume V of the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee considered flow rates through the cooling tower cells of only between 8,000 and 9,000 gpm. Id . at pp. C-1, C-9, C-12, C-16. As the permittee states, conditions were “optimized” only for the Basic and Enhanced Multi-Mode options, so that these 20-cell options are actually equivalent to the 30-cell option evaluated earlier by the permittee as described in Appendix C to Volume V. Id . at p. C-1.

7-42 S All of the above unit-specific Closed-Cycle cooling water options using mechanical draft wet cooling towers but designed to have the ability to operate with multi-mode capability (including bypass capability).

EPA believes the above options provide a reasonable and appropriate range of multi-mode options for consideration. The Enhanced Multi-Mode system is the permittee’s preferred option. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Executive Summary, p. 1. This option provides an additional point on the continuum of flow reductions and costs for the mechanical draft wet cooling tower options. It also offers significant operational flexibility at the plant. For these reasons, EPA believes this option warrants detailed consideration and analysis. Similarly, the Basic Multi-Mode should be evaluated because it provides another point on the flow reduction and cost continuum for which the permittee developed a significant amount of data. Id ., Vol. IV, Section 3.1.2. The Basic option, however, achieves less flow reduction and less flexibility, albeit at lower cost. Id . at Table 4-1. The Enhanced Multi-Mode option “achieve[s] further flow and heat reduction compared to the basic multi-mode system by utilizing additional piping . . . at a cost of approximately $9 million[, which] allows either Units 3 or 4 to operate in a closed-cycle mode . . . [or] would also be capable of cooling the discharge of Units 1 and 2 in a helper tower mode.” Id . at p. 3.1-15. With the Basic Multi-Mode option, only Unit 4 would be capable of operating in a closed-cycle mode. Compare Id . at Table 3.1- 1, with Table 3.1-2.

The permittee focused only on the Basic and Enhanced Multi-Mode options using a 20-cell cooling tower that could handle a flow of 260,000 gpm in order to meet its stated goal of eliminating a volume of flow equal to that represented by Unit 4. EPA has also considered multi-mode options with cooling towers to handle more than 260,000 gpm in order to achieve greater flow (and thermal discharge) reductions. It is clear that this is a practicable alternative both as a matter of common sense and because the permittee actually evaluated a “larger” multi-mode option at an earlier stage of its evaluation. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. V, Appendix C, p. C-16. Specifically, the permittee evaluated a 38-cell multi-mode cooling tower that would handle a flow of 330,000 gpm. 40 Of course, additional cooling tower cells, and additional piping and pumping capacity, would result in additional expense.MA0003654 Determinations Document July 22, 2002

7-43 **(C) Options Evaluation** 

For the most part, all the wet mechanical draft cooling tower options raise the same issues concerning potential impacts from the facilities. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, p. 4-4. Therefore, the issues for these options are discussed together. Where important distinctions can be drawn between the options, these distinctions are identified. Of course, as a general matter, the more cooling tower cells an option involves, the greater the magnitude of the potential impacts. This does not, however, necessarily mean that any such impacts are either significant or unacceptable.

Noise

. Noise can be a concern with respect to mechanical draft cooling towers if the towers are located very near to sensitive receptors (e.g., residences). Noise comes principally from the fans and possibly from water falling within the towers. See EPA TDD 2001- New Facilities, p. 3-35.

BPS is essentially surrounded on three sides by water and on one side by part of the Town of Somerset. The permittee indicates it would locate any cooling towers in a north-central area of the site. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Figures 3.3-1, 2.2-1; NEPCO January 15, 1998, NPDES Permit Application, Figure 1. The nearest residences to this area are approximately 1900 feet to the east in Somerset and approximately 1900 feet to the west across the Lee River in Gardners Neck in Swansea. See Figure 7.3-1, “Brayton Point, Somerset, MA, Distances from Proposed Cooling Towers to Sensitive Receptors (EPA, Jan. 24, 2002).

Before installing and operating any cooling towers an appropriate noise analysis will need to be done by the permittee to ensure compliance with applicable State and/or local noise standards. (There are no applicable Federal noise requirements.) That being said, EPA believes based on current information that the site configuration and the availability of various types of noise mitigation (e.g., low noise fans), if any is needed, should enable retrofitting of mechanical draft cooling towers at BPS while achieving compliance with applicable regulatory standards to prevent unacceptable impacts to the nearest receptors. See, e.g , December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3; Executive Summary, p. 8, n. 7; EPA Economic and Engineering Analysis, App. A, p. 14; Nuclear Regulatory Commission, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (NUREG-1437 Vol. 1), Section 4.3.7 (Dec.14, 2001); EPA TDD 2001- New Facilities, p. 3-35. If any special noise mitigation measures were required, it could increase the cost of cooling towers but not likely by a particularly significant degree.

Undoubtedly, noise would be greatest from a conversion of all 4 units to closed-cycle cooling(which the permittee indicates would involve 72 cooling tower cells), followed by the other multiunit options (i.e., the Units 1 & 2 (30 cells), Units 3 & 4 (42 cells), and Units 1 or 2 and 3 (37cells) options), followed by the conversion of Unit 3 (22 cells) and the Basic and Enhanced MultiMode options (20 cells). December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.3- 27. The amount of noise generated is essentially proportional to the number of cooling cells and fans required for the options. The Unit 3 and Basic and Enhanced Multi-Mode options wouldMA0003654 Determinations Document July 22, 2002

41 Moreover, the permittee did not explain why some or all of the cooling towers could not be built on the southwest portion of the site near the discharge canal, and further from the nearest residences, that the permittee has identified would be used for the helper cooling tower option if it were selected. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Figure 3.2-23. This question was asked of the permittee at the January 29, 2002 meeting and the permittee indicated that it would be significantly more expensive due to the need for lengthier “piping runs.” See 1/30/02 Email from Mark Stein, EPA, to David Webster, EPA, et al. (“Subject: Brayton - FYI). In any event, if noise were a problem, locating the towers further south might be another way to mitigate those impacts, though apparently at some cost.

7-44 yield similar noise based on the similar number of cooling tower cells and fans required. 41 Id . at pp. 3.3-27, 4-2, 4-5, 3.3-3. If a Multi-Mode option involving more cells were utilized, the extent to which it might produce more noise would depend on the number of additional cells and fans that are involved. None of this is to say that any noise issues cannot be controlled, and the permittee does not argue that noise presents a “fatal flaw” for the cooling tower options. Id

. Visual/Aesthetic Impacts. With respect to visual impacts, it cannot be denied that adding mechanical draft wet cooling towers will add additional visible industrial facilities to BPS. However, EPA does not ultimately believe that this should be regarded to be an unacceptable impact when the environmental benefits of cooling towers are considered. The permittee also has not argued that such impacts should be viewed as unacceptable.

BPS is already a huge industrial facility with large buildings, tall smoke stacks and electrical transmission lines on the site. Thus, the mechanical draft cooling towers would not be out of character with the surroundings at the plant. See Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. 6 (of 7). The unit-specific mechanical draft wet cooling towers would be built on fill at “grade elevation +30 feet (msl)” and are expected to be 65 feet “above grade” high, with the top of the tower at around +95 feet (msl), which is shorter than the existing smoke stacks (three 350-foot stacks and one 500-foot stack) and the largest building on site. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, p. 3.3-4, 3.3-10. The cooling towers included as part of the permittee’s “enhanced multimode” cooling system proposal are slightly taller, at 67 feet tall, with the top of the tower at +97 (msl).

The permittee has not concluded that any of these options would present an unacceptable visual impact. We agree with the permittee on this point. The mechanical draft cooling towers should not have the sort of dramatic adverse visual impact that might be regarded to be associated with conventional natural draft cooling towers, which are much taller. That being said, we also agree with the permittee that somewhat greater visual impacts might be imposed by the use of multiple, unit-specific options because more cooling tower cells mean additional visible facilities. Id . at pp. 3.3-3, 4-5.MA0003654 Determinations Document July 22, 2002

42USGenNE’s plume modeling analysis predicts that, on average, over the course of a year, a 20-cell cooling tower would yield 6 hours of “plume-induced” fog at nearby receptors as compared to 336 hours of natural “background fog” (i.e., a less than 2 % increase). December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), Appendix B, p. 1 (Table: Hours of Plume Induced Fogging and Icing Summary). While this analysis was performed for a different purpose, it gives an idea of the relatively

7-45 It is also possible that under certain meteorological conditions mechanical draft cooling towers may emit a visible plume into the air or create fog that could constitute an adverse visual impact. ( See discussion of possible plume effects on traffic safety below.) This may occur when ambient air temperatures are low, as compared to plume temperatures, and ambient humidity levels are high. The former condition promotes plume cooling and condensation, whereas the latter condition inhibits evaporation of the water in the plume. The direction and persistence of the plume would be determined by a number of factors including wind speed and direction, relative temperatures and humidity, the time needed for evaporation and dispersion, and the design of the cooling towers in question. Typically, however, a vapor plume will not be visible to off-site observers and/or will dissipate after traveling only a short distance due to dispersion and evaporation. See EPA TDD 2001- New Facilities, p. 3-33; Badger Power EIS, p. 54; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. 6 (of 7); “AES Londonderry Highlights” (p. 6 of 7) (AES, Inc., 1/18/02), p. 6 (of 7).

With respect to potential visual impacts from a visible plume from mechanical draft wet cooling towers at BPS, EPA notes that while our October 1982 Permit Modification Determination, at pp. 19-20, indicated that salt drift was the primary problem with the former Unit 4 spray pod cooling system, which sprayed warm water directly into the air for cooling, EPA stated that the system also created fog that was an undesirable impact for the local community. EPA believes that any fogging from new mechanical draft cooling towers would be either nonexistent or much less than was experienced with the old spray pod system. Mechanical draft towers do not throw the water directly into the air like the spray pod system. In addition, the towers would be equipped with drift eliminators that would remove water droplets and reduce drift to a rate of 0.0005%. See December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, p. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974) . This should mean a vastly reduced tendency to create visible fog as compared to the spray pod system and should reduce the density of any visible plume. Moreover, any fogging that does occur would typically be most severe on the plant site close to the towers. Finally, during at least some of the conditions when cooling tower fog might occur, naturally occurring fog is also likely to occur in the coastal environment of BPS. See 3/4/02 Memorandum from Mark Stein, EPA, to Brayton Point NPDES Permit File, “Memorandum to File re 2/21/02 Visit to Brayton Point Station for Meeting.” Under such conditions, fogging from the cooling towers would present only a small marginal increase over background conditions. 42MA0003654 Determinations Document July 22, 2002

small marginal effect of the cooling towers on fog.

7-46 In sum, EPA does not believe that the visible plume or any fogging from the cooling towers should be regarded as imposing an unacceptable adverse visual/aesthetic impact. Any adverse visual impact from cooling towers is relatively insignificant when compared to the major environmental benefit they could provide to the Mount Hope Bay ecosystem and fishery. See alsoEPA TDD 2001- New Facilities, p. 3-34. Potential local concerns about possible visible plumes or fog might also diminish when people learn that any such visible plume is merely water vapor –rather than any smog precursors or toxic air pollutants, for example– from cooling towers which have been installed to protect the fishery of the Mount Hope Bay estuary. In any event, while EPA does not believe this problem should be significant, it is clear that visible plume and fogging issues, if any, would be progressively worse for the alternatives involving more cooling tower cells. In addition, before installation of cooling towers, all applicable air emission standards will need to be satisfied.

Traffic Safety (Fogging, Icing). Another issue to be considered for a wet cooling tower such as would be used at BPS is whether there will be emissions of mist (i.e., water droplets) or water vapor that could cause a traffic hazard on nearby roadways due to fogging or icing. Protecting public health and safety is at the top of the priority list for EPA and the other involved state and federal agencies. Therefore, we take this issue seriously and have evaluated it from several perspectives.

The permittee has indicated that it believes that cooling towers at BPS would emit a vapor plume that could cause a fogging/icing traffic safety concern on nearby portions of Route 195 and the Braga Bridge. See, e.g. , December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3. The permittee also indicates that it would have to shut down the cooling tower during these periods to eliminate this potential hazard. Id . The permittee states that this would substantially increase the cost of the unit-specific options because shutting down the cooling towers also requires shutting down the associated generating units. The permittee states that these increased costs can be avoided for the multi-mode options, however, because the cooling towers can be shutdown if necessary to prevent fog or ice and the generating units can continue to operate in the once-through mode. This contributes to the permittee’s preference for the Enhanced Multi-Mode option from the perspective of cost and operational flexibility.

Based on current information, EPA’s assessment of the fogging/icing traffic safety issue is that it is uncertain whether this problem would occur to a significant degree if cooling towers are installed at BPS, but that there are several ways to eliminate the problem if it does occur. Methods for managing this potential problem are discussed below, along with the uncertainties surrounding the magnitude of the problem. Following that discussion, reasons for uncertainty regarding the likely extent of any problem are presented.

Cooling towers can be equipped with highly efficient mist (or “drift”) eliminators that can nearly eliminate the emission of water droplets (and salt) from a wet mechanical draft tower. As the permitteeMA0003654 Determinations Document July 22, 2002

7-47 explains, such drift eliminators can achieve a drift rate of 0.0005%, which would represent only a very small marginal increase over the moisture naturally in the air in a coastal environment such as that around BPS. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974). As a result, mist emissions should not significantly contribute to fogging or icing.

However, as the permittee indicates, mechanical draft wet cooling towers also emit water vapor (as opposed to mist ). See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3, n. 7. U nder certain meteorological conditions, this water vapor could condense and cause ice on road surfaces and/or fog. The permittee has conducted a site-specific modeling analysis based on a 20-cell cooling tower that predicts that such a cooling tower at BPS would emit a plume of water vapor that under certain meteorological conditions could cause fogging or icing on certain nearby “receptors.” See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001). The permittee has also concluded that this fogging or icing could cause a traffic safety problem on Route 195 and the Braga Bridge. Id . at p. 3-3.

The company’s fogging and icing analysis is based on a CalPuff modeling analysis using, among other things, meteorological data from T.F. Green Airport in Providence, RI, from 1989 to 1993. This analysis estimates that in an average year there are 343 hours of “background fog and ice” (fog: 336 hours/ice: 7 hours) near the plant and the cooling tower would add 7 hours of “plume-induced fog and ice” (fog: 6 hours/ice: 1 hour). This represents only a two percent (2%) increase over background conditions. In addition, the analysis predicts that 4 of these hours of fog or ice would “impact the highway and bridge.” December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), p. 9 (of 13) and Appendix B, p. 1 (Table entitled, “Hours of Plume Induced Fogging and Icing Summary”).

Nevertheless, the permittee’s modeling analysis also concludes that this fogging or icing threat to the highway or bridge would require cooling tower “plume outages” an average of 54 times a year for an average total duration during the year of 166 hours. Id . This is more than 41 times the number of predicted hours of plume-induced fog or ice at the highway and bridge (4 x 41.5 = 166). The permittee explains that this is because in order to prevent fog or ice beforeit occurs, the permittee would have to shut down the tower and generating unit whenever certain meteorological conditions occur that might lead to fog and ice, and that such conditions occur more frequently than actual fog or ice and may persist for several hours at a time. Id . at p. 8 (of 13). The permittee also states that the problem would be more severe if more than 20 cooling tower cells were utilized at the power plant. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3, 3-4, 4-6; Vol. III, App. G (Dynamic Cost Analysis, p. 7). In addition, the permittee states that generating unit outages are made even longer due to the 5 to 12 hours necessary to get a generating unit back on-line after it has been taken off-line. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab:MA0003654 Determinations Document July 22, 2002

7-48 Section 308 Information Request Submittal - 9/10/01), Attachment A, p. 10 of 13. Indeed, in the permittee’s Dynamic Cost Analysis , the permittee assumes that 648hours of generating unit outages per year would occur for the Unit 3 Closed-Cycle option, based on 54 outages and 12 hours of unit restart time, and that 486

hours per year of outage for units 1, 2 and 3 would occur for the Entire Station Closed-Cycle option based on 54 outages with 9 hours of restart time per unit. Id . Vol. III (Tab: Dynamic Cost Analysis), Unit 3 Conventional Closed Cycle Spread Sheet, p. 3 of 8. The 648 and 486 hours of predicted outage are 162 and 121 times more than the 4 hours of additional fog or ice actually predicted by the permittee’s model to affect the highway and bridge in the average year.

As mentioned above, because the permittee concludes that water vapor plumes will lead to required cooling tower shutdowns and associated generating unit shutdowns for the unit-specific cooling tower options, the permittee has included a substantial cost for hundreds of hours of “plume outages” for the unit-specific options. The permittee has not included such costs for the multi-mode options because the cooling towers can be bypassed, assuming such a bypass will still enable the permittee to meet its permitted heat and flow limits. The cost of the outages reflects lost profits due to the outages. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-4, Section 4-6, Table 4-1; Vol. III, App. G (Tab: Dynamic Cost Analysis, pp. 7-8; Tab: Section 308 Information Request Submittal - 9/10/01, p. 4).

EPA has looked at the plume/safety issue from a number of perspectives. Most importantly, EPA has concluded that to the extent a traffic safety issue may exist, there are several ways to adequately control it. First, as the permittee has indicated, if necessary, a cooling tower and associated generating unit could be shut down for a short period to avoid a safety issue. The permittee has indicated that it would expect to undertake such shutdowns if necessary. With the multi-mode options, of course, the permittee could shut down the cooling towers but continue to operate the generating units. Likewise, EPA believes that the unit-specific options could be engineered to allow the cooling towers to be bypassed so that the generating units could be operated in once-through mode during the period of any plume-related safety hazard. As discussed above, EPA has learned that a number of power plants around the country have cooling towers that are only used some of the time, so this is clearly a practicable approach. This approach may add some cost, due to piping or pumping needs, but any such costs would most likely be less expensive than the permittee’s predicted generating unit outages. Indeed, the ability to bypass the cooling towers is one key aspect of the multi-mode cooling tower operations. EPA’s evaluation estimated what the costs to operate in various multi-mode fashions might be and found them to be less than the cost of the outages. See SAIC Report (March 15, 2002), p. 15, Table 5; Abt Report (April 5, 2002), p. 8. (Costs are discussed more fully below.) Of course, the plant would still need to operate within its overall permit limits for flow, maximum-temperature, ) -T, and Btu loadings, but this is also true for the multi-mode options.

Second, when it is predicted that potentially hazardous fog or ice conditions might occur as a result of the cooling towers, instead of shutting the towers down, it might be feasible to develop an early warning system according to which the permittee would notify the Massachusetts Highway Department in orderMA0003654 Determinations Document July 22, 2002

7-49 to initiate icing controls (e.g., salting of roads) or activate lighted cautionary signs warning of potential fog conditions. 4/9/02 Memorandum by Damien Houlihan (EPA), “Re: Record of 4/9/04 Conference Call with MA DEP and Massachusetts Highway Department.” As discussed above, the permittee’s analysis predicts only a small marginal increase in fog and ice conditions from background, and the Massachusetts Highway Department already has programs in place for dealing with these background conditions.

Third, there are also plume abatement technologies that can be utilized with mechanical draft cooling towers to substantially reduce or eliminate vapor plume effects. These technologies are generally referred to as “wet/dry” or “hybrid” cooling towers. See EPA TDD 2001- New Facilities, p. 3-33; January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey; Materials obtained from Marley Cooling Technologies, Inc.; Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), Executive Summary, p. xii; “AES Londonderry Highlights” (p. 6 of 7) (AES, Inc., 1/18/02). Switching to hybrid cooling towers would, however, significantly increase the capital cost of the equipment and reduce electrical generation efficiency somewhat more than wet cooling towers. EPA’s consultants have estimated that adding plume abatement could more than double the capital cost of the cooling towers without plume abatement. See SAIC Report (March 15, 2002), p. 15, Table 5. See also66 Fed. Reg. 65283 (Dec. 18, 2001) (costs of dry cooling compared to costs of hybrid cooling and wet cooling); 1/31/02 Email from Richard Scogland, Marley Cooling Technologies, to Sharon Zaya, EPA, “Subject: Cost Estimate for Marley’s Clearflow;” 2/1/02 Email from Kenneth Detmer, Wisconsin Public Service Commission, to Mark Stein, EPA, “Subject: Cooling Towers;” January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey. However, despite these capital costs, EPA “... estimates the increase in overall project costs for a [retrofitted] hybrid wet/dry cooling tower unit over a wet (only) unit would range between 20 and 65 percent.” EPA TDD 2002- Existing Facilities, p.6-6. EPA further notes that Power Tech Associates, a consultant who estimated the costs of cooling system conversion for Hudson River power plants, states that “the effect of using wet/dry towers is much less than a 25 percent increase in the overall conversion costs.” Id . p. 6-6.

Another interesting alternative to abate plume effects would be to add more cells to the cooling towers. This would lessen any potential impacts because the factors determining cooling tower impact are the quantity of heat being disposed of and the air volume into which that waste heat is being rejected. A system with additional cooling tower cells, may have far less impact than the one with fewer cells, because more air flow is used. Neither EPA nor USGenNE has evaluated this option, but clearly an analysis of this option could be performed in order to determine its feasability and costs. See memo from Kirk Winges, Senior Atmospheric Scientists from MFG, Inc, entitled “Comments on “Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station,” dated September 2001"MA0003654 Determinations Document July 22, 2002

7-50 Ultimately, of course, the permittee may choose whichever method, or combination of methods, it wants from the several practicable approaches should the need for plume abatement arise. The choice of method would most likely be determined by the cost and the permittee’s operational preferences. At present, the permittee indicates that it prefers the Enhanced Multi-Mode option because, among other things, the cooling towers could be shut down to avoid plume hazards without requiring generating unit outages. This option, however, achieves less flow and thermal discharge reductions than any of the unit-specific options. For the unit-specific options, the permittee indicates it would engage in generating unit shutdowns to prevent plume-related hazards, but that these outages result in substantial cost to the company. EPA has concluded, however, that engineering a “bypass” of the cooling towers would likely be a less expensive, practicable alternative in the long-run for the unit-specific options. Alternatively, an early warning system in conjunction with the Massachusetts Highway Department might be sufficient to avoid either outages or cooling tower bypass. This would require further consultation and coordination between the Department, the permittee, EPA and the MA DEP. A more expensive option, but one that would maximize operational flexibility and the flow and thermal discharge reductions achievable by the unit-specific options, would be to install hybrid cooling. (The company also might want to consider, at a minimum, installing cooling towers that are amenable to retrofitting with plume abatement technology at a later date.)

Having addressed the issue of how to abate any plume hazards, EPA must also state that, based on current information, we believe it is uncertain that cooling towers at BPS would emit a vapor plume that would become a traffic hazard on the highway or bridge. It is also uncertain whether the hours of potential hazard predicted by the permittee would actually require generating units using cooling towers to be shut down for hundreds of hours per year in order to achieve our clear priority of ensuring public safety.

There are several reasons why the EPA believes that there is substantial uncertainty over whether the plume problem will be as severe as the permittee asserts. First, EPA has reviewed the permittee’s air modeling analysis and has a number of concerns and questions about it. While the “CALPUFF” model used by the permittee is certainly acceptable for certain air modeling purposes, the question is whether the model and the pre- and post-processors used with the model were appropriate for the purpose of assessing the plume issue in this case, especially when compared to other models that have been developed more specifically for modeling cooling tower plumes (such as the SACTI model developed by EPRI). See May 7, 2002 memorandum from Martha Seagall to Damien Houlihan containing MFG, Inc. Review of CALPUFF Model, January 3, 2002, Memorandum from Brian Hennessey, EPA, Through Steven Rapp, EPA, to Mark Stein, EPA (“Air Impact Analysis of Evaporative Cooling for Brayton Point Generating Station (Somerset, Massachusetts)); 12/11/01 Email from John Irwin, EPA, to Warren Peters, EPA, et al. (cc: Brian Hennessey, EPA, et al.); 12/05/01 Email from Warren Peters, EPA, to Brian Hennessey, EPA (cc: Joe Touma, EPA, John Irwin, EPA, et al.); December 10, 2001, Phone Memo from Sharon Zaya, EPA, Regarding Call with Gary Mirsky, P.E. Hamon Cooling Towers, N.J. January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey; 2/1/02 Email from Kenneth Detmer, Wisconsin Public ServiceMA0003654 Determinations Document July 22, 2002

7-51 Commission, to Mark Stein, EPA, “Subject: Cooling Towers” (expressing opinion that CALPUFF model works for wet/dry cooling tower evaluations, but uncertain about using it for traditional wet towers). EPA does not presently believe that the permittee has established the reasonableness of its modeling analysis.

Second, experience at the other plants does not appear to corroborate the threat suggested by the permittee. EPA spoke with representatives of two power plants that use mechanical draft cooling towers and learned that any icing concerns at these facilities are limited to areas very close to the cooling towers themselves (within a few hundred feet) and had not effected roadways or bridges within relatively short distances from the cooling towers (in one case within approximately a half-mile, and in another case within around 700 feet). January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey ; 12/12/01 Memorandum from Mark Stein to Brayton Point NPDES Permit File (“Brief Notes on an Issue Discussed During Conference Call with John Gulvas of Consumers Energy and the Palisades Nuclear power station in Covert, Michigan”); 39 Fed. Reg. 36192 (October 8, 1974). See also Nuclear Regulatory Commission, Generic Environmental Impact Statement for License Renewal of Nuclear Plants (NUREG-1437 Vol. 1), Sections 4.3.4.2, 4.3.5.1.1, 4.3.5.1.3 (Dec. 14, 2001). Neither icing nor fogging appeared to create a problem in any of the situations referenced above. One facility did install a wet/dry system to enable it to remove a visible plume due to initial concerns over potential highway icing or fogging, but this facility reported to EPA that it did not turn out to be a problem in practice. The facility only uses the “dry components” to mitigate an aesthetic issue related to a periodically visible plume of fog during humid conditions. January 4, 2002, Phone Memo from Sharon Zaya, EPA, Regarding Call with Ken Daledda, Bergen Station, New Jersey. Additionally, EPA identified 16 facilities with full-recirculating cooling systems and very large megawatt capacities that were within close proximity (that is, several yards to several hundred yards) to major highways, navigable rives and lakes, and railways. Only one of these facilities (Bergen Generating Station as discussed above) utilize a form of plume abatement. The other plants utilize either natural draft or mechanical draft wet towers. See EPA TDD 2002 - Existing Facilities, p. 6-7.

Third, EPA notes that in the January 1997 NEPCO Report, at p. 3-21, the permittee predicted that although “incidence of ground fog can occur during periods of high relative humidity, cool weather, moderate to low winds and inversions or some combination thereof . . . [, i]t is unlikely however that the fog would extend further than 500 to 1,000 feet downwind of the towers.” No concern was expressed about off-site icing. Furthermore, in the December 2001 USGenNE 316(a) and (b) Demonstration, the permittee explained that the helper towers are identical to the mechanical draft cooling towers, seeVol. IV, pp. 3-1, 3.2-1, and that even for the 48-cell helper tower “[f]ogging during cool wet weather, and when temperatures are cold enough, icing are expected to rarely be an issue with the helper tower design since these are local effects and the helper towers are located near the discharge canal and further away from the highway and bridge than the multi-mode or closed-cycle alternatives.” Id . Vol. IV, p. 3.2-19. The area near the discharge canal appears to be only around 500 feet or less further from the highway and bridge. See Figure 7.3-1, “Brayton Point, Somerset, MA, Distances from Proposed Cooling Towers toMA0003654 Determinations Document July 22, 2002

43 It is also worth noting that Badger Generating Company, LLC, an affiliate of PG&E operating in Wisconsin, proposed a new combined-cycle natural gas electric generating plant in the village of Pleasant Prarie, WI, that would use hybrid wet/dry cooling towers to control any threat of fogging or icing on roadways surrounding the facility. With the hybrid cooling towers, the analysis concluded that only a few hours per year of fogging and/or icing would result on certain roads immediately surrounding the plant. There was no suggestion, however, that these few hours of predicted fog or ice required many times more hours of generating unit outages, or indeed any outages at all, to eliminate all possibility of any fog or ice. In addition, the company argued that “[o]n days of rain, fog, snowfall, or blowing snow . . . plant-induced fogging and icing would not be important, since

7-52 Sensitive Receptors (EPA, Jan. 24, 2002). Although permittee expresses particular concern over fogging and icing impacts to Route 195 and the Braga Bridge, the bridge appears to be approximately 5000 feet (0.95 miles) from where the cooling towers would be located, while the nearest point on Route 195 is approximately 2164 feet away (0.41 miles), and the nearest residential streets are approximately 1900 feet away (0.36 miles). See Figure 7.3-1, “Brayton Point, Somerset, MA, Distances from Proposed Cooling Towers to Sensitive Receptors (EPA, Jan. 24, 2002). Moreover, moving the cooling towers further to the south on the site into the area that the permittee suggested the helper towers could be located would add even more distance and make any potential problems even less likely. See December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, Figure 3.2-19, 3.2-23. See also n. 48, supra

. Fourth, as a matter of common sense, it does not seem that the problem should be severe enough to require hundreds of hours of generating unit outages. The permittee’s own analysis confirms that in the coastal environment of Mount Hope Bay, the local roads and highways of this area periodically experience icing and fogging from natural conditions which is managed by local highway safety programs. The permittee’s analysis predicts that a 20-cell cooling tower would add only a small marginal increase in fogging and icing (around 2%) over background conditions in an average year. This average increase is well within the range of natural fluctuation in background conditions. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), Appendix B, p. 1 (Table: Hours of Plume Induced Fogging and Icing Summary). Again, the permittee predicted that in an average year only 1 hour of “plume-induced ice”and only 6 hours of “plume-induced fog” would occur, as compared to 343 hours of “background fog and ice” (a 2 % increase). Only 4 of these hours of plume-induced fog or ice were predicted to “impact the highway and bridge.” In response to this, the permittee predicts that literally hundreds of hours of unit outages per year would be needed to eliminate this potential plume effect. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. III (Tab: Section 308 Information Request Submittal - 9/10/01, Report on Fogging and Icing Effects Associated with Cooling Towers at Brayton Point Station (September 2001), p. 9 (of 13) and Appendix B, p. 1 (Table: Hours of Plume Induced Fogging and Icing Summary). As discussed above, this seems unrealistic based on common sense and experience at other plants, and we are not yet persuaded of the validity of the permittee’s modeling analysis. 43MA0003654 Determinations Document July 22, 2002

there might already be fog and ice on Pleasant Prairie roads and drivers would already be more cautious.” The Public Service Commission and the Department of Natural Resources of the State of Wisconsin considered the potential for additional fogging and icing to be a concern but were satisfied with the few hours that would be left after the installation of hybrid cooling. Thus, the State approved the facility recognizing the small number of hours of plant-induced fogging and/or icing that might occur. See Public Service Commission of Wisconsin/Wisconsin Department of Natural Resources, Final Environmental Impact Statement, Badger Generating Company, LLC, Electric Generation and Transmission Facilities (June 2000, 9340-CE-100), pp. xi, 73-74, 137-138; see alsoExecutive Summary.

7-53 Nevertheless, as stated above, the permittee proposes to deal with possible plume hazards from the unit-specific options by shutting down generating units and their associated cooling towers during conditions when it believes the risk exists. As a result, the permittee has included the cost of such outages in the costs of the closed-cycle cooling tower options. Because of EPA’s uncertainty about the likely need for these outages, EPA has evaluated the costs of these options under the following three scenarios: (a) accepting the permittee’s estimate of plume outages, (b) assuming half the plume outages predicted by the permittee, and (c) assuming no plume outages (but adding capital costs to equip the unit-specific cooling tower options to operate in a multi-mode fashion). EPA’s economic analysis is presented further below.

Salt Drift. With any salt water cooling tower, one must consider the issue of salt emissions from the towers. This should not be a significant problem at BPS, however, because the towers can be equipped with drift eliminators that reduce drift to 0.0005%. As the permittee has indicated, this would produce a rate of drift “several orders of magnitude lower than the total emissions from the past operation of the Unit 4 spray canal.” See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, p. 3-3, 3.3-3. See also 39 Fed. Reg. 36189 (October 8, 1974) . It would also produce “salt deposition and saline air concentrations that represent only a slight increase over ambient coastal conditions.” December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3-3. See also EPA TDD 2001 - New Facilities , pp. 3-34 and 3-35; January 1997 NEPCO Report, at p. 3-21

. However, to the extent that residential icing caused by salt drift is actually an issue, the concern would be greater from the options that involve more cooling towers and the placement of the cooling towers at the site. Any cooling towers that are installed and operated at BPS will, of course, have to comply with all applicable air emissions requirements (e.g., particulate emissions).

Energy Issues. One detriment of switching BPS from open-cycle cooling to closed-cycle cooling is that the change would marginally decrease the generating efficiency of each converted unit (“efficiency penalty”). See EPA TDD 2001 - New Facilities, p. 3-10, Table 3-2, pp. 3-9 to 3-21. In addition, the amount of electricity that a converted unit generates for sale is further reduced because a certain amount of energy must be used to run the fans and pumps utilized in a mechanical draft cooling tower (“auxiliary power penalty”).MA0003654 Determinations Document July 22, 2002

7-54 EPA estimates that for a conversion to wet mechanical draft cooling towers, assuming a 100% load factor, the annual efficiency losses would be approximately 0.29% for Units 1, 2 and 3, and 0.09% for Unit 4 (assuming current levels of “piggyback” operations). See SAIC Report (March 15, 2002), Table 9. See also EPA TDD 2001 - New Facilities, Table 3-14. The efficiency losses would increase to 0.75% for Units 1, 2 and 3, and 0.18% for Unit 4, assuming a load factor of 67%. See SAIC Report (March 15, 2002), Table 9. See also EPA TDD 2001 - New Facilities, Table 3-15. Since BPS Units 1, 2 and 3 are base-load units with a capacity factor of approximately 80%, the penalties are expected to be in between the two sets of figures. See EPA TDD 2001 - New Facilities, p. 3-10. Since Unit 4 has a much lower capacity factor of around 20%, its penalty figures would likely be somewhat higher than those for the 67% load factor. Because Unit 4 operates less, however, the efficiency penalty for that unit would have a relatively smaller effect on the overall efficiency of the plant. See SAIC Report (March 15, 2002), p. 21. Itshould be noted that EPA’s estimated efficiency penalties for the Enhanced Multi-Mode, ClosedCycle Units 1 & 2, Closed-Cycle Unit 3, and Closed-Cycle Entire Station Units options range from 58% to 77% lower than those predicted by the permittee. Id . at Table 10.

The company also predicts that the unit-specific options will result in greater lost generation than the multi-mode options, seeDecember 2001 USGenNE 316(a) and (b) Demonstration, Vol. IV, Table 4-1, because the multi-mode systems have “more flexibility to operate at a higher performance relative to the structure’s size under a greater variety of atmospheric conditions than any of the other cooling tower alternatives.” Id . at Section 4.7. This relates, at least in part, to the permittee’s predictions of plume outages for the unit-specific options but not for the multi-modeoptions. As discussed above, however, EPA has concluded that it is uncertain that the plumerelated problems will be as significant as the permittee predicts and that there are potential methods for controlling any such problems other than resorting to unit outages.

In light of our consultant’s analysis, EPA believes the permittee’s estimates of auxiliary power penalties are reasonable. See SAIC Report (March 15, 2002), p. 30. For some alternatives, EPA’s estimates are lower, whereas for other alternatives EPA’s estimates are higher. See SAIC Report (March 15, 2002), Table 7. See also EPA TDD 2001 - New Facilities, pp. 3-22 to 3-30, Table 3- 20.

On one level these various penalties represent an economic issue (i.e., lost revenues due to reduced sales of electricity). Therefore, the company considered these penalties in its economic evaluation of the alternatives, seeDecember 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G (Tab: Dynamic Cost Analysis), and EPA has done the same. See Abt Report (April 5, 2002), pp. 21-22. EPA’s economic analysis is presented further below.

On another level, these penalties raise energy supply issues that should be considered. Having done so, however, EPA does not believe that these penalties are significant from an energy perspective, especially when considered in light of the major reduction in adverse impacts from the CWIS (and from thermal discharges) that could be provided by a closed-cycle cooling system. EPA’s research indicates that New England has an adequate power supply at present and isMA0003654 Determinations Document July 22, 2002

44Interestingly, according to a recent article in the Salem Evening News(“PG&E Drops AllCoal Plan,” December 20, 2001), USGenNE recently decided to drop its plans to expand at its Salem, MA, power plant. A company official was quoted as explaining the decision by stating, “the supply (of power) [in New England] is far outstripping the demand.”

7-55 predicted to have an adequate supply moving into the future, thanks in part to the construction and proposal of new power plants that have added, and will continue to add, generating capacity to the supply inventory in the Region. See, e.g. , EPA-New England, Energy Fact Sheet (Feb. 12, 2001); “NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission, 2001 - 2010 (ISO-NE: April 1, 2001), pp. 1-2 (Section I Summaries, Summer and Winter System Capabilities and Peak Load Forecasts). Therefore, neither the small marginal loss in efficiency nor the small marginal increase in energy use that would result from converting to closed-cycle cooling at BPS presents a significant problem for the Region’s energy supply. See SAIC Report (March 15, 2002), Tables 6, 7, 9, 10 and 11 (USGenNE and SAIC independent estimates of reduction in energy produced for sale by BPS due to the Closed-Cycle Entire Station units option are 3.3% and 2.6%, respectively); see also EPA TDD 2001 - New Facilities, Tables 3-1, 3-2, 3-14, 3-15, 3-20. 44 Moreover, as new, more efficient plants continue to come on line, the overall efficiency of the Region’s energy supply will increase even if BPS has a marginal loss of efficiency due to shiftingentirely or partially to closed-cycle cooling. For example, the proliferation of new, combinedcycle power plants will significantly increase the overall efficiency of the Region’s power supply and more than offset any lost efficiency from closed-cycle cooling at BPS. See EPA TDD 2001 - New Facilities, p. 3-8.

In addition, there is at least one potentially significant energy benefitprovided by shifting to closedcycle cooling. The permittee has determined that improved cooling will enable it to operate more at peak demand times during the hottest days of the year – assuming compliance with applicable air pollution standards – because the plant will less frequently threaten to exceed the permit’s current maximum temperature limit of 95° F. See December 2001 USGenNE 316(a) and (b) Demonstration, Vol. III, App. G, (Tab: Dynamic Cost Analysis, p. 4). This not only enables the plant to sell more electricity during the peak pricing period, which benefits the permittee economically, but it also may benefit the Region’s overall power supply because that supply is most likely to be overstretched, if ever, during the hottest days of the year when peak demand

occurs. See Abt Report (April 5, 2002), pp. 12, 23-24. With cooling towers, BPS will be able to generate more power to help meet this peak demand. (It should also be noted, however, that this benefit may be marginally offset by the fact that efficiency penalties are likely to be somewhat greater during the hot summer days.) See EPA TDD 2001 - New Facilities, p. 3-9.

Plant Reliability, Operational Flexibility, and Construction-Related Outages. The permittee argues that the unit-specific cooling tower alternatives, but not the multi-mode options, reduce plant reliability because of the potential for plume-related outages in the winter, attributed to fogging/icing problems. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 4.5. Any problem in this regard would be more severe for the options using more cooling towers. As explainedMA0003654 Determinations Document July 22, 2002

7-56 above, however, EPA believes that plume-related hazards of the magnitude suggested by the permittee are uncertain and that there are potential methods of controlling any such hazards without generating unit outages.

Nevertheless, if such temporary outages were to occur, as predicted by the permittee, it would ultimately represent an economic issue to the permittee rather than an energy supply problem to the Region. It is unlikely that any such temporary, intermittent outages would jeopardize the adequacy of the Region’s power supply because that supply is constituted and managed to respond to occasional scheduled and unscheduled outages while maintaining adequate power. Any plume-related outages would similarly be managed without supply shortfalls. In addition, as discussed above, adding cooling tower technology is expected to enable BPS to generate somewhat more electricity during peak summer demand periods. This may help the Region’s power supply at the time it is most stressed.

For the installation of any of the closed-cycle cooling tower options at BPS, the permittee also predicts generating unit outages “for the tie into . . . the generating units . . . [to] complete the cooling system conversion.” December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 4.9. Unlike plume outages, construction outages are one-time events. Although any such outages would be sequenced to coincide with regularly scheduled maintenance outages, the permittee predicts that the construction outages would exceed the duration of the regular maintenance outages and, therefore, represent additional downtime for the units involved. The permittee predicts that these outages will be somewhat greater for the site-specific options than the multi-mode options. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 4.8, Table 4-1 (e.g., 5.5 months for the Enhanced Multi-Mode option; 8 months for the Closed-Cycle Unit 3 option).

There is no reason to expect that these one-time outages should endanger the Region’s power supply. The Regional power supply is already managed to accommodate periodic scheduled and unscheduled outages without a shortfall in capacity. There is nothing to suggest that the type of outages discussed here could not be handled in this manner. These outages could also, if necessary, be scheduled and sequenced to avoid peak demand periods. Ultimately, any such outages represent an economic issue for the permittee and both EPA and the permittee have evaluated such outages in our economic analyses, as discussed below. It should also be noted here that, as an engineering matter, EPA believes that the permittee has overestimated the necessary construction outages based on research concerning other plants that have converted their cooling systems from once-through to closed-cycle cooling
towers. See SAIC Report (March 15, 2002), pp. 25 - 29 and Attachment A; Memorandum from Nick Prodany and Mark Stein to Brayton Point NPDES Permit File, “Notes on Telephone Call with Engineer at Canadys Station power plant in South Carolina.”

Air Pollutant Emissions. Another issue that must be addressed is the possibility that due to lost efficiency as a result of installing cooling towers, a power plant would burn more fuel in an effort to make up for lost electricity generation and thus produce increased air emissions. This should not,MA0003654 Determinations Document July 22, 2002

45 Given that fuel is currently barged to the plant, it may also be feasible to bring some materials to the site by water so as to minimize truck traffic on streets surrounding the plant.

7-57 however, be an issue at BPS because the permittee has indicated that due to the fixed steam capacity of the boilers at BPS, the plant cannot actually burn more fuel to make more steam and generate more electricity in response to efficiency losses due to cooling towers. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III, App. G, (Tab: Dynamic Cost Analysis, p. 4). See also EPA TDD 2001 - New Facilities , p. 3-31 to 3-33. Instead, any needed lost megawatt-hours from BPS due to cooling tower-related penalties would be replaced by generation at other plants. It is more than likely that these other plants will be similar or cleaner burning facilities, given that BPS is an old coal burning plant. Therefore, the marginal penalties discussed above are likely, in turn, to lead to no changes in air pollutant emissions at BPS and only very marginal changes across the Region. Id . Moreover, it must be understood that any emission increases would be limited by applicable air pollution standards. Since the MA DEP has recently promulgated new air pollution standards that apply to BPS and will require significantly reduced air emissions from the plant (and several other major, older power plants), see310 CMR 7.29, the overall air emissions from this plant will be substantially reduced compared to current levels regardless of whether the plant burned marginally more fuel to make up for efficiency losses due to cooling towers. In addition, these new regulations will also lead to substantial overall emission reductions in Massachusetts. EPA reiterates that any new cooling towers will be subject to air permitting requirements and will obviously need to satisfy all applicable air pollution standards (e.g., standards for particulate emissions).

Construction Effects. As the permittee states, all the cooling tower options raise the likelihood of some “moderate” noise and truck traffic effects from construction activities. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 4-4. It should also be noted that construction for new air pollution control equipment will be occurring during a similar time-frame. Ultimately, some construction effects cannot be avoided if improvements are to be made to reduce the plant’s adverse water and air impacts on the environment. However, no filling of wetlands or tidelands should be needed for any of the construction. Moreover, the industrial nature of the site and existing facilities, as well as the large size and buffering capacity of the site, should moderate the impacts of construction. Any effects would be further reduced if the facilities were constructed in areas farther from local residences, and all local traffic and noise ordinances will obviously have to be complied with. 45 It should also be noted that, as proposed by the permittee, the multi-mode and single-unit options haveroughly similar construction durations of 13 months for the Unit 3 option, and 16 months for the multimode options, whereas the multiple-unit options have longer construction periods of 21 months for the Unit 1 & 2 option and 32 months for the entire facility option. December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, Table 4-1, Vol. V - Appendix B (Tabs B6, B7, B13, B15, B16). Thus, construction effects would undoubtedly increase as more units are converted to new cooling systems.MA0003654 Determinations Document July 22, 2002

7-58 **(D) Conclusions as to Wet Cooling Towers and Options**  **Carried for Detailed Review**

In sum, EPA believes that several potential options for retrofitting BPS with closed-cycle cooling with mechanical draft wet cooling towers warrant further detailed consideration in light of biological, engineering and economic factors. Generally, this technology can achieve significant reductions in adverse environmental impacts by reducing flow through the CWIS, as well as reducing thermal discharge. Although retrofitting this technology to BPS presents a number of economic, engineering, and environmental issues, none of these issues appear to present a fatal flaw for these options at this stage of our analysis.

The various mechanical draft wet cooling tower options that EPA has decided to carry forward for further analysis provide different increments of flow (as well as thermal discharge) reduction, different degrees of potential environmental concern, and different costs. They also include both unit-specific and multi-mode options that address either all or a portion of the generating units at BPS. As a result, an appropriate range of viable options is retained for more detailed consideration. EPA’s more detailed review includes a thorough, independent evaluation of the costs of these options, and a determination of whether or not these costs are wholly disproportionate to the environmental benefits they would provide. These detailed evaluations are presented further below.

EPA believes that the following options should receive further detailed consideration:

(A) Closed-Cycle Cooling with “Unit-Specific” Mechanical Draft Wet Cooling Towers for Unit 3 alone (flow rate: 654 MGD); (B) Closed-Cycle Cooling with “Unit Specific” Mechanical Draft Wet Cooling Towersfor Units 1 or 2 & 3 (flow rate: 350 MGD); (C) Any of the above options engineered to allow a multi-mode capabilities, without shutting down generating units; (D) Closed-Cycle Cooling with “Unit Specific” Mechanical Draft Wet Cooling Towers for the Entire Station (i.e., all four units) (with by-pass capability) (56 MGD); and (E) The permittee’s Enhanced Multi-Mode system (with 20 cooling tower cells) (flow rate: annual - 650 MGD (summer - 750 MGD & winter 600 MGD).

This set of alternatives covers a reasonable range of options in terms of flow reduction, expense, and overall environmental impact. The option for unit-specific closed-cycle cooling of the entire facility offers the greatest environmental protection in terms of flow (and thermal discharge) reduction, but is also the most expensive option and poses the greatest potential non-water impacts. For options that involve converting more than one but less than all of the plant’s generating units to closed-cycle cooling, EPA decided to eliminate the Units 1 and 2 option because it would reduce flow and thermal discharge less than the Units 1 or 2 & 3 option. EPA decided that conversion of Units 1 or 2 & 3 warranted further consideration. Although Units 1 and 2 have lower flow rates than Unit 4, Units 1 and 2 areMA0003654 Determinations Document July 22, 2002

46 The permittee does not concede that this proposal is necessary to comply with CWA § 316(b), but indicates that it is willing to undertake this expense because this option will achieve significant reduction of the adverse impacts of CWIS operations at BPS by reducing cooling water flow through the plant, and in recognition of the importance of the natural resources of Mount Hope Bay, the fact that other parties may disagree with its views on the role of BPS in the decline of the bay’s fishery, and the permittee’s desire to help promote the recovery of these resources. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. I, Executive Summary, pp. 3- 6, 47.

7-59 base-load units and, therefore, operate more frequently than Unit 4. As a result, greater environmental improvement would be achieved at a similar cost by converting Units 1 or 2 & 3, than by converting Units 3 and 4. For a single unit conversion, EPA focused on the Unit 3 option because converting that unit would have the largest effect on flow and thermal discharge reductions of all the units.

EPA has also retained for further consideration the option of equipping the various unit-specific cooling tower options with bypass/multi-mode capabilities, so that generating units could continue to operate even if the cooling towers were offline. This approach warrants further consideration because it could provide a relatively easy and inexpensive means of avoiding the expensive, plume-related outages of the generating units that the permittee fears with respect to the unit-specific options. (Of course, overall permit conditions would still need to be met.)

EPA has also retained the permittee’s Enhanced Multi-Mode proposal for further detailed consideration. As the permittee has explained, the multi-mode options involve an array of mechanical draft cooling towers and plumbing changes that result in a system that can operate in closed-cycle, “helper” or “piggyback” modes to enhance flow and thermal reductions while giving the power plant greater operational flexibility and reducing costs. EPA believes the company has shown ingenuity in developing the multi-mode options. EPA has decided to carry the Enhanced Multi-Mode system forward for further review and to drop the Basic Multi-Mode system because the former achieves greater flow and thermal discharge reductions at a similar cost. Although USGenNE has assessed the Enhanced Multi-Mode proposal to cost $9 Million more than the Basic Multi-Mode option, the former offers added flexibility by enabling the cooling towers to be used in closed-cycle fashion with either Unit 3 or 4 to achieve further flow (and heat) reductions. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Table 4-1 and p. 3.1-1, and Sections 3.1.3.1 and 3.1.2.1. Moreover, the permittee has indicated its support for the Enhanced Multi-Mode option. 46

ii. Wet “Helper” Cooling Towers

The permittee also evaluated “helper” mechanical draft cooling towers as another potential option for satisfying CWA § 316(b). The permittee’s most recent evaluation is presented in the December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 3.2. This assessment looks at five (5) helper tower options involving the installation of 8, 18, 24, 30, and 48 cells. EPA has decidedMA0003654 Determinations Document July 22, 2002

7-60 that these options would not satisfy the requirements of CWA § 316(b) because they do not result in any significant flow reductions. (Only the 48-cell helper tower option achieves any flow reduction. It reduces summer flow from 1080 MGD to 925 MGD by recirculating cooling water to the Unit 4 condenser. Id . at 3.2-15, 3.2-17, 3.2-20.)

Except for the 48-cell option, helper cooling towers transfer a portion of the heat energy discharged in the facility’s effluent directly to the atmosphere, but do not result in a recirculation of cooling water flow. Thus, helper tower systems are designed primarily to reduce thermal discharges rather than to reduce cooling water withdrawal rates. See EPA Economic and Engineering Analysis, App. A, p. 15. See also December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, Section 4.4, Table 4-1. Therefore, EPA does not believe that these options could constitute BTA under CWA § 316(b) and concludes that they do not warrant further analysis in this determination document.

iii. Non-Closed Cycle Flow Reduction Options

There are also methods of reducing flow at BPS without utilizing closed-cycle cooling. These methods, however, are only likely to achieve limited improvements by themselves. As a result, EPA does not regard any of them alone to constitute BTA. EPA will consider these options, however, as possible components of a larger overall approach to ensuring that the capacity and design of the CWISs at BPS reflect the BTA for minimizing adverse environmental impact under CWA § 316(b).

(A) “Piggy-back” Cooling

In the January 1997 NEPCO Report, the permittee looked at two “piggyback” cooling options. These options were re-evaluated by the permittee in the December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, Section 3.4. Piggyback cooling essentially eliminates the need to withdraw water from the Lee River through the intake to Unit 4 by “routing a portion of the mixed, warm condenser discharge of Units 1, 2, and 3 into the pump bay of Unit 4” for cooling. Id . at p. 3.4-1. This is made possible by the layout of the piping network at BPS. By eliminating the Unit 4 CWIS flow, these options could yield a maximum estimated reduction in flow rate of 260,000 gpm (or 29%), and a corresponding reduction in entrainment and impingement, as compared to that which occurs when Unit 4 is in operation. Id . It should be noted that this is not a 29% reduction on an annual volume basis, because Unit 4 only operates around 20% of the time.

Moreover, the permittee indicates that piggyback cooling could only be used around 8 months of the year. Id . at pp. 3.4-1 to 3.4-2. The piggyback cooling process transfers the waste heat from Unit 4 to the already heated effluent from Units 1, 2 and 3, thereby making this water even hotter. Thus, the piggyback options reduce flow but do not reduce the total heat load discharged to the bay, and when intake water temperatures are relatively warm, the heated effluent from piggyback cooling would likely exceed the permit’s current limitations for maximum temperature and ) -T. The maximum temperature limit would especially be a problem during the summer. Due to thisMA0003654 Determinations Document July 22, 2002

7-61 thermal discharge problem, implementation of year-round piggyback cooling would also require either installation of a thermal discharge reduction technology or substantial cutbacks in operations. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.4-1, 3.4-3.

The two piggyback cooling options evaluated by the permittee include the “simple” (or “conventional”) piggyback operation described above and a variation which involves re-routing the existing Unit 4 intake flow directly to Unit 3. In the latter mode, the flow drawn from the Taunton River for Unit 3 would be replaced with flow from the Lee River withdrawn through the newer Unit 4 CWIS. This approach would take advantage of the impingement reduction capabilities of the newer Unit 4 intake screen technology (i.e., angled revolving screens). The permittee indicates that the Unit 4 angled screens divert some fish from the intake so as to reduce impingement from levels experienced by the flush-mounted screens used for the CWIS for Units 1, 2 and 3.

Thus, the two piggyback options offer the same reductions in flow and entrainment, but the modified piggyback option would achieve greater impingement reductions by substituting flow through the Unit 4 angled screens for flow through the Unit 3 screens. It is impossible to quantify the exact margin of additional impingement reduction, but the permittee has pointed to informationsuggesting a possible 50% reduction in impingement for angled screens as compared to the nonangled screens. See NEPCO 1997 Report; EPA October 1982 Modification Determination, p. 21- 37.

Although the modified piggyback option provides a potential impingement reduction benefit, the permittee explains that it prefers the conventional piggyback option because it would have lower capital costs (i.e., zero), lower energy penalties, and could be implemented more quickly. See January 1997 NEPCO Report, Table 6-2; December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.4-9. Furthermore, the permittee also states that if obtaining the benefits of the Unit 4 intake screens was a goal, it would be more economical to simply retrofit the Unit 3 intake with angled screens than to implement the modified piggyback option. Id . The permittee does not, however, recommend implementation of either piggyback option because neither achieves the permittee’s own flow reductions targets. Id

. EPA has concluded that neither piggyback option constitutes BTA by itself for a number of reasons. First, piggyback cooling only reduces flow levels at times that Unit 4 is in operation and flow for both units 3 and 4 would otherwise be used by the plant. Since Unit 4 has a relatively low capacity factor of around 20%, the Unit 4 intake is already not operating much of the time. Second, the permittee has already been utilizing conventional piggyback cooling on a seasonal basis for a number of years, under approval from the regulatory agencies, and under MOA II, conventional piggyback cooling is used 8 months of the year. Thus, while piggyback cooling reduces flow rates by 29% from levels that occur when both intakes are operating, piggyback options do not provide a full 29% reduction on an annual volume basis over existing circumstances. Id . at p. 3.4-7 (as compared to MOA II requirements, the permittee estimates annual flow reductions of 4% for the conventional piggyback option and 7% for the modifiedMA0003654 Determinations Document July 22, 2002

7-62 piggyback option). To provide a significant reduction in flow compared to existing conditions, the piggyback option would need to be used significantly more frequently that it is now (e.g., continuously). As discussed above, however, BPS could not do this and at the same time comply with the maximum temperature and ) -T limits of its permit unless the plant significantly curtailed generation during the summer (or also installed a substantial thermal reduction technology of some kind). Such curtailment would be quite expensive and would reduce generation at times of peak demand. Third, as discussed below, EPA does not believe that even a 29% reduction in annual flow volume would be sufficient to satisfy CWA § 316(b). Fourth, unlike the closed-cycle cooling options discussed above, the piggyback cooling options can reduce flow but do not contribute to the additional goal of reducing the amount of heat discharged to the bay.

(B) Flow Reduction from Changes in Pumping Capacity or Practices

In a CWIS, pumps are used to draw water in through the intake and circulate it through the plant’s cooling system. One-speed pumps take in the maximum flow that the pump can handle at all times the pump is operating. They are either on or off. See, e.g.
, December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, p. 3.5-5. Pumps can, however, be designed to operate at variable speeds so that when set on a lower speed they withdraw less water from the source water body. Using some type of variable speed pump within a power plant cooling system would enable the facility to reduce flow whenever conditions such as low inlet temperatures and/or low demand dictate that less flow is needed to provide adequate cooling for the amount of electricity being generated. See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.5-1. In other words, variable-speed pumps give a plant some ability to tailor its cooling water withdrawals to the minimum amount actually needed for cooling without reducing electricity generation.

As with the piggyback cooling options, however, flow reductions may be limited at certain times by the cooling needs of the generating unit and the maximum temperature and ) -T limitations ofthe permit. Thus, the use of variable speed pumps could allow a reduction in flow for a oncethrough cooling system, but only at times when higher flows are not needed. These options also do not achieve any thermal discharge reductions. See Id . at Table 4-1.

At BPS, each generating unit’s condenser cooling system is equipped with 2 circulating water pumps. These pumps are not redundant. Instead, they are “1⁄2-size”and both pumps must operate in order to meet a unit’s maximum cooling water needs. Id . at p. 3.5-3. For Units 1, 2 and 3, the present pumps are one-speed, while the Unit 4 pumps already have variable-speed drives. Id . at p. 3.5-7.

The permittee has studied several options for reducing flow by altering pumping capacity or practices at BPS. January 1997 NEPCO Report, Section 4.5; December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, Section 3.5. First, the permittee investigated the simple option of periodically using only 1 of the 2 pumps associated with each generating unit. This option was rejected as being unreliable because the current pumps are not designed to be turned on and off onMA0003654 Determinations Document July 22, 2002

7-63 a frequent basis. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, pp. 3.5-12, 3.5-14. Second, the permittee investigated installing two-speed motors on the pumps, thus giving them high and low settings. Id . at Section 3.5.2. Third, the permittee investigated installing variable speed drives (VSDs) in the pumps for Units 1 and 2, which would enable the permittee to run the pumps at varying speeds. Id . at Section 3.5.3. The permittee concluded that VSDs would not be appropriate for Unit 3 because that unit generally requires maximum flows. Id . at p. 3.5-7. As stated above, Unit 4 already has VSDs. Fourth, the permittee considered “throttle flow” operations under which flows would be reduced by throttling the condenser outlet valves during periods of reduced generation.

The permittee ultimately concluded that either the two-speed pump, VSD (for Units 1 and 2), or throttled flow options would all be suitable as flow reductions measures, but since they do not achieve thermal discharge reductions they would, at a minimum, need to be coupled with a thermal reduction option. Id . p. 3.5-14. The permittee also concluded that these options alone do not by themselves meet the permittee’s own flow reduction goals. Id . at p. 3.5-12.

Obviously, unlike the other options discussed above, these options do not provide a constant entrainment and impingement reduction benefit. Instead, they provide a benefit only when the plant is actually able to reduce flows and still generate electricity, operate in a once-through cooling mode, and meet thermal discharge limitations. Because of the variability in inlet water temperatures and electricity demand, it is difficult to reliably project the effectiveness of this option for reducing flow (and entrainment and impingement) on an annualized basis. According to the permittee’s projections, the two-speed pump, VSD and throttled flow options all achieve similar flow reductions in the winter months, but very little reduction in the summer months. See Id . at Table 4-1. The permittee points out, however, that since the winter flounder spawning season occurs in the winter, the winter reductions may be environmentally significant. At the same time, however, it must be noted that even in the winter months these pump-related options achieve far more modest flow reductions than the closed-cycle cooling options. Id

. Of course, the pump-related options are also much less expensive. Id . (capital costs range from only $0.6 million to $2.5 million). In addition, generation penalties from these options are substantially offset by costs savings from reduced energy needs for pumping. See Id . at pp. 3.5-6, 3.5-8, 3.5-10.

In light of the above considerations, EPA believes that flow limits reflecting one of the three pumping options deemed suitable by the permittee should be a part of any set of CWIS design or capacity requirements to reflect BTA. EPA has also concluded that the pumping options should not be regarded to constitute BTA by themselves because they do not achieve flow reductions year-round and they do not achieve sufficiently large flow reductions at any time of year. In addition, these options do not achieve any thermal reductions.MA0003654 Determinations Document July 22, 2002

7-64 (C) Generation Curtailment & Timed Maintenance Outages

The permittee’s January 1997 NEPCO Report, Section 4.4, also looked at a so-called “flow reduction” option. As conceived by the permittee, this option essentially involved curtailing the generation of electricity to a level that would enable it to reduce flow by 29% (i.e., equivalent to eliminating the flow for Unit 4). Not surprisingly, the permittee indicated that very high energy losses would occur with this option on an annual basis. For example, the report states that this option would reduce BPS generation capacity by 300 MW. Id . at p. 4-7. The overall effect on plant energy output would, of course, depend on the extent to which generation was curtailed. See Id . 4-7 to 4-8, Table 6-1. The permittee also states that such generation curtailment would diminish station reliability. These problems would be especially acute during the high demand summer period.

Given that there are available methods of reducing flow without making major reductions in electrical generation, EPA does not believe this method constitutes BTA for BPS. Generation curtailment (or flow reduction) could, however, be a suitable method of meeting some short-term or seasonal heat reduction target. While EPA is not setting BTA limits based on this “flow reduction” option, the permittee is of course free to meet the final permit requirements in any manner it chooses, including by using curtailing generation. As discussed elsewhere in this document, some facilities have chosen to achieve seasonal flow reduction targets by curtailing generation.

In the December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 3.5.5, the permittee also investigated an option of “seasonally timed outages,” which would involve scheduling regular maintenance outages during the Mount Hope Bay winter flounder spawning season (February through May) so as to maximize the environmental benefit gained from flow reductions associated with maintenance outages that must happen anyway. The permittee notes, however, that timing maintenance outages with the winter flounder spawning season “would be difficult due to ISO New England scheduling constraints and other competing environmental factors, such as air quality operating constraints during the ozone season.”

Although it would be environmentally beneficial for the permittee to schedule regular maintenance outages to coincide with the winter flounder spawning season whenever possible, EPA believe’s that flow limits based on this practice alone would not constitute BTA. First, this practice would only achieve periodic, short-term reductions in flow, rather than the major flow reductions that other options under consideration can achieve. Second, EPA understands that there may be competing concerns (such as air quality constraints or energy demand) that constrain the permittee from scheduling all maintenance outages in this manner. Therefore, flow reductions from this option could not always be counted on. In contrast, options such as closed-cycle cooling provide substantial, definite and year-round flow reductions.MA0003654 Determinations Document July 22, 2002

7-65 7.3.4b Location Options

As a general matter, in the absence of closed-cycle cooling, one of the best ways to minimize the potential adverse impacts of a CWIS is to locate the intake in an area where impacts are more likely to be less severe, such as an off-shore, ocean location. It is always advisable in order to reduce adverse impacts from a CWIS to locate the intake in relatively less sensitive or biologically productive areas as well as areas where low approach velocities can be attained. Of course, other steps may also be needed to ensure that the capacity, design and construction of the CWIS reflect BTA.

Of course, for BPS, the CWISs are unfortunately already located in a sensitive estuarine environment. Therefore, the question here is whether re -locating the CWISs would constitute BTA in this case.

The permittee investigated relocating the intake to an off-shore location and concluded that, although technology existed to implement such an option, it was economically impracticable and raised a number of serious potential environmental issues that would have to be studied in depth before it would be approved. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 3.7. The permittee concluded that an off-shore intake re-location would require boring an 18-mile tunnel through bedrock to a location in Rhode Island Sound. As the permittee notes, the new, 9-mile Massachusetts Water Resources Authority sewage treatment plant outfall generally indicates that such a tunneling project could be done.

However, the permittee also indicates that the project would be a massive, complex construction project that would take approximately 5 years to complete and “is estimated to cost on the order of $600 million.” Id . at p. 3.7-3. The permittee also predicts that project construction could cause a number of potential adverse environmental effects, including to groundwater resources along the tunnel route. Id . at p. 3.7-2. Significantly, the permittee also points out a serious, potentially unacceptable environmental concern raised by this option. The offshore water taken in through the new intake would be heated and discharged into Mount Hope Bay. This could have harmful environmental effects because the offshore water has a different temperature, salinity and nutrient content from the bay water. Id . EPA agrees that this issue would require careful study before approval, and while this issue could be avoided by also relocating the discharge point offshore, that would add additional expense to an already hugely expensive and difficult project.

Having considered the matter, EPA concludes that CWIS location changes do not constitute BTA in this case. First, we agree that while entrainment and impingement effects are likely to be reduced by moving the intake outside the Mount Hope Bay estuary, a major reduction in impacts would likely require moving the intake outside Narragansett Bay to the ocean. Even still, there would be adverse impacts to the assemblage of organisms residing at the new location. Second, even assuming permits could be obtained to allow such a project, the work would likely be hugely expensive and would undoubtedly entail significant potential adverse environmental impacts from construction. Third, the environmental issues related to potentially discharging off-shore water,MA0003654 Determinations Document July 22, 2002

47 Please note that we are not citing the preamble to the Proposed CWA § 316(b) Rule for new power plants as if it imposes, or provides guidance suggesting, a velocity requirement of 0.5 fps for an existing plant such as BPS. We recognize that it does not. We only cite to the preamble here for the purpose of pointing to the technical references listed there that themselves independently suggest a velocity requirement of 0.5 fps. In other words, we are relying on the references and not on EPA’s federal register notice to suggest that 0.5 fps has been pointed to as a possible standard.

7-66 after cooling, into Mount Hope Bay would need to be carefully evaluated before such a project could be approved. EPA believes that the closed-cycle cooling options for reducing capacity are likely to be capable of achieving significant and sufficient improvements more quickly and at far lower cost. Thus, EPA does not believe that re-locating the CWIS would reflect BTA in this case.

7.3.4c Design Options

In general, the major options for ensuring that the “design” of a CWIS reflects the BTA for minimizing adverse environmental impacts, involve technologies that attempt to reduce impingement and entrainment of marine life by reducing intake velocities or by imposing some type of barrier to prevent organisms from entering the CWIS. In addition, technologies can be installed, such as fish return systems, to try to increase the survival rate of marine life that is impinged by any barrier mechanism. (CWIS design options to reflect BTA also include pumping modifications, but pumping options are discussed elsewhere in this document.)

i. Velocity Reduction Measures

Design options for reducing the velocity of the water drawn into the CWIS help to reduce impingement by making it easier for fish to escape the influence of the CWIS. A commonly used standard for intake flow velocity is that the flow should not be greater than 0.5 feet per second (fps) at the screens

. See 65 Fed. Reg. 49087 (August 10, 2000) (discussion of literature regarding intake flow velocity). 47 Other information points to similar velocity thresholds. See 1996 EPA Supplement to Background Paper No. 3, p. A-1 (“studies conducted with white perch and striped bass indicate a marked increase in impingement at approach velocities greater than 0.8 fps;” “Research indicates that approach velocities lower than 0.8 to 1.1 fps may be required to protect certain species against impingement” [references omitted]). Indeed, the CWIS angled traveling screen system installed at Unit 4 was apparently designed to try to produce an approach velocity of 0.5 fps based on certain research suggesting it would be beneficial. See EPA October 1982 Modification Determination, p. 37, 21-36. However, while the approach velocity at the Unit 4 CWIS is reported by the permittee to be 0.5 fps at the bar racks , it is around 1.0 fps approaching the traveling screens . 1997 NEPCO Report, p. 2-6; December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, p. 2-5. Moreover, the approach velocity at the intake for Units 1, 2 and 3 is approximately 1.4 fps at the trash racks

. See Brayton Point Station Monitoring Program, A Technical Review (September 30, 1992) (Metcalf & Eddy, under contract to EPA); December 2001 USGenNEMA0003654 Determinations Document July 22, 2002

7-67 316(a) and (b) Demonstration , Vol. IV, p. 2-2 (“theoretical” velocities calculated to be 1.35 fps at the trash racks for Units 1 and 2 and 1.56 fps at the trash racks for Unit 3) . Approach velocities at the screens would be even higher. Therefore, it does not appear that approach velocities at the screens are optimal for minimizing impingement at either of the BPS CWIS’s.

That being said, there are no obvious measures that appear to make sense for reducing velocity at the BPS CWISs. Velocity caps are technologies used for offshore ocean intakes to reduce approach velocity, but would not be appropriate at BPS. See EPA 1994 Background Paper No. 3, p. 3-9. It should be noted that in the January 1997 NEPCO Report, the permittee considered an option that involved installing angled, fine-mesh screens for the intake for Units 1, 2 and 3. This option also involved increasing the area of the intake bays to decrease the current screen approach velocity to 0.5 fps or less in order to prevent screen overloading during periods of heavy loadings from materials such as seagrass. January 1997 NEPCO Report, p. 4-34 to 4-35. However, the permittee indicated that this option had an associated capital cost of $30 million dollars. Id . p. 4- 37, Table 6-2. More recently, the permittee has estimated the cost for a similar option to be $56.4 million. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.6-5. EPA does not believe that an expenditure at that level would make sense for a technology that only yields marginal potential reductions in impingement. There are other steps with a similar order of magnitude of capital expense that can reduce impingement while also achieving improvements with respect to the (relatively) more serious problems of entrainment and thermal discharge. EPA believes that major expenditures for minimizing adverse environmental impacts from the CWIS should be directed toward measures which simultaneously address all these problems.

ii. Barrier Mechanisms

Barrier mechanisms can be divided into the general categories of Behavioral Deterrent Technologies and Physical Barriers.

(A) Behavioral Deterrent Technologies

Behavioral barriers which could be considered as possible steps to reduce impingement at BPS include sound barriers, light barriers, electrical barriers, air bubble barriers, and chain or cable barriers. These technologies are not, however, effective for reducing entrainment of floating or drifting organisms. Moreover, whether these technologies are capable of reducing impingement by repelling fish is highly uncertain. To determine their potential efficacy at a particular plant, a site-specific analysis of conditions at the plant and the likely behavior of the relevant species of marine life would be necessary. Thus, extensive testing would be required to determine whether one of these technologies might be effective at BPS.

In the January 1997 NEPCO Report, the permittee discussed behavioral barrier alternatives but dismissed them without further development of cost estimates because, according to the permittee, no effective site-specific options were identified for potential use at BPS. For behavioral deterrent systems, the permittee concludes that the technology is not feasible because visual barriers such asMA0003654 Determinations Document July 22, 2002

7-68 light or bubble curtains would have no effect on entrainment of larvae and eggs, and because sound and light systems are still considered to be in an experimental stage of development and would not be suitable for full scale installation at BPS. The permittee reached the same conclusion in its February 22, 2001, report entitled, “NPDES Renewal: USGen New England, Inc., Brayton Point Station, Somerset, Massachusetts.”

EPA agrees that at the present stage of development, behavioral deterrent systems do not constitute BTA for BPS. They are simply not clearly “available” or effective. In addition, even if effective at reducing impingement, they would not help with the problem of entrainment. EPA is aware that the Salem Nuclear Generating Station in New Jersey is actively investigating the feasibility of behavioral barriers as a technology to reduce impingement at the facility. Thus, it is possible that in the future such measures may be developed and require further consideration. At present, however, EPA believes it advisable to direct expenditures for reducing impingement at BPS to measures whose efficacy is more certain, and that any major expenditures should be directed to measures that will also reduce the (relatively) more significant problems of entrainment and thermal discharge impacts.

(B) Physical Barriers

There are many types of physical barrier technologies that can be considered for their potential to reduce entrainment and impingement impacts. These include screen systems (such as fine mesh screens), passive intake systems (such as perforated pipes, porous dikes, wedge-wire screens, and artificial filter beds), and diversion and/or avoidance systems . In addition, there are various fish return technologies that seek to maximize the survival of impinged organisms by returning them to the source water body with as little harm as possible. These include fish bypass systems, fish buckets and baskets, fish troughs, fish elevators, fish pumps, spray wash systems, and fish sills.

At present BPS has two different types of screening systems in operation. See Section 2.2.2. The CWIS for Units 1, 2 and 3 draws from the Taunton River and utilizes flush-mounted traveling screens. The screens are presently operated continuously as required by MOA II ¶ 8.e. Material is cleared from the screens with a high-pressure spray wash system. The material travels down a sluiceway and back to the water through a pipe to a point approximately 300 feet east of the intake. Impingement is monitored and reported by the permittee under requirements in the NPDES permit. In addition, fixed screens are installed upstream of the traveling screens from May to October to keep horseshoe crabs from being drawn into the traveling screens where the spray wash system is ineffective to remove them. Id . at p. 2-3. The CWIS for Unit 4 draws from the Lee River and utilizes angled traveling screens which are run continuously as per MOA II ¶ 8(e). This intake has a bypass system to remove fish that enter the CWIS but do not reach the traveling screens and return them to the Lee River downstream of the intake. Id . at p. 2-5. Fish that do reach the traveling screen are captured in fish buckets, washed into a trough by a low-pressure screen wash, and fed into a pipe which returns them to the Lee River downstream of the intake. Id . The screens for both CWISs are of a standard size ( i.e. , do not have fine-mesh) and do not prevent the entrainment of fish larvae, eggs, or plankton.MA0003654 Determinations Document July 22, 2002

7-69 In considering possible retrofits to the existing screening systems, the permittee has considered and rejected a number of possible options. In its February 22, 2001, report, the permittee considered and rejected cylindrical wedge-wire screens; drum screens; infiltration intakes; porous dikes; barrier nets; and fine-mesh and dual-flow traveling water screens.

Cylindrical wedgewire screens are a type of physical barrier that could possibly reduce fish losses to some extent, but the physical size of the screening device restricts application of wedge-wire screens to use for closed-cycle make-up water or other small flows. The permittee has stated that cylindrical wedge-wire screens do not presently appear feasible and testing would be required to further evaluate the risks of severe clogging and bio-fouling. EPA-New England has determined that several full-scale CWIS applications of this technology have performed satisfactorily, but with course bar spacings of 10mm. The potential use of bar spacing as small as 0.5 to 2.0 mm in order to protect at least some early life stages of fish has not been evaluated at a CWIS. Therefore, large-scale pilot studies would be needed to determine the potential of this technology for reducing adverse environmental impacts at BPS. Accordingly, EPA does not presently consider this technology to represent BTA for minimizing adverse environmental impacts at BPS.

The permittee also rejected rotary drum screens because they do not offer performance or cost advantages over similarly functioning traveling screens or angled traveling screens. EPA found no evidence of a drum screen application at a CWIS. Drum screens have been used at irrigation and hydroelectric facilities, but even in these applications the screens are limited by the requirement for maintaining constant water elevations. EPA agrees that angled stationary diversion screens would be preferred over rotary drum screens.

Passive intake systems, such as porous dikes and infiltration intakes, are a subset of the physical barrier technologies. They screen out debris and biota with little or no mechanical activity. Most of these systems are based on achieving very low water withdrawal velocities at the screening media so that organisms can avoid the intake. The permittee determined these systems to be infeasible because of the high circulating water requirements of the facility and problems ofbiofouling. In the early 1980's, in anticipation of changing from closed-cycle cooling to oncethrough cooling at Unit 4, NEPCO did an extensive study on the possible suitability of using porous dike systems at the threshold of the intake structure. The results of the study indicated that this technology is effective at excluding juvenile and adult fish, but the permittee also predicted that use of this technology would result in major problems from porous dike clogging, ice build-up and frazil ice in the dike proper, as well as biofouling by colonization with fish and plant life. As a result, this option was rejected. EPA concurs with the permittee’s decision to drop these technologies.

The permittee also eliminated “barrier nets or curtains” from consideration on the basis of the high water velocities, variable tidal and storm induced currents, and large quantities of debris experienced at BPS. Barrier nets or curtains act on the same principle as other screening systems, but use different screening media. For example, the technology known as the “Gunderboom” is made with a geotextile fabric curtain. Most of the recent information on barrier net efficacy relatesMA0003654 Determinations Document July 22, 2002

7-70 to their use at hydroelectric facilities.

It should be understood that if a net or curtain successfully blocks an organism from being drawn into the cooling system, then that organism is by definition impinged on the screening material. The question then becomes whether or not the organisms survive this impingement (or the measures used to wash them off of the screening material). This technology may be more likely to be successful in a river environment where organisms could be blocked from entering the CWIS and then washed downstream away from the intake, whereas they might be less successful in a ocean or estuarine situation where they would be washed back and forth against the barrier by the tide and be subjected to strong coastal storms, waves and tidal forces. It appears that acceptance of nets by resource agencies is growing for use at hydroelectric facilities. Ultimately, the ability of a net or curtain to protect early stages of fish from entrainment depends on the size of the mesh of the screening material. A Gunderboom has been used at a power plant on the Hudson River in New York (Lovett Station) and although there have been some problems anchoring the device, it has been reported to significantly reduce entrainment at that plant. (E.P. Taft, “Fish Protection Technologies: A Status Report,” Environmental Science and Policy (2000)).

Serious questions remain, however, regarding the feasibility of net or boom anchoring systems for coastal plants subject to potentially severe storm conditions. This raises the potential for operational and even safety problems if the net or curtain came loose and blocked the CWIS or created a navigational hazard. This has been raised as a concern with respect to the Gunderboom technology both by the permittee and by another coastal power plant in New England that has evaluated the technology (Pilgrim Nuclear Power Station). Moreover, in rejecting the Gunderboom technology in its response to an EPA information request letter in September 2001, the permittee also provided a letter from the Gunderboom company in which the company agreed that safely anchoring the system at BPS was not presently feasible. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. III (Tab: “Section 308 Information Request Submittal - 9/10/01, p. 16 and Attachment C.3). The permittee also pointed to potential interference with navigation from a Gunderboom installed seaward of the CWISs. Id

. EPA-New England does not presently consider barrier nets or booms as fully demonstrated at least for coastal plants. Moreover, since it is not clear that these technologies can significantly reduce CWIS mortality for the organisms of concern at BPS, EPA presently agrees with the permittee’s conclusion that these technologies should not be deemed BTA for BPS.

Another option considered by the permittee is the so-called “fine-mesh” screen. Fine-mesh screens use much smaller mesh sizes than conventional traveling screens. Fine-mesh screens must also be coupled with some sort of fish return system. Fine-mesh screens may be capable of screening out most small fish and possibly some eggs and larvae. What they block from being entrained dependson the relative size of the mesh and the organisms in question. Of course, to the extent that finemesh screens successfully stop smaller organisms from being entrained, those organisms will necessarily be impinged. As a result, the question then becomes whether or not these tiny, delicate organisms can survive the impingement process.MA0003654 Determinations Document July 22, 2002

7-71 Fine-mesh screens can also pose operational concerns, at least at certain sites, because they tend to capture more debris and, therefore, are more prone to clogging. As the permittee points out, they may also be prone to clogging by the growth of marine organisms, such as barnacles, on the screens. Although such “biofouling” can be combated by using biocides such as chlorine in the spray wash for the screens, such a practice would likely kill any surviving organisms impinged on the screens. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.6-3.

As the permittee also reports, a number of power plants around the country have installed finemesh screens for their CWISs, including retrofit installations,. See Id . at p. 3.6-2. These plants report success at reducing entrainment and impingement mortality. Nevertheless, the true benefit of these technologies must be assessed on a site-specific basis taking into account the size of the mesh, the approach velocity, the fish-return system, and the specific organisms and life stages in question. Again, to the extent fine-mesh screens reduce entrainment, they result in increased impingement of tiny organisms and the survival of these organisms must be evaluated.

The permittee evaluated two options involving replacing the traveling screens at BPS with finemesh screens –“angled fine-mesh” traveling screens and “modified dual-flow” traveling screens– but ultimately rejected both. These two approaches use similar technologies but configure them in different ways. Id . at pp. 3.6-3, 3.6-7, Figures 3.6-2, 3.6-9. For both options, the permittee expressed serious concern about potential clogging of fine-mesh screens at BPS due “a greater abundance of debris and trash” than experienced at other plants using fine-mesh screens. Id . at pp. 3.6-1, 3.6-10, 3.6-14. BPS actually tried a fine-mesh screen on Unit 4 in the past but replaced it with a larger mesh screen due to heavy loading with debris. The permittee also expressed concern about biofouling and clogging by frazil and floating ice. Id . at p. 3.6-3. The permittee explains that a mesh size of 1 to 2 mm might be too large to prevent entrainment of winter flounder larvae and eggs, id ., but a smaller mesh size (such as 0.5 mm) would be more prone to clogging. The permittee also explains that approach velocities would need to be reduced to 0.5 feet per second in order to reduce the threat of overloading the screens with debris, but that to achieve this would require additional construction. Id . at p. 3.6-4. The permittee also indicates that modified dual flow traveling screens have the advantage of “eliminat[ing] debris carryover,” id . at p. 3.6-7, but have lower impingement survival than the angled fine-mesh screens. See Id . at pp. 3.6-3, 3.6-7, 3.6-8.

With respect to biological performance, the permittee essentially seems to conclude that while there may be potential benefits to fine-mesh screens, such benefits are quite uncertain at BPS. The permittee makes the following statements:

S “A fine-mesh traveling water screen intake system minimizes entrainment, but increases potential for impingement of organisms . . ..” Id . at p. 3.6-2.

S “This screening system offers some promise of reducing mortality of both impinged fish and entrainable organisms by including two fish return systems in its design.” Id

.MA0003654 Determinations Document July 22, 2002

7-72 S “There is no data to quantify the expected improvement in impingement survival due to specific site and species survival factors. As always, some impinged species have higher survival than other species, and ambient water temperatures have some influence on the condition and survival of impinged fish” Id

.

S “Because this intake design [i.e., the angled fine-mesh screen] incorporates both impingement return and angled bypass system, this alternative should provide some improvement in survival for at least some species of impinged fish.” Id

.

S “It is not known if the entrainable species at the Brayton Point Station would have higher survival on the screens or in passage through the cooling system.” Id

.

S “Disadvantages of the fine-mesh traveling water screen concept include: . . . increased impingement of organisms and debris; . . . [m]esh size of 1 to 2 mm may still be insufficient to prevent entrainment of early life stages of winter flounder larvae and eggs.” Id . at p. 3.6-3.

S With the dual flow screen, “[m]ore water tends to enter the side of both the ascending and descending sides of the screen closest to the pumps. This unequal distribution leads to hot spots where impingement is more likely to occur than with a design that spreads the flow more uniformly. However, even with this limitation, the lower approach velocity, the modified lifting buckets, and spray wash system . . . should provide some potential for improvement in survival for at least some impinged fish.” Id . at p. 3.6-8.
The permittee has made an “order of magnitude estimate” of approximately $50 million for the capital cost of each of the two fine-mesh screen alternatives. Id . at p. 3.6-15. See also January 1997 NEPCO Report, p. 4-37 (order of magnitude cost estimate of $30 million for fine-mesh screen option). Neither option requires any unit outages for construction and neither option results in any efficiency or auxiliary energy penalties, though their annual operations and maintenance expenses are $430,000 for the angled fine-mesh screens and $170,000 for the dual flow fine-mesh

screens. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.6-15.

Based on present information, EPA concurs with the permittee’s decision to reject the two finemesh screen alternatives from further consideration at this time. The biological benefits of using fine-mesh screens at BPS are simply unclear. Entrainment would be reduced, but by how much is uncertain. Moreover, while reducing entrainment, fine-mesh screens would increase impingementof tiny, fragile organisms and the extent to which such organisms would survive is unclear. Sitespecific analysis would be required to try to characterize the overall effect of using fine-mesh screens at BPS. In addition, these options provide no thermal reduction benefit. Meanwhile, the company has estimated the capital cost of these options to be virtually the same as the costs for the Enhanced Multi-Mode and the Closed-Cycle Unit 3 options, see id . at Table 4-1, whereas the latter options provide clear benefits by cutting both entrainment and impingement as a result of flow reductions, and also by reducing thermal discharges. While EPA understands that theseMA0003654 Determinations Document July 22, 2002

7-73 closed-cycle cooling options may also have additional costs due to construction outages and energy penalties, EPA concludes that it makes more sense to undertake any significant capital expenditures on closed-cycle options that will provide more certain benefits than to undertake similar expenditures for measures, like fine-mesh screens, whose benefits are uncertain. Finally, the permittee has concluded that fine-mesh screens would pose a serious reliability problem due to screen clogging that might even lead to unit outages. While EPA has not independently evaluated this claim in detail, it appears to represent an additional reason to reject the fine-mesh screen alternatives at the present time.

The permittee also evaluated an option referred to as “modified traveling water screens.” This alternative essentially involves modifying the existing traveling screens for Units 1, 2 and 3, in order to improve the fish return system and reduce impingement mortality. December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 3.6.3. The permittee explains that this option would include “new screen mesh baskets with lifting buckets to retain impinged fish, low pressure fish removal sprays, a fish return trough, and operating components capable of continuous rotation of the traveling water screen assembly.” Id . at p. 3.6-10. The permittee estimates that the costs of these modifications will be relatively modest (around $1.3 million), with no energy penalties due to lost efficiency, auxiliary energy needs, or construction outages. Id . at p. 3.6-12. The permittee concludes that the improved fish return system and more reliable components of this option “offer[ ] some assurance for reducing mortality to impinged fish in comparison with the existing screening facilities at Units 1, 2 and 3.” Id . at p. 3.6-11. While acknowledging that “[t]here is no data to quantify the exact improvement in impingement survival due to specific site and species survival factors . . .,” the permittee nevertheless concludes that “the features of this intake alternative should provide some improvement in survival for at least some species of impinged fish.” Id

. EPA concludes that the “modified traveling screen” option should be carried forward for further review as a potential component of any set of options that utilizes the existing CWISs. It is clear that this type of a screening system retrofit of the intake for Units 1, 2 and 3 is economically and technologically practicable. Id . at p. 3.6-10, 3.6-12. Further, although this option would not provide flow reductions, entrainment reductions, or thermal discharge reductions, it does seem that it will help to reduce impingement mortality at relatively small expense, thus optimizing the performance of the existing screening system. In addition, the improved reliability of the component parts of this option are highly desirable because any option that continues to use the existing CWISs will be required by the NPDES permit to include continuous operation of the traveling screens, as per MOA II ¶ 8.e, in order to obtain the maximum environmental benefit from the existing technology. Id . at p. 3.6-10. Of course, if the intake for Units 1, 2 and 3 was not used under a future cooling tower option, and only the Unit 4 intake continued to be used, then there would be no need for these screening system upgrades.MA0003654 Determinations Document July 22, 2002

7-74 7.3.5 Summation - Comparison Chart

The chart below presents a comparison of the major options that EPA believes warrant further detailed consideration. It also covers the existing NPDES permit and MOA II for the sake of comparison. The chart looks only at the annual flow rate and annual

thermal rejection to Mount Hope Bay associated with each option. Ultimately, the permit may also address these parameters with daily, monthly, and/or seasonal limitations. Nevertheless, this chart provides a useful gross comparison.

Table 7.3-1: Comparison Chart Operating Scenario Flow Rate (MGD) Annual Heat Load Discharge (TBTU)

Current Permit 1452 97

MOA II 977 42
Enhanced Multi-Mode (20- cell cooling tower) 650 (annual) (750(summer)/600 (winter)) 28

Closed-Cycle Unit 3 654 22.9
Closed-Cycle Entire Station (Units 1, 2, 3 and 4) 56 (Intake) 0.8

Closed-Cycle Units 1 or 2 & 3 350 14

Pumping Improvements inCombination with a ClosedCycle Cooling Option (VSDs, Two-Speed Pumps, or Throttled Flow Operation) 844 - 860 (annual)

758 - 786 (winter) 1015 - 1037 (summer) (note: these figures represent reductions assuming no other flow reduction option was implemented, but are provided for illustration of the type of flow reductions provided by these technologies) No Change.

Modified Traveling Screens for the Units 1, 2 and 3 Intake No changes in flow or thermal discharge, but some improved impingement survivalMA0003654 Determinations Document July 22, 2002

48 See In re Public Service Company of New Hampshire (Seabrook Station, Units 1 and 2) , 10 ERC 1257, 1261 (NPDES Permit Application No. NH 0020338, Case No. 76-7; June 17, 1977) (Decision of the Administrator). The First Circuit Court of Appeals noted EPA’s application of the “wholly disproportionate cost” test with approval and cited to Congressman Clausen’s remarks for the proposition that “[t]he legislative history clearly makes cost an acceptable consideration in determining whether the intake design ‘reflect[s] the best technology available.’” Seacoast AntiPollution League v. Costle , 597 F.2d 306, 311 (1 stCir. 1979).

7-75 7.4 Economic Consideration of Technological Options

7.4.1 Introduction

As discussed in detail above, EPA has interpreted CWA § 316(b) to authorize it to consider the cost of the technological options for CWIS improvements when making determinations of what constitutes BTA for minimizing adverse environmental impacts. First, cost is considered in terms of whether an option is economically “practicable.” This can be understood as part of meeting the “availability” component of BTA. Second, under EPA’s current approach, the Agency also considers costs by determining whether or not the cost of the BTA requirements would be “wholly disproportionate to the environmental benefit to be gained.” This comparison is not a cost/benefit analysis; rather, it is a particular type of consideration of costs that EPA has determined, and the courts have upheld, is consistent with Congressional intent under CWA § 316(b). 48

In order to address these two sets of economic considerations (i.e., practicability and the wholly disproportionate cost test) in a case-by-case analysis, EPA must determine the appropriate cost for a particular option under consideration for satisfying the BTA requirement at BPS. EPA must assess the permittee’s ability to afford the option. These analyses are presented below. In addition, for the wholly disproportionate cost test, EPA must assess the environmental benefits to be obtained from the different options. This analysis is presented in another section of this § 316(b) determination. Finally, EPA must bring the costs and the benefits together to apply the wholly disproportionate cost test. This analysis is presented in a separate section further below. As part of our application of the wholly disproportionate cost test, EPA also considered what effects, if any, possible improvements at BPS would have on consumer electric rates.

7.4.2 EPA’s General Approach to Analyzing the Cost of Technology Options

EPA hired two contractors to provide expert analysis to assist with EPA’s independent assessment of the cost of the various technology options under consideration. Working with EPA, these two expert contractors addressed different aspects of the cost analysis.

First, EPA retained Science Applications International Corporation (SAIC), working under subcontractMA0003654 Determinations Document July 22, 2002

7-76 to Tetra Tech, Inc., to assess the “engineering aspects” of the cost of the technology alternatives. The “engineering aspects” of the cost include the capital and annual cost to the permittee of each option. The annual expenses include operations and maintenance costs, the cost of any reduction in electrical generation efficiency due the particular cooling system option, and the cost of the auxiliary energy needed to run the alternative cooling technologies. These efficiency and auxiliary energy penalties are discussed in some detail above. In addition, SAIC also evaluated the extent to which generation unit outages might be necessary to allow installation of any particular option, because lost generation during any such outage was also considered part of the cost of that option. Finally, SAIC also evaluated the likely construction schedule for the options because it has a bearing on their cost.

Second, EPA retained Abt Associates, Inc. (Abt), to assess the “financial aspects” of the cost to USGenNE of the various alternatives. This involved several elements. Abt developed a model todetermine the cost over time to the permittee of the various options, the net present value of these multiyear costs, and the equivalent annualized cost. The analytical approach mirrors that used by the permittee in the “Dynamic Cost Analysis.” See December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. III, Appendix G (Tab: Dynamic Cost Analysis). Thus, the results from Abt’s analysis can be meaningfully compared with the results of the permittee’s analysis. In other words, it provides an “apples-to-apples” comparison with the permittee’s analysis.

Abt’s analysis not only considers the capital costs and annual operations and maintenance costs for each option, but it also determines the cost of each option to the permittee in terms of lost revenue due to reduced electrical generation. Lost generation-related costs include one-time losses due to any generating unit outages needed to install a particular technology option (i.e., “construction outages”) and annual losses due to energy efficiency and auxiliary energy penalties. In addition, Abt’s analysis took into account the economic cost to the permittee from generating unit outages predicted by the permittee to be required due to vapor plume-related icing and fogging safety issues. Finally, Abt’s analysis also considered increased

revenues that the permittee would be able to obtain due to the installation of new cooling technologies that enable increased hours of operation during peak summer demand periods as a result of reduced discharge temperatures. EPA and the permittee agreed that this type of long-term economic/financial analysis was the most accurate way to assess the cost to the permittee of each option, as opposed to, for example, the “static cost analysis” approach that the permittee had used in several submissions prior to the December 2001 USGenNE 316(a) and (b) Demonstration. Abt’s analysis relied on various “engineering cost” data from the SAIC reports in order to generate EPA’s independent cost estimates. In instances where SAIC did not develop an independent value, or determined that the permittee’s figures seemed reasonable, Abt used inputs based on the USGenNE analysis. All of this is described in detail in the Abt report dated April 5, 2002.

In evaluating the economic/financial issues, EPA and its contractors carefully considered the permittee’s economic analyses as presented in the December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. III, Appendix G (Tab: Dynamic Cost Analysis); Volume IV; Volume V; and Volume I (Executive Summary). EPA and its contractors also considered a substantial amount of additional informationMA0003654 Determinations Document July 22, 2002

49 It should be noted that the permittee’s analysis of the cost of various options has changed significantly over time. For example, the January 1997 NEPCO report estimated that the option of closed-cycle mechanical draft wet cooling towers for Unit 4 would have a capital cost of $27.8 million and would result in an annual loss of 12,000 MW-hrs of electricity, whereas the December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, Section 3.3.3, estimated the capital costs for this option to be $48 million with lost annual generation of 25,000 MW-hrs.

50Actually, Abt uncovered two calculation errors by the permittee in the Dynamic Cost Analysis. One incorrectly reduced costs, but this reduction was more than offset by another error that incorrectly increased costs. Abt’s analysis corrected for both errors, as discussed in the Abt Report (April 5, 2002), pp. 39-40.

7-77 earlier submitted by the permittee, including, without limitation, the January 1997 NEPCO Report; various meeting handouts by the permittee, and a variety of information submitted by the permittee in response to EPA CWA § 308 information request letters. 49 The latter material includes data submitted by the permittee from Resource Data International and information submitted with an October 16, 2001 letter from the permittee’s counsel Wendy Jacobs of Foley Hoag, to Mark Stein of EPA. EPA and its consultants also had several meetings and conference calls with the permittee and its consultants to discuss various factual and analytical issues related to the assessment of the costs of the options. Finally, EPA’s consultants also did substantial research using a variety of sources of data independent from the permittee. These independent sources are described and referenced in the consultants’ reports.

EPA has independently reviewed the reports submitted by SAIC and Abt and determined them to contain reasonable and appropriate analyses. As explained in the reports, these analyses are conservative in many important respects (i.e., analytical choices were made that would tend to produce higher cost estimates). Therefore, EPA adopts the analyses contained in the SAIC and Abt reports. The SAIC and Abt reports are available in the administrative record. Rather than repeat all the details of these two reports, in this section of the document we only discuss key aspects of the analyses.

7.4.3 Results of EPA Analysis of the Cost of the Technology Options

In general, EPA has concluded that the permittee has substantially overestimated the likely costs of the various technologies. The biggest component of this overestimation is the capital cost predictions, but excessive predictions for construction outages, energy efficiency penalties and water vapor plume abatement outages also materially contribute to the total overestimate. In addition, the permittee’s overestimate of the costs of the options is affected by other aspects of the financial analysis, such as choice of discount rate, certain inappropriate tax treatments, 50and unrealistically using 2001 as the start-date for construction of new facilities. These issues are discussed in detail in Appendixes B and C hereto. Key points and conclusions from EPA’s analysis are presented below.MA0003654 Determinations Document July 22, 2002

7-78 7.4.3a “Engineering Aspects” of Cost Analysis

**i.** Capital Costs

SAIC conducted an independent assessment for EPA of the capital costs of the cooling water intake structure capacity reduction options under consideration. To do this, SAIC conducted two separate analyses. Each approach is discussed below and their respective results are presented in a table along with the permittee’s numbers.

SAIC’s first analysis generated independent costs estimates by comparing USGenNE’s detailed cost spreadsheets with an independent source of construction cost data (the “Independent Line Item Analysis”). SAIC reviewed and analyzed USGenNE’s capital cost estimates, which were submitted in detailed cost spreadsheets included in Volume V of the December 2001 USGenNE 316(a) and (b) Demonstration

, and discussed in the text of Volume IV of the December 2001 submission. SAIC then identified similar cost items in an independent data source, the RS Means Cost Works database for the third quarter 2001. Some of the Cost Works items were lower in cost than the USGenNE numbers, while others were higher. Because the Costs Works database is a construction cost estimating resource for general construction throughout the United States, many of the specific unit cost items in the USGenNE spreadsheets could not be matched with similar cost items in Costs Works. However, for each item that could be matched, SAIC used the Cost Works value in its analysis. Thus, SAIC did not selectively use some matching items and disregard others; all matching items were used. Depending on the option being considered, between 16% and 23% of the cost items in the USGenNE spreadsheets were able to be matched with items in the Cost Works data.

In addition, it is important to note that the Cost Works database allows for selection of cost factors that reflect specific regions of the country. In developing the independent cost estimates, SAIC chose data that represented the highest union labor rates for Boston, which is the most costly region in Massachusetts. These adjusted costs take into consideration regional costs for materials and labor, including the effects of using unionized labor.

For each alternative, the independent estimate line item costs were compared to the USGenNE line items costs. The comparison indicated overall that the independent, Cost Works-based estimates were significantly less than the USGenNE estimates. The ratio of the total of independently estimated line item costs to the total of the corresponding USGenNE line item costs indicates the relative extent to which the independent estimates are less than the USGenNE estimates for each technology option (and inversely, the extent to which the USGenNE estimates appear to have overestimated capital costs). Assuming that the comparative relationship observed for the matched items is representative of all of the cost items, multiplying this ratio by the corresponding total of USGenNE costs for a technology option yields an independent estimate of capital cost. Although we cannot be certain that this assumption isMA0003654 Determinations Document July 22, 2002

51 SAIC and Tetra Tech are also working for EPA on the 316(b) rulemaking effort for EPA and, thus, are well-versed in the 316(b) costing approaches. The 316(b) Rule costing methodology and costing equations are described in detail in the EPA TDD 2001 - New Facilities

. Id. at 12. This document can be found on EPA’s website at http://www.epa.gov/ost/316b/.

7-79 correct, SAIC and EPA believe it is not unreasonable to make this assumption. As mentioned above, SAIC did not pick and choose among the matching cost items; all matching items were used. Moreover, SAIC points out that most of the difference between the independent estimates and the USGenNE estimates appear to be attributable to differences in labor rates and man hours for the matching line items. In most cases the Cost Works labor rate and man hour estimates are much lower than the USGenNE estimates. SAIC points out that these types of differences can also be expected for other line items. Finally, as mentioned above, SAIC used the Cost Works data for the third quarter of 2001 and for the Boston area, the most expensive area for Massachusetts. Thus, EPA believes SAIC's approach is unbiased, reasonable and appropriately conservative.

The second analysis conducted by SAIC developed capital cost estimates for the technology alternatives derived from EPA’s costing methodology for estimating facility-level costs used in the development of EPA’s CWA § 316(b) regulations that were recently promulgated for new facilities and recently proposed for large existing power plants (the “316(b) Rule-Based Analysis”). SAIC adjusted the results produced by the cost equations EPA developed for new facilities by the relevant cost factors used by EPA to account for retrofitting a technology to an existing facility, dealing with salt water (which is more corrosive than fresh water and necessitates the use of more expensive materials and better drift control), and using fiberglass cooling towers (as proposed by the permittee) rather than redwood towers (which is the base case for the 316(b) rulemaking cost analysis). 51

SAIC notes that USGenNE estimated costs for the unit-specific options for multiple units by first estimating the cost of converting each individual unit and then adding the costs together. Thus, for example, the cost for the closed-cycle entire station option was calculated simply by summing the costs of separately converting units 1, 2, 3 and 4. SAIC noted that USGenNE’s approach likely overestimated costs because there would likely be some “economy of scale” benefit for multiple unitconversion options. SAIC estimated the total for these benefits to be approximately 6% for the closedcycle entire station option based on the EPA CWA § 316(b) costing methodology. SAIC followed USGenNE’s approach, but made the appropriate adjustment for economy of scale. See Appendix B, p. 9. SAIC also noted that USGenNE increased the cost of the options by 10% for “contingencies” (and an additional 10% for indeterminate costs). SAIC commented that the contingency adjustment appears high because typical contingency allowances for heavy construction projects are more in the range of 4% to 7%. Nevertheless, SAIC ultimately concluded that the 10% factor might not be unreasonable due to possible site-specific factors. Therefore, SAIC also used USGenNE’s 10% factors for both contingencies and indeterminate costs in its analysis. See Appendix B, p. 7.

In addition, because of the permittee’s concern that the use of cooling towers at BPS will cause fog/iceMA0003654 Determinations Document July 22, 2002

7-80 hazards that will require generating unit shutdowns for the unit-specific closed-cycle cooling options, SAIC also estimated costs for two approaches that would obviate any need for such generating unit shutdowns. First, SAIC adjusted the costs to account for pumping and piping necessary to allow the towers to function in a multi-mode fashion. In other words, SAIC determined a capital cost for equipping the cooling towers so that they could be by-passed to allow the generating units to be run in a once-through mode and eliminate any need for generating unit shutdowns. Second, SAIC also determined a cost for outfitting the cooling towers with plume abatement technology (i.e. , traditional wet/dry hybrid cooling towers), rather than multi-mode capability, as another means of eliminating any possible need for generating unit shutdowns.

As SAIC explains, the cost analysis for the 316(b) regulations represents a conservative approach to estimating cooling tower costs (i.e., it will tend to err on the high side). Although this is a costing approach developed for a national, industry-wide cost assessment and, therefore, could fail to account for certain site-specific factors at a given site, SAIC and EPA believe that the results from this method appear to be reasonable and conservative for BPS because even lower numbers were generated by the more site-specific Independent Line Item Analysis discussed above.

The capital costs computed by USGenNE, the SAIC Independent Line Item Analysis, and the EPA/SAIC 316(b) Rule-Based Analysis are presented in the table below.

Table 7.4-1: Capital Costs Technology Option USGenNE EPA/SAIC Independent Line Item Analysis EPA/SAIC 316(b)

Rule-Based Analysis

“Enhanced MultiMode”* $57.4 million $18.8 million $29.3 million

Closed-Cycle Unit 3* $56.4 million $19.8 million $27.0 million
Closed-Cycle Unit 3* (with Multi-Mode) X X $31.3 million

Closed-Cycle Unit 3* (with wet/dry for Plume Abatement) X X $68.3 million

Closed-Cycle Units 1 or 2 & 3* X X $50.8 million

Closed-Cycle Entire Station* $176.7 million $63.9 million $80.7 millionMA0003654 Determinations Document July 22, 2002

Technology Option USGenNE EPA/SAIC Independent Line Item Analysis EPA/SAIC 316(b)

Rule-Based Analysis

7-81 Closed-Cycle Entire Station* (with bypass) X X $93.8 million

Closed-Cycle Entire Station* (with wet/dry for Plume Abatement) X X $202.3 million

* Assumes retrofitting to the existing facility, use of fiberglass towers and equipped for use with salt water.

“X” indicates that no value was calculated for that cell of the Table.

In order to be more conservative in our economic analysis, EPA chose to proceed with our analysis using the numbers from the 316(b) Rule-Based Analysis (i.e., the far right-hand column of the above table) for the options under consideration. Therefore, EPA instructed Abt to use those figures in its economic/financial evaluations.

**ii.** Annual Costs for Auxiliary Power & Operations and Maintenance

SAIC independently assessed likely annual auxiliary power costs (principally to run pumps and fans necessary for the cooling tower systems) and annual operations and maintenance expenses for the various options.

To assess auxiliary power costs, SAIC determined likely hours of operation and capacity for the generating units at BPS based on various data from the permittee. SAIC assessed fan and pump power needs based on values from technical analyses supporting EPA’s 316(b) rulemaking. SAIC indicates that the resulting figures may be “something of an overestimate” because a system would likely turn off fans for some of the cooling tower cells (or reduce their speed, if possible) during cold weather. See SAIC Report (March 15, 2002), p. 19. SAIC provides the auxiliary energy costs in both MWHrs and dollars. The values are converted from MW-Hrs to dollars using an electric energy cost factor of $35/MW-Hr based on the permittee’s figures. SAIC explains that there was no way to refute or confirm the applicability of this figure, so it used the company’s figure. SAIC also noted certain inconsistencies in the auxiliary power figures provided in various submissions by the permittee. SAIC and EPA agreed to resolve these conflicts by using the figures from the Dynamic Cost Analysis, which were the permittee’s most recent figures. SAIC’s auxiliary power consumption penalty estimate was somewhat less than that predicted by USGenNE for the Enhanced Multi-Mode option, but was higherMA0003654 Determinations Document July 22, 2002

7-82 than that predicted by the permittee for the unit-specific closed-cycle options. As a result, SAIC concluded that USGenNE’s auxiliary power estimates were reasonable and could be used in EPA’s independent analysis.

SAIC also estimated overall annual operations and maintenance costs, including annual auxiliary power costs, using the cost equations that EPA used to estimate such costs on a national basis for the 316(b) rulemaking. These cost equations are considered to be conservative and include material, labor and equipment necessary to keep the units operational. This includes preventive maintenance, overhaul maintenance and auxiliary power requirements, but does not include energy efficiency penalties. EPA costs were verified with field data. To compare these numbers with USGenNE’s numbers, it was necessary to subtract energy efficiency values which the permittee had combined with auxiliary power and operations and maintenance costs. SAIC’s overall annual operations and maintenance cost estimates, including auxiliary power costs, were slightly less for the Enhanced Multi-Mode option and significantly higher for the unit-specific closed-cycle options. On the basis of this analysis, SAIC concluded that USGenNE’s annual operations and maintenance and auxiliary power costs estimates were reasonable and could be used in EPA’s independent analysis.

On the basis of this analysis, EPA agreed that the permittee’s costs estimates for annual operations and maintenance and auxiliary power needs were not unreasonable and directed Abt to use the permittee’s values in its economic analysis. These USGenNE figures are presented in the following table:

Table 7.4-2: USGenNE Annual Maintenance and Auxiliary Power Costs Technology Option Maintenance Expense Auxiliary Power Expense*

Enhanced Multi-Mode $240,000/year $2,542,610/year
Closed-Cycle Unit 3 $155,000/year $1,923,005/year
Closed-Cycle Entire Station $500,000/year $5,632,550/year * Figures derived from Table 12 in SAIC Report (March 15, 2002).

**iii.** Annual Costs from Energy Efficiency Penalties

As discussed above, retrofitting cooling towers to an existing power plant will result in a marginal loss of electrical generation efficiency. This lost generation has a cost to the permittee which USGenNE included in its assessment of the costs of the various cooling tower options. SAIC independently assessed the cost from efficiency penalties for EPA.

On the basis of its review, SAIC concluded that USGenNE had significantly overestimated the efficiency losses likely to result from installing cooling towers at BPS. SAIC conducted its analysis by applying the method used by EPA to calculate cooling tower efficiency losses for the Boston area for the recently promulgated CWA § 316(b) regulations for new facilities. SAIC then made the followingMA0003654 Determinations Document July 22, 2002

7-83 adjustments to tailor the analysis to the particular circumstances of BPS: (1) used monthly average intake temperatures for the Taunton River for Units 1, 2 and 3, and for the Lee River for Unit 4; (2) used time-weighted wet bulb temperatures for the 9:00 am to 4:00 pm time period from Providence/T.F. Green Airport historical weather data (the permittee has used T.F. Green weather data for certain of its analyses); and (3) for Unit 4 adjustments were made to reflect 8 months of piggyback operations as currently practiced under the MOA II. By using wet bulb temperatures from the hours of 9:00 am to 4:00 pm, rather than an average over a full 24 hour day, SAIC’s analysis will tend to produce a higher efficiency penalty (i.e., be more conservative economically). In addition, SAIC based its calculations on a design approach of 10° F, rather than the 8° F used in the USGenNE design, which will also tend to produce slightly higher efficiency penalty estimates. SAIC carried out calculations for both the 100% and 67% load cases, and then applied the results to the various technology alternatives based on the plant operating data presented earlier in the report (based on information obtained from the permittee).

The results of SAIC’s analysis along with the USGenNE’s values are presented in the tables below.

Table 7.4-3: Wet Tower Annual Efficiency Losses

Units 1, 2 and 3 Unit 4 (Piggyback)

100% Load 0.29% 0.09%

67% Load 0.75% 0.18%

Table 7.4-4: Annual Efficiency Penalty Estimates by USGenNE and SAIC/EPA Technology Option USGenNE

Efficiency PenaltyEstimate (MWHrs/year) SAIC/EPA

Independent Efficiency PenaltyEstimate (MWHrs/year) Percent

Difference in USGenNE andSAIC/EPA MWHr/year Estimates SAIC/EPA

Independent Efficiency Penalty Estimate Converted to $/year*

Enhanced MultiMode 25,278 10,673 - 58% $373,555

Closed-Cycle Unit 3 64,108 16,629 -74% $582,015

Closed-Cycle Entire Station 124,715 31,779 -75% $1,112,265

* Figures derived for illustrative purposes only by EPA using SAIC efficiency penalty estimateMA0003654 Determinations Document July 22, 2002

7-84 and the USGenNE figure of $35.00 per MW-Hr. The analysis conducted by Abt for EPA estimates more specifically what the actual cost of the efficiency penalty is likely to be over time taking into account the changes in cost of generation and price received over time.

It should be remembered that, as discussed above, BPS is also expected to experience certain annual economic gains as a result of being able to generate moreelectricity during the peak demand hot weather periods during the summer. Depending on the option being analyzed and the conclusions regarding certain other considerations, these gains are likely to either substantially offset, or more than offset, the auxiliary power and efficiency losses presented above. The issue of increased electrical generation allowed by cooling towers during hot weather periods is discussed further below.

**iv.** Generating Unit Construction Outages

The permittee has indicated that it believes that disconnection of the existing once-through cooling system and construction and connection of the cooling tower options will necessitate certain generating unit outages. The permittee has agreed with EPA that these outages should be scheduled to coincide with regular annual maintenance outages as much as possible, but the permittee has also concluded that generating unit outages extending beyond the duration of annual maintenance outages will be necessary for the unit-specific cooling tower options (though not for the Enhanced Multi-Mode option). As a result, the permittee has added a cost for this one-time loss of electrical generation from construction outages to the overall cost of the unit-specific options.

Specifically, the permittee determined that an 8-month outage would be required for installing unitspecific closed-cycle cooling towers for units 1, 2 and 3, and a 3-month outage for unit 4. These outages would run consecutively (i.e., back-to-back) for unit-specific cooling tower options for multiple units. In other words, down-time for converting the entire station to closed-cycle cooling would entail 27 unit-months. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, § 3.3.6.7. Since these outages would run concurrently with the 1-month annual maintenance outage for each unit, the cost of these outages in the permittee’s Dynamic Cost Analysis are based on 7-months of outages for units 1, 2 and 3, and no cost was attributed to the outage for unit 4 because it is not typically on-line
anyway.

SAIC evaluated the permittee’s construction outage estimates and on the basis of a conservative analysis, concluded that the outages appeared to be excessive. SAIC determined that the principal reason for the relatively lengthy construction outages estimated by USGenNE is the permittee’s “decision to install an entirely new set of pumping stations for the recirculation pumps for Units 1, 2 and 3 in a manner that interferes with the current once-through operation.” SAIC Report (March 15, 2002), p. 25. SAIC further explained that, “[t]his decision is based in part on the conclusion that the current pumps, piping and condenser may not be capable of handling the additional hydraulic pressure that would occur with the system if the condenser outlet were to be simply re-routed to the top of the new cooling towers.” Id

.MA0003654 Determinations Document July 22, 2002

7-85 In evaluating the permittee’s approach, SAIC accepted USGenNE’s concerns about piping and condenser pressure as valid. SAIC also reviewed four case studies involving large power plants that converted from once-through cooling to cooling with closed-cycle mechanical draft cooling towers (note: one plant uses the towers in a helper mode). See SAIC Report (March 15, 2002), Attachment A. The conversions in the case studies were undertaken with either no outages or far shorter outages than those estimated by the permittee, such as the 27 unit-months of outage that the permittee estimates for the Closed-Cycle Entire Station option. SAIC explains that these other plants have “mostly been able to incorporate the existing pumps and pump stations, the existing condensers and much of the existing piping into the closed cycle systems.” Id . at p. 26. All but one of the four case study facilities were able to retain the existing once-through cooling water pumps and pumphouses and incorporate them into the wet cooling tower recirculation system, while “[t]he other facility kept the downtime brief by installing a separate new pumphouse and piping in a manner that did not interfere with the existing system while under construction.” As a result of this approach, the latter facility only required downtime to “disconnect the existing once-through cooling water pipes and reconnect the new cooling water system pipes.” Id . SAIC concluded that it is likely that either approach would be feasible for units 1, 2 and 3.

Nevertheless, SAIC took a conservative approach and assumed that the current once-through pumps would require replacement. Even still, SAIC concluded that unit outage time could be shortened by retaining the existing pumphouse, replacing the existing pumps and then connecting the discharge pipe to the cooling towers. SAIC explained that:

[a]s with USGenNE’s proposed engineering design, water would flow by gravity through the condensers but would then be piped back to the intake wet well of the existing intake pumping station. Such a pump and pipe configuration would require the closing off of the individual intake bays for each unit, the replacement of the intake pumps, installation of the cooling water return piping from the condenser, replacement of electrical and control equipment, and tie-in of the new pump outlet pipe to the cooling tower. Without more detailed information regarding the intake structure configuration, it cannot be determined what other modification to the intakes might be necessary. However, the savings in construction costs for replacing the pumphouse should more than offset any modification costs. Certainly, the case study facilities came to that conclusion.

Id ., p. 27. SAIC further explained that this approach would eliminate various aspects of the permittee’s downtime estimate and also potentially some items of cost. SAIC then added back in two weeks of time to account for the constraints of working within the existing pumphouses. As a result of this approach, SAIC concluded the outage could conservatively be reduced to 4 months. Indeed, SAIC felt that it might be possible to reduce the outage to the 3-month figure the permittee estimated for Unit 4, but due to unknowns about possible intake differences between the Unit 4 intake and the intake for units 1, 2 and 3, it retained the 4-month estimate for each unit. SAIC prepared a detailedMA0003654 Determinations Document July 22, 2002

7-86 construction-related unit downtime estimate for Unit 1 specifically, but concluded that the same approach and outage reductions could be achieved for units 2 and 3 as well. More details on the construction outage analysis are presented in Appendix B.

Table 7.4-5: USGenNE and Independent Construction Outage Estimates Technology Option USGenNE

Construction Outage Estimate(total unitmonths) USGenNE

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage) EPA/SAIC

Construction Outage Estimate(total unitmonths) EPA/SAIC

Construction Outage Estimate (unit-months likely to cause generation losses in excess of normal maintenance outage)

Enhanced MultiMode 5.5 (broken into

different periods for individual units) 0 5.5 (broken into different periods for individual units) 0

Closed-Cycle Unit 3 8 (for Unit 3) 7 (for Unit 3) 4 (for Unit 3) 3 (for Unit 3)

Closed-Cycle Entire Station 27 (made up of

separate 8-month periods for Units 1, 2 & 3, and 3 months for Unit 4) 21 (made up of

separate 7-month periods for Units 1, 2 & 3) 15 (made up of

separate 4-month periods for Units 1, 2 & 3, and 3 months for Unit 4) 9 (made up of

separate 3-month periods for Units 1, 2 & 3)

On the basis of the SAIC analysis, supported by the case studies, EPA believes the generating unit outage period of 4 months (i.e. , three months in excess of the one-month annual maintenance outage) for units 1, 2 and 3 are reasonable and conservative and directed that these figures be used in the Abt economic analysis.

**v.** Period for Constructing the Closed-Cycle Entire Station Option

In light of the above-reductions in construction time for unit-specific cooling towers, SAIC also assessed the overall construction period estimated by USGenNE for the closed-cycle entire stationMA0003654 Determinations Document July 22, 2002

7-87 option. USGenNE estimated 47 months for the overall construction period. SAIC concluded that the construction period could be shortened in light of the above reduced estimates for construction of the individual unit-specific cooling tower systems. The construction period could not, however, reasonably be reduced by the full amount of the reduction for each individual unit because of the necessary sequencing of various tasks for bringing each unit on-line. SAIC concluded that the construction period for the closed-cycle entire station could be reduced from USGenNE’s 47-month estimate to an estimate of 39 months. EPA instructed Abt to use the 39-month construction period in its economic analysis.

7.4.3b “Financial Aspects” of Cost Analysis

Abt conducted a multi-faceted, independent analysis of the cost over time to the permittee of various technology options. This analysis took into account capital costs, the cost of one-time construction outages, various annual costs (e.g., operations and maintenance costs, auxiliary power cost penalties, reduced generation efficiency penalties, alleged vapor plume abatement outage penalties), and taxes. This analysis presents the overall accumulated costs over the specified time period both as a total present value, after-tax cash flow total cost and as an equivalent annual present value, after-tax cash flow cost.

There are numerous complexities involved in undertaking this type of analysis. For example, determining the cost of the various types of electrical generation reductions associated with each option (e.g., construction outages, auxiliary energy penalties), requires estimation of the additional profits that could have been made over time if that generation had not been lost, which in turn requires that estimates be developed of the cost of producing the electricity over time and subtracted from estimates of the price at which it could be sold over time. Despite these complexities, USGenNE, EPA and the MA DEP all agreed that this type of analysis was the most appropriate way to assess the cost to the permittee of the various technology options. (All the parties agreed this approach was a more accurate way of assessing costs than the “static cost” analysis that the permittee initially presented to the regulatory agencies in June 2001.) Thus, the permittee also conducted this type of analysis in its “Dynamic Cost Analysis,” which was submitted to EPA as part of the December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. III, Appendix G (Tab: Dynamic Cost Analysis). Abt’s analysis and the Dynamic Cost Analysis undertake equivalent assessments and their results can be meaningfully compared with each other.

One step in Abt’s analysis was essentially to re-create the Dynamic Cost Analysis’s financial assessment model. Abt did this to ensure that it correctly understood the permittee’s analysis, to assess the validity of the permittee’s approach, and to determine whether the permittee’s results were accurate based on the model used and the inputs to it. As Abt stated, this represented a type of “due diligence” review.MA0003654 Determinations Document July 22, 2002

7-88 Abt then went to vary inputs to the model as it deemed appropriate based on its independent expert opinion on financial/economic issues and as directed by EPA on the basis of the independent expert opinion of SAIC and EPA regarding engineering issues. An example of the former type of issue would be use of a discount rate different than that used by the permittee, whereas an example of the latter type of issue would be use of different capital costs than those used by the permittee. For a number of factors, Abt analyzed a variety of alternative scenarios in order to ensure that issues were considered from more than one perspective and to discern the overall effect on the results of the choices made with respect to these factors. For example, as discussed below, Abt looked at overall costs over both a 20- year and a 30-year equipment operating life.

The financial/economic analysis conducted by Abt is quite complex and it is explained and presented in detail in the report attached hereto as Appendix C and incorporated herein by reference. We will not repeat it in detail here. We will, however, present its key results and discuss some of the key factors that went into it.

**i.** Abt**“Replication”** of USGenNE Dynamic Cost Analysis Model

In order to analyze candidate technology options, Abt developed an analytic framework that essentially replicates USGenNE’s analysis. Apart from presentation differences, Abt’s analytic framework differs materially from the permittee’s framework only in including the ability to adjust the time period of analysis and recognize explicitly the estimated schedule requirements for installation of capital equipment and subsequent operating periods for technology equipment. In constructing the analytic framework and validating the permittee’s analysis, Abt was able to replicate the analyses presented in the “Dynamic Cost Analysis” in virtually all respects, including replication of the electricity price and input fuel cost schedules used in the permittee’s analysis. However, while Abt was able to replicate the growth rates of the electricity price and input fuel cost schedules going forward in time, based on the electricity price and fuel cost forecasts developed by RDI (and submitted to EPA by USGenNE), including those that depend on a blending of on- and off-peak price schedules, Abt was not able to independently verify the first-year values of electricity prices and input fuel costs for these schedules. These first-year values are reported by the permittee to be the current – presumed 2001 – values observed in operation of the Brayton Point Station plant. Accordingly, while the projections of future electricity prices and input fuel costs track the RDI projections in terms of change over time, the absolute numerical values in these schedules depend on the permittee’s reported baseline values. Again, Abt was not able to independently validate these baseline values which provide the “seed” for the future projection schedules. Therefore, Abt had to use these baseline values.

In addition, Abt’s examination and replication of USGenNE’s analyses, Abt Report (April 5, 2002), pp. 39-40, revealed the following two calculation errors by the permittee which materially affect its results:

1. Spreadsheet cells improperly referenced in calculations . In the permittee’s model for theMA0003654 Determinations Document July 22, 2002

7-89 Closed Cycle-All alternative, the spreadsheet row labeled “After-Tax Annual Cost” is improperly calculated. Specifically, the spreadsheet row titled “Tax Cost (Savings)” is added to the row labeled “Total Cost of Plume Abatement” instead of the proper row “Annual Cost” for the calculation of “After-Tax Annual Cost.” As a result, total after-tax annual costs are understated

in all years of the analysis and the subsequent calculations of present value and equivalent annual cost carry forward this error. When corrected, the total present value of cost for this option under the permittee’s 15 percent discount rate increases by $15.7 million. The permittee’s analysis does not make this error in its analysis of the Enhanced Multi-Mode and Closed Cycle -Unit 3 options.

2. Failure to account for the tax treatment of the construction outage income loss. In its analysis of the Closed Cycle -Unit 3 and Closed Cycle -All options, the permittee does not account for the tax treatment of the income loss during construction outages: the construction outage causes a reduction in income, which in turn reduces the permittee’s tax liability during that operating period. This treatment is inconsistent with the permittee’s proper recognition of the tax treatment of other revenue and cost effects from installation and operation of technology equipment. As a result, the permittee’s analysis overstates the cost of the Closed Cycle -Unit 3 and Closed Cycle -All technology options by $21.3 million and $39.1 million, respectively. This error is irrelevant to the permittee’s analysis of the Enhanced Multi-Mode option, because the permittee anticipates no construction outage income loss from this option.

The net effect of these errors is that the permittee’s analysis overstates – within its own framework of calculations and cost estimates – the total present value of cost, in the permittee’s 15 percent discount rate case, by $21.3 million for the Closed Cycle -Unit 3 option, and by $23.4 million for the Closed Cycle -All option. These errors are material in the permittee’s analysis, representing approximately 17 percent of the permittee’s total present value of cost for the Closed Cycle -Unit 3 option and approximately 15 percent of the permittee’s total present value of cost for the Closed Cycle -All option.

In response to these two errors, when presenting the permittee’s cost estimates for the purpose of comparison with Abt’s independent estimates, Abt corrected the permittee’s numbers to fix the two errors. As a result, Abt’s re-estimates of the permittee’s cost and cost effectiveness values for the Closed Cycle-Unit 3 and Closed Cycle-All options are somewhat lower than the values actually reported by the permittee in the Dynamic Cost Analysis.

In addition, Abt noted that its calculations also yielded other small differences from the Dynamic Cost Analysis values and interpreted them to arise from rounding. Abt indicated that these differences amounted to no more than a few thousand dollars in any given instance and concluded that the differences were inconsequential in the aggregate.MA0003654 Determinations Document July 22, 2002

7-90 **ii.** Elements of Abt’s Independent Financial/Economic Analysis

Some of the key aspects of Abt’s independent financial/economic analysis are discussed below.

Capital Costs. Abt used the capital costs from SAIC’s independent CWA § 316(b) Rule costing methodology-based analysis. As explained above, EPA directed Abt to use these figures rather than the figures from SAIC’s line-item approach, because the former were higher and would therefore result in a more conservative analysis.

Duration of Construction Outage. As discussed above, Abt used the construction outage figures calculated by SAIC.

Date for Commencement of Construction; Timing of Construction Outage. The time that one assumes construction would begin (and end) and the timing of the construction outages both impact the results of the economic analysis. USGenNE’s Dynamic Cost Analysis assumed that construction began and ended in 2001 and valued the construction outage based on the “spark spread price” from 2001. Given that it was already early 2002 as Abt was working on its analysis, it is indisputable that construction could not begin and end in 2001. Therefore, EPA and Abt agreed to use mid-2002 as the time for construction to start. In addition, Abt assumed that construction outages would occur at the end of the construction period and, therefore, valued the outages based on the spark spread price estimated for those times.

Construction Duration. As discussed above, the timing of construction and any outages affects thefinancial/economic analysis. Abt used the construction duration calculated by SAIC for the closedcycle Unit 3 option and the closed-cycle entire station option, but consistent with SAIC’s recommendation used the USGenNE construction duration estimate for the Enhanced Multi-Mode option.

Operations and Maintenance. Consistent with SAIC’s recommendation, EPA directed Abt to use the annual operations and maintenance expenses developed by USGenNE.

Auxiliary Energy Cost Penalties. Consistent with SAIC’s recommendation, EPA directed Abt to use the annual auxiliary energy penalties (in MWHrs) developed by USGenNE. Like the permittee, Abt also valued these penalties on the basis of lost revenue.

Energy Efficiency Cost Penalties. As discussed above, EPA directed Abt to use the annual energy efficiency penalty figures(in MWHrs) developed by SAIC. Like the permittee, Abt valued these penalties on the basis of lost revenue.MA0003654 Determinations Document July 22, 2002

7-91 Economic Gain from “Avoided Load Loss.” As discussed above, the permittee acknowledges that the cooling tower options offer an economic benefit because they enable greater electrical generation during certain peak demand (and therefore peak sales price) hot weather periods during which the permittee currently must curtail (or cap) generation to avoid violating the 95° F maximum temperature discharge limit presently in its NPDES permit. Abt has referred to this benefit as the “avoided load loss.” This benefit occurs because summer intake water temperatures can get high enough that heat added to the water by the power plant can push the discharge temperature over 95° F, but cooling towers can minimize this problem by rejecting heat to the atmosphere rather than back to Mount Hope Bay in the cooling water.

In its calculations, Abt used USGenNE’s estimate of the extent of avoided load loss events, which was based in part on permittee historical data from 1989 to 1999. In light of data (discussed elsewhere in this document) indicating an upward, long-term trend in the temperature of the waters of Mount Hope Bay (and Narragansett Bay), EPA notes that using the 1989-1999 data is likely to result in a relatively conservative estimate of avoided load loss events henceforth. Further, Abt noted that if the permittee had used data that included the very warm summer of 2001, then its estimated value of the avoided load loss also would have been higher. While acknowledging the avoided load loss benefit, USGenNE also determined that if it discharged more heat during peak periods, then in order to remain within its overall permit limits it would have to offset the increases by reducing generation during off-peak (and therefore lower sales price) periods. Abt followed the permittee’s approach to handling and estimating the value of this offset.

In addition, USGenNE estimated that the Enhanced Multi-Mode and closed-cycle entire stationoptions would be able to capture all (100%) of the potential avoided load loss, but that the closedcycle unit 3 option would only be able to capture part (48.6%) of the potential benefit. The permittee did not clearly explain how it came up with the 48.6% figure and Abt was unable to independently verify it. With no clear basis for an alternative figure, EPA and Abt decided to take the conservative approach of using the permittee’s figures.

In order to place a dollar value on avoided load losses, the profits that would have been lost to generating load curtailment must be calculated. This is done by determining baseline figures for the fuel cost for producing the electricity and for the price at which that electricity could have been sold. Working from these baseline figures, future changes in electricity prices and fuel costs must then be estimated to determine the future value of the net loss in operating income to the permittee from the predicted curtailment in generation that would have occurred in the absence of a particular cooling tower option.

In reviewing both the USGenNE static economic analysis from July 2001 and the Dynamic Cost Analysis submitted to EPA in December 2001, Abt found that the permittee used different baseline spark spread price schedules in the two analyses. In its July 2001 analysis, USGenNE used a schedule based on wholesale electricity prices from the summer of 1999. In the Dynamic Cost Analysis,MA0003654 Determinations Document July 22, 2002

7-92 however, the baseline price schedule was reportedly based on price data from 1999 and 2000 ( but not from the very warm summer of 2001 ). The schedule in the Dynamic Cost Analysis substantially reduced the price schedule from the July 2001 range of $20.00 to $400.00 per MWHr to a new range of $35.66 to $78.13 per MWHr. Abt found that this substantially reduces the value of the avoided load loss benefit (e.g., a 28% reduction in the baseline year). Abt also found that no data was provided by the permittee supporting a cap on the spark spread price at $78.13 per MWHr. Therefore, Abt conducted an independent analysis to judge the reasonableness of the spark spread price schedule by reviewing energy clearing price (ECP) data for the summers of 1999, 2000 and 2001 obtained from Independent System Operator-New England (ISO). Abt found that values ranged as high as $1000 per MWHr, with a maximum average for a given temperature of $409.06 per MWHr. Therefore, Abt concluded that it could not justify the $78.13 cap on the spark spread price schedule used in the Dynamic Cost Analysis, and that the baseline schedule from the permittee’s July 2001 static analysis appeared to be more reasonable. As a result, in assessing the avoided load loss benefit for the independent financial/economic analysis, Abt used the baseline spark spread price schedule from the permittee’s July 2001 static analysis.

Building off the baseline spark spread price schedule, the USGenNE Dynamic Cost Analysis estimated the operating effects over time of the avoided load loss benefit based on a forecast of year-to-year changes in on-peak wholesale electricity prices, fuel costs, and spark spread prices developed by Resource Data International (RDI). Abt concluded that the permittee’s approach here was reasonable. Therefore, Abt used the “implied growth rates” from the Dynamic Cost Analysis to project future spark spread price values from the permittee’s July 2001 (static analysis) baseline schedule.

Unit Outages to Abate Alleged Hazard from Cooling Tower Water Vapor Plumes. As discussed elsewhere in this document, the permittee has concluded that generating unit outages will be necessary for the unit-specific cooling tower options in order to abate potential fog and/or ice hazards from cooling tower water vapor plumes. Although a very small number of hours of potential cooling tower-induced fog or ice were predicted by its model, the permittee’s analysis nevertheless concludedthat hundreds of hours of outage would be needed to prevent these few hours of predicted towerinduced fog and/or ice. The cost of these outages is a significant element in the permittee’s economic analysis. The permittee estimates that no such outages will be needed for the Enhanced Multi-Mode option because the cooling towers can be bypassed.

EPA has explained its skepticism about the permittee’s conclusions elsewhere in this document. In light of this skepticism, EPA asked Abt to assess the financial ramifications of several different scenarios. First, we asked Abt to evaluate the matter assuming no plume abatement unit outages. For this scenario, however, we instructed Abt to use the SAIC capital cost estimates that include an upward adjustment for the cost of adding piping and pumping to enable the unit-specific option to be operated in a multi-mode fashion so that the cooling towers could be bypassed if necessary. Abt’s analysis showed that these increased capital costs would be more than offset by the economic benefit of avoiding the permittee’s predicted unit outages. Second, we asked Abt to evaluate costs assuming thatMA0003654 Determinations Document July 22, 2002

7-93 100% of the permittee’s predicted outages would, in fact, be necessary. Third, we asked Abt to evaluate costs assuming that 50% of the permittee’s predicted outages would be necessary. For the latter two scenarios, Abt used SAIC’s estimated capital costs for the unit-specific options without the cost adjustment for modifications to operate in a multi-mode fashion. In order to determine the cost to the company of the outages, Abt followed the permittee’s approach, including the use of RDI data to determine the future revenue losses due to the outages.

Life of Capital Equipment; Time Horizon for Economic Analysis. The permittee assumed a 20- year life for the capital equipment. It also assumed that construction began and ended in 2001 and did its present value calculations at 2001.

EPA, SAIC and Abt concluded that 20 years might underestimate the reasonable life of the capital equipment, including the likely remaining life of the major components of the entire Brayton Point Station, and concluded that 30 years might be a more reasonable figure. Indeed, for the CWA § 316(b) rulemaking, EPA has assumed a 30-year life for this equipment. Therefore, Abt did its analyses for two scenarios: one assuming a 20-year life and one assuming a 30-year life. As discussed above, Abt assumed that construction began in mid-2002, determined the first year of operation based on the particular option’s construction schedule, and Abt did its present value calculations back to mid-2002.

Depreciation. USGenNE’s Dynamic Cost Analysis used a 20-year straight-line depreciation schedule, with no depreciation recorded in the first year of operation (i.e., only 19 years of depreciation were included). Abt concluded that it was not reasonable to omit the first year of depreciation and, as a result, recorded a full year of depreciation in the first operating year. Abt noted that its approach yielded a lesser depreciation tax benefit than what would have accrued if a Modified Accelerated Cost Recovery Schedule (MACRS) had been used instead of the 20-year straight-line approach, and that a MACRS approach probably would be appropriate in this case. Therefore, Abt’s decision to use a 20- year straight-line schedule, but to include depreciation in the first operating year, is a reasonable and conservative approach.

Discount Rate.

USGenNE did not want to reveal its internal company discount rate/cost of capital, which it regards as highly confidential business information. As a result, the permittee used a range of discount rates that it stated would encompass the rate it would use in its assessment of investment opportunities. USGenNE then conducted its Dynamic Cost Analysis for two scenarios: one using a discount rate of 15% and one using a discount rate of 20%.

In order to test the reasonableness of the permittee’s figures, Abt undertook a cost-of-capital analysis for six comparable merchant power producers. From this analysis, Abt estimated a market capitalization-weighted cost-of-capital of 11.8%. Abt then used this figure as the discount rate for its analyses.MA0003654 Determinations Document July 22, 2002

7-94 **iii.** Results of Abt’s Analysis Compared to USGenNE’s Analysis

Abt’s financial/economic analysis yielded costs that were substantially lower than the costs indicated by the USGenNE analysis. A number of factors played into this, but the most important was the difference in capital cost inputs, followed (in no particular order) by efficiency penalty inputs, treatment of the water vapor plume abatement issue, construction outage inputs and avoided load loss inputs. It should be noted that under Abt’s 30-year cost assessment, the Enhanced Multi-Mode option would actually earn money for the permittee due to the combination of the avoided load loss benefit over time and the other factors previously mentioned. As described above, Abt also evaluated a number of different scenarios by varying certain elements in the analysis. The several tables below present a comparison of some of the key conclusions of Abt’s analysis with that of the permittee.MA0003654 Determinations Document July 22, 2002

7-95 Table 7.4-6: Comparison of Selected USGenNE and EPA/Abt Cost Scenarios

Technology Option USGenNE 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures (using 11.8 Discount Rate and other independent values) (over 30 years)

Enhanced Multi-Mode Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $38.233 Million

$6.108 Million $1.077 Million

$142 Thousand - $909 Thousand*

- $111 Thousand*

Closed-Cycle Unit 3 0% plume abatement 2
Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

50% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 4

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

Not Calculated

Not Calculated

$104.949 Million

$16.767 Million $23.574 Million

$3.117 Million

$29.710 Million

$3.928 Million

$38.861 Million

$5.138 Million $23.031 Million

$2.817 Million

$30.337 Million

$3.710 Million

$40.658 Million

$4.973 MillionMA0003654 Determinations Document July 22, 2002

Technology Option USGenNE 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures (using 11.8 Discount Rate and other independent values) (over 30 years)

7-96 Closed-Cycle Entire Station Units

0% plume abatement 2
Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

50% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 4

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

Not Calculated

Not Calculated

$254.485 Million

$40.657 Million $68.385 Million

$9.041 Million

$71.685 Million

$9.477 Million

$83.269 Million

$11.009 Million $67.975 Million

$8.314 Million

$72.747 Million

$8.898 Million

$85.803 Million

$10.494 Million

* Negative numbers indicate the permittee is gaining the indicated amount of money.

1 The USGenNE figures for Closed-Cycle Unit 3 and Closed-Cycle Entire Station Units reflect the permittee’s capital costs and its assumptions for generating unit outages for water vapor plume abatement.

2 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid generating unit outages for plume abatement.

3 The Abt/EPA “50% plume abatement” numbers reflect calculations including 50% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.

4 The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.MA0003654 Determinations Document July 22, 2002

7-97 Table 7.4-7: USGenNE Total & Annual Equivalent Costs (with & without Calculation Errors Corrected by Abt)
Technology Option USGenNE Figures

(15% Discount Rate/over 20 years) w/o Calculation Correction USGenNE Figures

(20% Discount Rate/over 20 years) w/o Calculation Correction Abt-Replicated

USGenNE Figures w/ calculation Correction (15% Discount Rate/over 20 years) Abt-Replicated

USGenNE Figures w/ calculation Correction (20% Discount Rate/over 20 years)

Enhanced MultiMode

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $38,226,000

$6,107,000 $41,981,000

$8,621,000 $38,228,000

$6,107,000 $41,983,000

$8,621,000

Closed-Cycle Unit 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $126,289,000

$20,176,000 $122,688,000

$25,195,000 $104,964,000

$16,769,000 $101,366,000

$20,816,000

Closed-Cycle Entire Station Units

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: $267,294,000

$42,703,000 $268,717,000

$55,183,000 $254,768,000

$40,702,000 $250,638,000

$51,470,000MA0003654 Determinations Document July 22, 2002

7-98 Table 7.4-8: Abt/EPA Cost Estimates Over 20- and 30-Year Periods
Technology Option (& Plume Abatement Assumption) Abt/EPA Total After-Tax Cash Flow Cost, Present Value (20-Year Period) Abt/EPA Annual Equivalent Cost (20-Year Period) Abt/EPA

Total After-Tax Cash Flow Cost, Present Value (30-Year Period) Abt/EPA

Annual Equivalent Cost (30-Year Period)

Enhanced Multi-Mode

(No Plume Abatement) 2 $1.077 Million $142 Thousand - $909 Thousand 1 - $111 Thousand 1

Closed-Cycle Unit 3

0% Plume Abatement 3

50% Plume Abatement 4

100% Plume Abatement 5 $23.574 Million

$29.710 Million

$38.861 Million $3.117 Million

$3.928 Million

$5.138 Million $23.031 Million

$30.337 Million

$40.658 Million $2.817 Million

$3.710 Million

$4.973 Million

Closed-Cycle Entire Station

0% Plume Abatement 3

50% Plume Abatement 4

100% Plume Abatement 5 $68.385 Million

$71.685 Million

$83.269 Million $9.041 Million

$9.477 Million

$11.009 Million $67.975 Million

$72.747 Million

$85.803 Million $8.314 Million

$8.898 Million

$10.494 Million

1 Negative numbers indicate the permittee is gaining the indicated amount of money.

2 USGenNE has concluded no plume abatement generating outages are needed for the Enhanced Multi-Mode option. EPA/Abt adopted this assumption as well.

3 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid generating unit outages for plume abatement.

4 The Abt/EPA “50% plume abatement” numbers reflect calculations including 50% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.

5 The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode functioning.MA0003654 Determinations Document July 22, 2002

7-99 Table 7.4-9: Detailed USGenNE and EPA/Abt Costs for Enhanced Multi-Mode Option

Parameter USGenNE

(15% Discount Rate) (w/ Calculation Errors Corrected by Abt) (20-Year Period) EPA/Abt (using 11.8% Discount Rate and other Independent Elements) (20

Years) EPA/Abt (using 11.8%

Discount Rate and other Independent Elements) (30

Years)

Capital Costs $57.406 Million $24.054 Million $24.054 Million

Construction Outage Cost $0 $0 $0

Total Initial Cost, Net Depreciation Tax Benefit $50.112 Million $20.324 Million $20.324 Million

Maintenance $1.186 Million $1.070 Million $1.207 Million

Auxiliary Energy and Efficiency Penalties $13.775 Million $9.896 Million $10.965 Million

Avoided Load Loss Benefit - $26.840 Million 1 - $30.212 Million 1 - $33.405 Million 1

Cost of Plume Abatement $0 $0 $0

Total of Annual Expenses, After Tax -$11.879 Million 1 - $19.246 Million 1 - $21.232 Million 1

Present Value Total After-Tax Cash Flow $38.233 Million $1.077 Million - $909 Thousand 1

Equivalent Annual Cost $6.108 Million $142 Thousand - $111 Thousand 1

1 Negative numbers indicate the permittee is gaining the indicated amount of money.MA0003654 Determinations Document July 22, 2002

7-100 Table 7.4-10: Detailed USGenNE and EPA/Abt Costs for Closed-Cycle Unit 3 Option

Parameter USGenNE

(20 Years) 100% Plume* 1 EPA/Abt

(20 Years) 0% Plume* 2 EPA/Abt

(20 Years) 50% Plume* 2 EPA/Abt

(20 Years) 100% Plume* 2 EPA/Abt

(30 Years) 0% Plume* 2 EPA/Abt

(30 Years) 50% Plume* 2 EPA/Abt

(30 Years) 100% Plume* 2

Capital Costs $56.4

Million $25.692

Million $22.123

Million $22.123

Million $25.692

Million $22.123

Million $22.123

Million

Construction Outage Cost $30.688

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million $7.349

Million

Total Initial Cost, Net Depreciation $79.921

Million $29.057

Million $26.042

Million $26.042

Million $29.057

Million $26.042

Million $26.042

Million

Maintenance $0.766

Million $0.691

Million $0.691

Million $0.691

Million $0.780

Million $0.780

Million $0.780

Million

Aux. Energy & Efficiency Penalties $16.747

Million $8.501

Million $8.501

Million $8.501

Million $9.419

Million $9.419

Million $9.419

Million

Avoided Load Loss Benefit - $13.036

Million 3 - $14.674

Million 3 - $14.674

Million 3 - $14.674

Million 3 - $16.225

Million 3 - $16.225

Million 3 - $16.225

Million 3

Cost of Plume Abatement $20.566

Million $0 $9.151 Million $18.302

Million $0 $10.321 Million $20.642

Million

Total Annual Expenses, After Tax $25.043

Million - $5.482

Million 3 $3.669

Million $12.819

Million - $6.026

Million 3 $4.295

Million $14.616

Million

Present ValueTotal AfterTax Cash Flow $104.964

Million $23.574

Million $29.710

Million $38.861

Million $23.031

Million $30.337

Million $40.658

Million

Equivalent Annual Cost $16.769

Million $3.117

Million $3.928

Million $5.138

Million $2.817

Million $3.710

Million $4.973

Million * USGenNE figures for the Closed-Cycle Unit 3 option reflect the permittee’s capital cost estimates and predicted generating unit outages for water vapor plume abatement. Abt/EPA figures for the “0% Plume” case reflect no unit outages for plume abatement, but do reflect the SAIC estimates of capital costs that were increased to reflect piping and pumping to equip the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid any plume abatement outage. Abt/EPA figures for the “50% Plume” and “100% Plume” reflect the stated percentage of the permittee’s predicted plume abatement outages, but also reflect the SAIC capital cost estimates that were not adjusted for multi-mode capacity.

1 USGenNE figures reflect its analysis using a 15% discount rate, with calculation errors corrected by Abt.

2 Abt/EPA figures reflect a discount rate of 11.8%, as explained above.
3 Negative numbers indicate the permittee is gaining the indicated amount of money.MA0003654 Determinations Document July 22, 2002

7-101 Table 7.4-11: Detailed USGenNE and EPA/Abt Costs for Closed-Cycle Entire Station Units Option

Parameter USGenNE

(20 Years) 100% Plume* 1 EPA/Abt

(20 Years) 0% Plume* 2 EPA/Abt

(20 Years) 50% Plume* 2 EPA/Abt

(20 Years) 100% Plume* 2 EPA/Abt

(30 Years) 0% Plume* 2 EPA/Abt

(30 Years) 50% Plume* 2 EPA/Abt

(30 Years) 100% Plume* 2

Capital Costs $176.676

Million $70.592

Million $60.788

Million $60.788

Million $70.592

Million $60.788

Million $60.788

Million

Construction Outage Cost $56.290

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million $13.325

Million

Total Initial Cost, Net Depreciation $210.517Mi

llion $72.971

Million $64.686

Million $64.686

Million $72.971

Million $64.686

Million $64.686

Million

Maintenance $2.347

Million $1.945

Million $1.945

Million $1.945

Million $2.195

Million $2.195

Million $2.195

Million

Aux. Energy & Efficiency Penalties $40.182

Million $20.805

Million $20.805

Million $20.805

Million $23.055

Million $23.055

Million $23.055

Million

Avoided Load Loss Benefit - $26.840

Million 3 - $27.336

Million 3 - $27.336

Million 3 - $27.336

Million 3 - $30.245

Million 3 - $30.245

Million 3 - $30.245

Million 3

Cost of Plume Abatement $28.278

Million $0 $11.584 Million $23.169

Million $0 $13.056 Million $26.112

Million

Total Annual Expenses, After Tax $43.968

Million - $4.586

Million 3 $6.998

Million $18.583

Million - $4.995

Million 3 $8.061

Million $21.117

Million

Present ValueTotal AfterTax Cash Flow $254.485

Million $68.385

Million $71.685

Million $83.269

Million $67.975

Million $72.747

Million $85.803

Million

Equivalent Annual Cost $40.657

Million $9.041

Million $9.477

Million $11.009

Million $8.314

Million $8.898

Million $10.494

Million * USGenNE figures for the Closed-Cycle Unit 3 option reflect the permittee’s capital cost estimates and predicted generating unit outages for water vapor plume abatement. Abt/EPA figures for the “0% Plume” case reflect no unit outages for plume abatement, but do reflect the SAIC estimates of capital costs that were increased to reflect piping and pumping to equip the cooling towers to function in multi-mode fashion so that they could be bypassed to avoid any plume abatement outage. Abt/EPA figures for the “50% Plume” and “100% Plume” reflect the stated percentage of the permittee’s predicted plume abatement outages, but also reflect the SAIC capital cost estimates that were not adjusted for multi-mode capacity.

1 USGenNE figures reflect its analysis using a 15% discount rate, with calculation errors corrected by Abt.

2 Abt/EPA figures reflect a discount rate of 11.8%, as explained above.
3 Negative numbers indicate the permittee is gaining the indicated amount of money.MA0003654 Determinations Document July 22, 2002

7-102 **iv.** Screening and/or Pumping Options

As discussed above, the permittee has indicated that it intends to implement certain improvements to the pumping and screening systems to further minimize flow and enhance impingement survival. EPA has explained above that it does not regard any of these alternatives to constitute BTA by themselves, but that they could be part of a BTA option. The permittee also did not propose that these technologies would constitute BTA by themselves.

With respect to pumping/flow changes, the permittee did not indicate a clear preference among the two-speed pump, variable speed pump drive and throttled flow operations alternatives. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, pp. 3.5-14; 4-6. The costs for these options are small on a relative basis, with capital costs ranging from $600,000 to $2.5 million and maintenance costs ranging from $2,000 to $100,000 per year. See December 2001 USGenNE 316(a) and (b) Demonstration
, Vol. IV, Table 4-1. With respect to screening system improvements, it appears, but is not entirely clear, that the permittee is proposing to implement the modified conventional traveling screen design for Units 1, 2 and 3. See Id . at p. 3.6-16. These improvements may include, for example, improved fish buckets and spray washes. The permittee estimates capital costs for this option to be $1.3 Million with no increased annual maintenance costs. See Id . at Table 4-1.

Given that the above costs are low relative to the cooling tower system-related costs, and given EPA’s desire to conserve financial resources for expert contractor assistance on more significant issues, we did not ask our contractors to independently evaluate the costs of these options or to work them into the overall financial analysis. Therefore, EPA accepts the permittee’s estimates of the costs for these options and considers them to be easily affordable add-ons to whatever larger BTA option is selected.

7.5 Biological Impacts of Cooling Water Intake

Section 316(b) of the Clean Water Act addresses the adverse environmental impact of cooling water intake structures at facilities requiring NPDES permits. Adverse environmental impact by cooling water intake structures results from the entrainment of fish eggs and larvae and other marine life through the plant’s cooling system and the impingement of fish and other marine life on the intake screens. Adverse impacts can also result in some areas from a power plant’s use of limited public water resources for cooling.

EPA has considered a wide range of data and analyses from many sources including the permittee. We note, however, that on July 3, 2002, the permittee submitted three new papers presenting biological analyses by its hired contractors. As a result of the late date of the submission, EPA was not able to consider the new studies prior to issuance of the draft permit. EPA does, however, look forward to giving these analyses careful evaluation during the public comment period, along with any other public comments and/or new information that may be submitted.MA0003654 Determinations Document July 22, 2002

52Memorandum from Russell A. Isaac to John R. Elwood, “Subject: Brayton Point Permit Modification Hearing at Somerset High School on June 30, 1976" (July 2, 1976) (“Dr. George Mathieson of Marine Research, Inc., who has conducted studies at the plant for the company during the past 6 years,...stated that Mount Hope Bay continues to rank among the most productive estuaries in the Northeast.”

7-103 7.5.1 Impingement

Impingement of organisms occurs when water is drawn into a facility through its cooling water intake structures and organisms too large to pass through the protective screens and unable to swim away become trapped against the screens and other parts of the intake structure. The quantity of organisms impinged is a function of the intake structure’s location, design, capacity and approach velocity, and the abundance of organisms of various species in the general vicinity of the cooling water intake structures.

Intake structure location can vary by geographic location and water depth. EPA’s Guidance Document for Best Technology Available for the Location, Design, Construction and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact (1976) recommends selecting locations to avoid important spawning areas, juvenile rearing areas, fish migration paths, shellfish beds or areas of particular importance for aquatic life. Estuaries and shallow coastal waters are well known to be productive nursery areas for finfish in the northeast. For example, winter flounder, tautog, windowpane and scup are all known to spawn in shallow estuarine waters, such as those of Mount Hope Bay (Able and Fahay, 1998). In addition, anadromous fish runs occur in the Taunton, Lee, Cole and Kickamuit Rivers, all of which are part of the Mount Hope Bay estuary, and all of which enter the Bay in relatively close proximity to the intake structures of Brayton Point Station. Mount Hope Bay has been recognized as one of the

more historically, biologically productive areas in New England. 52

Water depth is another important consideration for siting water intake structures. Structures that rest directly on the bottom may tend to impinge more fish than intakes that are drawing water from mid-water column. This is typically because pelagic fish are stronger swimmers than benthic fish. In addition, mobile benthic invertebrates, in particular decapod crustaceans and lobsters, will walk into intake structures seeking refuge if the intake is flush with the bottom. Brayton Point Station, for example, has had problems with large numbers of horseshoe crabs becoming impinged ( December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 2-3). Schiller Station in New Hampshire, as another example, had past problems with lobster impingement when siltation filled in the area below its intake so that it lay directly on the bottom of the Piscataqua River.

The speed of water entering the intake structure through the screens is called the approach velocity. Typically, the greater the approach velocity, the greater the potential for impingement. Some species of fish actually cue to water movement and will be attracted to fast moving water.MA0003654 Determinations Document July 22, 2002

7-104 Thus, intakes with high approach velocities may artificially attract fish to these structures. In addition, high approach velocities reduce the ability of a fish to escape, once it is pulled into the structure. Once impinged, the pressure of the high flowing water holds the fish and other organisms in place against the screens causing injury and frequently death.

The seasonal abundance of fish and other creatures effects the quantity of organisms impinged. During times of high abundance of juvenile fish, impingement rates can be expected to increase. Juvenile fish are more susceptible to impingement than adults, because they are generally present in greater quantities than adults and are weaker swimmers.

Brayton Point Station presently operates with 2 separate intake locations (Figure 7.3-1), one on the Taunton River that supplies Units 1, 2 and 3, and a second on the Lee River that supplies Unit 4. Several of the alternatives now under consideration would significantly reduce the use of the separate intake for Unit 4. For example, the permittee estimates that the Unit 4 intake would be used around 500 hours per year or less for the Enhanced Multi-Mode Option. (See December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 3.1-18). However, the intake for Units 1, 2 and 3 is flush with the bottom and does not possess a sill or any other structure that would deter bottom or demersal creatures from entering the intake. Details regarding the design of the existing Brayton Point Station intake structures are discussed elsewhere in this document and are also discussed in the permittee’s December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, Section 2.2.2. Furthermore, as discussed above, impingement is reduced by minimizing intake velocities through the screens and an approach velocity of 0.5 fps has been identified as a target for appropriately minimizing impingement. However, the approach velocities at the intake trash racks for Units 1 and 2, and the intake trash racks for Unit 3, are reported to be 1.35 fps and 1.56 fps, respectively ( December 2001 USGenNE 316(a) and (b) Demonstration , Vol. IV, p. 2-5) and is even higher through the intake screens. Comparatively, the approach velocity at the Unit 4 intake bar racks is reported by the permittee to be 0.5 fps, and approximately 1.0 fps approaching the traveling screens (1997 NEPCO Report, p. 2-6; December 2001 USGenNE 316(a) and (b) Demonstration

, Vol. IV, p. 2-5). Therefore, it does not appear that approach velocities at the Brayton Point Station CWISs are optimal for minimizing impingement at BPS.

The Brayton Point Station intakes for all four units have traveling screens with a mesh of 0.375 in 2

. Id . at pp. 2-2, 2-6. The Unit 4 intake, however, has an angled screen configuration that the permittee has stated reduces impingement as compared to the non-angled screens used in the intake of Units 1, 2 and 3. Objects caught on Units 1, 2 and 3 intake screens are rinsed off with a high pressure spray system that delivers water at a pressure of 120 pounds per square inch (psi), which may cause serious injury to impinged organisms. Comparatively, the Unit 4 intake has a low pressure spray (5-10 psi) for less traumatic removal of fish from the screens. Id . at pp. 2-3, 2-5, 2- 6. Objects rinsed off the traveling screens at both intakes travel approximately 300 feet in their respective fish return sluiceways or pipes back to the waters of the estuary. Id . at pp. 2-3, 2-5. On low tide, fish leave the sluiceway above the water line and fall back into the bay. The distance of this fall is dependent on the height of the low tide. Fish dropped from significant heights back to the water can be easily stunned and injured making them more susceptible to predation. FromMA0003654 Determinations Document July 22, 2002

7-105 May through October, fixed screens with a mesh of 1.5 in 2are placed upstream of the traveling screens for Units 1, 2 and keep horseshoe crabs off the traveling screens. Id . at p. 2-3.

The permittee conducted an impingement survival study for only the Unit 4 intake structure from 1984-1986 to calculate survival rates for different species of impinged fish (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F-70). The results of this study are interesting, but not relevant for estimating impingement survival rates at the cooling water intakes for Units 1, 2 and 3, because of the major differences discussed above. Moreover, the two intakes have different fish return systems. The study measured survival, it did not discuss the general condition and vitality of the fish after being impinged. Finally, EPA personal observed on February 14, 2002, large numbers of sea gulls around the end of the fish return sluiceway. They appeared to be feeding on fish that were coming out of the fish return system. EPA has taken theconservative approach of assuming 100% mortality of fish that are impinged, because the longterm health and viability of impinged fish remains in question. In other words, fish may initially survive injury suffered from being impinged, retained on the screens by large volumes of water, rinsed off the screens and dropped from the sluiceway back into the bay, but their long-term health and viability has certainly been compromised.

Impingement rates have been monitored at Brayton Point Station since 1972. The quantity of fish impinged at the plant in any given calendar year varies as a function of the intake approach velocity, plant operations, cooling water flows, and the type and abundance of organisms present in the bay. Thus, if other factors remained stable, one would generally expect impingement rates to increase as plant cooling water flows increased. Conversely, if other factors remained stable, and fish abundance declined, one would generally expect impingement rates to decline. Interestingly, with respect to Brayton Point Station and Mount Hope Bay, fish abundance in Mount Hope Bay has dramatically declined, but plant operations and cooling flows have increased. Impingement rates, however, have generally followed the trajectory of the fish abundance date in the bay, with a steady decrease through time (Gibson, 2002A).

7.5.1a Impingement Losses

Monitoring of impingement losses has been an ongoing effort since mid 1972 at Brayton Point station. Over that period of time the 19 most common species of finfish that have been impinged are listed in Table 7.5-1, with 10 of those being considered commercial species.MA0003654 Determinations Document July 22, 2002

7-106 Table 7.5-1: Most Common Finfish Species That Have Been Impinged at BPS

Common Name Scientific Name Commercial Recreational Forage

Alewife Alosa pseudoharengus X

American sand lance Ammodytes americanus X

Atlantic menhaden Brevoortia tyrannus X

Atlantic silverside Menidia menidia X
Bay anchovy Anchoa mitchilli X

Blueback herring Alosa aestivalis X

Butterfish Peprilus triacanthas X

Hogchoker Trinectes maculatus X

Rainbow smelt Osmerus mordax X

Scup Stenotomus chrysops X X

Seaboard goby Gobiosoma ginsburgi X

Silver hake Merluccius bilinearis X

Striped killifish Fundulus majalis X

Tautog Tautoga onitis X X

Threespine stickleback Gasterosteus aculeatus X

Weakfish Cynoscion regalis X X

White perch Morone americana X X
Windowpane Scophthalmus aquosus X

Winter flounder Pleuronectes americanus X X
Routine impingement monitoring occurs 3 times a week for Units 1, 2 and 3. A trap has been placed in the fish return sluiceway downstream of the traveling screens. The frequency of monitoring increases when station operators detect an “unusual impingement event”. An unusual impingement event is defined as an impingement rate of greater than 25 fish per hour. These events typically happen when schools of forage fish get impinged. EPA personnel observed a recent unusual impingement event (2/14/02) with Atlantic menhaden. The trap in the fish sluiceway became clogged with the bodies of fish and on this occasion, fish were escaping over the top of the trap, resulting in an underestimate of the actual number of fish impinged. It is possible that this has occurred on other occasions during large impingement events.MA0003654 Determinations Document July 22, 2002

7-107 To derive annual estimates of impingement, the company extrapolates from 3 weekly samples to derive a weekly total. These weekly totals are then summed to derive an annual estimate of impingement losses. To assess whole plant impingement rates, losses from Unit 4 operation must be accounted for as well.

In the following analysis, we present 2 different estimates of annual impingement losses. The first is USGenNE’s estimate of impingement losses. The company derives average impingement densities using impingement density data from 1990-1999. The company, using a simulation that mimics specific plant operating conditions and corresponding average impingement densities, calculated an annual impingement estimate for multiple control technologies (Table 7.5-2). It should be noted that these values represent impingement rates and are comprised of fish of multiple ages. These values do not represent Age 3 adult equivalents. To assess impingement losses, EPA assumes 100% mortality for all fish impinged.

Table 7.5-2: USGenNE’s Estimates of Annual Impingement Rates Under 5 Different

Station Operating Scenarios Species 1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All units CC 3

Alewife 4,970 4,848 3,420 3,540 365

American sand lance 0 0 0 0 0

Atlantic menhaden 14,879 14,326 10,169 10,445 1,009

Atlantic silverside 16,051 14,829 10,315 10,926 1,142

Bay anchovy 175 152 106 110 11

Bluefish 22 20 14 14 1
Hogchoker 398 395 254 268 26

Rainbow smelt 807 729 543 577 60

Scup 64 58 39 40 4

Seaboard goby 1 1 0 0 0

Silver hake 964 924 627 652 68
Striped bass 25 24 17 18 2
Tautog 317 285 192 198 21MA0003654 Determinations Document July 22, 2002

7-108 Threespine stickleback 5,019 4,680 3,292 3,518 367

Weakfish 45 41 30 28 3 White perch 1,003 865 613 642 69
Windowpane 98 90 61 63 7

Winter flounder 2,602 2,326 1,603 1,701 178

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and New England Power, former owners of Brayton Point Station
2USGenNE’s preferred alternative Enhanced Multi- Mode Option

3 Closed Cycle wet cooling

Stratus Consulting Inc., also prepared an analysis of impingement losses for EPA. For this analysis, only impingement data from 1974 to 1983 was considered. This time period was selected for several reasons:

1. Comprehensive (year round for all species) entrainment sampling began in 1972 and was ended in 1985. Entrainment and impingement losses are totaled for the final 316(b) determination, thus it is appropriate to be comparing these losses from the same time periods;

2. Time periods that did not include the use of “piggyback” cooling were considered more representative of plant impacts for the purposing of predicting future impacts from technologies that obviate the need for “piggyback” cooling. Therefore, 1984 and 1985 were not considered for this analysis because “piggyback” cooling was used for periods of time in both of these years;

3. Unit 4 did not go into service until 1974, so data from 1972 and 1973 were not included for consideration; and

4. This time period is prior to the dramatic decline in fish populations previously discussed, beginning in 1985.

Consequently, Stratus used impingement densities from 1974-1983 and then adjusted for the facility’s current technologies and operations. For example, impingement rates were adjusted for the greater cooling water flow that the plant operates at now. Rates were also adjusted to consider the effectiveness of the angled screens on Unit 4, which has been estimated to reduce impingement by approximately 55%. Taking both of these factors into consideration, EPA estimates that impingement rates are 6.4% greater than during 1974-1983. Estimates of impingement losses are presented as Age 3 equivalents for each species in Table 7.5-3 for each control technology. ToMA0003654 Determinations Document July 22, 2002

7-109 estimate impingement losses, EPA assumes 100% mortality for all fish that are impinged. EPA’s impingement estimates represent losses from predicted station operation with fish populations at levels prior to the dramatic collapse. However, it can be fairly stated that even this estimate represents a conservative or low loss number, because power plant impacts had been occurring since the mid to late 1960s, thus no true unimpacted baseline data exists. Table 7.5-3: EPA’s Estimates of Annual Impingement Losses in Age 3 Equivalents under

5 Different Station Operating Scenarios Species 1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All units CC 3

Alewife 1,943 1,313 867 880 52

American sand lance 0 0 0 0 0

Atlantic menhaden 889 600 396 402 24

Atlantic silverside 8 1 <1 <1 0

Bay anchovy 107 72 48 49 3

Bluefish N/A N/A N/A N/A N/A
Hogchoker 862 582 384 390 23

Rainbow smelt 287 194 128 130 8

Scup 0 0 0 0 0

Seaboard goby 0 0 0 0 0

Silver hake 4,953 3,347 2,213 2,243 134
Striped bass N/A N/A N/A N/A N/A
Tautog 1,528 1,033 682 692 42 Threespine stickleback 282 190 126 128 8

Weakfish 450 304 201 204 12
White perch 1,011 683 451 458 27
Windowpane 672 454 300 304 18MA0003654 Determinations Document July 22, 2002

7-110 Winter flounder 2,925 1,976 1,304 1,324 79

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and New England Power, former owner of Brayton Point Station
2 USGenNE’s preferred alternative Enhanced Multi-Mode Option

3 Closed Cycle wet cooling

Periodically, about 1 to 15 times a year, Brayton Point Station experiences what is called an “unusual impingement event” (DeHart, 1997). These events are defined to occur, when the station impinges 25 or greater fish per hour. These events can result in large numbers of fish beingimpinged and killed in a fairly short period of time. A month long event occurred in from midAugust of 1999 to mid-September resulting in the loss of approximately 76,400 fish (Ketschke, 1999). Two separate events this past winter resulted in the combined loss of over 40,000 fish (Simas, 2002). These large events tend to occur primarily with schooling fish. Though the results provided by both the company and Stratus are calculated as annual averages, for species such as Atlantic menhaden, bay anchovy, alewives and other schooling fish, these losses tend to occur all at once in large discrete events rather than continuous losses throughout the year. Individual schools of these fish could be entirely eliminated in these events.

7.5.2 Entrainment

Fish eggs and larvae, along with many other organisms, are entrained when cooling water is drawn into the facility and organisms small enough to fit through the mesh of the intake screens pass through the plant cooling system with the cooling water flow. Organisms that transit the plant cooling system are typically exposed to high sheer stress as the water moves through the system, high quantities of heat as the water absorbs heat from the plant’s condenser, and occasionally high concentrations of chlorine or biocides. These stresses are easily sufficient to kill the entrained organisms. Generally, the quantity of entrained organisms is a function of cooling water flow through the plant and the concentration of organisms in the source water that are small enough to pass through the intake structure’s screening system. As explained above with respect to impingement, the location of the intake can have a major influence on entrainment. Different types of ecosystems may have greater or lesser concentrations of entrainable fish eggs and larvae. Estuaries are well known to be spawning and nursery areas for many different species of fish and invertebrates, thus intake structures located in estuaries are especially prone to entraining large concentrations of eggs and larvae. To further illustrate this point, Mount Hope Bay, including the Massachusetts portion and significant sections of the lower Taunton, Cole, Lee and Kickamuit Rivers, has a surface area of about 14 square miles, while the surface area of all of Rhode Island state waters is approximately 280 square miles. Thus, Mount Hope Bay constitutes only 0.05% of the total surface area of Rhode Island State waters, yet USGenNE has estimated that entrainment and impingement losses associated with Brayton Point Station operation constitute a quantity equal to almost 2% of the commercial winter flounder catch (USGenNE, 2002). This two order of magnitude disparity is due to the importance of estuaries as producers of fish eggs and larvae and the large impact of Brayton Point Station operations.MA0003654 Determinations Document July 22, 2002

7-111 The BPS cooling water intakes are located in the Mount Hope Bay estuary which should be, and historically has been, a biologically productive spawning and nursery area for fish. Fish eggs and larvae of the species present in Mount Hope Bay are easily small enough to fit through the 0.375- inch mesh of the intake screens at BPS. Moreover, data collected by USGenNE clearly show that large numbers of fish eggs and larvae are entrained at BPS (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F 26-27).

In assessing the impact of entrainment at BPS, EPA assumes that eggs and larvae that pass through the plant’s once-through cooling water system do not survive. In other words, we assume 100% mortality from entrainment, because of the multiple stresses inherent in these systems that are capable of killing the organisms. This is a conservative assumption, but one that we believe is reasonable and appropriate and one that has often been used in evaluating power plant entrainment effects.

The permittee conducted an entrainment survival study in 1997 and 1998 at Brayton Point Station (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F16-24) This study was conducted without a prior review or endorsement of its methodology by EPA or the BPS Technical Advisory Committee (TAC), which include biologists from the various relevant state and federal regulatory agencies. See 1993 Permit, Fact Sheet, p. 10. In general, the permittee’s study concluded that a substantial quantity (approximately 60%) of larval winter flounder survived the entrainment process. However, EPA believes the methodology used in this study was flawed and that its conclusions are not supported.

EPA hired experts Dr. Chuck Coutant and Dr. Mark Bevelheimer from the Oak Ridge National Laboratories to independently review the entrainment survival study. Coutant and Bevelheimer (2001) found numerous flaws in the basic study design that render the results of the permittee’s study unreliable and inconclusive. Some of the major flaws include:

1. Representativeness of samples - Larval fish concentrations were consistently higher in the discharge than in the intake. This suggests two possible problems: (1) that samples taken in the intake do not correspond to samples taken in the discharge; or (2) that handling of intake samples killed some percentage of the fish larvae in the sample. Either way, the representativeness of the samples is compromised and any further comparison between the intake and discharge samples is invalid. Thus, estimates of entrainment survival rates are rendered unreliable; and

2. Sampling location - Discharge samples were taken at the beginning of the discharge canal and then immediately transferred to ambient bay water conditions in the lab for observation. In reality, the larval fish would be exposed to an additional 20 minutes of hot water as the thermal plume transits the discharge canal and mixes out into the bay. This again calls into question the representativeness of the sampling regime.MA0003654 Determinations Document July 22, 2002

7-112 Based on these and other concerns identified by Coutant and Bevelheimer, EPA has decided to continue to use the assumption of 100% mortality of any organism that passes through the facility. While this may be a conservative approach, EPA believes it is reasonable and appropriate in lieu of any credible alternate survival rates based on site-specific data for the power plant cooling system in question and the affected species of concern. EPA also believes this conservative approach is reasonable and appropriate in light of the depressed condition of fish populations in Mount Hope Bay and our obligation to implement Clean Water Act § 316(b) to minimize adverse environmental impacts.

USGenNE has also suggested that larval fish survival rates are density dependent, so that the “cropping” of fish eggs and larvae by Brayton Point Station entrainment would actually improve natural survival rates of larvae left in the bay (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F-63). This theory might be true if larval fish survival is only being limited by access to prey. This has not been shown for Mount Hope Bay and in recent years, larval densities have dropped dramatically (MRI, 2002), thus competition for prey resources by larval fish would likely be reduced and “cropping” of additional larvae would have no positive effect on remaining larvae. Additionally, this argument ignores the ecological value of having a large number of fish eggs and larvae produced and residing in the Mount Hope Bay ecosystem. Natural mortality rates, due to predation, are typically high for most fish eggs and larvae. They serve an important role as prey for a variety of other organisms in the food web. Removing them from the system due to entrainment losses represents a lost food opportunity for other organisms in the bay. Finally, the naturally large quantity of fish eggs and larvae presents opportunities for years of high recruitment to the adult fishery. EPA defines recruitment, in this context, as the number of fish of the same age that enter the exploitable phase of a fish stock, in a given time period, as a result of the growth and survival of the smaller younger individuals. There are numerous factors that control recruitment and they can vary dramatically on an annual basis. Some combination of these factors come together to vary natural survival and/or growth rates of fish to make some years good recruitment years and other years unfavorable. The relative magnitude of recruitment events may be dampened by the “cropping” of significant numbers of eggs and larvae due to entrainment. This could serve to reduce the resilience of a population, making it more susceptible to a decline and prevent or inhibit the recovery of a particular population that is depressed, such as, for example, the winter flounder population in Mount Hope Bay.

7.5.2a Entrainment Losses

To assess entrainment losses at BPS, icthyoplankton sampling has been conducted in the discharge canal from 1972-1985 and 1993 to the present time. Sampling from 1972-1985 was conducted January through December for all species, while sampling from 1993 to the present has focused on winter flounder. Thus, samples from 1993 to the present are only collected between February to mid-May, because this time period represents peak abundance of winter flounder eggs and larvae in Mount Hope Bay.MA0003654 Determinations Document July 22, 2002

7-113 For the following analysis, two estimates of entrainment losses are presented. USGenNE used entrainment rates from 1972-1985 for all species, except winter flounder. For winter flounder, data on entrainment rates from 1993-1999 were used. Similar to the impingement estimates, simulations were run for various plant control options and entrainment losses were estimated. Similar to EPA, the company assumed 100% mortality for all species. For winter flounder, they also presented an estimate with variable through-plant mortality. Table 7.5-4 presents the USGenNE’s estimate of larvae and eggs entrained through the plant. Table 7.5-5 presents USGenNE’s estimate of Age 3 adult equivalent entrainment losses.

Table 7.5-4: USGenNE’s Estimate of Annual Entrainment Totals of Eggs and Larvae

Under 5 Different Station Operating Scenarios Species Life

Stage 1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All units CC 3

Alewife Egg 439,045 282,227 210,219 265,158 20,418

Larvae 1,180,603 1,024,084 595,551 611,277 57,695

American sand lance Egg 107,074 77,337 38,404 32,372 5,495

Larvae 112,861,678 90,824,398 63,691,321 65,082,486 7,299,955

Atlantic menhaden Egg 551,216,666 492,040,224 262,079,664 271,917,014 27,758,424

Larvae 209,201,258 222,772,805 123,559,555 133,183,938 12,582,365

Atlantic silverside Egg 395,378 338,310 261,541 254,144 23,692

Larvae 28,871,677 29,501,926 17,961,624 19,022,933 1,742,189

Bay anchovy Egg 4,907,759,05 3 4,693,187,848 3,288,723,135 3,309,720,188 304,100,84 7

Larvae 7,856,152,56 1 7,119,626,718 5,147,887,171 5,022,738,920 467,841,07 1

Bluefish Egg 0 0 0 0 0

Larvae 0 0 0 0 0

Hogchoker Egg 96,286,365 96,161,641 63,821,864 66,283,573 6,079,803

Larvae 7,958,804 7,467,128 5,231,163 5,198,545 485,176

Rainbow smelt Egg 1,071,777 1,026,153 723,499 778,030 82,262

Larvae 3,807,775 3,077,093 1,883,715 1,941,379 212,499

Scup Egg 7,272,690 8,417,876 3,662,637 4,069,976 436,524

Larvae 233,374 229,973 157,234 161,278 14,816MA0003654 Determinations Document July 22, 2002

7-114 Seaboard goby Egg 562,665 533,649 350,024 376,038 34,214

Larvae 671,399,305 633,456,759 444,567,414 445,605,559 41,068,438

Silver hake Egg 21,690 25,715 9,938 11,402 1,345

Larvae 30,096 30,028 22,504 24,666 2,274

Striped bass Egg 0 0 0 0 0

Larvae 0 0 0 0 0

Tautog Egg 3,529,810,09 1 3,491,783,200 1,981,600,616 2,108,291,977 199,023,94 6

Larvae 44,256,809 44,256,809 28,830,657 29,376,343 2,709,320

Threespine stickleback Egg 0 0 0 0 0

Larvae 19,314 16,842 13,561 14,492 1,475

Weakfish Egg 94,475,334 99,119,571 57,455,141 61,344,344 5,697,139

Larvae 21,851,073 22,139,052 14,268,639 14,883,971 1,364,261

White perch Egg 643,795 757,474 303,811 339,623 38,631

Larvae 93,369 78,441 46,136 48,368 5,209

Windowpane Egg 375,888,042 362,734,696 214,381,175 226,812,836 21,190,832

Larvae 13,682,593 13,472,888 8,246,770 8,522,301 800,223

Winter flounder Egg 63,215,121 58,394,355 42,565,233 45,456,047 4,646,753

Larvae 254,416,824 192,988,834 152,639,826 160,026,899 17,020,740

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and New England Power, former owner of Brayton Point Station
2USGenNE’s preferred alternative Enhanced Multi-Mode Option

3 Closed Cycle wet cooling

Table 7.5-5: USGenNE’s Estimate of Entrainment Losses of Age 3 Equivalent Adults

Under 5 Different Station Operating Scenarios Species 1993 Permit MOA II 1 EMM 2 Units 3 CC 3 All Units CC 3

Atlantic menhaden 15,625 15,614 8,543 9,094 882

Bluefish 0 0 0 0 0
Scup 554 628 292 320 34MA0003654 Determinations Document July 22, 2002

7-115 Silver hake 0 0 0 0 0
Striped bass 0 0 0 0 0
Tautog 7,126 7,045 4,039 4,285 404

Weakfish 371 384 232 246 23
White perch 0 0 0 0 0
Windowpane 1,002 971 577 608 57

Winter flounder 24,608 27,438 15,408 12,214 2,443

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and New England Power, former owner of Brayton Point Station

2USGenNE’s preferred alternative Enhanced Multi-Mode Option
3 Closed Cycle wet cooling

EPA estimated entrainment losses in a similar fashion as calculated for impingement losses, using USGenNE’s estimates of flow reductions achievable by the various technological options. Entrainment data from 1974-1983 was used (See section on impingement for explanation of this time period) and entrainment rates were adjusted for the operation of Unit 4 and the effectiveness of angled screens. It was estimated that entrainment rates are 14% greater under current operations than during 1974-1983. Table 7.5-6 presents EPA’s estimate of plant entrainment losses in Age 3 equivalents. These figures represent a conservative estimate of what entrainment losses for current plant operations would be if fish populations did not collapse. This estimate is conservative (i.e. low), because even the 1974-1983 dataset represents fish populations on the decline. These numbers are presented for comparative purposes with USGenNE’s estimates.

Table 7.5-6: EPA’s Estimate of Annual Entrainment Losses in Age 3 Equivalents at

Brayton Point Station under 5 Different Operating Scenarios Species 1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All Units CC 3

Alewife 101 68 45 46 3

American sand lance 83,771 56,602 37,357 37,923 2,264

Atlantic menhaden 3,566 2,409 1,590 1,614 96

Atlantic silverside <1 <1 <1 <1 0MA0003654 Determinations Document July 22, 2002

7-116 Bay anchovy 21,681 14,650 9,669 9,815 586

Bluefish N/A N/A N/A N/A N/A Hogchoker 23 15 10 10 <1

Rainbow smelt 9,337 6,309 4,164 4,227 252

Scup 417 282 186 189 11

Seaboard goby 13,440 9,081 5,994 6,084 363

Silver hake <1 <1 0 0 0
Striped bass N/A N/A N/A N/A N/A
Tautog 37,466 25,315 16,708 16,961 1,013
Threespine stickleback 67 46 30 31 2

Weakfish 369 249 164 167 10 White perch 0 0 0 0 0
Windowpane 3,752 2,535 1,673 1,698 101

Winter flounder 109,051 73,683 48,631 49,368 2,947

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and New England Power, former owners of Brayton Point Station
2USGenNE’s preferred alternative Enhanced Multi-Mode Option

3 Closed Cycle wet cooling

7.5.3 Ecological Significance of Entrainment and Impingement Losses

To assess the ecological significance of entrainment and impingement losses, EPA compared Age 3 adult equivalent losses to estimates of existing fish populations in Mount Hope Bay. In addition, production foregone modeling was done to assess the impact of the loss of forage species.

USGenNE, in its variance request, compares Age 3 adult equivalent losses from entrainment and impingement to commercial and recreational fisheries landings for all of Massachusetts and Rhode Island waters (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F-74-76). The landings numbers USGenNE cites include catches from all coastal waters out to the 3-mile limit and it is inappropriate to compare losses attributed to Brayton Point Station in Mount Hope Bay to fish landings numbers from all of Rhode Island waters. A more appropriate comparison,MA0003654 Determinations Document July 22, 2002

7-117 for each target species, would be between the entrainment and impingement losses in Mount Hope Bay and the estimated population of Age 3 or adult fish in Mount Hope Bay.

EPA believes that Mount Hope Bay is the appropriate frame of reference for the impingement and entrainment losses, because this area represents a distinct subpopulation of the Rhode Island winter flounder stock. RIDFW’s tagging study demonstrated a high level of fidelity to Mount Hope Bay as a spawning location (Reitsma, 2002). In addition, Crawford and Carey (1985) showed an extremely high level (over 90%) of fidelity by winter flounder to their spawning sites in Rhode Island coastal ponds. Thorrold et al.(2001) also documented high fidelity to natal spawning sites in the highly migratory weakfish.

EPA has compared Brayton Point Station’s projected impingement and entrainment losses for winter flounder to a Mount Hope Bay winter flounder population estimate. Gibson (1993) estimated a pre-1985 winter flounder population size for Mount Hope Bay using 4 different techniques. First, he used an area-swept by trawl method utilizing the MRI trawl catches from 1972-1983. In this method, a mean catch per tow from February to April in the MRI trawl survey was used from the years prior to the collapse. Area swept by the trawl was calculated using the net dimensions, vessel speed and tow duration. The mean catch per tow figure was then scaled up by the appropriate factor to correspond to the total area of Mount Hope Bay deeper than two meters. A catch rate of 75% was assumed and mean catch per tow was corrected for this. In addition, the standing stock estimate was multiplied by a factor of three to account for the wave type spawning that occur with winter flounder. This spawning strategy involves the fairly rapid movement of large numbers of fish into and out of an area during spawning. The factor of three was derived by multiplying the length of the spawning season (3 months) by the mean residence time of any one fish (1 month).

A second population estimate was derived using a mark and recapture study. A tag return rate is determined and a Petersen estimate was derived using commercial and recreational catch estimates for Mount Hope Bay.

A third estimate was derived from the VPA estimate of the Narragansett Bay-Rhode Island Sound winter flounder population. Assuming a similar density of fish per unit area, scaling down the larger population number of all of Narragansett Bay-Rhode Island Sound to the area of Mount Hope Bay produced a winter flounder population estimate for Mount Hope Bay.

For the final estimate, Gibson applied a regression model representing the relationship between primary spawning and production areas and adult population size to develop a population number for Mount Hope Bay. These four estimates with the corresponding 95% confidence intervals are presented in Table 7.5-7. The arithmetic mean population estimate for these four methods is 378,957 winter flounder in Mount Hope Bay prior to the collapse of the fishery.

USGenNE cites Gibson’s (1993) winter flounder population estimates and attributes values in its Table 7-7 in Appendix F of Volume II of their 316(a) and 316(b) Variance request to his 1993MA0003654 Determinations Document July 22, 2002

7-118 report. However, two of the values they cite are incorrect and as a result the mean of the population estimates is also incorrect. They substitute values for the Gibson estimate for the VPA and the Area Swept Method and calculate a mean value of 349,033 fish. This number is lower than Gibson’s actual mean population estimate, but it is also arithmetically incorrect for the data USGenNE presents in their own table. The mean value for the data presented in their table is actually 318,563 fish.

Table 7.5-7: Estimated Adult (Age 3+)Winter Flounder Population Size in Mount

Hope Bay (Gibson, 1993)
Method Population Size 95% Confidence Intervals
Area Swept Method 90,236 84,422-96,061
Mark-Recapture 279,953 230,926-328,980

VPA 869,320 681,605-1,057,035
Acreage Model 276,320 44,814-1,703,777

MEAN 378,957 40,258-717,656

Gibson (2002B) updated his winter flounder population estimate for Mount Hope Bay through time based on a mean population, from 1972-1985, of 378,957 fish and scaled this value based on fish abundance data from the standard trawls (Figure 7.5-1). This analysis produces a year 2001 population estimate of approximately 2,300 winter flounder in Mount Hope Bay. EPA conducted a sensitivity analysis on Gibson’s population estimate. Changing the pre-1985 population estimate has a fairly minimal effect on year 2001 fish population estimates. For example, increasing the pre-1985 population estimate to 700,000 fish, results in a year 2001 estimate of just over 4,000 fish. Table 7.5-8 compares the combined Age 3 adult equivalent annual losses for entrainment and impingement of winter flounder for several of the control technology options. The loss numbers assume 100% mortality from impingement, but represent the company’s variable survival rate for entrainment for all operating scenarios except for the whole plant closed cycle. USGenNE did assume 100% mortality for all eggs and larvae that would be entrained in a whole plant closed cycle scenario. Thus, loss values represent a conservative or low estimate of the annual Age 3 adult equivalent losses for the following reasons:

1. The Age 3 adult equivalent entrainment losses were derived using some quantity of through plant survival for eggs and larvae for all options except the whole plant closed cycle. USGenNE did not calculate losses of Age 3 adult equivalents assuming 100% mortality of eggs and larvae that are entrained for winter flounder. They made this assumption for every other species, but treated winter flounder differently. EPA has not yet derived Age 3 adult equivalent losses for winter flounder assuming 100% mortality from entrainment, thus we are temporarily relying on the USGenNE’s current entrainment loss estimates. Obviously, if 100% mortality were assumed, as EPA believes it should be, winter flounder adult equivalent losses would be higher.MA0003654 Determinations Document July 22, 2002

7-119 2. The Age 3 adult equivalent impingement losses may be an underestimate as a result of the difficulty in determining the quantity of fish over 3 years of age. It is not clear what assumptions USGenNE made for fish age with individuals that were clearly larger and older than Age 3 fish. These larger and older fish can represent a significant number of Age 3 equivalents depending on their assumed age.

To calculate the impact to the winter flounder population, the total (entrainment + impingement) Age 3 adult equivalent losses are divided by the total losses plus 7,428 (population estimate of winter flounder in Mount Hope Bay from 1993-1999 modified from Gibson 2002B). Table 7.5-8 shows the percentage of the population that is lost with each operating condition with losses ranging from 26 to 80%. By comparison, the Atlantic States Marine Fisheries Commission set a fishing induced mortality rate target of 30% for 1997 (NMFS, 1999). In addition, stocks in Mount Hope Bay are dramatically depressed, thus mortality rates may need to be lowered even further to promote a recovery.

Table 7.5-8: Estimated Winter Flounder Age 3 Equivalent Adult Impingement and

Entrainment Annual Losses Under 5 Different Station Operating Scenarios
1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All Units CC 3

Annual Flow (MGD) 1,440 975 650 653 56

Entrainment 24,608 27,438 15,408 12,214 2,443
Impingement 2,602 2,326 1,603 1,701 178

Total 27,210 29,764 17,011 13,915 2,621

% of population 79 80 70 65 26

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and NEP

2USGenNE’s preferred alternative Enhanced Multi-Mode
3 Closed Cycle

EPA apprised USGenNE of this analysis of entrainment impacts and USGenNE responded in writing (April 4, 2002 Meredith Simas to Phil Colarusso, U.S. EPA) with the following 6 points of disagreement.

1. Inappropriate comparison of numbers : USGenNE suggests that the entrainment and impingement losses were conservative estimates to be used only for economic analysis. USGenNE claims these values are not appropriate for any ecological assessment, though in the variance request document USGenNE tries to put this loss figure in context by comparing it to commercial fish landings. USGenNE states that Rhode Island fishermen catch 1.3 million pounds of winter flounder annually and impacts from Brayton PointMA0003654 Determinations Document July 22, 2002

7-120 Station operations constitute 1.6% of that total. The 1.3 million catch figure represents winter flounder caught from all of the State of Rhode Island waters. The majority of the 1.3 million pounds of catch come from the offshore waters of Rhode Island, with none of this total coming out of Mount Hope Bay.

In a meeting on February 14, 2002, a USGenNE consultant suggested comparing the entrainment losses to “Gibson’s Mount Hope Bay winter flounder population estimate of 300,000". EPA believes that comparing entrainment and impingement losses incurred by Brayton Point Station operations to fish population numbers in Mount Hope Bay is the appropriate ecological comparison. EPA’s reasoning in selecting Mount Hope Bay as the proper frame of reference is due to the high level of site fidelity to natal spawning sites seen in winter flounder, weakfish and anadromous fish (Thorrold et al., 2001; Crawford and Carey, 1985) and the large size of the bay itself (35 km 2 ). Independent of the site fidelity questions, EPA does not believe that an alternative that results in the significant decline of biomass from all finfish species (Gibson, 1996) in an embayment of 35 km 2represents a minimization of impacts under the spirit of §316(b) of the Clean Water Act. Unlike an open ocean or well-flushed system, Mount Hope Bay is a fairly self-contained water body with obvious geographic constraints and limited water exchange with Narragansett Bay. Considering the impacts to the larger Narragansett Bay or all of Rhode Island waters, at the expense of Mount Hope Bay, is contrary to the intent of the Clean Water Act.

Finally, USGenNE in its 316(a) and (b) Demonstration document, provide its assessment of entrainment losses using the Empirical Transport Model on a hypothetical population in Mount Hope Bay. Thus, the permittee in its own analysis chooses the same frame of reference for considering impacts as EPA does, which is Mount Hope Bay.

2. EPA’s population number is in error : USGenNE suggests that the population estimate produced by Mark Gibson and utilized by EPA is in error. The only information that USGenNE provided to rebut EPA’s population estimate is the claim that it would require 40,000 adult winter flounder to produce the quantity of Stage-3 larvae that have been estimated to be entrained. Several possible explanations exist to explain the apparent discrepancy between Stage-3 larval abundance and resulting Age 3 adult abundance. It is possible that some larvae from Narragansett Bay may be imported into Mount Hope Bay, though the rate and quantity of that exchange is currently unknown. EPA has refined its original estimate of winter flounder abundance in Mount Hope Bay to approximately 7,500 fish. This adjustment was made to simply match in time the entrainment losses and the annual population estimates in the bay. Specifically, based on Gibson’s scaled population estimates, the average annual winter flounder population from 1993 to 1999 is 7,500 adults. Population estimates for 2001 result in a total of approximately 2300 fish.

Further winter flounder population analysis by MA DEP using an area swept methodologyMA0003654 Determinations Document July 22, 2002

7-121 estimated an adult fish population number of approximately 1,800 fish per year from 1993- 1999 (Appendix B). EPA still believes the actual estimate of adult winter flounder in Mount Hope Bay is less than 10,000 fish, however, even considering USGenNE’s estimate of 40,000 fish would represent entrainment loss figures equal to 30% of the bay’s winter flounder population. This level of impact would not allow for winter flounder stock rebuilding. In addition, one must keep in mind that the entrainment and impingement impacts do not occur in isolation. Thermal impacts are added to these, so the total plant impact on the winter flounder population would be even greater than the 30% from entrainment and impingement alone.

3. EPA ignored the Empirical Transport Model : EPA reviewed the assumptions that USGenNE made for this model and had several points of disagreement, which are detailed below:

A. In deriving the W -factor (this is the ratio of the quantity of particular life stage in the bay to the quantity of that life stage that is entrained) for winter flounder eggs, USGenNE use the Gibson adult winter flounder population estimates for Mount Hope Bay. These estimates represent a pre-collapse situation and would result in a dramatic overestimate of the number of eggs produced in Mount Hope Bay. The egg production numbers form the denominator of the W -factor. Currently, the adult winter flounder population in Mount Hope Bay is dramatically reduced compared to Gibson’s original estimates. In addition, 80% of the adults found in the bay, are found at one station in front of the intake. A W

-factor that incorporates current population estimates and distribution would certainly obtain a much greater W -factor than what USGenNE has calculated.

B. In deriving the W

-factor for Stage-4 winter flounder larvae, USGenNE uses the following equation:

W

= (0.5 * ¶ r2 )/ A

r = the radius of the Stage-4 home range A = area of the bay immediately in front of the intake

USGenNE assumes that Stage-4 larvae have limited mobility and will only move approximately 200 feet (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. F-58). USGenNE attributes this mobility estimate to Saucerman andDeegan (1991). Saucerman and Deegan (1991) studied the movement of young-ofthe-year winter flounder, which is the life stage after the Stage-4 larval stage. Stage-4 larvae are still found throughout the water column as data presented by MRI at recent TAC meetings show. Stage-4 larvae can be more numerically abundant in the upper half of the water column than the bottom half. The implication of these findings are thatMA0003654 Determinations Document July 22, 2002

7-122 Stage-4 larvae will move or be carried by currents significantly greater distances than the truly demersal young-of-the-year stage. By significantly underestimating the home range of Stage-4 larvae, USGenNE substantially underestimates the true value for the W -factor. A lower W

-factor for Stage-4 larvae results in a lower estimate in the number of Stage-4 larvae impacted and a significantly lower entrainment mortality estimate for the stock.

C. USGenNE does not assume 100% mortality for larvae and eggs entrained by the plant. As stated earlier in this document, EPA assumes 100% mortality for entrained organisms, unless credible site-specific evidence demonstrates adjustments are warranted. USGenNE has not provided a scientifically credible site-specific study to alter EPA’s assumption of 100% mortality. An assumption of significant through plant survival, would dramatically reduce entrainment mortality estimates.

D. USGenNE uses data on ichthyoplankton distribution from 1978 and 1979. This is well before the collapse and likely does not represent the current distribution of winter flounder larvae in Mount Hope Bay.

As a result of these inappropriate assumptions, EPA believes that USGenNE’s application of the Empirical Transport Model to estimate entrainment impacts from the Enhanced Multi-Mode scenario greatly under predicts the impact on the winter flounder population in Mount Hope Bay. 4. Mount Hope Bay is not a closed or sealed system : Obviously, Mount Hope Bay does have exchange of water and some quantity of fish larvae with Narragansett Bay. The relative magnitude of this exchange is unknown, however, and it is not clear if this exchange of larvae results in the net importation into/or exportation out of Mount Hope Bay. Finally, if there is a general infusion of winter flounder larvae into Mount Hope Bay from Narragansett Bay, it makes the lack of subsequent recruitment to the adult population all the more troubling. Infusion of large numbers of larvae from Narragansett Bay should result in large numbers of subsequent juveniles and adults. The fact that adult numbers in Mount Hope Bay have stayed extremely low, even with fishing pressure reduced, suggests one of two things:

1. large quantities of larvae are not being imported into Mount Hope Bay; or

2. larval mortality rates are elevated in Mount Hope Bay.

5. Regional Effects : USGenNE suggests that region-wide stressors have reduced winter flounder stocks in Mount Hope Bay and have kept stocks low since the mid 1980s. As already stated in other parts of this document, fish populations in Mount Hope Bay have shown unique changes in abundance. This is true for the entire species complex and for several individual species (winter flounder, tautog, windowpane and hogchoker). Gibson’s (2002A) comparison of trawl data from Mount Hope Bay with other geographic locations shows that theMA0003654 Determinations Document July 22, 2002

7-123 scope of the decline in Mount Hope Bay is a site-specific phenomenom.

Total losses for species other than winter flounder under various operating scenarios are listed in Table 7.5-9. Unfortunately, unlike winter flounder there has not been an extensive analysis of Mount Hope Bay population estimates for other species. However, recorded catch rates for windowpane and tautog are as low as, if not lower than, those for winter flounder (Figure 7.5-2 and Figure 7.5-3). This suggests that their population numbers in Mount Hope Bay are at as equally low levels as winter flounder.

Table 7.5-9: Estimated Annual Finfish Entrainment and Impingement Equivalent Adult

Losses Under 5 Different Station Operating Scenarios for Certain Species Other Than Winter Flounder Species 1993 Permit MOA II 1 EMM 2 Unit 3 CC 3 All Units CC 3

Atlantic menhaden 36,504 29,940 18,712 19,539 1,891

Bluefish 22 20 14 14 1
Scup 618 686 331 359 38

Silver Hake 964 924 627 652 68
Striped bass 25 24 17 18 2
Tautog 7,443 7,330 4,231 4,483 425

Weakfish 416 425 262 274 26
White perch 1,003 865 613 642 69
Windowpane 1,100 1,061 638 671 64

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and NEP

2USGenNE’s preferred alternative Enhanced Multi-Mode
3 Closed Cycle

Production Foregone: Production foregone is an estimate of the quantity of biomass that would have been realized by fish killed by a particular stressor, if they had not been killed. The stressor in this situation is entrainment and/or impingement by Brayton Point Station. This analysis is typically done to estimate production for forage fish, as they tend to be the most numerous and serve as a critical component of the food chain for numerous predatory fish.

For EPA’s analysis, Stratus Consulting derived Age 1 equivalents for each forage species based on age specific mortality rates taken from the scientific literature. Biomass estimates are derived for each species based on established relationships between length, age and weight ratios from theMA0003654 Determinations Document July 22, 2002

7-124 scientific literature. EPA’s estimate of production foregone from entrainment and impingement losses are depicted in Table 7.5-10.

Table 7.5-10: EPA’s Estimate of Annual Production Foregone (in lbs) From Entrainment

and Impingement Losses at Brayton Point Station Species Impingement Entrainment Total

Alewife 168 584 752

American sand lance 0 1,737 1,737

Atlantic menhaden 225 546,168 546,393

Atlantic silverside 2 8,748 8,750
Bay anchovy 1 1,501,808 1,501,808

Butterfish 3 0 3
Hogchoker 6 81,576 81,582

Rainbow smelt 7 4,276 4,283
Scup 1,707 0 1,707
Seaboard goby 0 731 731

Silver hake 1,026 108 1,134 Striped killifish 4 0 4
Tautog 0 60,371,893 60,371,893
Threespine stickleback 1 28 29

Weakfish 137 2,440,664 2,440,801
White perch 81 72 153
Windowpane 61 181,291 181,352

Winter flounder 879 4,380,576 4,381,455

The summed production foregone total (in pounds) of all species is presented in Table 7.5-11 with 5 different operating scenarios for the plant. Annual production foregone ranges from 3 million pounds of fish to almost 122 million pounds of fish depending on the operating scenario. These estimates represent production foregone from entrainment and impingement of fish species, butMA0003654 Determinations Document July 22, 2002

7-125 they do not address total ecosystem production foregone. Many invertebrate species have planktonic lifestages that are vulnerable to entrainment. Additionally many of the mobile benthic fauna are susceptible to impingement, as evidenced by USGenNE erecting additional screens from May to October to prevent horseshoe crab impingement (December 2001 USGenNE 316(a) and (b) Demonstration, Vol. II, p. D-3). Entrainment and impingement losses of invertebrates at Brayton Point Station have not been measured, but these organisms tend to be lower on the food chain than most if not all fish. Thus, their numerical abundance and the biomass they comprise will greatly exceed that of just the nekton (fish) community alone. Thus, the total ecosystem production foregone actually greatly exceeds the value calculated for the nekton community and as a result it is hard to envision this quantity of biomass being removed from the system without significantly impacting normal trophic dynamics and ecosystem diversity.

Table 7.5-11: Annual Total Production Foregone in Pounds for Brayton Point Station

Under 5 Different Operating Scenarios Operating Scenario Impingement Entrainment Total
1993 permit 4,926 121,968,640 121,973,566

MOA II 1 3,343 82,764,440 82,767,783

EMM 2 2,211 54,741,834 54,744,045

Unit 3 CC 3 2,246 55,617,704 55,619,950
Whole plant CC 3 134 3,312,155 3,312,289

1 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and NEP

2USGenNE’s preferred alternative Enhanced Multi-Mode
3 Closed Cycle

7.5.4 Summary of Entrainment and Impingement Losses

Currently, Brayton Point Station withdraws close to 1 billion gallons of cooling water a day from Mount Hope Bay. This results in the entire volume of Mount Hope Bay being cycled through the plant about 7 times a year. Associated with this water withdrawal is the entrainment and impingement of trillions of organisms, the vast majority of which are killed. In addition to large losses of individual organisms, the facility has taken large percentages of the Mount Hope Bay population of a variety of commercially and recreationally important fish species (e.g. winter flounder, tautog). Furthermore, EPA concludes that losses from entrainment and impingement have significantly contributed to the collapse of the overall indigenous community of fish in Mount Hope Bay and prevention of the recovery of that assemblage of organisms to a healthy condition. In sum, these constitute severe adverse environmental impacts.

Under the proposed Enhanced Multi-Mode scenario, Brayton Point Station would still entrain and impinge large quantities of fish eggs, larvae, juveniles and adults of numerous species. Putting these losses in context, the entrainment and impingement losses from the Enhanced Multi-ModeMA0003654 Determinations Document July 22, 2002

7-126 scenario represent a figure equal to 70% of the winter flounder population in Mount Hope Bay. Similarly, large percentages of the Mount Hope Bay populations of windowpane, tautog and hogchoker are lost through entrainment and impingement with the Enhanced Multi-Mode scenario. Finally, with the Enhanced Multi-Mode scenario, well over 54 million pounds of the nekton production is foregone due to entrainment and impingement. Total ecosystem production foregone, which would include invertebrates and phytoplankton, from entrainment and impingement would greatly exceed the 54 million pounds per year figure. The large quantity of biomass lost from the system due to entrainment and impingement undoubtedly significantly affects normal trophic dynamics. Additionally, the large impact of entrainment from the Enhanced Multi-Mode scenario would continue to retard the recovery of specific species, such as winter flounder, tautog, windowpane and hogchoker. EPA considers these to be severe adverse impacts and draws the same conclusions on environmental impact for the Closed-Cycle Unit 3 option, which (using USGenNE’s flow estimates) achieves very similar levels of reduction to the Enhanced Multi-Mode option.

In order to give the Mount Hope Bay ecosystem a chance to recover, the total number of organisms taken via entrainment and impingement by Brayton Point Station must be dramatically reduced. Such large-scale reductions can be accomplished by the Closed-Cycle Entire Station option, which achieves flow reductions by 96% over the current condition, achieving similar degrees of reduction in entrainment and impingement. Coupling these reductions with current fishing restrictions and water pollution controls (including the substantial reductions in Brayton Point Station’s thermal discharges that will accompany the Closed-Cycle Entire Station option) will result in the increased survival of large numbers of individual organisms. EPA believes this level of increased survival of individuals will foster the recovery of specific fish populations and the Mount Hope Bay ecosystem as a whole.

7.6 Qualitative and Quantitative Assessments of the Value of Reduced CWIS Impacts at BPS

The biological analysis presented above characterizes the adverse environmental impacts resulting from operation of the BPS cooling water intake structures. It also describes the degree of biological improvement that EPA expects will result from particular reductions in cooling water intake structure capacity or changes in intake structure design.

Beyond the strictly biological analysis, under CWA § 316(b), EPA also must consider the costs and benefits of implementing technological options for minimizing adverse impacts from the cooling water intake structures at BPS. As explained above, EPA is not required to conduct a cost/benefit analysis to support its case-by-case CWA § 316(b) determinations. EPA has, however, interpreted CWA § 316(b) to authorize EPA not to impose BTA requirements for minimizing adverse environmental effects when the cost of meeting those requirements would be wholly disproportionate to their benefits. As a result, EPA must consider both the costs and the benefits of these steps within the “wholly disproportionate cost test.”MA0003654 Determinations Document July 22, 2002

53 Since the Unit 3 cooling tower handles 280,000 gpm, while the Enhanced Multi-Mode cooling tower handles only 260,000 gpm, EPA would have generally expected greater flow reductions from the Closed-Cycle Unit 3 option. It may be that USGenNE has calculated that this expected difference is offset by the Enhanced Multi-Mode option’s ability to handle flows from Unit 4 when Unit 3 is not operating, though this has not been indicated clearly. If that is the case, however, then EPA would expect that equipping the Closed-Cycle Unit 3 option with multi-mode capability would enable that option to yield greater flow reductions than the Enhanced Multi-Mode option.

7-127 Above we have presented EPA’s assessment of what the cost would be to the permittee of implementing various technological improvements to the cooling water intake structures at BPS. The
cost to society

of implementing particular options is discussed in Section 7.7 of this document. In this section we discuss the benefits to society from the reduced adverse environmental effects that would accompany cooling system improvements at BPS. Neither the CWA, EPA regulations, nor applicable EPA guidance under CWA § 316(b) dictate how EPA should assess the significance of these benefits in applying the wholly disproportionate cost test under § 316(b). EPA believes that a variety of factors should be considered in EPA’s assessment of whether or not the costs of a particular option are wholly disproportionate to its benefits. These factors are discussed below.

7.6.1 Summary of Flow Reduction Improvements

CWA § 316(b) requires that the “capacity” of cooling water intake structures reflect the Best Technology Available for minimizing adverse environmental impacts. Entrainment and impingement of aquatic life are two of the key adverse environmental impacts from cooling water intake structure operations and they can be minimized by reducing intake flow volume (or “capacity”) as much as possible.

The different technological alternatives investigated in this § 316(b) determination document achieve different levels of flow reduction. The Closed-Cycle Entire Station option reduces cooling water intake flow by approximately 96% (to around 56 MGD). An option that provided closed-cycle cooling for Units 1 or 2 & 3 would result in a reduction in intake flow of approximately 63% (to around 350 MGD). The permittee’s preferred Enhanced Multi-Mode option reduces intake flow by approximately 33% (to around 650 MGD). The permittee estimates that a Closed-Cycle Unit 3 option would achieve a flow reduction similar to that of the Enhanced Multi-Mode option (down to around 650 MGD), though EPA is unclear how that figure was derived. 53 (The Closed-Cycle Entire Station option also would provide the greatest reduction in the discharge of heat (from approximately 42 Trillion Btu/year to approximately 0.8 Trillion Btus/year), as compared to a Closed-Cycle Units 1 or 2 & 3 option (at approximately 14 Trillion Btus/year), the Closed-Cycle Unit 3 option (at approximately 23 Trillion Btus) and the Enhanced Multi-Mode Option (at approximately 28 Trillion Btus/year).)

7.6.2 Summary of the Biological Gains from Various Technology OptionsMA0003654 Determinations Document July 22, 2002

7-128 As presented in detail above, EPA has concluded that CWIS operation at BPS has caused, and is causing, severe adverse environmental impacts. These adverse impacts include the loss of both vast numbers of individual organisms and a significant percentage of the local populations of various fish species. We believe that these losses have contributed to significant adverse population-level effects for specific species of fish and have contributed both to causing the collapse of the overall community of fish species in Mount Hope Bay and to inhibiting or preventing their recovery.

The technological options under consideration would yield different levels of flow reduction, as described above, but all allow BPS to generate nearly the same amount of electricity for sale that it does now. These flow reductions would essentially provide corresponding, proportional reductions in the number of individual organisms, and the percentage of each species’ population, being entrained and impinged by the BPS CWISs. (The biological analyses presented above indicate the actual numbers of organisms involved.) Thus, from the perspective of minimizing losses of absolute numbers of organisms and percentage reductions in populations of particular species of fish, the Closed-Cycle Entire Station option is the preferred alternative. The Closed-Cycle Units 1 or 2 & 3 option would provide the next greatest level of improvement. The least improvement would be provided by the Enhanced Multi-Mode option. According to the permittee’s estimate the Closed-Cycle Unit 3 option would provide a similar level of improvement to the Enhanced Multi-Mode option, though if the Closed-Cycle Unit 3 option were equipped with multi-mode capability we would expect it to provide somewhat greater improvements than the Enhanced Multi-Mode option.

In addition, from the perspective of the recovery of populations of various fish species and the overall ecological health of the Mount Hope Bay and Greater Narragansett Bay ecosystem – as opposed to the simple perspective of the numbers of individual organisms directly saved from the intake – EPA has concluded that the Closed-Cycle Entire Station option would provide biological benefits markedly greater than indicated solely by its proportionally greater reduction in flow. In particular, EPA has concluded that the Closed-Cycle Entire Station option is the only option under consideration that will offer sufficient reductions in entrainment and impingement mortality – together with other important steps such as thermal discharge reductions and fishing restrictions – to allow the likely recovery of the severely depleted populations of winter flounder and other species (e.g., tautog, scup, windowpane flounder) in Mount Hope Bay. The other options under consideration – the Closed-Cycle Units1 or 2 & 3, the Closed-Cycle Unit 3, and the Enhanced Multi-Mode options – will not reduce intake capacity sufficiently to allow the likely recovery of the collapsed fish species populations in Mount Hope Bay. The increased likelihood of the fishery recovering adds an important additional quantum of benefit to the Closed-Cycle Entire Station option.

In EPA’s view, the Closed-Cycle Entire Station option is also the only option under which entrainment and impingement of organisms by the plant’s cooling water intake structure would not interfere with the satisfaction of Massachusetts and Rhode Island water quality standards. Massachusetts has classified the western portion of the estuarine waters of Mount Hope Bay as Class SA and the eastern portion, bordering the City of Fall River, as Class SB. 314 CMR 4.06, Figure 15. These classifications areMA0003654 Determinations Document July 22, 2002

7-129 the highest and second-highest recognized by the Commonwealth’s Water Quality Standards. SA waters are to provide “excellent habitat” for fish and other aquatic life as a designated use, while SB waters are to provide “a habitat” for fish and other aquatic life. 314 CMR 4.05(4)(a) and (b). Similarly, Rhode Island has classified the western portions of the Rhode Island segment of Mount Hope Bay as Class SA and the eastern segment as Class SB, the two highest classifications under the state’s Water Quality Standards. Rhode Island’s SA and SB waters are to provide “habitat for fish and wildlife.” State of Rhode Island Water Quality Regulations (as amended June 23, 2000), Rule 8.B.(2)(a) and (b). In addition, Rhode Island’s Water Quality Standards specify water quality criteria stating that “all waters shall be free of . . . anthropogenic activities subject to these regulations that: i. Adversely affect the composition of fish and wildlife; ii. Adversely affect the physical, chemical, or biological integrity of the habitat; iii. Interfere with the propagation of fish and wildlife; [or] iv. Adversely alter the life cycle functions, uses, processes and activities of fish and wildlife . . ..” Id . at Rule 8.D.(1)(a)(i - iv).

EPA believes these state water quality standards are being violated as a result of entrainment and impingement by the current BPS cooling water intake structures and that the Closed-Cycle Entire Station option is the only alternative currently under consideration that will satisfy these standards in the future. Each of the other options would also reduce the number of organisms killed by the plant’s cooling system, but to a significantly lesser degree. These options would still take large numbers of individual organisms, large percentages of species populations, and would not provide sufficient improvement to support recovery of the fishery. Therefore, we believe that these options would not satisfy applicable state water quality standards. Of course, EPA will carefully review the water quality determinations by each state under CWA § 401 in order to verify how the states interpret and apply their own water quality standards to this situation.

Having said all this, EPA also acknowledges that predicting the trajectory of future fish populations under different scenarios is difficult and unavoidably full of uncertainty due to scientific unknowns and data issues. Thus, while EPA has concluded that only the Closed-Cycle Entire Station option is likely to be sufficient to allow the recovery of the damaged fish populations, EPA also recognizes that there is at least some chance that one of the other options might also prove to be adequate in this regard. This chance decreases, however, to the extent that an option provides lesser reductions in flow and associated entrainment and impingement mortality. Each fish population suffers from numerous sources of mortality; some are natural and others anthropogenic. To restore depleted fish populations, total mortality rates for the population need to be sufficiently reduced. For the winter flounder population in Mount Hope Bay, fishing restrictions have reduced fishing-induced mortality. BPS operations are another significant source of anthropogenic mortality to winter flounder and other species. EPA has concluded that the only way to reduce total mortality on fish stocks in Mount Hope Bay to a point that will allow them to recover is to require a major reduction in BPS intake flows.

It must also be remembered that to the extent an option reduces thermal discharges, in addition to reducing flow, it provides an additional critical biological benefit by improving habitat quality andMA0003654 Determinations Document July 22, 2002

54In discussing CWA § 302 – which mandates effluent limits more stringent than technology standards if required to achieve water quality necessary for, among other things, “the protection and propagation of a balanced population of fish, shellfish, and wildlife,” but also allowed for a temporary extension of time to achieve this level of water quality where, among other things, the cost of doing so is determined to have “no reasonable relationship” to the benefit of doing so – the Senate Report on S. 2770 stated the following:

Balancing economic costs against what may be considered intangible social benefits is difficult. Some economic benefits can be calculated with reasonable accuracy. These include savings of the costs to public health of polluted waters, the costs of lowered property values along polluted lakes and rivers, the cost to the community of lower tax revenues and an unattractive business climate, the loss of future industry and jobs because of severe pollution problems, as well as the expansion of recreation opportunities available to the general public, including lower-income persons who rely heavily on public recreation facilities; transportation and other savings through the provision of recreation sites in close proximity to densely populated areas; and the impact of not imposing proposed effluent controls and strategies on neighboring

7-130suitability for indigenous organisms and possibly reducing predation rates. In this respect, the ClosedCycle Entire Station option again provides the greatest benefit, followed in order by the Closed-Cycle Units 1 or 2 & 3 option, the Closed-Cycle Unit 3, and the Enhanced Multi-Mode option.

7.6.3 Public Policy Significance or Import of the Biological Improvements

The public policy significance or import of the biological gains from cooling water intake structure improvements at Brayton Point Station can be assessed in a number of ways. EPA has applied several approaches to develop relevant information to consider in applying the wholly disproportionate cost test under CWA § 316(b). This work is discussed below.

7.6.3a Qualitative, Public Policy-Level Assessment

As the courts have recognized, in enacting the Federal Clean Water Act, Congress plainly understood that it was not necessarily possible to quantify in dollar terms all the benefits of restoring and maintaining the health of the Nation’s waters or all the detriments of allowing those waters to be degraded. See,
e.g. , American Iron and Steel Institute v. E.P.A. , 526 F.2d 1027, 1075 (3d Cir. 1975) (citing to Legislative History of the CWA of 1972); E.I. du Pont de Nemours & Co. v. Train , 541 F.2d 1018, 1030 (4 thCir. 1976). Cf. State of Ohio v. U.S. Dept. of Interior , 880 F.2d 432, 457 (D.C. Cir. 1989) (in case involving judicial review of Department of Interior natural resource damages regulations, court states that Congress “recognizes that natural resources have value that is not readily measured by traditional means”). Nevertheless, even unquantifiable benefits could be significant to the public and should be considered. 54 Looked at outside of a strictly monetary framework, EPA believes that theMA0003654 Determinations Document July 22, 2002

communities. Benefits more difficult to calculate such as long-term improvement of water quality and reduction of estuarine and ocean pollution should not be ignored. . . . Any balancing of costs and benefits should take into account the nature of the receiving waters and the feasibility of their use for recreational purposes, and the recreational and aesthetic values of maintaining a balanced population of shellfish, fish and wildlife in the particular waterway. The Committee recognizes that no mathematical balance can be achieved in considering relative costs and benefits nor would any precise formula be desirable, but in each case the Administrator or the State will be able to determine whether there is any reasonable connection at all between the costs which a particular effluent limitations would impose and any benefits (including the attainment of natural water quality) which might be derived.

1972 Legislative History, p. 1466. While CWA § 302 is not at issue in this case, the above passage provides an indication of how Congress thought about the issue of assessing the costs and benefits of water quality improvements under the CWA.

7-131 public benefits of implementing the Closed-Cycle Entire Station option are highly significant. The benefits of the other options also have some significance but the degree of significance declines as the amount of entrainment/impingement allowed to continue increases and the corresponding chance that the improvements will be sufficient to facilitate a recovery of the collapsed Mount Hope Bay fishery is diminished.

The central objective of the CWA, as stated by Congress, is “to restore and maintain the chemical, physical and biological integrity of the Nation’s waters.” 33 U.S.C. § 1251(a). Congress also stated that “it is the national goal that wherever attainable, an interim goal of water quality which provides for the protection and propagation of fish, shellfish, and wildlife and provides for recreation in and on the water be achieved by July 1, 1983 . . ..” 33 U.S.C. § 1251(a)(2). Clearly, these national goals have not been attained in Mount Hope Bay. The Mount Hope Bay fishery is in dire condition and the natural thermal profile of the Bay has been dramatically altered by the thermal discharge from Brayton Point Station. Replacing BPS’s old, once-through cooling water system with a modern closed-cycle system will dramatically reduce the damage done to the Bay’s chemical, physical and biological integrity by the power plant’s cooling water intakes (and thermal discharges). A large reduction in cooling water flow (and thermal discharge) – as would be provided by the Closed-Cycle Entire Station option – will also substantially reduce the plant’s impact on the bay’s water quality. Furthermore, EPA believes that the Closed-Cycle Entire Station option (in conjunction with other measures) is likely to be sufficient to give the collapsed Mount Hope Bay fishery a reasonable chance to recover over time. The other options are unlikely to be sufficient in this regard, with the chance of recovery declining rapidly and becomingremote as the level of flow reduction decreases below that projected to be achieved by the ClosedCycle Entire Station option.MA0003654 Determinations Document July 22, 2002

55 See also, generally , Section 102(1) of the Estuary Restoration Act of 2000 (P.L. 106-457), the purposes of which include “to promote the restoration of estuary habitat . . ..” 33 U.S.C. § 2901(1). Cf

. Executive Order No. 13158 (“Marine Protected Areas”).

7-132 Restoring the biological integrity of the Mount Hope Bay ecosystem has substantial environmental importance because the Mount Hope Bay estuary is an important part of the larger Narragansett Bay estuary ecosystem. The Mount Hope Bay estuary was once a productive nursery area for fish. The collapse of the Mount Hope Bay fishery not only damages the Mount Hope Bay estuary ecosystem, but also harms the overall Narragansett Bay estuary ecosystem of which it is a part. In the 1987 amendments to the CWA, Congress established the National Estuary Program because the “Nation’s estuaries are of great importance for fish and wildlife resources and recreation and economic opportunity . . .[, and] maintaining the health and ecological integrity of these estuaries is in the national interest . . ..” Water Quality Act of 1987 (P.L. 100-4), § 317(a)(1)(A) and (B) (adding § 320 to the CWA, 33 U.S.C. § 1330). 55 See also Atlas of Narragansett Bay Coastal Habitats (Narragansett Bay Estuary Program Report # 01-118, October 2001), p. 1. Congress expressly directed that Narragansett Bay receive priority consideration by EPA for designation under the National Estuary Program and it was one of the first estuaries to have been so designated. See 33 U.S.C. § 1330(a)(2)(B); EPA Website for National Estuary Program (www.epa.gov/owow/estuaries/nb.htm). (So far, there are 28 estuaries designated under the National Estuary Program.) As a result of this designation, substantial federal and state resources have been directed to the Narragansett Bay Estuary Program to help enhance knowledge about, and the conservation of, the Narragansett Bay estuary, which includes the Mount Hope Bay estuary. EPA estimates that since 1984 some 15 million dollars in federal and state matching funds have been spent under this program to benefit the health of the Narragansett Bay estuary.

Another indicator of the great public importance of the Mount Hope Bay ecosystem are the water quality designations given to the waters of this estuary by both Massachusetts and Rhode Island. As mentioned above, Massachusetts has classified parts of Mount Hope Bay as Class SA and other parts as Class SB. 314 CMR 4.06, Figure 15. These classifications are, respectively, the highest and second-highest recognized by the Commonwealth’s Water Quality Standards. SA waters are to provide “excellent habitat” for fish and other aquatic life as a designated use, while SB waters are to provide “a habitat” for fish and other aquatic life. 314 CMR 4.05(4)(a) and (b). Similarly, Rhode Island has also classified portions of the Rhode Island segment of Mount Hope Bay as Class SA and other portions as Class SB, the two highest classifications under its Water Quality Standards. Rhode Island’s SA and SB waters are to provide “habitat for fish and wildlife.” State of Rhode Island Water Quality Regulations (as amended June 23, 2000), Rule 8.B.(2)(a) and (b). As also mentioned above, Rhode Island’s Water Quality Standards further specify water quality criteria stating that “all waters shall be free of . . . anthropogenic activities subject to these regulations that: i. Adversely affect the composition of fish and wildlife; ii. Adversely affect the physical, chemical, or biological integrity of the habitat; iii. Interfere with the propagation of fish and wildlife; [or] iv. Adversely alter the life cycle functions, uses, processes and activities of fish and wildlife . . ..” Id . at Rule 8.D.(1)(a)(i - iv).MA0003654 Determinations Document July 22, 2002

7-133 The great value placed on the health of Mount Hope Bay and its fishery by the State of Rhode Island is also indicated by Resolution (No. 2001-H 6304) passed by the House of the Rhode Island State Legislature on April 4, 2001, which stated, among other things, the following:

WHEREAS, Mount Hope Bay is a valuable natural resource for the citizens of Rhode Island and Massachusetts; and

WHEREAS, Populations of marine fish in Mount Hope Bay have declined dramatically since 1986 and remain at historic low levels; and

* * *

WHEREAS, The importance of the preservation of Mount Hope Bay is immeasurable. This beautiful and vital body of water contains numerous aquatic species indigenous to the New England area and the State of Rhode Island. Mount Hope Bay is an indelible part of our exceptional state and quality of life that Rhode Islanders enjoy; . . ..

The public importance of restoring Mount Hope Bay as a healthy ecosystem for fish is further reflected in the concern expressed regarding the condition of the Bay by the New England Fishery Management Council (NEFMC). See May 7, 2001, Letter from Thomas R. Hill, Chairman, NEFMC, to Ira Leighton, EPA. The NEFMC notes, among other things, that the waters of Narragansett Bay and Mount Hope Bay have been designated as Essential Fish Habitat (EFH) for several species managed by the NEFMC. (EPA is consulting with the National Marine Fisheries Service to satisfy the EFH requirements of the Magnuson-Stevens Fishery Conservation and Management Act. 16 U.S.C. § 1801, et seq .) The public importance of restoring this fishery is further reflected in the aggressive actions that have been taken by Federal and State resource agencies to reduce fishing pressure in the waters of Mount Hope Bay, Narragansett Bay and elsewhere in our region. These steps include strict fishing restrictions imposed by Rhode Island and Massachusetts in their respective portions of Mount Hope Bay. Restrictions have also been imposed in greater Narragansett Bay. Meanwhile the federal government is taking regional steps that have included measures such as buying back fishing licences, and even fishing vessels, at substantial public expense. Fishing restrictions not only impose limitations on those who wish to make a living from fishing, but limit the public’s beneficial use of its waterways and require some to travel longer distances (i.e., outside of Mount Hope Bay) in order to fish. Such additional travel distances may also pose additional personal risk to the fishermen involved. These difficult steps are necessary to enable our fisheries to recover their health and the fact that we are taking these steps in Mount Hope Bay and more broadly reflect the public importance of achieving that
recovery.

Another indication of the public importance of restoring the ecological health of the Mount Hope Bay estuary is the fact that the City of Fall River, Massachusetts, has undertaken significant sewageMA0003654 Determinations Document July 22, 2002

7-134 treatment plant upgrades, and is currently in the midst of implementing a large-scale combined sewer overflow (CSO) abatement program. These efforts have been expensive, with the CSO program estimated to cost approximately $150 million of public funds. The CSO program has been implemented under the CWA to attain compliance with state water quality standards. The importance to the public of not allowing Brayton Point Station’s cooling water intake (and thermal discharge) to prevent the recovery of the bay’s fish populations is highlighted when this type of public expenditure is being undertaken to meet water quality standards.

It should also be noted that the National Oceanic and Atmospheric Administration (NOAA) of the United States Department of Commerce has designated a National Estuarine Research Reserve (NERR) in Narragansett Bay not far from the mouth of Mount Hope Bay. The National Estuarine Research Reserve (NERR) System was established by the Coastal Zone Management Act of 1972. See 16 U.S.C. § 1461. The NERR System is managed by NOAA in cooperation with States that manage the individual sites. The Narragansett Bay NERR in Rhode Island was designated in 1980 and is one of 25 sites in the National network. It provides an opportunity for scientists to conduct research, and educators to communicate information, to enhance public awareness and understanding of estuarine

areas. See 16 U.S.C. § 1461(b). The site is managed by the RI DEM and has strong partnerships with the Audubon Society of Rhode Island and the Prudence Conservancy. Through integrated research and education, NERRs such as the Narragansett Bay NERR help communities and managers develop strategies to deal successfully with coastal resource issues, such as point and non-point source pollution, habitat restoration and invasive species. The Narragansett Bay NERR site encompasses a total of approximately 4,000 acres including 60 percent of Prudence Island, Patience and Hope Islands and the recently acquired Dyer Island, as well as the water adjoining the islands out to 18 feet. The island complex supports a major rookery for colonial nesting wading birds, one of the densest herds of white tailed deer in the northeast and, on certain of the islands, access for the public to enjoy nature trails and woodlands. Reserve staff estimate that since 1980 approximately $10.5 million has been spent on land acquisition and Federal and State operations to further our understanding, and improve the management, of this nationally significant area.

EPA’s biological assessment indicates that a very major reduction in the plant’s cooling water flow (and thermal discharge) – such as provided by the Closed-Cycle Entire Station option – is a threshold requirement to allow recovery of the Bay’s fishery and restoration of related ecosystem services. Without meeting this threshold condition for recovery, the other efforts underway to improve Mount Hope Bay’s water quality and aquatic habitat and restore its fishery are unlikely to be successful and these expensive societal efforts will be undermined.

7.6.3b Monetary Assessments

EPA is not required to conduct a cost/benefit analysis in determining requirements for the new NPDES permit for BPS under CWA § 316(b). Instead, EPA must consider the cost of the BTA requirements. In doing so, EPA applies a “wholly disproportionate” cost test and retains broad discretion inMA0003654 Determinations Document July 22, 2002

7-135 determining how to apply that test. Of course, this must be done within the confines of the Administrative Procedures Act’s (APA) dictate against “arbitrary or capricious” action by government agencies.

As discussed above, Congress and the courts have in various contexts noted our present inability to accurately or fully value natural resources or environmental quality in monetary terms. This is, in part, because not all environmental services, amenities or values are traded in markets and, as a result, it is not possible to observe directly the value – via conventional market prices – that the public assigns to these resources. Nevertheless, there are a number of methods of trying to “monetize” the value of the type of fishery, habitat and water quality resources adversely effected here by the BPS cooling water intake structures. EPA has considered a number of these methods and attempted to apply several of them. EPA recognizes that each of these methods of “monetizing” the biological or environmental benefits of cooling water intake structure improvements has certain flaws and weaknesses, and that none is able to provide a truly complete or fully accurate assessment. Thus, in some instances discussed below, EPA applied a method of economic analysis and produced a numeric estimate of the monetary value of the environmental resources in question. In other instances, EPA discusses the economic analyses conducted by other parties. In still other cases, EPA simply discusses a method of analysis that neither EPA nor any other party applied. Typically, these latter methods were not applied by EPA because they were too expensive and time-consuming to apply for the development of this NPDES permit. In all cases, EPA has tried to briefly discuss some of the advantages and disadvantages of the analytical method in question.

Because of the limitations of these methods for monetizing the value of environmental resources, it is not possible to quantify with exact precision the monetary value of the environmental improvements offered by various technological options. As a result, EPA has not conducted these analyses to provide numeric values that will be strictly determinative of the appropriate conditions for the BPS permit. Rather, EPA has developed various types of admittedly rough estimates of the value of these benefits in order to provide an array of potentially relevant information for decision-making officials to consider in applying the wholly disproportionate cost test. EPA believes that this approach is consistent with the dictates of CWA § 316(b).

Furthermore, EPA also believes this approach is consistent with a correct, balanced understanding of the proper role of economic analysis in many types of environmental decision-making. Even economists who strongly support efforts to estimate the monetized benefits of protecting “environmental services” in order to support cost/benefit analysis or other economic analyses also caution that precise monetization of benefits may not always be possible, that uncertainties should be acknowledged, that the numeric results of these analyses should not be regarded as strictly determinative of the policy decisions at hand to the exclusion of other relevant considerations, and that “care should be taken to assure that quantitative factors do not dominate important qualitative factors in decision-making.” Arrow, Kenneth J., et. al., “Is There a Role for Benefit-Cost Analysis in Environmental, Health, and Safety Regulation?, ” in Economics of the Environment: Selected Readings ( Robert N. Stavins, Ed., 4 thMA0003654 Determinations Document July 22, 2002

56 It should be noted that there are also expert commentators who question or oppose the use of cost/benefit analysis and other analytical methods relying on efforts to monetize environmental or human health benefits on both theoretical and methodological grounds. See See
, e.g. , Nicoll, James L., “Environmental Restoration: Challenges for the New Millennium: The Irrationality of Economic Rationality in the Restoration of Natural Resources,” 42 Ariz. L. Rev. 463 (Summer, 2000); Heinzerling, Lisa and Ackerman, Frank, “Pricing the Priceless: Cost-Benefit Analysis of Environmental Protection” (Georgetown Environmental Law and Policy Center, c. 2002). Cf. State of Ohio , 880 F.2d at 456, 457, n. 40 (D.C. Cir. 1989). This debate, however, is beyond the scope of analysis necessary to support this permit development.

7-136 Ed. 2000), p. 321-23. 56

It should be understood that EPA does not intend to present in this CWA § 316(b) determination a detailed discussion of the economic theory underlying various methods of estimating monetized benefits of environmental resources. Such a discussion is not necessary for this permit determination and is beyond the scope of this document. For a discussion of some of the basics of environmental benefits assessment, EPA directs the reader to review Chapters A9 (“Economic Benefit Categories and Valuation Methods”) of the “Case Study Analysis for the Proposed Section 316(b) Phase II Existing Facilities Rule” (EPA-821-R-02-002, February 2002) (the “EPA February 2002 Case Study Analysis”).

In the following discussion, EPA - New England reviews three separately developed economic assessments related to the benefits of intake flow reduction and reduced impingement and entrainment at BPS. These include two analyses performed by EPA Headquarters in collaboration with the Region as part of the development of both the new proposed CWA § 316(b) regulations for large existing power plants and the new NPDES permit for BPS, and a third analysis prepared directly for EPA - New England for the BPS permit development process. Following its review of these EPA-developed analyses, EPA - New England then reviews analyses conducted by USGenNE and the Rhode Island Department of Environmental Management.

In carrying out our economic analysis of the environmental benefits of various technological options for BPS, EPA’s New England Region coordinated its effort with EPA Headquarters in the following manner. EPA Headquarters is working on the development of new CWA § 316(b) regulations. In support of this work, EPA developed estimates of the monetized benefits of environmental improvements from the new regulations. As part of this effort, the Agency conducted “case studies” of the benefits that might flow from various levels of improvements at a number of specific power plants. One of the plants selected was Brayton Point Station because of its northeastern location, its placement within an estuary, its large flow, and because of the availability of a significant amount of data regarding plant operations and their possible environmental effects. EPA Headquarters and EPA’s New England Regional office cooperated in developing this analysis. Both offices agreed that preparing a case study on BPS promised informational benefits and cost efficiencies to both offices. Stratus Consulting, Inc.MA0003654 Determinations Document July 22, 2002

57 A Revised Chapter A11 of the Case Study (EPA/Stratus, May 23, 2002) is also available as part of the administrative record for the permit.

7-137 (Stratus), was retained to help with this work.

The EPA February 2002 Case Study Analysis, including the Brayton Point case study, is part of the administrative record for the proposed CWA § 316(b) regulations for existing power plants published on April 9 2002, and is also part of the administrative record for the Brayton Point Station draft NPDES permit. 57 It is available on the EPA Headquarters website (at www.epa.gov/waterscience/316b/casestudy/).

The Brayton Point Case Study presents location, economic, and background information on the power plant and Mount Hope and Narragansett Bays. The case study then discusses impingement and entrainment losses at the facility (Chapter F3). The analysis does not, however, consider the effect of thermal discharges on organisms in Mount Hope Bay because regulation of thermal discharges is not a directly a part of the national § 316(b) rulemaking process, and time and resource constraints prevented the Agency from including thermal reductions as an secondary benefit of regulatory options involving flow reductions by recycling cooling water. (The Region does, however, consider thermal discharge benefits in its case-by-case analysis for the BPS permit.) The Case Study then uses two different approaches to generate values to use in estimating benefits: (1) the “Benefits Transfer” approach (Chapter F4); and (2) the “Habitat Replacement Cost Method” (Chapter F5).

In addition, as mentioned above, EPA’s New England Regional Office has also conducted additional analyses of the benefits of possible cooling water intake improvements beyond the analyses presented in the EPA February 2002 Case Study Analysis. These analyses were conducted by the Region with the assistance its contractor Abt Associates, Inc. (Abt).

**i.** EPA “Benefits Transfer” Analysis

One set of approaches to valuing environmental benefits seeks to place a monetary value on those benefits by using various measures and surrogate measures for determining how much a relevant population of people would pay in dollars to obtain or preserve that environmental resource. A benefits analysis should try to capture all the benefits derived from the targeted environmental resources or condition. Using fish conservation as an example, direct use values should be quantified (e.g., what the fish saved would be worth at market), indirect use values should be quantified (e.g., the monetary value of species of fish that are not themselves commercially valuable but support the propagation of other species that are commercially valuable, or provide other types of valuable ecological services), and non-use (or “passive”) values should be quantified (e.g., “existence value,” which represents the value that people receive from knowing that healthy fish populations are being conserved in a waterway, and “bequest value,” which represents the value people place on knowing that healthy fish populations have been preserved for future generations ). In addition to trying to monetize all the benefits, it is alsoMA0003654 Determinations Document July 22, 2002

7-138 important to avoid “double-counting” benefits. See EPA February 2002 Case Study Analysis, at p. A9-3.

There are a variety of ways of trying to estimate the monetary value of environmental benefits and eachhas its analytical shortcomings. Furthermore, some approaches are more expensive and timeconsuming than others. In light of time and budget limitations, EPA implemented a relatively simple, inexpensive and conventional method of trying to monetize the benefits of the fish that might be saved by implementing flow reduction technologies at BPS. EPA refers to the approach it followed as the “Benefits Transfer Analysis.” This analysis is presented in Chapter F4 (“Value of I&E Losses at the Brayton Point Station Based on Benefits Transfer Techniques”) of the EPA February 2002 Case Study Analysis. First, we will describe how the analysis was conducted and what it attempted to assess. Second, we will provide the results of the analysis. Third, we will describe some of its weaknesses and limitations.

Analytical Method. EPA evaluated the most numerically abundant species of fish entrained and/or impinged at Brayton Point Station. These include species of commercial and/or recreational importance as well as forage species. EPA generally explains the analysis as follows:

Recreational fishery impacts are based on benefits transfer methods, applying results from nonmarket valuation studies. Commercial fishery impacts are based on commodity prices for the individual species. The economic value of forage species losses is determined by estimating the replacement cost of these fish if they were to be restocked with hatchery fish, and by considering the foregone biomass production of forage fish resulting from I&E [(i.e., impingement and entrainment)] losses and the consequential foregone production of commercial and recreational species that use the forage species as a prey base. All of these methods are explained in further detail in . . . [the Case Study Analysis].

EPA February 2002 Case Study Analysis, p. F4-1.

To avoid double-counting for fish that are exploited by both commercial and recreational fishing, EPA allocated portions of the overall losses of particular species to the recreational and commercial components of the analysis based on National Marine Fisheries Service data indicating the proportions of state landings of that species that come from recreational and commercial fishing, respectively. Id . at p. F4-1, Table F4-1. EPA used its estimates of the mean numbers of “Age 1 Equivalent” fish impinged and entrained at BPS annually as the basis for its economic assessment. Id . at p. F4-2, Tables F4-2and F4-3. Thus, EPA looked at the numbers of fish lost to the intake structures of the BPS oncethrough cooling system in the past and assumed that the same number of fish would be saved in the future from eliminating cooling water intake flow at the plant. These numbers were then adjusted, however, to reflect commercial and recreational catch rates. EPA then calculated a monetary value for the adjusted figures. (Fish that escape commercial or recreational capture are not valued.)MA0003654 Determinations Document July 22, 2002

7-139 To determine the monetary benefit of various levels of intake capacity reduction, EPA made the simple assumption that fish losses would be reduced by the same percentage that intake flow is reduced. Therefore, the value of flow reductions could be calculated by multiplying the monetary value of all the fish by the percentage by which flow would be reduced.

Recreational Fishing Results: EPA explains that “[t]he benefits of recreational fishing cannot be tracked in the market, since much of the recreational activity associated with fisheries occurs as nonmarket events.” Id . at p. A9-7. Therefore, EPA looked to the literature providing “willingness-topay values” for increases in recreational fishing catch rates. Id . at p. F4-3. Because none of the studies reviewed pertained to Mount Hope Bay directly, and because the lack of site-specific data could lead to inaccurate estimates (either low or high), EPA presents a range of annual values for the fish lost to entrainment and impingement at BPS based on the range of values in the literature. Id . at p. F4-4, Table F4-5. The resulting value for each species depends on the number of individual members of that species entrained or impinged at the plant and the value from the literature for an individual member of that species.

Using this method, the value of the annual recreational losses of all species combined was found to range from $1,056 to $1,737 for impingement and from $22,641 to $38,794 for entrainment. Id . at Tables F4-5, Table F4-6.

Commercial Fishing Results: EPA estimated the value of commercial fishing losses due to the BPS cooling water intake structures based, in part, on the dockside market landings. Id . at pp. F4-5 to F4- 6. The total annual losses to commercial fishing were $2,713 from impingement and $69,321 from entrainment. Id . at Tables F4-7 and F4-8. These values do not, however, encompass the adverse economic effects that these losses would have for producers, wholesalers, retailers and consumers in the multi-tiered commercial fishery market. Therefore, based on values in the literature, EPA used adjustment factors to derive a range of values reflecting the “total economic surplus” lost to the commercial fishery market annually as a result of entrainment and impingement of commercially important species by Brayton Point Station. Id . at p. F4-6. These losses ranged from $4,900 to $8,600 per year from impingement and from $126,000 to $220,600 per year for entrainment. Id . at p. F4-7. EPA did not, however, consider adverse secondary economic ripple effects from fishery losses (e.g., effects on marinas, bait shops, property values).

Forage Fish Results: Many species lost to entrainment and impingement at BPS are not fished on a commercial or recreational basis. We will refer to these species as “forage fish.” Although they are not regarded to have direct market-based economic value, these species provide important ecological services within the Mount Hope Bay and Narragansett Bay estuarine ecosystem and food web. In an effort to estimate a monetary value for these fish, EPA used two different methods.

First, EPA attempted to estimate a monetary value for the forage fish lost to the BPS cooling water intake structure utilizing a “production foregone” approach. This approach presumes that the fish haveMA0003654 Determinations Document July 22, 2002

7-140 no value other than the extent to which they contribute to the production of other species of fish that are subject to recreational and/or commercial exploitation and whose value can, therefore, be monetized. This, of course, ignores a variety of other ecological services that may also provided by these organisms. This approach then uses estimates of trophic transfer efficiency to determine the loss of commercial and recreational species resulting from the loss of forage species. Using this method, the losses from impingement were estimated to range from $73 to $204 per year , and the losses from entrainment were estimated to range from $3,381 to $4,747 per year

. Id . at p. F4-8.

Second, EPA also applied a “replacement cost” approach that sought to quantify the cost of producing and stocking these fish as part of a hatchery/restocking program. Strictly speaking, this approach does not quantify the “monetary benefit” of the forage fish; rather, it calculates the cost of trying to “replace” those fish in the environment. EPA explains, however, that the numbers are useful if understood in the following manner, Id . at p. F4-7:

C “[I]f the fish are not caught in the commercial or recreational fishery, but are important as forage or bait, the replacement value can be used as a lower bound estimate of their value (it is a lower bound because it would not consider how reduction in their stock may affect other species’ stocks).”

C “[W]here there are not enough data to allow calculation of value losses to the recreational and commercial fisheries, replacement cost can be used as a proxy for lost fishery values.”

EPA also explains that, “[t]ypically the consumer or producer surplus is greater than fish replacement costs, and replacement costs typically omit problems associated with restocking programs (e.g., limiting genetic diversity).” Id

.
Understanding that these replacement cost numbers do not represent a direct estimate of the true monetary value of the forage fish, EPA believes these numbers are nevertheless of interest as a possible lower bound for that true monetary value. The replacement cost estimates developed also represent an underestimate because they did not include the “transportation costs” involved in getting the fish from a hatchery to the habitat in question. These costs involve personnel, fuel, water, chemicals, vehicles, containers, and nets, and can be substantial. However, EPA was unable to obtain data to support a reasonable estimate. Therefore, EPA conservatively did not include a transportation cost value in the estimates. Id . at pp. F4-7 to F4-8. In addition, EPA was able to find hatchery cost estimates for only two of the forage species impinged/entrained by BPS. For other species, EPA used an average value across a number of species. This analysis estimated replacement costs for impinged fish of $398 per year and for entrained fish of $17,860 per year

.

Non-Use Value Results: All of the above analyses were directed at estimating direct and indirect “use” values of implementing flow reduction technologies at BPS. In addition to estimating the “use”MA0003654 Determinations Document July 22, 2002

58 See EPA February 2002 Case Study Analysis, p. A9-3, n. 2.

7-141 values of flow reduction, as part of its “benefits transfer” case study, EPA also estimated non-use values from flow reduction and reduced impingement and entrainment of species at BPS.

In addition to the “use value” of natural resources, such as the value that fish provide for commercial fishing, these resources also provide “non-use” or “passive use” values to the public. Id . at pp. A9-2 to A9-3, A9-10. Passive or non-use values represent the value that people place on a natural resource unrelated to actual use of that resource. These non-use values include such items as the “existence value” (the value a person places on simply knowing that a particular resource has been protected, whether or not she (or anyone) ever uses it), the “bequest value” (the value a person places on protecting a resource for future generations), and the “option value” (the value a person places on preserving the resource to ensure the opportunity to use it in the future). 58 See, e.g.
, Id . at Figure A9- 1, pp. A9-3, A9-10, and A11-3. Cf. State of Ohio , 880 F.2d at 462-64 (“natural resources have values that are not fully captured by the market system” and “non-consumptive” (i.e., non-use or passive) values need to be assessed in order to completely value a resource).

As part of the benefits transfer case study analysis, EPA estimated non-use values using a crude “rule of thumb” identified in certain papers in the literature. Specifically, this rule of thumb assumes that non-use values are “at least equivalent to 50 percent of the recreational use impact.” Id . at p. F4-9. EPA noted in the Case Study Analysis that this rule of thumb has been used in a number of past EPA assessments of the benefits of water quality-related improvements. Id . at p. A9-10. It should be understood that this rule of thumb approach does not represent an effort to directly estimate all non-use values; instead, it is a “quick and dirty” approach to developing a low estimate of non-use values that is preferable to ignoring non-use values entirely. Completely ignoring non-use values would be even more inaccurate because there is a large body of information indicating that many people hold substantial non-use values for protecting or conserving environmental quality and natural resources.

While using the rule of thumb in the Case Study Analysis, EPA also identified several possible problems that may undermine use of the 50% factor, including (a) that the literature on which the factor is based is dated and more recent literature exists which must be reviewed and assessed, (b) that the studies underlying the literature have a variety of important differences, which could undermine support for the rule of thumb, and (c) that there are issues concerning how to properly apply the conclusions from the literature to other specific cases. Id . The rule of thumb also may only provide a rough estimate of the non-use value for recreational fishermen , and does not necessarily provide a non-use value for nonusers themselves (or for commercial anglers or other users apart from recreational fishermen). This makes it, at best, a highly conservative estimate of total non-use values. EPA also explained that:

[t]he overall reliability and credibility of applying the 50 percent rule approach is, as for any benefits transfer approach, dependent on the credibility of the underlying study and the comparability in resources and changes in conditions between the research surveyMA0003654 Determinations Document July 22, 2002

7-142 and the § 316(b) rule’s impacts at selected sites. The credibility of the non-use value estimate also is contingent on the reliability of the recreational angling estimates to which the 50 percent rule is applied. Id

.
As a result of these issues, EPA Headquarters indicated that it would use the rule of thumb for the present Benefits Transfer analysis, but that, as it continued working on the development of the new CWA § 316(b) regulations for existing facilities, it would conduct additional research to determine whether the rule-of-thumb estimate remained supportable even as a quick way of deriving a conservative estimate of non-use value that is better than ignoring non-use values entirely. Id

.
Applying the 50% of recreational value factor, EPA produced estimates of non-use values ranging from $528 to $869 per year

for mean annual impingement and from $11,320 to $19,397 per year for mean annual entrainment. Id . at p. F4-9.

Range of Total Value Results: The sum of the individual values stated above are presented in the following table.

Table 7.6-1: Sum of Benefits Transfer Estimates

(Source: EPA February 2002 Case Study Analysis, Table F4-13)

(with figures adjusted to Year 2002$)

Summary of Economic Valuation of Mean Annual I&E at BPS (Year 2002$) (Figures Represent Sum of Commercial + Recreational + Forage + Non-Use Values)

Impingement Entrainment Total

Low Estimate : $6,917 $171,454 $178,293
High Estimate : $12,212 $311,275 $323,487

Mid-Point of Range : $9,564 $241,364 $250,890

To estimate the economic significance of the biological improvements from each technological option using this method, EPA simply determined the percentage flow reduction associated with an option and, assuming a proportional reduction in impingement and entrainment, EPA multiplied the dollar values from the above table by that percentage. Thus, for example, using the mid-point of the range values, an option that would reduce flow by 33% would yield an annual monetary benefit of 33% of $250,890 (i.e., $82,793), while an option that would reduce flow by 96% would produce a monetary benefit ofMA0003654 Determinations Document July 22, 2002

7-143 96% of $250,890 (i.e., $240,854). See
, id ., at Table F6-2 (note: numbers in this text have been adjusted to Year 2002$).

Limitations/Inadequacies of “Benefits Transfer” Analysis. This section of the document discusses limitations and inadequacies of the above analysis.

As described above, EPA’s Case Study Analysis used a simple approach to monetizing benefits that assumed that reductions in flow would achieve like reductions in fish mortality. The number of fish “saved” was then used as the basis for the monetary calculations. As a straightforward, general analytical approach for the Case Study for EPA Headquarters’ CWA § 316(b) rulemaking, this approach is reasonable.

EPA’s New England Region believes, however, that when applied to the Brayton Point Station/Mount Hope Bay situation, this approach is likely to significantly underestimate the value of technology optionsthat achieve very high levels of flow reduction (such as the 95% reductions achieved by the ClosedCycle Entire Station option). A principal concern is EPA- New England’s belief that the method for quantifying the fish mortality losses materially understates the restorative effect on fish populations that would result from the substantial flow reductions of the Closed-Cycle Entire Station option. This material understatement principally stems from reliance on previously observed impingement and entrainment loss rates as the measure of the fish population losses that would be avoided by implementing the Closed-Cycle Entire Station option. In fact, these previously observed loss rates reflect a depleted and declining fish population.

This is, at least in part, because entrainment and impingement monitoring did not begin until 1972, well after BPS began operations and after the Mount Hope Bay fishery already appears to have been indecline. As noted previously, EPA’s biological assessment indicates that implementation of the ClosedCycle Entire Station option is essential for the recovery of the collapsed Mount Hope Bay ecosystem. As a result, EPA believes that the steady-state fish population implied by the impingement and entrainment loss estimates is actually markedly smaller than the population that would be achieved through a major reduction in intake flow at BPS. Consequently, estimates based on the previously observed impingement and entrainment losses are believed to materially understate the loss that would be observed if the current intake flows were imposed on this larger, more robust fish population that the bay supported in the past

. EPA - New England believes this higher loss rate would be the appropriate measure for judging the cost to society from operation of BPS’s current intake system and, therefore, the benefit that would be achieved from implementation of the Closed-Cycle Entire Station system

It is also true that estimates of the value of the options involving lesser reductions in flow may overestimate the benefits of such steps. This is because although such lower-level flow reductions will save a certain number of fish, they will not likely be sufficient to allow stocks to recover to the degree that current severe fishing restrictions will actually be able to be lifted from Mount Hope Bay. Thus, itMA0003654 Determinations Document July 22, 2002

7-144 seems inappropriate to attribute a fishing-related benefit to all the saved fish from these options if the savings are unlikely to be sufficient to actually allow fishing to be fully restored as an activity in the bay. These fish would still provide value of many types, such as various ecological services, but the value to commercial and recreational fishing would be considerably limited as the resource improvements would likely not be sufficient to permit full exercise of the use benefit activities themselves.

Another principal concern relates to the estimate of non-use value. It is well recognized in the literature that the public values environmental quality well beyond direct use benefits. See id . at p. A11-2. As discussed above, there are many questions about the validity of the 50% of recreational value rule of thumb used to derive a minimum estimate of non-use value. Id . at p. A9-10. Even putting suchquestions aside, the rule of thumb was only developed in the first place to provide a crude, lowerbound estimate of non-use values that would be preferable to ignoring them altogether. This approach may be especially questionable when applied to natural resources of exceptional public importance, such as the Mount Hope Bay fishery. Moreover, it only clearly addresses the non-use values of recreational fishermen.

Additional shortcomings of the benefits transfer-based method for estimating the monetary value of the biological/fishery improvements from new cooling water intake structure technologies are discussed below. Generally, this conventional technique ignores or does a poor job of valuing a number of important services provided by the organisms lost to the BPS cooling water intake structure.

1. For various reasons, the benefits transfer analysis does not place a value on a majority of the organisms lost to the BPS cooling water intake structures. The valuations based on expected recreational and commercial fishing impacts rely on indirectly derived nonmarket value estimates (e.g., consumer surplus per angling outing as estimated by travel cost models) and direct market values, respectively. In both instances, all benefits are based solely on direct use values of the impacted fish, and the physical impacts are characterized by the adult life stage of the species targeted by the recreational and commercial anglers. However, I&E losses at BPS include vast numbers of eggs and larvae, which play a vital role to a well-functioning ecological system, but have no obvious direct use value in and of themselves to humans. In addition, commercial and recreational losses constitute only a small subset of the species lost to I&E at BPS. See id . at p. A11-1. Even when losses of early life stages are converted to adult equivalents, the ecological services and associated public values provided by early life stages that do not make it to adulthood in the environment are omitted. Id

. See alsoFigures F6-2 and F6-3. In addition, as mentioned above, numbers were adjusted to reflect commercial and recreational catch rates so that fish that escape commercial or recreational capture are not valued.

2. The benefits transfer figures may underestimate the value of fishery losses because they are based on estimates of the number of organisms lost to entrainment and impingement derived from data collected from 1974 - 1983. The plant began operations approximately a decadeMA0003654 Determinations Document July 22, 2002

7-145 earlier but did not begin monitoring entrainment and impingement until 1972. Thus, there is no true baseline data. Moreover, there is data suggesting that the Mount Hope Bay fishery was declining before 1974 due, at least in part, to plant operations. Thus, the estimated numbers of organisms lost to BPS do not appear to reflect losses from a healthy fishery. As a result, these figures are believed to represent an underestimate of the impact of the BPS CWISs. Obviously, larger numbers of organisms lost to the plant would produce higher monetary estimates. Id . at Table F6-4. Other potential problems with the entrainment and impingement data include the fact that monitoring did not take place for all species in all years that monitoring did occur; since 1985, entrainment monitoring has been conducted only for winter flounder.

3. In addition, thermal discharges from BPS are also likely to have reduced the number of individual organisms that would otherwise have been subject to impingement and entrainment as a result of altering the temperature regime of the bay. This would also mean that estimates of the numbers of organisms to be taken by the cooling water intake structure that are based on data from 1974 to 1983 would tend to be underestimates. These, in turn, would lead to underestimates of the value of the lost resources.

4. EPA did not analyze the interaction of the effects from the cooling water intake with other environmental stressors. For example, annual losses of organisms to the intake may leave the assemblage of species or specific species more vulnerable to serious harm from other environmental stresses, such as water pollution. Conversely, EPA also did not assess whether improvements with respect to these other stresses, such as water pollution reductions and fishing pressure reductions, would result in larger numbers of organisms being killed by the plant’s intakes over time. Id

.

5. The EPA estimate of recreational benefits using this method only reflects the anticipated increase in value per outing, without accounting for any potential increases in the level of participation that might result from improved fishery conditions. Id . at Table F6-4, p. A9-7.

6. EPA only considered recreational impacts to fishing and did not consider other recreational activities that might benefit from improved fish stocks, such as boating or bird-watching (e.g., for fish-eating birds), or other near-water recreational activities. Id . at Table F6-4.

7. Due to a lack of site-specific recreational value data for various species, EPA used recreational values from various locations outside the Mount Hope Bay region. This may inject inaccuracy into the estimates. Id

.

8. The benefits transfer analysis did not consider adverse secondary economic ripple effects from a degraded fishery (e.g., effects on marinas, bait shops, property values).

Thus, there are a host of issues that serve to undermine the confidence that EPA has in the results of theMA0003654 Determinations Document July 22, 2002

7-146 benefits transfer analysis. These issues for the most part tend to suggest the analysis will greatly underestimate the monetary value of the fishery resource of Mount Hope Bay and the monetary benefits of aiding in its recovery by reduced entrainment and impingement by BPS.

**ii.** EPA Per-Person Recreational and Non-Use Value Analysis

Background. As explained above, EPA does not have confidence that the benefits transfer analysis provides a complete assessment of the total value of the fish resources that could be saved by cooling water flow reductions at BPS. Therefore, EPA requested its consultant, Abt Associates, Inc. (Abt), to consider whether there was another valid approach to estimating the non-use values of the fish thatwould be saved by reduced cooling water intake flow at BPS that would be less expensive and timeconsuming than a site-specific “contingent valuation” study. Contingent valuation studies involve surveys of a relevant population to try to discern non-use values for particular environmental amenities. Such studies provide site-specific information but are extremely expensive and time-consuming to carry out properly.

In response, Abt concluded that another approach could “provide[] meaningful insight into the non-use values that could be reasonably expected from improved protection of aquatic resources in Mount Hope Bay.” May 23, 2002, Memorandum titled, “Assessment of Benefits to Recreational User and Non-User Populations from Reduced Adverse Environmental Impacts of Cooling Water Intake System Operation at Brayton Point Station,” from Dr. Elena Besedin, Michael Fisher, Ryan Wardwell, Abt, toMark Stein and Phil Colarusso, EPA, Region I, pp. 2 (May 23, 2002, Per-Person Recreational/NonUse Analysis). Abt further stated that, “. . . absent the ability to undertake the considerably more resource intensive event-specific non-use value analysis, we believe that the benefit ratio approach applied here provides a reasonable and valid basis for estimating the non-use benefit value from improved protection of aquatic resources in Mount Hope Bay.” Id . EPA has reviewed this analysis and concluded that it represents a reasonable approach, within the time and budgetary constraints faced by EPA in developing the BPS NPDES permit, to providing estimates of the non-use values of the natural resources in question.

Method. This assessment considers the benefit to identified user and non-user constituencies from improved protection of aquatic resources in Mount Hope Bay. May 23, 2002, Per-Person Recreational/Non-Use Analysis, at pp. 1-2. These benefits stem from reduced impingement and entrainment (I&E) of aquatic organisms in the operation of cooling water intake structures (CWIS) at Brayton Point Station (BPS). BPS’s withdrawal of water from Mount Hope Bay for its cooling system impinges and entrains fish species sought by recreational anglers and, as well, numerous other aquatic species. Although these other species don’t have direct recreational or commercial use values, they play an important role in the overall Mount Hope Bay ecosystem and support the viability of species with recognized recreational and commercial value. Improved quality of recreational fishing for species sought by anglers visiting affected fishing sites can be expected to generate substantial user benefits. In addition, improving protection of Mount Hope Bay will also likely have a large non-use value, given theMA0003654 Determinations Document July 22, 2002

7-147 importance of the affected resources, as discussed above. Because the non-use value for improved protection of the Mount Hope Bay aquatic resources is likely to be large, both absolutely and in relation to estimated use values, underestimating the non-use values could lead to inappropriate, ill-considered policy decisions.

This analysis estimates both use and non-use values of improved protection of aquatic resources in Mount Hope Bay from reduced Brayton Point impingement and entrainment (I&E). It is similar in concept to, but different in analytic approach from, the Brayton Point “Benefits Transfer” case study analysis performed by the U.S. EPA Office of Water for the Clean Water Act 316(b) national rule. The principal difference is in the development of use and non-use benefit values on a per-person basis for identified benefit constituencies. Non-use benefit values were estimated by applying an adjustment to the estimated per-person use benefit values and then multiplying the resulting estimated per-person non-use benefit values by the number of persons in the estimated non-use benefit constituencies. The adjustment to per-person use benefit values to generate per-person non-use benefit values was based

on an average ratio of per-person non-use benefit to use benefit from six prior studies of the value to both users and non-users of protecting water resources. These calculations were performed for non-use constituencies at both the New England regional and national levels.

The “benefit ratio approach” for estimating per-person non-use benefit values from use benefit values is inevitably less precise than a site- and policy event-specific analysis of the estimates of non-use benefit values from improved protection of aquatic resources in Mount Hope Bay. However, such specific studies of non-use value, which are typically based on contingent value surveys, are quite expensive and require considerable calendar time. Given budget and time constraints for the current effort, this approach was not possible. The alternative non-use benefit to use benefit ratio approach applied herein provides meaningful insight into the non-use values that could be reasonably expected from improved protection of aquatic resources in Mount Hope Bay. Indeed, the prior studies on which the adjustment ratio is based found a relatively narrow range of ratios of per-person non-use benefit to use benefit value. The consistency of the benefit ratio range found in these studies provides confidence in the findings from the benefit ratio approach as applied herein. Accordingly, absent the ability to undertake the considerably more resource intensive event-specific non-use value analysis, the benefit ratio approach applied here provides a reasonable and valid basis for estimating the non-use benefit value from improved protection of aquatic resources in Mount Hope Bay.

This assessment relied on the following: information developed as part of the BPS case study analysis performed by EPA for the CWA 316(b) national rule; recreational fishing data from the National Marine Fisheries Service (NMFS); values from the environmental economics literature; and membership information from various environmental organizations.

The analysis involved the following steps:

< Identifying the geographical area where fish abundance is likely to be increased by reducedMA0003654 Determinations Document July 22, 2002

7-148 I&E of aquatic species at BPS (impact area);

< Characterizing recreational fishing in the impact area;

< Estimating improvement in impact area recreational fishing site quality from reduced I&E at BPS;

< Estimating recreational user benefits from increased catch rate at recreational fishing sites in the impact area; and

< Estimating non-use benefits from improved protection of aquatic resources in the impact areas.

Further discussion of each of these steps is provided in the May 23, 2002, Per-Person Recreational/Non-Use Analysis.

Results. This analysis estimated annual New England regional non-use benefit values from elimination of I&E at BPS ranging from $17.7 to $58.1 million (2002$). Id . Table 7. These values are based on multiplying the estimated per-person non-use values for eliminating I&E at BPS by the number of members of a selection of New England environmental organizations who have natural resource protection as a part of their mission, and the estimated number of saltwater anglers in New England. Id . pp. 12 -14. The range of values reflects different figures based on the low and high ends of a range of per-person values for the environmental improvements, see id . at p. 12, n. 10, and different values depending on whether one assumes an environmental group membership represents one person or 1.9 people (the average number of adults in a New England household). See id . at pp. 12 - 13.

Non-use benefit values were also estimated for non- New England benefit constituencies, by performing the same calculations using the number of members of a selection of national environmental organizations who have natural resource protection as a part of their mission, and the estimated number of saltwater anglers nationally. Id . at pp. 14 -16. The range of non-New England figures were combined with the range of New England figures to produce a range of national estimates, which included estimated annual values ranging from $53.3 to $195.6 million. Id . at Table 8. Again, the range of values reflects different figures based on the low and high ends of a range of per-person values for the environmental improvements, and different values depending on whether one assumes an environmental group membership represents one person or 1.9 people (the average number of adults in a New England household). See id . at p. 15.

Limitations of the Analysis. As with the benefits transfer analysis, the Per-Person Recreational and Non-Use Value Analysis also has a number of limitations and potential uncertainties. Many of these issues are discussed in the text of the May 23, 2002, Per-Person Recreational/Non-Use Analysis, including an explanation of how the uncertainties were handled and why they were handled in aMA0003654 Determinations Document July 22, 2002

7-149 particular manner. On the whole, EPA believes that these issues were handled reasonably and that it is as likely as not that the analysis underestimates the total non-use value for eliminating entrainment and impingement from BPS.

Some of the more significant issues are discussed below:

S The analysis, based on recreational species, only considers improvements for winter flounder and tautog. Due to data limitations, improvements for other recreational fish such as bluefish, striped bass, and windowpane flounder, were not considered. This is likely to underestimate the total non-use value. See Id . at pp. 3 (n. 4), 7, 9 - 10.

S This analysis only used the lower non-use value ratio calculated for non-users (as opposed to the higher non-use value ratio for users). However, it was believed that this possible source ofunderestimate would not have a significant material effect because the number of affected nonusers is so much greater than number of affected users. See Id . at p. 11.

S Various calculations made in this analysis rely on values from studies conducted by other parties. For example, recreational fishing data comes from surveys conducted by the National Marine Fisheries Service (NMFS), id . at pp. 6 - 7, and per-person non-use values come from a selection of studies. See Id . at pp. 10 - 11. As with the reliance on studies in the benefits transfer analysis, to the extent there are flaws in the studies relied upon here, they could affect the results of this analysis. However, with respect to the non-use values from the studies relied upon here, six studies were used and they indicate a relatively narrow range of values. This gives some confidence in the reasonableness of the estimates produced using these figures. Id

. at pp. 2, 10, 12, n. 11.

S As with the benefits transfer analysis, estimates of the number of organisms lost to entrainment and impingement were derived from data collected from 1974 to 1983. This approach would tend to lead an underestimate of the number of organisms that would be lost to the plant from a healthy ecosystem and a corresponding underestimate of their value. These points are discussed in the section addressing limitations of the benefits transfer analysis.

S Due to the absence of data, several assumptions had to be made for different factors. If these assumptions rendered the estimates less accurate, we cannot tell which direction the error would lie. For example, in the absence of data regarding willingness-to-pay for an additional fish by so-called no-target anglers (anglers who do not have a stated preference for catching particular species or types of fish), the analysis assumes their willingness-to-pay is 50% of that of anglers who specifically target tautog or winter flounder. See Id . at p. 9. As another example, the percent of anglers targeting winter flounder specifically was unknown, so the number was estimated based on percent of anglers targeting flounder in general, which was known, and the ratio of winter flounder catch to total flounder catch. See Id . at p. 10.MA0003654 Determinations Document July 22, 2002

7-150 S The relationship of willingness to pay for environmental improvement and protections and the distance a person is from the affected resources is unknown. Abt concluded that the willingness-to-pay is likely to be less outside of New England and, therefore, made the rough assumption that the benefit for those outside New England would be 10% of that for those within New England. See Id . at p. 14. EPA believes this is likely a reasonably conservative assumption, especially given the significance of the Mount Hope Bay fishery resources involved. However, it is impossible to know whether this approach leads to an underestimate or an overestimate.

S With respect to both the New England and national environmental group memberships used in the analysis, it was impossible to tell from the data whether the memberships in the organizations represented one or more than one person. As a result, Abt did two calculations: one assuming each membership represented one person and one assuming each membership represented 1.9 people (the average number of adults in a New England household). EPA believes this constituted a reasonable approach to the uncertainty. EPA also agrees with Abt that it is reasonable to expect that the one person per membership calculation is likely to be an underestimate, as some memberships clearly represent more than one person. EPA also agrees that the 1.9 persons per membership calculations could represent an overestimate, but are more likely to be closer to accurate given the expected likelihood that adult members of a household are likely to share similar views on environmental protection. See Id . at pp. 12-13, 15.

S Due to lack of data, the analysis did not adjust for the possibility of an individual being a member of multiple environmental organizations either across the selected New England organizations, or across the New England and national organizations. This could result in an overestimate due to double-counting of some individuals. However, as Abt points out, such individuals may also have a higher non-use value than individuals who are members of only one organization. See Id . at pp. 14, 15. Still, the non-use values of these types of individuals may already be reflected in the average non-use values used from the literature. See Id . at p. 10. On the whole, it is impossible to tell the effect of these elements. ( See Item 9 below.)

S Due to lack of data, the analysis also could not determine how many of the New England and national environmental group members were also reflected in the number of saltwater anglers. See Id . at pp. 14, 15, n. 15. This could result in some degree of overestimation as a result of double-counting. Any such double-counting, however, is likely offset to an unknown degree by the fact that the non-use value to anglers was conservatively calculated using the lower non-use value for non-users. See Id . at pp. 14. Furthermore, in order to minimize any potential doublecounting for the national environmental organizations, Abt excluded the membership figures for the following three groups on the list who typically would be expected to have a significant number of anglers (Trout Unlimited, Fish Unlimited, and the National Wildlife Federation). See Id . at p. 15, n. 15.MA0003654 Determinations Document July 22, 2002

7-151 S Various possible sources of overestimate are also likely offset by two important sources of possible underestimate: (1) the analysis assumes that people who are not members of the selected environmental organizations would garner no non-use value from the environmental improvements at issue here; and (2) the list of environmental organizations is not an exhaustive list. See Id . at pp. 14, 15, Attachment A. EPA believes it is reasonable to conclude that these two factors will largely offset, and perhaps more than offset, the possible sources of overestimate, such as those cited in numbers 7 and 8 above.

**iii.** EPA “Habitat Restoration Cost” Analysis

Background. In light of the many limitations and issues related to the conventional benefits transfer analysis described above, EPA was also interested in conducting additional analyses to provide further potentially pertinent information for consideration in decision-making. As stated above, budgetary and time constraints precluded undertaking a full contingent valuation-style study to derive willingness to pay-based estimates of the value to the public of the fishery resources lost to the BPS cooling water intake structures. Therefore, EPA not only undertook the “per-person” analysis described above, but also worked with Stratus to prepare an alternative economic assessment referred to as a “Habitat Replacement Cost” (HRC) analysis. EPA February 2002 Case Study Analysis, Chapters A11, F5 and F6; see alsoRevised Chapter A11 (EPA/Stratus, May 23, 2002). EPA believed that this method, which was more affordable and less time-consuming than a full contingent valuation study, offered promise for providing pertinent information for both the development of the BPS permit and the new CWA § 316(b) regulations.

The HRC analysis seeks to identify the cost of habitat restoration efforts sufficient to replace the same number of equivalent-aged fish of each species that is lost to entrainment and impingement by the Brayton Point Station intake. Id . at p. F5-1. The HRC analysis does not actually measure the value, expressed as willingness to pay (or sell), that people place on the fish of Mount Hope Bay; rather, it assesses the cost of actions that would be needed to create or restore the natural environment to a condition where it would naturally produce (or replace) the number of fish otherwise lost to the power plant. EPA believes this information is useful for the Agency to consider in determining whether or not the costs of a BTA alternative are wholly disproportionate to its benefits.

The HRC results are relevant in several ways. They are a measure of what it would cost society to replace the fishery resources lost to the plant in an effective, ecologically sound manner. This is pertinent information in light of the CWA goals of restoring and maintaining the biological integrity of the Nation’s waters and rendering them suitable for maintaining balanced, indigenous populations of fish that can support fishing. It is also pertinent in light of the public importance of these resources, as indicated in the above discussion of “qualitative” considerations, including that large public expenditures have been made and fishing restrictions put in place in an effort to restore the fishery and meet applicable water quality standards in Mount Hope Bay. The HRC results are also relevant in that the cost of trying to restore the damaged natural resources through public restoration efforts can beMA0003654 Determinations Document July 22, 2002

59 This is, of course, an artificial comparison because even if the restoration actions were actually taken, EPA believes Mount Hope Bay fish populations would not truly be restored as long as BPS continues killing huge quantities of organisms by its water withdrawals and adversely altering the bay’s habitat through its thermal discharges.

60This is also similar in concept to the approach to mitigation for damage to wetlands used in the CWA § 404 permitting context. Under CWA § 404, after first avoiding or minimizing any impacts to wetlands as much as possible, mitigation (in terms of off-site restored or created wetlands) for any damage to wetlands that occurs is scaled to offset the lost “functions and values” of the damaged

7-152 compared to the costs of doing so through technological improvements at BPS. 59

Finally, there is some evidence indicating that at least in cases involving the type of resource damage we see from impingement and entrainment loss at BPS, HRC results appear to be less than the total value of damage to those resources that would be revealed in a total value assessment. In this light, the HRC cost estimate may provide a conservative, albeit indirect, estimate of the value to society from restoration of the damaged resource. In other words, if used as a “stand-in” for a total value analysis, the HRC results would be unlikely to overshoot the result that a total value analysis would reach. This conclusion is suggested by two cases known to EPA in which both HRC and total value analyses were conducted. Both of these cases found that HRC estimates were lower than the total value estimates. See May 23, 2002 Revised Chapter A11, pp. A11-6 to A11-7. See alsoMay 23, 2002 Revised Chapter A11, Table A11-2 (results of various total valuation studies). In addition, a comparison of the HRC results in this case to the “per-person” non-use value results discussed above tends to suggest the same conclusion. Of course, EPA recognizes that while these results are suggestive, the relative magnitude of HRC and total value results could well vary from case to case and more research would be desirable in the future to further examine this relationship in more, and different types of, cases. See Id . at pp. A11-8 to A11-10, A11-16 to A11-17. Still, these results are worthy of consideration as part of the information currently available to EPA as we move forward at this time to make the CWA § 316(b) determination for the new BPS NPDES permit.

Derivation of the HRC Method. The HRC method is derived from replacement cost estimation methods, including the Habitat Equivalency Analysis (HEA) method, used in certain natural resource damage contexts. The HEA method for determining appropriate restoration costs is well established and has been upheld in federal court in natural resource damages cases under certain federal statutes. See United States v. Great Lakes Dredge & Dock Company , 259 F.3d 1300, 1305 (11 thCir. 2001); United States of America v. Melvin A. Fisher, Kane Fisher, Salvors, Inc. , 977 F. Supp. 1193, 1197- 98 (S.D. Fla. 1997). For example, under the National Marine Sanctuaries Act (NMSA), the Federal Government is expressly entitled to the restoration of the illegally damaged natural resources or the replacement costs for those resources. Great Lakes Dredge , 259 F.3d at 1304. The HEA method is used to “scale” the amount of restored or created natural resources necessary to replace the environmental services lost on an interim and/or permanent basis from the damaged resources. 60 GreatMA0003654 Determinations Document July 22, 2002

wetlands.

61 The HRC analysis for BPS satisfies these three criteria.

7-153 Lakes Dredge , 259 F.3d at 1304; Fisher , 977 F. Supp. at 1197-98. In Fisher , 977 F. Supp. at 1197, the court explained that it is appropriate to use the HEA method “when 1) the primary category of lost on-site services pertains to the ecological/biological function of an area; 2) feasible restoration projects are available that provide services of the same type, quality and comparable value to those that were lost; and 3) data on the required HEA input parameters exist and are cost effective to collect.” 61

Replacement cost as a measure of damages has also been upheld by the federal courts in the context of natural resource damages claims under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and the oil spill-related provisions of the Clean Water Act. State of Ohio v. U.S. Department of Interior , 880 F.2d 432, 444-46, 448, 450, 459 (D.C. Cir. 1989). CERCLA provides that natural resource damages recovered shall be used only to “restore, replace, or acquire the equivalent of such [damaged] natural resources” and that the “measure of damages . . . shall not be limited by sums which can be used to restore or replace such resources.” State of Ohio , 880 F.2d at 444 (quoting 42 U.S.C. § 9607(f)(1)). The court explained that Congress intended these two clauses to be read together so that the guiding Congressional purpose of achieving restoration of damaged resources would not be interpreted to make restoration costs a “ceiling” on damages recovery, though they would provide the measure of damages in most cases. State of Ohio , 880 F.2d at 444, n. 8, 445- 46 (also noting that any recovery in excess of restoration costs would be directed to acquiring equivalent resources).

The State of Ohio court states that in most cases restoration costs for damaged natural resources will be greater than their “use” value (but not their total values). 880 F.2d at 441, 445, 446, n. 13. The court explains that:

[t]he fatal flaw of Interior’s approach[, which favored use values over restoration values], however, is that it assumes that natural resources are fungible goods, just like any other, and that the value to society generated by a particular resource can be accurately measured in every case – assumptions that Congress apparently rejected. As the foregoing examination of CERCLA’s text, structure and legislative history illustrates, Congress saw restoration as the presumptively correct remedy for injury to natural resources. To say that Congress placed a thumb on the scale in favor of restoration is not to say that it foreswore the goal of efficiency. “Efficiency,” standing alone, simply means that the chosen policy will dictate the result that achieves the greatest value to society. Whether a particular choice is efficient depends on how the various alternatives are valued . Our reading of CERCLA does not attribute to Congress an irrational dislike of “efficiency”; rather, it suggests that Congress was skeptical of the ability of human beings to measure the true “value” of a naturalMA0003654 Determinations Document July 22, 2002

7-154 resource. . . . Congress’ refusal to view use value and restoration cost as having equal presumptive legitimacy merely recognizes that natural resources have value that is not readily measured by traditional means.

State of Ohio , 880 F.2d at 456-57 (emphasis in the original). Thus, the court concluded that Congress recognized that traditional measures of use value did not fully monetize the total value (including non-use value) of natural resources.

The court in State of Ohio also noted that many scholars shared Congress’ skepticism concerning our ability to adequately monetize the total value of natural resources. 880 F.2d at 457, n. 40. One of these scholars is quoted at some length by the court as follows:

Cross explains how the use of restoration cost as a presumptive measure of damages does not repudiate the goal of economic efficiency:

At first glance, restoration cost appears to be inferior, because it is acost-based, supply-side measure, rather than a demand-side, valuebased measure of natural resource value. For this reason, when natural resource economics advances far enough to provide an adequate demand-side measure, reliance on restoration cost will become inappropriate. At present, however, the economic tools for valuing natural resources are of questionable accuracy . . . [Using restoration costs as the measure of damages] acknowledges the current ignorance of economic valuation of resources by adopting a cautious, preservationist approach.

Cross, [Natural Resource Damage Valuation , 42 Vand. L. Rev. 269,] 331-32 [(1989)]. Others agree that restoration cost can generally be estimated more accurately and easily than can the value of an injured resource.

880 F.2d at 457, n. 40 (additional citations omitted). This discussion suggests that when traditional demand-side measures are inadequate to fully value resources and restoration costs are estimated more easily and cheaply, restoration costs may provide a useful substitute for traditional demand-side

measures.

While the above analysis is presented in the context of natural resource damages cases where restoration of the resources is required by law, this thinking can be applied by analogyto the CWA § 316(b) context where adverse impact to environmental resources is to be minimized. This analogy may be particularly strong when the resources in question are of special importance, such as the Mount Hope Bay ecosystem. Like the HEA method, the HRC method indicates how much of what type of restoration is necessary to offset the resources lost to a cooling water intake structure.MA0003654 Determinations Document July 22, 2002

7-155 As stated above, EPA believes that estimating what it would cost to replace the lost fishery resources by implementing ecologically sound restoration actions is relevant information for us to consider in applying CWA § 316(b)’s wholly disproportionate cost test. We understand that this is not a natural resource damages case under the NMSA, CERCLA or the oil spill provisions of the CWA. We also understand that no statute declares that the cost of restoring the fishery resources destroyed by the power plant must be recovered. Nevertheless, the wholly disproportionate test under CWA § 316(b) is not a cost/benefit analysis and does not require one. It allows broad discretion to EPA to consider a range of “costs” and “benefits” in making a reasoned, articulated policy decision. As discussed above, HRC results provide a measure of what it would cost society to replace the fishery resources lost to the plant in an effective, ecologically sound manner. The HRC results also enable a comparison of the cost of trying to restore the damaged natural resources through public or private restoration efforts to the cost of doing so through technological improvements at BPS.

Furthermore, as also discussed above, HRC results may provide a conservative figure to use for a benefit estimate in place of a total value analysis. Conventional demand-side measures that are reasonably available to permitting agencies in light of budget and time constraints, such as the benefits transfer analysis, are unable to fully value these fishery resources. These problems are discussed in detail above. See EPA February 2002 Case Study Analysis, p. A11-1, Table F6-3 (omissions, biases and uncertainties in benefits estimates). See alsoMay 23, 2002 Revised Chapter A11, pp. A11-2 to A11-6. While a contingent valuation study would provide another means of assessing the total value of the resources in question, such an approach was beyond the budget and time constraints faced by EPA in developing the BPS permit. (We believe this would typically be the case for most permitting agencies.) Moreover, contingent valuation studies hardly eliminate all controversy. See State of Ohio
, 880 F.2d at 474 - 81 (industry challenge to contingent valuation-related provisions of Department of Interior natural resource damages regulations). The HRC method at least allows us to assess restoration costs in a relatively easily and accurate manner. As EPA explains in the May 23, 2002 Revised Chapter A11, p. A11-1:

[t]he HRC method provides an estimate of the expenditures needed to provide natural habitat to a level that will offset I&E losses of aquatic organisms and the ecosystem services they provide. . . . By focusing on recovering I&E losses through natural production in the environment, the HRC method considers both the species lost and the services they provide.

The HRC Method: In the EPA February 2002 Case Study Analysis, at p. F5-1, EPA generally explained the HRC method as follows:

[t]o summarize, the HRC method identifies the habitat restoration actions that are most effective at replacing the species that suffer I&E losses at a CWIS. Then, the HRC method determines the amount of each restoration action that is required to offset fully the I&E losses. Finally, the HRC method estimates the cost of implementing theMA0003654 Determinations Document July 22, 2002

62It should be noted that EPA looked to habitat restoration measures that would replace the lost fish in an ecologically sound and complete manner, rather than to fish stocking programs which do not address several ecological services and address others inefficiently, and which may raise ecological problems and fail to produce fish equivalent to wild fish. See the May 23, 2002 Revised Chapter A11, at p. A8 (discussion of fish stocking).

7-156 restoration actions, and uses this cost as a proxy for the value of the I&E losses. Thus, the HRC valuation method is based on the estimated costs to replace the organisms lost because of I&E, where the replacement is achieved through improvement or replacement of the habitat on which the organisms depend.

More specifically, the HRC method involves a multiple step process:

1. Quantify impingement and entrainment losses (as discussed earlier in the document);

2. Identify habitat requirements of species that are impinged and/or entrained;

3. Identify potential habitat restoration actions that could benefit species from Step 1;

4. Consolidate, categorize and prioritize identified habitat restoration alternatives;

5. Quantify the benefits for the prioritized habitat restoration alternatives;

6. Scale the habitat restoration alternatives to offset impingement and entrainment losses;

7. Estimate “unit costs” for the habitat restoration alternatives; and

8. Develop total cost estimates for impingement and entrainment costs.

Id . at Figure A11-1. EPA used published data wherever possible in applying the HRC method to losses at BPS regarding restoration costs and other matters, but where published data was lacking EPA used and documented unpublished data and best professional judgment from knowledgeable resource experts. Id . at p. F5-1.

EPA used various cost-reducing assumptions throughout the analysis but not beyond the range of values the experts deemed reasonable. In other words, the HRC analysis sought to identify what relevant experts believed to be the minimum restoration costs necessary to offset the fish lost to the BPS cooling water intakes. Id . at p. F5-2. 62Cost-reducing assumptions used in the analysis are discussed in Chapter F5 and at § F6-3 of the EPA February 2002 Case Study Analysis. Two of the more important ones are the following: (1) although data did not exist to specify proposed habitat restoration measures for all species of fish entrained and impinged at BPS, it was assumed thatMA0003654 Determinations Document July 22, 2002

63 As discussed above, EPA believes this approach would tend to produce a conservative (i.e., low) estimate.

7-157 measures for the species for which data was available would be sufficient to replace all species, id . at p. F5-2; and (2) entrainment and impingement losses are based on data from 1974 to 1983, but these data may underestimate the losses from a healthy fishery because BPS operations pre-dated 1974 and some data indicates that BPS contributed to a fishery decline commencing prior to that date. Id . at p. F6-6.

EPA believed it was appropriate to adopt these and other cost-reducing assumptions because the purpose of this exercise was to develop an estimate of restoration costs for EPA to consider in applying the wholly disproportionate cost test under § 316(b) rather than actually to require implementation of a specific restoration program to fully offset fishery losses to the power plant. It would, of course, make little sense to implement these measures to restore fish to Mount Hope Bay only to have those fish killed by the BPS cooling water intake structures or otherwise harmed by habitat changes resulting from the plant’s thermal discharges. The costing components of the HRC analysis are described in §§ A11-2.7 and A11-2.8 and F5-7 and F5-8 of the EPA February 2002 Case Study Analysis.

Additional discussion of strengths and weaknesses of the HRC method is presented in the May 23, 2002 Revised Chapter A11, pp. A11-15 to A11-16.

HRC Results: The HRC analysis ultimately estimates that the cost of habitat restoration needed to replace the fish lost to impingement is $873,400 per year (Year 2000$) and to entrainment is $27.7 million per year (Year 2000$). Id . at Tables F5-40 and F5-41 and Figure F5-5.

**iv.** Range of EPA Estimates

Combining the “benefits transfer” analysis with the “per-person” non-use value analysis, one finds a range of estimated values for all the fish lost to the BPS cooling water intake structure from $239,078
per year (Year 2000$) (entrainment and impingement combined; mid-point of the range of benefits transfer values) to $ 37.9 million (Year 2002$) (entrainment and impingement combined; mid-point of range, of per-person New England estimate) and $124.5 million (Year 2002$) (entrainment and impingement combined; mid-point of range of per-person national estimates). As stated above, the estimated cost to restore the lost fish through an ecologically sound restoration program is estimated by the HRC analysis to be approximately $28.6 million per year (Year 2000$) (impingement and entrainment effects combined). As stated above, there is some data to suggest, as explained above, that HRC values are unlikely to be greater than the total value of these resources to the public.

In order to relate the above figures to particular technology options, EPA then assumed that the proportion by which a technology would reduce flow would also reduce entrainment and impingement by the same percentage. 63 This percentage was then applied to the monetary values indicated above toMA0003654 Determinations Document July 22, 2002

7-158 determine the value of the resources saved by a particular option, or the cost of restoration that would be needed to provide the same number of fish that a particular option would save. Thus, since the Closed-Cycle Entire Station option would reduce flows by approximately 96%, the approximate values associated with that option are calculated by multiplying the above figures by 0.96. Likewise, since the Closed-Cycle Units 1 or 2 & 3 option would reduce flows by approximately 59%, the approximate values associated with that option are calculated by multiplying the above figures by 0.59. Since the Enhanced Multi-Mode option would reduce flows by approximately 33%, the approximate values associated with that option are calculated by multiplying the above figures by 0.33. The resulting values from these calculations are presented in Table 7.6.3.2.d-1 below.

Table 7.6-2: Natural Resource Value and Restoration Cost Estimates Associated with

Different Technology Options (all values in Year 2002$) Technology % Flow

Reduction Benefits

Transfer (Use and Non-Use Values) Per-Person

Non-Use Values (New England) Per-Person

Non-Use Values (National) HRC*

ClosedCycle Entire Station: 96% $240,853/yr. $36.4 million/yr. $119.5

million/yr. $28.9

million/yr.

ClosedCycle Units 1 or 2 & 3: 59% $148,025/yr. $22.4 million/yr. $73.5

million/yr. $17.7

million/yr.

Enhanced Multi-Mode: 33% $82,793/yr. $12.5 million/yr. $41.1

million/yr. $9.9

million/yr.

* HRC values represent the cost of restoring the same number of fish that would be saved by the particular technology option.MA0003654 Determinations Document July 22, 2002

64 See U.S. EPA 2002, CWA § 316(b) Phase II Rule: Benefits Case Studies, Part C: The Ohio River Case Study. (U. S. EPA, Office of Water, Washington, D.C. 2002).

7-159 **v.** Assessment of Reasonableness of the High Values

Obviously, the various analyses undertaken have produced a considerable range of figures. We have already discussed above some of the issues related to the various analytical approaches, including reasons why we believe the low figures are likely to represent substantial underestimates. In addition, EPA undertook, with the support of its consultant, Abt Associates, the following effort to review the likely reasonableness of the high estimated values developed from the “per-person, non-use to use benefit” ratio and the HRC methods.

To perform this reasonableness review, EPA compared these benefit estimates to values derived from illustrative calculations of the potential use and non-use benefit that might arise in certain New England regional populations based on very simple and conservative valuation assumptions. In effect, EPA asked the following questions: (1) if regional populations assigned relatively conservative values to the prospective improvement to the aquatic resources and habitat affected by BPS intake system operations, what would the indicated benefit of the improvements be those regional populations? and (2) do the values resulting from this relatively crude approach to benefit assessment suggest that the “per-person, non-use to use benefit” ratio method and the HRC estimates are within a “ballpark” degree of reasonableness?

For this comparison, EPA used three populations of households as representative of the potential “market” for valuing the improvement of aquatic resources that would result from reduced impingement and entrainment at BPS. The first and most narrowly defined market is the estimated number of households in the Narragansett Bay watershed. These households comprise the population group who will most readily value – whether as users or non-users – improvements in the affected aquatic resources. As a somewhat broader population, we also considered the number of households within 120 miles of the affected area. The distance of 120 miles has sometimes been used in natural resource valuation studies as an outer bound for defining the population who might reasonably travel to an affected resource site in the course of a one-day trip and, accordingly, would readily benefit from resource improvements at the affected site. 64We believe the 120-mile distance is reasonably conservative; some resource valuation studies have used longer distances. Finally, as a third, broader potential market that would benefit from the improvements in question, EPA considered the number of households in the six New England states. This, in effect, is the population of the region covered by the EPA - New England Regional office.

The resulting numbers of households in each defined “market” area are as follows: 800,354 households within the Narragansett Bay watershed; 4,209,126 households within 120 miles; and 5,611,374 households in the New England states. Since EPA limited the definition of potential benefit populations to households within New England for this illustrative “test-of-reasonableness” calculation, anyMA0003654 Determinations Document July 22, 2002

7-160 additional benefit from households beyond New England is ignored. This represents a point of conservatism in this analysis.

EPA also used the following three values as a range of potential annual benefits per household: $5.00, $10.00 and $37.50. The $5.00 per household value is essentially a nominal, lower bound estimate. The $37.50 per household value is approximately the average of per household, annual non-use benefit values found in six studies of non-use value for improvements to water resources, as reported in Brown and referenced by Abt Associates in its estimation of the per-person, non-use benefit values from reduced impingement and entrainment at BPS. The intermediate, $10.00 per household value is approximately the average of the two lowest per household values reported in the Brown article. Not using the high values from the studies for this analysis represents another point of conservatism in the analysis.

Combining the estimated numbers of households within the defined “markets” and the range of annual benefit values per household yields estimated potential benefit values ranging from $4.0 million to $210.4 million. Table 7.6.3.2.d-2, below, reports the values calculated from this analysis. As shown in the table, except for the values produced by combining the two lowest per-person values with the most narrowly defined benefit population (i.e., households within the Narragansett Bay Watershed), the indicated potential benefit values are all greater than $20 million per year. Even at the conservative, nominal value of $5.00 per household, the indicated potential values exceed $20 million per year based on the numbers of households within 120 miles of the affected area and in the six New England States. At the intermediate annual benefit value of $10.00 per household, the indicated benefit values increase substantially to approximately $50 million per year for the cases defined by the number of households within 120 miles of the affected area and in the six New England States. Finally, when the average non-use benefit value of $37.50 per household from the six water resource studies cited in Brown is used as the basis of the calculation, the potential benefit values increase to more than $150 million per year for the two higher population cases.

These annual benefit values were developed on the basis of relatively simple and conservative assumptions about the potential population of households that may value improvements to the affected aquatic resources and the potential annual benefit values per household. That the resulting annual values fall in a range extending from a few million to over one hundred million dollars per year providessupport for the reasonableness and credibility of the values reported above for the “per-person, nonuse to use benefit” ratio and HRC methods. The values from these analyses fall very much within the range of the values developed from the illustrative potential benefit calculations presented in the table below.

On balance, EPA concludes that the estimates from the “per-person, non-use to use benefit” ratio and HRC methods are reasonable and credible and provide realistic, meaningful insight into the potential benefits of reduced intake flow at BPS and accompanying improvement in aquatic resources in Mount Hope Bay.MA0003654 Determinations Document July 22, 2002

7-161 Table 7.6-3: Potential Range of Annual Benefits Based on Number of Households in Benefit

Markets and Potential Annual Household Benefit Values

Estimated Potential Annual Benefit ($000,000; 2002$) Number of Based on Average Benefit Value Per Household Benefit Population (Households) Households $5.00 $10.00 $37.50 Narragansett Bay Watershed* 800,354 4.0 8.0 30.0 Population Within 120 Miles** 4,209,126 21.0 42.1 157.8 Six New England States^ 5,611,374 28.1 56.1 210.4 * Source: Narragansett Bay Estuary Program, "Atlas of Narragansett Bay - Coastal Habitats" (Report # 01-118; October 2001). Households calculated as estimated population (approximately 2 million divided by 2.5 persons per household; average number of persons per household for New England from 2000 Census). ** Based on 2000 Census, U.S. Bureau of the Census. Population calculated for all census tracts within 120 miles of estimated aquatic resource impact area. Excludes Long Island. ^ Estimated 2001 population values from U.S. Bureau of the Census.

**vi.** USGenNE Analysis

USGenNE has indicated that it is also undertaking an effort to monetize the benefits that would flow from technological improvements to reduce capacity of the cooling water intake structures at BPS. December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Executive Summary, p. 60. The permittee indicated in the December 2001 USGenNE 316(a) and (b) Demonstration, p. 60, n. 88, that it would be submitting this analysis to the regulatory agencies “shortly,” but at least as of July 15, 2002, it has not been submitted. Therefore, it is impossible to fully consider or even describe the permittee’s analysis.

EPA will, however, say a few things about this analysis based only on the brief statements about it in the Executive Summary of the December 2001 USGenNE 316(a) and (b) Demonstration and a few subsequent comments made by the permittee at various meetings. First, the permittee indicates that it has addressed both commercial and recreational fishery benefits of reducing cooling water intake flow. December 2001 USGenNE 316(a) and (b) Demonstration, Vol. I, Executive Summary, p. 60. This was later reiterated at a January 29, 2002, meeting between EPA, MA DEP and USGenNE. See April 30, 2002, Memorandum from Mark Stein, EPA, to Brayton Point NPDES File, “Some Notes Regarding Meeting with USGenNE on 1/29/02.” Second, it is unclear from the text in the December 2001 USGenNE 316(a) and (b) Demonstration, at Vol. I, Executive Summary, p. 60, whether the permittee attempted to monetize any value for fish that are not exploited in commercial or recreational fishing (though we would expect that the permittee’s consultants would do so). Third, it does not appear from the text of the December 2001 USGenNE 316(a) and (b) Demonstration, at Vol. I, Executive Summary, p. 60, or from statements at meetings with EPA, seeApril 30, 2002, Memorandum from Mark Stein, EPA, to Brayton Point NPDES File, “Some Notes Regarding Meeting with USGenNE on 4/8/02,” that the permittee has included any non-use values in its assessment.MA0003654 Determinations Document July 22, 2002

7-162 Second, it seems

that the permittee’s analysis may be conceptually similar to EPA’s analyses in the sense that we expect that the permittee took its estimates of fish mortality from entrainment and impingement under current flows with the once-through cooling system, and then reduced those losses by the percentage of flow reduction provided by the various options. We expect that the permittee then took the number of fish “saved” and did certain calculations to derive an estimated value of those fish. In any event, the permittee did provide certain values in the December 2001 USGenNE 316(a) and (b) Demonstration, at Vol. I, Executive Summary, p. 61, Table IV.C.2. Specifically, USGenNE concluded that the total monetized benefit (over 20 years, presented as a present value in 2001 dollars) from various flow reduction technologies are as follows: $0.28 million from the Enhanced Multi-Modeoption; $0.32 million from the Unit 3-Closed-Cycle option; $0.38 million from the Units 1 & 2 ClosedCycle option; and $0.62 million from the Entire Station Closed-Cycle option. The permittee did not provide an equivalent annual values, but it would appear that the permittee’s values would be even lower than the above-cited figures developed in EPA’s benefits transfer analysis.

**vii.** RI DEM Analysis

The RI DEM’s Division of Fish and Wildlife conducted an assessment of the value of the fish lost to the Brayton Point Station since the 1986 Mount Hope Bay fishery collapse . The analysis is presented in a paper entitled, “Ex-Vessel Value of Production Foregone in Mt. Hope Bay as a Result of Operations at USGen of New England’s Brayton Point Station” (Gibson, 2002C). It is EPA’s understanding that RI DEM conducted this analysis in the context of assessing damages to the Mount Hope Bay fishery by the BPS cooling water intake structures since the fishery collapse in the mid-1980's. In the introduction to the paper, RI DEM explains:

While denied fishing opportunities are the most obvious loss, denied ecological services also need to be considered. Since most natural deaths in the marine environment are caused by predation, power plant losses remove food resources from the benthic and pelagic food webs. Computation of production-foregone accounts for both denied catch opportunities and biomass contributing to higher trophic levels. Attaching monetary value to the production foregone is more difficult. The simplest approach is to assign a value to the production commensurate with the ex-vessel value in a commercial fishery.

Id . at p. 3. Gibson used this “simple” approach, but approached his production foregone analysis by looking at the response of the total stock complex and working down to losses of individual species. (In contrast, both EPA and USGenNE began their analyses from the individual losses.)

RI DEM’s analysis concludes that, “[t]he value of foregone fishery production, including unexploited and seasonal species, has fluctuated between 0.5 and 1.4 million dollars per year . . . [and s]ince 1986, the cumulative loss has been 12.7 million dollars.” Id . at p. 8. RI DEM further explains that “[t]he loss is understated as recreational value is not considered, a commercial multiplier is not employed [toMA0003654 Determinations Document July 22, 2002

65 Increased use of “piggyback” operations under the MOA II, however, has somewhat reduced flows and allowed the use of only one intake for eight months of the year.

66 We also note that BPS is also the largest New England source of emissions of an array of important air pollutants (e.g., nitrogen oxides, sulfur dioxide).

7-163 capture economic ripple effects], and foregone production from plant startup through 1985 is not included.” Id

.

7.7 CWA § 316(b) Determination and Application of “Wholly Disproportionate Cost” Test

This section of the document discusses the analyses presented above, applies the “wholly disproportionate cost test,” and presents EPA’s determination regarding the necessary NPDES permit requirements for Brayton Point Station under CWA § 316(b). To the extent that this section reiterates matters that have been discussed and documented in earlier sections of this document, supporting references will not be repeated here.

7.7.1 Introduction

Brayton Point Station (BPS) is the largest fossil fuel burning power plant in New England. With an operating capacity of approximately 1500 MW – approximately 1100 MW from coal-burning units 1, 2 and 3, and 400 MW from oil/natural gas-burning Unit 4 – BPS produces about six percent of the electricity consumed by New England (at 2001 consumption levels). See Abt Associates, Inc., “Impact of Thermal Discharge Management and Air Pollution Control Options for Brayton Point Station on New England Electricity Market and Consumer Rates,” p. 3 (May 8, 2002). As such, it is clearly an important contributor to New England’s power supply at the present time.

Unfortunately, in addition to producing electricity, BPS also kills fish (eggs, larvae, juveniles and adults) and other organisms, and adversely alters the habitat of the Mount Hope Bay estuary on a massive scale. Situated at the head of Mount Hope Bay, at the confluence of the Taunton and Lee Rivers, BPS withdraws a daily average flow of nearly one billion gallons of water from Mount Hope Bay through its two cooling water intake structures. 65 In the process of withdrawing water from the bay, the plant annually kills literally trillions of organisms. These organisms are not taken for the beneficial uses of food, recreation or ecological services; rather, they are simply wasted as a byproduct of the cooling method presently used to generate electricity at BPS. In addition, by discharging the huge volume of heated water back to the bay, BPS significantly alters the thermal regime of the water body. The extent and significance of the habitat alteration varies seasonally, and with the tides, but at times can cause important effects across much of the bay, throughout the water column, and in important parts of the rivers that flow into the bay. 66

The Mount Hope Bay estuary is an important part of the larger Narragansett Bay estuary, an estuary ofMA0003654 Determinations Document July 22, 2002

7-164 great local and national environmental significance. Mount Hope Bay once supported a productive fishery and the Mount Hope Bay estuary should provide an important nursery area for fish and other aquatic organisms. At present, the Bay is achieving neither of these ecological services. It is widely accepted that Mount Hope Bay’s fishery has collapsed. In an effort to help restore fish stocks to health, Massachusetts and Rhode Island have imposed stringent commercial and recreational fishing restrictions across the bay. These restrictions have been in place for a number of years, drastically limiting public use and enjoyment of these natural resources. Applicable Massachusetts and Rhode Island Water Quality Standards (designated uses and criteria) related to fishery resources and habitat quality are clearly not being attained in the bay.

Current once-through cooling operations at BPS result in the cooling water intake structures killing vast numbers of individual aquatic organisms and substantial percentages of the populations of various fish species. Furthermore, data indicates that the precipitous decline in the bay’s fish stocks occurred around 1985, coincident in time with BPS’s conversion of Unit 4 from closed-cycle to open-cycle cooling, and its attendant large increases in cooling water flow and thermal discharge. In addition, however, other data suggests that the fishery decline began well before 1985. This data indicates that the Mount Hope Bay fishery has been in decline since the early 1970's, and that the changes at Unit 4 in the mid-1980's simply helped to push the fishery “over the edge.” On the basis of current information, EPA has concluded that BPS cooling water intake operations have, at a minimum, significantly contributed to the collapse of fish stocks in Mount Hope Bay. EPA concludes that BPS operations – Units 1, 2 and 3 began operation in the 1960's – played a significant role contributing to fishery declines prior to the mid-1984 conversion of Unit 4 to open-cycle cooling. The Unit 4 conversion, in turn, helped to trigger the precipitous fishery decline of the mid-1980's.

EPA understands that this correlative data does not prove “cause and effect” in a strict scientific sense. The only way to achieve that level of certainty would be to conduct a controlled experiment on the Mount Hope Bay estuary, recreating true baseline conditions and then controlling all variables, including the power plant. It is obviously impossible to conduct such an experiment. In addition, it is impossible to be certain about the exact extent of the fishery decline since the commencement of BPS operations because collection of fish abundance data for Mount Hope Bay did not begin until 1972, after Units 1, 2 and 3 began operations. EPA cannot, however, simply “throw up its hands” in light of these limits on the scientific certainty that can be achieved. Instead, we have to do the best we can to draw reasonable conclusions from the best, reasonably available information in order to apply the requirements of the Clean Water Act. We believe the above-stated conclusions are reasonable and appropriate in light of current data and understanding.

Despite the current problems in Mount Hope Bay, the “good news” is that by upgrading BPS’s cooling systems with modern cooling technologies that cut cooling water volume (and thermal discharge), the power plant can both drastically reduce its harmful effects on the waters of Mount Hope Bay andcontinue generating electricity for New England’s energy supply. By taking advantage of these wellestablished cooling technologies, BPS can generate electricity in a manner that is far less harmful to theMA0003654 Determinations Document July 22, 2002

67 Similarly, BPS’s air pollutant emissions can also be greatly reduced by utilizing updated technologies to comply with new Massachusetts air regulations.

7-165 marine environment. 67 Moreover, we believe that undertaking such efforts are clearly worthwhile because experience shows that when pressure on depleted fish stocks is reduced or removed, those stocks can rebound. It is clear that strong, difficult and expensive actions have been, or are being, taken to reduce other pressures on Mount Hope Bay’s fish stocks. These include fishing restrictions, water pollution reductions. Improvements are also needed at BPS.

7.7.2 Brief Reiteration of Legal Standards

CWA § 316(b) states that:

[a]ny standard established pursuant to section 301 or section 306 of this Act and applicable to a point source shall require that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.

33 U.S.C. § 1326(b). Assessing the level of “adverse environmental impact” includes, among other things, assessing the number of individual aquatic organisms of various species that are killed, assessing the percentage of various species’ populations that are killed, and assessing whether the health of specific species populations or the overall community or assemblage of species in the water body is compromised. Considering all of these elements, EPA can judge the overall magnitude of the adverse environmental impacts from the cooling water intake structure to help determine what measures should be implemented. “Minimize” has been defined by EPA in the past to track the common dictionary definition of “reduce to the smallest possible amount, extent, size, or degree.”

The “Best Technology Available” (BTA) refers to the available technology that would do the best job of minimizing (

i.e. , get the greatest reductions of) the adverse environmental impacts from operation of the cooling water intake structure. The technologies relied upon must be technologically and economically practicable.

EPA may regulate the level of cooling water flow through a cooling water intake structure as part of ensuring that the “capacity” of the intake structure reflects the BTA. This type of flow-based performance standard may indirectly lead a discharger to use a particular type of cooling system, though EPA cannot directly mandate that a particular type of cooling system be used. For example, EPA cannot mandate the use of cooling towers, but EPA can impose a flow limit that might lead a facility to choose to use cooling towers as a means of compliance. EPA can also require improvements to pumping, screening and fish return systems as part of ensuring that the “design” of the intake structure reflects the BTA.MA0003654 Determinations Document July 22, 2002

7-166 Although the text of CWA § 316(b) makes no mention of economic considerations, EPA has long interpreted the provision to bring economic considerations to bear in two ways. First, remarks by Representative Clausen from the legislative history of CWA § 316(b) indicated that BTA means “best technology available commercially at an economically practicable cost.” Therefore, the cost of measures to meet BTA requirements should be economically practicable. 1972 Legislative History, p. 264. Second, EPA has interpreted § 316(b) to contemplate a consideration of economics such that the costs of BTA measures should not be “wholly disproportionate” to their benefits. Neither statute, regulations nor EPA guidance dictate exactly how to apply the wholly disproportionate cost test under § 316(b). The Administrator of EPA explained the Agency’s interpretation, later upheld by the courts, in the case of In re Public Service Company of New Hampshire (Seabrook Station, Units 1 and 2), 10 ERC 1257, 1261 (NPDES Permit Application No. NH 0020338, Case No. 76-7; June 17, 1977) (Decision of the Administrator), stating as follows:

. . . the Agency’s position, that cost benefit analysis is not required under Section 316(b), is correct. Section 316(b) provides flatly that cooling water intakes shall “reflect the best technology available for minimizing adverse environmental impact.” Unlike Sections 301 and 304, Section 316(b) determines what the benefits to be achieved are and directs the Agency to require use of “best technology available” to achieve them. There is nothing in Section 316(b) indicating that a cost benefit analysis should be done . . .. Indeed, but for one bit of legislative history [citation to Representative Clausen’s remarks omitted], there would be no indication that Congress intended costs to be considered under Section 316(b) at all. I find, therefore, that insofar as the RA’s decision may have implied the requirement of a cost/benefit analysis under Section 316(b), it was incorrect. However, the RA may have meant only that some consideration ought to be given to costs in determining the degree of minimization to be required. I agree that this is so – otherwise the effect would be to require cooling towers at every plant that could afford to install them, regardless of whether any significant degree of entrainment or entrapment was anticipated. I do not believe that it is reasonable to interpret Section 316(b) as requiring the use of technology whose cost is wholly disproportionate to the environmental benefit to be gained.

Thus, a cost/benefit analysis is not required. Rather, “some consideration” must be given to costs and EPA does so by applying the wholly disproportionate cost test.

For general guidance, EPA looked both to past EPA § 316(b) decisions as well as EPA’s past application of the “wholly disproportionate cost” test in the analogous area of developing Best Practicable Treatment (BPT) technology standards for pollutant discharges. Numerous court casesMA0003654 Determinations Document July 22, 2002

7-167 indicate that under the BPT wholly disproportionate cost test, cost is not to be considered a factor of “primary” or “paramount” importance, that EPA’s assessment of costs and benefits “is a relatively subsidiary task and need not be precise,” that an “overall” cost/benefit comparison is sufficient, and that EPA is not required to prepare an “incremental” cost/benefit analysis or “knee of the curve” analysis. (Citations to court cases for the above quoted language are set forth in the legal discussion presented in an earlier section of this document.)

At present, EPA continues its longstanding practice of applying CWA § 316(b) to existing facilities on a case-by-case, best professional judgment basis. On April 9, 2002, EPA published for public review and comment new proposed regulations for applying § 316(b) to large, existing power plants. However, these proposed regulations are not yet in effect, are subject to change, and specify that they are not to be used as guidance for current permit actions. 67 Fed. Reg. 17121 (April 9, 2002).

7.7.3 BTA for Minimizing Adverse Environmental Impacts

EPA concludes that the magnitude of the adverse environmental impacts from current operations of the Brayton Point Station cooling water intake structures is severe, and that the location, design and capacity of the current intake structures do not reflect the Best Technology Available for minimizing those adverse environmental impacts (BTA). Vast numbers of individual organisms – literally trillions of organisms, including billions of fish eggs, fish larvae, adult and juvenile fish – are being killed and/or injured annually as a result of entrainment and impingement at BPS. The ecological functions that these organisms provide to the food web and ecosystem are lost from the Mount Hope Bay estuary. Even after calculations to convert eggs and larvae to “Age 1 equivalent” fish, millions of these Age 1 fish are lost annually to entrainment and impingement, including species of commercial and recreational importance and forage fish species of significance to the food web and ecosystem health (e.g., 520,716 winter flounder; 1,237,140 bay anchovy). EPA February 2002 Case Study Analysis, p. F5-2.

BPS is also clearly taking substantial percentages of the Mount Hope Bay adult populations of a number of fish species (e.g., winter flounder, tautog, hogchoker). Moreover, the overall assemblage of fish species has collapsed in Mount Hope Bay. The balanced indigenous community of fish that should exist in Mount Hope Bay has been severely compromised. EPA believes that BPS’s take of organisms through its cooling water intake structure has contributed to the fishery collapse, and is helping to prevent or inhibit a recovery despite public steps being taken to promote such a recovery, including fishing restrictions and water pollution reductions. In sum, the magnitude of adverse environmental impacts in this case is severe.

EPA has determined that the essential means of reducing the adverse environmental impacts of the cooling water intake structures at BPS in the future is to substantially cut their permitted capacity (i.e., flow reductions). This is the only practicable way to get major reductions in the number of individual organisms and the percentage of species populations that are killed by the power plant as a result of entrainment and impingement. Indeed, EPA has concluded that unless there is a major reduction in theMA0003654 Determinations Document July 22, 2002

68 It will also be important for the regulatory agencies to work with the permittee to negotiate an implementation schedule that minimizes any generating unit construction outages occurring during peak electricity demand periods.

7-168 number of organisms that BPS culls from the Mount Hope Bay ecosystem, the bay’s balanced indigenous community of organisms is unlikely to recover. Conversely, with major reductions in the cooling water intake structure’s take of fish (as well as major reductions in the scope of the thermal discharge plume and other measures, such as careful management of fishing pressure), EPA believes that the fishery of Mount Hope Bay can recover and once again be a productive ecological resource contributing to the public’s welfare and quality of life.

Like the permittee, EPA investigated numerous technological options for determining what permit requirements are needed in order for the design, location, capacity and construction of the cooling water intake structures to reflect the BTA for minimizing adverse environmental impacts (BTA). From this work, EPA has concluded that cooling water intake structure capacity limits should be based on flows commensurate with converting Units 1, 2, 3 and 4 to closed-cycle cooling using mechanical draft wet cooling towers (the Closed-Cycle Entire Station option) in order to reflect the BTA for minimizing adverse impact. The flow limits associated with this option are 56 MGD, down from the current flow of approximately 1.0 BGD (a reduction of about 94%).

First, EPA has concluded that retrofitting closed-cycle wet mechanical draft cooling towers for Units 1, 2, 3 and 4 at BPS should be technologically and economically practicable. See May 20, 2002, Memorandum from Michael Fisher and Geoff Bennett, Abt Associates, Inc., to Mark Stein and Dave Webster, US EPA Region 1, “Subject: Financial Impact of Closed Cycle System Installation at Brayton Point Station - WITH CONFIDENTIAL BUSINESS INFORMATION EXCLUDED FROM TEXT AND TABLES.” Such retrofits have been completed in the past at other large power plants. This fact along with other site-specific information indicates that such a retrofit should be feasible at Brayton Point Station. It is recognized, however, that there will be logistical challenges at the site and the regulatory agencies will need to work closely with USGenNE to develop an appropriate schedule for implementing the retrofit. 68

Second, in order to give the Mount Hope Bay fishery a chance to recover, EPA has concluded that the number of organisms, and the percentages of species populations, taken by entrainment and impingement by the BPS cooling water intake structures must be drastically reduced. Such large-scale reductions can be accomplished by the Closed-Cycle Entire Station option. This option can achieve approximately a ninety-six percent reduction in flow. It will achieve comparable reductions in entrainment and impingement. With this option, the losses of organisms of various species can be reduced by nearly two orders of magnitude. This option will also allow the elimination of one of BPS’s two cooling water intake structures. Coupled with current fishing restrictions and water pollution controls – including the substantial reductions in BPS’s thermal discharges that will accompany the Closed-Cycle Entire Station option – removing the severe stress the BPS intake structures place on theMA0003654 Determinations Document July 22, 2002

7-169 ecosystem and fish populations will give the community of organisms an opportunity to recover.

EPA acknowledges that there will still be some adverse environmental impacts from the Closed-Cycle Entire Station option because organisms will continue to be entrained and impinged due to the approximately 56 MGD of makeup cooling water that the power plant would still need to withdraw from Mount Hope Bay with this technology. As stated above, however, the number of organisms and percentages of species populations lost to the cooling water intake structures will be substantially reduced with this option as compared to the other options. Moreover, EPA believes this level of improvement should be sufficient to facilitate the recovery of Mount Hope Bay’s balanced, indigenous community of organisms. In sum, based on current information, we believe the magnitude of the adverse environmental effects from this option will not be substantial.

Finally, although even greater reductions in adverse impacts could theoretically be achieved with the use of dry cooling technology, which essentially eliminates the need for cooling water, EPA has concluded based on current information that this technology is not clearly practicable for use at BPS. As far as we or the permittee could learn, no large existing power plant has been retrofitted to dry cooling. Further, this technology has been estimated to cost roughly three times the cost of mechanical draft wet cooling towers. EPA deemed it inappropriate to impose flow restrictions that would triple the cost in order to increase flow reductions from ninety-six to one hundred percent, given that we believe that flow levels associated with the Closed-Cycle Entire Station option will result in insubstantial adverse impacts.

EPA also considered various other environmental and energy issues raised by a proposed conversion to the Closed-Cycle Entire Station option. Based on this evaluation, EPA has concluded that these issues do not pose serious problems and can be effectively managed. Of greatest importance, because it raises the possibility of a public safety concern, is the issue that the permittee raises concerning the potential for traffic safety problems to result from cooling tower vapor plumes causing fog or ice affecting Route 195 or the Braga Bridge. The permittee indicates it could alleviate any such problem by instituting periodic generating unit shutdowns, but complains that such shutdowns would be very expensive.

EPA’s research on the vapor plume fog/ice issue at other plants indicates that it is unlikely that cooling tower plumes would create fog or ice that would pose significant traffic safety problems at Route 195 or the Braga Bridge and require generating unit shutdowns. Indeed, the permittee’s analysis –which EPA has many questions and reservations about – suggested only a small marginal potential increase in fog or ice over existing background conditions, and this possible increase was well within the range of natural variability in the background conditions. Nevertheless, EPA also believes there are a number of potential ways to deal with any problem that could emerge. These range from coordinating extra safety measures with the Massachusetts Highway Department (MHD) (e.g., deployment of extra fog warning signs, extra road sanding/salting crews, as EPA and MA DEP have discussed with the MHD), to engineering the cooling towers so that they can be bypassed (i.e., shifted to temporary once-through cooling operations) if necessary to protect traffic safety, to undertaking cooling tower and generatingMA0003654 Determinations Document July 22, 2002

7-170 unit shutdowns if absolutely necessary to ensure public safety. However, EPA does not believe the latter situation is likely to occur. The permittee also could install a technology known as “hybrid” (or “wet/dry”) cooling towers to further reduce any threat of vapor plume problems, but the likely extent of the potential problem here does not appear to warrant the increased expense of this technology.

EPA also believes that the other environmental issues raised by the plant are either insignificant or can be managed. As discussed in detail above, neither noise, air emissions, aesthetic concerns, salt drift, nor any other issue raises a problem that renders modernizing the BPS cooling system with wet mechanical draft cooling towers infeasible or inappropriate. Obviously, federal, state and local requirements for noise and air emissions will need to be addressed and complied with.

EPA also evaluated numerous technological options beside the Closed-Cycle Entire Station option. For example, we assessed and rejected dry cooling, as discussed above. Options such as intake design modifications (e.g., screening technologies) and re-locating the intake structures to less sensitive water body segments were also evaluated and rejected for various reasons.

Furthermore, EPA evaluated options that would have provided closed-cycle cooling with wet mechanical draft cooling towers for fewer than all four steam-electric generating units at BPS (e.g., the Closed-Cycle Unit 3 option and the Closed-Cycle Units 1 or 2 & 3 options). EPA believes these options are also practicable. They would obviously be cheaper than the Closed-Cycle Entire Station option as they involve lower capital costs, energy penalties, and maintenance expenses. However, they also would achieve substantially lesser flow reductions. As a result, with these options BPS would continue to take huge numbers of individual organisms and significant percentages of Mount Hope Bay’s populations of various fish species. Furthermore, EPA does not believe the reductions achievable with these options would be sufficient to allow the recovery of the balanced, indigenous population of organisms in Mount Hope Bay (despite fishing restrictions and water pollution improvements). Obviously, the Closed-Cycle Units 1 or 2 & 3 options would reduce flows to a significant degree beyond the Closed-Cycle Unit 3 option, but EPA is not convinced that this incremental improvement would be sufficient to facilitate the fishery’s recovery. In light of the above factors, EPA has determined that capacity limits based on these two options would not reflect the BTA for minimizing adverse environmental impacts.

Finally, EPA also carefully evaluated the Enhanced Multi-Mode option proposed by USGenNE. This option also utilized closed-cycle cooling with wet mechanical draft cooling towers configured in such a way that the cooling towers could be bypassed or could cool water from different units under different circumstances. EPA commends the permittee for developing and proposing this option. We believe it was a constructive proposal that showed ingenuity. Indeed, we believe that the closed-cycle cooling system for the Closed-Cycle Entire Station option should be designed and constructed with the same ability to bypass the cooling towers that the Enhanced Multi-Mode option has. (Cooling tower bypass capability has also been used at other existing power plants.)MA0003654 Determinations Document July 22, 2002

69 Since the intake structure for Units 1, 2 and 3 will not be used under the Closed-Cycle Entire Station option – only the Unit 4 intake will be used – there is no need to implement the screening and fish return system upgrades discussed above for the Units 1, 2 and 3 intake (e.g., improved fish buckets, low pressure spray wash). The Unit 4 intake structure already has these components.

7-171 Nevertheless, the Enhanced Multi-Mode option would achieve only approximately a one-third reduction in flow from the current condition, far less than the Closed-Cycle Entire Station option. With the Enhanced Multi-Mode option, vast numbers of organisms, and substantial percentages of the Mount Hope Bay populations of various fish species, would continue to be killed by entrainment and impingement by BPS’s intake structures. Moreover, EPA does not believe that the reductions achievable with this option would be sufficient to allow the recovery of the overall community of organisms that should exist in Mount Hope Bay, despite restrictions on fishing and improved controls on water pollution. As such, EPA does not believe that intake capacity limits based on flows achievable by the Enhanced Multi-Mode would reflect the BTA for minimizing adverse environmental impacts. (The Enhanced Multi-Mode option also achieves far lower thermal discharge reductions than the Closed-Cycle Entire Station option.)

In summary, EPA determines that a capacity limit reflecting the BTA for minimizing adverse environmental impacts should be based on the performance capability of closed-cycle cooling with mechanical draft cooling towers for Units 1, 2, 3 and 4. 69 Thus, the flow limit in the draft permit is 56 MGD.

7.7.4 Application of the Wholly Disproportionate Cost Test under CWA § 316(b)

As stated above, cost/benefit analysis is not required under CWA § 316(b). Instead, EPA must “consider” costs. EPA does so by determining whether the cost of a selected BTA option for minimizing adverse environmental impacts is practicable, and by determining whether the cost of the option is “wholly disproportionate” to its benefits. There is no statutory, regulatory, or CWA § 316(b) guidance document indicating exactly how this test should be applied. EPA has a substantial range of discretion in applying this test. Looking by way of analogy to case law concerning EPA’s application of a “wholly disproportionate cost” test in the development of BPT effluent discharge guidelines, the courts have held, among other things, that cost is not to be considered a factor of “primary” or “paramount” importance, that this assessment “is a relatively subsidiary task and need not be precise,” and that an “overall” assessment is sufficient.

In order to inform the best possible decision, and in light of the complexity of the issues involved and the range of discretion left to the Agency under CWA § 316(b), EPA has considered the cost of the BTA options and the significance of their environmental benefits from a number of perspectives.MA0003654 Determinations Document July 22, 2002

70EPA has also concluded that flow reductions from the permittee’s Enhanced Multi-Mode proposal would be insufficient to minimize adverse impacts. Continued adverse effects from this option would be severe and would continue to prevent or inhibit a recovery of the Mount Hope Bay fishery.

7-172 7.7.4a Significance of Environmental Improvements from BTA Upgrades at BPS

EPA has determined that cooling water intake structure capacity limitations based on the Closed-Cycle Entire Station option are necessary to reflect the Best Technology Available for minimizing adverse environmental impacts. Among the practicable options that were considered, the Closed-Cycle Entire Station option achieves the greatest reduction in the number of individual organisms entrained and impinged by the BPS intakes. It also achieves the greatest reduction in the percentages of fish species populations lost to entrainment and impingement. Moreover, EPA has concluded that the major flow reductions associated with this option are needed to allow the Mount Hope Bay fishery to recover. EPA believes that the Closed-Cycle Entire Station option would not only greatly reduce adverse environmental impacts but it would remove the BPS cooling water intake structures as a major impediment to the recovery of the Mount Hope Bay fishery. (Other steps are also necessary, such as achieving major reductions in thermal discharges and, for the present time, continued fishing restrictions.) Although this option would not eliminate all adverse impacts, EPA believes that the remaining adverse effects would be insubstantial and that permit requirements based on this option would reflect the BTA for “minimizing” adverse environmental impacts as required by CWA § 316(b). 70

The Closed-Cycle Entire Station option also has the major “secondary” benefit of achieving large reductions in thermal discharges. These reductions should restore most of Mount Hope Bay to temperatures consistent with suitable habitat for the balanced indigenous community of aquatic life that should reside in the Bay. This will also be an important part of restoring the ecosystem to health.

Based on a qualitative evaluation, the environmental improvements to be obtained from the ClosedCycle Entire Station option are exceptionally significant and valuable. As discussed in more detail above, restoring the Mount Hope Bay fishery is an extremely important public goal for a number of reasons. It is consistent with the federal Clean Water Act’s goal of restoring and maintaining the biological, physical and chemical integrity of the Nation’s waters and rendering those waters suitable for the protection and propagation of fish and providing for recreation in and on the water. It is also necessary to achieve the designated uses and satisfy water quality criteria assigned to Mount Hope Bay and its tributaries by both the Commonwealth of Massachusetts and the State of Rhode Island.

In addition, the Mount Hope Bay estuary is an important component of the greater Narragansett Bay estuary. The Narragansett Bay estuary is a federally designated estuary of national environmentalMA0003654 Determinations Document July 22, 2002

7-173 significance under the National Estuary Program, and the Mount Hope Bay estuary should provide a productive nursery area for fish and other organisms. Moreover, the waters of the bay are designated Essential Fish Habitat for several species managed under the Magnuson-Stevens Act.

Nevertheless, due to depleted fish stocks in Mount Hope Bay, Massachusetts and Rhode Island have had to severely restrict or prohibit both commercial and recreational fishing in Mount Hope Bay. This has impacted people’s livelihoods and recreational opportunities and deprived the public of the beneficial use of the bay’s natural resources. This has no doubt caused people to have to travel further for fishing opportunities or pursue other forms of recreation. In addition, the City of Fall River has been required to undertake a $150 million dollar combined sewer overflow program, as well as sewage treatment plant improvements, in order to improve water quality and meet applicable requirements. Thus, the ecosystem of the Mount Hope Bay estuary is extremely important and the public has made significant, expensive sacrifices to improve the condition of the bay.

Meanwhile, the BPS cooling water intake structures annually kill trillions of organisms, including billions of fish eggs, fish larvae, and juvenile and adult fish. The intakes remove these organisms from the food web. Operation of the BPS cooling water intake structures has contributed to the collapse of Mount Hope Bay’s fishery and helped to prevent or inhibit its recovery. Marine organisms are being killed by the BPS cooling water intakes as a byproduct of making electricity. This is not a beneficial use of these organisms.

These adverse effects from the plant’s intake structures are avoidable. Installation of well-established, practicable cooling technologies at BPS can dramatically reduce these impacts, thus meeting the CWA § 316(b) standard of minimizing adverse environmental effects and facilitating the recovery of the Mount Hope Bay ecosystem. From a qualitative standpoint, these improvements are extremely valuable.

While a cost/benefit analysis is not required by CWA § 316(b), EPA also attempted to evaluate the benefits of improvements at BPS from a monetary perspective in order to provide additional information to consider in applying the wholly disproportionate cost test. Any such effort to monetize the value of environmental quality or natural resources will unavoidably suffer from significant weaknesses due to our present inability to fully and accurately quantify all the benefits flowing from ecological services, such as those that would be provided by a healthy ecosystem and fishery in Mount Hope Bay. As discussed above, recognition of this limitation is one of the reasons that Congress has not required application of cost/benefit analysis in determining requirements under a number of environmental statutes, just as it did not for CWA § 316(b).

One of the most difficult challenges is to try to estimate as fully and accurately as possible the non-use value to the public of such environmental resources. One method for determining non-use values for particular environmental resources is to conduct a site-specific “contingent valuation” study. However, designing and completing these studies can be extremely time-consuming and expensive. Despite theirMA0003654 Determinations Document July 22, 2002

7-174 cost in time and money, the results of contingent valuation studies can still be controversial. EPA had neither the time nor budget to undertake such an analysis in connection with this NPDES permit. Moreover, such expenditures for a contingent valuation study would be especially hard to justify when a cost/benefit analysis is not actually required.

Due to the above issues, EPA implemented several different approaches to estimating the value of the resources in question and developing relevant information for Agency consideration. Each of these analyses is discussed in detail in prior sections of this document. First, EPA undertook a “benefits transfer” analysis to estimate the use benefits of reduced impingement and entrainment losses at BPS. This somewhat conventional approach had several limitations, including that it was only able to account for the benefits of a small fraction of the fish that would be preserved by the technological improvements in question. Furthermore, this analysis also included only a crude estimate of the non-use value of the fish that could be saved. This estimate was based on the application of a “quick and dirty” “rule of thumb” to estimate aggregate non-use benefits in relation to recreational use benefits. For this analysis, EPA used the rule of thumb because it was preferable to ignoring non-use values entirely. Still, EPA believes that this rule of thumb approach does not reasonably capture the non-use value of the resources in question – at least in cases involving especially significant natural resources such as those within the Mount Hope Bay and Narragansett Bay estuarine ecosystem. As a result of these issues, and others, EPA concludes that use and non-use benefits from the “benefits transfer” analysis are likely to substantially underestimate the value of the resources in question. ( See Table 7.7-1 below.)

Second, in order to try to develop a more comprehensive and accurate estimate of the non-use value of the fishery resources at issue, EPA undertook an analysis based on developing a ratio of per-person recreational use value to non-use value. ( See Table 7.7-1 below.) Although this analysis is not a sitespecific contingent valuation study, EPA undertook a conservative analysis to review the likely reasonableness of the estimated values developed from the “per-person, non-use to recreational use benefit” ratio. This analysis developed annual benefit values on the basis of relatively simple and conservative assumptions about the potential population of households likely to value improvements to the affected aquatic resources and the potential annual benefit values per household. The resulting annual values fell in a range extending from a few million to over one hundred million dollars per year. ( See Table 7.6-3, above.) The values reported above for the “per-person, non-use to recreational use benefit” ratio method fall very much within this range. Therefore, these results provide support for the reasonableness and credibility of the per-person results. On balance, EPA concludes that the values estimated from the “per-person, non-use to use benefit” ratio are reasonable and credible and provide realistic, meaningful insight into the potential benefits of reduced intake flow at BPS and accompanying improvement in aquatic resources in Mount Hope Bay.

Third, EPA conducted a Habitat Replacement Cost (HRC) analysis using a method adapted from natural resource damages evaluations. The HRC analysis does not directly estimate the value of the natural resources in question. Rather, it calculates the cost of habitat restoration measures sufficient toMA0003654 Determinations Document July 22, 2002

71 Obviously, from an ecological and public policy perspective, it generally makes more sense to avoid the harm in the first place than to commit the harm and then hope that natural resource restoration projects will be sufficient to offset that harm, given that the success of such restoration projects is always uncertain.

72It should also be noted that USGenNE has conducted an analysis that appears to have resulted in figures even lower than the benefits transfer figures. (USGenNE reported the results of its analysis but did not submit the analysis itself.) This analysis appears not to have looked at non-use values.

7-175 replace the fish lost from the Mount Hope Bay estuary to the BPS intake structures. ( See Table 7.7-1 below.) For a variety of reasons, the HRC estimates are likely to underestimate the true costs of restoring the fish to Mount Hope Bay. Furthermore, undertaking such restoration efforts would clearly be futile as long as the BPS intakes continue to kill huge numbers of organisms from the bay and the BPS thermal discharge continues to render large areas of habitat unsuitable for various fish species.

Nevertheless, the HRC data is of significant interest for two reasons: (1) it provides an estimate of what it would cost society to try to restore the lost fish that can be compared to estimates of what it would cost the power plant to upgrade cooling system technology in order to avoid taking the fish in the first place; 71 and (2) there is some (albeit limited) information from cases in which both a total value analysis and an HRC analysis was conducted that suggests that the HRC values are likely to be lower than the total value results. The second point suggests that an HRC analysis – if used as a substitute for a total value analysis – would be unlikely to yield a figure greater than a total value estimate. Because the HRC approach may be cheaper and quicker to implement than a total value analysis, this suggests that the HRC method could provide a useful alternative analytical method that would provide “supply-side” numbers that would be unlikely to exceed the results of a “demand-side” total value analysis. In other words, the HRC analysis would be likely to produce conservative figures. This conclusion tends to be supported by a comparison of the above-discussed per-person non-use value estimates and the HRC figures. The latter are, indeed, lower than the former.

The above analyses have produced a wide range of figures. 72The figures presented in Table 7.7-1 below represent particular estimates of particular components of the value of, or cost of restoring, the fish that would be saved as a result of the approximately 96% flow reductions that would accompany the Closed-Cycle Entire Station option. It is important to remember that none of these estimates include any value for the “secondary” benefit that these cooling water intake improvements would have in terms of greatly reducing thermal discharges, which will also be important for restoring habitat quality in Mount Hope Bay. (This benefit is “secondary” only in the sense that thermal discharges are not the primary focus of CWA § 316(b)).

Table 7.7-1: Natural Resource Value and Restoration Cost Estimates Associated with the

Closed-Cycle Entire Station Option (all figures in Year 2002$)MA0003654 Determinations Document July 22, 2002

7-176 Technology % Flow

Reduction Benefits

Transfer (Use and Non-Use Value) Per-Person

Non-Use Value (New England) Per-Person

Non-Use Value (National) HRC

ClosedCycle Entire Station: 96% $240,853/yr. $36.4 million/yr. $119.5

million/yr. $28.9

million/yr.

7.7.4b Expense to USGenNE of Improvements

Both EPA and USGenNE prepared detailed estimates of the potential expense to the company associated with implementing various technological options at BPS. Despite the parties’ efforts to narrow areas of disagreement, our respective cost estimates vary considerably. Nevertheless, EPA believes our cost estimates are reasonable and appropriate.

EPA’s cost estimates are reasonably conservative and based on sound, careful evaluation. Our cost analyses were conducted in conjunction with expert consultants. Capital costs represent the largest source of variation in the estimates by EPA and the permittee. Yet, EPA conducted two different, independent analyses to develop capital cost estimates and both yielded similar and substantially lower figures than those estimated by USGenNE. To be conservative, EPA used the higher of our two independent capital cost estimates in our subsequent analyses. Apart from capital costs, there were also other areas of difference between the cost estimates of EPA and the company. These include areas such as the extent of cooling tower energy efficiency penalties, the extent of generating unit outages for cooling tower construction, and the discount rates used in the calculations. Again, EPA believes its analyses are reasonable and appropriate. These factors are discussed in more detail earlier in this document. In the table below, we have set forth certain relevant figures from EPA’s and USGenNE’s respective analyses related to the Closed-Cycle Entire Station option. This table is excerpted from Table 7.4-6 above.MA0003654 Determinations Document July 22, 2002

7-177 Table 7.7-2: Comparison of Selected USGenNE and EPA/Abt Cost Scenarios

Technology Option USGenNE 15% Discount Rate Figures (with calculation errors corrected by Abt) (over 20 years) 1 EPA/Abt Figures

(using 11.8 Discount Rate and other independent values) (over 20 years) EPA/Abt Figures (using 11.8 Discount Rate and other independent values) (over 30 years)

Closed-Cycle Entire Station 0% plume abatement 2
Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost:

100% plume abatement 3

Total After-Tax Cash Flow Cost, Present Value:

Annual Equivalent Cost: Not Calculated

Not Calculated

$254.485 Million

$40.657 Million $68.385 Million

$9.041 Million

$83.269 Million

$11.009 Million $67.975 Million

$8.314 Million

$85.803 Million

$10.494 Million

1 The USGenNE figures for the Closed-Cycle Entire Station option reflect the permittee’s capital costs and its assumptions for generating unit outages for water vapor plume abatement.

2 The Abt/EPA “0% plume abatement” figures reflect no generating unit outages for plume abatement, but do reflect the SAIC-estimated capital costs that were increased to reflect piping and pumping costs to allow the cooling towers to function in multi-mode fashion so that they could be bypassed if necessary to avoid generating unit outages for plume abatement.

3 The Abt/EPA “100% plume abatement” numbers reflect calculations including 100% of the plume abatement effect predicted by the permittee. However, these figures also reflect SAIC’s capital cost estimates without the upward adjustment to equip the cooling towers for potential multi-mode/bypass functioning.

Assuming a twenty-year equipment life, USGenNE estimated the Total After-Tax Cash Flow Cost, Present Value costs for the Closed-Cycle Entire Station option to be approximately $254 million, with an equivalent annual cost of approximately $41 million. However, also assuming a twenty-year equipment life, EPA estimated the Total After-Tax Cash Flow Cost, Present Value costs for the Closed-Cycle Entire Station option, assuming no plume abatement outages and increased capital costs to allow for bypass capability of the cooling towers, to be approximately $68 million, with an annual equivalent cost of approximately $9 million. Assuming a thirty-year equipment life, which EPA believes is more likely, the total costs are still approximately $68 million, but the equivalent annual cost drops to $8 million.MA0003654 Determinations Document July 22, 2002

73 Abt also concluded “on a very preliminary basis” that it would not expect the additional cost of air pollution controls to comply with recent Massachusetts regulations to “materially change the qualitative character of our findings.” Id . at p. 2, n. 3.

7-178 Based on the information available to us to date, EPA concludes that the cost of implementing the Closed-Cycle Entire Station option at BPS is economically practicable for the permittee. We believe this to be the case whether one considers the EPA costs with the zero percent or the 100 percent plume abatement economic effects scenario (and we believe the zero percent scenario is more likely). See May 20, 2002, Memorandum from Michael Fisher and Geoff Bennett, Abt Associates, Inc., to Mark Stein and Dave Webster, US EPA Region 1, “Subject: Financial Impact of Closed Cycle System Installation at Brayton Point Station - WITH CONFIDENTIAL BUSINESS INFORMATION EXCLUDED FROM TEXT AND TABLES.” We also believe it to be the case even if one considers the permittee’s costs estimates. Indeed, the permittee has not presented a financial impracticability argument to the regulatory agencies.

Nevertheless, EPA understands that the expenditures contemplated are significant and will cut into the permittee’s profits. See Id . at pp. 2, 7. These cooling intake improvements are necessary, however, to protect the public’s natural resources adequately under applicable law. Moreover, Brayton Point Station has long been a very profitable plant and will remain so after the improvements are installed. Id

. 73

7.7.4c Cost to Society of Undertaking Improvements at BPS

The above cost estimates were developed from the perspective of the power plant’s owner, USGenNE. These estimates consider the cost to the companyin terms of the estimated change in after-tax cash flow that would result from implementing a particular technology. Cash flows were presented in nominal dollars (i.e., without removing the expected effects of inflation) and were discounted to present value on the basis of an estimated weighted-average, after-tax, cost-of-capital for the company.

In applying the wholly disproportionate cost test, however, it is also appropriate to consider costs from the perspective of society (i.e., the “social costs”). To recast the costs of the Closed-Cycle Entire Station option within a social cost framework, EPA’s consultant, Abt Associates, Inc. (Abt), reviewed the earlier cost analysis to determine how it should be modified to reflect social costs. See May 9, 2002, Memorandum from Michael Fisher, Geoff Bennett, Abt Associates, to Mark Stein, Dave Webster, “Subject: Social Cost Analysis of Closed Cycle System Installation at Brayton Point Station.” For some cost elements (e.g., the capital cost of technology installation and annual maintenance costs), Abt concluded that the market prices estimated to be paid by the Company reasonably represent their “opportunity cost” to society. For other elements, however, a number of adjustments were needed to convert the private cost estimates to a social cost concept under which cost is measured in terms of opportunity costs to society. These adjustments included: (1) adjusting the value of Brayton PointMA0003654 Determinations Document July 22, 2002

7-179 Station production losses for construction outages, auxiliary energy requirements, and energy efficiency losses to reflect the electricity production cost of replacement generating capacity in the New England market, including provision for use of higher production cost capacity than would otherwise have been needed to meet electricity demand at the time of these production losses; (2) adjusting the cost savings from increased Brayton Point electricity production during high water temperature periods to reflect the electricity production cost of generating capacity that would be displaced by the increased availability of Brayton Point’s generating units, including recognition that marginal generating unit production cost may be somewhat less than the market clearing price for electricity at the time of these increased production events; (3) elimination of tax considerations from the cost analysis; (4) use of an estimated real (i.e., with the effect of expected inflation removed) social discount rate of 7 percent instead of the estimated cost-of-capital to USGenNE for calculating present value and equivalent annual costs; and (5) conversion of all cost values to a 2002 constant dollar basis (i.e., estimates of costs that exclude the effect of expected inflation).

On the basis of these adjustments, the estimated present value of the social cost for the Closed-Cycle Entire Station option, considering EPA’s cost estimate with no plume hazard abatement impact, is $119 million, assuming an equipment life of 20 years, and $122 million, assuming an equipment life of 30 years. These figures represent the present value of the costs calculated at mid-year 2002, at a discount rate of 7 percent, and in 2002 constant dollars. The corresponding equivalent annual costs for these values are $11.2 million and $9.8 million for the 20-year and 30-year equipment life cases, respectively. Assuming the full plume hazard abatement impact estimated by the permittee, the present value of the total cost increases to $157 million and $168 million for the 20-year and 30-year equipment life cases, respectively. The equivalent annual costs then increase to $14.9 million and $13.6 million, respectively, for the 20-year and 30-year equipment life cases. As noted in earlier discussions, EPA finds it unlikely that the plume-related generating unit outages predicted by USGenNE will be necessary. In addition, EPA also believes that the new equipment is more likely to have a 30-year useful life than the 20-year life proposed by the company. Accordingly, EPA believes the $9.8 million equivalent annual cost value is the more credible estimate of social cost for consideration. This figure is somewhat higher than the costs to the company estimated by EPA and presented in Table 7.7-2.

7.7.5 Additional Factors Considered

EPA has also considered certain other factors in applying the wholly disproportionate cost test. First, EPA investigated what effect the Closed-Cycle Entire Station option would have on consumer electric rates. “Impact of Thermal Discharge Management and Air Pollution Control Options for Brayton Point Station on New England Electricity Market and Consumer Rates” (Abt Associates, Inc., May 8, 2002). As a result of this analysis, EPA concludes that the effects will be relatively insignificant. The long-term rate effect to the typical 500 kWh per month consumer from increased production costs and slightly reduced generation as a result of the cooling system improvements is conservatively estimated to range from $0.03 per month to $0.13 per month. When possible BPS expenditures to comply with recent Massachusetts air pollution regulations are taken into account, the figures only rise to $0.09 toMA0003654 Determinations Document July 22, 2002

7-180 $0.38 per month.

EPA also conservatively estimates that generating unit construction outages would likely result in a short-term rate effect of $4.70 spread over 36 weeks (i.e., approximately $0.52/month for just 9 months) for the typical 500 kWh per month consumer. This short-term effect is not altered as a result of likely BPS improvements to comply with the new Massachusetts air quality regulations. The analysis also indicates that even these figures are likely an overestimate.

In addition, EPA has considered whether the improvements at BPS would have any significant adverse effect on the Region’s energy supply and, as discussed in more detail above, we have concluded that they will not. With these improvements, BPS can continue to generate approximately the same amount of electricity. Indeed, the new cooling technologies offer the benefit of enabling BPS to generate somewhat moreelectricity during hot weather peak demand periods when the Region’s energy supply is most stretched. Of course, it is important to note that short-term generating unit outages are likely to be needed for cooling system construction. EPA estimates that these outages could extend approximately three months beyond the regularly scheduled one month annual maintenance outages for each unit. This short-term effect will only occur for one unit at a time, and EPA and the MA DEP expect to work with USGenNE to schedule construction so that any necessary outages avoid peak electricity demand periods. Also, the new cooling technology will have no effect on the Region’s fueldiversity as it will not require any changes in BPS’s current fuel mix. Thus, neither the Region’s longterm nor short-term energy supply should be significantly affected by this permit decision.

Finally, while the cooling system improvements required to meet intake capacity limits reflecting the Closed-Cycle Entire Station option will clearly require significant expenditures by the permittee, it is also worth remembering that the owners of BPS have clearly reaped substantial economic benefit over the years from avoiding upgrading the once-through cooling system until this time. The once-through cooling system for Units 1, 2 and 3 was installed in the 1960's, prior to enactment of the Clean Water Act and the creation of EPA. Unit 4 was originally not permitted to operate in an open-cycle mode by the regulatory agencies due to concerns about the effects it might have on the Mount Hope Bay estuary, but the owners of the plant eventually convinced EPA and Massachusetts to authorize conversion to once-through cooling, which took place in 1984. We recognize that the BPS has not yet been required by the regulatory agencies to install closed-cycle cooling. However, it is worth noting, that EPA has estimated that (1) the benefit to the permittee of “delaying” the installation of the Closed-Cycle Entire Station option by one year from 2002 to 2003 is approximately $5.6 million; and (2) the benefit to the permittee of delaying the installation of the Closed-Cycle Entire Station for the four years from 1998 to 2002 is approximately $27.7 million (present value at mid-year 2002). May 14 2002, Memorandum from Michael Fisher, Abt Associates, Inc., to Mark Stein, EPA (Subject: Financial Benefit of Delayed Technology Implementation). If the analysis were run further back, the financial benefits to the owners of BPS would be even greater. EPA’s biological analysis indicates that closed-cycle cooling should have been installed years ago and that BPS’s open-cycle operations have significantly contributed to the collapse of the Mount Hope Bay fishery. The above economic analysis indicates that the owners ofMA0003654 Determinations Document July 22, 2002

7-181 the power plant have profited significantly from being able to avoid that expenditure for many years.

EPA also observes that the plant’s current owner, USGenNE, will almost certainly have prudently taken into account the expectation of capital outlays and additional operating expenses for cooling water system improvements as part of its due diligence for the acquisition of BPS. USGenNE acquired the plant in 1998 around the same time the current thermal discharge permit expired. This was also only shortly after major public controversy had erupted regarding the power plant’s contribution to the collapse of the Mount Hope Bay fishery and subsequent negotiation of the MOA II. In addition, there had been a long history of controversy regarding BPS operations, including permits in the 1970's that included thermal discharge limits based on water quality standards and required Unit 4 to operate with closed-cycle cooling. Therefore, it is inconceivable to EPA that the permittee would not have factored an expectation of potentially significant capital outlays and additional operating expenses into the estimated value of the plant at the time of purchase and reduced the offered purchase price accordingly. In effect, USGenNE will likely have established a “reserve liability” against the value of the plant in the anticipation of needing to make cooling water system upgrades. In short, the possible need to upgrade the cooling system at substantial expense was foreseeable and the plant’s owner will likely have planned for a substantial financial commitment on these matters.

7.7.6 Conclusions

Cooling water intake system capacity limitations of 56 MGD, with an additional 6,847 million gallons per year allowable for cooling tower by-pass, based on the Closed-Cycle Entire Station option, reflect the Best Technology Available for minimizing adverse environmental effects. In light of the above analysis, EPA concludes that the cost of the Closed-Cycle Entire Station option is not wholly disproportionate to the benefits it would produce. We believe this to be the case whether EPA’s cost estimates (including the social cost estimate) or the permittee’s cost estimates are considered, though we believe EPA’s estimates are more reasonable and should be used.

EPA concludes that there will be great benefits from upgrading BPS’s cooling system to utilize the wellestablished technology of mechanical draft wet cooling towers. Operation of the cooling water intake structure with the current open-cycle system has caused severe adverse environmental effects to the Mount Hope Bay estuary and, as a result, to the greater Narragansett Bay estuary of which it is a part. Severe adverse impacts are likely to remain from the options other than the Closed-Cycle Entire Station option. The Closed-Cycle Entire Station option, on the other hand, will dramatically reduce these adverse effects and give the fishery a chance to recover to a healthy state.

As discussed above in some detail, this will have major benefits in a qualitative sense. In addition, recognizing the uncertainties inherent in all the efforts to estimate the monetary value of the fishery resources that would be saved by the Closed-Cycle Entire Station option, EPA concludes that these estimates also indicate that there will be major benefits from this option. While one estimate (the benefits transfer analysis) produced an annual sum of approximately $240,853/yr. (Year 2002$), weMA0003654 Determinations Document July 22, 2002

7-182 have discussed how this estimate fails to account for a variety of important aspects of the total value of the resources and, therefore, must be regarded to be a significant underestimate. Meanwhile, another estimate of resource value (the “per-person recreational use/non-use analysis”) yielded a “New England estimate” of approximately $36.4 million/yr. (Year 2002$) and “a national estimate” of approximately $119.5 million/yr. (Year 2002$). These estimates are likely to be more accurate than the “benefits transfer analysis” results because the per-person analysis yields a more refined estimate of non-use value. EPA also conducted a conservative analysis to test the likely reasonableness of these estimates and found the estimates to be reasonable.

The per-person results are also supported by the HRC results, which were approximately $28.9 million/yr. (Year 2002$). (As discussed above, there is some information suggesting that HRC numbers will tend to be lower than a total value analysis and this tends to be confirmed by the “reasonableness analysis” discussed above.) Moreover, the HRC results indicate it would cost society more than $28 million per year to implement ecologically sound restoration projects to restore the number of fish lost to BPS’s cooling water intake structures, whereas the loss of these organisms could be prevented in the first place by implementing the Closed-Cycle Entire Station option at a lower or similar cost. And all of these estimates are likely to be underestimates because they are based on fishery data from 1974 - 1983, which does not reflect a healthy fishery unaffected by the plant, and because none of these estimates take into account any of the adverse effects of the BPS thermal discharge on the fishery. EPA also notes that making the proposed improvements at BPS would result in only a relatively small long-term increase in electric rates for the average household, with our conservative estimate placing the increase at between from $0.03 per month to $0.13 per month.

Finally, retrofitting BPS with the Closed-Cycle Entire Station option should not harm the Region’s overall energy supply and offers some potential benefits during the peak hot weather demand periods. The option is affordable for the permittee and, although it will reduce the value of the plant, the facility should continue to make substantial profits for the owners.

In conclusion, cooling water intake capacity limits of 56 MGD based on the Closed-Cycle Entire Station option reflect the Best Technology Available for minimizing adverse environmental impacts. The option is technologically and economically practicable and its costs are not wholly disproportionate to its benefits. It is also a necessary step, in conjunction with other measures being taken, to allow the recovery of the ecosystem of the Mount Hope Bay estuary and its fishery. We are bolstered in our conclusion by the knowledge that both the Commonwealth of Massachusetts and the State of Rhode Island share our view.MA0003654 Determinations Document July 22, 2002

8-1 

### 8.0 Final Permit Requirements for Thermal Discharge and Cooling Water Intake

Each time the permit is reissued, EPA must revisit its latest determinations under Sections 316(a) and (b) of the Clean Water Act. CWA Section 316(a) allows for variance-based limitations for thermal discharges if certain conditions are met, while CWA Section 316(b) governs cooling water intake requirements.

EPA’s determinations and supporting evaluations for setting thermal discharge and cooling water intake structure limits under CWA Sections 301, 316(a) and (b) for the Brayton Point Station NPDES permit are contained in this document . This document includes the biological, engineering, economic, legal and policy analyses upon which EPA’s final determinations are based. A brief summary of the conclusions and the resulting permit limitations are presented below.

It should be noted here that the existing permit contained narrative thermal conditions (see Part I.A.1.g of existing permit) that have been deleted from the draft permit. EPA believes that the removal of these narrative conditions is warranted because the proposed numerical draft permit conditions for heat and flow are sufficiently stringent to ensure that the previously contained narrative statements will not be violated. These narrative conditions were included in the prior permit due to unavoidable uncertainty regarding whether the numeric permit conditions would prove sufficient to satisfy the biological standards set forth in the narrative conditions. In other words, the narrative standards provided “backstop” permit conditions to ensure that the biological goals would be met. For the current permit, EPA is more confident that the new numeric permit conditions will meet the appropriate biological goals and, therefore, the narrative, backstop conditions are no longer needed.

8.1 Thermal Discharge Effluent Limitations: Technology-Based, Water Quality-Based, and Section 316(a) Variance-Based Limitations

In developing effluent limitations, EPA is to determine technology-based and water quality-based requirements, and whichever is more stringent governs the permit requirements. For thermal discharges, however, EPA may also consider granting a variance under Section 316(a) from eitheror both the technology-based and water quality-based effluent limitations if less stringent variancebased limitations will nevertheless be sufficient to “assure the protection and propagation of a balanced, indigenous population of shellfish, fish, and wildlife” (BIP) in and on the water body receiving the discharge. As a practical matter, EPA has with some permits simply jumped to developing permit limitations under a Section 316(a) variance if a set of limitations were determined to be sufficient assure protection and propagation of the BIP. In such cases, determining the technology-based and water quality-based limitations would serve no practical purpose. Similarly, in some cases, EPA has determined water quality-based conditions without determining the technology-based requirements, when we had reason to believe that it was clear that the water quality-based requirements would be more stringent than the technology-basedMA0003654 Determinations Document July 22, 2002

8-2 standards.

In this case, however, it was not clear to EPA which CWA requirements would drive the thermal discharge standards. Therefore, we have endeavored to determine technology-based limits and water quality-based limits, as well as to determine whether alternative limitations based on a CWA Section 316(a) variance would be warranted. The permittee has requested a variance pursuant to Section 316(a) and has proposed specific thermal discharge limitations that would apply under such a variance.

8.1.1 Technology-Based Limits

EPA has developed Best Available Technology Economically Achievable (BAT) thermal discharge limitations for BPS on a case-by-case basis using Best Professional Judgment (BPJ) pursuant to CWA § 402(a)(1), 33 U.S.C. 1342(a)(1), and 40 C.F.R. 125.3. This is because BAT requirements apply to thermal discharges and there is presently no applicable National Effluent Guideline for thermal discharges from steam electric facilities. For BPS, EPA has determined that thermal discharges consistent with closed-cycle cooling using mechanical draft cooling towers for Units 1, 2, 3 and 4 at BPS are required to satisfy the BAT requirements of the CWA. Some thermal discharge is still necessary to accommodate blowdown requirements. Therefore, EPA has set the following performance standard limitation based on this technology (including blowdown requirements):

Yearly Heat Load Discharged to Mount Hope Bay : 0.8 Trillion British Thermal Units

Daily Maximum Temperature : 85 °F

8.1.2 Water-Quality Based Limits

The Commonwealth of Massachusetts has developed water-quality based limits based on a mixing zone designed to protect the designated uses of the Massachusetts portions of Mount Hope Bay and satisfy other aspects of the Commonwealth’s water quality standards (including its mixing zone requirements). The resulting thermal limits from this mixing zone are:

Maximum Allowable Average Temperature(s) at Benthic Monitoring Locations within the Bay : 5 °C from February 12 - April 23, and 24 °C at all other times

Maintain Zone of Passage in the Lee River during Fish Migration Periods

No Discharge as needed to Allow for the Normal Migration of Striped Bass

At times, depending on background conditions, the mixing zone would allow only minimal or no discharge; at other times, however, the mixing zone would allow a discharge and for those times the mixing zone provides the following thermal discharge maximum limits to “cap” the allowedMA0003654 Determinations Document July 22, 2002

8-3 discharges: Monthly Maximum Heat Load to Mount Hope Bay : 1.2 Trillion BTUs per year

The submission of a nuisance species monitoring and prevention plan within 90 days of a final permit.

8.1.3 Thermal Discharge Limits Under Section 316(a) of the CWA

BPS has submitted a variance request which included legal, biological, financial, and technical information. EPA has reviewed this information, as well as other available information, and has determined that thermal discharge limits sufficient to allow for the protection and propagation of the BIP are as follows:

Yearly Heat Load to Mount Hope Bay : 1.7 Trillion British Thermal Units

Maximum Discharge Temperature : 95 o F

The above variance-based thermal discharge limitation being proposed for the new BPS permit is somewhat less stringent than the technology-based limits and it is likely to be less stringent than thewater quality-based thermal discharge limits as well. EPA has determined that the technologybased and, most likely, the water-quality based thermal limits are both more stringent than necessary to assure the protection and propagation of a balanced, indigenous population of shellfish, fish and wildlife in and on Mount Hope Bay. At the same time, however, EPA has also determined that the specific variance-based limits proposed by the permittee are not sufficient to assure the protection and propagation of the BIP. Therefore, although EPA is denying the specific variance-based limits proposed by the permittee, EPA is, nevertheless, granting a variance pursuant to Section 316(a) of the CWA from both the technology-based and water quality-based limits and is imposing alternative thermal effluent limits on BPS that will be sufficient to assure the protection and propagation of the balanced indigenous community of shellfish, fish, and wildlife in and on Mount Hope Bay. These variance-based limits are significantly more stringent than the limitations proposed by the permittee in its variance application.

Specifically, as indicated above, the permittee shall be required to meet a yearly heat load not to exceed 1.7 Trillion British Thermal Units. This heat load is somewhat higher than the above referenced technology-based limit of 0.8 TBTU/year. This 0.9 TBTU increase over entire station closed-cycle may allow some switching to once-through cooling, should conditions such as potential icing and/or fogging warrant it. EPA has calculated, based on a maximum station heat load of 7360 MBTU/hr (combined condenser duty of all 4 units operating), that the facility may operate approximately 122 hours per year in the once-through mode while meeting the proposed thermal limits. See below:

(0.16 x 10 12 BTU/yr)/(7.36 X 10 9 BTU/hr) = 122 hr/yrMA0003654 Determinations Document July 22, 2002

8-4 8.2 316(b), Cooling Water Intake Structures

CWA § 316(b) governs requirements related to cooling water intake structures (CWISs) and requires “that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.” EPA recently promulgated new, final § 316(b) regulations providing specific technology standard requirements for new power plants and other types of new facilities with CWISs. 66 Fed. Reg. 65255 (Dec. 18, 2001) (effective date of the regulations is January 17, 2002). These regulations do not , however, apply to existing facilities such as BPS. EPA has also issued proposed §316(b) regulations for existing power plants with flows of 50 million gallons per day or more (so-called “Phase II” facilities), such as BPS, but these regulations are not yet final. These proposed regulations are currently undergoing public review and comment, are subject to change, and are not to be applied to permits currently under development for existing plants. 67 Fed. Reg. 17122 (April 9, 2002). As a result, EPA continues the longstanding practice of applying § 316(b) on a case-by-case basis to existing facilities.

EPA has considered the nature and magnitude of the adverse environmental impacts from Brayton Point Station’s CWIS (namely, the entrainment and impingement of marine organisms) and has evaluated the technological options available for minimizing these impacts. EPA has also considered the costs of implementing these technological options.

While EPA is not authorized to directlyorder the installation of cooling towers, CWA § 316(b) does authorize EPA to impose a intake capacity (or flow) limit based on the permittee’s ability to meet that limit using the best technologies available, such as, for example, cooling towers. Such a technology-based limit imposes a performance standard for CWIS capacity (or flow) which the permittee should be capable of meeting using a particular technology but is permitted to meet in any manner it chooses.

EPA has determined that operation of BPS’s cooling water intake structures is causing severe adverse environmental impacts and that minimizing these impacts requires cooling water intake flow or capacity to be greatly reduced. EPA investigated a wide range of technology options and has determined that there is a practicable method of reducing cooling water flows by approximately ninety-five percent without substantially reducing the amount of electricity that BPS can generate. Specifically, this method is to retrofit mechanical draft closed-cycle cooling towers for the four major generating units at the power plant to replace the current open-cycle cooling system. EPA has concluded that without a change of this magnitude the fishery of Mount Hope Bay is unlikely to recover to a healthy state, but that with this change it has a good chance of doing so. While this technology will clearly be expensive for the permittee to implement, EPA has also determined that the costs of this option are not wholly disproportionate to its benefits. Therefore, EPA is imposing a capacity (flow) requirement consistent with this technology. The draft permit limits the withdrawal of water from Mount Hope Bay to 56 Million Gallons per Day (for cooling tower makeup water). The resulting discharge from outfall 001 is 39 Million Gallons per Day (cooling tower blowdown plus wastewater treatment plant flow, with the balance lost to evaporation).MA0003654 Determinations Document July 22, 2002

8-5 As with the thermal limit above, EPA has determined that allowing approximately 122 hours per year of operation in the once-through mode will not increase the facilities entrainment and impingement losses to a significant degree. Therefore, the draft permit allows an additional 6,847 million gallons of water withdrawal per year to allow the station to operate in the once-through mode. See below:

Once-through flow = 1347 million gallons/day x 1 day/24 hours = 56.125 million gallons per hour 122 hours/year of once-through flow allowed to meet thermal limit, so Annual increase = 56.125 million gallons/hr x 122 hr/yr = 6847 million gallons per year

This translates into approximately 5 days of operation in the once-through cooling mode, although EPA does not expect that the facility will actually need to switch to once-through cooling.

It should be clear that it will take a significant amount of time to implement this technology option. EPA and Massachusetts will work with the permittee to agree upon an enforceable, expeditious schedule for putting the technology in place taking into account site constraints, regional energy needs, and other factors.Literature Cited

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