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

2-1

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 mi2

 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 ft3

/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. Water
MA0003654 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 35.6o

 F, while the average monthly temperature in August is 75.2o 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 1.5o 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 and
MA0003654 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 than
MA0003654 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 (R2>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 Hope 

Bay 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, Conditions 

I.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 

3-1
 
MA0003654 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 

3-2
 
 

MA0003654 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. 

3-3
 
MA0003654 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 

3-4
 
MA0003654 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. 

3-5
 
MA0003654 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 (4th 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”).

4-1

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).3
MA0003654 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-based

limits), 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 in
MA0003654 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.”8 There

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 setting
MA0003654 Determinations Document July 22, 2002

11 See 40 C.F.R. § 125.3. See also NRDC v. EPA, 863 F.2d 1420, 1424-25 (9th 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 (5th 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 (5th 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.”12 
MA0003654 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 (9th 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.15 Here, 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 individual
MA0003654 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 (6th 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 (9th 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.19
MA0003654 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 be
MA0003654 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 (9th 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 (5th

Cir. 1989), citing Congressional 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.”25 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.”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 quality
MA0003654 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 (9th 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 (4th 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 (7th 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).28 These 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 not
MA0003654 Determinations Document July 22, 2002

which demonstrates that the level can be achieved or that there is

sufficient 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 (5th 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 (1st

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 (4th Cir. 1985) (“Congress contemplated that EPA might use technology from other

industries to establish the Best Available Technology.”). The Kennecott court 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 (4th 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 and
MA0003654 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.35 The 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.38 As 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 a
MA0003654 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 limits
MA0003654 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, citing CWA § 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 ....”45 The United States Supreme Court has

read these sections to mean that BAT should “represent ‘a commitment of the maximum
MA0003654 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.47 It

does not require a precise calculation of the costs of complying with BAT limits.48 Rather, 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.”49 Moreover, 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 “economically
MA0003654 Determinations Document July 22, 2002

50 CMA v. EPA, 870 F.2d at 250, citing CWA § 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 (3rd 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 test
MA0003654 Determinations Document July 22, 2002

53 E.g., Ass’n of Pacific Fisheries, 615 F.2d at 817, quoting 1972 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, citing CWA § 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” test
MA0003654 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.55 However, these courts affirmed

EPA’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.57 As one court concisely
MA0003654 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’n court 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, 95th 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.58
MA0003654 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.”59 When 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.63 
MA0003654 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.66
MA0003654 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 (10th 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.67 Its 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.69 In 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 the
MA0003654 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 then

presents 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 retrofitting
MA0003654 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 Stone
MA0003654 Determinations Document July 22, 2002

76 The baseline heat load to Mount Hope Bay from BPS currently peaks around

4x1012 [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

2x1012 (trillion) BTUs.76 EPA was not aware of these limitations on the permittee’s analysis prior
MA0003654 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.”77 In 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.78 Nevertheless, 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 Plants
MA0003654 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 steam
MA0003654 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.85 In 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.87 In addition, a number of plants use wet/dry cooling towers.88
MA0003654 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 in

accordance with CWA §§ 301(b)2) and 304(b)(2), EPA must determine which of these closedcycle cooling technologies, if any, is available for retrofitting specifically 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 air
MA0003654 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.95 They

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.97 For 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.99 In

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).100
MA0003654 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) with EPA 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 in
MA0003654 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.105 Indeed, 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 that

would 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.107 EPA 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.108 Therefore, 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 tower

technology. The permittee has proposed this alternative, which it calls “Enhanced MultiMode.”109 EPA believes the permittee has demonstrated technological ingenuity in developing
MA0003654 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 flow

reductions 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.112
MA0003654 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),

with December 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 not
MA0003654 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.117 The

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.118 In 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 as
MA0003654 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” Cooling
MA0003654 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.125 The 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 would
MA0003654 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.127 The overall effect on plant energy output would, of course, depend on the

extent to which generation was curtailed.128 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 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 wet
MA0003654 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.129 The 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 reductions
MA0003654 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.135 As discussed in detail in
MA0003654 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 the
MA0003654 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 block
MA0003654 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] determines
MA0003654 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 open
MA0003654 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 the
MA0003654 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 3
MA0003654 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 4.146
MA0003654 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 and

condenser, 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. Freeze

protection 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 a
MA0003654 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 +98
MA0003654 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 in
MA0003654 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.155 In 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.159
MA0003654 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 its
MA0003654 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 new

circulating 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 Unit
MA0003654 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 from
MA0003654 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.169 According 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 the

Unit 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 tunnel
MA0003654 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 the
MA0003654 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 460

feet 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.177 The existing discharge channel bottom would be dredged for the conduit, to allow
MA0003654 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 be
MA0003654 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-Mode
MA0003654 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.185 According 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 for
MA0003654 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.189 It arrived

at 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 Option
MA0003654 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.198
MA0003654 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.199 Then, 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 the

permittee 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 permittee

of 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 increased revenues 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 CWA
MA0003654 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 Costs
MA0003654 Determinations Document July 22, 2002

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

4-70

SAIC 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”).205 SAIC 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 of
MA0003654 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-Cycle
MA0003654 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 would

cause 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 Estimates
MA0003654 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 Entire

Station* (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 power
MA0003654 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).211
MA0003654 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 MultiMode25,278 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 outages

extending 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 cooling
MA0003654 Determinations Document July 22, 2002

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

214 See id., Attachment A.

215 Id., 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 any
MA0003654 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 MultiMode5.5 (broken into

different periods

for individual

units)

 0 5.5 (broken into

different periods

for individual

units)

 0
MA0003654 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-Cycle

Entire 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 understated in all years of the analysis, and the
MA0003654 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 summer
MA0003654 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 the
MA0003654 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 a
MA0003654 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 abatement2

Total After-Tax Cash

Flow Cost, Present

Value: 

Annual Equivalent Cost: 

50% plume abatement3

Total After-Tax Cash

Flow Cost, Present

Value: 

Annual Equivalent Cost: 

100% plume abatement4

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 Million
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)

4-90

Closed-Cycle Entire

Station Units

0% plume abatement2

Total After-Tax Cash

Flow Cost, Present

Value: 

Annual Equivalent Cost: 

50% plume abatement3

Total After-Tax Cash

Flow Cost, Present

Value: 

Annual Equivalent Cost: 

100% plume abatement4

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)

TechnologyOption 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

 $51,470,000
MA0003654 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 Thousand1 - $111 Thousand1

Closed-Cycle Unit 3

0% Plume Abatement3

50% Plume Abatement4

100% Plume Abatement5

$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 Abatement3

50% Plume Abatement4

100% Plume Abatement5

$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.

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

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 Million1- $30.212 Million1- $33.405 Million1 

Cost of Plume

Abatement $0 $0 $0 

Total of Annual

Expenses, After Tax -$11.879 Million1- $19.246 Million1- $21.232 Million1 

Present Value Total

After-Tax Cash Flow $38.233 Million $1.077 Million - $909 Thousand1 

Equivalent Annual Cost

 $6.108 Million $142 Thousand - $111 Thousand1 

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 Value

Total 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 Value

Total 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 penalties
MA0003654 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.225 The 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, the
MA0003654 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.227 If 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.228 In 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 Impacts
MA0003654 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 visual
MA0003654 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.235 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, 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.237 Under such conditions, fogging from the cooling
MA0003654 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.”239 It 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 each
MA0003654 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.”248 This relates, at

least in part, to the permittee’s predictions of plume outages for the unit-specific options but not
MA0003654 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) with Abt 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.249 For 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 overall
MA0003654 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 overall

efficiency 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.255 This 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.258 According 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.259 Thus, 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 icing
MA0003654 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 before it 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.265 The 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 five
MA0003654 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.268 The 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.269 The 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 less
MA0003654 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.273
MA0003654 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 for
MA0003654 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).275 EPA 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.”278 No concern
MA0003654 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 the

discharge canal and further away from the highway and bridge than the multi-mode or closedcycle alternatives.”279 The 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 background

conditions. 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 this
MA0003654 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 the
MA0003654 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.285 Any 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 the

units 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 outages

based 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.288 It 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 and
MA0003654 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 of
MA0003654 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, and
MA0003654 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 at

other existing power plants. Ultimately, however, EPA determined that the Enhanced MultiMode option could not be the “best” available technology because it achieves far lower thermal
MA0003654 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.’”295 
MA0003654 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 abatement2

Total After-Tax Cash

Flow Cost, Present

Value: 

Annual Equivalent Cost: 

100% plume abatement3

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 °F296, 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 forbid
MA0003654 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 the
MA0003654 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 with the 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 (1st 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 such
MA0003654 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 (1st 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 (5th 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 standards
MA0003654 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). The
MA0003654 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 quality
MA0003654 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 18.3o

 C (65o F);

2. May 15 - May 31: water temperature maximum shall not equal or exceed an hourly

average of 20o

 C (68o F);

3. June 1 - June 7: water temperature maximum shall not equal or exceed an hourly

average of 21.1o

 C (70o F);

4. June 8 - June 23: water temperature maximum shall not equal or exceed an hourly

average of 26.7o

 C (80o F);

5. June 24 - July 7: water temperature maximum shall not equal or exceed an hourly

average of 27.9o

 C (82.2o F);

6. July 8 - October 31: water temperature maximum shall not equal or exceed an hourly

average of 28.9o

 C (84.1o 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 5o

 C. For the rest

of the year the facility’s discharge must not contribute to benthic layer water temperatures

exceeding 24o

 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)

Determination
MA0003654 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 Context
MA0003654 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 the
MA0003654 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., 1st 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).3
MA0003654 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 BIP
MA0003654 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 the
MA0003654 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 (4th 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 would
MA0003654 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 effluent
MA0003654 Determinations Document July 22, 2002

5

 Senator 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 (7th 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 Muskie5 stated 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 so
MA0003654 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 application
MA0003654 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: 95o

 F 95o F

Delta Temperature: 22o

 F 22o/30o 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 connection
MA0003654 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; or
MA0003654 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 of
MA0003654 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, or 
MA0003654 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 the
MA0003654 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; and
MA0003654 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 for

Narragansett 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 0.8o

 C greater than the controls. Cool tanks were held at 2o 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 7o

 C at the
MA0003654 Determinations Document July 22, 2002

6-23

beginning of the experiment in December to 3o 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 0.8o

 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 km2

 (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 )0.8o

 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 )0.8o

 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 dominant
MA0003654 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. leidyi has 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. leidyi can 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. leidyi is 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 Mount
MA0003654 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 35o

 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 5o

 C, thus

representing the point of maximum growth. At temperatures above 30o

 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, 30o

 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 35o C at light saturation to 5o

 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 chronic
MA0003654 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 Company
MA0003654 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 95o , 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

TBTUs1

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 predictive
MA0003654 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 Representative
MA0003654 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 was
MA0003654 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 30.2o

 C

(64-86.4o

 F). At 26.9o C (80.4o F), feeding and swimming activity decreased. Feeding and

swimming activity further decreased at 28.1o

 C (82.6o) and sharply fell off at 29.3o C (84.7o F). 

USGenNE then chose the midpoint between 28.1 and 29.3o

 or 28.7o 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 35o

 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 25o

 C, though this may be physiologically less

favorable. Thus, as the authors of the study question, the ecological relevance of 35o

 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” biothermal
MA0003654 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 larvae

from 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 6.3-3 
MA0003654 Determinations Document July 22, 2002

6-35

show that adult flounder abundance drops to nearly zero above 15o C and

juvenile abundance declines in a similar fashion above 24 or 25o

 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 24o

 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 22.2o

 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 22.2o

 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 20so

 C and result in complete avoidance of the

area by 24 or 25o

 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 5o

 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 of

temperature 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 2o

 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 1.0o

 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 1o

 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 1o 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 1o

 C above

(warm) the long term water temperature average and at 2o 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 3o C) systems and predators dramatically

reduce winter flounder larval abundance. We are presently unable to predict or even identify all
MA0003654 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 24o

 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 22o

 C. Grace Klein-MacPhee, a flounder

expert at the University of Rhode Island, stated that sublethal effects begin at 20o

 C (MA

DEP, 2002). EPA selected 24o

 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 3o

 C resulted in 100%

viability of eggs. At 5o

 C, egg viability was reduced to 83.5 % and at 10o C, egg

viability was only 50%. Rogers (1976) found no viable eggs at 15o

 C. Keller and KleinMacPhee (2000) found an over 90% hatching rate at an average incubation temperature

of 1.86o

 C and an approximately 75% hatching rate at an average incubation temperature

of 5.11o

 C. EPA selected 5o 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 10o

 C would be likely to interfere with the recovery of the winter

flounder population in Mount Hope Bay. Therefore EPA selected 5o

 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 8o

 C as best
MA0003654 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 12o

 C, but their survival and growth is

reduced. Given the depleted state of the winter flounder population in Mount Hope Bay,

EPA believes the 8o

 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 (24o

 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 24o

 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

24o

 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 24o

 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 24o C in Warm Summer Conditions

Scenario % Volume < 24o

 C % Volume > 24o C

1 to 4 days

% Volume > 24o C

> 5 days

MOA II1

 14 11 75

EMM2

 20 18 62

Hypo B3

 32 13 55

Hypo A4

 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 25o C. The

Enhanced Multi-Mode option exceeds 25o

 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 25o

 C. For Hypothetical A, only 5% of the surface water volume

exceeded 25o 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 25o

 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 25o

 C . For Hypothetical

A, less than 1% of the middle water volume exceeded 25o

 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 25o

 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 25o C

Scenario % Volume < 25o C % Volume > 25o C

1 to 4 days

% Volume > 25o C

> 5 days

MOA II1

 7 17 76

EMM2

 30 29 41

Hypo B3

 53 16 21 

Hypo A4

 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 25o C in Warm Summer Conditions

Scenario % Volume < 25o

 C % Volume > 25o C

1 to 4 days

% Volume > 25o C

> 5 days

MOA II1

 36 24 40

EMM2

 65 17 18

Hypo B3

 77 14 9

Hypo A4

 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 5o

 C under all modeling scenarios. Ninety

percent of the bay exceeded 5o

 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. They
MA0003654 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 5o

 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 5o

 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 5o

 C threshold with more regularity than

Hypothetical A. None of the operating scenarios exceeded 10o 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 5o C in Warm Winter Conditions

Scenario % of volume < 5o

 C % Volume > 5o C

1 to 4 days

% Volume > 5o C

> 5 days

MOA II1

 0 0 100

EMM2

 0 0 100

Hypo B3

 0 0 100

Hypo A4

 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 8o

 C (Table 6.3-6). For all

other scenarios, essentially 100% of the surface water volume does not exceed 8o

 C. For all

operating scenarios, virtually 100% of the middle water volume remains below 8o

 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 8o C in Warm Winter Conditions

Scenario % of volume < 8o

 C % Volume > 8o C

1 to 4 days

% Volume > 8o C

> 5 days

MOA II1

 81 18 1

EMM2

 91 9 0

Hypo B3

 99 1 0

Hypo A4

 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 8o C in Warm Winter Conditions

Scenario % of volume < 8o

 C % Volume > 8o C

1 to 4 days

% Volume > 8o C

> 5 days

MOA II1

 91 8 1

EMM2

 98 2 0 

Hypo B3

 100 0 0

Hypo A4

 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 by
MA0003654 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 10o

 C isotherm
MA0003654 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 natural
MA0003654 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 length
MA0003654 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 to
MA0003654 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 concentrations

in 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; and
MA0003654 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, several 
MA0003654 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 24o

 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 suggest
MA0003654 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 95o

 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 its
MA0003654 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., 1st Session,

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 permit
MA0003654 Determinations Document July 22, 2002

2

 See Virginia Electric & Power Corp. v. Costle, 566 F.2d 446, 448-51 (4th Cir. 1977);

United States Steel Corp. v. Train, 556 F.2d 822, 850 (7th Cir. 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). 

4

 EPA 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 new facilities 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 306.2 The 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 (4th Cir. 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 also 66 Fed. Reg. 65261 (Dec. 18, 2001)
MA0003654 Determinations Document July 22, 2002

7

 United States Steel Corp. v. Train, 556 F.2d 822, 850 (7th Cir. 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 (4th

Circuit),” p. 3. See also 40 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 (5th Cir. 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, see 66 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 of
MA0003654 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 (2nd Ed.

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 BTA
MA0003654 Determinations Document July 22, 2002

9

 Consistent with this understanding, the American Heritage Dictionary (2nd Ed.) (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 any

plant 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 the
MA0003654 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 also 65 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 (5th Cir. 1998);

Association of Pacific Fisheries v. Environmental Protection Agency, 615 F.2d 794, 816-17 (9th Cir.

1980); American Meat Institute v. E.P.A., 526 F.2d 442, 462-63 (7th Cir. 1975). 

12 These 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 (5th Cir. 1988); Pacific

Fisheries, 615 F.2d at 816-17; BASF Wyandotte Corp. v. Costle, 614 F.2d 21, 22 (1st Cir. 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 (2nd 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.12 This 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-burning
MA0003654 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. 

14 In one sense, one can think of a technology used at a new power 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 actually be 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 any adverse

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 Hampshire does 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 also 41 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 See
MA0003654 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 also May 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 (see pp. 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 magnitude of the adverse

impact. See also EPA 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.17 
MA0003654 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 one of

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 (1st Cir. 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 (2nd Ed.) (1982). See also 41 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. (Seabrook
MA0003654 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 mentioned
MA0003654 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 any

plant 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 (1st
MA0003654 Determinations Document July 22, 2002

20 Again, 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 application
MA0003654 Determinations Document July 22, 2002

22

 See, e.g., Chemical Manufacturers Association v. U.S. E.P.A., 870 F.2d 177, 203-04 (5th

Cir. 1989); Eli Lilly and Company v. Costle, 598 F.2d 638, 656 (1st Cir. 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.22 Nevertheless, 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.24 Presumably,

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 (9th Cir. 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 (4th Cir. 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 with other 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 two
MA0003654 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 face
MA0003654 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 to
MA0003654 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 1976
MA0003654 Determinations Document July 22, 2002

30 The 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.

32 The 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.30 EPA 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.32 The 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 directly order 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.34 What

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 a
MA0003654 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 whole so 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

both components, 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 discussion
MA0003654 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 2x1012 [trillion]

BTUs. (Nb., The baseline heat load to Mount Hope Bay from BPS currently peaks around

4x1012 [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 or
MA0003654 Determinations Document July 22, 2002

7-33

recirculating 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 of

alternatives 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 to
MA0003654 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. Compare January 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 4 vs. $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, see pp. 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 offer
MA0003654 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, see 39 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 the

quality 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 39,000
MA0003654 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 the
MA0003654 Determinations Document July 22, 2002

7-40

permittee. It also potentially could 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, see SAIC 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); and 
MA0003654 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 (37

cells) 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 would
MA0003654 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

42 USGenNE’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.42 
MA0003654 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 also EPA 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 permittee
MA0003654 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. Under 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 before it 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 648 hours 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 order
MA0003654 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 also 66 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 Service
MA0003654 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, see Vol. 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 to
MA0003654 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.43 
MA0003654 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 also Executive

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. It

should 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, see December 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-mode

options. 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, see December 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 is
MA0003654 Determinations Document July 22, 2002

44 Interestingly, 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 shifting

entirely 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 benefit provided 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 explained
MA0003654 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), see 310 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 have

roughly 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 Towers for

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 are
MA0003654 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 decided
MA0003654 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 this
MA0003654 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 information

suggesting 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 modified
MA0003654 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 of

the 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 on
MA0003654 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 USGenNE
MA0003654 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 as
MA0003654 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 of

biofouling. 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 relates
MA0003654 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 depends

on 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 impingement

of 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 these
MA0003654 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 in

Combination 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

survival
MA0003654 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 (1st Cir. 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 subcontract
MA0003654 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 to

determine 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 information
MA0003654 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. 

50 Actually, 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,50 and 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 is
MA0003654 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 unit

conversion 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/ice
MA0003654 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 million
MA0003654 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 higher
MA0003654 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 following
MA0003654 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 Penalty

Estimate (MWHrs/year)

SAIC/EPA

Independent

Efficiency Penalty

Estimate (MWHrs/year)

Percent

Difference in

USGenNE and

SAIC/EPA MWHr/year Estimates

SAIC/EPA

Independent

Efficiency Penalty

Estimate

Converted to

$/year*

Enhanced MultiMode25,278 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
MA0003654 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 more electricity 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 detailed
MA0003654 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 MultiMode5.5 (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 station
MA0003654 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 the
MA0003654 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 the

financial/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 station

options 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 concluded

that 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 that
MA0003654 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 abatement2

Total After-Tax Cash

Flow Cost, Present Value: 

Annual Equivalent Cost: 

50% plume abatement3

Total After-Tax Cash

Flow Cost, Present Value: 

Annual Equivalent Cost: 

100% plume abatement4

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 Million
MA0003654 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 abatement2

Total After-Tax Cash

Flow Cost, Present Value: 

Annual Equivalent Cost: 

50% plume abatement3

Total After-Tax Cash

Flow Cost, Present Value: 

Annual Equivalent Cost: 

100% plume abatement4

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

 $51,470,000
MA0003654 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 Thousand1- $111 Thousand1

Closed-Cycle Unit 3

0% Plume Abatement3

50% Plume Abatement4

100% Plume Abatement5

$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 Abatement3

50% Plume Abatement4

100% Plume Abatement5

$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 Million1- $30.212 Million1- $33.405 Million1 

Cost of Plume

Abatement $0 $0 $0 

Total of Annual

Expenses, After Tax -$11.879 Million1- $19.246 Million1- $21.232 Million1 

Present Value Total

After-Tax Cash Flow $38.233 Million $1.077 Million - $909 Thousand1 

Equivalent Annual

Cost $6.108 Million $142 Thousand - $111 Thousand1 

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

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 Value

Total 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

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 Value

Total 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

52 Memorandum 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 in2

. 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. From
MA0003654 Determinations Document July 22, 2002

7-105

May through October, fixed screens with a mesh of 1.5 in2 are 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 the

conservative 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 II1 EMM2 Unit 3 CC3 All units CC3

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 21
MA0003654 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

2

 USGenNE’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. To
MA0003654 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 II1 EMM2 Unit 3 CC3 All units CC3

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 18
MA0003654 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 being

impinged 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 II1 EMM2 Unit 3 CC3 All units

CC3

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 14,816
MA0003654 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

2

 USGenNE’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 II1 EMM2 Units 3 CC3 All Units

CC3

Atlantic

menhaden

15,625 15,614 8,543 9,094 882

Bluefish 0 0 0 0 0

Scup 554 628 292 320 34
MA0003654 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

2

 USGenNE’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 II1 EMM2 Unit 3 CC3 All Units

CC3

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 0
MA0003654 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

2

 USGenNE’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 1993
MA0003654 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 II1 EMM2 Unit 3 CC3 All Units

CC3

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

2

 USGenNE’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 Point
MA0003654 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 km2). 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 km2 represents 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 methodology
MA0003654 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 and

Deegan (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 that
MA0003654 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 the
MA0003654 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 II1 EMM2 Unit 3 CC3 All Units CC3

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

2

 USGenNE’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 the
MA0003654 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, but
MA0003654 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 II1 3,343 82,764,440 82,767,783

EMM2 2,211 54,741,834 54,744,045

Unit 3 CC32,246 55,617,704 55,619,950

Whole plant CC3 134 3,312,155 3,312,289

1

 Memorandum of Agreement II signed between EPA, MA DEP, RI DEM and NEP

2

 USGenNE’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-Mode
MA0003654 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 Options 
MA0003654 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 are
MA0003654 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 and
MA0003654 Determinations Document July 22, 2002

54 In 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

7-130

suitability 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 (4th Cir. 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 the
MA0003654 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 becoming

remote 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 sewage
MA0003654 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 in
MA0003654 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., 4th
MA0003654 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 also
MA0003654 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 each

has 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 F4-2

and 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 have
MA0003654 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 survey
MA0003654 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 of
MA0003654 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 options

that 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 in

decline. 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, it
MA0003654 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 such

questions 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 also Figures 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 decade
MA0003654 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 the
MA0003654 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 that

would 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, to

Mark 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 the
MA0003654 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 reduced
MA0003654 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 a
MA0003654 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 of

underestimate 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 also Revised 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 be
MA0003654 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. 

60 This 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 also May 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 (11th Cir. 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 Great
MA0003654 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 natural
MA0003654 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 a

cost-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 analogy to 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 also May 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 the
MA0003654 Determinations Document July 22, 2002

62 It 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. F5-2.62 Cost-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 that
MA0003654 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 to
MA0003654 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.64 We 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, any
MA0003654 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 provides

support 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, see April 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-Mode

option; $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 [to
MA0003654 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 of
MA0003654 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 and

continue 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 the
MA0003654 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 cases
MA0003654 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 the
MA0003654 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 the
MA0003654 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 generating
MA0003654 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

70 EPA 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 environmental
MA0003654 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 their
MA0003654 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 to
MA0003654 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.

72 It 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.72 The 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 abatement2

Total After-Tax Cash

Flow Cost, Present Value: 

Annual Equivalent Cost: 

100% plume abatement3

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 company in 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 Point
MA0003654 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 to
MA0003654 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 more electricity 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 fuel

diversity 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 of
MA0003654 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 $240,853/yr. (Year 2002$), we
MA0003654 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 either

or 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-based
MA0003654 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 allowed
MA0003654 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: 95o 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 the

water 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 1012 BTU/yr)/(7.36 X 109 BTU/hr) = 122 hr/yr
MA0003654 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 directly order 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 

Able, K.W. and M.P. Fahay. 1998. The First Year in the Life of Estuarine Fishes in the Middle 

Atlantic Bight. Rutgers University Press, New Brunswick, New Jersey, 342 pp. 

Berman, M. 2001. Pers. Comm. to Phil Colarusso (November 2001). 

Buckley, L.J., A.S. Smigielski, T.A. Halavik and G.C. Laurence. 1990. Effects of water 

temperature on size and biochemical composition of winter flounder Pseudopleuronectes 

americanus at hatching and feeding initiation. Fishery Bulletin, Vol. 88, pp. 419-428. 

Bulthuis, D.A. 1987. Effects of temperature on photosynthesis and growth of seagrasses. Aqu. 

Bot., Vol. 27, pp. 27-40. 

Callaghan, T. 2002. Pers. Comm. to Phil Colarusso (May, 2002). 

Casterlin, M.E. and W.W. Reynolds. 1982. Thermoregulatory behavior and diel activity of 

yearling winter flounder, Pseudopleuronectes americanus (Walbaum). Env. Biol. Fish. Vol. 7, 

No. 2, pp 177-180. 

Chinman, R.A. and S.W. Nixon. 1985. Depth-area-volume relationships in Narragansett Bay. 

NOAA/Sea Grant Marine Technical Report 87. Graduate School of Oceanography, the 

University of Rhode Island 

Cicchetti, G. 2001. Pers. Comm. to Phil Colarusso (October 2001). 

Colarusso, P. 2002. Personal observation on February 14, 2002. 

Collie, J.S. and A.K. DeLong. June 26, 2001. Examining the decline of Narragansett Bay winter 

flounder. Year 1 Progress Report to RI DEM Division of Fish and Wildlife. 

Coutant, C.C. and D.L. Benson. 1990. Summer habitat suitability for striped bass in Chesapeake 

Bay: reflections on a population decline. Trans. of the Amer. Fish. Soc., Vol. 119, pp 757-778. 

Coutant, C.C. and M.S. Bevelhimer. February 12, 2001. Comments on Lawler, Matusky & 

Skelly Engineers, LLP. 1999 draft. Brayton Point Power Plant Entrainment Survival Study 

1997-1998. Report for US Gen New England, Inc. Pearl River, New York. Environmental 

Sciences Division, Oak Ridge National Laboratory. 

Crawford, R.E. and C.G. Carey. 1985. Retention of winter flounder Larvae within a Rhode 

Island Salt Pond. Estuaries, Vol. 8, No. 2B, pp 217-227. 

Deacutis, C. 2002A. Pers. Comm. to Phil Colarusso (April 2002). 

Deacutis, C. 2002B Pers. Comm. to Phil Colarusso (February 2002). 
DeHart, R.E. 1997. April 8 letter to Jane Downing response to EPA §308 information request. 

EPA. 2000. Ambient Aquatic Life Water Quality Criteria for Dissolved Oxygen (Saltwater): 

Cape Cod to Cape Hatteras. EPA-822-R-00-012. 

Fogarty, M.J. and S.A. Murawski. 1998. Large-scale disturbance and the structure of marine 

systems: fishery impacts on Georges Bank. Ecological Applications, Vol. 8(1) Supplement, pp 

S6-S22. 

Franz, D.R. and J.T. Tanacredi. 1992. Secondary production of the amphipod Ampelisca abdita 

Mills and its importance in the diet of juvenile winter flounder (Pleuronectes americanus) in 

Jamaica Bay, New York. Estuaries, Vol. 15, No. 2, pp 193-203. 

Gibson, M.R. 1996. Comparision of trends in the finfish assemblage of Mt. Hope Bay and 

Narragansett Bay in relation to operations a the New England Power Brayton Point Station. RI 

Division Fish and Wildlife Research Reference Document 95/1. Revised August 1996. 

Gibson, M.R. 2001. 10/3/2001 Letter to Phil Colarusso on Winter Flounder Regulations in 

Rhode Island. 

Gibson, M.R. 2002A. Winter Flounder Abundance Near Brayton Point Station, Mt. Hope Bay 

Revisted: Separating Local from Regional Impacts using Long Term Abundance Data. RI 

Division of Fish and Wildlife Research Reference Document 02/1. 

Gibson, M.R. 2002B. Scaled winter flounder population estimate from MRI trawl survey data. 

Gibson, M.R. 2002C. Ex-vessel value of fishery production foregone in Mount Hope Bay as a 

result of operations at USGEN of New England’s Brayton Point Station. RI Division of Fish and 

Wildlife Research Reference Document 02/2. 

Haas, G. 2002. May 16 MA DEP letter to EPA, Office of Ecosystem Protection Director Linda 

Murphy reviewing Brayton Point Station Variance Request Application 

Houlihan, D. 2002. 5/7/02 Memo to Phil Colarusso. Calculation of heat addition to Mount Hope 

Bay caused by the long term temperature rise. 

Isaac, R.A. 1997. Estimation of nutrient loadings and their impacts on dissolved oxygen 

demonstrated at Mount Hope Bay. Env. Int. Vol. 23, No. 2, pp. 151-165. 

Keller, A.A., C.A. Oviatt, H.A. Walker and J.D. Hawk. 1999. Predicted impacts of elevated 

temperature on the magnitude of the winter-spring phytoplankton bloom in temperate coastal 

waters: A mesocosm study. Limnol. Oceanogr., Vol. 44(2), pp 344-356. 

Keller, A.A. and G. Klein-MacPhee. 2000. Impact of elevated temperature on the growth 

survival, and trophic dynamics of winter flounder larvae: a mesocosm study. Can. J. Fish. 

Aquat. Sci., Vol. 57, pp 2382-2392. 
Keller, A.A., G. Klein-MacPhee and J. St.Onge Burns. 1999. Abundance and distribution of 

ichthyoplankton in Narragansett Bay, Rhode Island, 1989-1990. Estuaries, Vol. 22, No. 1, pp 

149-163. 

Ketschke, B.A. 1999. September 17 letter to Dave Webster reporting unusual fish impingement 

event. 

Ketschke, B.A. 2000. January 13 letter to Dave Webster reporting unusual fish impingement 

event. 

Ketschke, B.A. 2002.February 11 and March 7 letters to Dave Webster reporting unusual fish 

impingement events. 

Krahforst, C. 2001. Pers. Comm. to Phil Colarusso (December 2001). 

Lawton, B. 2001. July 30 letter to Phil Colarusso detailing fishing restrictions in Massachusetts 

portion of Mount Hope Bay. 

Link, J.S. 2002. Ecological considerations in fisheries management: when does it matter?. 

Fisheries, Vol. 27, No. 4, pp 10-17. 

Lynch, T.R. 2000. Assessment of recreationally important finfish stocks in Rhode Island waters: 

coastal fishery resource assessment trawl survey. Rhode Island Division of Fish and Wildlife. 

Report # F-61-R-8. 

Marsh, J.A., W.C. Dennison and R.S. Alberte. 1986. Effects of temperature on photosynthesis 

and respiration in eelgrass (Zostera marina L.). J. Exp. Mar. Bio. Ecol., Vol. 101, pp 257-267. 

Meng, L. and J.C. Powell. 1999. Linking juvenile fish and their habitats: an example from 

Narragansett Bay, Rhode Island. Estuaries, Vol. 22, No. 4, pp 905-916. 

Mustard, J.F., C.Swanson and C. Deacutis. 2001. Final Report: Narragansett Bay from Space: a 

Perspective for the 21st Century. NAG-13-39. 80 pp. 

NEP. 1997. New England Power meeting handout on water quality monitoring results. 

NEP. 1998. New England Power Company Response to US EPA Information Request, May 26, 

1998. 

NMFS.1995. Status of the fishery resources off the northeastern United States for 1994. NOAA 

Technical Memorandum NMFS-F/NEC-101. 

NMFS. 1999. Our Living Oceans. Report on the status of U.S. living marine resources, 1999. 

U.S. Dep. Commer., NOAA Tech. Memo. NMFS-F/SPO-41, on-line version, 

http://spo.nwr.noaa.gov/olo99.htm. 
Olla, B.L., R. Wicklund, S. Wilk. 1969. Behavior of winter flounder in a natural environment. 

Trans. Amer. Fish. Soc. No. 4, pp 717-720. 

Oviatt, C.A. 1994. Biological Considerations in Marine Enclosure Experiments: Challenges and 

Revelations. Oceanography, Vol. 7, No. 2, pp 45-51. 

Pereira, J.J., R. Goldberg and J.J. Ziskowski. August 1998. Winter Flounder, 

Pseudopleuronectes americanus (Walbaum), Life History and Habitat Characteristics. Essential 

Fish Habitat Source Document, pp 1-39. 

Phelan, B.A., R. Goldberg, A.J. Bejda, J. Pereira, S. Hagan, P. Clark, A.L. Studholme, A. 

Calabrese and K.W. Able. 2000. Estuarine and habitat-related differences in growth rates of 

young-of-the-year winter flounder (Pseudopleuronectes americanus) and tautog (Tautoga 

onitis) in three northeastern US estuaries. J. Exp. Mar. Biol. Ecol., Vol. 247, pp1-28. 

Pohl, O. 2002. New jellyfish problem means jellyfish are not the only problem. May 21 New 

York Times. 

Reitsma, J.H. 2002. May 31 RI DEM letter to EPA Regional Administrator Robert W. Varney 

commenting on USGenNE’s 316(a) and (b) Demonstration document. 

Rogers, C.A. 1976. Effects of temperature and salinity on the survival of winter flounder 

embryos. Fishery Bulletin. Vol.74, No. 1, pp 52-58. 

Rountree, R., D. Borkman, W. Brown, Y. Fan, L. Goodman, B. Howes, B. Rothschild, M. 

Sundermeyer and J. Turner. 2002. Framework for formulating the Mount Hope Bay natural 

laboratory: a synthesis and summary. Working Draft dated January 18, 2002. 

Scherer, M. 2002A. Pers. Comm. to Phil Colarusso (April 2002). 

Scherer, M. 2002B. Pers. Comm. to Phil Colarusso (February 2002). 

Scherer, M. 2002C. Handout from 2/21/02 TAC Meeting. 

Scherer, M. 2002D. Pers. Comm. to Phil Colarusso (March 2002). 

Scherer, M. 2002D. Pers. Comm. to Phil Colarusso (February 2002). 

Sherman, K. 1994. The changing ecosystem. Maritimes. Vol 37(1), pp.3-7. 

Short, F.T., B.W. Ibelings and C. Den Hartog. 1988. Comparison of a current eelgrass disease to 

the wasting disease in the 1930s. Aqu. Bot., Vol. 30, pp. 295-304. 

Spaulding, M.L. and F.M. White. 1990. Circulation dynamics in Mount Hope Bay and the lower 

Taunton River. Coastal and Estuarine Studies. Vol. 38, R.T. Cheng (Ed.), Residual Currents 

and Long-Term Transport, Springer-Verlag, New York, Inc. 
Stoner, A.W., J.P. Manderson and J.P. Pessutti. 2001. Spatially explicit analysis of estuarine 

habitat for juvenile winter flounder: combining generalized additive models and geographic 

information systems. Mar. Ecol. Prog. Ser., Vol. 213, pp 253-271. 

Sullivan, B.K., D. Van Keuren and M. Clancy. 2001. Timing and size of blooms of the 

ctenophore Mnemiopsis leidyi in relation to temperature in Narragansett Bay, RI. Hydrobiologia, 

Vol. 451, pp 113-120. 

Thayer, G.W., W.J. Kenworthy and M.S. Fonseca. 1985. The ecology of eelgrass meadows of 

the Atlantic coast: a community profile. U.S. Fish Wildl. Serv. FWS/OBS-84/02. 147 pp. 

Turner, C. 2001. Pers. Comm. to Phil Colarusso (April, 2001). 

U.S. EPA. May 1, 1977. Interagency 316(a) Technical Guidance Manual And Guide For 

Thermal Effects Sections Of Nuclear Facilities Environmental Impact Statements. Office of 

Water Enforcement, Permits Division, Industrial Permits Branch, Washington, D.C. 

U.S. EPA. June 1985. Rates, Constants, and Kinetics Formulations in Surface Water Quality 

Modeling (Second Edition). EPA/600/3-85/040. 

USGen. 2001. NPDES Permit Number MA0003654-Response to Section 308 Information 

Request dated August 10, 2001. Meredith Simas, USGen to Phil Colarusso, US EPA, dated 

October 1, 2001. 

Valiela, I. 1995. Marine Ecological Processes. Springer-Verlag Publishing, New York. 686 pp.