i

Electricity 

Reliability Impacts 

of a Mandatory 

Cooling Tower Rule 

for Existing Steam 

Generation Units

U.S. Department of Energy 

Office of Electricity Delivery and 

Energy Reliability 

October 2008 
ii
iii

TABLE OF CONTENTS 

EXECUTIVE SUMMARY ........................................................................................................................... i 

SUMMARY................................................................................................................................................... ii 

INTRODUCTION: Request from Congress ............................................................................................. 1 

CHAPTER 1: Background of Thermoelectric Power Plant Cooling Systems – Technical and 

Regulatory Issues.......................................................................................................................................... 3 

CHAPTER 2: Maintaining Electricity Adequacy..................................................................................... 9 

Existing Generation Fleet ......................................................................................................................... 10 

Coal-Fired Generation .............................................................................................................................. 10 

Nuclear Power .......................................................................................................................................... 11 

Natural Gas-Fired Generation .................................................................................................................. 11 

Renewable Generation.............................................................................................................................. 14 

Electricity Generation Challenges ............................................................................................................ 15 

CHAPTER 3: Analysis of Wide-Scale Retrofit of Cooling Systems at Existing Electric 

Generating Facilities .................................................................................................................................. 17 

Identification of Affected Facilities.......................................................................................................... 17 

Scenario Analysis – Retrofit and Retirement Assumptions...................................................................... 23 

 Economic Retirements ......................................................................................................................... 23

 Siting/Permitting Retirements.............................................................................................................. 24

Estimate of Generation Capacity Losses .................................................................................................. 26 

CHAPTER 4: Electricity Reliability Scenario Analysis......................................................................... 31 

NERC White Paper................................................................................................................................... 31 

Discussion ................................................................................................................................................ 32 

CHAPTER 5: Conclusion ......................................................................................................................... 37 

APPENDIX: NERC White Paper 
i
i

Executive Summary 

The U.S. Senate Committee on Appropriations, Subcommittee on Energy and Water 

Development, requested the Office of Electricity Delivery and Energy Reliability of the 

Department of Energy (DOE or Department) to examine the impacts on electricity 

reliability of requiring existing steam generators using once-through cooling systems to 

replace those systems with closed-cycle cooling towers to condense and to cool the steam 

after its use in the generation of electricity. 

DOE provided the North American Electric Reliability Corporation (NERC) with a list of 

steam generation units that would be required to retrofit to cooling towers. 1

 DOE 

requested NERC to model the reliability impacts of the cooling tower mandate using 

certain assumptions (see Chapter 3). NERC provided DOE with its results in a white 

paper entitled, “2008-2017 NERC Capacity Margins: Retrofit of Once-Through Cooling 

Systems at Existing Generating Facilities, (NERC White Paper), which is provided as an 

Appendix to this analysis. 

In its white paper, NERC concludes that once the deadline for the cooling tower retrofits 

has passed, the generation losses resulting from the requirement would exacerbate a 

potential decline in electric generation reserve margins that are needed to ensure reliable 

delivery of electricity. Generally, the goal for NERC regions is to have the equivalent of 

between 10.5 and 13 percent of their peak generation demand available to meet 

contingencies. Assuming only planned generation is built, NERC projects overall 

capacity reserve margins to fall to 14.7 percent by 2015. However, upon analyzing the 

impact of a cooling tower mandate, NERC projects that, “U.S. resource margins drop 

from 14.7 percent to 10.4 percent when both the retired units and auxiliary loads due to 

retrofitting were compared to the Reference Case.” (NERC White Paper, p. 4) 

Based on the best available data, the loss of generation capacity due to reduced 

operational efficiency in combination with the early retirement of facilities that either 

cannot or choose not to retrofit may jeopardize the ability of California, New York, and 

New England to meet peak demand for electricity. In addition, one could reasonably 

expect that the capacity margin reduction would further aggravate transmission 

congestion in the Mid-Atlantic Area National Interest Electric Transmission Corridor. 

 

1

 In preparation of this analysis, DOE’s Office of Electricity Delivery and Energy Reliability (OE) worked 

with staff in DOE’s Office of Fossil Energy in the Systems, Analysis, and Policy Group at the National 

Energy Technology Laboratory (NETL). 
ii

Summary 

The U.S. Senate Committee on Appropriations, Subcommittee on Energy and Water 

Development, requested the Office of Electricity Delivery and Energy Reliability of the 

Department of Energy (DOE or Department) to examine the impacts on electricity 

reliability of a potential rule under section 316(b) of the Federal Water Pollution Control 

Act (Clean Water Act) that would require existing steam generators using once-throughcooling systems to replace those systems with closed-cycle cooling towers to condense 

and to cool the steam after its use in the generation of electricity. 

Section 316(b) was enacted to provide for the regulation of thermal discharges to the 

Nation’s surface waters. On January 25, 2007, the U.S. Circuit Court of Appeals for the 

Second Circuit remanded several provisions of the Phase II Final Rule promulgated by 

the Environmental Protection Agency (EPA). The United States Supreme Court has 

agreed to hear the appeal of the circuit court’s ruling and oral argument is scheduled for 

later in this year. 2

 One potential outcome could require all existing power plants 

withdrawing 50 million gallons of water or more per day and using at least 25 percent of 

the water withdrawn for cooling purposes to comply with new requirements to minimize 

impingement and entrainment of larval fish and other aquatic organisms. Among the 

alternatives advocated is the replacement of existing once-through-cooling systems with 

cooling towers. This paper evaluates the potential impact of such a requirement on 

electric reliability. 

DOE provided the North American Electric Reliability Corporation (NERC) with a list of 

steam generation units that would be required to retrofit to cooling towers. 3

 DOE 

requested NERC to model the reliability impacts of the cooling tower mandate using 

certain assumptions (see Chapter 3). NERC provided DOE with its results in a white 

paper entitled, “2008-2017 NERC Capacity Margins: Retrofit of Once-Through Cooling 

Systems at Existing Generating Facilities” (NERC White Paper), which is provided as an 

appendix to this analysis. 

The Nation’s electricity industry faces major challenges during the next 15 years to keep 

adequate reserve capacity margins of electricity generation available to meet peak 

demand growth, even if that peak demand growth is dampened by initiatives focused on 

demand-response, improved technology, and energy efficiency. Nevertheless, electricity 

operators must plan to provide adequate generation capacity during periods of peak 

electricity demand, with a margin of additional capacity ready for contingencies, such as 

an unexpected generation plant shutdown. These capacity requirements are expected to 

grow despite increasing participation of consumers and utilities in demand response 

 

2

 See Entergy Corporation v. Environmental Protection Agency, et al., No.07-588, April 14, 2008. 

3

 In preparation of this analysis, DOE’s Office of Electricity Delivery and Energy Reliability (OE) worked 

with staff in DOE’s Office of Fossil Energy in the Systems, Analysis, and Policy Group at the National 

Energy Technology Laboratory (NETL). 
iii

programs and investments in energy efficiency. According to data collected by the 

NERC, average peak demand during the summer is expected to increase by over 135,000 

megawatts (MW) or 17.7 percent by 2017, while committed resources4 are projected to 

grow by only 77,000 MW.5

Over half of the existing fleet of thermoelectric power plants in the United States is 

estimated to be equipped with once-through cooling systems (see Table 3-1, p. 17.). This 

represents 385 existing power plants that could be affected by 316(b) Phase II 

regulations. By far the majority of the affected plants (roughly 70 percent) are baseload 

steam plants, predominantly coal and nuclear facilities. The remaining 30 percent are 

mostly older, less efficient oil- and gas-fired steam facilities. 

Retrofitting a facility that was originally designed for once-through cooling to a 

recirculating cooling system will result in reduced power output from the additional 

equipment that needs to be run (ancillary load loss), such as pumps and fans, and from 

the loss of efficiency because the cooling water is generally warmer coming back from a 

cooling tower than it is from the body of water used by a once-through cooling system. 

While the reduced power output (energy penalty) from both types of losses is estimated 

to be less than two percent of the average net power output of the facility, when summer 

ambient conditions are at their worst (i.e., hot and humid, so that the cooling tower water 

is at its warmest), the reduced output increases, approaching as much as 4 percent of the 

facility’s net output. Accordingly, the energy penalty of retrofitting to a recirculating 

cooling system is the greatest when the power grid is strained the most, during periods of 

peak summer electric demand. The loss of efficiency and generation capacity means that 

less electricity is available to meet demand or to serve as reliable reserve capacity. 

Nuclear plants would be particularly impacted by a cooling tower mandate because reevaluation of the nuclear plant safety basis and Nuclear Regulatory Commission (NRC) 

licensing amendments would be required for existing nuclear reactors to comply with 

such a rule. This is in addition to the engineering, construction, outage, and power 

replacement impacts and loss of revenue similar to large, baseload coal plants. The 

licensing impact would be determined by the complexity of necessary design changes to 

safety and non-safety cooling systems, preparation of required license application 

documentation and supporting analyses, submission of the license amendment package, 

and the review and approval by the U.S. Nuclear Regulatory Commission. The potential 

for significant negative economic impact could influence utilities to not pursue further 

license renewals based on unfavorable financial returns, further reducing electricity grid 

operating margins. During Fiscal Year 2009, the Department of Energy will work with 

NRC and industry to better characterize the scope and impact of such a change to an 

operating nuclear plant. 

 

4

 Committed resources include generating capacity resources that exist, are planned, or under construction. 

These resources are considered available, deliverable, and committed to serve demand, plus the net of 

capacity purchases and sales. 

5

 NERC 2007 Long-Term Reliability Assessment. (NERC further states that, “a major driver of the 

uncertain or inadequate capacity margins is the industry’s relatively recent shorter-term approach to 

resource planning and acquisition, relying heavily on unspecified, undeveloped, and/or uncommitted 

resources to meet projected demand.”), p. 11 (October 2007). 
iv

In its white paper, NERC concludes that once the deadline for the cooling tower retrofits 

has passed, the generation losses resulting from the requirement would exacerbate a 

potential decline in electric generation reserve margins that are needed to ensure reliable 

delivery of electricity. Generally, the goal for NERC regions is to have the equivalent of 

between 10.5 and 13 percent of their peak generation demand available to meet 

contingencies. Assuming only planned generation is built, NERC projects overall 

capacity reserve margins to fall to 14.7 percent by 2015. However, upon analyzing the 

impact of a cooling tower mandate, NERC projects that, “U.S. resource margins drop 

from 14.7 percent to 10.4 percent when both the retired units and auxiliary loads due to 

retrofitting were compared to the Reference Case.” (NERC White Paper, p. 4) 

Absent a plant-by-plant investigation, this analysis is limited in its ability to project 

which individual generating units subject to a retrofit mandate would not be retrofitted 

for either economic or siting reasons. Generally, older units may not have sufficient 

useful operating life remaining to recover the retrofit investment. Also, less efficient 

generation facilities may not be operated enough hours of the year (i.e., have a low 

“capacity factor”) to justify the retrofit investment. 

Similarly, this analysis is not able to make quantitative conclusions on the location and 

number of facilities that do not have the physical space or could not obtain the requisite 

permits to construct cooling towers. For example, the 483 MW coal-fired Mirant 

Potomac River Power Plant, located next to the flight path into Ronald Reagan 

Washington National Airport and which supplies much of downtown Washington, D.C., 

would be unlikely to be able to install cooling towers due to both space and permit 

restrictions. 

For this analysis, DOE used capacity factor (the percentage of the time a plant is actually 

generating) as a proxy for economic and permitting viability of facilities considering a 

cooling tower retrofit. The DOE analysis assumed a range of potential plant retirements 

– from no retirements, to retirements by plants with 25 percent capacity factor or less, to 

retirements by plants with a capacity factor of 35 percent or less. The use of the capacity 

factor thresholds are used as proxies to estimate those plants that would not be economic 

to retrofit or could not obtain land or permits, and would have to retire. Using a range of 

assumptions, DOE estimated the capacity of the plants that would retire as 38,000 to 

75,000 MW. The facilities that would retire are overwhelmingly (more than 90 percent) 

oil- and gas-fired steam units. DOE notes that using the 25 and 35 percent or less 

utilization rates as proxies for the units that would retire as a consequence of this rule has 

the effect of assuming few coal plants and no nuclear plants would retire. 

Note that this proxy approach does not account for facility-specific economic factors, 

including revenue streams other than from electricity sales alone, loss of generation 

revenues, a plant’s cumulative capital and operational costs of complying with new SOx, 

NOx, mercury, or carbon emission limits, or the cost of seeking amendments to existing 

licenses or permits. Although, these proxies likely underestimate the potential impact of 

the mandate on many baseload coal and nuclear units, they are used in this analysis to 
v

provide rough approximations of possible retirement scenarios from a cooling tower 

mandate. 

In its white paper, NERC concludes that once the deadline for the cooling tower retrofits 

has passed, the generation losses resulting from the requirement would reduce generation 

capacity by 49,000 MW, or 4.3 percent points compared to what otherwise would be in 

service. This loss of generation capacity would exacerbate what NERC already projects 

as a decline in electric generation reserve margins that are needed to ensure reliable 

delivery of electricity. Generally, the goal for NERC regions is to have the equivalent of 

between 10 and 15 percent of their peak demand available to meet contingencies. In its 

reference case (without a cooling tower mandate), NERC assuming no plant retirements 

and that all “planned” generation is built, NERC projects overall capacity reserve 

margins to fall to 14.7 percent by 2015. However, upon analyzing the impact of a 

cooling tower mandate, NERC projects that, “U.S. resource margins drop from 14.7 

percent to 10.4 percent when both the retired units and auxiliary loads due to retrofitting 

were compared to the Reference Case.” (NERC White Paper, p. 4). The U.S. does not 

have a national electricity grid, but rather a series of large regional power grids. The 

amount of reduced generation capacity and its impact on regional reliability would vary 

from region to region. 

Based on the best available data, this loss of generation capacity in combination with the 

early retirement of facilities that either cannot or choose not to retrofit may jeopardize the 

ability of California, New York, and New England to maintain reserve margins needed to 

meet contingencies during peak electricity demand periods. (Figure 4-1, p. 32, and see

NERC White Paper, p. 6.) 

To the extent that a cooling tower mandate would cause the retirement of once-through 

cooling generation facilities near load centers, additional grid reliability concerns arise 

with the loss of local generation to provide peaking power as well as frequency and 

voltage support to maintain the quality of the delivered electricity. Moreover, loss of 

local generation would necessitate at least some increase in imported generation. 

Demand-side management initiatives and smart grid technologies will help reduce future 

demand and replace some of the lost generation. New wind generation will continue to 

make increasing contributions, although this will require additional transmission. 

Nevertheless, additional conventional generation, almost certainly natural gas units, 

would be required in the near term. Although there is evidence that domestic natural gas 

production is increasing, these increases are not likely to keep up with growing natural 

gas demand, thereby increasing dependence on LNG imports that are vulnerable to 

potentially high global process. Replacing prematurely retired local facilities with natural 

gas, wind, and solar will require careful planning to ensure enough new natural gas 

pipeline and electric transmission facilities are sited and constructed in a timely manner. 

While a detailed analysis of the impacts on electric transmission reliability was not 

performed, NERC advises that transmission congestion in the Mid-Atlantic Area 
vi

National Interest Electric Transmission Corridor could be expected to be aggravated by 

reduced capacity margins (NERC White Paper, p. 7.) 

This analysis did not update previous DOE studies concerning the potential cost of 

construction of cooling towers. These costs are expected to be substantial,6

 and would be 

in addition to the cost of increasing generation and transmission to meet growing 

electricity demand and the changing mix of the generation fleet to include more 

remotely-located clean energy sources. 

 

6

 During the rule-making, DOE submitted analyses to the Environmental Protection Agency (EPA) 

concluding that the retrofit to closed-looped cooling systems would impose significant capitol cost burdens. 

The EPA, in adopting the rule, found retrofit of existing plants was many times higher, $130 to $200 

million per tower, than for new facilities that are required to install cooling towers. 
1

Introduction: Request from Congress 

The U.S. Senate Committee on Appropriations Subcommittee on Energy and Water 

Development requested the Office of Electricity Delivery and Energy Reliability of the 

Department of Energy (DOE or Department) to prepare an analysis of the impacts on 

electricity reliability on a regional basis if the Environmental Protection Agency (EPA) 

were to promulgate a Clean Water Act (CWA) thermal discharge rule that would require 

all existing steam generators to retrofit to use cooling towers rather than other options to 

condense and cool the steam after its use in the generation of electricity. Specifically, the 

Subcommittee sent the following questions for the record to DOE after the FY 2009 

appropriations hearing held on March 5, 2008. 

1. Part of DOE's mission is to promote America’s energy security through 

reliable, clean and affordable energy. I understand that EPA plans to propose a 

revised rule before the end of the year governing cooling water intake structures 

at existing power plants as a result of a recent 2nd Circuit court decision. The 

central question before the agency is what should be deemed the best technology 

available (BTA) to minimize the adverse environmental impacts that might result 

from cooling water intake structures. The Court has directed the agency to clarify 

why cooling towers or their performance equivalent, were not deemed BTA. I 

understand that approximately 40 percent of the nation's existing generation will 

be directly and materially affected by this rulemaking. Has DOE examined the 

short and long term energy reliability and security impacts of designating cooling 

towers as BTA for existing generation facilities and does DOE believe they would 

be significant? 

2. Could DOE do an analysis of the potential impacts for this Committee, 

including the impacts on electricity reliability on a regional basis, and provide 

preliminary results as early as May so that these results could be meaningfully 

considered in the EPA rulemaking? 

In response to this request, the Department determined that this analysis should focus on 

the electricity reliability impacts that would be created if a mandatory cooling tower rule 

were issued by the EPA. The Department did not attempt to quantify the costs to 

industry, consumers, and the economy of such a mandate. As discussed later in the 

analysis, during EPA’s rulemaking DOE submitted analyses demonstrating a significant 

cost associated with requiring a retrofit of existing steam generators.
2
3

Chapter 1: Background of Thermoelectric Power Plant 

Cooling Systems – Technical and Regulatory Issues

Substantial progress is expected in electric power demand reduction technologies and 

programs. Nevertheless, the DOE Energy Information Administration (EIA) projects 

electricity demand will grow at an average of 1.1 percent per year through 2030. 

Substantial amounts of new generation capacity are planned or anticipated for 

construction over the next decade to meet this demand growth or replace generation 

facilities scheduled for retirement. Whether sufficient new generation and transmission 

will be operational to keep pace with demand will depend on public acceptance, 

availability of labor and materials, new regulatory programs, tax policy, and other factors. 

Clearly, meeting the growing demand for reliable electricity will require continued 

reliance on the large base of currently operational power plants for the foreseeable future. 

According to EIA, approximately 70 percent of the Nation’s annual electricity generation 

in 2006 was produced by thermoelectric generating plants.7

 More than 2,775 billion 

kilowatt-hours (kWh) were generated by these largely baseload coal and nuclear plants, 

although older oil- and natural gas-fired steam plants were often used during periods of 

peak electricity demand. 

Thermoelectric power plants generate electricity by boiling water to produce steam. 

Regardless of the primary fuel (e.g., coal, oil, natural gas, biomass, or nuclear), the 

process is fundamentally the same. Water is boiled at very high temperature and 

pressure, and the resulting superheated steam is harnessed to spin a turbine coupled to a 

generator. While much of the energy is extracted from the steam and used to generate 

electricity, the turbine exhaust steam must be cooled and condensed so that the water can 

be reheated and sent back to the turbine to produce more electricity. This process, known 

as the Rankine Cycle, has been used to generate electricity for more than a century. 

In order to cool and condense the turbine exhaust, a large heat “sink” is required. The 

simplest and most effective power plant heat sink involves the use of substantial volumes 

of cooling water. Historically, power plants were located on large water bodies or high 

flow-rate rivers typical of the northeastern United States. Many of these facilities were 

constructed using what is known as once-through cooling systems, which draw large 

volumes of cool water from the source (such as a river or ocean), pass it through the 

power plant’s condenser, and return it, warmed by the heat transfer process, to the source 

downstream from the intake. 

Accordingly, section 316 of the Federal Water Pollution Control Act (Clean Water Act), 

was enacted to provide for the regulation of thermal discharges to the Nation’s surface 

waters. Regarding the existing fleet of electric power plants, section 316 includes three 

subsections, two of which separately address thermal discharges and cooling water intake 

structures. Section 316(a) addresses thermal discharges from power plants and provides 

 

7

 DOE/EIA, Annual Energy Outlook 2008 (June, 2008). http://www.eia.doe.gov/oiaf/aeo/index.html. 
4

that “the Administrator [of the Environmental Protection Agency (EPA)]...may impose 

an effluent limitation with respect to the thermal component of the discharge...that will 

assure the protection and propagation of a balanced, indigenous population of shellfish, 

fish, and wildlife” in and on the receiving body of water. Section 316(b) addresses the 

location, design, construction, and capacity of cooling water intake structures and 

requires that the structures “reflect the best technology available for minimizing adverse 

environmental impact.” This latter provision addresses impingement and entrainment8 of 

biota with resulting mortality of fish, larvae, and other aquatic organisms. 

Section 316 was added as a series of amendments to the Clean Water Act in 1972. 

Applicability of requirements under section 316(a) was divided to address affected 

facilities existing as of July 1, 1972, and those built after July 1, 1972. Generation 

companies comply with section 316(a) mostly by designing plants to produce a specific 

discharge that minimizes environmental impacts. The rise in temperature of the water 

discharged to the receiving water body must be kept at a level such that thermal 

discharges do not adversely affect wildlife in and on that water body, commonly 

accomplished by dilution. In order to minimize the temperature increase of the cooling 

water, many large plants require significant water withdrawals, often in excess of 100 

million gallons per day. 

EPA promulgated a final regulation implementing 316(b) in 1976. Subsequent to 

substantial challenges from industry groups, the regulation was remanded in 1977, and 

not addressed again until the 1990s.9

 Even lacking Federal regulation, however, most 

newer plants have been designed and constructed with cooling systems that require much 

lower water withdrawals than once-through cooling systems (e.g., cooling towers or 

recirculating cooling systems, including man-made cooling reservoirs or cooling ponds). 

Nonetheless, DOE estimates that today, over half of the existing thermoelectric power 

plants (fossil and nuclear combined) – nearly 300 gigawatts (GW) – are still equipped 

with once-through cooling systems. 

After nearly two decades and a 1995 consent decree, EPA committed to complete a 

316(b) rule by August 2001. EPA entered into a series of rulemaking actions, breaking 

the 316(b) effort into three phases: Phase I established standards for cooling water intake 

structures at new facilities. The final rule was published November 9, 2001, and was 

later amended with minor changes on June 19, 2003.10, 11 Phase II established standards 

for existing power plants. The final rule was published February 16, 2004.12 Phase III 

 

8

 Impingement refers to aquatic organisms pinned against parts of the intake structure, entrainment refers to 

the sucking in and carrying along of organisms throughout the cooling system. Impingement and/or 

entrainment result in physical harm to the affected organism. 

9

 EPA, Phase I – New Facilities, Proposed Rule for the Location, Design Construction and Capacity 

Standards for Cooling Water Intake Structures at New Facilities. EPA-821-F-00-008 (July, 2000). 

10 EPA, Phase I – New Facilities, Final Rule, Phase I, Fact Sheet. EPA-821-F-01-017 (November, 2001). 

11 EPA, Phase 1 – New Facilities, Amended Final Phase I Rule, Fact Sheet. EPA 821-F-03-010 (June, 

2003). 

12 EPA, Phase II- Large Existing Electric Generating Plants, Fact Sheet: Final Regulations. EPA-821-F04-003 (February, 2004). 
5

established categorical requirements (not standards) for new offshore oil and gas 

extraction facilities. 

Relevant to a substantial portion of the existing fleet, final Phase II regulations published 

in 2004 required that existing power plants withdrawing 50 million gallons per day or 

more and using at least 25 percent of the water withdrawn for cooling purposes, must 

comply with requirements to minimize impingement and entrainment. The final rule 

provided several compliance alternatives including technological and restorative 

measures but did not require installation of recirculating cooling systems (e.g., cooling 

towers) at facilities equipped with once-through cooling systems.13

 

On January 25, 2007, the Second U.S. Circuit Court of Appeals remanded several 

provisions of the Phase II Final Rule (see, Riverkeeper, Inc., v. EPA, 475 F.3d 83, (2nd

Cir. 2007)). In response, on March 20, 2007, EPA suspended the Phase II Final Rule.14 

An appeal of the Second Circuit decision was filed by Entergy Corporation and others, 

and the U.S. Supreme Court has agreed to hear the case. The United States filed a brief 

in support of the EPA being able to compare costs with benefits in determining the best 

technology available for minimizing adverse environmental impacts at cooling water 

intake structures. 

DOE estimates that 385 existing power plants (~ 300 GW) could be affected by Phase II 

regulations. Potential impacts of imposing stringent 316(b) regulations on existing power 

plants could result in decreased power output due to auxiliary power requirements 

(parasitic load) associated with cooling water. In addition, the circulating water in a 

closed-cycle system is usually warmer than the fresh water in a once-through cooling 

system. The use of warmer water results in less efficient operations, resulting in 

“derating” the maximum efficiency of the unit. The combination of the auxiliary power 

load and derating that would result from a retrofit of a once-through cooling to a closedcycle system is often referred to as the “energy penalty.” 

 DOE conducted an assessment of the energy penalty associated with retrofitting coalbased power plants equipped with once-through cooling systems with either recirculating 

evaporative cooling towers or indirect dry cooling technology (NETL Energy Penalty 

Analysis).15 (Evaporative [wet] cooling towers can be either natural draft or mechanical 

draft; the two are significantly different in numerous critical respects, including land use.) 

The NETL analysis considered a variety of cooling system design assumptions and 

ambient conditions for both wet-and dry-cooling tower retrofits.16 

 

13 EPA, Phase II- Large Existing Electric Generating Plants, Fact Sheet: Final Regulations. EPA-821-F04-003 (February, 2004). 

14 EPA, Phase II Implementation Memo. Last accessed (August 2008) online at 

http://www.epa.gov/waterscience/316b/phase2/implementation-200703.pdf. 

15 NETL, Energy Penalty Analysis of Possible Cooling Water Intake Structure Requirements on Existing 

Coal-Fired Power Plants (October, 2002). 

http://www.netl.doe.gov/technologies/coalpower/ewr/water/pdfs/EP%20Final%20Report.pdf 

16 Wet cooling exchanges heat primarily by evaporation, with concomitant consumptive water loss. Wet 

cooling towers can be either natural draft (i.e., ambient air flow is maintained by convective buoyancy 

effects) or mechanical draft (i.e., air flow is maintained by fans). The two technologies are significantly 
6

Energy penalties were estimated for five representative regions of the continental United 

States,17 and calculated both for an average annual energy penalty and an energy penalty 

based on the one-percent-high temperature (the recorded ambient condition that is 

exceeded only 1 percent of the time June through September at each modeled location). 

The one-percent-high temperature represents the time of year when the performance of 

the retrofit system is expected to be poorest and the electricity demand is likely to be 

highest. As expected, the energy penalty that results from retrofitting from once-through 

cooling to dry cooling towers is higher than that which results from retrofitting from 

once-through to wet cooling towers. Also, the energy penalty observed during the onepercent-high temperature is more severe than that which is observed as an average annual 

energy penalty. Summary results of the NETL analysis are presented in Table 1-1. 

Table 1-1: Comparative Energy Penalties for a Once-Through Cooling System Retrofita

 Wet Cooling Tower Retrofit 

Region Average Annual Energy 

Penalty, Percent 

One-percent-highest Energy 

Penalty, Percent 

Delaware River Basin 1.18 3.12 

Michigan/Great Lakes 1.47 3.08 

Ohio River Valley 1.14 2.98 

South 0.82 2.41 

Southwest 0.80 2.06 

Notes: a) The energy penalties presented here are for representative fossil (coal) model plants. Nuclear plants were not part of the above 

analysis and were not modeled. However, the literature suggests that nuclear plants would have slightly higher energy penalties for 

similar retrofits.

In addition to assessing the energy penalty associated with retrofitting once-through 

systems with recirculating (closed-cycle) systems, NETL also examined facility-specific 

factors that may impact the feasibility of retrofitting such systems at existing plants. 

Recirculating cooling systems are relatively large structures and require large areas for 

installation. NETL commissioned the Parsons Corporation to evaluate four existing 

thermoelectric power plants using only publically available data. This analysis affirmed 

the results of the earlier NETL Energy Penalty Analysis and concluded that the retrofit of 

closed-loop cooling systems would impose significant capital cost burdens.18

 

 

different in a number of critical respects. The DOE analysis focused on the application of mechanical draft 

wet cooling systems. Dry cooling, which is akin to an automobile radiator, does not sustain water loss, but 

is less energy-efficient, causing higher parasitic energy losses from operation. In either case, a certain 

amount of water is periodically returned to the source in the form of “blowdown” as a means of purging the 

system of built up impurities. 

17 The regions and representative locations considered in the DOE Energy Penalty Analysis included the 

Delaware River Basin (Philadelphia, PA), Michigan/Great Lakes (Detroit, MI), Ohio River Valley 

(Indianapolis, IN), South (Atlanta, GA), and Southwest (Yuma, AZ). 

18 Parsons Corporation, An Investigation of Site-Specific Factors for Retrofitting Recirculating Cooling 

Towers at Existing Plants (October 8, 2002). 

http://www.netl.doe.gov/technologies/coalpower/ewr/water/pdfs/316b_NETL_ParsonFinalReport_wAddnd

_012203.pdf
7

Following the issuance of the Parsons Corporation analysis, NETL held discussions with 

each of the utilities that owned the plants examined in the analysis. In addition to the cost 

and energy impacts, additional factors not addressed in the Parsons Corporation were 

identified as worth considering. A condition peculiar to mechanical draft cooling towers 

is that, under certain atmospheric conditions, a visible plume forms above the cooling 

tower. This plume can have deleterious effects (i.e., fogging, icing, corrosion) to nearby 

infrastructure. In the case of natural draft (hyperbolic) cooling towers at fossil-fired 

power plants, there is the potential for sulfuric acid mist formation from comingling of 

the water vapor and smokestack plumes of SO2. 

NETL concluded that the supplemental information received from discussions with the 

plant owners only reinforced the conclusions of the two earlier studies and indicated that 

cooling tower retrofits can be substantially more difficult and costly when significant, 

facility-specific constraints are considered.19 As part of the rule making process, the 

Energy Penalty Analysis, the Parsons Corporation analysis, and the DOE addendum to 

the Parsons Corporation analysis based on the conversations with the plant owners were 

formally submitted to EPA during their regulatory effort.20

 

19 NETL, Addendum to Report An Investigation of Site-Specific Factors for Retrofitting Recirculating 

Cooling Towers at Existing Power Plants (January 22, 2003). 

http://www.netl.doe.gov/technologies/coalpower/ewr/water/pdfs/316b_NETL_ParsonFinalReport_wAddnd

_012203.pdf 

20 EPA, Response to Public Comment: CWA Section 316(b) Phase II Existing Facility Rule—Final (March 

29, 2004). http://www.epa.gov/waterscience/316b/phase2/comments/author-ph2.pdf. 
8
9

Chapter 2: Maintaining Electricity Adequacy 

As discussed in Chapter 1, this analysis assumes that a new rule is issued by the EPA 

pursuant to section 316 of the Clean Water Act that will require all steam-powered 

electricity generating facilities to use cooling towers to condense the steam that passes 

through its generators. This analysis indicates that under such a scenario, roughly half of 

the coal and nuclear facilities in the United States may be required to retrofit and install 

cooling towers. To provide a context within which to asses the implications of this 

requirement, the following chapter will examine the current U.S. generating fleet and 

explore the potential challenges of meeting electricity demand through 2020. 

To promote a more efficient use of electricity and slow demand growth, DOE has 

strongly supported energy efficiency, demand response initiatives, and implementation of 

smart grid technologies. While the annual growth rate of electricity demand has 

gradually declined during the past 40 years, it nevertheless continues to grow. The EIA 

reported in its most recent long-term energy forecast that electricity demand will maintain 

a 1.1 percent increase every year through 2030, leading to an increase in electricity 

consumption of 30 percent between 2006 and 2030.21 Given this outlook, construction of 

additional generating capacity will be necessary, not only to meet additional demand with 

an adequate reserve margin, but also to replace existing generation facilities that will be 

retired. 

Electricity operators must plan to provide adequate generation capacity during periods of 

peak electricity demand, with a margin of additional capacity ready for contingencies, 

such as an unexpected generation plant shutdown. These capacity requirements are 

expected to grow despite increasing participation of consumers and utilities in demand 

response programs and investments in energy efficiency. According to data collected by 

NERC, average peak demand during the summer is expected to increase by over 135,000 

MW or 17.7 percent by 2017 while committed resources22 are projected to grow by only 

77,000 MW.23 Even assuming no plant retirements, certain regions may be unable to 

supply enough committed resources to meet the projected increases in peak demand. 

Meeting the need for this additional generation capacity will be challenging. 

Expectations for completion of new generation facilities must be informed by an 

understanding of the additional time needed for permitting and construction. Because the 

average cost to build a single power plant (all generating types considered) has been 

significantly increasing over the past several years, many utilities have become very 

 

21 DOE/EIA, Annual Energy Outlook 2008, p. 10 (June, 2008). 

22 Committed resources include generating capacity resources that exist, are planned, or under construction. 

These resources are considered available, deliverable, and committed to serve demand, plus the net of 

capacity purchases and sales. 

23 NERC 2007 Long-Term Reliability Assessment, p. 11, (October, 2007). (NERC further states that, “a 

major driver of the uncertain or inadequate capacity margins is the industry’s relatively recent shorter-term 

approach to resource planning and acquisition, relying heavily on unspecified, undeveloped, and/or 

uncommitted resources to meet projected demand.”) 
10

cautious in planning future construction.24 It is important to also consider the sometimes 

even longer lead times are required to address electricity delivery concerns such as the 

need to expand transmission capacity, strengthen grid management, and improve 

distribution systems as needed in order to satisfy the expectations of future demand 

growth. This particularly applies to situations where longer distances will separate 

generating facilities and consumers. 

Existing Generation Fleet 

The United States uses a broad energy mix to generate electricity. This mix shifts over 

time, most recently emphasizing natural gas and renewable energy, which is expected to 

continue in the mid-term. However, coal has long been the predominant fuel for 

electricity generation and continues to generate almost half of the Nation’s energy (see

Figure 2-1). 

Coal-Fired Generation 

Coal has long been a reliable and relatively inexpensive energy source, providing a 

majority of America’s base-load generation. Most of the coal facilities operating in the 

United States today were built before 1990. EIA projects that coal will continue to be the 

dominant source of electricity generation in the mid-term, increasing its generation by 

357 billion kWh between 2006 and 2020 (see Figure 2-2).25

 

Figure 2-1. U.S. Net Generation by Energy 

Source, 2007

Figure 2-2. Projected Electricity Generation 

from Coal (billion kilowatthours) 

 

However, coal generation in the United States has faced increased scrutiny because these 

plants produce roughly twice as much carbon dioxide as natural gas-fired power plants 

for each unit of electricity delivered.26 This is a substantial amount, considering 

electricity generation emitted 33.7 percent of all U.S. greenhouse gasses in 2006.27 

Consequently, coal-fired power plant developers are faced with increasing scrutiny along 

with regulatory uncertainties, higher capital costs, and skilled labor shortages. These 

 

24 See, e.g., Wall Street Journal, Costs to Build Power Plants Pressure Rates (May 27, 2008). 

25 DOE/EIA Annual Energy Outlook 2008, p. 131 (June, 2008). 

26 The Environmental Protection Agency (EPA) Regulating Greenhouse Gas Emissions under the Clean 

Air Act, p. 37 (July, 2008). 

27 Id. p. 101. 
11

problems caused delays in the construction along with several cancelled plans for new 

coal plants. The current coal-fired projects in development reflect a potential surge in 

new facility additions. However, it has been evident in the past that coal plant 

announcements exceed actual plant completions. A NETL analysis indicates that by 

2007, only about 12 percent of the capacity announcements pending in 2002 were 

completed during the subsequent five years.28

Nuclear Power 

Nuclear power has been a vital source of base-load electricity generation in the United 

States since the early 1960s. Currently, a fleet of 104 operating nuclear power plants 

supply about one-fifth of the Nation’s total generation.29 Substantial efforts have been 

made to increase the output of these units. In 2007, these plants were able to operate at 

an estimated capacity factor (the percentage of time a facility is operating) of 91.5 

percent compared to 71.1 percent a decade earlier,30 increasing net generation by 28.3 

percent.31 Unlike fossil-fuel fired units, nuclear plants generate electricity with virtually 

no CO2 emissions or criteria air pollutant emissions. However, new construction for a 

reactor has not started since the late 1970s; the last plant to begin commercial operation 

was the Watts Bar I site in 1996 by the Tennessee Valley Authority (and construction for 

this plant began over 20 years earlier in 1976).32

Looking forward, the EIA projects 10.7 GW of additional nuclear generation capacity 

between 2006 and 2020 (including 2.7 GW of uprates).33 NERC’s 2007 Long-Term 

Reliability Assessment assumes 12 GW of proposed nuclear capacity to come online by 

2016.34 The EIA reports that nine applications for new commercial nuclear reactors have 

been submitted and as many as three reactors could come online between 2114 and 

2016.35 However, delays could be caused by a recent jump in construction costs for 

nuclear facility developers. Recent estimates anticipate a single nuclear plant could be 

priced anywhere between $5 and $12 billion, particularly due to the skyrocketing costs 

for cement, copper, and steel, as well as shortages of skilled labor and specialized parts – 

particularly the critical pressure vessels.36

Natural Gas-Fired Generation 

Natural gas-fired generating facilities have several advantages over coal-fired plants, 

including lower air pollution and CO2 emissions, lower capital costs, shorter construction 

times, and smaller site footprints.37 Unlike base-load coal and nuclear facilities, natural 

gas plants can be designed to respond quickly to changing electricity demand or 

 

28 DOE/NETL, Tracking New Coal-Fired Power Plants, pp. 9, 14 (February, 2008) – updated with Revised 

EIA AEO 2008 Projections). 

29 DOE/EIA Annual Energy Review 2007, p. 271 (June, 2008). 

30 Id. p. 273. 

31 Id. p. 226. 

32 Id. p. 271. 

33 DOE/EIA, Annual Energy Outlook 2008, p. 19 (June 2008). 

34 NERC, NERC 2007 Long-Term Reliability Assessment, p. 14 (2007). 

35 DOE/EIA Status of Potential Nuclear Reactors in the United States, 

http://www.eia.doe.gov/cneaf/nuclear/page/nuc_reactors/reactorscom.html. 

36 The Wall Street Journal, New Wave of Nuclear Plants Face High Costs (May 11, 2008). 

37 NERC, 2007 Long-Term Reliability Assessment, p. 15 (October, 2007). 
12

balancing intermittent generation from wind and solar. Newer combined-cycle facilities 

are able to utilize natural gas more efficiently and provide base-load generation. These 

attractive features have resulted in an 86.3 percent increase in natural gas-fired electricity 

generation between 1997 and 2007.38 Today, roughly one-fifth of America’s electricity 

generation is provided by natural-gas fired power plants.39 A majority of this generation 

is used to meet peak electricity demands, especially during the summer when natural gas 

net capacity exceeds other forms of generation. For example, natural gas accounted for 

39.5 percent of the total electric net summer capacity in 2007, compared to smaller 

contributions by coal (31.4) and nuclear (10.1).40 Moreover, natural gas units are now 

producing more electricity in non-peak hours compared to earlier years. 

During 2007, 6.9 trillion cubic feet (Tcf) of natural gas (over one-third of total U.S. 

consumption) was used for electricity generation.41 To satisfy this demand, the United 

States has relied primarily on domestic production, importing only about one-fifth of its 

total consumption, primarily through natural gas pipelines from Canada.42 These 

Canadian imports experienced positive growth to satisfy a growing demand between 

1988 and 2005, when U.S. natural gas production (gross withdrawals) remained relatively 

static.43 During this 17-year period, Canadian imports more than doubled from 1.27 Tcf 

to 3.7 Tcf.44 Looking forward, however, EIA projects a sharp decline in natural gas 

imports from Canada through 2020 (see Figure 2-3).45

 

Domestic natural gas production has responded to higher prices by ramping up 

production, with expected increases of 7.8 percent in 2008 and 3.8 percent in 2009.46 

This current surge is the result of expansion of the outer continental shelf production in 

the Gulf of Mexico and horizontal directional drilling techniques in natural gas-bearing 

shale deposits. In 2007, natural gas producers drilled over 31,252 wells, nearly doubling 

2002 figures.47 Domestic natural gas pipeline expansions also reached a record high level 

of new capacity in 2006 and 2007 with additions totaling 27.6 billion cubic feet (Bcf) per 

day.48 By 2020, the EIA projects the completion of an Alaskan pipeline would deliver an 

additional 4.5 Tcf per year to the United States.49 Despite these expansions, EIA’s long 

term forecast predicts domestic natural gas production will rise by only 6.3 percent 

between 2006 and 2020.50 Even if the EIA long-term forecast underestimates the 

potential for increased domestic natural gas production, domestic supply is unlikely to 

match the growth in demand for natural gas over the next decade. A majority of the 

 

38 DOE/EIA, Annual Energy Review 2007, p. 226 (June, 2008). 

39 DOE/EIA, Electric Power Monthly, p.15 (April, 2008). 

40 DOE/EIA, Annual Energy Review 2007, p. 260 (June, 2008). 

41 Id. p. 191. 

42 Id. p. 183. 

43 DOE/EIA, Annual Energy Review 2007, p. 185 (June, 2008). 

44 Id. p. 187. 

45 DOE/EIA, Annual Energy Outlook 2008, p. 78 (June, 2008). 

46 DOE/EIA, Shorterm Energy Outlook, p. 5 (September 9, 2008). 

47 DOE/EIA Natural Gas Navigator, U.S. Natural Gas Exploratory and Developmental Wells Drilled 

(Count) (http://tonto.eia.doe.gov/dnav/pet/pet_crd_wellend_s1_a.htm]). 

48 NERC, 2008 Summer Reliability Assessment, p. 16 (May, 2008). 

49 DOE/EIA, Annual Energy Outlook 2008, p. 140 (June, 2008). 

50 Id. p. 139. 
13

required new supply will need to come in the form of LNG imports, which the EIA 

projects will increase from 0.5 Tcf in 2006 to 2.4 Tcf in 2020. The trend of increasing 

purchases of LNG imports to keep up with growing domestic natural gas demand is 

illustrated in Figure 2-3, below. 

Figure 2-3. Net U.S. Imports of Natural Gas 

by Source (trillion cubic feet) 

 

In order to support the projected need for increased LNG imports, a robust North 

American infrastructure will be crucial. The Federal Energy Regulatory Commission 

(FERC) reports that six regasification terminals currently import LNG into the 

continental United States. According to the EIA, total U.S. LNG-importing capacity will 

grow from 1.5 Tcf in 2006 to 5.2 Tcf in 2009 with the completion of two new receiving 

terminals and several facility expansions.51 Although these projections indicate U.S. 

infrastructure will remain capable of importing a steadily increasing supply of LNG, 

NERC suggests that actual imports “will depend on relative global prices.”52

EIA anticipates a significant increase in global LNG liquefaction capacity in 2009. 

However, continuing natural gas demand growth and higher relative prices in Europe and 

Asia are expected to attract much of the new supply. In its August Short-Term Energy 

Outlook, EIA notes that the futures price of natural gas for January 2009 delivery in the 

United Kingdom (as reported on the Intercontinental Exchange) is about double the 

futures price for natural gas in January 2009 on the New York Mercantile Exchange 

(NYMX). Accordingly, EIA has been adjusting its near-term forecast for LNG imports 

to the United States. In its August Short-Term Forecast, EIS indicates it expects U.S. 

LNG imports fall from 2007’s 771 Bcf to only 390 billion cubic feet (Bcf) in 2008 and 

480 Bcf in 2009. 

The EIA’s longer-term projections indicate natural gas will continue contributing 

approximately 20 percent of the total U.S. electricity generation through 2017. However, 

certain legislation leading to a substantial increase of natural gas use for electricity 

generation could have detrimental effects on electricity reliability as well as the economy. 

Consider a recent EIA-conducted analysis of the proposed Lieberman-Warner Climate 

 

51 DOE/EIA, Annual Energy Outlook 2008, p. 78 (June 2008). 

52 Id. p. 16. 
14

Security Act (S. 2191) which stated that the affects of the bill would require nearly twice 

as much natural gas generation by 2030 without a widespread availability of carbon 

capture and storage (CCS) technology.53 Doubling the U.S. natural gas-fired generation 

would require additional LNG imports. However, the EIA stresses the “uncertainty in 

future domestic and overseas natural gas prices.”54 A separate recent report by EPA 

warns that: “Among other effects, a large policy-forced shift towards increased reliance 

on imported LNG would raise energy security and economic concerns by raising 

domestic prices for consumers (including electricity prices) and increasing U.S. reliance 

on foreign sources of energy.”55 Without EIA’s-projected increases in net coal and 

nuclear generation, an additional 2.1 Tcf per year would be needed to provide sufficient 

natural gas-fired generation in 2020.56 Accordingly, the premature closures of existing 

coal or nuclear generation facilities, whether the result of a cooling tower mandate or of 

any other regulatory measure, could require substantial additional generating units 

dependent on LNG imports that are vulnerable to potentially higher global prices. 

Renewable Generation 

DOE strongly supports research, development, demonstration, and commercial 

penetration of renewable energy for electricity generation. While hydroelectric 

generation has long been the largest source of renewable generation, future growth is 

limited due to a lack of appropriate sites (see Figure 2-4).57 Alternatively, non-hydro 

renewables is seeing significant growth due to 25 States and the District of Columbia 

having “renewable portfolio standards” (RPS) that mandate future minimum levels of 

electric generation from renewables. RPS initiatives generally require that a specific 

percentage of a utility’s electricity be generated with non-hydroelectric renewable 

sources by a certain date in the future. If fully met, these existing mandates will require 

about 61 GW of new renewables by 2025, or about 15 percent of projected electricity 

demand growth.58 While biomass, geothermal, small hydro and now some beginnings of 

solar usage have been built due to the State mandates, wind has captured 93 percent of 

the RPS capacity additions. Wind power’s contribution has risen significantly throughout 

the past decade providing 10 times more generation compared to a decade ago. EIA’s 

monthly analysis reported wind generation’s year-to-date generation April 2008 was 38 

 

53 DOE/EIA, Energy Market and Economic Impacts of S. 2191, the Lieberman-Warner Climate Security 

Act of 2007, p 25. 

54 DOE/EIA, Annual Energy Outlook, 2008 (June, 2008) p. 79. According to the EIA, “given the 

uncertainty in future domestic and overseas natural gas prices, the level of future U.S. LNG imports is 

highly uncertain. In the high price case, the higher world crude oil price is expected to result in increased 

natural gas consumption in overseas energy markets, exerting upward pressure on LNG prices. In addition, 

some LNG contract prices are tied directly to crude oil prices. Higher crude oil prices will also [place] 

additional pressure on world natural gas supplies. Collectively, these activities are expected to increase 

overseas wellhead natural gas prices and worldwide LNG prices, reducing both domestic natural gas 

consumption and LNG imports in the United States.” 

55 EPA, Regulating Greenhouse Gas Emissions under the Clean Air Act, p. 39. 

56 Assumes nuclear and coal remain at 2008 capacity levels, less planned retirements, and operate at 

capacity factors consistent with Annual Energy Outlook 2008 values. Generation from missing coal and 

nuclear is assumed to be made up by natural gas combined cycle with 50 percent capacity factor. 

57 DOE/EIA, Annual Energy Outlook 2008, p. 71 (June, 2008). 

58 Lawrence Berkeley National Lab, Renewable Portfolio Standards in the U.S.: A Status Report, p. 1 

(April 2008). 
15

percent higher than April 2007, and 70 percent higher than April 2006. Wind power 

accounted for only 0.77percent of total U.S. generation in 2007, though it is expected to 

account for more in the future.59

Figure 2-4. Renewable Electricity Generation 

(billion kilowatthours)

Figure 2-5. Wind Plant Nameplate and 2008 

Summer Peak Capacity 

 

DOE recently released a report which explores the impacts of strengthening wind’s 

contribution so that it can provide 20 percent of America’s electricity by 2030. In order 

to meet this scenario, wind capacity would need to grow from its 2006 level of about 11.5 

GW to about 305 GW by 2030.60 NERC expects a large expansion of wind power as a 

result of recently implemented RPS and other similar forms of legislation in over 25 

States.61

 

Wind generation is intermittent, which poses operational challenges for grid operators 

when the installed wind percentage is high. However, diversification of wind facilities 

over large geographic areas in the same grid will do much to balance the intermittency of 

particular wind farms. Nevertheless, a persistent concern is the need for improved or new 

transmission to bring remote wind power to consumers. Until advanced storage 

technology is developed along with new grid balancing mechanisms, wind farms will 

have an only limited ability to provide firm power without other forms of generation to 

ensure a steady flow of power to the grid. This is especially crucial on hot summer days, 

when higher temperatures thwart ideal wind conditions. 

Electricity Generation Challenges 

The U.S. electricity industry faces major challenges during the next 15 years to keep 

adequate reserve capacity margins of electricity generation available to meet peak 

demand growth, even if that peak demand growth is dampened by initiatives focused on 

demand-response, improved technology, and energy efficiency. 

 

59 DOE/EIA, Electric Power Monthly, pp. 15, 16 (April, 2008). 

60 DOE, 20% Wind Energy by 2030, p. 7 (May 2008)

61 NERC, 2008 Summer Reliability Assessment, p. 17 (May, 2008). 
16

Figure 2-6. Electricity Generation by Fuel 

1980 – 2020 (billion kilowatthours) 

 

With little additional hydroelectric or hydrokinetic generation and only modest growth in 

nuclear power expected by 2020, EIA projects new electricity demand will be met 

primarily by coal (Figure 2-6). Although there is strong DOE support for research and 

demonstration of CCS technologies, significant penetration of commercial-scale CCS 

projects is not expected until after 2020. 

Should EIA’s projections for net capacity additions of coal-fired plants fail to materialize, 

increased imports of LNG will be needed to fire natural gas generation in order to make 

up this shortfall. Policies that result in premature closures of existing power plants, 

whether the result of a cooling tower mandate, carbon limitations, or other requirements, 

will result in a likely boost to U.S. reliance on imported LNG during this period. If EIA’s 

projected increases in net coal and nuclear generation do not occur, an additional 2.1 Tcf 

per year would be needed to provide natural gas-fired generation in 2020.62 Accordingly, 

the premature closures of existing coal or nuclear generation facilities, whether the result 

of a cooling tower mandate or any other regulatory measure, would require additional 

generating units that will be dependent on imports of LNG. 

Finally, a primary goal for electricity planners must include a continuation of providing 

reliable electricity to meet demand with an adequate reserve margin. Increasing reliance 

on just one or two new generation sources, such as natural gas and wind, will require 

careful planning to ensure that enough new pipeline and transmission facilities are 

completed in a timely manner. 

 

62 Assumes nuclear and coal remain at 2008 capacity levels, less planned retirements and operate at 

capacity factors consistent with Annual Energy Outlook 2008 values. Generation from missing coal and 

nuclear is assumed to be made up by NGCC with 50 percent capacity factor. 
17

Chapter 3: Analysis of Wide-Scale Retrofit of Cooling Systems 

at Existing Electric Generating Facilities 

Identification of Affected Facilities 

Using information available to the public, DOE reviewed facility design and operations 

data to identify a subset of the existing fleet of thermoelectric power plants that are 

equipped with once-through cooling systems and withdraw cooling water on an annual 

average basis at a rate of 50 million gallons per day (MGD) or more. DOE reviewed 

cooling system performance information from EIA Form 767, Steam-Electric Plant 

Operation and Design Report, for fossil-fueled and nuclear powered thermoelectric 

generating facilities. DOE used the most current data available. For fossil-based units, 

data represent operations for the year 2005. For nuclear plants, data represent operations 

for the year 2000.63 Furthermore, due to insufficient forecasted load data (see Table 3-6, 

below), Hawaii and Alaska are excluded from this analysis, as well as the analysis 

conducted by NERC. 

Due to the limited scope of this analysis, DOE relied on existing information. DOE 

constrained its analysis to only those facilities where cooling system data were available, 

i.e., facilities with nameplate capacity greater than 100 MW. To understand the 

magnitude of impact that smaller facilities could have, DOE attempted to estimate the 

number of facilities below 100 MW that may meet or exceed the 50 MGD threshold and 

the aggregate fraction of electric generating capacity those facilities represent of the 

NERC region in which they are located. DOE estimates that approximately 160 

additional plants (those in the 60-70 MW range or larger) with a combined generating 

capacity of nearly 17 GW may withdraw cooling water above the threshold. While large 

in number, on average these facilities represent 1-2 percent of the projected 2015 

generating capacity of the respective NERC region in which they are located.64 While 

DOE believes that a thorough analysis of the impact of a restrictive 316(b) rule should 

 

63 While EIA Form 767 is considered to be one of the most extensive sets of design and operational data for 

the Nation’s thermoelectric generating fleet, it is not exhaustive. Cooling system data considered for this 

analysis are required to be reported (EIA Form 767 – Schedule 6) only by facilities with a nameplate 

capacity greater than or equal to 100 MW. Furthermore, due to the reporting requirements and data format, 

there is no direct link between cooling system data and generator output. As a result, for facilities with 

multiple boiler/generator/cooling system combinations, there is some remaining uncertainty regarding total 

capacity served by each cooling system and therefore some uncertainty related to affected capacity. 

However, DOE believes there is sufficient information to correlate cooling systems to plant output and to 

differentiate between thermoelectric generation and combustion turbine generation. In instances where 

data-gaps were identified, DOE used other data sources (public and private) to verify or validate 

correlations where possible. EIA has discontinued or altered data collection activities over the past decade, 

removing nuclear facilities after data year 2000 and discontinuing data collection for Form 767 altogether 

for all facilities after data year 2005. For more information related to EIA’s data collection and reporting 

activities see http://www.eia.doe.gov/cneaf/electricity/page/eia767.html. 

64 Two notable exceptions are Hawaii, where these smaller units approach one-third of the projected 2015 

generating capacity, and Alaska, where nearly all of the units are less than 100 MW. Due to a lack of 

facility design information of suitable detail, no conclusions can be made as to potentially affected 

facilities. 
18

consider these smaller plants that may be required to comply, the available data do not 

provide sufficient information to draw conclusions in this analysis. 

DOE identified 391existing thermoelectric plants that meet the > 50 MGD criterion. In 

order to account for facilities that were retired between the time of data submission to 

EIA (April 30 following the data year) and the present, DOE compared the identified 

subset of affected facilities to the present day operating fleet identified in the Ventyx 

Energy Velocity Database.65 This comparison resulted in slightly reduced numbers of 

affected facilities. This subset of 385 affected plants was aggregated on the basis of the 

NERC Sub-Regions and is presented in Table 3-1. Figure 3-1 graphically illustrates the 

percentage of currently installed and operating electric generating facilities that are 

affected in each NERC region. 

 

65 http://www1.ventyx.com/velocity/vs-overview.asp 
19

Table 3-1. AFFECTED FACILITIES 

Number of Plants and Aggregate Generating Capacity with Average Daily 

Cooling Water Withdrawals > 50 MGD 

Fossil Steam1 Nuclear2Total 

Region SubRegion 

Number of 

Plants3

Capacity, 

MW4

Number of 

Plants3

Capacity, 

MW4

Number of 

Plants3

Capacity, 

MW4

ERCOT ERCOT 28 27,576 1 2,430 29 30,006 

FRCC FRCC 18 12,191 2 2,590 20 14,781 

HAWAII HI/HISR N/A N/A N/A N/A N/A N/A 

MRO US MRO 36 13,180 5 3,519 41 16,698 

NPCC ISO NE 20 9,170 4 4,646 24 13,817 

NPCC NY 21 15,349 5 4,343 26 19,692 

RFC RFC 98 62,220 10 15,867 108 78,087 

SERC Entergy 18 16,607 2 2,102 20 18,709 

SERC Gateway 15 12,126 1 985 16 13,111 

SERC Southern 17 10,344 0 0 17 10,344 

SERC TVA 19 17,820 2 5,973 21 23,793 

SERC VACAR 21 14,925 7 12,335 28 27,260 

SPP SPP North 10 5,138 1 1,237 11 6,375 

SPP SPP South 3 1,023 0 0 3 1,023 

WECC AZNMSNV 1 74 0 0 1 74 

WECC CA 15 13,528 2 4,555 17 18,083 

WECC NWPP 2 631 0 0 2 631 

WECC RMPA 1 40 0 0 1 40 

Total 343 231,942 42 60,582 385 292,524

Notes: 1. Data based on EIA Form 767 (Steam-Electric Plant Operation And Design Report) – Year 2005 Data adjusted for 

 retirements since 2005 using the Ventyx Energy Velocity Database. 

 2. Data based on EIA Form 767 – Year 2000 Data. For Year 2001 and beyond, EIA did not publish operational data 

 for Nuclear Facilities 

 3. Based on EIA Plant Government ID. 

 4. Capacity represents the total electrical generating capacity (MW) cooled by the associated cooling system. For 

 combined cycle systems, only the steam cycle generating capacity is captured here. 
20

Figure 3-1. AFFECTED FACILITIES 

Percent of Existing Installed Operating Capacity (Affected MW/Existing MW) 
21

To assess the impact of retrofitting to recirculating wet cooling towers at the identified 

plants, DOE relied extensively on prior work conducted by NETL during EPA’s earlier 

316(b) activities.66 For fossil-fueled thermoelectric plants, NETL used the estimated 

energy penalties for the geographic regions developed for the 2002 Energy Penalty 

Analysis. NETL did not estimate energy penalties for nuclear fueled facilities in the 

earlier 2002 report. For this analysis, DOE estimated the energy penalty for nuclear 

plants by adjusting the fossil energy penalties based on information obtained in the public 

literature.67 Energy penalties used in this analysis for fossil- and nuclear-fueled plants are 

presented in Table 3-2. 

Table 3-2. Energy Penalty Assumptions 

Derate from Nameplate Capacity Resulting from Retrofit of Once-Through Facility to Recirculating Wet 

Cooling Towers 

Fossil1 Nuclear2

Region 

Annual Average 

Energy Penalty, % 

Reduction in 

Nameplate 

Capacity 

1% Highest 

Energy Penalty, % 

Reduction in 

Nameplate 

Capacity 

Annual Average 

Energy Penalty, % 

Reduction in 

Nameplate 

Capacity 

1% Highest 

Energy Penalty, % 

Reduction in 

Nameplate 

Capacity 

Delaware River Basin 1.18 3.12 1.48 3.90 

Michigan/Great Lakes 1.47 3.08 1.84 3.85 

Ohio River Valley 1.14 2.98 1.43 3.73 

South 0.82 2.41 1.03 3.01 

South West 0.80 2.06 1.00 2.58 

Notes: 1. Source: NETL, Energy Penalty Analysis of Possible Cooling Water Intake Structure 

 Requirements on Existing Coal-Fired Power Plants, October 2002 

 2. Assumes energy penalty for nuclear plants is ~25% greater than that of a fossil plant.

Using the energy penalties identified in Table 3-2, DOE applied these factors to each 

affected facility based on the State in which the plant is located.68 Estimates of energy 

penalties for each NERC sub-region were applied for both the annual average basis as 

well as for the one-percent-highest temperature basis. Table 3-3 presents the total 

capacity derate as well as remaining thermoelectric capacity for each NERC sub-region if 

all affected facilities (as indicated in Table 3-1) were required to retrofit from oncethrough cooling systems to wet cooling towers. 

 

66 For this analysis, DOE did not consider retrofitting once-through cooling to dry-cooling systems. 

Retrofit of a dry system would result in a greater energy penalty, reduced reliability, and higher economic 

cost. The impact of requiring such a retrofit would be greater (worse) than the results presented here. 

67 Veil, J.A., J.C. VanKuiken, S. Folga, and J.L. Gillette, Impact on the Steam Electric Power Industry of 

Deleting Section 316(a) of the Clean Water Act: Energy and Environmental Impacts, Argonne National 

Laboratory Report ANL/EAIS-5 (January 1993). 

68 Energy penalties were applied to units in each State based on a “best-fit” assumption of the climate 

conditions (temperature and humidity) of the representative regions considered in the DOE Energy Penalty 

Analysis. For States that did not fit into one of the existing representative regions, the energy penalty was 

averaged across two regions that were considered closest to the climate conditions of the State in question. 
22

Table 3-3. Impact of Energy Penalty Due To Cooling Tower Retrofits At All Affected Facilities 

Capacity Derate at Affected Facilities 

Annual Average Energy Penalty Highest 1% Ambient Condition 

Region Sub- Region Capacity Derate, MW Removed From the Grid Remaining Capacity, MW % Capacity Reduction Capacity Derate, MW Removed From the Grid Remaining Capacity, MW % Cap

Redu

ERCOT ERCOT 251 29,755 0.8% 738 29,268 2.5FRCC FRCC 127 14,654 0.9% 372 14,409 2.5HAWAII HI/HISR N/A N/A N/A N/A N/A N/MRO US MRO 236 16,462 1.4% 519 16,179 3.1NPCC ISO NE 179 13,638 1.3% 467 13,350 3.4NPCC NY 238 19,454 1.2% 634 19,058 3.2RFC RFC 1,235 76,852 1.6% 2,674 75,413 3.4SERC Entergy 170 18,539 0.9% 487 18,222 2.6SERC Gateway 154 12,957 1.2% 404 12,707 3.1SERC Southern 85 10,259 0.8% 249 10,095 2.4SERC TVA 217 23,576 0.9% 626 23,167 2.6SERC VACAR 271 26,989 1.0% 765 26,495 2.8SPP SPP North 77 6,298 1.2% 202 6,173 3.2SPP SPP South 8 1,015 0.8% 24 999 2.3WECC AZNMSNV 1 73 1.4% 2 72 2.7WECC CA 161 17,922 0.9% 446 17,637 2.5WECC NWPP 9 622 1.4% 19 612 3.0WECC RMPA 0 40 0.0% 1 39 2.5Total 3,419 289,105 1.2% 8,629 283,895 2.9
23

The Remaining Capacity columns in Table 3-3 represent the remaining capacity of the 

derated affected facilities once the energy penalty is applied to each unit, assuming that 

all affected facilities undergo a cooling system retrofit. 

Scenario Analysis – Retrofit and Retirement Assumptions 

Without a plant-by-plant investigation, DOE does not have meaningful information that 

would allow a projection of which of the facilities subject to a retrofit mandate would not 

be retrofitted for economic reasons. Generally, older units may not have sufficient useful 

operating life remaining to recover the retrofit investment. Also, less efficient generation 

facilities may not be operated enough hours of the year to justify the retrofit investment. 

Therefore, the assumption of retiring all affected units with 35 percent or less utilization 

rate is used in this analysis as a proxy for retirements of all combustion generation units 

for both economic and siting reasons. Admittedly, the assumption likely underestimates 

the potential impact to many of the older baseload coal units.69

 

 1. Economic Retirements 

The new capital and higher operating costs associated with retrofitting a once-through 

cooling system may make it uneconomic for a plant to undergo a cooling system retrofit. 

DOE did not conduct an economic impact analysis of the capital and operating costs70

associated with the retrofits as part of this analysis, nor did DOE consider the impact of 

increased capital and operating expenses on the economic dispatch of affected facilities 

and how that would impact the security and reliability of the Nation’s grid. However, to 

provide a high-level view of potential economic impacts to financially marginal plants, a 

preliminary assessment was considered where capacity factor (CF) was used as a proxy 

for plants that may not be economic to retrofit. 

The use of the capacity factor as a proxy for economic viability is assumed reasonable for 

this preliminary, order-of-magnitude analysis. Many factors would need to be considered 

to assess the economic viability at each individual plant, including typical costs 

associated with cooling equipment, balance of plant modifications, and engineering 

(including design safety margins, potentially applicable to nuclear facilities) and 

construction. Furthermore, permitting costs, land acquisition costs, and other “soft” costs 

 

69 Discussions with the Electric Power Research Institute (EPRI) provided several examples of coal fired 

facilities that appear likely to be at risk because of site specific considerations. While not intended as an 

exhaustive list, it clearly shows that all thermal generation units, including coal, may have site-specific 

constraints that could make compliance very difficult. 

70 While this analysis did not estimate facility costs of cooling tower retrofits, a recent NETL study (NETL, 

Cost and Performance Baseline for Fossil Energy Plants, Volume 1, DOE/NETL-2007/1281, August 2007, 

(http://www.netl.doe.gov/energy-analyses/pubs/Bituminous%20Baseline_Final%20Report.pdf ) identified 

recirculating wet cooling tower system costs at a greenfield facility of approximately $70/kW for a 

thermoelectric plant and $35/kW for a combined cycle plant. Considering that retrofit installations can be 

somewhat more difficult and costly than a greenfield construction, the costs associated with a complete 

cooling system retrofit could range as high as $100//kW. For a nominal 500 MW facility, retrofit costs 

could range from roughly $17.5 Million - $50 Million. 
24 

may also be relevant to the economic viability. Detailed analysis of individual factors on 

a plant-by-plant basis is beyond the scope of this analysis. However, potential space 

constraints are examined on a limited basis later in this report. 

 

Similarly, this analysis did not attempt to project future costs to comply with other 

potential regulations, such as new ambient air standards and carbon reduction. Such 

other factors faced by individual generating facilities may result in early retirement not 

captured in this analysis and subsequently the total impact of a 316(b) rule could be even 

further underestimated. Ultimately, such facility-specific issues (both physical and 

economic) should be evaluated thoroughly prior to a final rule. 

 2. Siting/Permitting Retirements 

• Siting Constraints 

In addition to the nationwide NERC region analysis of capacity loses due to economic 

retirements, DOE also recognized the potential for capacity losses due to space 

limitations at existing facilities. While DOE identified a set of potentially affected 

facilities (see Table 3-1, row no. 6), it may not be feasible to retrofit the identified 

facilities because of land and space constraints. The New York (NY) NERC sub-region 

was used as an initial sample to evaluate potential space constraints for building the 

recirculating cooling retrofits. This region was chosen because it is highly urbanized and 

many of its generating units are within densely populated areas. The 26 identified 

facilities in the NY sub-region included in Table 3-1 were visually assessed using 

publically available satellite images. 

The visual analysis was used to qualitatively identify obvious land constraints for a 

recirculating cooing system retrofit and did not consider any detailed surface features or 

ownership of any adjacent land. From the aerial view, it was determined that at least 

three of the 26 plants located in the NY sub-region have apparent land constraint issues. 

The three plants produce a total of 3,066 MW and have capacity factors greater than 60 

percent. Figure 3-4 is a Google aerial view of the Ravenswood plant along the East River 

in Queens, New York City. The plant produces 1,827 MW with natural gas- or oil-fired 

steam turbines and uses once-through cooling. The overall plant area is heavily crowded, 

constrained by the river on the west, buildings to the north, east and south, and by a park 

to the southwest. The plant site itself is congested by many buildings a substation 

switchyard and parking lots. 
25 

Figure 3-4. Land Constrained Plant – Ravenswood Plant71

Using the capacity factor criteria as a proxy for retirement, two of the three units at the 

Ravenswood plant would be retrofit and continue to operate. However, the aerial image 

suggests that there may be significant facility-specific constraints to the retrofit of a 

recirculating cooling system. 

New York City is perhaps the country’s most highly congested load pocket, with peak 

summer locational prices regularly exceeding $1,000/MW. Removing 1,000 MW or 

more from the city would have obvious deleterious consequences, for both price and 

associated power scarcity. Other plants that share the space and logistical constraints of 

Ravenswood may have similar value to their regions. 

• Permitting Constraints 

This analysis is not able to reach quantitative conclusions on the location and number of 

facilities that could not obtain the requisite permits and water rights required to construct 

cooling towers. For example, the 482-MW Mirant Potomac River Power located next to 

the flight path into Ronald Reagan Washington National Airport and which supplies 

electric power to much of downtown Washington, D.C., would be unlikely to install 

cooling towers due to both space and permit restrictions. 

 

71 Source: Google Maps, http://maps.google.com , last accessed June 2008. 
26 

Estimate of Generation Capacity Losses 

Using the assumptions for energy penalty and retirements discussed above, three cases 

were considered: 

• Case 1 – 100 percent retrofit; 

• Case 2 – Only facilities with a capacity factor greater than 25 percent would 

retrofit, those below the 25 percent capacity factor threshold were assumed to 

retire; and 

• Case 3 – Only facilities with annual capacity factor greater than 35 percent would 

retrofit, those below the 35 percent capacity factor threshold were assumed to 

retire. 

The rationale for capacity factors as a proxy for economic viability is that it is assumed 

that plants with low average annual capacity factors are uneconomical to dispatch and are 

therefore candidates for retirement. Some of these plants, however, may be operated 

relatively intensively during peak months, especially those near areas of high demand. 

In conducting the analysis, DOE considered a retirement range, where the low retirement 

case (Case 2) and high retirement case (Case 3) were bracketed by the upper and lower 

bounds of two conceptual approaches to the capacity factor.72 The first concept, CF1, 

based as reported by EIA on the Form 767, is percentage annual hours that the affected 

boiler unit is online, that is: 

CF1 = hours of boiler unit operation/8760 

The second concept, CF2, refers to generation as a percentage of nameplate capacity, or 

to asset utilization as a percentage of its potential output, namely: 

CF2 = annual generation (Mwh)/(capacity (MW) x 8760), where 8760 is the total number 

of hours in a year. 

 

72 The two concepts are derived from the type of data reported in EIA Form 767, specifically “Boiler Hours 

Under Load” and “Total Net Electrical Generation - Annual”. As the illustration indicates, the two 

concepts result in different conclusions when used as a proxy for economic viability of a cooling system 

retrofit. For the cases considered here, the limiting concept was applied (i.e., CF1 for the low retirement 

case and CF2 for the high retirement case). 
27 

An example of the difference between CF1 and CF2 can be illustrated by Units 2 and 3 of 

the Arthur Kill generating station in New York. Both units are steam turbines fueled by 

natural gas. Their 2005 output is given below: 

Table 3-4. Example Comparison of Capacity Factor Concepts 

Unit Nameplate 

Capacity 

2005 Generation 

(MWh) 

Unit Load Capacity 

Factor (CF1) 

Annual Generation 

Capacity Factor 

(CF2) 

Arthur Kill Unit 2 376 752,902 0.75 0.23 

Arthur Kill Unit 3 536 605,337 0.41 0.13 

Based on CF1, neither unit would be retired; based on CF2, both would be. An attempt 

was made to see whether reported locational marginal prices of the NYISO justified the 

operation of plants with CF2 < 0.35. The exercise indicated these plants did not make 

profits from energy revenues, but DOE had no way of determining whether such plants 

received ancillary payments or other reimbursements for reserve status, etc. Thus the 

question of whether any given plant is economic can not be answered by this analysis. 

Nonetheless, the 35 percent threshold for CF2 may serve as a useful threshold for 

economically constrained units. 

For each NERC region, DOE evaluated the possible loss of system capacity from unit 

retirement and de-rate occurring at the highest ambient conditions at the remaining 

retrofitted facilities. The lost capacity was then compared to the expected 2015 regional 

capacity and load from the Energy Velocity database, which in turn is based on the 

NERC 2007 Long-Term Reliability Assessment. Results from the three cases for the 

NERC regions and the WECC-California, New York-ISO, and ISO-New England subregions are presented in Table 3-5. 
28

Table 3-5. Potential Loss of Generating Capacity in 2015, Selected NERC Regions 

Case 1 Case 2 C

Region 

2015 

Expected 

Capacity 

(MW) 

Derate at 

Retrofitted 

Facilities 

(MW) 

Percent 

Reduction of 

2015 Expected 

Capacity 

Retired 

Capacity 

(MW) 

Derate at 

Retrofitted 

Facilities 

(MW) 

Percent 

Reduction of 

2015 Expected 

Capacity 

Retired 

Capacity 

(MW) 

De

Ret

Fac

(

WECC-CA 59,694 -446 -0.7% -8,798 -246 -15.2% -13,128 -

WECC-TOT 151,136 -468 -0.3% -8,912 -265 -6.1% -13,242 -

ERCOT 81,307 -738 -0.9% -15,129 -373 -19.1% -19,776 -

RFC 222,732 -2636 -1.2% -3,152 -2,541 -2.6% -7,179 -2

SERC 254,993 -2531 -1.0% -4,796 -2,413 -2.8% -16,194 -2

NYISO 33,353 -634 -1.9% -3,307 -532 -11.5% -8,708 -

ISO-NE 30,056 -467 -1.6% -2,091 -402 -8.3% -5,040 -

NPCC-US 63,410 -1,101 -1.7% -5,398 -934 -10.0% -13,748 -

MRO 47,545 -519 -1.1% -240 -511 -1.6% -529 -

SPP 55,583 -222 -0.4% -817 -201 -1.8% -1,166 -

HAWAII N/A N/A N/A N/A N/A N/A N/A 

FRCC 59,473 -372 -0.6% -303 -365 -1.1% -3,114 -

These losses can be compared to regional capacity and expected load in, say, 2015, which could be a compliance 316(b) rule. Table 3-6 compares the remaining capacity for the regions evaluated with the expected load for 201

illustrates the remaining capacity margins for each of the regions evaluated, and compares the scenario results to capacity margin absent a restrictive 316(b) ruling (No Rule). 
29 

 Table 3-6. Capacity Loss and Capacity Margins 

Remaining Capacity (MW) Capacity Margins3 (Perce

Region 

2015 

Expected 

Capacity 

(MW)1 Case 1 Case 2 Case 3 

2015 

Expected 

Load 

(MW)2 Case 1 Case 2 Case 3 

WECC-CA 59,694 59,248 50,650 46,417 64,308 -9% -27% -39% WECC-TOT 151,136 150,668 141,959 137,726 156,408 -4% -10% -14% ERCOT 81,307 80,569 65,805 61,270 74,471 8% -13% -22% RFC 222,732 220,096 217,039 213,130 202,400 8% 7% 5% SERC 254,993 252,462 247,784 236,664 229,636 9% 7% 3% NYISO 33,353 32,719 29,514 24,281 35,669 -9% -21% -47% ISO-NE 30,056 29,589 27,563 24,706 31,510 -6% -14% -28% NPCC-US 63,410 62,309 57,078 48,988 67,179 -8% -18% -37% MRO 47,545 47,026 46,794 46,514 49,615 -6% -6% -7% SPP 55,583 55,361 54,565 54,224 48,934 12% 10% 10% HAWAII N/A N/A N/A N/A N/A5 N/A N/A N/A FRCC 59,473 59,101 58,805 56,062 52,266 12% 11% 7% Notes: 1. 2015 expected capacity per EV database, 6/2008. Expected capacity = operating capacity+standby+under construction+permitted, as of 8/2. 2015 expected load derived from NERC forecast Net Internal Demand, EV database 6/2008. Does not include proposed plants that did no

permits as of 8/2008. 3. Capacity Margins used here is calculated for each NERC region as [1 – (2015 Remaining Capacity/2015 Expected Load) x 100]. It does noelectricity imports, firm or otherwise. 4. NERC, 2007 Long-Term Reliability Assessment 2007-2016, October 2007. 5. Hawaii did not report forecast load. 

Figure 3-2 graphically presents the results from the three cases and the NERC LTRA. Adequate additional electrtransmission capacity is required to meet unanticipated demand or unplanned facility losses. Surplus electric genrequired that may quickly be dispatched to match load and to maintain system reliability. The amount of capacitexpressed as a percent of peak demand, is called the net capacity reserve margin or reserve margin. Reliable systa net reserve margin (native generation plus contracted imports) of 10 to 15 percent. The percentage of reserve mappropriate for a control area varies depending on the generation mix, the load variability, and the interconnectivthat of adjacent systems. Reserve margin may, or may not, include capacity generated outside the control area. Tpresented in this paper do not include capacity generated outside the control area. 
30 

Figure 3-2. NERC Region Map - Potential 2015 Capacity Margins 

NYISO 

 -9% Case 1 -21% Case2 -47% Case 3 

 -4% Case 1 -10% Case 2 -14% Case 3 

 8% Case1 -13% Case 2 -22% Case3 

 8% Case 1  7% Case 2  5% Case 3 

 9% Case 1  7% Case 2  3% Case 3 

 -8% -18% -37% 

-6% Case 1 -6% Case 2 -7% Case 3 

12% Case 1 10% Case 2 10% Case 3 

WECC-CA 

 -9% Case 1 -27% Case 2 -39% Case 3 

12% Case 1 11% Case 2  7% Case 3 
31

Chapter 4: Electricity Reliability Scenario Analysis 

One measure of electricity reliability is the reserve capacity margin, which measures the 

bulk power system’s ability to satisfy consumers’ energy demand in the event of 

unplanned outages, inclement weather, or other problems. The Office of Electricity 

Delivery and Energy Reliability requested that NERC assess the reliability impacts that 

would result from reduced reserve capacity due to retrofitting and retirement cases 

described in Chapter 3, above. In response, NERC prepared a white paper entitled, 

“2008-2017 NERC Capacity Margins: Retrofit of Once-Through Cooling Systems at 

Existing Generation Facilities” (NERC White Paper), which is provided as an appendix 

to this analysis. 

NERC’s analysis evaluates the different reserve capacity margins resulting from a 

reference case with no system changes and a case where the effects of implementing 

316(b) regulations are simulated. DOE requested that NERC assume, for purposes of 

their assessment, that closed-loop cooling systems will be added to all nuclear units, that 

generation facilities having less than a 35 percent capacity factor will be retired (Case 3) 

and that no replacement capacity will be built. DOE did not request that NERC evaluate 

the lower retirement case (Case 2), after concluding that the lower retirement case would 

simply provide results that would fall between the range of outcomes defined by no 

mandate and the more significant Case 3 scenario. 

NERC White Paper 

Using the assumptions defined by DOE for this assessment, NERC determined that 

capacity reductions due to auxiliary loads caused by equipment retrofitting are about 

9,300 MW. In addition, approximately 39,500 MW of capacity resources are eliminated 

by generation unit retirements under Case 3. NERC’s analysis concludes that, across all 

NERC U.S. regions, that the potential loss of 49,000 MW from the retrofitting energy 

penalties and premature unit retirements would reduce the NERC-US generation capacity 

resources by 4.3 percentage points. 

However, NERC emphasizes that the reductions in reserve capacity margin would be 

different in each region and have very different impacts on the electricity reliability in 

each region depending on the vintage and design of their units. (See NERC White Paper, 

Figure 3, and Figure 3-3, infra). NERC identified the regions with the highest generation 

capacity losses as Texas, New York/New England, California, and the Southeast. 

The WECC-CA US sub-region sees the largest impact with a reduction of 

almost 15 percent (10,400 MW), significantly reducing their summer peak 

capacity margin. NPCC-New England also experiences a significant 

impact of 10.3 percent. This impact may be the result of the abundant gasfire plants which have low capacity factors in this assessment indicating a 

retrofit would not be economically suitable. 
32 

ERCOT faces the most substantial impact at the regional level. 

Retirement and retrofit effects may result in a loss of up to 11,500 MW, 

reducing their margins almost 13 percent. 

Some regions starting above the NERC Reference Margin Level in the 

Reference Case fall below as a direct result of this analysis: ERCOT, RFC, 

and SERC. These regions may require additional resources to accommodate 

the potential retirements/retrofits from the Section 316b Phase II action. 

Similarly, the full region of SERC shows a total capacity reduction of 

about 9,300 MW, most coming from the SERC-Delta (South-Central U.S.) 

sub-region. However, the impact on the Adjusted Potential Resources 

capacity margin is only 3 percent due to its overall large demand and 

capacity base line in the Reference Case for the region. 

NERC also noted in its conclusions that transmission congestion and reliability might be 

aggravated and detailed system transmission studies may be needed to determine bulk 

power system reliability resulting from the loss of the specific units studied. 

Discussion 

The Nation’s electricity industry faces major challenges during the next decade or more 

to keep adequate reserve capacity margins of electricity generation available to meet peak 

demand growth, even if that peak demand growth is dampened by initiatives focused on 

demand-response, improved technology, and energy efficiency. 

With little increase in hydroelectric generation and only modest growth in nuclear power 

expected by 2020, EIA projects new electricity demand will be met primarily by coal and 

renewable energy. However, the magnitude of new coal generation that is actually put in 

service may be limited by siting restrictions, emissions limits, and RPS pressures. At this 

time, it does not appear that there will be significant penetration of commercial-scale 

CCS projects prior to 2020. Alternative energy and conservation will make important 

contributions in replacing lost generation. Nevertheless, it appears that combined-cycle 

natural gas generation, which is dependent on LNG imports on the margin, will be 

required to meet new electricity demand and to replace retirements of existing generation 

facilities, whether planned or the result of a cooling tower mandate or other regulatory 

measure. 

Regarding the existing fleet of thermoelectric power plants (fossil and nuclear combined), 

DOE estimates that over half – nearly 300 gigawatts (GW) – are equipped with oncethrough cooling systems. This represents 385 existing power plants that could be 

affected by 316(b) Phase II regulations. The majority of the affected facilities (roughly 

70 percent) are baseload steam plants, predominantly coal and nuclear facilities. The 

remaining 30 percent are mostly older, less efficient oil- and gas-fired steam units. 
33 

Since retrofitting to a recirculating cooling system at a facility originally designed for 

once-through cooling will result in reduced power output, this overall loss of capacity 

(energy penalty) has been modeled for this analysis. However, practical considerations 

did not permit this analysis to conduct a facility-by-facility investigation to determine 

how many facilities could not or would not meet the cooling tower mandate. Potential 

retirements due to economic considerations or site and permitting restrictions are roughly 

estimated by using a proxy assumption that the cooling tower mandate would cause the 

retirement of all affected units operating between 25 percent of the time or less, and 35 

percent of the time or less (see Table 3-5). Although this range of retirements may 

underestimate the amount of generation capacity that would be retired, it provides a 

perspective on the reliability impacts that would result from this range of plant 

retirements. 

Nuclear plants would be particularly impacted by a cooling tower mandate because reevaluation of the nuclear plant safety basis and Nuclear Regulatory Commission (NRC) 

licensing amendments would be required for existing nuclear reactors to comply with 

such a rule. This is in addition to the engineering, construction, outage, and power 

replacement impacts and loss of revenue similar to large, baseload coal plants. The 

licensing impact would be determined by the complexity of necessary design changes to 

safety and non-safety cooling systems, preparation of required license application 

documentation and supporting analyses, submission of the license amendment package, 

and the review and approval by the U.S. Nuclear Regulatory Commission. The potential 

for significant negative economic impact could influence utilities to not pursue further 

license renewals based on unfavorable financial returns, further reducing electricity grid 

operating margins. During Fiscal Year 2009, the Department of Energy will work with 

NRC and industry to better characterize the scope and impact of such a change to an 

operating nuclear plant. 

Although the proxies used in the DOE scenario analysis likely underestimate the potential 

impact of the mandate on many baseload coal and nuclear units, they are used in this 

analysis to provide rough approximations of possible retirement scenarios from a cooling 

tower mandate. The analysis indicates that, on a national basis, a cooling tower mandate 

would cause a relatively modest reduction (46,000 to 81,000 MW)73 in available 

generating capacity which has a total capacity of over 1,000,000 MWs. The U.S. does 

not have a national electricity grid, but rather a series of large regional power grids. The 

amount of reduced generation capacity and its impact on regional reliability would vary 

from region to region. While a number of NERC regions likely have adequate capacity 

margins to accommodate such a reduction, certain sub-regions, particularly the New 

York, New England, and California NERC sub-regions, could suffer significant capacity 

margin reductions. The overall impact of the decreased capacity margin could result in 

impaired reliability during critical periods (peak summer demand) in these already at-risk 

regions. 

Similarly, DOE’s independent analysis of changes in capacity margins for the NERC 

subregions demonstrated concerns for reliability in similar subregions. Note that in 

 

73 DOE’s total projected retired capacity plus derate from Cases 2 and 3. See Table 3-5. 
34 

DOE’s analysis it assumed no new generation would be constructed where NERC’s 

analysis assumed planned construction would go into service as scheduled. Nevertheless, 

DOE’s results are illustrative of the potential reliability issues that could occur under a 

cooling tower mandate. DOE’s results are depicted in Figure 4-1. 

Figure 4-1. Potential 2015 Capacity Margins for the three cases evaluated and from NERC’s 

Long Term Reliability Assessment (LTRA) 

-60%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

WECC-CA WECCTOTERCOT RFC SERC NYISO ISO-NE NPCC-US MRO SPP FRCC

Case 1 Case 2 Case 3 NERC LTRA

Case assumptions: Source: NETL, 2008 

• Includes only native generation 

• No new facilities constructed 

• No replacement of derated or retired 

Figure 4-1 clearly indicates that under this analysis, a national cooling tower mandate 

would result in a range of impacts to capacity margins across the various NERC regions. 

Many of the regions are significantly impacted, and ERCOT, NPCC, and WECC margins 

plunge in the worst case. Potentially more significant is that four of the eight regions 

(ERCOT, MRO, NPCC, and WECC) result in a capacity deficit in nearly all of the cases 

evaluated. These regions are affected more because of their relatively high use of older 

oil and gas steam turbines. 

Generally, older units may not have sufficient useful operating life remaining to recover 

the retrofit investment. Also, less efficient generation facilities may not be operated 

enough hours of the year, i.e., have too low a capacity factor, to justify the retrofit 

investment. Within the scope of this analysis, DOE cannot precisely estimate the 

number of existing generation facilities that would retire rather than meet retrofits 

required to meet new SOx, NOx, mercury, or carbon emission limits. However, it is clear 

that a significant number of base-load coal generation facilities will not be economic 

under the burden of the cumulative capital and operational costs of complying with new 
35 

air emissions limitations in addition to the capital costs and energy penalties caused by a 

cooling tower mandate. Similarly, some nuclear facilities may determine it is not 

economic to comply due to the cumulative costs of complying with such a rule, including 

amending their license and the loss of revenue during retrofit. 

If those generation facilities that could not or would not meet a mandatory cooling tower 

standard were retired, the loss of existing generation capacity would be in addition to the 

energy penalties that reduce the nameplate capacity of the facilities that do construct 

cooling towers, as discussed in Chapter 3. 

Construction of hundreds of cooling towers over the next six or so years would obligate 

financing, construction materials, and labor at a time when these resources are in 

competition with new energy infrastructure facilities needed to meet increasing demand 

while reducing ambient air emission and greenhouse gases. Construction would require a 

prolonged outage period for many existing units, as each unit is transitioned from one 

cooling system to another. Depending on when these outages occur, and for how long, 

the outages may jeopardize the ability of electricity suppliers to meet peak demand. 

These types of outages are typically scheduled during periods of reduced demand. 

Avoiding plant closures during peak demand periods may not be possible based on the 

deadlines of the mandate, time for permit approvals, or availability of construction firms 

and materials. Nuclear plants, in particular, may be forced to suspend generation for 

substantial periods during construction and tie-in of cooling towers. In its Phase I Report 

on Old Thermal Generation (2008-2012),” (February 2008), CAISO provided a detailed 

analysis of the reliability dangers caused by requiring too many facilities to retrofit or 

retire too quickly. 

The California Independent System Operator Corporation (CAISO) has been analyzing 

the impact of cooling tower mandates on electricity reliability in the State of California in 

response to actions by the California State Water Resources Control Board (SWRCB) 

proposing to implement section 316(b) for the State as a cooling tower mandate. In its 

February 2008 Old Thermal Generation Report, cited above, CAISO found that 

approximately 40 percent of California’s entire in-State generation capacity would be 

subject to SWRCB’s proposed cooling tower rules.74

In its comment letter to the SWRCB dated May 20, 2008,75 CAISO warns that increasing 

electricity imports into a region to replace loss of capacity from the loss of once-throughcooling generation with low utilization rates would create serious grid and delivery 

reliability problems, including voltage and frequency support, stabilization of system 

dynamics, emergency local power when import lines are interrupted, loss of critical back 

up (“Reliability Must Run”) units, and loss of WECC required Contingency Reserve 

capacity. 

Additionally, CAISO notes in its May 20 letter that units with low capacity factors that 

are capable of ramping, load flowing, and regulation services are increasingly important 

 

74 (http://www.caiso.com/1f80/1f80a4a5568f0.pdf) 

75 (http://www.waterboards.ca.gov/water_issues/programs/npdes/cwa316_may08_comments.shtml). 
36 

to achieve the reliable integration of increased wind and solar generation. Some of the 

once-through-cooling units that CAISO believes are “at risk from retirement [due to the 

SWRCB cooling tower mandate] are those expected to provide the services required to 

maintain reliable operation in order to accommodate wind power and renewable resource 

integration capability for ramping and load following.” CAISO concludes that the loss of 

these units may present serious reliability concerns, especially during peak conditions and 

localized emergencies, such as the 2007 San Diego fires, and increase the likelihood of 

localized blackouts or load shedding. 

Recently, WRCB announced further hearings, opportunities for public comment, and 

workshops prior to taking action on the once- through cooling ban. (Power Market 

Today, August 4, 2008.76

 

76 (http://www.waterboards.ca.gov/water_issues/programs/npdes/cwa316.shtml#otc). 
37 

Chapter 5: Conclusion 

 

 

A National mandate requiring the installation of cooling towers (recirculating water 

cooling) at all existing thermal electric generators with once-through-cooling of 50 MGD 

or greater would require construction of cooling towers at 385 existing fossil and nuclear 

electric generation facilities. The direct and indirect effects of this action would be to 

reduce electric generation capacity throughout the country at a time the electric industry 

faces major challenges to maintain adequate reserve margins. A loss of efficiency of 1 to 

4 percent would occur at each retrofitted electric generation unit due to increased 

ancillary load to power pumps, fans, and other equipment, and to the reduced efficiency 

of recirculated water compared to once-through cooling water. In addition, a number of 

existing facilities would be unable to retrofit to cooling towers because of space 

limitations or the inability to acquire requisite permits or water rights. For this analysis, 

it is assumed that those facilities would be required to cease operation. Also, owners of 

older less efficient units may choose to retire units rather than to complete the cooling 

tower retrofits, especially if other retrofits may also be required to meet new SOx, NOx, 

mercury, and carbon limits. 

DOE requested NERC to review the impact of retrofitting potentially affected facilities 

with existing once-through-cooling systems to closed-loop cooling systems. NERC 

assumed a 4 percent reduction in nameplate capacity of steam units due to the energy 

penalty of cooling tower systems combined with a presumed unit retirement if the 

capacity factor is less than 35 percent. The analysis was conducted NERC-wide for the 

period of 2008-2017. NERC concludes that nationally, net capacity reserve margins may 

be reduced up to 4.3 percentage points. Transmission congestion and reliability might be 

aggravated and detailed system transmission studies may be needed to determine bulk 

power system reliability resulting from the loss of the specific units studied. The 

congestion in the Mid-Atlantic Area National Interest Electric Transmission Corridor 

would likely be exacerbated 

The impact of this cumulative lost existing generation capacity would vary from region to 

region. The net capacity reduction would have a disproportionately large affect on those 

regions where reserve capacity is already low. This loss of generation capacity in 

combination with the early retirement of facilities that either cannot retrofit or choose for 

economic reasons not to retrofit may jeopardize the ability of California, New York, and 

New England to meet peak electric demand over the next decade. 

Construction of hundreds of cooling towers over the next six years would obligate 

financing, construction materials, and labor at a time when these resources are in 

competition with new energy infrastructure facilities needed to meet increasing demand 

while reducing ambient air emissions and greenhouse gases. Construction could require 

a prolonged outage period for some existing units as they are transitioned from one 

cooling method to another. Depending on the timing of these outages and their duration, 

they may jeopardize the ability of certain sub-regions to meet peak demand. 
38 

Finally, additional generation and transmission capacity would be required to replace the 

lost capacity caused by the outages during retrofit, lost efficiency, and forced or 

economic retirements. Some of that capacity may be replaced by conservation and 

demand response initiatives. Nevertheless, new conventional generation, some of it sited 

near the retired plants to maintain load-following capabilities, would also be required. 

Based on recent construction history, it is presumed that these conventional generation 

facilities would be natural gas-fired. This additional capacity may be dependent on LNG 

imports that are vulnerable to potentially high global prices. 
0

APPENDIX 
116-390 Village Blvd. 

Princeton, NJ 08540 

609.452.8060 | www.nerc.com

1 

2008-2017 NERC Capacity Margins: 

Retrofit of Once-Through Cooling Systems at 

Existing Generating Facilities 

Background 

The North American Electric Reliability Corporation’s (NERC) mission is to ensure the bulk 

power system in North America is reliable. To achieve this objective, NERC develops and 

enforces reliability standards; monitors the bulk power system; assesses and reports on future 

adequacy; evaluates owners, operators, and users for reliability preparedness; and offers education 

and certification programs to industry personnel. NERC is a non-profit, self-regulatory 

organization that relies on the diverse and collective expertise of industry participants that form its 

various committees and sub-committees. It is subject to oversight by governmental authorities in 

Canada and the United States (U.S.)77

 

NERC assesses and reports on the reliability and adequacy of the North American bulk power 

system divided into the eight regional areas. The users, owners, and operators of the bulk power 

system within these areas account for virtually all the electricity supplied in the U.S., Canada and a 

portion of Baja California, Mexico. 

 

77

 On June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce reliability standards 

with all U.S. owners, operators, and users of the bulk power system, and made compliance with those standards mandatory NERC has similar 

authority in Ontario and New Brunswick, and is seeking to extend that authority to the other Canadian provinces. NERC will seek recognition in 

Mexico once the necessary legislation is adopted. 

ERCOT 

Electric Reliability 

Council of Texas 

RFC

ReliabilityFirst 

Corporation 

FRCC 

Florida Reliability 

Coordinating Council 

SERC 

SERC Reliability 

Corporation 

MRO 

Midwest Reliability 

Organization 

SPP 

Southwest Power Pool, 

Incorporated 

NPCC 

Northeast Power 

Coordinating Council, 

Inc. 

WECC 

Western Electricity 

Coordinating Council 
2 

Capacity Resources & Margins

Net Internal Demand (MW) — Total Internal Demand reduced 

by dispatchable controllable (capacity) demand response. 

Total Internal Capacity — The Sum of Existing (both Certain 

and Uncertain) and Planned Capacity. 

Existing Capacity 

a) Certain — Existing capacity resources reasonably 

anticipated to be available and operate and that are 

deliverable to or into the region. 

b) Uncertain — Includes mothballed generation and portions 

of variable generation not included in “Certain” 

Planned Capacity — Capacity resources expected to be 

available for the 2008-2017 Summer peak conditions that have 

achieved one or more of the following milestones: 

a) Construction has started 

b) Regulatory permits approved 

c) Approved by corporate or appropriate senior management 

Proposed Capacity — Capacity resources not listed in the prior 

categories, but has been identified through one or more of the 

following sources: 

a) Corporate or appropriate senior management 

announcement 

b) Included in integrated resource plan 

c) Generator Interconnection Queues 

Capacity Purchases and Sales – the following categories may 

be applied to existing and future capacity calculations. 

a) Firm 

b) Non-Firm 

c) Expected 

d) Provisional 

Existing Capacity, Planned Capacity and Net Firm 

Transactions (MW) — Existing capacity resources reasonably 

anticipated to be available and operate and that are deliverable to 

or into the region plus net Firm Purchases/Sales. 

Net Capacity Resources (MW) — Total Internal Capacity, less 

Transmission-Limited Resources, all Derates, Energy Only, and 

Inoperable resources; plus net Firm, Expected and Provisional 

Purchases/Sales. Net Capacity Resources do not include NonFirm Purchases/Sales. 

Adjusted Potential Resources (MW) — Net Capacity 

Resources, Existing Uncertain Resources less all Derates, Total 

Proposed Resources reduced (multiplied) by a confidence factor 

(percentage); plus Net Non-Firm and Provisional Transactions.

Net Capacity Resources Margin (%) — Net Capacity 

Resources reduced by the Net Internal Demand; shown as a 

percent of Net Capacity Resources. 

Adjusted Potential Resources Margin (%) — Adjusted 

Potential Resources reduced by the Net Internal Demand; shown 

as a percent of Adjusted Potential Resources. 

NERC’s primary role in providing reliability 

assessment is to identify areas of concern to the 

reliability of the North American bulk power 

system and to make recommendations for their 

remedy. NERC cannot order construction of 

additional generation or transmission or adopt 

enforceable standards having that effect, as that 

authority is explicitly withheld by Section 215 of 

the U.S. Energy Policy Act of 200578. In addition, 

NERC does not make any projections or draw any 

conclusions regarding expected electricity prices 

or the efficiency of electricity markets. The 

enclosed Special Reliability Assessment provides 

a high-level view of future resource adequacy. 

Special Reliability Assessment79

Upon a request from the U.S. Department of 

Energy’s (DOE) Offices of both “Electricity and 

Energy Reliability” and “Fossil Energy,” NERC 

measured the affects on capacity margins 

resulting from retrofitting existing plants with 

open-loop cooling systems to closed-loop 

systems, or retiring them. This special reliability 

assessment is part of DOE’s response to the U.S. 

Senate Subcommittee on Energy and Water 

Appropriation’s request to identify the impacts of 

EPA’s rulemaking on Section 316b of the Clean 

Water Act. 

Approach - Preliminary 2008-2017 Long-Term 

Reliability Assessment data was used (Reference 

Case). The data includes U.S. summer peak 

demand and capacity. Though this data is subject 

to change, NERC does not believe any future data 

enhancements will materially change the 

assessment results. Specific unit information was 

received from the U.S. Department of Energy, 

and EPA Section 316b permitting dates were 

received from the Edison Electric Institute (EEI), 

providing the year a decision is required. 

 

78 http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=109_cong_bills&docid=f:h6enr.txt.pdf 

79 This Special Reliability Assessment was approved by NERC’s Board of Trustees on September 8, 2008
3 

Adjusted Potential Resources (MW) — Net Capacity 

Resources, Existing Uncertain Resources less all Derates, Total 

Proposed Resources reduced (multiplied) by a confidence factor 

(percentage); plus Net Non-Firm and Provisional Transactions.

Net Capacity Resources Margin (%) — Net Capacity 

Resources reduced by the Net Internal Demand; shown as a 

percent of Net Capacity Resources. 

Adjusted Potential Resources Margin (%) — Adjusted 

Potential Resources reduced by the Net Internal Demand; shown 

as a percent of Adjusted Potential Resources. 

Region/Sub-region Target Margin (%) — a suitable objective 

to maintain available capacity resources, determined largely by 

the type of generation that exists in the region. 

NERC Reference Margin Level (%) — either the Target 

Capacity Margin provided by the region/sub-region or 

NERC assigned based on capacity mix (i.e. thermal/hydro) 

Reliability is measured by comparing Adjusted Potential Resource Margins between the summer 

peaks from the 2008-2017 Long-Term Reliability Assessment Reference Cases to a case with 

capacity changes resulting from EPA’s Section 

316b regulations. 

Capacity margins are used to measure the need 

for additional resources and serves to measure the 

bulk power system’s ability to supply the 

aggregate electric power and energy requirements 

of the electricity consumers, accounting for 

scheduled and reasonably expected unscheduled 

outages of system components. Capacity margins 

measure supply that could be available to cover 

random factors such as generating equipment 

force outages, demand forecast errors, weather 

extremes, and capacity service schedule slippage. 

Capacity margin is calculated by reducing the 

peak capacity by peak demand and normalizing it by peak capacity. Capacity margins are 

expressed as percent and reference margins are calculated using the peak load and capacity of the 

Reference Case. 

Assumptions – The following assumptions were used in this assessment:

Assumptions specified by DOE: 

• Close-loop cooling systems will be added to all nuclear units. 

• Capacity factors can be used as a proxy for economic suitability for retrofit 

• Unit Retirements/Retrofits were based on capacity factors from 2006: 

- Units with a capacity factor less than 0.35 are assumed to be retired. 

- Units with a capacity factor greater than or equal to 0.35 were derated by 4 percent 

of maximum rated (nameplate) capacity.

- 60 percent of retirements/retrofits was projected to begin in 2013, 20 percent in 

2014 and 20 percent in 2015. 

• Plants deemed “difficult to retrofit” due to geographical limitations (i.e. land-locked, 

space and permitting constraints) could result in early retirement.80 This assessment 

does not assume their early retirement. 

• No new plants are built to replace capacity lost to retired units or auxiliary loads. 

• Retrofits are instantaneous, with no capacity short-falls due to plant shutdowns. 

 

80 Identifying plants that are “difficult to retrofit” would necessitate a site-specific survey of all plants with open-loop cooling 

systems. While this assessment does not provide site-specific analysis, some plants with capacity factors greater the 0.35 have 

been identified as “difficult to retrofit”, such as, Eddystone #1 and #2, Fisk Street, Joliet 9 and 29, Crawford, and Will County. 
4 

• Plants with a zero capacity factor (inactive or not yet built) are not assessed. These 

plants are not included in the region’s Reference Case. 

Assumptions specified by NERC: 

• The NERC Reference Margin Level adopted the regional/subregional Target 

Capacity Margin. If not available, the NERC Reference Margin Level is based on 

supply-side fuel: 13 percent for thermal systems and 9 percent for hydro. 

• Unit Retirement/Retrofit capacity reduction comparison is based against “Adjusted 

Potential Resources”, calculated with all Existing Capacity and probable Planned 

Additions, Proposed Additions, and Net Transactions. 

• Units already expected to retire between 2010 and 2015 were not considered part of 

the capacity reduction as they are already factored into the region’s projections.81

The difference in Adjusted Potential Resources margins represents the percent reduction a region 

would experience over the three-year retirement and retrofit time period, based on the previously 

stated assumptions. Reliability assessment is performed only for the U.S Adjusted Potential 

Resource Capacity Margins measuring the region’s capacity margin against a pre-specified target 

margin. Falling below the NERC Reference Margin Level may indicate the need for more 

resources, which, if not acquired, might suggest a higher risk to bulk power system reliability. 

NERC-US Impacts - Based on the aforementioned assumptions, NERC-US impacts were 

calculated. U.S. resource margins drop from 14.7 percent to 10.4 percent when both the retired 

units and auxiliary loads due to retrofitting were compared to the Reference Case (see Figure 1). 

NERC US - Cooling Tower Retrofit Effects

Change in Adjusted Potential Resource Margin

Summer Peak Demand

0%

5%

10%

15%

20%

25%

2013 2014 2015

Margin (%)

Adjusted Potential Resources Margin

Reduced Adjusted Potential Resource Margin

NERC Reference Margin Level

 Figure 1: NERC-US Summer Capacity Margin 

 

81 Plants expected to retire during this time frame with open-loop cooling systems represent a total capacity reduction of 9,500 MW. 

4.3 percent reduction in 

the Adjusted Potential 

Resources Capacity 

Margin 
5 

NERC-US Regional/Subregional Impacts - Capacity resources for NERC regions are each 

impacted differently, depending on the vintage and design of their units. In Figure 3, the impact 

on summer peak capacity margins of retirements and retrofitting are provided. 

A significant finding is the capacity reductions due to auxiliary loads and parasitic losses caused 

by equipment retrofitting is about 9,300 MW. Approximately 39,500 MW of the capacity 

resources are eliminated by unit retirements (see Figure 2). This 49,000 MW total capacity 

reduction in resources could reduce NERC-US capacity margins by 4.3 percent. 

As a percent of the Adjusted Potential Resources margin, WECC-CA-MX US, ERCOT, NPCCUS, and the SERC-Delta sub-region see the largest impact as most units would be retired due to 

the low capacity factors units. 

NERC US - Cooling Tower Retrofit Effects on 

Adjusted Potential Resources

Summer Peak Demand

0

10,000

20,000

30,000

40,000

50,000

60,000

2013 2014 2015

∆MW

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

Reduction of

Adjusted Potential 

Resources Margin 

Derate Effects

Retirement Effects

Total Capacity Reduction

% of Margin Lost due to Retirements and Derate Effects

 Figure 2: NERC-US Cooling Tower Effects

Table 1 provides a listing of regions/sub-regions whose capacity margins are impacted by plant 

retirements and retrofits. Note the capacity factor data provided by the U.S. Department of Energy 

was based on 2006 performance, where natural gas prices were increasing. Natural gas prices can 

drive capacity factors for gas-fired units and, therefore, many regions with a predominance of 

natural gas plants see more capacity margin reduction from plant retirements than those regions 
6 

with plants fired by other fuels experiencing a 4 percent reduction in capacity to support auxiliary 

demand supporting retrofit equipment. 

Table 1: 2015 US Summer Peak Retrofit/Retirement Effects†

Adjusted 

Potential 

Resources 

(MW)

 Reduction 

due to 

Retirement 

(MW) 

 Derate due 

to Retrofit 

(MW) 

 NERC 

Reference 

Margin 

Level 

 Adjusted 

Potential 

Resources 

Margin 

 Margin 

Reduction 

Reduced 

Margin 

United States

WECC - CA-MX US†

72,293 10,137 289 13.2% 12.7% 14.7% -2.0%

NPCC - New England 31,673 2,827 428 13.0% 10.0% 10.3% -0.3%

ERCOT 86,436 10,919 542 11.1% 15.9% 12.9% 3.0%

NPCC US 72,750 6,481 990 13.0% 13.3% 9.9% 3.4%

WECC US†

176,944 10,177 314 12.3% 11.1% 5.6% 5.5%

NPCC - New York 41,077 3,654 561 13.0% 15.9% 9.6% 6.3%

SERC - VACAR 78,182 553 1,032 13.0% 11.0% 1.8% 9.2%

WECC - RMPA†15,609 40 0 10.5% 10.2% 0.2% 10.0%

SERC - Central 54,548 0 949 13.0% 12.6% 1.5% 11.0%

SERC - Delta 41,259 4,266 466 13.0% 21.5% 10.2% 11.4%

RFC 230,062 3,339 2,863 12.8% 14.5% 2.4% 12.1%

SERC 269,599 6,054 3,307 13.0% 15.6% 3.0% 12.5%

SERC - Southeastern 66,675 675 357 13.0% 13.9% 1.4% 12.6%

MRO US 55,582 529 612 13.0% 15.1% 1.8% 13.3%

FRCC 63,170 1,267 454 13.0% 18.7% 2.3% 16.4%

WECC - NWPP†51,861 0 25 11.9% 16.9% 0.0% 16.8%

SPP 63,700 817 257 12.0% 24.1% 1.3% 22.8%

SERC - Gateway 28,935 560 502 13.0% 28.8% 2.7% 26.1%

Total-NERC US 1,018,243 39,583 9,339 13.0% 14.7% 4.3% 10.4%

The WECC-CA US sub-region sees the largest impact with a reduction of almost 15 percent 

(10,400 MW), significantly reducing their summer peak capacity margin. NPCC-New England 

also experiences a significant impact of 10.3 percent. This impact may be the result of the 

abundant gas-fire plants which have low capacity factors in this assessment indicating a retrofit 

would not be economically suitable. 

ERCOT faces the most substantial impact at the regional level. Retirement and retrofit effects may 

result in a loss of up to 11,500 MW, reducing their margins almost 13 percent. 

Some regions starting above the NERC Reference Margin Level in the Reference Case fall below 

as a direct result of this analysis: ERCOT, RFC, and SERC. These regions may require additional 

resources to accommodate the potential retirements/retrofits from the Section 316b Phase II action. 

 

† Adjusted Potential Resource Margins are subject to change, as updated capacity information is expected. 
7 

Similarly, the full region of SERC shows a total capacity reduction of about 9,300 MW, most 

coming from the SERC-Delta (South-Central U.S.) sub-region. However, the impact on the 

Adjusted Potential Resources capacity margin is only 3 percent due to its overall large demand and 

capacity base line in the Reference Case for the region. 

Transmission Reliability Impacts - Though NERC did not perform detailed analysis of the 

transmission impacts resulting from the loss of capacity, it is expected that the volatility and 

predictability of intra-regional and inter-regional transmission limits could change. For example, 

NPCC-US experiences a potential reduction of up to 10 percent of their capacity margin due to 

unit retirements and auxiliary loads (7,500 MW) while RFC experiences a reduction of less than 3 

percent (6,200 MW). System flows from West to East along the interface between RFC and 

NPCC-US already has shown congestion82 and has been named a National Interest Electricity 

Transmission Corridor (NIETC).83 One would expect that this capacity margin reduction could 

further aggravate the congestion on this corridor. 

More transmission may also be needed to serve replacement supply or demand-side resources that 

will be added and ancillary services. Retired plants might be replaced by new resources, in which 

generation may be distant from the load (i.e. wind or other renewables). Detailed transmission 

system studies may be needed to measure reliability impacts and system reinforcement 

requirements resulting from specific capacity reductions. 

Conclusion 

NERC reviewed the impact of either retrofitting units with existing once-through-cooling systems 

to closed-loop cooling systems (4 percent reduction in nameplate capacity) or unit retirements 

(capacity factor less than 0.35) on NERC-US and regional capacity margins for 2008-2017. 60 

percent of retirements/retrofits were projected to begin in 2013, 20 percent in 2014 and the 

remaining 20 percent in 2015. This was retirement/retrofit process was consistently performed in 

each sub-region. 

Based on a worst case view, NERC-US Adjusted Potential Resources may be impacted up to 

49,000 MW, reducing the Adjusted Potential Resource Margin by 4.3 percent and some areas may 

require more resources to offset capacity reductions and maintain the reliability of the bulk power 

system. Some sub-regions experience significant impacts such as California, New England, Texas, 

South-Central and New York. These regions/subregions may require additional resources to 

accommodate the potential retirements/retrofits from the Section 316b Phase II action. 

Transmission congestion and reliability might be aggravated and detailed system transmission 

studies may be needed to determine bulk power system reliability resulting from the loss of the 

specific units studied. 

 

82 http://nietc.anl.gov/documents/docs/NIETC_MidAtlantic_Area_Corridor_Map.pdf

83 http://www.oe.energy.gov/nietc.htm