Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Staff Report to the Secretary on 

Electricity Markets and Reliability

August 2017
Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Table of Contents 

Table of Contents................................................................................................................................

List of Figures......................................................................................................................................

List of Tables.......................................................................................................................................

1 Introduction ...............................................................................................................................1

2 Findings of This Study ...............................................................................................................10

3 Power Plant Retirements..........................................................................................................15

3.1 Coal Plant Retirements ...............................................................................................................20

3.2 Natural Gas Plant Retirements ...................................................................................................24

3.3 Nuclear Plant Retirements..........................................................................................................27

3.4 Hydropower Retirements and Repowering ................................................................................34

3.5 Falling Natural Gas Prices............................................................................................................35

3.6 Environmental Regulations.........................................................................................................39

3.7 Growing VRE Deployment...........................................................................................................47

3.8 Flattening Electricity Demand.....................................................................................................54

3.9 Power Plant Retirements Looking Forward ................................................................................57

4 Reliability and Resilience ..........................................................................................................61

4.1 Assessing Challenges to Reliability..............................................................................................63

4.2 Diversity, Fuel Assurance, and Onsite Storage ...........................................................................89

4.3 High-Risk Events and System Resilience .....................................................................................97

4.4 Enhancing Reliability and Resilience...........................................................................................99

4.5 Reliability and Resilience Looking Forward...............................................................................100

5 Wholesale Electricity Markets.................................................................................................102

5.1 Evolution of U.S. Wholesale Electricity Markets.......................................................................102

5.2 Wholesale Electricity Markets Today........................................................................................104

5.3 Challenges in Wholesale Electricity Markets............................................................................107

5.4 Wholesale Electricity Markets Looking Forward ......................................................................118

6 Affordability...........................................................................................................................119

6.1 Affordability of Generation Portfolios......................................................................................119

6.2 The Wholesale-Retail Disconnect .............................................................................................120

6.3 Affordability Looking Forward ..................................................................................................124

7 Policy Recommendations........................................................................................................126

8 Areas for Further Research .....................................................................................................128

Appendix A: National and Regional Profiles ...................................................................................130

Appendix B: VRE Integration Studies..............................................................................................151

Appendix C: Power Plant Cycling ...................................................................................................154
Staff Report on Electricity Markets and Reliability U.S. Department of Energy

List of Figures

Figure 1.1. Regions Used in This Study .........................................................................................................4

Figure 1.2. Schematic of Typical Daily Load Curve Showing Base Load........................................................6

Figure 3.1. Location of Coal, Natural Gas, Nuclear, and All Other Retirements, 2002–2016,...................15

Figure 3.2. Net Generation Capacity Additions and Retirements...............................................................16

Figure 3.3. Retirements of Coal, Natural Gas, Nuclear, and Other Generating Units, 2002–2022 ............18

Figure 3.4. Retirements by Date, Location, Ownership, and Capacity .......................................................18

Figure 3.5. Operating Generation Capacity, Additions, Retirements, and Announced Retirements by 

Region for All Generation Types, January 2002–December 2022 ..............................................................20

Figure 3.6. Location of the Existing Coal Fleet............................................................................................21

Figure 3.7. Location of Coal Retirements, 2002–2016................................................................................21

Figure 3.8. U.S. Utility-Scale Coal-Fired Electric Generating Capacity Additions by Coal Type and Initial 

Operating Year ..........................................................................................................................................22

Figure 3.9. Location of the Existing Natural Gas Fleet................................................................................25

Figure 3.10. Capacity Additions of U.S. Utility-Scale Natural Gas-Fired Electricity Generation by 

Technology Type and Initial Operating Year...............................................................................................26

Figure 3.11. Natural Gas Fleet Capacity Factors.........................................................................................26

Figure 3.12. Location of Natural Gas Retirements......................................................................................27

Figure 3.13. Location of the Existing Nuclear Fleet ....................................................................................28

Figure 3.14. Location of Nuclear Power Plant Retirements: Closed, Announced, and Averted ................30

Figure 3.15. Nuclear Plant Retirements Compared to NRC Plant Operating License Terms ....................33

Figure 3.16. Hydropower Plants in the United States by Capacity and Average Annual Runoff................34

Figure 3.17. Conventional and Shale Natural Gas Production, 2007–2016................................................36

Figure 3.18. Wholesale Day-Ahead Electricity Prices vs. Henry Hub Natural Gas Price (Monthly Average)

....................................................................................................................................................................37

Figure 3.19. Total Annual U.S. Natural Gas Generation, 1950–2016 .........................................................38

Figure 3.20. Heat Rates for Coal, Nuclear, and Natural Gas, 2002–2016...................................................39

Figure 3.21. PJM Merit-Order Dispatch: Various Control Technologies.....................................................42

Figure 3.22. Changes in U.S. Coal Capacity, December 2014–April 2016...................................................44

Figure 3.23. Average Coal Plant Capacity Factors, 2008–2014...................................................................45

Figure 3.24. Projected and Actual Coal Retirements, 2008–2018..............................................................46
Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.25. VRE Generation by Fuel as Percentage of Total U.S. Generation, 2002–2016 .......................48

Figure 3.26. Cumulative U.S. Utility-Scale Wind and Hydroelectric Generation Capacity, 1915–December 

2016 ............................................................................................................................................................48

Figure 3.27. Relationship between the PTC and Annual Wind Capacity Additions ....................................50

Figure 3.28. VRE Penetration as a Percentage of 2016 Generation versus Retired Capacity since 2010 as a 

Percentage of Non-VRE Capacity ................................................................................................................51

Figure 3.29. Gross Domestic Product and Net Electricity Production, Historical (1950–2016) and 

Projected (2017–2027) .............................................................................................................................54

Figure 3.30. Estimated U.S. Energy Savings from Structural Changes in the Economy and Energy 

Efficiency, 1980–2016 ................................................................................................................................55

Figure 3.31. EIA Annual Electricity Sales 2000–2016 (terawatt-hours) and AEO Reference Case Electricity 

Sales Projections 2017–2030 ......................................................................................................................56

Figure 3.32. Baseload Capacity Additions and Retirements from EIA AEO 2017 (No Clean Power Plan 

Scenario) .....................................................................................................................................................57

Figure 3.33. Modeled Projections for Natural Gas Price, Electricity Sales, and VRE Generation from EIA 

AEO 2017 (No Clean Power Plan Scenario) ................................................................................................. 58

Figure 3.34. NGCC Capacity Factors and Number of Starts, 1998–2016 ....................................................59

Figure 4.1. System Operation Time Scales ..................................................................................................62

Figure 4.2. Five-Year Average Reserve Margins across Different Regions (2018–2022) ............................66

Figure 4.3. Historical Solar On-Peak Capacity Factors in ERCOT ................................................................. 67

Figure 4.4. NERC Definitions of Reserves Used to Provide ERS ..................................................................70

Figure 4.5. System Frequency after a Grid Event (Top) and How Frequency Control Mechanisms Work to 

Restore Frequency (Bottom).......................................................................................................................71

Figure 4.6. EEI Historical and Project Transmission Investment (Nominal Dollars)....................................76

Figure 4.7. Location of the Existing Wind Fleet ..........................................................................................77

Figure 4.8 Wind Energy Share of Electric Generation by State, 2016.........................................................78

Figure 4.9. Ways To Integrate VRE, Arrayed by Type of Intervention and Cost (2014) .............................80

Figure 4.10. CAISO Load, Net Load, and Wind and Solar Output on Example Weekdays during 2014 ......82

Figure 4.11. The CAISO Duck Curve ............................................................................................................83

Figure 4.12. Demand and Net Demand Shapes at Different Distributed Energy Resource Penetration 

Levels...........................................................................................................................................................84

Figure 4.13. Mapping Reliability Attributes Against Resources ................................................................. 86

Figure 4.14 Selected Ancillary Service Market Design Characteristics .......................................................87

Figure 4.15. Ancillary Service Products Exchanged in the Centrally Organized Markets, Listed by RTO/ISO 

and Category of Ancillary Service ...............................................................................................................88

Figure 4.16. Generation Mix and Various Economic and Policy Drivers Since 1949, Including Diversity 

Index............................................................................................................................................................89
Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 4.17. Changes in U.S. Capacity (Top) and Generation (Bottom) Mix over Time (Left to Right: 2002, 

2009, 2016) .................................................................................................................................................90

Figure 4.18. Natural Gas Storage Facilities.................................................................................................93

Figure 4.19. Coal Stocks and Days of Burn, January 2010–May 2017 ........................................................96

Figure 4.20. Electricity Generation Changes from 2013 to 2014 by Fuel Type ..........................................97

Figure 4.21. Sandia National Laboratories’ Resilience Analysis Process...................................................101

Figure 5.1. Utility Restructuring by State as of May 2017 ........................................................................104

Figure 5.2. The Seven RTOs or ISOs in the United States .........................................................................105

Figure 5.3. States and Regions along the Spectrum from Traditional to Fully Restructured Electric 

Markets.....................................................................................................................................................106

Figure 5.4. How Market Prices Allow Resource Costs to be Recovered in a Centrally-organized Wholesale 

Market.......................................................................................................................................................110

Figure 5.5. Simulated ERCOT Dispatch Curves..........................................................................................112

Figure 5.6. Type of Fuel Used in PJM (by Real-Time Marginal Units): 2004 through March 2017...........113

Figure 5.7. Annual Average Capacity Factors of Coal and Natural Gas Generators.................................113

Figure 5.8. Negative Northwest Off-Peak Daily Spot Prices ($/MWh) in 2011.........................................116

Figure 6.1. Average U.S. Residential Sector Retail Electricity Prices over Time .......................................121

Figure 6.2. Average Wholesale Electric Costs/MWh Have Fallen between 2002 and 2016. ...................122

Figure 6.3. Day-Ahead, On-Peak Wholesale Electric Prices Reach Near-Record Lows in 2016................123

Figure 8.1. Average Three-Year Capacity Factors for Retired U.S. Coal Plants.........................................155
Staff Report on Electricity Markets and Reliability U.S. Department of Energy

List of Tables 

Table 3-1. Direct Employment and Income in Industries Related to Electric Power Supply, 2016 ............23

Table 3-2. Nuclear Plant Retirements, Announced Closures, and Plants Averted by State Action ..........31

Table 3-3. Average Nuclear Costs by Plant Size and Operator Type, 2016 .................................................32

Table 3-4. Major Environmental Regulations Related to Coal, Natural Gas, and Nuclear Generation ......40

Table 3-5. Fiscal Year 2013 Electricity Production Subsidies and Support .................................................53

Table 4-1. How Various Energy Storage Options Can Deliver Grid-Level Applications ..............................74

Table 4-2. Characteristics of VRE, Grid Integration Challenges, and Mitigation Options ...........................78

Table 4-3. Dependence on Imported Just-in-Time Energy for Electricity ...................................................94

Table B-1. VRE Integration Studies .......................................................................................................... 151
1 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

1 Introduction 

On April 14, 2017, Energy Secretary Rick Perry issued a memorandum requesting a study to examine 

electricity markets and reliability. With this document, Department of Energy (DOE) staff are delivering a 

study that seeks not only to evaluate the present status of the electricity system, but more importantly 

to exercise foresight to help ensure a system that is reliable, resilient, and affordable long into the 

future. Therefore, while carefully acknowledging history, this study focuses on the present trajectory of 

trends that are of particular concern in meeting those long-term goals. 

Specifically, the April 14 memo directed a study that explores the following three issues: 

 The evolution of wholesale electricity markets, including the extent to which Federal policy

interventions and the changing nature of the electricity fuel mix are challenging the original

policy assumptions that shaped the creation of those markets;

 Whether wholesale energy and capacity markets are adequately compensating attributes such

as on-site fuel supply and other factors that strengthen grid resilience and, if not, the extent to

which this could affect grid reliability and resilience in the future; and

 The extent to which continued regulatory burdens, as well as mandates and tax and subsidy

policies, are responsible for forcing the premature retirement of baseload power plants.

The U.S. electricity industry is facing unprecedented changes. Last year, for the first time in history, 

natural gas replaced coal as the leading source of electricity generation. In 2015, a record-high amount 

of generating capacity retired. Over the course of the last decade, overall growth in electricity 

consumption at the national level has stalled, while many generation sources—particularly natural gas, 

wind, and solar—frequently hit new record levels of penetration. 

The stakes are high around these issues because electricity is crucial to modern society and economic 

activity, and because of the physical and financial magnitude of the industry. As noted in the report, 

Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review

(QER 1.2): 

The United States has around 7,700 operating power plants1 that generate electricity from a 

variety of primary energy sources; 707,000 miles of high-voltage transmission lines;2 more 

than 1 million rooftop solar installations;3 55,800 substations;4 6.5 million miles of local 

distribution lines;5

 and 3,354 distribution utilities6 delivering electricity to 148.6 million 

customers. The total amount of money paid by end users end for electricity in 2015 was 

about $400 billion.7 This drives an $18.6 trillion U.S. gross domestic product and significantly 

influences global economic activity totaling roughly $80 trillion.8

Recognizing how vital electricity is to our society and the health of the U.S. economy, the April 14 memo 

asked staff to “provide concrete policy recommendations and solutions.” It also offered principles for 

policy formulation: “the Trump Administration will be guided by the principles of reliability, resilience, 

affordability, and fuel diversity—principles that underpin a thriving economy.” To that end, this report 

concludes by outlining policy recommendations to advance those principles. 

Section 2 of this study offers a summary of findings. Sections 3 through 6 provide the analytical 

framework, relevant data, and research. In addition, each of these sections concludes with a “looking 

forward” note, as many of the issues raised in the April 14 memo are of growing importance. Section 1
2 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

presents policy recommendations available—to DOE and others—to address the issues identified in this 

study. Section 8 outlines potential areas for further research. 

Data Used in This Study 

This study uses data collected by the Energy Information Administration (EIA) for the years 2002 through 

2017, looking back before 2002 on a few specific issues. The 2002–2017 time range captures several 

important developments: 

 Centrally-organized wholesale electricity markets (Regional Transmission Operators [RTOs] and

Independent System Operators [ISOs]) were in the early stages of implementation in 2002.

Competition within centrally-organized markets among a large segment of merchant generation

did not take effect until the mid-2000s. Three RTO/ISOs initiated mandatory capacity markets in

2006–2007: New York ISO (NYISO), PJM Interconnection (PJM), and ISO-New England (ISO-NE).

 The emergence of a large amount of unconventional natural gas production—the shale

revolution—started in 2006–2007. The consequent drop in natural gas prices began in 2009

under the combined impacts of low demand during the economic recession and a significant

increase in supply.

 The recession contributed to a significant drop in electricity demand in 2008, and it took several

years for demand to return to 2008 levels. Although economic activity has picked up in recent

years, electricity consumption and gross domestic product (GDP)—which grew together for

decades—now appear less correlated as industries have become less energy-intensive and

energy efficiency measures have taken full effect.

 Several environmental regulations implemented under statutes enacted in the 1970s and 1990s,

which raise capital and operating costs for affected power plants, had compliance deadlines in

the period 2010–2017.

 Driven in part by Federal and state policies, tax incentives, and mandates, significant quantities

of variable renewable energy (VRE) resources—specifically wind and solar, and at levels high

enough to alter traditional patterns of grid operation—began to impact certain areas around

2010. 

 Also around 2010, demand response emerged as a way for customers to compete in most

centrally-organized wholesale markets.

Because all of the above factors have emerged over the past 15 years—each affecting power supply and 

demand in different ways—looking at data since 2002 helps to reveal the impact and interactions of 

these changes. Additionally, EIA believes that the highly detailed EIA data used in this study (down to 

the level of individual generators) is most reliable for 2002 forward. 

Further, the data used for this study include power plant fuel conversions as retirements for the original 

fuel source. This study reports power (e.g. generation capacity) and energy (e.g. production or 

consumption over time) in megawatts (MW) and megawatt-hours (MWh), respectively (unless 

otherwise noted). Finally, all generation capacity figures reported in this study are net summer capacity 

as opposed to nameplate (unless otherwise noted). 
3 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

The U.S. bulk power system (BPS) is a patchwork of different markets for electricity, shaped over time by 

technological changes, as well as state, regional, and Federal policies. This patchwork presents 

organizational and operational challenges, but its diversity also contributes to the system’s robustness. 

The U.S. power system in the lower 48 statesa is divided into three synchronized grids: the Eastern 

Interconnection, the Western Interconnection, and the Electric Reliability Council of Texas (ERCOT).b, 9

There are limited connections between the Eastern and Western Interconnections, and even fewer 

connections from ERCOT to the other grids. 

Issues confronting the BPS vary widely across regions. This study divides the lower 48 states into nine 

regions that represent either individual or groups of electric systems, known as balancing authority

areas (see Figure 1.1). Within these regions, there are 66 balancing authorities (which can be as small as 

individual utilities or as large as a multi-state region). Using nine balancing authority-based regions for 

this analysis is a useful way of aggregating electricity data and revealing regional trends. 

a

 Both Alaska and Hawaii have unique islanded electric power systems that are not comparable to the rest of the Nation and 

thus are not included in this study. This is discussed in detail in a later section. 

b

 For most purposes, ERCOT can be considered electrically isolated from the other grids. ERCOT is also not subject to most 

elements of the Federal Power Act and therefore economic regulation by the Federal Energy Regulatory Commission. A 

significant exception is Federal Energy Regulatory Commission oversight and regulation of power system reliability, which does 

apply to ERCOT. 

Defining Regions 
4 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 1.1. Regions Used in This Study10

Seven of the nine regions analyzed in this study correlate primarily or directly to the seven ISOs and 

RTOs in the United States that supply about two-thirds of electricity delivered to end-use customers:c

 NE = ISO-NE

 NY = NYISO

 ERCOT = Electric Reliability Council of Texas

 Mid-Atl = PJM

 Midwest = Mid-Continent ISO (MISO)

 Central = Southwest Power Pool (SPP)

 CAISO+ = California ISO (plus smaller balancing areas in the state)

The two remaining regions include numerous balancing authorities, all of which lie outside RTO/ISO 

service areas: 

 SE = Southeast

 West = non-CAISO+ Western Interconnection.

c

 The last four regions in this list include a few additional (mostly small) balancing authorities outside the formal ISO or RTO 

footprint. 
5 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

This study defines baseload generation as power plants that are operated in baseload patterns—that is, 

plants that run at high, sustained output levels and high capacity factors, with limited cycling or 

ramping. While this definition includes most nuclear, coal, and natural gas steam generators, it is not a 

given that every nuclear, coal, or natural gas steam generator is operated as a baseload plant, or that 

other technologies cannot function as baseload plants (such as hydroelectric generators). In addition, 

this study uses the term conventional generation to mean coal, nuclear, and natural gas power plants, 

regardless of how they are operated.d

Other organizations and publications use similar definitions. For example, PJM defines baseload 

generation as “those units which operate the great majority of hours of the year to meet load 

requirements.”11 

The North American Electric Reliability Corporation (NERC) offers an explanation as well: 

There is a distinction between baseload generation and the characteristics of generation 

providing reliable “baseload” power. Baseload is a term used to describe generation that falls 

at the bottom of the economic dispatch stack, meaning [those power plants] are the most 

economical to run. Coal and nuclear resources, by design, are designed for low cost O&M 

[operation and maintenance] and continuous operation [...] 

However, it is not the economics nor the fuel type that make these resources 

attractive from a reliability perspective. Rather, these conventional steam-driven 

generation resources have low forced and maintenance outage hours traditionally 

and have low exposure to fuel supply chain issues. Therefore, “baseload” 

generation is not a requirement; however, having a portion of a resource fleet with 

high reliability characteristics, such as low forced and maintenance outage rates and 

low exposure to fuel supply chain issues, is one of the most fundamental necessities 

of a reliable BPS. These characteristics ensure that “baseload” generation is more 

resilient to disruptions.

12

The electricity industry has traditionally referred to baseload generation as the power plants that are 

used to meet “base” load—the minimum level of electricity that customers demand around the clock, as 

illustrated in Figure 1.2. Large nuclear, coal, natural gas steam, and hydroelectric plants have historically 

been used for baseload generation.e Baseload plants generally have high capital costs but low fuel costs, 

and they tend to be fairly fuel efficient. Although the output level of these plants can be changed, they 

are most economic—in terms of cost per unit of electricity produced—when operated at near-full 

capacity at all times (although hydroelectric plants are more flexible). Traditional baseload units tend to 

have longer start-up and shut-down times and generally move (ramp) slowly between production levels 

to avoid damaging plant components with thermal stress or metal fatigue (see Appendix C on cycling). 

d

 QER 1.2 does not define the term baseload in its glossary. However, the report states in a caption on page 1-21 that “baseload 

is considered coal, nuclear, and natural gas combined-cycle plants.”

e

 Other technologies that have traditionally operated as baseload include geothermal and biomass power plants. However, 

those technologies represent a relatively small portion of total U.S. electricity generation; while valuable for the grid reliability 

services they provide, they are not covered in this report. 

Defining Baseload Generation 
6 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 1.2. Schematic of Typical Daily Load Curve Showing Base Load13

Intermediate or mid-merit plants are used to follow load, meeting daily variations in demand. 

Depending on the mix of generation resources available in different regions of the country and relative 

fuel prices, natural gas and/or coal units are typically used for load following. Short-duration demand 

peaks, which occur infrequently throughout the year, are generally met by natural gas units with high 

heat rates.f

 More recently, customer-provided demand response is helping to meet peak demand. 

Analysis in Section 3 shows that many of the power plants that retired between 2002 and 2016 were 

used for baseload generation in the past, but were no longer operating in that role at the time of 

retirement due to changes in electricity market dynamics. With the sustained drop in natural gas prices, 

for example, natural gas-fired combined-cycle (NGCC) plants are currently a less costly source of 

baseload generation than coal or nuclear power in many regions of the country. 

VRE resources such as wind and solar are beginning to serve more of minimum load, albeit at variable or 

intermittent output levels.g

 The proliferation of these sources has also led grid operators in some 

regions to place an increasing premium on flexible generation resources (e.g., NGCC units) that can help 

balance VRE variability by meeting base load and intermediate load, both of which are affected by a 

f According to EIA, “Heat rate is one measure of the efficiency of a generator or power plant that converts a fuel into heat and 

into electricity. The heat rate is the amount of energy used by an electrical generator or power plant to generate one kilowatthour (kWh) of electricity.” https://www.eia.gov/tools/faqs/faq.php?id=107&t=3. 

g

 For the purposes of this study, wind and solar are referred to as VRE. Terms such as “non-dispatchable” and “intermittent” 

may also apply to these technologies, but for consistency, this study uses the term variable. In contrast, some renewables are 

dispatchable—that is, sources that can provide power to the grid within sub-hourly time scales to match demand during any 24-

hour period. Dispatchable renewables include sources such as biofuels, geothermal, and hydropower (with the caveat on 

hydropower that it may only be seasonally dispatchable in some cases). 
7 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

changing net load profile.h These factors, among others, have collectively lessened the immediate need 

for traditional baseload resources in certain regions, but still speak to the need for baseload generation. 

Defining Premature Retirement 

The dictionary definition of premature is “happening ... or performed before the proper, usual or 

intended time.”14 The Department does not have an official definition for the term “premature 

retirement”i with respect to power plants, as the term is highly subjective. Below are some of the 

prevailing viewpoints and associated meanings: 

 Power plant engineers may think a power plant retired prematurely if it has not yet run to the

end of its nominal design life (for instance, approximately 40 years for post-1970 coal plants) or

through the term of reasonable plant life extension modifications.

 An RTO/ISO or reliability organization may think a power plant retirement is premature if its

continued operation is still required to deliver Essential Reliability Services (ERS)

j

 in that location

(in which case the operator may delay retirement by designating it a “reliability-must-run”

resource).

 A policymaker or legislator may think a power plant has been forced to retire prematurely if the

plant delivers benefits that the state or society values, such as emissions-free energy, local jobs,

or maintaining local generation.

 A mayor or employee may think a power plant is retiring prematurely if the retirement causes

harms to the community and the individuals who work there.

 A merchant competitor that built or acquired a power plant may think its plant has been forced

to retire prematurely if the merchant has not been able to recover its investment in the plant

through sales of energy and capacity or through other revenue streams.

 A vertically integrated utility executive may think a power plant has been forced to retire

prematurely if the utility has not yet fully recovered its rate-based capital investment in the

plant and its return on that rate base.

 Nuclear or hydroelectric plant owners and regulators may think a power plant has retired

prematurely if it has not yet run through the full term of its operating license and/or license

extension. Federal Energy Regulatory Commission (FERC) hydro licenses run for up to 50 years

with potential reauthorizations of 30–50 years, and Nuclear Regulatory Commission (NRC)

nuclear operating licenses run for 40 years with potential 20-year extensions.

 Electricity economists may think a power plant retired has prematurely if the plant was still able

to sell electricity competitively against other energy sources but was required to close due to

policy directives. On the other hand, economists may also think a power plant retired

h “Net load” is the instantaneous difference between total customer electricity demand (load) and VRE generation. 

i

 QER 1.2—Transforming the Nation’s Electricity System: The Second Installment of the Quadrennial Energy Review—discussed 

“premature nuclear retirements” but did not explicitly define the term. For example, in Chapter 3, page 24, the report notes:

“When analyzing the impacts of premature nuclear retirements on power generation in the state, a state of Illinois report 

considered a scenario in which 80 percent of the replacement generation was coal. Other analysis concludes that roughly 

75 percent of the at-risk nuclear generation nationwide would be replaced with fossil generation, largely powered with natural 

gas.” [notes omitted, emphasis added] 

j

 See Section 4.1.1 for a discussion of ERS. 
8

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

prematurely if the plant provided un-priced benefits to society that, if priced, would have made

the plant profitable.

 A long-term planner and risk manager may think a power plant has retired prematurely if it 

offered valuable diversity, reliability, resilience, and optionality benefits that are not yet fully 

recognized, valued, and/or compensated.

Each of these viewpoints represents a valid perspective, particularly those of grid operators and other 

institutions responsible for reliability. While stakeholders may maintain that a power plant has been 

forced to retire prematurely based on one or more of the considerations above, the results of this study 

show that some observed power plant retirements were appropriate and consistent with markets as 

they are currently functioning. In other words, not every power plant retirement is cause for alarm.

However, NERC is concerned with the trend of retirements as it relates to reliability and resilience. NERC 

wrote in response to the April 14 memo:

As conventional resources prematurely retire, sufficient amounts of essential reliability 

services, such as frequency and voltage support, ramping capability, etc., must be replaced 

based on the configuration and needs of the system.

15 [emphasis added]

Given the difficulty in assigning a single definition to premature retirement, as well as the subjective 

nature of such a definition, this study does not attempt to determine whether any specific power plant 

retirements have been premature. Instead, this study assesses the various factors that contribute to 

power plant retirement trends.

Topics Beyond the Scope of This Study

This study does not directly address several topics for the following reasons:

 Cybersecurity is a critical component to ensuring the reliable and resilient operation of the 

Nation’s energy infrastructure. Existing and emerging cybersecurity threats can affect any aspect 

of the electric sector, ranging from power plants, to transmission and distribution systems, to 

customers and end-use devices. The December 2015 attack on the Ukrainian electricity system 

and the 2012 Shamoon virus targeting the energy sector in Saudi Arabia, for example, were 

wake-up calls.16

DOE takes these threats seriously and is designated as the Federal Government’s lead SectorSpecific Agency for cybersecurity for the energy sector, which entails supporting the cyber 

protection of the Nation’s critical energy infrastructure.k However, while cybersecurity is a 

significant concern and top priority, it is not addressed in this report because it is the subject of 

an upcoming joint report between DOE and the Department of Homeland Security being 

prepared in response to Executive Order No. 13800, Strengthening the Cybersecurity of Federal 

Networks and Critical Infrastructure.

 Alaska and Hawaii: While the broad trends discussed in this report apply in Alaska and Hawaii as 

well as the lower 48 states, many of this study’s economic observations do not directly apply to 

the power plants in the Hawaii and Alaska power systems, as they are not large, interconnected 

energy markets, and utility system operators in the states face unique operational and fuel 

supply chain considerations. 

 

k For more information, visit DOE’s website on the Department’s cyber activities: https://www.energy.gov/national-securitysafety/cybersecurity. 
9 

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

The Hawaii and Alaska power systems are remote, vertically integrated systems with plant sizes 

that tend to fall below the size screens used in this study. The average generating unit sizes in 

Hawaii and Alaska are 18 MW and 5 MW, respectively, compared to an average unit size of 70 

MW in the lower 48 states.17 Because neither state is interconnected with any of the major U.S. 

interconnections, or to any transmission or distribution network in Canada, utilities in both 

states must self-supply all ERS.

l

 As a result, utilities in these isolated systems might consider 

different parameters for reliability in their system planning compared to utilities in the 

contiguous United States, who can obtain reliability services and products in real time through 

markets and bilateral transactions.18 Their experiences, however, may inform the efforts of 

utilities in the contiguous U.S. seeking to better manage rural systems and effectively integrate 

VRE and microgrids.

 Geothermal, biomass, and combined heat and power plants are often operated as baseload

plants, operating at a relatively stable level over a long period of time. However, because these

types of plants are not as prevalent or widespread as gas, coal, and nuclear plants, this study did

not perform detailed analyses of trends and closures for these technologies.

l

 In 2014, an intertie to the Western Interconnection of British Columbia was proposed to the Alaska Energy Authority in order 

to bring power to Alaska. However, as of 2016, no further work on the project had been completed due to economic reasons. 

http://energy-alaska.wikidot.com/railbelt. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

2 Findings of This Study

This study identified several critical issues central to protecting the long-term reliability of the electric 

grid in accordance with the April 14 memo, which asked staff to explore:

1) The evolution of wholesale electricity markets, including the extent to which Federal policy 

interventions and the changing nature of the electricity fuel mix are challenging the original policy 

assumptions that shaped the creation of those markets.

While centrally-organized markets have achieved reliable wholesale electricity delivery with 

economic efficiencies in their short-term operations, changing circumstances have challenged both 

centrally-organized and, to a lesser extent, vertically-integrated markets.

m

 To date, wholesale markets have withstood a number of stresses. While markets have evolved 

since their introduction, they are currently functioning as designed—to ensure reliability and 

minimize the short-term costs of wholesale electricity—despite pressures from flat demand 

growth, Federal and state policy interventions, and the massive economic shift in the relative 

economics of natural gas compared to other fuels. The resulting low average wholesale energy 

prices, while beneficial for buyers of wholesale electricity, represent a critical juncture for many 

existing baseload generation resources and their role in preserving reliability and resilience.

n

 Market designs may be inadequate given potential future challenges. VRE—with near-zero 

marginal costs and if at high penetrations—will lower wholesale energy prices independent of 

effects of the current low natural gas prices. This would put additional economic pressure on 

revenues for traditional baseload (as well as non-baseload) resources, requiring careful 

consideration of continued market evolutions.

 Markets need further study and reform to address future services essential to grid reliability 

and resilience. System operators are working toward recognizing, defining, and compensating 

for resource attributes that enhance reliability and resilience (on both the supply and demand 

side). However, further efforts should reflect the urgent need for clear definitions of reliabilityand resilience-enhancing attributes and should quickly establish the market means to value or

the regulatory means to provide them.

Evolving market conditions and the need to accommodate VRE have led to the increased flexible 

operation of generation and other grid resources. Some generation technologies originally designed 

to operate as baseload were not intended to operate flexibly, and in nuclear power’s case, do not 

have a regulatory regime that allows them to do so.

 

m This study also refers to vertically integrated markets as bilateral markets.

n Former FERC Commissioner Tony Clark summarizes today’s changing demands on centrally-organized markets: “Affordable 

power was the goal when markets were created. The current markets are still procuring affordable power, but many state 

public policy makers no longer see that as the only goal [...] other public policy goals [include...] incenting in-state jobs, 

promoting ‘green’ energy or other politically favored resources, preserving carbon-free resources, and retaining substantial tax 

revenues to state and local government.” Clark goes on to say, “[Markets] were never designed for job creation, tax 

preservation, politically popular generation, or anything other than reliable, affordable electricity.” 

http://www.wbklaw.com/uploads/file/Articles-%20News/2017%20articles%20publications/Market%20Identity%20Crisis%20Fin

al%20(7-14-17).pdf.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

 Generation from VRE can change widely over the course of a single day, which requires

dispatchable power plants to be operated more nimbly. Additionally, in some areas of the

country, there may be over-generation from VRE at some points in a day, which drives prices to

almost zero yet requires quick-ramping assets when VRE subsides. Taken together, these trends

have placed a premium on flexible output rather than the steady output of traditional baseload

power plants. This flexibility is generally provided by generation resources. However, nongeneration sources of flexibility—such as flexible demand, increased transmission, and energy

storage technologies—are being explored as ways to enhance system flexibility.

Society places value on attributes of electricity provision beyond those compensated by the current 

design of the wholesale market. 

 Americans and their elected representatives value the various benefits specific power plants

offer, such as jobs, community economic development, low emissions, local tax payments,

resilience, energy security, or the national security benefits associated with a nuclear industrial

base. Most of these benefits are not recognized or compensated by wholesale electricity

markets, and this has given rise to a variety of state and private efforts that include keeping

open or shutting down established baseload generators and incentivizing VRE generation.

2) Whether wholesale energy and capacity markets are adequately compensating attributes such as

onsite fuel supply and other factors that strengthen grid resilience and, if not, the extent to which

this could affect grid reliability and resilience in the future.

Markets recognize and compensate reliability, and must evolve to continue to compensate

reliability, but more work is needed to address resilience.

 Reliable and affordable electricity is essential to the modern economy, including the

manufacturing, services, and financial sectors. NERC’s most recent annual State of Reliability

report concludes that during 2016, the “bulk power system reliability remained within defined

performance objectives to provide an Adequate Level of Reliability (ALR).”o

 NERC reached the

same conclusion for 2013–2015. However, in a May 2017 letter to the Secretary of Energy, NERC

pressed the importance of reliability issues that require attention, including maintaining ERS as

conventional generation retires and ensuring flexibility and sufficient transmission to

supplement and offset VRE.19 These issues are indicative of the technological and institutional

changes that are now affecting the electricity sector, and dealing with these issues will require

new levels of coordination and collaboration among the sector’s many constituencies. Presently,

BPS reliability is adequate despite the retirement of a portion of baseload capacity and unique

regional hurdles posed by the changing resource mix.

 Fuel assurance is a growing consideration for the electricity system. Maintaining onsite fuel

resources is one way to improve fuel assurance, but most generation technologies have

experienced fuel deliverability challenges in the past. While coal facilities typically store enough

o NERC defines ALR as “the state that the design, planning, and operation of the Bulk Electric System (BES) will achieve when 

the [five] listed Reliability Performance Objectives are met.” These objectives are detailed at 

http://www.nerc.com/pa/Stand/Resources/Documents/Adequate_Level_of_Reliability_Definition_(Informational_Filing).pdf. 
12

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

fuel onsite to last for 30 days or more, extreme cold can lead to frozen fuel stockpiles and 

disruption in train deliveries. Natural gas is delivered by pipeline as needed. The NERC letter to 

DOE emphasized ensuring natural gas fuel supply and mitigating delivery vulnerabilities. 

Capacity challenges on existing pipelines combined with the difficulty in some areas of siting and 

constructing new natural gas pipelines, along with competing uses for natural gas such as for 

home heating, have created supply constraints in the past. Supply constraints can create 

increased price risk and, in extreme cases, could impact reliability.p

 Recent severe weather events have demonstrated the need to improve system resilience. The 

range of potential disruptive events is broad, and the system needs to be designed to handle 

high-impact, low probability events. This makes it very challenging to develop cost-effective 

programs to improve resilience at the regional, state, or utility levels. Planning, practice, and 

coordination on an all-hazards basis and having a mix of resources and fuels available when a 

major disturbance occurs are both essential to fast response. Work still remains to identify 

facilities that merit hardening; stage periodic exercises and drills so that governmental agencies 

and utilities are prepared for emergencies; and ensure that wholesale electricity markets are 

designed to recognize and incentivize investments that would achieve or enhance resiliencerelated objectives.

 Significant progress is already being made to understand what is needed to maintain power 

system reliability under changing market conditions, but more work is needed to understand 

what can be done to maintain resilience in a variety of conditions as the grid changes over the 

coming years. Further, low natural gas prices are driving greater use of natural gas for electricity 

generation, which has made exposure to natural gas price risk related to availability a growing 

concern in several regions. There are tradeoffs between multiple desirable attributes of the grid.

For example, within power systems, it may be the case that a more reliable and resilient system 

is more costly than the least-cost system that a centrally-organized wholesale market is 

intended to deliver. Similarly, policies that seek to deliver more jobs, reduce pollution, or reduce 

risk may require more upfront investment at an initially higher cost to society as a whole than a 

least-cost system. It is important that policymakers have a clear understanding of the true costs 

and benefits of services to the grid, as well as an understanding of the tradeoffs between 

desirable attributes like reliability, flexibility, and affordability.

 

p

Indeed, ISO-NE has repeatedly expressed that reliability and resilience concerns are not being adequately addressed by the 

New England region on natural gas.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

3) The extent to which continued regulatory burdens, as well as mandates and tax and subsidy

policies, are responsible for forcing the premature retirement of baseload power plants.

The recent and unprecedented rise of natural gas as a top electricity generation resource, the increase 

in VRE penetration, the flattening of electricity demand growth, and a host of policy issues—regulations, 

mandates, and subsidies at the state and Federal levels—have negatively impacted traditional baseload 

generation, particularly coal and nuclear power plants. 

Between 2002 and 2016, 132,000 MW of generation capacity retired—representing about 15 percent of 

the total 2002 installed base—and 390,500 MW of new capacity was added. While power plants retire 

for a variety of reasons, several factors have contributed to recent retirements and continuing pressure 

for additional retirements. 

The biggest contributor to coal and nuclear plant retirements has been the advantaged economics 

of natural gas-fired generation. 

 Low-cost, abundant natural gas and the development of highly-efficient NGCC plants resulted in

a new baseload competitor to the existing coal, nuclear, and hydroelectric plants. In 2016,

natural gas was the largest source of electricity generation in the United States—overtaking coal

for the first time since data collection began.20 The increased use of natural gas in the electric

sector has resulted in sustained low wholesale market prices that reduce the profitability of

other generation resources important to the grid. The fact that new, high-efficiency natural gas

plants can be built relatively quickly, compared to coal and nuclear power, also helped to grow

gas-fired generation. Production costs of coal and nuclear plants remained somewhat flat, while

the new and existing, more flexible, and relatively lower-operating cost natural gas plants drove

down wholesale market prices to the point that some formerly profitable nuclear and coal

facilities began operating at a loss. The development of abundant, domestic natural gas made

possible by the shale revolution also has produced significant value for consumers and the

economy overall.

Another factor contributing to the retirement of power plants is low growth in electricity demand.

 Growth of total electricity use has slowed from averaging 2.5 percent annually in the late 1990s,

to averaging 1.0 percent annually from 2000 to 2008, to remaining roughly flat since then.21

Changes in electricity demand—particularly the apparent decoupling of economic output and

electricity demand—have been driven in part by energy efficiency policies. The combination of

slow growth in electricity demand and the 390,500 MW of capacity additions from 2002 to 2016

made significant amounts of older, higher-cost capacity redundant.

Dispatch of VRE has negatively impacted the economics of baseload plants.

 Since 2007, the contribution to total generation from wind and solar has grown quickly,

accelerated by government policies and mandates. State renewable portfolio standards (RPS)

have been the largest contributor—associated with 60 percent of VRE growth since 2000—

followed by Federal tax credits and government research (which contributed to the dramatic

drop in wind and solar technology costs). Because these resources have lower variable operating

costs than traditional baseload generators, they are dispatched first and displace baseload

resources when they are available.

 Participants on a panel of economists at a May 2017 FERC technical conference cited state-level

RPS and Federal tax credits for VRE as examples of wholesale market impacts and distortions.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Competition from resources that benefit from such policiesqreduces revenues for traditional 

baseload power plants by lowering the wholesale electric prices they receive and by displacing a 

portion of their output. 

Investments required for regulatory compliance have also negatively impacted baseload plant 

economics, and the peak in baseload plant retirements (2015) correlated with deadlines for power 

plant regulations as well as strong signals of future regulation.

 A suite of environmental regulations scheduled for implementation between 2011 and 2022 has 

had varying degrees of effects on the cost of generation. For example, the largest number of 

coal plant retirements occurred in 2015—the deadline for coal and oil plants to add pollution 

control equipment for Mercury and Air Toxics Standard (MATS) compliance. In the same year, 

the Environmental Protection Agency (EPA) finalized its Clean Power Plan, which, if fully 

implemented, would place additional pressure on coal-fired generation. Nuclear power plants 

also face regulatory costs—principally the Cooling Water Intake Rule. Three nuclear plants that 

announced closure (Oyster Creek, Diablo Canyon, and Indian Point) have cited disputes with 

their respective states, who implement the rule, as among the reasons for plant retirement. 

Ultimately, the continued closure of traditional baseload power plants calls for a comprehensive 

strategy for long-term reliability and resilience. States and regions are accepting increased risks that 

could affect the future reliability and resilience of electricity delivery for consumers in their regions.

Hydropower, nuclear, coal, and natural gas power plants provide ERS and fuel assurance critical to 

system resilience. A continual comprehensive regional and national review is needed to determine how 

a portfolio of domestic energy resources can be developed to ensure grid reliability and resilience.

 

q These same economists also cited other “out-of-market” interventions as distorting efficient price formation in wholesale 

markets, such as recently enacted and pending state laws that provide support to existing nuclear units. During the economist’s 

panel discussion at the FERC May 2017 technical conference, the phrase “subsidies beget subsidies” was used.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

3 Power Plant Retirements 

A combination of factors is causing power plant retirements, including low natural gas prices, wholesale 

competition, low customer demand growth, regulation-driven cost increases, and the growth of VRE. As 

Figure 3.1 shows, the types, magnitude, and timing of conventional power plant retirements vary 

regionally. 

Figure 3.1. Location of Coal, Natural Gas, Nuclear, and All Other Retirements, 2002–201622, r

To understand observed power plant capacity retirements, it is useful to begin with an examination of 

historical capacity additions. From 1950 to 2015, capacity additions of different generation technologies 

tended to come in waves that were largely influenced by policy, fuel costs, and technology development 

(see Figure 3.2). Coal expansion was highest from 1950 to 1990, nuclear power was widely deployed in 

the 1970s and 1980s, natural gas capacity additions peaked in the early 2000s and continue through 

today, and VRE has grown rapidly over the last decade.s 

r

 VIEU stands for vertically integrated electric utilities. 

s

 Not depicted: prior to the 1950s, hydropower was a large source of generation capacity additions, the vast majority of which is 

still operational today. https://www.eia.gov/todayinenergy/detail.php?id=30312. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.2. Net Generation Capacity Additions and Retirementst23

Power plant retirements have accelerated since 2011, and retirement trends vary significantly by 

generation source. For instance, the current wave of nuclear plant retirements only occurred over the

last five years.

u

Some of the nuclear units now closing are doing so because of state policy pressure (as 

with California’s Diablo Canyon, New Jersey’s Oyster Creek, and New York’s Indian Point), and some 

have had maintenance issues that were too costly to fix. However, most plants are closing or 

threatening closure because–given the economics in some regions—they have become unable to 

compete against primarily low-cost, gas-fired generation and, to a lesser extent, subsidized and 

mandated VRE in a low electricity demand environment.

The design of traditional baseload power plants assumed operations primarily at a constant output level 

with limited cycling (see Appendix C).

24 As the electricity system continues to evolve and market 

conditions change, these plants are increasingly being moved into load-following operations, or are 

 

t Acronyms: Clean Air Act (CAA), Energy Policy Act of 1992 (EPAct 1992), Energy Policy Act of 2005 (EPAct 2005), Investment Tax 

Credit (ITC), Production Tax Credit (PTC).

u However, we note that 29 U.S. nuclear power plants retired from 1974 through 2001, including 13 power plants in the 

commercial utility nuclear fleet sized at 700 MW or larger. These plants retired for a variety of reasons, including damage (Fort 

St. Vrain), safety or operational difficulties (Three Mile Island 2, Zion 1 & 2, Millstone 1), costly safety requirements (Humboldt 

Bay), and state or utility policy choices (Rancho Seco, Trojan, Indian Point 1). This study only looks at the nuclear units in 

operation in 2002 and beyond.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

required to more frequently adjust the load and the on/off dispatch of their units. The extra costs 

incurred to do so can affect a retirement decision. 

QER 1.2 discusses these issues: 

Currently, the changing electricity sector is causing the closure of many coal and nuclear 

plants in a shift from recent trends. From 2000 through 2009, power plant retirements were 

dominated by natural gas steam turbines. Over the past 6 years (2010–2015), power plant 

retirements were dominated by coal plants (37 GW), which accounted for over 52 percent of 

recently retired power plant capacity. Over the next 5 years (between 2016 and 2020), 34.4 

GW of summer capacity is planned to be retired, and 79 percent of this planned retirement 

capacity are coal and natural gas plants (49 percent and 30 percent, respectively). The next 

largest set of planned retirements are nuclear plants (15 percent).

25

Retirements typically can be tied to the units’ inability to compete economically, but the factors 

complicating a given plant’s economics can be numerous and can compound each other. Currently, 

these factors include low wholesale electricity prices (driven by competing generators with low marginal 

costs, as well as subsidies); higher operating costs from unit age or lower efficiency; and looming capital 

needs, including compliance with safety and/or environmental regulations; among others. Further, 

minimal growth in electricity demand has compounded the impact of VRE policy; in an era of low-cost 

natural gas and increasing levels of state-mandated renewable generation—for example, a 20-percent 

share of wind and solar by 2020—lack of demand growth means natural gas and new VRE added to 

meet state mandates compete with existing conventional generation to satisfy a static level of demand. 

A review of coal, nuclear, and natural gas retirements to date shows that power plant retirements 

reflect regional patterns of generation development, state policies, and differences in market structure 

across regions. However, national patterns also emerge—Figure 3.3 shows that a significant amount of 

capacity (the highest on record) retired in 2015, coinciding with the MATS compliance deadline (which 

applied to coal- and oil-fired units across the country) as well as the finalization of the Clean Power Plan 

rule. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.3. Retirements of Coal, Natural Gas, Nuclear, and Other Generating Units, 2002–202226

Figure 3.4 highlights retirement trends by ownership type (i.e., merchant vs. VIEU) and time period. 

Merchant plants accounted for nearly 70 percent of retired capacity during the period 2002–2010 

(depicted as triangles below; note how most of the triangles are purple and dark blue). VIEU plants 

tended to retire later (depicted as circles below; note how most of the circles are light blue and green).

The merchant vs. VIEU comparison indicates that market structure is a significant factor in power plant 

retirements, particularly the timing of retirements.

Figure 3.4. Retirements by Date, Location, Ownership, and Capacity27
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

The data displayed in Figure 3.4 is categorized into four time frames because a variety of economic 

trends and regulatory events occurred throughout the period 2002–2017: 

 During the period 2002–2006 (shown in purple), VIEU plants retired or sold many of their

generating assets to third parties through state-initiated processes collectively known as

restructuring. During the late 1990s, many states passed legislation initiating restructuring

concurrent with the creation of several RTOs and ISOs. The majority of retirements occurring

during this period were smaller, older merchant power plants in restructured areas including

California, Texas, the Northeast, and the mid-Atlantic region.

 The period 2007–2010 (shown in dark blue) saw early growth of subsidized utility-scale wind

generation; the economic recession from 2008 through 2011; and the start of the shale

revolution in 2006–2007, with natural gas prices starting a downward trend. Also in this time

frame was the 2007 U.S. Supreme Court decision of Massachusetts v. EPA, finding that the EPA

has the authority to regulate carbon dioxide (CO2) and other greenhouse gases (GHGs),

opening the door to further regulation under the Clean Air Act.28 Older, less fuel efficient

natural gas-fired plants retired early in this period, but the fall in natural gas prices starting in

2009 also began to force the shutdown of smaller, older coal and oil plants in 2009.

 In the period 2011–2015 (shown in light blue), low natural gas prices proved to be a longlasting rather than a short-term phenomenon. The compliance deadline for MATS converged

with tightening pollution limits in sulfur dioxide (SO2) and nitrogen oxide (NOX) trading

programs. Many of the coal and oil retirements in this period were plants whose owners chose

to shut down a plant rather than invest in costly environmental remediation measures.

Further, the EPA’s final Clean Power Plan rule was finalized during this time.v This period had

the most power plant retirements, with a marked increase in California, the mid-Atlantic,

Midwest, and Southeast. During this period, it also became clear that a portion of the customer

electricity demand lost from the recession was not going to reappear in the near term, which

meant that electricity demand would not support the higher-cost plants that occupied higher

positions on the supply curve.

 In 2016 and going forward (shown in green), power plant retirements are and may continue to

be driven by continued economic challenges in the form of market dynamics and compliance

costs of regulations, as well as operational pressures from a changing resource mix.

Figure 3.5 shows generation capacity, additions, retirements, announced retirements, and demand 

responsew as a percentage of 2002 total installed net summer capacity in each region. The graphic 

shows that in every region except CAISO+, the proportion of retirements between 2002 and 2016 (in 

v

 Although the Clean Power Plan was later stayed by the Supreme Court, the investment uncertainty around the time of the 

final rule made reinvestment in coal technology a difficult decision for plant owners. 

https://www.iaee.org/ej/ejexec/EJ391_ExecSum_Morris.pdf. 

w Demand response is “a voluntary program offered by independent system operators/regional transmission organizations, 

local utility service providers, or third parties, which compensate end-use (retail) customers for reducing and/or changing the 

pattern of their electricity use (load) over a defined period of time, when requested or automatically instructed to do so during 

periods of high power prices or when the reliability of the grid is threatened.” https://energy.gov/epsa/quadrennial-energyreview-second-installment. 
20

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

orange) is 20 percent or less of the total installed capacity available in 2002 (in red, orange, and light 

blue). The figure also shows that the amount of new capacity added (dark blue) exceeds the combined 

amounts of capacity retired (in red) and planned for retirement (in orange) in every region over the 

study period.x

Figure 3.5. Operating Generation Capacity, Additions, Retirements, and Announced Retirements 

by Region for All Generation Types, January 2002–December 202229

3.1 Coal Plant Retirements

There were approximately 306,000 MW30 of coal-fired power plants in the United States at the start of 

2002 and 270,000 MW31 at the end of 2016, representing a net retirement of approximately 36,000 MW

(about 12 percent) of coal capacity. The remaining fleet of coal-fired generators covers most of the 

lower 48 states, with the exception of the Northeast, Northwest, and California, as shown in Figure 3.6.

 

x While the graphic includes currently planned additions in EIA’s data, this figure does not show generation (megawatt-hour) or 

technology type, and most of planned and added capacity (megawatt) comes from new natural gas and VRE sources that do not 

meet the NERC baseload characteristic discussed earlier.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.6. Location of the Existing Coal Fleet 

EIA reports that: 

Coal-fired electricity generators accounted for 25% of operating electricity generating 

capacity in the United States and generated about 30% of U.S. electricity in 2016. Most coalfired capacity (88%) was built between 1950 and 1990, and the capacity-weighted average 

age of operating coal facilities is 39 years.32

More than 90 percent of the coal consumed in the United States is used for power generation.33 Coal 

energy production peaked in 2007 and has been declining since. No new coal plants have been built for 

domestic utility electricity production since 201434 because new coal plants are more expensive to build 

and operate than natural gas-fired plants.35 Further, as Figure 3.7 shows, coal retirements span many 

regions. 

Figure 3.7. Location of Coal Retirements, 2002–201636
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Between 2002 and 2016, 531 coal generating units representing approximately 59,000 MW of generation 

capacity retired from the U.S. generation fleet. 

The age of coal plants is an important factor. As Figure 3.8 shows, the vast majority of coal-fired capacity 

was built before 1990, with the average of the fleet built in the mid to late 1970s.37 According to the 

Congressional Research Service, the service life of coal-fired generators reportedly “averages between 

35 and 50 years, and varies according to boiler type, maintenance practices, and the type of coal 

burned, among other factors.”38

Figure 3.8. U.S. Utility-Scale Coal-Fired Electric Generating Capacity Additions by Coal Type and 

Initial Operating Year39 40

Between 2002 and 2016, 531 coal generating units representing approximately 59,000 MW of 

generation capacity retired from the U.S. generation fleet.41 EIA reported that coal-fired power plants 

made up more than 80 percent of the 18,000 MW of electric generating capacity that retired in 2015, 

and that the retiring units “tended to be older and smaller in capacity than the coal generation fleet that 

continues to operate.”42

An analysis of coal plant and other data indicates several important trends and attributes: 

 About 70 percent of the plants that retired between 2010 and 2016 had a capacity factor of less

than 50 percent in the year prior to retirement, and about half of the future planned

retirements operated below a 50 percent capacity factor in 2016.43

 While none of the units that retired between 2010 and 2016 had significant SO2 control

equipment installed, more than half of the future announced retirements have SO2 control.

 The average size of planned retirements (380 MW) exceeds the average size of recent

retirements (218 MW), indicating that future retirements will be generally larger than previous

ones.44
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

 Retired plants are older than the remaining fleet. The coal units that retired in 2015 were mainly

built between 1950 and 1970, and the average age of those retired units was 54 years. The

remaining coal fleet is relatively younger, with an average age of 38 years in 2016.45

In summary, until quite recently, the coal plants that have retired were smaller, older, had higher heat 

rates, and therefore were dispatched less often and ran at lower capacity factors. Most of the earliest 

coal retirements were merchant-owned units in the Northeast and Midwest that were more exposed to 

competition from other generators and fuel types, while VIEU-owned plants in the Southeast and 

elsewhere experienced a longer period of protection from low market prices. 

Workforce Impacts of Coal Plant Retirements and Shifts in Coal Production 

Falling demand for coal due to coal plant retirements and capacity factor reductions, a regional shift in 

coal production, and automation in mining have led to a reduction in coal production jobs. Between 

2011 and September 2016, increased mechanization and a shift to western coal resulted in a loss of 

36,000 coal mining jobs, of which nearly 90 percent were in Appalachia.46 As shown in Table 3-1, more 

than 80 percent of the coal jobs in the United States support electricity production.47 The oil and gas 

extraction sector is not subdivided and includes many non-power uses. About 35 percent of the natural 

gas and roughly one percent of petroleum jobs in the United States support electricity production.48

Growth in some energy sectors, such as solar energy deployment, supported new jobs, but they vary 

regionally and often do not correlate well with concurrent job losses in sectors such as coal mining or 

power plant operations. Job growth in other energy sectors and regions cannot sufficiently offset job 

losses in the coal sector without adequate training, salary adjustments, or transition assistance.

Table 3-1. Direct Employment and Income in Industries Related to Electric Power Supply, 201649

Industry Sector/Subsector Jobs Percent Related to 

Electricity Industry

Average Annual 

Income

Electric power generation 191,000 100% $113,000

Electric power transmission and 

distribution

292,000 100% $99,000

Electric power total 483,000 100% $104,000

Coal miningy 55,000 ~80% $82,000

Oil and gas extractionz 377,000 ~35% of gas, ~1% of oil $118,000

Mining and extraction total 432,000 Unknown $113,000

y

 Includes supporting North American Industry Classification System (NAICS) industry categories. 

z

 Includes supporting NAICS industry categories. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Coal Plant Closure Considerations50

In September 2016, Ed Malley of Power Magazine noted:

The primary recent drivers of coal plant retirement announcements include low natural gas prices 

and new environmental regulations—especially the Mercury and Air Toxics Standards (MATS), 

Clean Water Act Section 316(b), and the Coal Combustion Residuals rule. Other contributing factors 

include more competitive markets and a variety of regional and state-level policies involving 

renewables and carbon pricing.

Most of the power plants being closed today were built in the 1940s to 1960s, before the Clean Air 

Act was passed in 1970. Many have minimal air pollution controls, use once-through cooling water, 

and sluice wet coal ash to ponds. Scrubbers, closed-loop cooling, and dry ash handling are current 

requirements, or will be phased in over the next few years. Because much of the older capacity 

tends to be smaller units less than 300 megawatts (MW), which are not economical to retrofit, they 

are therefore retired. Many closures coincided with the MATS deadlines in 2015 and 2016, at a time 

when natural gas prices were at historic lows.

Now that the MATS deadlines have passed, additional companies are announcing closures, 

including Dynegy (5,000 MW) and DTE Energy (2,100 MW). Economics, renewable energy 

mandates, and reduced demand for electricity are driving these additional closures.

Power plant closure activity began on the East and West Coasts in oil-fired plants because of the 

high cost of fuel. Closures are now occurring in the coal belts, the Upper Midwest, and the 

Southeast. There are even some coal-fired plant closures in Western states.

3.2 Natural Gas Plant Retirements

In recent years, the story of natural gas for electricity generation has been one of overall growth rather 

than decline. However, many natural gas plants have retired since 2002. Natural gas plants are located 

across the lower 48 states, and are concentrated around major population centers, as shown in Figure 

3.9. 

According to EIA:

In 2016, natural gas-fired generators accounted for 42% of the operating electricity 

generating capacity in the United States. Natural gas provided 34% of total electricity 

generation in 2016, surpassing coal to become the leading generation source. The increase 

in natural gas generation since 2005 is primarily a result of the continued costcompetitiveness of natural gas relative to coal.51
25

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.9. Location of the Existing Natural Gas Fleet52

NGCC units accounted for 54 percent of the 447,000 MW of total U.S. natural gas-powered generator 

capacity in 2016. Combined-cycle generators have been a popular technology choice since the 1990s 

and made up a large share of the capacity added between 2000 and 2005. Some other types of natural 

gas-fired technology, such as combustion turbines (CTs, representing about 28 percent of total natural 

gas-powered generator capacity) and steam turbines (NGSTs, 17 percent), generally only run during 

hours when electricity demand is high. 

The capacity-weighted average age of U.S. natural gas power plants is 22 years, which is less than hydro 

(64 years), coal (39 years), and nuclear (36 years). The improved efficiency of NGCC plants has led to 

them being used to a greater degree as baseload generation and increased the overall generation from 

natural gas. Figure 3.10 shows the initial operating years for the three types of natural gas-fired capacity 

additions (and their respective share of total natural gas generation in 2016). 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.10. Capacity Additions of U.S. Utility-Scale Natural Gas-Fired Electricity Generation by 

Technology Type and Initial Operating Year53

Figure 3.11 shows total natural gas-fired net generation and how the capacity factors of these plants 

vary by technology over the period 2011–2016. Although NGSTs were originally built principally for 

baseload use, since the early 2000s, they have been displaced in the dispatch merit order by more

efficient NGCC plants designed for greater flexibility. As shown in Figure 3.11, NGST units operate at 

significantly lower capacity factors than NGCC units. 

Figure 3.11. Natural Gas Fleet Capacity Factors54

The States of California, Texas, New York, and Florida all had more than 20,000 MW of natural gas-fired 

capacity at the end of 2016. The National Renewable Energy Laboratory (NREL) reports that, due to the 

flexibility, efficiency, and cost competitiveness of NGCC power plants, grid operators have been 

dispatching NGCC plants more frequently as baseload generators.55 In consequence, the average 

capacity factor for all NGCC plants has grown from about 40 percent in 2008 to roughly 56 percent in 

2016, surpassing that of coal.

56
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.12. Location of Natural Gas Retirements57

Figure 3.12 shows the retirements of natural gas plants between 2002 and 2016. The ERCOT and CAISO 

markets have presented difficulties for merchant natural gas (depicted as triangles above; note the 

concentration of merchant retirements in California and Texas). EIA reported in 2011 that between 2000 

and 2010, 33,000 MW of natural gas-fired generation retired (72 percent steam turbines), with an 

average age at retirement of 48 years and with significantly higher heat rates than the average NGCC.58

3.3 Nuclear Plant Retirements 

The current operating nuclear power fleet consists of approximately 54,000 MW of generating capacity 

in regulated markets and approximately 45,000 MW in restructured electricity markets.59 This 

represents nine percent of total U.S. utility-scale generation capacity in 2017 and 20 percent of U.S. 

electric generation in 2016. EIA reports that nuclear plants have higher capacity factors than any other 

electric generation technology, averaging more than 90 percent (nearly full capacity, full time) over the 

past five years. The plants refuel every 18 to 24 months.60
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.13. Location of the Existing Nuclear Fleet61

The first of these units went online in 1969, and the capacity-weighted average age of the nuclear fleet 

is 37 years old.

62 Almost all of the operating plants have received approval to conduct at least one 

capacity uprate; through 2016, these uprates to the existing fleet have contributed more than 7,000 

MW of additional nuclear capacity.63 In addition to capital investments for capacity uprates, nuclear 

owners make significant capital investments to replace aging components to qualify for license renewal, 

as well as a suite of additional security and safety investments to comply with new regulations following 

9/11 and the Fukushima nuclear accident in 2011.

The United States has the world’s largest nuclear reactor fleet. Nuclear power plants contribute about 

60 percent of total U.S. emissions-free generation.64 Located in 60 power plants, the 99 active nuclear 

reactors provide almost half a million jobs and contribute more than $60 billion to the U.S. GDP.

65

Nuclear energy is viewed as a key strategic asset for the United States, and continued U.S. leadership in 

the global nuclear energy market has important nonproliferation and safety ramifications to national 

security interests.

66 As noted recently by Prof. Michael Webber of the University of Texas:

While the environmental and reliability impacts of the [nuclear plant] closures are wellunderstood, what many don't realize is that these closures also pose long-term risks to our 

national security. As the nuclear power industry declines, it discourages the development of 

our most important anti-proliferation asset: a bunch of smart nuclear scientists and 

engineers....The loss of expertise from a declining domestic nuclear workforce makes it hard 

for Americans to conduct the inspections that help keep the world safe from nuclear 

weapons.67

Of the 99 active nuclear units, 51 are owned by VIEUs, which rely on regulated cost-of-service 

ratemaking. This form of ratemaking provides a stable source of cost recovery assuming reasonably 

prudent operation and management by the utility. The continued operation of these units depends on 

decisions by their ratemaking authorities: state regulators; state governments; city councils; cooperative 

boards; Federal entities; and state regulatory bodies. If these plants become less competitive, 

authorities may decide to close nuclear units on economic grounds. Authorities can also decide to close 

nuclear units on grounds other than economics—for example, proximity to the New York City 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

metropolitan area (36 miles) has been cited as an additional concern in the continued operation of the 

Indian Point nuclear plant. 

Twenty-eight nuclear plants are now merchant plants that were spun off by VIEUs to affiliates under 

state electric restructuring efforts in the early 2000s. All of these merchant nuclear units operate in 

centrally-organized wholesale markets. Many of the units were spun off to exploit high locational 

marginal prices (LMPs) in centrally-organized wholesale electricity markets in the days of high natural 

gas prices.aa

 

In New York and Illinois, Clean Energy Standards and associated Zero Emission Credits (ZEC) for nuclear 

plants are being used to help maintain the economic viability and continued operations of nuclear 

plants, in part to help meet the states’ GHG-limiting goals. Modeled after existing RPS and Renewable 

Energy Certificates (REC), these ZEC payments68 69 have been established to direct additional funds to 

existing nuclear power plants that are no longer cost-competitive. Currently, only New York and Illinois 

have Clean Energy Standard programs, and these programs are being litigated in the courts. 

A recent Idaho National Laboratory report observes that70

 There is an industrywide systemic economic and financial challenge to operating nuclear

power plants in centrally organized markets;

 Given the confluence of market factors in combination with market structure in centrally

organized markets, a significant number of operating nuclear plants have negative cash

flow positions today;

 Given current trends, these market factors are unlikely to change significantly over the

next five years;

 Retirement of nuclear plants before their operating licenses expire is caused primarily by

lower revenues as opposed to higher operating costs, as wholesale electricity prices

have precipitously fallen over the last several years;

 The magnitude of the gap between operating revenues and operating costs is in the

range of $5–$15 per megawatt-hour (MWh). For a 1,000 MW nuclear unit, approximately

every $5/MWh of gap represents about $40 million in annual negative cash flow;

 Without action to enhance revenue (e.g., New York ZEC payments), more nuclear plants

will face retirements before the end of their operating license in the future.71

Figure 3.14 shows the nuclear reactors that have announced retirement, those that have closed, and 

those whose closure has been averted by state action. Between 2002 and 2016, 4,666 MW of nuclear 

generating capacity was announced for retirement, or approximately 4.7 percent of the U.S. total.72

 

aa Profits from high wholesale prices are not available to utility cost-of-service regulated units because their revenues are set by 

state regulators to recover operating costs and provide a target return on invested capital. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.14. Location of Nuclear Power Plant Retirements: Closed, Announced, and Averted73

As shown in Table 3-2, another eight reactors representing 7,167 MW of nuclear capacity (7.2 percent of 

U.S. nuclear capacity and 0.6 percent of total U.S. generating capacity74) have announced retirement 

plans since 2016. This does not include seven reactors that averted early retirement through state 

action.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Table 3-2. Nuclear Plant Retirements, Announced Closures, and Plants Averted by State Action75

76 77

As Table 3-2 shows, Indian Point is the only announced closure that lists state policy as the sole reason 

for retirement. 12 of the 16 plant closure announcements refer to unfavorable market conditions as the 

driver for plant retirement. Four of the five nuclear power plants (six reactors) that have shut down 

since 2013 were single-unit plants. Of the 11 nuclear power plants (15 reactors) that have announced 
32

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

intentions to close—including the five plants (seven reactors) in New York and Illinois that will remain 

open as a result of state action—four are dual-unit plants and seven are single-unit plants.

Table 3-3 shows the range of nuclear plant average costs in 2016 (in $/MWh). The data indicates that 

single-unit plants are more costly than multi-unit plants, and that operators who own only one nuclear 

plant have higher costs than those who own a fleet of plants. This is largely because some operating 

costs, such as security, do not scale linearly with plant size. As a result, single-unit or smaller plants are 

more expensive, and thus more likely to be retired prior to the end of their license terms.

Table 3-3. Average Nuclear Costs by Plant Size and Operator Type, 201678

A nuclear plant fully exposed to low wholesale energy prices can earn additional revenues in three other 

ways: it may receive capacity payments if it is located in a centrally-organized market with a capacity 

payment scheme (New York, New England, MISO, and PJM), it can earn revenues for providing reliability 

products such as frequency response,bb or it may receive ZEC or similar subsidy payments from its host 

state.

If a nuclear plant is owned by a VIEU, its regulators may allow it to continue collecting capital recovery 

from its ratepayers even though the utility is effectively paying more to run the nuclear unit than it 

would cost to buy the same energy and capacity under a bilateral contract or spot market purchases.

However, as long as natural gas prices stay low and there is an oversupply of energy in many hours, the 

typical nuclear plant may not be profitable. Bloomberg New Energy Finance estimates that 34 of the 

Nation’s 60 nuclear plants are losing money.

79

Not all nuclear power plants close due to unfavorable economics alone. For example, Pacific Gas and 

Electric (PG&E) has decided to shut down its dual-unit Diablo canyon plant in California due to several 

factors, including changes in state policy (California is moving to 50 percent RPS by 2040), new 

environmental regulations (replace once-through cooling system at an estimated cost of $8–$12 billion), 

local opposition to the NRC relicensing extension application, and uncertainty about future loads to be 

 

bb See Section 4.1.1 for the technical definition of frequency.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

served by the regulated utility (specifically, community choice aggregation, which allows for third-party 

retail suppliers). 

The NRC’s nuclear relicensing program is another factor affecting the future of U.S. nuclear power 

generation. The NRC issues initial reactor operating licenses covering a 40-year term, but those licenses 

have been routinely extended. Of the 99 operating nuclear reactors in the United States, 84 have been 

approved to operate for 60 years, while another nine are currently under review.80 However, based on 

the current and potential license extensions to 60 years, only three units (Comanche Peak Unit 2 and 

Watts Bar Units 1 and 2) will still be operating after 2050, unless subsequent license extensions—out to 

80 years—are submitted and approved. Two utilities have already announced plans to seek subsequent 

license renewal for two plants.81 

Extended nuclear plant operations often entail major capital upgrades of plant equipment. According to 

DOE’s Light Water Reactor Sustainability Program, the required capital costs for equipment upgrades 

drive the total cost for extension; these costs vary by plant. DOE estimates that it requires $500 million 

to $1 billion per plant of additional capital expenditures to operate a plant for an additional 20 years.82

These routine maintenance and equipment replacements would be required in this time frame 

regardless of the licensing process.83

Figure 3.15 shows a comparison of license duration to planned closure date. As depicted, most decisions 

to retire have come well before the expiration of the plant’s license. A few of the plants shown in the 

figure (indicated by a box around the plant name) were able to avert closure as a result of state actions. 

Figure 3.15. Nuclear Plant Retirements Compared to NRC Plant Operating License Terms84 85 86
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

3.4 Hydropower Retirements and Repowering

In 2015, the U.S. hydropower fleet included 2,198 active power generation plants with a total capacity 

of 79,600 MW and 42 pumped-storage hydropower plants totaling 21,600 MW.87 As of 2016, 

hydropower accounted for more than six percent of net U.S. power sector electricity generation, nearly 

nine percent of U.S. electric generating capacity, and 97 percent of U.S. utility-scale electrical storage 

capacity.88 Hydropower is currently the largest source of renewable generation, providing nearly 44 

percent of all U.S. renewable energy in 2016.89 90

Half of U.S. hydro capacity is located in the States of Washington, California, and Oregon. The 

hydropower fleet is the oldest in the U.S. -- as stated in QER 1.2, “About half the U.S. hydroelectric fleet 

is over 50 years old since many large dams were built between the 1940s and 1960s,”

91 and the average 

hydroelectric facility has been operating for 64 years. However, with routine maintenance and 

refurbishment of turbines and electrical equipment, the expected life of a hydropower facility is likely to 

be 100 years or more.92

Hydropower is a varied resource. Forty-eight states (see Figure 3.16) have hydropower facilities, led by

California, Oregon, and Washington. Ownership of hydropower plants is highly diverse, split across a 

wide range of private and public entities. Approximately 50 percent of hydropower capacity is owned by 

the Federal Government—the three main Federal agencies authorized by Congress to own and operate 

hydropower plants are the U.S. Army Corps of Engineers, the Bureau of Reclamation, and the Tennessee 

Valley Authority. Other public ownership includes public utility districts, irrigation districts, states, and 

rural cooperatives, whose hydropower resources consist of about 24 percent of the total installed 

capacity. Private owners—including VIEUs, merchant power producers, and industrial companies—

control the remaining 25 percent of total installed capacity.

93

Figure 3.16. Hydropower Plants in the United States by Capacity and Average Annual Runoff94
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

While some hydropower plants are operated as baseload resources, many also support the dynamic 

behavior of grid operations by offering a full range of ancillary services, including load following, 

spinning and non-spinning reserve, and voltage and frequency support. This flexibility has historically 

complimented other traditional forms of baseload generation, such as coal and nuclear. The majority of 

hydropower capacity is operated as either peaking or run-of-river. Peaking plants shift or delay water 

releases used for generation to higher value times of the day, contingent on a project’s storage 

capability and the regulatory requirements governing its operation. While peaking plants have usable 

storage from a project’s reservoir, run-of-river facilities have little to no ability to store water, and 

generation only changes based on the natural variability of flows, though even these types of facilities 

are capable of providing a number of ERS. In some regions, hydropower assets have been operated in 

more flexible modes in recent years as VRE penetration increases.95

 

At the beginning of 2011, hydropower plants comprised 24 of the 25 oldest operating power facilities in 

the United States, with 72 percent of facilities older than 60 years.96 However, significant capital 

investment toward modernizing and upgrading the existing fleet is consistently taking place to maintain 

reliability and, at times, uprate the capacity of existing facilities. From 2007 to 2016, the industry 

invested at least $8.7 billion in refurbishments, replacements, and upgrades to hydropower plants at 

143 hydropower facilities, including $1.2 billion and 34 plants in 2016 alone.97 This often includes 

equipment upgrades, turbine efficiency improvements, and modifications that ensure environmental 

protection and mitigation as part of relicensing terms. Most of the recent hydropower capacity additions 

in the United States have come from unit upgrades or additions to existing projects.98 While FERC does 

receive appropriations from Congress to defray operating costs, these appropriations are recovered 

completely through annual charges and administrative fees.99

EIA public reports indicate that 1,376 MW (of the total 79,985 MW of U.S. hydroelectric capacity) retired 

between 2002 and 2017—in most cases as part of repowering projects in which the retired turbine 

generators were replaced with new equipment. Fifty-two relatively small-scale hydroelectric generators 

representing 283 MW of generation capacity were retired without replacement.100

3.5 Falling Natural Gas Prices 

Shale gas development has significantly expanded the availability of natural gas and lowered its cost 

across the United States and the world.101 Before the widespread use of horizontal drilling techniques in 

the past decade, U.S. natural gas prices averaged more than $7 per million British thermal unit (MMBtu) 

between 2003 and 2008, and approached $14/MMBtu in several short periods (including in 2005 after 

Hurricanes Katrina and Rita reduced production and delivery from Gulf of Mexico sources).102 Hydraulic 

fracturing practices spread and made previously inaccessible gas sources economic, causing natural gas 

prices to fall, averaging less than $3.20/MMBtu between 2012 and 2016.

103

 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.17. Conventional and Shale Natural Gas Production, 2007–2016104

Wholesale electricity prices generally tracked natural gas prices for the study period, as shown in Figure 

3.18. This is likely because gas-fired mid-merit and peaker power plants have been the marginal 

generators following load in many hours of the day, and their short-run marginal costs are driven by 

natural gas prices.105 Thus, natural gas plants and gas prices have been the largest single driver of spot 

electricity prices. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.18. Wholesale Day-Ahead Electricity Prices vs. Henry Hub Natural Gas Price (Monthly 

Average)106

The price of natural gas is a key factor in the prices generators offer in the bid-based RTO/ISO wholesale 

electricity markets. It is also a factor in the prices set in bilateral power sales, including in the nonRTO/ISO regions such as the Southeast. Consequently, wholesale and bilateral transaction prices are 

often driven by natural gas prices across large parts of the U.S. power market.cc On one hand, wholesale 

electricity prices have become increasingly exposed to potential volatility in natural gas delivered prices. 

On the other hand, the Nation has realized significant economic benefits from the shale revolution—

falling natural gas prices between 2007 and 2013 generated an estimated net economic benefit of $48 

billion per year over this period.107

Natural gas-fired generation has grown nearly continuously since the late 1980s (see Figure 3.19) for 

several key reasons. These plants have low capital costs and are, in general, relatively less expensive 

than some competing technologies.108 They are also much less land-intensive than many other types of 

generation, and thus often can be more easily sited in urban areas near electric demand.109 Similarly, 

natural gas pipelines can be built more quickly than electric transmission lines (in most states) because 

they have a comparatively streamlined permitting process, which often has made it easier for a plant 

developer to build a new gas-fired plant near a large electric load than to build a power plant farther 

away and transmit its electricity to large load centers by wire.dd

 

cc When natural gas prices were high, this situation yielded large profits to the then lower-cost coal and nuclear power 

producers. However, as gas prices and therefore wholesale and bilateral contract power prices have declined, the situation has 

reversed, and many coal and nuclear plants have been losing money. 

dd Interstate natural gas pipelines can often be built more quickly than transmission lines because the pipeline owners, once 

granted a FERC-issued certificate of public convenience and necessity, have eminent domain power under section 7(h) of the 

Natural Gas Act and the procedures set forth under the Federal Rules of Civil Procedure (Rule 71A). By contrast, electric 

transmission developers are dependent on states to grant eminent domain authorization. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.19. Total Annual U.S. Natural Gas Generation, 1950–2016

110

The two main types of natural gas generators (NGCCs and CTs) offer distinct operational advantages. 

NGCC generators are very efficient and have significantly higher capacity factors than single111 (simple) 

cycle natural gas CTs, which contribute primarily to meeting peak load and may only operate for a few 

hours a year.112 A CT’s short start-up time and fast ramp rate make it the most responsive component

for ensuring enough capacity exists to meet demand during the highest-peak demand hours of the year

and help maintain grid reliability, absent affordable grid-scale storage. For this reason, CT capacity 

factors are usually lowee (generally below 10 percent).113 CTs can go from cold start-up to 100 percent 

output in seven to 11 minutes; in contrast, coal-fired units ramp on the order of hours, and doing so 

incurs increased operations and maintenance costs.114 NGCC ramp rates fall somewhere in between, and 

some NGCC units can ramp to full-rated power in less than 30 minutes.115 This flexibility makes NGCCs 

and CTs useful in complementing VRE because their flexibility allows these plants to match changes in 

solar or wind output.

Until recently, most NGCC units were used for intermediate and peak loads rather than baseload.

However, because natural gas prices have been low for a sustained period, and because NGCC plants 

retain some of the flexible characteristics of CTs and operate at a higher efficiency and lower cost, these 

units often are now used for baseload power. As a result, some coal plants have been pushed higher on 

the merit order, which reduces their average capacity factors, negatively impacts their economics, and 

can ultimately lead to retirements.

 

ee Some states rely on CTs more regularly than other locations; most notably, Texas, Louisiana, Wyoming, New Hampshire, 

Maine, and Rhode Island all have CT capacity factors greater than 20 percent. https://energy.gov/epsa/downloads/electricitygeneration-baseline-report.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

On top of low fuel prices, natural gas-fired power plants have become more fuel efficient over the study 

period. Figure 3.20 shows how the fuel energy usage per unit of electricity generation of the fleet of 

generators has changed from 2002 to 2016 for each fuel type. The natural gas fleet has become 

increasingly efficient (i.e., achieved a lower heat rate) as old steam electric plants have retired and many 

new, highly efficient NGCC plants have been built and operated at high utilization rates.116

Figure 3.20. Heat Rates for Coal, Nuclear, and Natural Gas, 2002–2016117

3.6 Environmental Regulations 

A suite of environmental regulations affecting the electricity generation sector had implementation 

deadlines between 2011 and 2021, stemming from statutes enacted between 1970 and 1990. These 

regulations have had disparate effects on the costs of various power generation technologies. While the 

cost of environmental regulations has been significant for coal-fired power plants in particular, the 

evidence reviewed below indicates that regulations were not the sole cause of observed coal 

retirements, but were certainly a contributing factor. Following are two key takeaways: 

1. Timing suggests that regulations had an impact on retirements. Of the 59,392 MW of coal-fired

power plants that retired between 2002 and 2016, approximately 48,800 MW or 82 percent of

that capacity retired in the period 2012–2016, when significant environmental regulations

would have affected the invest-or-retire decision. This left 270,000 MW of coal-fired capacity on

the grid (down from 315,000 MW in 2002), which produced 30 percent118 of total 2016 U.S.

electricity output (down from 50 percent in 2002).

2. Many of the coal plants that retired were no longer “baseload.” Due to low natural gas prices

and abundant natural gas generation capacity additions, most of the coal plants that retired

between 2011 and 2015 (when the environmental regulations took effect) had not been

operating in their intended baseload fashion for several years.119
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

All nuclear power plants are affected by regulations pertaining to safety, security, and upgrades required 

for license renewal. In addition, nuclear plants are affected by the Cooling Water Intake Rule, and some

announced closures have cited, among other reasons, state requirements to modify cooling water

systems as a reason for retirement.

120 121 Hydropower plants are also affected by other environmental 

regulations and unique licensing processes.

Table 3-4 summarizes major environmental regulations finalized after 2011 affecting coal, natural gas, 

and nuclear power plants.

Table 3-4. Major Environmental Regulations Related to Coal, Natural Gas, and Nuclear Generation

Name Year 

Finalizedff

Year (s) 

Implemented

Authorizing 

Statutegg

Major Provisions Generation 

Sources 

Affected

Cooling Water 

Intake Rule122

2001 

(Phase 1), 

2003 

(revised 

Phase 1),

2014 

(Phase II) 

Phase II: 

2014–2018123

Clean Water 

Act 

 Promulgated under 316(b) of the Clean 

Water Act. New sources regulated under 

Phase I and existing sources regulated 

under Phase II.

 States consider requirements for power 

plants on a case-by-case basis.

124

 Requires controls to reduce mortality to 

fish and other aquatic organisms.

Coal

Gas

Nuclear

Cross-State Air 

Pollution 

Rule125

2011 Phase 1: 2015

Phase 2: 2017

Clean Air Act  The Cross-State Air Pollution Rule 

replaced the Clean Air Interstate Rule 

starting on January 1, 2015, and requires 

states to reduce power plant emissions of 

SO2 and NOx that contribute to ozone 

emissions and fine particle pollution in 

other states.126

Coal

Gas

Steam Electric 

Effluent 

Limitations 

Guidelines127

1974;

policy 

updates in 

1977, 

1978, 

1980, 

1982, and

2015

1982; 2015 

update is 

stayed while 

EPA reviews 

rule

40 CFR 423  Established limitations on the discharge of 

toxic and other chemical pollutants and 

thermal discharges from existing and new 

steam electric power plants, as well as 

pretreatment standards.

 The 2015 update sets the first Federal 

limits on levels of toxic metals that can be 

discharged.

Coal

Gas

New Source 

Reviewhh

1980;

policy 

updates in 

1996 and 

2002

1980; 2002 

updates under 

court 

challenge

Clean Air Act  Affects stationary sources of air pollutants. 

Requires that a new or modified power 

plant obtain a pre-construction permit to 

ensure, among other things, that modern 

pollution control equipment is installed.

 Requirements differ depending on whether 

or not the plant is located in an area that 

Coal

Gas

 

ff Dates shown here reflect the date of publication in the Federal Register.

gg For regulations only.

hh The New Source Review (NSR) program affects most new and modified power plants and manufacturing facilities. 

Determining when a facility is making a modification that triggers NSR has been a subject of debate. Attempts have been made 

over decades to update NSR—the latest in 2002. More information can be found at: 

http://www.rff.org/research/publications/epa-s-new-source-review-program-time-reform and 

http://www.aei.org/publication/making-sense-of-new-source-review/
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

meets the requirements under the National 

Ambient Air Quality Standards.

Mercury and Air 

Toxics 

Standards128

2012 2015–2016 Clean Air Act  Establishes emissions limits for mercury,

arsenic, acid gases, and other toxic

pollutants from coal- and oil-fired power

plants.129

 Utilities had until April 2015 to comply with

the standards with many plants receiving a

1-year extension.

Coal

Coal 

Combustion 

Residuals 

Rule130

2015 2015-2018ii Resource 

Conservation 

and 

Recovery Act

 Addresses groundwater contamination

risks from coal combustion residuals (i.e.,

“coal ash”) disposal in unlined landfills and

surface impoundments by establishing

national standards for disposal.

Coal

Regional Haze 

Rule

1999; 

policy 

revisions 

in 2017

Revised state 

plans due in 

2021

Clean Air Act  Requires states to develop long-term

strategies, including enforceable measures

to improve visibility in 156 national parks

and wilderness areas.

 Aims at returning visibility to natural

conditions by 2064.

Coal

Carbon 

Pollution 

Standards and 

Clean Power 

Plan131

2015 Under EPA

review

Clean Air Act  Carbon Pollution Standards established

CO2 emission standards for new fossil fuelfired generators under Clean Air Act

section 111(b).

 The Clean Power Plan, promulgated under

section 111(d) of the Clean Air Act,

establishes CO2 emission standards for

existing power plants.

Coal

Gas

The collective impact of this suite of regulations required owners to weigh the cost implications of a 

variety of compliance options for their plants, and to also look closely at whether their market prospects 

(expected production costs and capital needs, relative coal and natural gas fuel costs, competition from 

other generators, technology availability, and customer demand levels) or regulatory regime would 

allow recovery of those costs in future operating years. Most of these rules were litigated and 

delayed—the Clean Power Plan, for example, currently is stayed and ultimately may be rescinded, but 

uncertainty about its implementation nonetheless affected plant owners’ compliance and retirement 

planning. 

In 2011, looking at then-current energy market prospects and fuel prices, it appeared that many power 

plants would be affected by these environmental regulations. Fitch Ratings estimated that 51,000 MW 

of coal units (smaller than 200 MW each, with a capacity-weighted average age of nearly 

50 years) were at risk for retirement, particularly those operating in restructured electricity markets 

with no recourse to regulated cost recovery.132 

In 2011 and 2012, electric industry projections of likely regulation-induced retirements that focused on 

the many unknowns associated with pending environmental regulations sometimes showed a very large 

number of retirements. These unknowns included how stringent environment remediation 

requirements would be; what remediation technology and strategies might satisfy those requirements; 

how close together the compliance deadlines would fall; and the implications for regional reliability, 

ii The Water Infrastructure Improvements for the Nation Act S.612, passed in December 2016, authorizes states to create their 

own permitting programs for coal combustion residuals disposal, subject to EPA approval. The act specifies that states may 

adopt alternative standards that are “at least as protective” as national standards. EPA has not yet issued guidelines or 

regulations by which state permitting programs can be approved. 
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energy production costs, and retail energy rates if too many power plants were to close rather than 

invest in remediation.

Environmental regulations generally increase power plant operating costs by requiring plant owners to 

install capital equipment that controls plant emissions. The electrical load from equipment such as SO2

scrubbers (“parasitic load”) may also reduce the plant’s net generation available for sale on the grid.

Increased operating costs push the compliant plant farther out on the energy supply (dispatch) curve 

and can cause it to be dispatched less frequently than it would have without the emissions controls, as 

shown in Figure 3.21 using coal as an example. 

Figure 3.21. PJM Merit-Order Dispatch: Various Control Technologies133

This figure shows power plants separated by technology type for PJM, in “merit order”, i.e., based on their 

marginal cost of generation, in the year 2012. The vertical lines represent various levels of load. The 

diamonds represent marginal costs (sum of fuel and variable operating and maintenance costs) for one 

subcritical pulverized coal plant with no control technology and that same plant with variations of two 

select pollution control technologies that reduce acid gas pollution. In principal, all the plants left of a 

vertical line operate at the level of demand represented by that line. (In reality, transmission constraints 

and reliability considerations can change that significantly.) 

As a plant moves to the right on the curve it will tend to operate less due to the increase in marginal cost. 

Control technologies key: dry FGD = dry flue gas desulfurization; three types of DSI (hydrated lime, trona, 

and sodium bicarbonate) = dry sorbent injection. Another control technology not shown that is used to 

reduce acid gas emissions is wet flue gas desulfurization. Technology key: Renew = other renewables 

not including hydropower or wind power; Water = hydropower; LOil = light oil-fired power plants; HOil = 

heavy oil-fired power plants; Nuc = nuclear power. 
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3.6.1 Coal Plants and Environmental Regulation 

Existing coal-fired power plants must not only comply with all Federal requirements related to emissions 

and water use, wastewater treatment, and solid waste management, but also with any additional 

applicable state regulations.134 Cost impacts of these regulations varied. The EPA reported that a typical 

coal-fueled unit with a capacity of 700 MW could incur incremental operating and maintenance costs 

ranging from $287 million to $351 million to install a scrubber, from $116 million to $137 million to 

install a selective catalytic reduction unit, and from $97 million to $114 million to install a baghouse 

(fabric filter). Fitch estimated the lifetime costs and reduced cash flow associated with environmental 

retrofits at $1,700–$1,900 per kilowatt (kW) for a 100 MW plant burning bituminous coal, as compared 

with a range of $1,200–$1,300/kW for a 500 MW plant.135 These costs are on par with those of 

constructing a new typical (i.e., subcritical) coal plant of similar size during this same time period 

(averaging $1,361/kW).136 Reported planned retirements from that time suggest that approximately 

27,000 MW or 8.5 percent of 2011 coal-fired capacity was rendered uneconomic under the combination 

of regulatory compliance costs, little demand growth, and falling natural gas prices.137

The MATS rule was potentially the most expensive and immediate of the suite of pending regulations, 

with a compliance deadline of April 2015 (later extended to April 2016 for some plants). Further, owners 

of coal facilities were dealing with MATS compliance in combination with the cost of imminent 

additional regulations of CO2, along with other GHGs. EIA reported that by the end of 2012, 64 percent 

of the U.S. coal generating capacity in the electric power sector already had the appropriate 

environmental control equipment (most reported using flue gas desulfurization) to comply with the 

MATS rule and operate past 2016; another six percent planned to add control equipment; 10 percent 

had announced plans to retire; and the other 20.4 percent still had to decide whether, how, and when 

to upgrade or retire their plants.138 

The dominant MATS compliance strategy among coal-fired plant owners was to install activated carbon 

injection (Figure 3.22), which averaged a relatively modest $5.8 million per generator from 2015 to 

2016. EIA estimates that “operators invested at least $6.1 billion from 2014 to 2016 to comply with 

MATS or other environmental regulations.”

139 In its rulemaking, EPA estimated an annualized cost of 

$9.6 billion in 2015, declining to $7.4 billion annually in 2030.140
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Figure 3.22. Changes in U.S. Coal Capacity, December 2014–April 2016141

The retrofit-or-retire decision for owners is also impacted by EPA's New Source Review (NSR) regulations 

that can affect owners’ ability to enhance plant efficiency due to the delay, cost, and uncertainty 

associated with obtaining an NSR permit. The NSR permitting program requires stationary sources of air 

pollution—including factories, industrial boilers, and power plants—to get permits before construction 

starts, whether the unit is being newly built or modified.142 This is an important concern for owners 

considering retrofitting an existing power plant with carbon capture equipment to reduce CO2 emissions, 

or adding new components to improve operating efficiency. These upgrades could trigger the NSR 

requirements of the Clean Air Act because they would constitute a “physical change,” or lead to a 

designation of the change as a “major modification,” subjecting the unit to NSR permitting 

requirements.

The uncertainty stemming from NSR creates an unnecessary burden that discourages rather than 

encourages installation of CO2 emission control equipment and investments in efficiency because of the 

additional expenditures and delays associated with the permitting process.143 144 Ironically, the 

uncertainty surrounding NSR requirements has led to a significant lack of investment in plant and 

efficiency upgrades, which would otherwise lead to more efficient power generation, benefits to grid 

management, and reduced environmental impacts. EPA has acknowledged these burdens and has made 

attempts to reform the rules to improve and streamline NSR:

As applied to existing power plants and refineries, EPA concludes that the NSR program has 

impeded or resulted in the cancellation of projects which would maintain and improve 

reliability, efficiency and safety of existing energy capacity. Such discouragement results in 

lost capacity, as well as lost opportunities to improve energy efficiency and reduce air 

pollution.

145

The NSR program distinguished between “routine maintenance and repair” of existing facilities—which 

would be allowed—and more “substantial modification” of existing facilities, which would put the 

facilities over the threshold and thus require them to meet new emissions standards. 

Environmentalists argued that owners of electric generation and industrial plants were building virtually 

new facilities from the inside out by exploiting the “routine maintenance and repair” exclusion from 

NSR. EPA changed its interpretation in the 1990s to a more rigorous standard, culminating in numerous 

enforcement-related lawsuits beginning in the late 1990s.146
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By the late 2000s, some older coal units operating without pollution controls were no longer operating 

as baseload units, having operational capacity factors estimated at 47 percent to 56 percent.147 As Figure 

3.23 shows, rather than acting as baseload units at high capacity factors, these older units (with an 

average capacity of 109 MW) were operating at falling capacity factors. The units that retired in 2014 

had an average capacity factor of 13 percent in 2013. 

Figure 3.23. Average Coal Plant Capacity Factors, 2008–2014148

Coal plant capacity factors generally fell from 2008 through 2014, with plants that retired in 2014 

operating at much lower capacity factors than all coal plants. 

Some owners delayed their retirement announcements and retrofit decisions in order to see how the 

regulation litigation challenges played out, in case a late court ruling made compliance unnecessary, 

signifying that the cost of complying with those regulations was a factor in their retirement decisions. 

Others delayed closing uneconomic plants to see if enough other plants retired, in hopes that the 

resulting shift in market dynamics and prices might render the unretired plants profitable again.149

 

Figure 3.24 shows total U.S. coal capacity from 2008 through mid-2016 and projections through 

mid-2018. While there was a fall in coal plant capacity in 2015 associated with the MATS compliance 

deadline, EIA finds that fewer coal facilities retired in 2015 and the first half of 2016 than EIA had 

projected ahead of the compliance deadline. Specifically, in 2015 and until the April 2016 extended 

MATS deadline, about 20,000 MW of coal capacity retired and another 9,000 MW of coal capacity 

converted to natural gas, while EIA projected 50,000 MW of retirements between 2013 and 2020, with 

the majority retiring in 2015 in response to MATS.150 However, EIA’s projection also included other 

factors that can drive retirement decisions, such as the Clean Power Plan. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.24. Projected and Actual Coal Retirements, 2008–2018151

Fewer coal plants retired in 2015–2016 than projected.

3.6.2 Natural Gas Plants and Environmental Regulation

Because natural gas emits far less air pollution than coal-fired power plants,

152 the regulatory burden 

and cost to natural gas-fired power plants is much lower than for coal plants. ERCOT’s December 2014 

analysis estimated that the Cross-State Air Pollution Rule (CSAPR)

jj and the Cooling Water Intake Rule

would impose moderate compliance costs on natural gas-fired power plants.153 Specifically, ERCOT 

estimated costs of $0.10–$2.75/MWh for CSAPR and $0.10–$0.50/MWh for the Cooling Water Intake 

Rule.

The large majority of natural gas plants that have retired are NGSTs, which are less efficient than the 

newer NGCCs.

154 From 2002 to 2016, there was a steady stream of NGST retirements, some of which 

may be linked to decisions about the cost effectiveness of retrofit upgrades. However, during the period 

2014–2016, 23,500 MW of new natural gas capacity was added, nearly double the total natural gas 

capacity that was retired as part of the transition from NGST units to more efficient NGCC units.

155 NGCC

plants have replaced NGST plants for baseload use and natural gas combustion turbines have been built 

for peak power demand.

3.6.3 Nuclear Plants and Environmental Regulation

The principal environmental regulation affecting nuclear power plants is the Cooling Water Intake Rule, 

which applies to all types of power plants but is most challenging for nuclear plants. A revised version of 

the Cooling Water Intake Rule has been in effect since 2003. The rule was promulgated to protect 

aquatic life. States may decide how to implement the rule, such as by requiring a nuclear (or other) plant 

to invest in a closed-loop cooling system to replace once-through ocean or waterway cooling. Three of 

the nuclear plants that have announced closures (Oyster Creek in New Jersey, Diablo Canyon in 

 

jj Finalized in 2011 and effective in 2015.
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California, and Indian Point in New York) have cited disputes with their respective states over cooling 

water rule compliance among the reasons for plant retirement. 156 157

The Administrative Consent Order between Exelon and New Jersey establishing Oyster Creek’s 2019 

retirement specifically mentions Section 316(b) of the Clean Water Act as part of the state’s justification 

in requiring the construction of cooling towers if the plant were to operate for the full duration of its 

license extension.158 

Nuclear plants are also affected by other regulatory factors and fees that are not imposed on other 

types of power plants. Recent examples include major safety reviews following the Fukushima Daiichi 

nuclear plant failures in 2011. A recent study found that the rising regulatory costs of nuclear energy—

which approach $60 million per year—exceed the profit margins of many of these plants.159

3.6.4 Hydropower Plants and Environmental Regulation 

As authorized under the Federal Power Act, FERC issues licenses to non-Federal hydropower projects, 

which comprise roughly 50 percent of existing U.S. hydropower capacity. The FERC regulatory 

framework involves numerous participants, such as Federal and state resource agencies; nongovernmental organizations; state, local, and tribal entities; and the public. Because of the complexity of 

the regulatory processes and numerous agencies involved, hydropower licensing timelines often are 

cited as being among the lengthiest and costliest for energy projects in the United States. A DOE analysis 

looking at the development timelines of 29 projects that came online from 2005 to 2013 found that the 

median project took over 15 years from application to operation.160 For wind and solar, the average 

permitting time is two to four years.161

A few hydroelectric power plants have not sought relicensing due to concerns over the cost of meeting 

mandatory environmental requirements imposed by Federal and state resource agencies. Capital 

upgrade requirements can include capacity uprates (initiated by the plant owner rather than a 

regulator), dam safety upgrades, or environmental improvements.162 

3.7 Growing VRE Deployment 

Wind and solar PV—collectively, VRE—have constituted the vast majority of the VRE deployed in recent 

years. Wind first surpassed 1 percent of total U.S. generation in 2008, while total solar generation 

reached that threshold in 2015.kk Figure 3.25 shows trends in penetration—as a percentage of total 

generation—for wind, solar, hydroelectric, geothermal, and biomass power plants in the United States 

since 2001. Total end-use demand served by wind generation tripled from 1.5 percent in 2008 to 4.5 

percent in 2013. Total renewable generation has now exceeded 14 percent of the U.S. total, with hydro 

and wind comprising the largest components. 

kk While annual variation in water availability affects conventional hydroelectric output from year to year, hydro generally has 

been consistent between 6 percent and 8 percent of total generation since 2001. 

https://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 
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Figure 3.25. VRE Generation by Fuel as Percentage of Total U.S. Generation, 2002–2016163

At the end of 2016, U.S. installed wind capacity surpassed that of hydro for the first time (see Figure 

3.26).164 165 However, given the hydro fleet’s higher average capacity factors and the above-normal 

precipitation on the West Coast so far this year, hydro generation will likely once again exceed wind 

generation in 2017, though the gap continues to narrow. 

Figure 3.26. Cumulative U.S. Utility-Scale Wind and Hydroelectric Generation Capacity, 1915–

December 2016166 

3.7.1 Technology and Policy Drivers for Deployment 

The deployment of wind and solar power has been spurred by a combination of technology cost 

declines; state RPS; private sector sustainability goals; consumer choice; Federal and state incentives; 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

transmission expansion—such as the Texas Competitive Renewable Energy Zone project—to reach highquality resource areas; and Federal and state environmental, air quality, and GHG emissions reductions 

policies. 

RPS—now in 29 states and the District of Columbia, covering 55 percent of total U.S. retail electricity 

sales—have also been substantial drivers of VRE growth, as they are associated with 60 percent of 

renewable generation growth since 2000.167 Though wind has historically been the largest beneficiary of 

RPS policies, more RPS-driven solar than wind was added in 2015.168 RPS also create a market for RECs. 

RECs represent some of the environmental attributes of renewable generation that can be bought, sold,

and applied to meet certain state RPS plans, and they create an additional subsidy to renewable 

generation. 

Technologies typically experience cost reductions as their deployment grows due to technology 

improvement and increasing economies of scale. Lower investment costs, in turn, spur further 

deployment—since 2009, solar PV installed system costs have fallen approximately 60 percent on a per 

kilowatt basis for residential and commercial systems (from $7.06/WDC to $2.93/WDC for residential and 

from $5.23/WDC to $2.13/WDC for commercial) and 70 percent for utility-scale systems (from $4.46/WDC 

to $1.42/WDC).169 However, other factors can interrupt this general trend; for example, increases in 

warranty costs and the prices of commodities such as steel and fiberglass (among other factors) drove 

wind turbine installed system costs on a per-megawatt basis to double between 2000 and 2008 (though 

these costs went on to decline by 40 percent since 2010).170

 

Importantly, these capital cost trends do not account for technology improvements that improve 

performance and economics. For wind, improvements in turbine technologies and taller towers have 

resulted in increased capacity factors. For example, in 2015, capacity factors averaged 25.8 percent for 

wind projects built from 1998–2003 and averaged 41.2 percent for wind projects built in 2014.171

Similarly, for utility-scale PV, optimized system design—including use of single-axis tracking and 

increasing inverter loading ratios—partially contributes to capacity factors increasing from 

21 percent for 2010 vintage projects to 26.7 percent for 2014 vintage projects in 2015. 

In addition to research and development (R&D)—which is aimed at reducing technology costs through 

innovation—the investment tax credit (ITC) and PTC, as well as state-level RPS, have driven expansion of 

VRE, particularly wind and solar. Figure 3.27 shows the substantial increase in wind capacity since 1998 

during the period when a PTC has been in effect. It also suggests the wind industry’s tendency to 

increase investments in years when the tax credit was due to expire and its extension was uncertain. 

The current PTC is scheduled to be phased out after 2019.172 The solar ITC—currently at 

30 percent—will be reduced after 2021 to its statutory level of 10 percent for commercial and industrial 

projects, and will be phased out completely for residential projects.173
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Figure 3.27. Relationship between the PTC and Annual Wind Capacity Additions

The PTC has accelerated wind project deployment significantly—between 2000 and 2013, cumulative 

wind capacity grew from less than 5,000 MW to more than 60,000 MW—though capacity additions 

noticeably track the PTC expiration and extension schedule. Similarly, the dramatic decrease in wind 

capacity additions during PTC expiration years underscore the notion that credits are driving 

deployment, rather than market decisions. For example, during the PTC expiration “cliff” in 2013, new 

builds counted for 1 MW of added capacity. After renewal of the PTC, new capacity jumped to 5 MW.174

This change occurred in the absence of any change in state RPS requirements.

A panel of economists at a May 2017 FERC technical conference cited state-level RPS and Federal tax 

credits for VRE as examples of market-distorting subsidies and mandates. These policies reduce 

revenues for traditional baseload power plants by lowering the wholesale electric prices they receive 

and by displacing a portion of their output. To date, however, the data do not show a widespread

relationship between VRE penetration and baseload retirements, as shown in Figure 3.28.

175

 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.28. VRE Penetration as a Percentage of 2016 Generation versus Retired Capacity since 

2010 as a Percentage of Non-VRE Capacity176

While concerns exist about the impact of widespread deployment of renewable energy on the retirement 

of coal and nuclear power plants, the data do not suggest a correlation. 

Subsidies 

Federal and state governments use subsidies, mandates, and prohibitions to affect how public and 

private entities behave. Subsidies make the favored behavior or product more appealing relative to 

other competing products by accelerating its development (as with R&D and direct construction 

expenditures), lowering its ultimate cost to the consumer (as with tax incentives, low lease payments or 

grants), or making the product better known and more appealing (customer education, ratings, and 

marketing). In contrast to subsidies, mandates and prohibitions create absolute requirements for the 

user for whether and how much of the targeted product to consume. 

The Federal Government has always used a variety of subsidies to support a myriad of public and private 

sector goals. Over the long term, subsidies are spent on different technologies at different times, 

reflecting differing societal priorities and technology maturities. Early subsidies included Federal 

construction of hydroelectric dams and multi-purpose water management projects beginning in the 

1930s. Energy R&D spending began in the 1950s with the passage of the Atomic Energy Acts of 1946 and 

1954, with major Federal investments in the commercialization of nuclear electricity. R&D investments 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

increased sharply after the oil price shocks and energy crisis in the 1970s, and renewable energy R&D 

supported VRE.

Accurately accounting for energy subsidies and expenditures is highly dependent on the scope and time 

period of the analysis. For example, some tax incentives may affect energy industries but are not specific 

energy-related measures, such as Section 199 of the American Jobs Creation Act of 2004, which allows 

tax deductions for domestic manufacturing. Natural gas producers, along with many other types of 

manufacturers, have been able to take advantage of this tax incentive even though it was not an energyspecific measure. This is just one example of the difficulty in examining energy-related subsidies and 

expenditures both from Federal and non-Federal sources, many of which may not be directly 

comparable.

ll

As a snapshot of Federal subsidies and support for electricity generating technologies for a given year, 

Table 3-5 shows electricity production subsidies and support that includes breakouts by direct 

expenditures, tax expenditures, R&D, and other Federal programs, compiled by EIA for Fiscal Year 2013. 

Although this data has not been compiled for every year, the 2013 data can be instructive. For example, 

VRE technologies received a majority of Federal support that year relative to other technologies, 

particularly reflecting the technical maturity of VRE relative to conventional technologies.

 

ll For a longer discussion on energy subsidies and various reports examining energy subsidies, see 

https://www.eia.gov/analysis/requests/subsidy/pdf/subsidy.pdf.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Table 3-5. Fiscal Year 2013 Electricity Production Subsidies and Support177

Similarly, it is important to note how these particular results are driven by the unique nature of a given 

year. For example, the large direct expenditures for wind and solar overwhelmingly arise due to the 

Treasury 1603 program enabled by the American Recovery and Reinvestment Act of 2009, which 

allowed one-time cash grants to eligible renewable generators in lieu of tax credits. This was only 

available to generators who began construction in 2009–2011, and as such is no longer a direct 

expenditure. 

There is no complete multi-year assessment available that describes and analyzes the Federal subsidies 

and support provided to different generation technologies over time. Continued examination of Federal 

subsidies and support, and provision of this information to the public, can better inform the decisions 

made by Federal, state, and local entities. 

Workforce Impacts of Growing VRE Deployment 

As the electricity system changes, so do the types of jobs, skills needed, and education or training 

required. The evolving demands of the grid are creating new opportunities in information and 

communication technologies and in the deployment of new generation, including natural gas and VRE. 

Job growth has been strong in the VRE sector, and the solar and wind workforce increased by 25 and 32 

percent, respectively, in 2016.178 DOE’s 2017 U.S. Energy and Employment Report found that the solar 

and wind industries provide 373,000 and 101,000 jobs, respectively, across the Nation.179 Veterans 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

comprise a higher percentage of employees in the electricity industry compared to other industries, and 

in 2015, the solar industry provided nearly 17,000 jobs for veterans in manufacturing, installation, and 

project management.180

3.8 Flattening Electricity Demand

Between 1970 and 2005, total U.S. electricity generation to meet customer demand grew at a 

compound annual growth rate (CAGR) of 2.7 percent.

181 But since 2005, generation growth has stalled 

with a CAGR of only 0.05 percent from 2005 to 2015, even as the Nation’s GDP grew by 1.3 percent per 

year over the same period.

182

Electricity demand historically had risen with economic growth (real GDP), but the two began 

decoupling around 2000, as shown in Figure 3.29. EIA attributes this decline in the demand growth rate

to a variety of factors, including the cumulative impact of energy efficiency programs, standards, and 

codes; technology improvements in appliances, lighting, and other end-use equipment; and broader 

structural changes, such as a shift toward less electricity-intensive industries and slower population 

growth.

183

Figure 3.29. Gross Domestic Product and Net Electricity Production, Historical (1950–2016) and 

Projected (2017–2027)184 185 186 187

Figure 3.30 shows one analysis of how efficiency improvements, coupled with structural changes in the 

economy, have led to flattening energy use in recent years.Overall, there has been significant progress 

across the U.S. economy in improving the value of goods and services produced per unit input of energy.

For example, electricity productivity in the industrial sector—measured in dollars of economic output 

per kilowatt-hour of electricity input—nearly doubled between 1990 and 2014. The noticeable dip in 

both GDP and net electricity generation in 2008–2009 reflects the U.S. recession, which lowered 

electricity usage enough to affect power plant economics and prompt some plant closures.188
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.30. Estimated U.S. Energy Savings from Structural Changes in the Economy and Energy 

Efficiency, 1980–2016189 190

The U.S. economy has made significant progress in improving the value of goods and services produced 

per unit input of energy, through both energy efficiency and structural changes to the U.S. economy. 

Figure 3.31 shows more broadly the impact of these changes on the EIA's Annual Energy Outlook (AEO) 

Reference case electricity sales forecast for various years. Each AEO forecast is made assuming that laws 

and regulations in effect at the time of the projection will continue unchanged through the projection 

period, unless scheduled end dates for those laws and regulations are within that period. The objective 

is to provide a “business-as-usual case;” no assumptions about new policies are included. Over the past 

several decades, new Federal and state policies, market forces, and broader economic factors have 

contributed to lowering levels of electricity consumption compared to what was expected to occur in 

absence of any new policy, as shown by the comparison of historical Reference case projections to 

actual U.S. electricity sales (shown as dotted lines in Figure 3.31). 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.31. EIA Annual Electricity Sales 2000–2016 (terawatt-hours) and AEO Reference Case 

Electricity Sales Projections 2017–2030191

A changing policy and market environment since 2000 has made it challenging to accurately forecast 

electricity demand. TWh is terawatt-hours.

As stated in QER 1.2: 

Currently, about 90 percent of residential, 60 percent of commercial, and 30 percent of 

industrial energy consumption are used in appliances and equipment that are subject to 

Federal minimum efficiency standards implemented, and periodically updated, by the 

Department of Energy. Between 2009 and 2030, these cost-effective standards are projected 

to save consumers more than $545 billion in utility costs, reduce energy consumption by 

40.8 quads, and reduce carbon dioxide emissions by over 2.26 billion metric tons.192

There are two significant impacts from the growth in energy efficiency. First, suppliers can no longer 

expect robust demand growth. Second, because customers are buying less electricity, the market price 

of electricity clears lower on the electricity supply curve (all else equal). Thus, higher-cost power plants 

that might have been dispatched and earned revenues in a higher-demand market are dispatched less 

frequently and earn less revenue due to increased energy efficiency.

 

nn The report, Economic and Market Challenges Facing the U.S. Nuclear Commercial Fleet, produced by Idaho National 

Laboratory and the Center for Advanced Energy Studies (September 2016), attributes low electricity market prices to “low 

natural gas prices, low demand growth, increased penetration of renewable generation, and negative electricity market prices.”
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3.9 Power Plant Retirements Looking Forward 

While recognizing the difficulty in making any long-range forecast, it is useful to examine modeled 

scenarios to understand how the factors affecting retirements are expected to evolve. Figure 3.32 shows 

the announced and modeled coal, NGCC, and nuclear retirements and additions from 2017 through 

2030 in EIA’s AEO 2017. This shows that coal retirements are projected to continue in the near term—

with 37,800 MW projected to retire between 2017 and 2022—and taper off in the longer term, with 

another 4,400 MW of retirements between 2023 and 2030. Announced nuclear retirements in the near 

term account for most projected retirements, with an additional 3,000 MW of modeled unplanned 

retirements in the period 2019–2020 due to market conditions and uncertainty. A modest number of 

NGCC plants are also expected to retire in the near term in this modeled scenario. 

Figure 3.32. Baseload Capacity Additions and Retirements from EIA AEO 2017 (No Clean Power 

Plan Scenario)193

Three factors impacting the economic conditions of baseload generators that are modeled in the AEO—

natural gas price, electricity sales, and VRE generation—are shown in Figure 3.33 below. In general, 

there is a mixed outlook for these factors as they affect baseload generators: 

1. Natural gas prices for the electric power sector are modeled to rise modestly, increasing 30

percent over 2017 levels by 2022 and rising more slowly thereafter. While this may provide

some upward pressure on electricity prices, natural gas prices are notoriously challenging to

predict.

2. Electricity continues to grow at a slow rate—modeled at 0.8 percent CAGR through 2030.

3. Over the same period, VRE generation is modeled to approximately double to 600 terawatthours by 2030. The majority of this growth occurs by 2024 and slows thereafter, reflecting the

expiration and stepdown of the PTC and ITC in 2020 and 2022, respectively. Based on these

trends, unless natural gas prices or electricity demand rise significantly faster than projected,

the economic conditions of baseload generators are not projected to change significantly in the

near term.
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.33. Modeled Projections for Natural Gas Price, Electricity Sales, and VRE Generation from 

EIA AEO 2017 (No Clean Power Plan Scenario)

194

VRE generation includes wind, utility-scale PV, and distributed PV. MCf is million cubic feet

While the financial strains on existing coal, nuclear, and even older natural gas plants have been real and 

significant, the role of conventional resources continues to evolve. PJM notes the changing nature of 

baseload:

“Baseload” can generally be thought of as those units which operate the great majority of 

hours of the year to meet load requirements. Given the reduction in gas prices, we have 

seen a noticeable inversion in the types of units which clear in the market in the off-peak 

hours and thus fit the traditional notion of “baseload.” Specifically, due to low energy prices 

and the overall efficiency of the units, combined cycle natural gas units are dispatched as 

baseload with coal units more often being cycled and thus dispatched in what has 

traditionally been deemed “mid-merit” units.195

EIA staff analyzed NGCC unit dispatch trends over time, from 1998 to 2016.

196 NGCC plant operation 

closely follows natural gas prices—when prices were high in the mid-2000s, the number of NGCC starts 

(when the plant goes from zero output into production) increased as the capacity factor decreased, 

confirming that these plants were used more in load-following mode rather than baseload-operation 

mode. Capacity factor has been rising steadily and starts have fallen since about 2010, indicating that 

NGCC units are being used in more hours at higher capacity factors—i.e., in baseload-type operation

(see Figure 3.34).
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Figure 3.34. NGCC Capacity Factors and Number of Starts, 1998–2016 

Decreased starts and increased capacity factors indicate that NGCC plants are increasingly used for 

baseload-type operation. 

Market conditions will continue to be dynamic, such as with the scheduled phasing out of the wind PTC 

and solar ITC. Trends in natural gas prices and efficiency gains would also need to be thoroughly 

examined and accurately forecast in order to get a clearer picture of expected retirements over the 

coming years. In the event present market, policy, and technology conditions continue, the retirement 

of coal and nuclear facilities is likely to continue, as well as new builds of natural gas and VRE capacity. 

Going forward, coal and natural gas generators will continue to monitor several EPA rules: 

 The Steam Electric Effluent Limitation Guidelines have been postponed until EPA completes

review of the rule finalized in 2015.197 EPA recently completed an extended public comment

period of the rule and comments are currently being reviewed.198 Based on the 2015 finalized

rule, EPA estimated industry-wide costs at approximately $480 million per year,199 although

industry groups such as the Utility Water Act Group dispute this estimate.oo 200

 The Cooling Water Intake Rule for existing sources is currently being phased in. Regions have

been given authority to consider requirements for power plants on a case-by-case basis. EPA

estimated an annualized post-tax final rule cost of $147.6 million for electric generators.201

However, due to the flexibility allotted to the regional permit directors, the compliance timeline

and costs are unclear.

 While MATS and CSAPR have affected plant decisions to retrofit or retire in the recent past,

most of the capital investment for MATS and CSAPR compliance has already occurred (see Table

3-4). In the future, generators will continue to have smaller operating and maintenance costs

associated with MATS. For example, based on generator survey responses, ERCOT estimates an

average operating and maintenance cost for MATS of $0.75/MWh,202 which is approximately

oo According to a petition submitted by the Utility Water Act Group, selected individual compliance cost estimates from its 

members included: $308 million (Dynegy), $200 million (NRG Energy), and $400–$500 million (American Electric Power). 
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3 percent of the average monthly day-ahead wholesale electricity price (approximately 

$23.5/MWh) for the ERCOT North Hub from 2015 to 2016.203

 The Coal Combustion Residuals Rule, prompted by a 2008 coal ash spill, is currently being 

implemented.204 EPA estimated the annualized cost of the rule to be $509–$735 million for coalfired electric utilities.205

 The Regional Haze Rule, which currently requires states to submit state plans for compliance by 

2021, is expected to mainly affect Western states (the rule aims to improve visibility in national 

parks, which are located primarily in Western states). It also includes a provision allowing power 

plants that are already complying with CSAPR (eastern half of the United States206) to substitute 

their compliance status for compliance with the Regional Haze Rule.207 208

 In 2015, EPA finalized New Source Performance Standards, entitled Carbon Pollution Standards,

which set CO2 emission limits for new generators.pp These standards are currently under legal 

challenge.

 The Clean Power Plan rule to reduce CO2 emissions from existing power plants was promulgated

by EPA in 2015 for effect in 2022 for existing plants, but those rules are under review by EPA—

which may initiate actions to rescind them—and by the courts. 

Several large coal plants built after 1970 with capacities greater than 1,000 MW have announced plans 

to retire in the next few years. These plants have already made the capital investments needed to 

comply with MATS, indicating that MATS itself is not the single forcing factor in these retirement 

decisions. Although these plants were designed to operate around the clock, low wholesale electric 

prices tied to natural gas were a significant driver that caused them to operate at lower capacity factors. 

As Rhodium Group analyst John Larsen states:

The wider market dynamics are more concerning for coal.... For a power plant to make 

money today, it must be able to ramp up and down to coincide with the variable levels of 

renewable generation coming online. That makes combined cycle natural gas plants 

profitable, even at lower prices. [But] coal plants have relatively high and fixed operating 

costs and are relatively inflexible. They make their money by running full-out.209

While there have been significantly fewer retirements of hydropower generation than coal or nuclear, 

this does not mean that hydropower operators are immune to the same market and regulatory forces 

that have affected other baseload plants. Depressed prices and costly regulatory barriers decrease the 

margins on all hydroelectric facilities and, in some cases, cause economic stress.

210 A certain amount of 

new development continues, primarily through powering existing non-powered dams and installing 

hydropower in conduits and other constructed waterways. Two hundred and forty-two new hydropower 

projects, with a total capacity of 3,250 MW, were in the U.S. development pipeline at the end of 2016, 

including 93 MW under construction. At least nine projects (225 MW) reached commercial operation in 

2016.211

 

pp Under current market conditions, these standards were not expected to affect new build decisions because economic 

conditions were already unfavorable for building new coal units. For example, EIA’s 2015 AEO, which does not include the Clean 

Air Act 111(b) carbon standards for new coal plants, builds only a very small amount (roughly 400 MW) of new coal capacity by 

2040 beyond what is already planned. https://www.eia.gov/outlooks/aeo/pdf/0383(2015).pdf. 
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4 Reliability and Resilience 

The April 14 memo expressed concerns over whether the erosion of baseload power is compromising a 

reliable and resilient grid. It also asked whether wholesale energy and capacity markets are adequately 

compensating attributes that strengthen grid resilience and, if not, the extent to which that could affect 

grid reliability and resilience in the future. Indeed, a recent National Academies study indicates that 

there is a growing emphasis within the industry on grid resilience.212 In this chapter, we address those 

issues, starting with the question of whether grid reliability has been lessened by the retirement of 

baseload and other coal, nuclear, and natural gas power plants over the past 15 years. 

The Department staff offer three general findings: 

1) A diverse portfolio of generation resources and well-planned transmission investments are

critical to meeting regional reliability objectives. A resource portfolio approach is necessary to 

ensure ERS, fuel assurance, and flexibility capabilities are available. Conventional generation 

sources, in particular hydropower, combustion turbines, and steam turbines, are currently the 

chief providers of these attributes. 

2) One of the greatest challenges to integrating VRE lies in managing its effects (variability,

uncertainty, location specificity, non-synchronous generation, and low capacity factor) on grid 

operations and planning. Lack of long-term forecasting, for example, increases risks when 

scheduling planned generation outages and managing severe weather events. 

3) There are tradeoffs between multiple desirable attributes for the electric grid. A more reliable

and resilient system may be more costly than the least-cost system. Consumer life, safety and 

health are dependent on a reliable and resilient electric grid, making the grid a national security 

asset. Infrastructure hardening213 and grid recovery and restoration strategies require advanced 

planning and investment. 

Reliability 

NERC defines BPS reliability as a function of adequacy and operating reliability. In this context, NERC 

defines adequacy as, “the ability of the electric system to supply the aggregate electric power and 

energy requirements of the electricity customers at all times, taking into account scheduled and 

reasonably expected unscheduled outages of system components.” Operating reliability is defined as, 

“the ability of the electric system to withstand sudden disturbances to system stability or unanticipated 

loss of system components.”qq 214

Reliability operates in different time scales. Long-term reliability is closer to resource adequacy: it is the 

business of ensuring that there will be enough resources available to serve customers’ load several years 

qq

 Both components of reliability are needed. Adequacy, often called “resource adequacy,” is much easier to model and thus 

forecast for the future, particularly a decade or two out. Most longer-term studies, such as by DOE and its national laboratories, 

largely look at this one aspect of reliability (with some consideration of operational reliability aspects as well). Operational 

reliability, in contrast, is very difficult (both in data needed and computational complexity) to completely model and thus 

forecast in definitive terms many years out. 
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out plus a reserve margin (typically 15 percent). Short-term reliability ensures that there will be enough 

capacity to meet demand over the next few hours. Maintaining short-term reliability has grown more 

complex in light of higher levels of VRE, evolving customer electricity usage patterns, and the wider use 

of 15-minute load metering and customer time-of-use rates. However, grid operators have kept up with 

these factors by developing new information technology and analysis capabilities, such as more 

sophisticated wind and solar forecasting tools. 

Figure 4.1. illustrates the timescale for different grid events. Events on very short timescales, such as 

frequency regulation, match second-by-second generation and demand. Medium-term activities and 

factors include day-ahead and day-of energy markets, security-constrained economic dispatch,rr

contingency analysis, asset availability, relay and other equipment operations, and operator action.

Longer-term activities and factors include system planning, capacity markets, interconnection rules, 

reliability standards, and energy market designs. Grid operators must thoroughly consider all these 

timescales and their associated events in ensuring short-term through long-term reliability.

Figure 4.1. System Operation Time Scales215

Planning to maintain system reliability depends on managing (potentially) multiple events in varying time 

scales.

NERC’s CEO Gerry Cauley spoke to the Energy Secretary’s concerns by describing the current reliability 

issues.

As a common thread in each of our Reliability Assessments, the most pressing reliability 

issues in North America are: 

 As conventional resources prematurely retire, sufficient amounts of essential 

reliability services, such as frequency and voltage support, ramping capability, etc., 

must be replaced based on the configuration and needs of the system. 

 Resource flexibility is needed to supplement and offset the variable characteristics of 

solar and wind generation. 

 Higher reliance on natural gas exposes electric generation to fuel supply and delivery 

vulnerabilities, particularly during extreme weather conditions. Maintaining fuel 

diversity and security provides best assurance for resilience. Premature retirements 

 

rr “Security-constrained economic dispatch [of power plants] is an area-wide optimization process designed to meet electricity 

demand at the lowest cost, given the operational and reliability limitations of the area’s generation fleet and transmission 

system.” https://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/final_ED_03_01_07_rev2.pdf. 
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of fuel secure baseload generating stations reduces resilience to fuel supply 

disruptions. 

 Because the system was designed with large, central-station generation as the

primary source of electricity, significant amounts of new transmission may be needed

to support renewable resources located far from load centers.216

To make risk-informed decisions about how to maintain and protect BPS reliability, NERC has often 

stressed the need to study evolving market, technology, policy, and regulatory factors, as well as to 

understand how they are affecting “fuel supply, generation and transmission infrastructure planning, 

operations and investment decisions.”

217

Resilience

NERC uses the infrastructure resilience definition that the National Infrastructure Advisory Council 

developed in 2010: “Infrastructure resilience is the ability to reduce the magnitude and/or duration of 

disruptive events. The effectiveness of a resilient infrastructure or enterprise depends upon its ability to 

anticipate, absorb, adapt to, and/or rapidly recover from a potentially disruptive event.”

218 Examples of 

events that test a system’s resilience include severe natural events (wildfires, hurricanes, floods, 

droughts, and earthquakes) and coordinated, extensive physical and cyber-attacks and geomagnetic 

disturbances. 

Resilience is typically achieved through hardening or recovery. Hardening refers to physically changing 

infrastructure to make it less susceptible to damage. Hardening improves the durability and stability of 

energy infrastructure, making it better able to withstand the impacts of hurricanes, weather events or 

attacks. Recovery, by contrast, refers to the ability of an energy facility to recover quickly from damage 

to any of its components or to any of the external systems on which it depends – typically through 

storage and redundancy. Recovery measures do not prevent damage; rather, they enable energy 

systems to continue operating despite damage, and/or they promote a rapid return to normal 

operations when damages/outages occur. Advanced planning for contingencies, interagency 

coordination, and training exercises enable an effective restoration process. 

BPS reliability is adequate219 today despite the retirement of 11 percent of the generating capacity 

available in 2002, as significant additions from natural gas, wind, and solar have come online since then. 

Overall, at the end of 2016, the system had more dispatchable capacity capable of operating at high 

utilization rates than it did in 2002.220 The composition of the BPS and its requirements, however, are 

changing, so simple extrapolation of previous reliability trends is not prudent. In this chapter, we review 

current system reliability and resilience, look at how power plant operations are changing with the 

evolving generation mix, and evaluate potential reliability and resilience issues. 

4.1 Assessing Challenges to Reliability 

NERC is the primary entity responsible for ensuring BPS reliability,ss and collaborates with FERC to 

ensure compliance. Over the last several years, NERC has consistently highlighted how the power 

ss NERC is the designated “electric reliability organization” under the Energy Policy Act of 2005, monitoring reliability for all 

lower 48 states and, under special agreement, portions of the Canadian and Mexican grids. 
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sector’s rapid transformation may require new approaches to reliability measurement and planning in 

order to ensure continued reliability.tt 221 222 223 224 225 

NERC believes BPS reliability is adequate as measured by various metrics,226 but is undertaking various 

initiatives to address potential reliability challenges posed by the changing generation mix. For example, 

NERC created an Essential Reliability Services Working Group to draw attention to the need to maintain 

these servicesuu as the resource mix evolves.227 NERC also created the Integration of Variable Generation 

Task Force and the Distributed Energy Resources Task Force to address the reliability implications of 

increasing levels of distributed generation.

228

NERC’s position on the reliability implications of the evolving resource mix is best summarized in its 

recent communication with DOE (see text box below).

NERC: How the Changing Resource Mix Affects Reliability229

The North American BPS is designed to be a highly reliable, robust, and resilient system. The system is 

interconnected, and the integrated networks work together to maintain reliability through both wide-area 

interregional planning and coordinated system operations. The adequacy of the system is maintained by 

having the right combination and amount of resources and transmission to deal with unexpected facility 

outages or extreme weather events that increase system demand. Operating reliability is maintained in 

real time through highly coordinated operator actions across many operating companies. The system is 

also planned as many as 15 years in advance by performing highly detailed, complex, and data-intensive 

power system simulations. 

The resource mix of the BPS is changing in fundamental ways. Variable energy resources, especially 

wind and solar, are rapidly expanding and capturing the majority share of new capacity additions. 

Conventional generation (such as coal and nuclear) are retiring and have become economically

marginalized. The balancing resource tends to be natural gas, as environmental rules and commodity 

economics tend to make oil-fired generation uneconomic. Developing hydroelectric resources, a major 

energy source in some parts of the country (such as the West), is extremely challenging. The confluence 

of the changing resource mix can fundamentally impact reliability in two major ways: 

1. A balancing authority responsible for managing the balance of demand and resources through unit 

commitment. Forecasting may become capacity deficient and unable to serve firm load. Resources

may not be available when needed, particularly those that have not secured onsite fuel. In that 

instance, manual load shedding may be required to maintain reliability. 

2. Large, unanticipated voltage or frequency deviations during a disturbance, which can lead to 

uncontrolled, cascading instability. With no mass, moving parts, or inertia, increasing amounts of 

inverter-based resources (such as solar photovoltaic) present new risks to reliability, such as 

managing faster fault-clearing times, reduced oscillation dampening, and unexpected inverter 

action. 

The rapid changes occurring in the generation resource mix and technologies are altering the operational 

characteristics of the grid and will challenge system planners and operators to maintain reliability. More 

specifically: 

 Impact of Premature Retirements: Conventional units, such as coal plants, provide frequency 

support services as a function of their large spinning generators and governor-control settings,

along with reactive support for voltage control. Power system operators use these services to plan 

 

tt NERC’s concerns about the reliability implications of the fast-evolving grid transformation underway were so strong that it 

chose to rename a set of key components of operational reliability from a term understood only by engineers and others 

directly involved in reliability, the term “ancillary services,” to the plainer English and self-defining, “essential reliability 

services.”

uu ERS include frequency response, voltage support, and ramping.
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and operate reliably under a variety of system conditions, generally without the concern of having 

too few of these services available. Coal-fired and nuclear generation have the added benefits of 

high availability rates, low forced outages, and secured onsite fuel. Many months of onsite fuel 

allow these units to operate in a manner independent of supply chain disruptions. 

 Replacement Resource Capability and Characteristics: As the generation resource mix evolves, the

reliability of the electric grid depends on the operating characteristics of the replacement resources.

Natural gas-fired units, variable generation, storage, and other resources can provide similar

reliability services. However, as a practical matter, costs, market rules, or regulatory requirements

(or lack thereof) can affect whether these resources are equipped and available to provide reliability

services. To ensure reliability, new generator and load resources must maintain the balance

between load and generation, especially during ramping periods. In addition, in some jurisdictions,

substantial amounts of generation are now being added “behind the meter” (e.g., roof top solar),

and these resources are invisible to system operators.

Planning Reserve Margins 

In terms of the resource adequacy part of reliability, NERC reports that all regions project more than 

sufficient planning reserve margins. NERC and its regional reliability coordinators conduct ongoing 

analyses to assess resource adequacy as system conditions change over time. Figure 4.2. shows that 

planning reserve marginsvv exceed their respective regional targets despite the loss of traditional 

baseload capacity since 2002.230 The orange bars in the figure indicate regional or NERC-determined 

target reserve margins for resource adequacy, which in most cases are administratively set at 15 percent 

above the predicted peak load. The calculation of resources in most regions includes current VIEUowned generation and merchant plant capacity (modified by an expected forced outage rateww and 

reduced by expected retirements), planned capacity additions (with interconnection agreements and 

customer contracts), renewable generation (derated to expected capacity at peak load hour),xx

contracted imports, energy efficiency, DR, and distributed generation (derated to expected capacity at 

peak hour). 

vv Forecasts of reserve margins may decline in the out-years of a projection because new resources such as power plants, 

demand response, and energy efficiency are not firm at the time the forecast is made. Because of the uncertainty associated 

with more distant years, NERC planning reserve margin determinations do not look out past 10 years. 

ww ISO-New England reports that the expected forced outage rate for generators in their regions have increased because power 

plants in the region are operating under more stressed conditions. Older power plants in each region are less reliable and go 

out of service more often as they age. https://energy.gov/sites/prod/files/2014/10/f18/08a-REthier.pdf 

xx Each ISO and RTO calculates the on-peak contribution of renewable resources as a function of historic resource performance. 

Land-based wind plants are assumed to deliver four to 14 percent of nameplate capacity during peak summer afternoon 

periods, and solar resources are assumed to deliver between 10 percent and 80 percent of nameplate capacity. Note, however, 

that as the level of PV penetration increases, the cumulative amount of PV generation on summer afternoons is moving net 

load peak hour later. 
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Figure 4.2. Five-Year Average Reserve Margins across Different Regions (2018–2022)231

All regions have reserve margins above resource adequacy targets.

The types of resources available within a region affect the reserve margin calculation. Each type of 

resource has a different availability rate (based on past performance) that reflects the likelihood that it 

can be relied upon to be available at system peak. For instance, 1,000 MW of coal units with an on-peak

availability rate of 90 percent would have a greater impact on the reserve margin than 1,000 MW of 

wind with an on-peak availability rate of 10 percent; in other words, the actual nameplate capacity 

totals underlying these reserve margin calculations are significantly higher than the reserve margins 

suggest. NERC and regional planning authorities are working to understand how common dependencies 

or failure modes, such as gas pipeline outages or a weather front affecting wind and solar performance 

across a wide area, could affect reserve margins. NERC and others are also studying how the on-peak 

hourly capacity factor (similar in concept to capacity valueyy) of VRE changes as a function of VRE 

penetration, as shown for solar in Figure 4.3. 

 

yy NERC defines capacity value as “the contribution of a power plant to the generation adequacy of the power system. It gives 

the amount of additional load that can be served in the system at the same reliability level due to the addition of the unit.” 

http://www.nerc.com/docs/pc/ivgtf/omalley-ieee-confidential.pdf
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Figure 4.3. Historical Solar On-Peak Capacity Factors in ERCOT232

As increased solar penetration in ERCOT shifts the net peak load further into the evening, its net on-peak 

capacity factor diminishes. 

As the Department has previously noted, however, having an adequate planning reserve margin is 

necessary but not sufficient to ensure resource adequacy (see text box below): 

“Rules” to Enable Reliable Operation233

In December 2016, DOE articulated four consolidated “rules” that must be maintained to enable reliable 

operation. These include the following:

1. Power generation and transmission capacity must be sufficient to meet peak demand for

electricity.

The power grid must have sufficient capacity available to meet the demand for electricity. Because there 

are uncertainties in forecasting demand and the potential for generation and transmission outages, the total 

amount of capacity must exceed the expected level of demand by a given fraction, termed the reserve 

margin, often about 15 percent.

2. Power systems must have adequate flexibility to address variability and uncertainty in

demand (load) and generation resources.

The level of demand changes throughout the day and from season to season. This, and the addition of 

variable generation such as wind and solar, places a premium on having flexible generation capacity that 

can change its level of output to account for changes in demand and the amount of generation from variable 

resources (such as when the wind stops blowing or the sun goes down).

3. Power systems must be able to maintain steady frequency.
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The power system uses what is called alternating current (AC), where the electricity reverses direction 60

times per second (60 hertz (Hz)). If this frequency of oscillation were to deviate significantly from 60 Hz, it 

could damage machines and electronics. Any mismatch between the supply and demand of electricity can 

cause this sort of deviation, and several mechanisms operating at different timescales are used to maintain 

a steady frequency.

4. Power systems must be able to maintain voltage within an acceptable range.

In addition to maintaining a steady frequency, the electric grid must also deliver electricity at a given voltage. 

This voltage varies throughout the power grid, with transformers used to change voltages. Maintaining the 

correct voltage requires the management of “reactive power,” which is a property of AC electricity that 

allows power to flow. If the levels of reactive power are too high or too low, the voltage level can change, 

potentially even collapsing catastrophically.

NERC notes that traditional calculations of resource adequacy based on capacity (such as the planning 

reserve margin) will need to change:

Until recently, new generators have generally added significant energy capability along with 

the capacity they provide. With the advent of newer energy limited technologies replacing 

older ones (e.g., with emerging larger penetrations of variable generation), an assumption of 

energy adequacy cannot be made simply on the basis of capacity adequacy. Future-looking 

detailed probabilistic assessments of resource adequacy (energy, capacity and operability), 

transmission adequacy and congestion are increasingly becoming an essential requirement, 

consistent with the growing penetration of variable generation, and in the changing nonrenewable supply mix environment.234

4.1.1 Essential Reliability Services

Reliable operation of the BPS requires a suite of Essential Reliability Services (ERS). One key ERS is the 

control of system frequency, a parameter which NERC explains as follows:

Each Interconnection is actually a large machine, as every generator within the island is 

pulling in tandem with the others to supply electricity to all customers. This occurs as the 

rotation of electric generating units, nearly all in (steady-state) synchronism. The “speed” (of 

rotation) of the Interconnection is frequency, measured in cycles per second or Hertz (Hz). If 

the total Interconnection generation exceeds customer demand, frequency increases beyond 

the target value, typically 60 Hz, until energy balance is achieved. Conversely, if there is a 

temporary generation deficiency, frequency declines until balance is again restored at a point 

below the scheduled frequency.235

NERC further expands on the two main types of frequency control, Primary and Secondary:

 Primary frequency control (immediate) comes from automatic generator governor response, 

load response, and other devices based on local (device-level) frequency-sensing control 

systems. In general, frequency response refers to the initial actions provided by the 

autonomous devices within an interconnection to arrest and stabilize frequency deviations, 

typically from the unexpected sudden loss of a generator or load. Primary frequency control 

is quick and automatic; it is not driven by any centralized control system, and it begins 

seconds after a system frequency event. Response to a frequency event can be provided by 

various sources, including generation resources, loads, and storage devices.

 Secondary frequency control (seconds to minutes) and tertiary frequency control (ten

minutes and longer) -- Secondary and tertiary control are the centralized, coordinated control 

of generation, demand response, and storage resources, and these controls are performed 
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by the system operator’s energy management system over minutes to hours to balance 

generation and load.236

In addition to frequency control, NERC provides definitions for two other ERS, ramping and voltage 

support:

Ramping – Ramping is related to frequency, but more in an “operations as usual” sense 

rather than after an event. Changes in the amount of non-dispatchable resources, system 

constraints, load behaviors, and the generation mix can impact the ramp rates needed to 

keep the system in balance. 

Voltage – Voltage must be controlled to protect the system and move power where it is 

needed. This control tends to be more local in nature, such as at individual transmission 

substations, in sub-areas of lower-voltage transmission nodes and the distribution system. 

Ensuring sufficient voltage control and “stiffness” of the system is important both for normal 

operations and for events impacting normal operations (i.e., disturbances).237

If grid voltage levels fall too low, customers connected to distribution networks may see their devices 

“brown out” and stop working. An area that has inadequate voltage support is vulnerable to voltage 

collapse, so the system must be operated such that a single contingency would not result in voltage 

collapse or cascading outages. 

Generators provide voltage support by producing both real and reactive power. As FERC explains in its 

2016 Reliability Primer: 

Power transferred along transmission lines consists of both “real” power and “reactive” 

power. The real power is the energy that is capable of performing work in electrical devices 

including industrial equipment, refrigerators, or toasters. Reactive power is needed to 

maintain the voltage as well as electric and magnetic fields in AC equipment, which includes 

air conditioners, motors, transmission lines, and other devices. Together, real power and 

reactive power comprise apparent power, which is measured in units of Volt-Amperes or kilo 

Volt-Amperes - kVA. 

Reactive power cannot be transmitted as far as real power and instead must be replenished 

locally. Moreover, a deficit in reactive power causes voltage to drop. This is seen when the 

lights dim as an electric motor starts. While reactive power consumed by facilities or devices 

tends to cause the voltage to drop, it can also be produced or injected into the system to 

increase voltage in what is often referred to as “voltage support.” This is accomplished in a 

variety of ways, including by adjusting the reactive power output of generators or by 

activating capacitor banks or other power electronic equipment. If reactive power is not 

supplied promptly and in sufficient quantity, voltages decline, and in extreme cases a 

“voltage collapse” may result.238

 

FERC Order No. 827, issued in June 2016, revised FERC’s pro forma Large Generator Interconnection 

Agreement and pro forma Small Generator Interconnection Agreement to eliminate the previous 

exemption for wind generators from reactive power requirements, thereby requiring all newly 

interconnecting, non-synchronous generators—including new wind generators—to provide reactive 

power as a condition of interconnection to the transmission system. FERC wrote: 

We therefore conclude that improvements in technology, and the corresponding declining 

costs for newly interconnecting wind generators to provide reactive power, make it unjust, 

unreasonable and unduly discriminatory and preferential to exempt such non-synchronous 

generators from the reactive power requirement when other types of generators are not 

exempt. Further, requiring all newly interconnecting non-synchronous generators to design 

their Generating Facilities to maintain the required power factor range ensures they are 

subject to comparable requirements as other generators.239
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FERC’s primary frequency response Notice of Proposed Rulemaking proposes to require new large and 

small generators to install, maintain and operate equipment capable of providing primary frequency 

response as a condition of interconnection.240

NERC explains the various reserve products from which grid operators obtain these ERS:

 Frequency-Responsive Reserve: On-line generation with headroom that has been tested 

and verified to be capable of providing droop [...] In most cases, only portions of a, b and c in 

[Figure 4.4] qualify as Frequency Responsive Reserve. 

 Nonspinning Reserve: Operating Reserve capable of serving demand or Interruptible 

Demand that can be removed from the system, within 10 minutes. (This is c in [Figure 4.4]) 

 Operating Reserve: That capability above firm system demand required to provide for 

regulation, load forecasting error, equipment forced and scheduled outages, and local area 

protection. (This is a+b+c+d+e in [Figure 4.4]).

 Regulating Reserve: An amount of spinning reserve responsive to Automatic Generation 

Control, which is sufficient to provide normal regulating margin. (This is “a” in [Figure 4.4]) 

 Replacement Reserve: (This is d+e in [Figure 4.4]). NOTE: Each NERC Region sets times 

for reserve restoration, typically in the 30–90 minute range. The default contingency reserve 

restoration period is 90 minutes after the disturbance recovery period. 

 Spinning Reserve: Unloaded, synchronized, resource, deployable in 10 minutes. (This is b 

in [Figure 4.4]). 241

Figure 4.4. NERC Definitions of Reserves Used to Provide ERS242

Figure 4.5 shows how system frequency falls after a major generation loss. The decline in frequency is 

determined by the size of the generation loss event and the availability of frequency control reserves to 

respond. The frequency rebound that follows is due to automated primary frequency control measures 
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(governor response from generators and frequency-responsive DR from customer loads controlled by 

relays). Secondary frequency control may derive from many sources, including from local plant controls, 

from a centralized control system, or from instructions issued by balancing authorities. Tertiary 

frequency control refers to operator-initiated, off-line resources. If these frequency management 

measures don’t work, system frequency can keep dropping, resulting in under-frequency load shedding 

procedures. 

Figure 4.5. System Frequency after a Grid Event (Top) and How Frequency Control Mechanisms 

Work to Restore Frequency (Bottom)243

System operators have a number of levels of frequency control to manage a significant grid event. 

Not all generators can provide primary frequency control, as explained by Lawrence Berkeley National 

Laboratory (LBNL): 

Some generators, including all current nuclear generators, most wind turbines in North 

America, as well as many new natural gas turbines do not provide governor response. Other 

generators, which may be capable of providing governor response, are sometimes operated 

in ways that prevent them from providing that response. For example, a generator operated 
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at its maximum capability cannot provide upward primary frequency control because it has 

no head room. Finally, some generators have additional controls [...] that override the 

sustained delivery of governor response.244

NERC recognized several years ago that the changes affecting the grid—particularly retirement of 

traditional baseload capacity, increased generation from VRE, and greater use of DR and distributed 

generation—could create BPS reliability problems without careful study and management. In 2014, a

task force under NERC’s direction identified ERS as the elemental reliability building blocks from supply

and demand resources that are necessary to maintain grid reliability. NERC stated that:

To meet the needs of the future Bulk Power System, maintaining sufficient ERS will include a 

mix of market approaches, technology enhancements, and reliability rules or other regulatory 

rule changes. While the solution sets will likely be different in various regions, it may be 

necessary for regulators to make appropriate adjustments to market rules and reliability 

standards that will ensure reliable operation of the BPS.245

Although NERC has requirements for balancing areas,zz it does not require that individual generators 

provide primary frequency response, which involves the automatic, autonomous, and rapid action of 

turbine governors or equivalent controls. Further, there is no mandatory compensation for primary 

frequency response, though FERC Order No. 755 provides for compensation for secondary frequency 

response.246 Because provision of primary frequency response may require a generator to operate at 

less than its full output (so it can increase power production if needed to manage frequency), standing 

prepared to provide frequency response services means that a generator may forgo some potential 

revenues. 

The reliability attributes discussed above are recognized as valuable, but regional procurement and 

compensation for these services varies across the centrally-organized markets. In vertically integrated 

regions that use bilaterally organized markets, it is generally the incumbent utility’s obligation to provide 

ERS; some interconnection agreements specify other generators’ reliability service obligations if any.

4.1.2 Inertia and Inertial Response

PJM explains how conventional generators provide inertia:

Due to electro-mechanical coupling, a generator's rotating mass provides kinetic energy to 

the grid (or absorbs it from the grid) in case of a frequency deviation to arrest frequency 

change and stabilize the electric system. The contribution of inertia is an inherent and crucial 

feature of rotating synchronous generators.

247

Every operating conventional generator has mass that spins, including rotors, turbines and other masses 

connected to the shaft of the generator or motor. The rotating mass in each generator collectively 

provides inertia to help keep grid frequency at a relatively stable level, for example slowing the rate of 

frequency drop after a major grid event and giving other automatic controls time to act to restore 

frequency. Inertia also works to slow the spike in frequency that occurs after the loss of a large amount 

of load (for instance, if part of a city “blacks out” suddenly from a transmission or distribution failure). 

 

zz NERC Reliability Standard BAL-003-1.1 establishes requirements for balancing authorities, but does not include requirements 

for individual generator owners or operators. However, some ISOs/RTOs, including CAISO, ISO-NE, and PJM, have implemented 

operating requirements for individual generating resources within their regions. Regional Reliability Standard BAL-001-TRE-01 

(Primary Frequency Response in the ERCOT Region) establishes requirements for the balancing authority, generator owners, 

and operators in ERCOT.
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Recently, manufacturers have designed electronic controls for newer model wind turbines that can 

provide automatic generation control, primary frequency response and synthetic inertia. General 

Electric (GE) notes: 

A key difference between wind inertia and fast frequency response from other resources 

(batteries, PV, flywheels) is that wind turbines do not need to be pre-curtailed in order to 

provide synthetic inertial response. Wind inertia extracts some of the kinetic energy from the 

spinning rotor and uses it to provide increased power output within seconds.248

There has not yet been much analysis of how much primary frequency response will be needed as the 

composition of the grid changes, nor how best to complement primary frequency response from 

traditional sources, such as governors, with electronics-based synthetic inertia or non-governor-based 

forms of primary frequency response, such as storage or DR. These are substantive engineering 

questions that merit further study, particularly in a future with increasing VRE levels and decreasing 

rotating mass-based inertia.249

4.1.3 Energy Storage 

Energy storage will be critical in the future if higher levels of VRE are deployed on the grid and require 

additional balancing of energy supply and demand in real time. A few storage mechanisms such as 

pumped hydroelectric storage and thermal energy storage have been used for years to shift energy 

demand from peak to off-peak periods. A grid with higher levels of VRE and more dynamic customer 

loads will need more of the services that energy storage can provide by acting on both the supply and 

demand side, including energy, capacity, energy management, backup power, load leveling, and ERS, 

over periods from seconds to hours or days. However, the need for storage may not be as great for a 

grid more reliant on traditional baseload generation.250

 

DOE has been investing in energy storage technology development for two decades, and major private 

investment is now active in commercializing and the beginnings of early deployment of grid-level 

storage, including within microgrids.aaa The DOE Grid Energy Storage program notes that as energy 

storage technologies mature and become commercially viable, they will need to achieve the following: 

 Cost competitive energy storage technology—Achievement of this goal requires attention

to factors such as life-cycle cost and performance (round-trip efficiency, energy density,

cycle life, capacity fade, etc.) for energy storage technology as deployed. It is expected

that early deployments will be in high value applications, but long term success requires

further cost reductions and the ability to monetize revenues for all grid services that

storage provides.

 Validated reliability and safety— Validation of the safety, reliability, and performance of

energy storage is essential for user confidence.

 Equitable regulatory environment— Value propositions for supply-side grid storage

depend on reducing institutional and regulatory hurdles to levels comparable with those

of other grid resources.bbb 251

aaa Storage is an important component of most micro-grid designs reliant on VRE and is expected to play an essential role in 

helping customers and the BPS recover from extreme weather events (and should improve resilience and recovery following 

severe, high-impact events). 

bbb A recent FERC Notice of Proposed Rulemaking seeks to identify and reduce such barriers for increased participation by 

energy storage in centrally-organized wholesale markets. 
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 Industry acceptance—industry adoption requires manufacturers to have confidence that 

storage will deploy as expected, and deliver as predicted and promised.252

Table 4-1 details DOE analysis of how energy storage options can be used to provide grid-level services.

Table 4-1. How Various Energy Storage Options Can Deliver Grid-Level Applications253

State policies are emerging to encourage further use of energy storage technologies for grid support and 

energy security. California has directed its utilities to acquire 500 MW of energy storage by 2020; 

Massachusetts has ordered its utilities to procure 200 MWh of energy storage by the end of 2019; New 

York’s legislators have proposed creation of an Energy Storage Deployment Program, with a 2030 

procurement target; Maryland has adopted at 30 percent investment tax credit for storage facilities; and 

Nevada’s legislature has passed a storage incentivize. These programs are generally technology-neutral 

and will support the use of storage at the grid-level or behind the meter (on the customer’s premises).254

255

4.1.4 Transmission

The transmission system is a vast engineered network that transmits electricity from generators to local 

substations for distribution to end-use consumers. As DOE’s Annual U.S. Transmission Data Review

(2016) states, “Transmission planning activities are undertaken to enable future reliable and efficient 

utilization of transmission facilities by addressing, among other things, reliability concerns, constraints, 

and congestion.”

256 Transmission reliability is maintained by enforcing operating procedures that ensure 

efficient system utilization, including preventing users from transmitting more power over a line than its 
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rated power capacity. Transmission congestion results from the inability to dispatch the lowest-cost 

generation resources due to transmission constraints. 

Transmission investments provide an array of benefits that include providing reliable electricity service 

to customers, relieving congestion, facilitating robust wholesale market competition, enabling a diverse 

and changing energy portfolio, and mitigating damage and limiting customer outages (resilience) during 

adverse conditions. Well-planned transmission investments also reduce total costs. SPP analyzed the 

costs and benefits of transmission projects from 2012–2014 and found that the planned $3.4 billion 

investment in transmission was expected to reduce customer cost by $12 billion.ccc This yielded an 

estimated benefit of $3.50 for every dollar invested in the region.257 

A robust transmission system is needed to provide the flexibility that will enable the modern electric 

system to operate. Although much transmission has been built to enhance reliability and meet customer 

needs, continued investment and development will be needed to provide that flexibility. 

The challenge for building transmission continues to revolve around the three traditional steps involved, 

each of which can be time-consuming, involved, and complex: (1) demonstrating a need for the 

transmission project, also known as transmission planning, (2) determining who pays for the 

transmission project, also called cost allocation, and (3) state and Federal agency siting and permitting. 

FERC has taken steps to help with the first two, with reforms such as Order No. 1000, which remains a 

work in progress.258 259 260 261 262 Transmission planning entities, as well as regional state-based groups, 

are also contributing to improving these three necessary process steps. The current and past 

administrations, aided by various new Federal laws, have issued various Executive Orders and other 

initiatives to improve the processes involved in siting and permitting of transmission when Federal lands 

or waters are involved. 

All three transmission building steps can be time-intensive and complex; in particular, siting and 

permitting for large networks or long multi-state lines is challenging. 263 264 265 The second necessary step 

of cost-allocation can be time-consuming as well. For example, large overlay networks now being built in 

MISO (“Multi-Value Projects”)

266 and SPP (“Highway/Byway Plan”)267 required several years of sensitive 

negotiations among states brokered by the respective Organization of MISO States and SPP Regional 

State Committee to determine the cost allocation of each large transmission buildout.268 269

ccc Nearly $12 billion in net present value benefits for consumers over the next 40 years, or around $800 for each person 

currently served by SPP, or $2,400 per each metered customer. 
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Figure 4.6. EEI Historical and Project Transmission Investment (Nominal Dollars)270

Prudent and well planned transmission can reduce total system costs by reducing localized congestion 

that sometimes leads to high wholesale electricity prices at transmission-constrained nodes. 

Transmission investments in future years could increase as utilities and system operators seek to mitigate 

reliability impacts of plant closures and bring new generation to load centers.

4.1.5 System Requirements to Meet Higher Levels of VRE on the Grid

Levels of wind and solar penetration—including distributed and utility-scale installations—have grown in 

recent years from 0.3 percent of total annual generation nationwide in 2002 to 6.9 percent in 2016.ddd

271 Various integration studies (see Appendix B:) have explored grid operations at higher levels of VRE

penetration (ranging from 10 percent to 60 percent) and examined the technical challenges for grid 

operators.eee These challenges can generally be met at lower levels through a number of changes to grid 

operation, planning, and transmission expansion practices, and with other sources of grid flexibility. 

Solutions vary by region, depending on existing transmission constraints, generators, sources of 

flexibility, and institutions and markets – each of which comes with associated implementation costs

and other consequences to address. Costs can change over time as technologies and markets evolve, or 

 

ddd AEO 2017 reference case indicates that this could grow to 17% by 2030.

eee The studies (see Appendix B) that look into the distant future are exploratory only and represent initial investigations into 

how to implement high levels of VRE. They do not look into all the operational aspects of reliability due to the needed complex 

and computationally challenging modeling. Typical assumptions (sometimes implicit) include successful siting of (at times long 

multistate) transmission lines and new generation, sufficient new and existing economically viable conventional generation and 

other resources to support the VRE, institutional and market changes, and relevant grid modernization-type spending at both 

the transmission and distribution level. One study, for the ease of modeling, even assumes the nation’s 66 balancing 

authorities, including their governing boards and member states, would agree to one national joint dispatch). Some of these 

assumptions are non-trivial. These studies recognize that given enough time and money, power system engineers can make any 

resource and configuration reliable, as long as the laws of physics are not violated; whether the changes needed are indeed 

affordable, doable, and desirable may be a different question. Also, affordability was typically not in the scope of these studies.
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as other enabling technologies such as storage mature. Grid operators and planners continually evaluate 

and determine how to maintain reliability as the resource mix changes and evolves. 

Figure 4.7. Location of the Existing Wind Fleet272

Most of the contiguous United States’ wind power plants are installed in the center of the Nation, which 

has the best wind resources. 

Total penetration of VRE is increasing rapidly in several regions, and wind represents the majority of 

current installed VRE. Wind turbines have contributed more than one-third of the nearly 200,000 MW of 

total utility-scale generating capacity added since 2007, reflecting a combination of improved wind 

turbine technology and lower costs, increased access to transmission capacity, state-level RPS, and 

Federal tax credits and grants. Distribution of wind capacity across the contiguous United States is 

shown in Figure 4.7. 

Percentage wind generation by state is shown in Figure 4.8. In particularly windy hours, wind output in 

regions with significant wind capacity can be very high. On May 16, 2017, the CAISO hit a new daily 

renewables record when the combination of wind, solar, hydro, and other renewables served nearly 42 

percent of electricity demand; during peak renewables production (the 2:00 p.m. hour), renewables 

supplied nearly 72 percent of electricity.273 In Texas, at the end of 2016, ERCOT had more than 17,600 

MW of installed wind capacity and 566 MW of utility-scale solar capacity.274 ERCOT reached 50 percent 

wind penetration in the early morning on March 23, 2017, when load was below 29,000 MW; at 5:00 

p.m. that afternoon, when peak load hit 45,391 MW, wind contributed about 30 percent to the energy 

needed to meet that peak.275 SPP recently set a new wind-penetration record of 52.1 percent on 

February 12, 2017, the highest across North American RTOs.ggg 276 277

ggg On the other hand, there are times when wind generation can be low. For example, ERCOT reports that for 2016, wind 

generation was below 2,500 MW (approximately 15% of total operating wind capacity as of November 2016) for 17 percent of 

the year’s hours. http://www.ercot.com/news/releases/show/113533. 
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Figure 4.8 Wind Energy Share of Electric Generation by State, 2016278

One of the greatest barriers to widespread VRE adoption is the challenge of managing its variability and 

corresponding impacts on net load. Table 4-2 summarizes the characteristics of VRE, the challenges to 

integration, and how to mitigate those challenges. 

Table 4-2. Characteristics of VRE, Grid Integration Challenges, and Mitigation Options279

Wind & Solar 

Characteristics

Potential Grid Integration 

Challenges

Mitigation Options

Variability Generator output can 

vary as underlying 

resource fluctuates.

In many power systems, sufficient flexibility exists to 

integrate additional variability, but this flexibility may 

not be fully accessible without changes to power 

system operations or other institutional factors (e.g., 

increased ramping of generation and improved 

coordination across markets and balancing areas) 

(Lew et al. 2013). 

Uncertainty Generation cannot be 

predicted with perfect 

accuracy (day-ahead, day 

of). 

Integration of advanced renewable supply forecasting 

into dispatch and market operations has reduced 

uncertainties, improved scheduling of other resources 

to reduce reserves and fuel consumption, and 

enabled VRE to participate as dispatchable resources 
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(IEA 2014; Lew et al. 2011). Examples: Xcel Energy, 

U.S. RTOs/ISOs (Porter et al. 2012). 

Location

specificity 

Generation is more 

economical where 

highest-quality resources 

are available.

Competitive Renewable Energy Zones in Texas are 

an example of an approach to quickly develop 

generation and transmission in coordination (18.5 GW

and 3,600 miles were completed nine years after 

Competitive Renewable Energy Zones legislation was 

signed) to access wind resources in remote parts of 

the state. 

Nonsynchronous 

generation 

Generators provide 

voltage support and 

frequency control in a 

different manner than 

traditional resources.

Grid code requirements are evolving in response to 

technological advances and anticipation of high VRE

penetration levels. For example, ERCOT, which is a 

small interconnection and more vulnerable to 

frequency excursions, now requires wind generators 

to provide inertial response, which helps keep a 

system stable in the initial moments after a 

disturbance (Bird, Cochran, and Wang 2014). 

Low capacity 

factor 

Availability of the 

underlying energy 

resource limits the runtime of the plant.

Capacity payments or markets, potentially tied to 

performance, could ensure sufficient cost recovery. 

The potential for stranded assets is not unique to VRE 

and can occur whenever generation with lower 

marginal costs is added to the system. For example, 

low natural gas prices have reduced the market 

competitiveness of nuclear plants, contributing to 

recent retirements (Wernau and Richards 2014). 

Utility-scale wind and solar plants are more location-limited than some other generation types, so they 

may require transmission construction to be able to interconnect with the grid and secure deliverability 

to customer load centers. LBNL researchers state that power systems with large or growing amounts of 

VRE: 

[W]ill benefit if the rest of the electricity system is flexible – able to respond to shifts in 

demand and VRE availability. VRE impacts and system costs will be driven lower as power 

systems transform to manage the unique characteristics that VRE resources introduce. 

Power systems that resist change as VRE penetrations increase will experience greater 

challenges in maintaining reliability and managing costs.280

 

Figure 4.9 shows a suite of options for integrating VRE effectively, spanning physical, operational, 

markets, load, and other means.hhh

hhh However, proponents of dispatchable renewables (biomass, hydro, and geothermal) argue that other approaches should 

also be considered. http://www.sciencedirect.com/science/article/pii/S104061901500024X 
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Figure 4.9. Ways To Integrate VRE, Arrayed by Type of Intervention and Cost (2014)

281

Forecasting of VRE is a critical challenge to system operators to manage high-risk weather days. Specific 

issues include wind icing forecasts and weather fronts that result in low-level jet winds and other wind 

cut-out scenarios. Since long-term VRE forecasting is not practicable today, system operators will have 

to rethink outage scheduling if a region has high dependency on wind as a resource.282

FERC, NERC, and the RTO/ISOs have undertaken several initiatives to modify requirements for 

interconnecting VRE to improve grid reliability. These initiatives include early work to develop lowvoltage ride-through requirements for interconnecting wind and solar generation (which are included as 

a requirement for wind plant interconnection under the FERC open access transmission tariff), as well as 

California updating its solar photovoltaic (PV) distribution interconnection requirements to include 

smart inverters. Other nations have grid codes that require the provision of specific ERS for new VRE

resources as a condition of interconnection. And FERC and several RTOs and ISOs have sought to remove 

barriers to participation in organized markets by DR resources that can deliver some ERS and provide 

benefits to consumers.

The Bonneville Power Administration (BPA) offers a good example of managing the challenges of 

integrating VRE effectively using better operational and business practices. Wind generation capacity in 

BPA’s balancing authority area grew from 250 MW to 4,782 MW within a 10-year span, driven by state 

RPS requirements and Federal tax credits. Much of the wind generation is located along the Columbia 

River Gorge, connecting to the high-voltage transmission system serving the Federal Columbia River 

hydroelectric plants, so the wind fleet had little diversity and could swing output as much as 1,000 MW 

within an hour. BPA began charging for using hydropower to balance the wind generation (also called a 

balancing capacity rate and since adopted by FERC for other regions), and it set a penalty rate to 

encourage accurate wind production scheduling. Wind forecasting and scheduling practices and tools 

have since improved significantly.

283
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Because wind generation receives the PTC and has PPAs that encourage production regardless of system 

demand, it can be economical for wind to generate even when market prices are negative. As a result, 

generators that are “must-run” (either for statutory or reliability reasons) must compete with resources 

that will generate when prices are negative. Anticipating the growing challenges posed by the changing 

resource mix in the region, BPA worked with stakeholders to develop the Oversupply Management 

Protocol to displace generation in BPA’s balancing authority area and replace it with Federal 

hydroelectric generation that must run for endangered fish operations. Displaced generators are 

compensated for any costs that they incur, and BPA recovers these costs through rates to its wholesale 

customers.284

However, this over-supply situation combined with sustained low natural gas prices has continued to 

erode the price of wholesale power in the western wholesale market. Changes in the wholesale market 

may be necessary to better balance state priorities, maintain grid reliabilities, and appropriately 

compensate baseload and other flexible resources, such as hydropower, for the ERS they provide.285 

The process of BPS consolidation and market cooperation among producers across a larger electric 

market and operational region has been shown to smooth out VRE output variability. MISO found that 

[T]here are significant benefits from the geographic diversity of wind generating facilities and 

the size of the MISO operating footprint. The large number of individual turbines and plants, 

spread across a large geographic area with dimensions in the hundreds of miles, results in 

statistical smoothing of production changes driven by local meteorological effects. Large 

changes in aggregate production are driven by large-scale meteorological phenomena such 

as weather fronts, and occur over longer timescales from many tens of minutes to several 

hours.286

4.1.6 Impact of VRE on Net Load 

More than 60 percent of all utility-scale electric generating capacity that came online in 2016 was from 

wind and solar technologies.287 In March 2017, wind and solar accounted for 10 percent of total U.S. 

electricity generation, up from 7 percent for the whole of 2016.288 The increase in VRE has altered grid 

operation in some regions and the way dispatchable generation and DR are used to protect the grid and 

meet loads. 

The Western Area Power Administration (WAPA), a Federal power marketing agency, operates 8,000 

MW of hydroelectric generation and three balancing areas in 15 states across the West. WAPA sums up

the operational changes and challenges for grid managers facing VRE, variable loads, and a variety of 

generation types with differing capabilities and constraints: 

Generation operators, including VERs [Variable Energy Resources], must coordinate with 

their host Balancing Authority (BA) to ensure that their output continuously matches load. 

Generation is adjusted throughout the day to meet scheduled output and is made available 

to regulate moment variations intra-hour. For VERs when the wind drops off or clouds pass 

over a solar array, less energy may be produced than scheduled (over-scheduled/underproduced), and additional resources must be brought on-line to make up the difference. 

There is a cost associated to these added generation resources. Similarly, if VERs are 

producing more than what was scheduled, or if electrical demand is less than anticipated, 

other resources must be backed down to ensure resources and load are balanced. Not all 

generation is capable of responding. Traditional generation, like coal, is not capable of 

reacting quickly to changing needs and takes hours or days to reach full operating potential. 

Gas turbines can react fairly quickly, but only if the plants are not already producing at full 

rated generating capacity. Hydro generation, while being an ideal resource to help with VER 
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integration, is generally scheduled to meet reservoir requirements or provide for downstream 

water demands, including fish, wildlife, and other environmental mitigation requirements.289

To illustrate how VRE can increase the need for flexibility, Figure 4.10 demonstrates how VRE

impacts system operations. The figure introduces the concept of “net load”—electricity demand 

minus VRE generation—which represents the demand that must be supplied by the 

conventional generation fleet if all VRE is to be utilized. The dark orange line in the graph 

represents total demand and shows the daily variability of demand on an hourly basis. The light 

blue area shows wind energy, and the yellow area shows solar energy. The dark blue line

represents the demand (less VRE) that must be supplied by the remaining generators, assuming 

no curtailment of wind energy. The graph shows that often the output level of the remaining 

generators must change more quickly and be turned up or down inversely with VRE production.

Figure 4.10. CAISO Load, Net Load, and Wind and Solar Output on Example Weekdays during 

2014290

CAISO data show the effect of VRE on net load (total customer load minus wind and solar output) during 

representative days in the spring, summer, and fall. As the amount of VRE generation increases, daily net 

load decreases, and the impacts on net load become more acute in shoulder months.

In regions with high penetration of VRE, sharper fluctuations in net load require increased flexibility 

(ramping up and down) from conventional sources. While the resulting ‘duck curve’ of daily net load has 

so far been limited to regions such as California and the Southwest where solar generation is highest, 

other regions such as the Carolinas are beginning to see similar net load patterns.

291
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What the Duck Curve Tells Us About Managing a Green Grid292

Figure 4.11. The CAISO Duck Curve

The electric grid and the requirements to manage it are changing... The ISO created future 

scenarios of net load curves to illustrate these changing conditions. Net load is the difference 

between forecasted load and expected electricity production from variable generation resources. In 

certain times of the year, these curves produce a ‘belly’ appearance in the mid-afternoon that quickly 

ramps up to produce an “arch” similar to the neck of a duck — hence the industry moniker of ‘The 

Duck Chart.’

...[S]everal conditions emerge that will require specific operational capabilities:

 Short-steep ramps – when the ISO must bring on or shut down generation resources to meet an

increasing or decreasing electricity demand quickly, over a short period of time;

 Oversupply risk – when more electricity is supplied than is needed to satisfy real-time electricity

requirements; and

 Decreased frequency response – when less resources are operating and available to

automatically adjust electricity production to maintain grid reliability.”

[...] To ensure reliability under changing grid conditions, the ISO needs resources with ramping 

flexibility and the ability to start and stop multiple times per day [...] Addressing concerns about 

frequency response capabilities in times of low load and high renewable generation may require 

operating renewable generators such that they can increase power with automated frequency 

response capability. 

At some level of penetration of distributed PV, the collective amount of PV will shift the time of peak load 

net of solar generation away from its previous point to later in the evening when insolation (and therefore 

PV production) is lower, as shown by NERC in Figure 4.12. 
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Figure 4.12. Demand and Net Demand Shapes at Different Distributed Energy Resource

Penetration Levels293

To date, RTOs and ISOs are working hard to integrate growing levels of VRE through extensive study, 

deliberate planning, and careful operations and adjustments. 

The Role of Technical Standards and Grid Codes for Effective VRE Integration

Several types of standards apply to VRE and other generation. Interoperability standards define basic 

technical and engineering performance requirements, such as the Institute of Electrical and Electronics 

Engineers Standard 1547, which defines uniform requirements for the performance, operation, testing, 

safety, and maintenance of interconnection between distributed generation resources and the grid. 

Regulatory requirements such as FERC’s pro forma open access transmission tariff (including 

interconnection requirements) dictate further reliability and performance terms for generators. As the 

level of installed wind and solar generation has grown, early technical requirements and standards for 

wind and solar have required updates to ensure performance under disturbance conditions. 

The examples described below illustrate the need to evolve standards as the penetration of nonsynchronous generation increases.

 In August 2016, the Blue Cut wildfire crossed a major transmission corridor in Southern 

California, resulting in 15 line faults. One of these faults caused the near-instantaneous loss of 
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1,200 MW of utility-scale PV in Southern California. Approximately 700 MW of this loss occurred 

when PV inverters tripped due to a “perceived, though incorrect, low system frequency 

condition.”294 Another 450 MW of this loss occurred when system voltage fell below the lowvoltage ride-through setting of the inverters—resulting in “momentary cessation.”295 The 

subsequent NERC disturbance report determined that 11 similar inverter events occurred 

between August 16, 2017 and February 6, 2017, and NERC made several recommendations with 

respect to inverter settings and standards that would prevent or mitigate these events.296 

 Australia’s Renewable Energy Target has achieved significant VRE use; 35 percent of South

Australia’s generating capacity is wind-powered. On September 28, 2016, severe weather

resulted in multiple faults on the South Australian transmission system. A number of faults in

quick succession caused 456 MW of wind generation to trip off-line within approximately seven

seconds as a result of a protection feature that disconnects or reduces wind turbine output

when the number of low-voltage ride-through events in a specific time period exceeds a

predefined limit.297 This loss of generation increased imports from the AC interconnector until

protective relays activated, islanding South Australia. Unable to rapidly shed load to match the

reduced supply, the islanded region experienced a blackout. The Australian Energy Market

Operator’s report on the incident noted the role of changes in the fuel mix: a low amount of

synchronous generation dispatched—and hence low inertia—at the time of the event resulted

in a faster frequency change than had previously been experienced during separation events.298

The report produced a list of 19 recommendations, including changes to operating procedures,

regulations, and performance standards.

 The German Energiewende initiative encouraged high levels of wind and distribution-level solar

installations, leading to over-generation and the need for VRE’ curtailment in some hours. The

grid technical code in place at the time required PV inverters to immediately disconnect from

the grid if system frequency increased from nominal 50 Hz to 50.2 Hz. However, Germany

discovered that the combination of this technical code and the growing amount of distributionlevel PV capacity heightened the risk of some excess PV generation causing all PV capacity to

disconnect simultaneously and create severe under-frequency conditions, potentially causing

rolling blackouts and grid collapse.299 In response, Germany modified its standards to require

inverter retrofits with different low-frequency performance requirements.300

4.1.7 Mapping Reliability Attributes to Generation Resources 

To assess its changing resource mix, PJM developed a matrix of reliability attributes needed to maintain 

reliable grid operation under its operating procedures (see Figure 4.13). Ultimately, a diverse generation 

portfolio is necessary to provide the reliability attributes discussed in this section. 
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Figure 4.13. Mapping Reliability Attributes Against Resourcesiii 301

Conventional generation sources—particularly hydroelectricity, combustion turbines (natural gas and 

oil), and steam turbines (oil, coal, and natural gas)—performed very well against most of PJM’s reliability 

requirements. Nuclear units are not optimized for significant flexibility or ramping capability, but do 

exhibit strong fuel assurancejjj attributes. Batteries and storage meet all flexibility requirements, and DR 

offers high flexibility and ramping management capability. Wind and solar are highly time dependent 

and do not offer fuel assurance on their own, but can offer good flexibility if they have the proper 

controls and contractual arrangements.

The Electric Power Research Institute (EPRI) summarizes how regional grid operators use centrallyorganized markets to procure specific reliability attributes from generators:

 

iii Combined-cycle plants are included in the Natural Gas – Steam group.

jjj Fuel assurance is the resource portfolio’s ability to access sufficient fuel to meet system needs and maintain reliability; 

aspects of fuel assurance include onsite fuel storage, as well as a generator’s access to sufficient fuel supplies through markets 

or bilateral contracts.
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Ancillary Services in Centrally-Organized Markets302

... [E]ach ISO also operates auction markets for spinning, non-spinning reserves, and regulation with

uniform clearing prices, with additional performance payments for regulation. (ERCOT, however, does not 

offer performance payments). Table 2 [Figure 4.14 on the following page] presents some of the terminology 

and characteristics. The hourly requirements for these services are set based on reliability standards and 

operational requirements that vary by ISO. The market designs generally co-optimize energy and reserves. 

Although ancillary service market designs can be complicated, the level of procurement typically only 

comprises less than 2% of total market volume. Ancillary service pricing is also used to signal short-term 

supply shortages. Because procurement of these ancillary services is allowed to be deficient before load is 

curtailed, the failure to procure sufficient reserves is often a first indicator of supply shortage. Hence, the 

ISOs include administrative scarcity prices in the market designs. Such pricing allows ancillary service 

prices—along with energy prices, when opportunity costs are included—to increase during shortages to 

levels more consistent with the value of lost load than the energy market offer caps. These scarcity prices 

are established differently in each ISO. 

There are a number of recent initiatives to modify the ancillary service markets. CAISO and MISO have 

recently implemented types of ramping reserves, intended to increase the ramping range from committed 

resources available during real-time energy dispatch. Some ISOs, notably ERCOT, have also begun to 

develop designs for frequency-responsive and inertial response reserve markets. 

Two ancillary services—voltage support/reactive power and black start services—are not yet considered to 

have the appropriate characteristics for competitive markets and are thus compensated through cost-based 

rates. 

Figure 4.14 Selected Ancillary Service Market Design Characteristics

Continued on next page
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Figure 4.15. Ancillary Service Products Exchanged in the Centrally Organized Markets, Listed by 

RTO/ISO and Category of Ancillary Service 

Note: (“DAM” = day-ahead market; RTM = real-time market)

Several flexibility options are available to grid operators, such as DR, fast-ramping natural gas 

generation, and energy storage. As stated in QER 1.2: 

A recent study of the value of fast-ramping gas for supporting variable renewables noted 

that, ‘...to date FRF [fast ramping fossil] technologies have enabled RE [renewable energy] 

diffusion by providing reliable and dispatchable back-up capacity to hedge against variability 

of supply... renewables and fast-reacting fossil technologies appear as highly complementary 

and... should be jointly installed to meet the goals of cutting emissions and ensuring a stable 

supply.’

303

 

In addition to existing sources of flexibility and reliability services, there is a growing understanding of 

the abilities of VRE to economically contribute to grid flexibility and reliability through operational 

changes and advanced power electronics. Recent technology advancements now enable wind plants to 

provide nearly the full spectrum of ERS (synthetic inertial control, primary frequency control, and 

automatic generation control). Similarly, for PV, CAISO, First Solar, and NREL recently demonstrated a 

First Solar 300 MW PV plant that provides active and reactive power controls, plant participation in 

automatic generation control, primary frequency control, ramp rate control, and voltage regulation.304 

A recent NERC assessment on reliability in the BPS noted that DR can enhance system flexibility and 

reliability by providing, “regulation, governor response, spinning reserve, non‐spinning reserve, and 

supplemental operating reserve[. F]or example, ERCOT obtains half of its spinning reserves from DR and 

is considering a DR‐based Fast Frequency Response Service that is positioned between inertia and 

governor response.”305 Consumer end uses—including building energy management systems, as well as 

water and space heating and cooling—can also serve as DR resources using load control and 

communicating technologies to ramp their consumption up or down in order to support VRE 

integration.306

Demand-side flexibility via “smart charging” plug-in electric vehicles is another potential source of grid 

flexibility. This involves a utility or some other centralized entity remotely controlling the charging 

patterns of participating vehicles and/or charging stations. An aggregated fleet of vehicles or chargers 

can act as a DR resource, shifting load in response to price signals or operational needs; for example, 

vehicle charging could be shifted to the middle of the day to absorb high levels of solar generation and 
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shifted away from evening hours when solar generation disappears and system net load peaks. Research 

in this area is currently underway at the national laboratories.307

4.2 Diversity, Fuel Assurance, and Onsite Storage 

The April 14 memo raises the questions of whether the diversity of the generation resources in the 

electric system has diminished and whether this is a problem for grid reliability and resilience. In fact, 

when looked at nationally, the electric system is more diverse today than it was 20 years ago, although 

increased national diversity does not necessarily mean diversity has increased in all regions. A holistic 

view of reliability and risk management, however, must include both diversity and fuel assurance. 

4.2.1 Fuel Diversity 

The U.S. generation mix has continually evolved as changes in technology, economics, government 

policy, and geopolitical forces affected the relative availability, economics, and feasibility of competing 

energy sources. PJM documents this evolution in Figure 4.16, which also displays a diversity index 

showing increasing diversity levels from about 2000 through 2014. PJM observes that, “government 

policy has played a major role in the development of generation resources, including policies that 

focused on energy security, jobs, environmental protection and conservation.”308 The chart shows how 

the mix of U.S. electricity use has moved in cycles for decades—how the generation share of 

hydroelectric facilities (most built with Federal funds during the 1930s and 1940s) declined as coal and 

natural gas grew (helped with funding from low-cost Federal land and mineral leases); how nuclear 

generation grew (aided by Federal policy and funding assistance) in the 1960s; how nuclear energy 

displaced hydroelectricity and natural gas-fired electricity in the 1970s; and how coal, nuclear, and 

natural gas-fired electricity have displaced oil-fired generation since the 1980s. 

Figure 4.16. Generation Mix and Various Economic and Policy Drivers Since 1949, Including 

Diversity Index309
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Closely tracking the PJM trends, the national picture of the resource mix shows coal and oil being 

displaced by gas and VRE. In addition to this, Figure 4.17 shows how the national U.S. capacity and 

generation mix have become more diverse over time. Changes in capacity (top) have moved the 

resource mix toward a greater proportion of natural gas, wind, and solar, while coal and oil capacity 

have decreased. Energy generation trends for these resources (bottom) have tracked changes in 

capacity, with natural gas generation almost doubling in proportion. While nuclear capacity has 

decreased relative to other resources, the proportion of nuclear generation remains unchanged as 

capacity factors for nuclear units have increased

Figure 4.17. Changes in U.S. Capacity (Top) and Generation (Bottom) Mix over Time (Left to Right: 

2002, 2009, 2016)310

The grid was, on average, more diverse in 2016 than in 2002 in terms of both capacity and generation.

Diversity can be a useful tool for managing both reliability and financial risks. For the power system,

developing and maintaining a portfolio of diverse generation, storage, and demand-side options can be 

useful for system planners and operators in creating optionality and hedging risks. Physical and financial 

risks can also be managed and hedged using reliability standards, operating rules, and financial markets 

and contracts. Better system diversity with greater use of domestic energy sources enhances U.S. energy 

security. However, greater fuel diversity does not always translate to increased system reliability.

Risk, Reliability, and Fuel Diversity311

In a summary of the policy implications of the impacts of fuel diversity on risk and reliability, Devin Hartman 

of the R Street Institute states that:

Policymakers and regulators should recognize that fuel diversity is a poor proxy for valid policy 

objectives, like risk management and reliability. Specifically, a high level of fuel diversity does not 

necessarily mean that an electricity system manages risk efficiently or meets reliability needs.

Conversely, policies or market-design changes intended to increase fuel diversity will not necessarily 

improve risk management or reliability. 

Fuel neutrality is essential for both monopoly-utility resource planning and competitive markets to 

manage risk and achieve reliability efficiently. Interventions to promote specific fuel types—such as 

44%

19%

2%

3%

20%

7%

2%

1%

0%

2%

23%

30%

3% 28%

2%

20%

7%

6%

1%

1%

3%

34%

50%

10% 3%

5%

20%

7%

0%

2%

0%

2%

18%

31%

20% 12%

8%

10%

8%

3%

6%

0%

2%

40%

26%

23%

12%

7%

9%

8%

8%

3%

2%

2%

42%

36%

12% 12%

12%

11%

9%

0%

7%

0%

2%

35%

Coal

Natural Gas (all)

Natural Gas (CC)

Natural Gas (CT)

Natural Gas (ST)

Nuclear

Hydro

Wind

Oil

Solar

Other
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bailouts for coal and nuclear or mandates and subsidies for renewables—skew investment risk and 

can undermine incentives for reliability-enhancing behavior (e.g., a public intervention to finance 

pipeline expansion removes incentives for the private sector to invest in fuel security). Fuel-specific 

subsidies and mandates replace individual choice with collective choice. This one-size-fits-all 

approach to risk mitigation ignores variances in individuals’ risk tolerances, results in high-cost risk 

mitigation, and creates perverse incentives for market participants by transferring risk and costs from 

the private to the public sector. 

For regulators, attempts to achieve fuel diversity in market designs explicitly would likely result in 

inefficient and potentially discriminatory practices that are inconsistent with the Federal Power Act. 

The reliable performance of power generators varies across and within fuel types and changes with 

fluctuating conditions. This renders any attempt to value fuel diversity very complex. It would require 

extensive administrative judgment, expanding the potential for government failure. Ultimately, the 

central aim of market design should remain to procure specific reliability attributes at the least cost. 

4.2.2 Fuel Assurance and Onsite Storage 

FERC uses the term fuel assurance to mean a generator’s access to sufficient fuel supplies through 

markets or bilateral contracts (and the degree to which those arrangements are firm). On the RTO/ISO 

level, fuel assurance refers to the regional resource portfolio’s ability to access sufficient fuel to meet 

system needs and maintain reliability.312 313

NERC’s 2017 State of Reliability report identified “lack of fuel” among the top ten causes of forced 

outages for 2014 and 2015.314 While lack of fuel is a relatively infrequent cause of generator outages, it 

can still have major repercussions when it does occur because system fuel supply chain disruptions can 

impact many generators during a single widespread fuel shortage event. Nuclear and coal plants 

typically have advantages associated with onsite fuel storage compared to natural gas. While having fuel 

onsite reduces the risk that a generator will be unable to operate when needed, every type of fuel and 

power generation source has known vulnerabilities that can compromise its ability to perform reliably. 

Valuation or regulation of onsite fuel storage varies across the Nation’s organized markets. Onsite fuel 

supplies can be required, incentivized, or not compensated—depending on the RTO/ISO in question. For 

example, some dual-fuel generators in the New York City region (NYISO Zone J) are required under local 

reliability rules to maintain onsite fuel to protect against the loss of gas supplies.315 Several markets have 

also attempted to incentivize firm and onsite fuel supplies by adding performance requirements to their 

capacity markets. In PJM and ISO-NE, these requirements were adopted after generator 

underperformance occurred during several instances of system stress between 2010 and 2014.kkk The 

incentives in these markets are designed to reward or penalize generators based upon how they 

respond to the system operator during performance events. 

According to Gordon van Welie, President and CEO of ISO-NE: 

We currently have a precarious operating situation in the winter time and we're worried about 

it becoming unsustainable beyond 2019... The reality is that we're really operating with a 

very slim operating margin during the winter time that may not cover these large 

contingencies that worry us.316

kkk These events included both situations in which natural gas power plants were unable to draw fuel from pipelines, as well as 

ones in which sufficient fuel was available but unit outages and/or start times inhibited operation. 
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Both programs remain in their infancy: ISO-NE’s takes effect in 2018, and PJM’s has only been active 

since 2016 (with a gradual phase-in through the 2019/2020 delivery year). In the interim, ISO-NE 

instituted a stopgap measure called the Winter Reliability Program, which compensates some dual-fuel 

generators for procuring onsite fuel.317 Outside of these regions, onsite fuel is not compensated or, in 

the case of VIEU, is incorporated into integrated resource planning (IRP) efforts. Other aspects of fuel 

assurance include having dual fuel capabilities and having low exposure to supply chain interruptions 

(including adequate, reliable infrastructure and sufficient contractual arrangements for fuel delivery). 

Natural Gas

NERC refers to the “single point of disruption risk” as the increasing risk of fuel disruption that threatens 

generator availability. In a letter to Secretary Perry, NERC CEO Gerry Cauley observed that:

Growing reliance on natural gas continues to raise reliability concerns regarding the ability of 

both gas and electric infrastructures to maintain the BPS reliability at acceptable levels. 

Many efforts have focused on the gas-electric interface and yet, insufficient progress has 

been made reconciling the planning approaches and operating practices (scheduling 

situation awareness, information sharing) between these two inter-linked sectors. Planning 

approaches, operational coordination, and regulatory partnerships are needed to assure fuel 

deliverability, availability, security (physical and cyber), and resilience to potential

disruptions. Unfortunately, an approach not obvious in electricity markets today.318

Natural gas-fired generators have been described as relying on “just-in-time” fuel delivery.319 NERC, 

FERC, and several of the ISOs and RTOs have studied the gas-electric interactions and interdependence, 

which are most severe in the areas where natural gas generation is growing most quickly, but natural 

gas pipeline infrastructure is more constrained—particularly New England and California. NERC has 

concluded that:

[...] areas with a growing reliance on natural gas-fired generation are increasingly vulnerable 

to issues related to gas supply unavailability. Common-mode, single contingency-type 

disruptions to fuel supply and deliverability in areas with a high penetration of natural gasfired generation are reducing resource adequacy and potentially introducing localized risks to 

reliability. Not only can impacts to BPS reliability occur during the gas-load peaking winter 

season, but they can also manifest during the summer season when electric demand is high 

and natural gas facilities are out of service, which can lower the operational capacity and 

flow of the pipeline system.320

NERC recommends a number of planning and operational changes to address this challenge, including 

risk-based approaches to study the potential regional reliability implications of greater natural gas 

dependence; the potential for wide-spread, common-mode failure events such as interstate gas pipeline 

or supply source losses; regional mitigation strategies; better information-sharing and coordination 

between electric generators, gas suppliers, and pipeline operators; and ensuring the availability of more 

flexible resources for use to mitigate the added uncertainties associated with natural gas fuel risks.321

Natural gas storage is a way to reduce the just-in-time delivery problem. Natural gas is stored in 

depleted natural gas and oil fields, depleted natural aquifers, and salt caverns. Figure 4.18 shows natural 

gas storage facilities across the Nation. The ideal storage facilities are near major gas consumption 

centers, where storage can supplement gas pipelines to meet high demand levels and fill in deliveries in 

the event of any delivery disruptions.
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Figure 4.18. Natural Gas Storage Facilities322

The United States has over 400 natural gas storage facilities; the majority are depleted natural gas fields 

used for storage, with salt domes concentrated in the Southeast and aquifer storage concentrated in 

Illinois and Indiana.

Data presented at a recent testimony before FERC offers an interesting perspective on areas that 

depend on just-in-time energy. The data in Table 4-3 show a dozen states that depend on high levels of 

just-in-time imports, whether those imports are natural gas for in-area generation or transmissionenabled electricity imports. These areas may need greater planning and resilience measures to ensure 

fuel security, which may include some availability of petroleum-based fuels for units that can use them 

when natural gas may be difficult or expensive to source. 
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Table 4-3. Dependence on Imported Just-in-Time Energy for Electricity323

The leaks discovered at California’s Aliso Canyon natural gas storage facility in October 2015 California 

illustrate another natural gas common failure mode problem, according to analysis completed by PJM:

Analysis performed after the leak identified 17 nearby electric generators with a combined 

output of over 9,800 MW that relied on Aliso Canyon for fuel supply. Some of these 

generators are required for local reliability; however, without supply from Aliso Canyon, low 

pressure in gas pipelines could stop the flow of gas to the generators, leaving them unable to 

operate.324 The loss of Aliso Canyon gas storage field highlights the risk to the power grid 

from failures in the pipeline infrastructure. Electric market and regulatory changes in 

California resulting from this event include: expedited procurement of electric storage 

resources, enhanced gas-electric coordination, expanded demand response program and a 

constraint in the electric market that reflects gas limitations.325

After the 2014 Polar Vortex, when many gas-fired power plants were forced off-line due to natural gas 

production and delivery problems, inadequate gas supply contracts, and spiked natural gas prices, NERC 

recommended the following:

Examine and review the natural gas supply issues encountered during the event. Industry 

should also work with gas suppliers, markets, and regulators to quickly identify issues with 

natural gas supply and transportation so that appropriate actions can be developed and 

implemented to allow generators to be able to secure firm supply and transportation at a 

reasonable rate.326

FERC has since promulgated orders to improve coordination between natural gas and power industry 

operations. While various electric and gas industry groups, including NERC, have had and continue 

coordination efforts, a significant amount of coordination remains unresolved. 
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Nuclear 

As NERC noted, low exposure to fuel supply issues is one of the fundamental necessities of a reliable 

BPS. Still, fuel availability does not always guarantee dependable performance, particularly during 

extreme weather events. In 2010, the Browns Ferry nuclear plant in Alabama was throttled back to 50 

percent of its maximum output because the plant was unable to draw and return enough water (due to 

environmental regulations) to cool all three of its reactors.327 

Nuclear generators have onsite fuel storage due to their 18-month or 24-month refueling cycles.328

During the Polar Vortex, some coal and nuclear plants had fuel onsite but failed to perform nonetheless. 

However, overall nuclear generators performed extremely well during the Polar Vortex, with an average 

capacity factor of 95 percent.329

Nuclear power plants tend to have a very high number of “days of burn” onsite relative to coal, as their 

refueling occurs in 18-month or 24-month cycles. During each refueling, about one-third of the core is 

replaced with new fuel. The new fuel arrives onsite between nine and five weeks prior to the planned 

refueling. However, even if there is a delay in the arrival of new fuel, the reactor could continue to 

operate for an additional three months before reaching 70 percent capacity and two more months 

beyond that (for a total of five months) before decreasing to 50 percent capacity. The fuel that is 

replaced during each refueling has typically been used in the reactor for four-and-a-half to six years 

before it is removed. Planned refueling outages are typically scheduled for the spring and fall and 

average 35 days.330

Coal

A limited number of coal plants, including all plants that use lignite coal, are “mine-mouth” facilities that 

rely on dedicated, nearby coal mines. Otherwise, coal plants rely on rail, barge, or truck delivery of coal, 

and they maintain onsite coal stockpiles to accommodate both normal variance in deliveries and the 

possibility of a major supply disruption. Coal stockpiles have recently been slightly smaller than historical

averages, while days of burn have increased slightly relative to historic averages from the 70–80-day 

range to the 85–100-day range (see Figure 4.19). lll 331 

lll At an individual plant, stockpiles can be viewed in terms of days of burn. The days-of-burn calculation considers both the 

current stockpile level at a plant and its estimated consumption (burn) rates in coming months to approximate how many days 

the plant could run at historical levels before depleting its existing stockpile. 
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Figure 4.19. Coal Stocks and Days of Burn, January 2010–May 2017332

While bituminous coal stockpiles in tons have been slightly lower than historic averages in recent months, 

these stocks are expected to last relatively longer than historic average (measured in days of burn) due to 

lower capacity factors and expected lower fuel consumption in coal plants. Subbituminous coal stocks 

(not pictured) have increased in recent months relative to historic averages both in terms of tons and days 

of burn. 

For the winter of 2014, compared to 2013, coal-fueled generation provided 92 percent of increased 

generation, as shown in Figure 4.20. Although electricity demand was greater in 2014, natural gas 

generation decreased because natural gas was diverted to fuel residential heating needs and gas prices 

rose to greater than three times those of coal. 
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Figure 4.20. Electricity Generation Changes from 2013 to 2014 by Fuel Type 

Competition for natural gas between residential heating and power production caused a rise in natural 

gas prices in the early months of 2014. The high gas prices coupled with onsite coal storage led to a 

sharp increase in coal electricity production in those months compared to the winter of 2013. 

Coal plants can also experience delivery interruptions. In 2013, there were 166 power plants (172,000 

MW of generating capacity) across the United States that used subbituminous coal from the Powder 

River Basin. During the winter of 2013–2014, BNSF Railway rationed and limited coal deliveries to many 

of these generators due to construction and other disruptions. Stockpiles fell from 25 percent to 40 

percent below normal levels at coal plants across the Midwest, Central, and Texas regions; many plants 

feared that they might not be able to rebuild their inventories in time to meet winter electric 

demands.333 

4.3 High-Risk Events and System Resilience 

The April 14 memo asks whether wholesale energy and capacity markets are adequately compensating 

attributes that strengthen grid resilience and, if not, the extent to which not compensating resilience 

attributes could affect grid reliability and resilience in the future. 

A resilience approach recognizes that while not all risks can be avoided, many risks can be managed to 

mitigate damage and expedite recovery. Some options to improve grid resilience may be risk-specific 

(e.g., to protect against flooding) or component-specific (to protect a transformer), while others are 

“threat-agnostic, providing system-wide resilience to a broad range of threats including those that 

cannot be anticipated” according to the Grid Modernization Lab Consortium (GMLC).334 As the fuel mix 

evolves and as threats change, there will be more ways that elements and regions of the BPS can fail. 

Causes of failure can include extreme weather events and cyber or physical attacks on grid 

infrastructure. 335 336
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Extreme Weather Events

In January and February 2014, the Nation was swept by the Polar Vortex as a band of very cold weather 

spread across much of the eastern United States, creating record-high winter peak electric demand for 

heating and equally high demand for natural gas for residential heating. While the Polar Vortex tested 

the integrity of electricity supply, grid operators generally met demand, even under these severe 

conditions. 

However, electricity and gas prices surged for many consumers as energy supplies were stressed. The 

extremely cold weather caused a variety of power system performance problems, including the loss of 

35,000 MW of generation capacity across a wide stretch of the Nation, with 55 percent of the affected 

generation from natural gas plants, 26 percent coal plants and five percent nuclear.337 In PJM, one of the 

regions most affected by the event, 22 percent of generating capacity was in forced outage.338

Many natural gas-fired generators had their fuel supplies curtailed because they were buying gas on 

non-firm, interruptible contracts, or because demand was so high that pipelines implemented delivery 

restrictions to power plants located near major metropolitan areas. In the Northeast, after several days 

of extremely cold weather, some generators experienced fuel-gelling, where the natural gas froze in the 

fuel injectors and was unable to feed into the turbines.339 In Texas, a major source for natural gas 

production and a transport hub, several gas field production facilities froze up, as did some gas 

compressor stations along pipelines—shutting down gas feeds into and through pipelines that were to 

be shipped into New Mexico and elsewhere. This caused fuel shortages to the power plants served by 

those pipelines.340 Limited supplies led to natural gas price spikes across much of the country; in some 

areas, gas to produce electricity was more expensive than liquid fuel, even though the price of oil for 

generation rose to over $400 per barrel. 341

Many coal plants could not operate due to conveyor belts and coal piles freezing342, which—coupled 

with outages across other fuels and high electricity demand—led operators to call on older plants 

nearing the end of their useful lives. American Electric Power reported that it deployed 89 percent of its 

coal units scheduled for retirement in 2014 to meet demand during the Polar Vortex, and Southern 

Company reported using 75 percent of its coal units scheduled for closure.343 Using these retiring units 

enabled utilities to meet customer demand during a period when already limited natural gas resources 

were diverted from electricity production to meet residential heating needs.344 345Once retired, 

however, these units will not be available for the next unseasonably cold winter. 

In October 2012, Superstorm Sandy caused large-scale flooding and wind damage in the Mid-Atlantic 

and Northeast, as well as blizzard conditions in the central and southern Appalachians. Three nuclear 

reactors totaling 2,845 MW of capacity were shut down, and five operated at reduced levels due to 

disruptions in transmission infrastructure, reduced demand from distribution outages, and 

precautionary measures to protect equipment.

346 The storm impacts significantly disrupted East Coast 

refining activity. Spectra Energy lost two natural gas compressor stations on its Texas Eastern 

Transmission pipeline in northern New Jersey due to the loss of commercial power and the failure of 

backup generation to operate as intended, which affected gas supply to upstream gas-fired power 

plants. New Jersey Natural Gas shut down part of its natural gas infrastructure serving Ocean and 

Monmouth counties, including Long Beach Island and the barrier islands from Bay Head to Seaside Park, 

with subsequent distribution line damages.347 Sandy also damaged solar PV installations in New Jersey, 

with storm surges causing $3 million of damage to ground-mounted PV systems and wind and lightning 

damage to rooftop PV systems.348
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4.4 Enhancing Reliability and Resilience 

Recently, based on extensive information about the operational profiles of PJM resources, PJM assessed 

the capability of each generator type to provide different ERS.mmm PJM then built a series of hypothetical 

resource portfolios using different mixes of generation types to determine how well each portfolio 

performed at delivering sufficient reliability. PJM also considered the risk that each portfolio would fail 

to meet resource adequacy needs and thus cause reliability problems. After simulating many 

combinations and portfolios, the following conclusions were reached: 

 The expected near-term resource portfolio is among the highest-performing portfolios and is

well equipped to provide the generator reliability attributes.

 As the potential future resource mix moves in the direction of less coal and nuclear

generation, generator reliability attributes of frequency response, reactive capability and fuel

assurance decrease, but flexibility and ramping attributes increase.

 A marked decrease in operational reliability was observed for portfolios with significantly

increased amounts of wind and solar capacity (compared to the expected near-term

resource portfolio), suggesting de facto performance-based upper bounds on the percent of

system capacity from these resource types. Additionally, most portfolios with solar unforced

capacity shares of 20 percent or greater were classified infeasible because they resulted in

LOLE criterion violations at night. Nevertheless, PJM could maintain reliability with

unprecedented levels of wind and solar resources, assuming a portfolio of other resources

that provides a sufficient amount of reliability services.

 Portfolios composed of up to 86 percent natural gas-fired resources maintained operational

reliability. Thus, this analysis did not identify an upper bound for natural gas. However,

additional risks, such as gas deliverability during polar vortex-type conditions and

uncertainties associated with economics and public policy, were not fully captured in this

analysis. Risks with respect to natural gas may lie not in capability to provide the generator

reliability attributes but rather in these other uncertainties.

 More diverse portfolios are not necessarily more reliable; rather, there are resource blends

between the most diverse and least diverse portfolios which provide the most generator

reliability attributes.349 [original footnotes omitted]

Significantly, when PJM tested the most desirable portfolios (in terms of reliability) against a polar 

vortex event, only a third of those were resilient: 

Only 34 of the 98 portfolios which were classified as desirable were resilient when subjected 

to a polar vortex event. This sensitivity specifically captured the increased risk of natural gas 

delivery under extremely cold and high load conditions. The polar vortex sensitivity highlights 

the importance of resilience, which is not captured by the generator reliability attributes that 

were considered in this study.350

DOE, NERC, and industry stakeholders prepare for a variety of potential threats, including high-impact, 

low-frequency events, to improve resilience and recovery. Planning, practice, and coordination on an allhazards basis are as important for improving resilience as having a mix of resources and fuels available 

when a major grid disturbance occurs. A diverse resource portfolio could complement wholesale market 

products that recognize and compensate providers for the value of ERS on a technology-neutral basis. 

mmm The PJM study assumed firm gas supply contracts for natural gas-fired generators. 
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DOE’s Grid Modernization Initiative (GMI) works to better understand what resilience means for the 

power system and how to measure and achieve it.

Transmission planning also supports grid reliability and resilience through interconnecting diverse 

resources, and it occurs at a variety of levels—ranging from individual utility system studies to regional 

and interconnection-wide studies. In 2009, DOE issued a series of grants to support interconnectionwide transmission planning. In 2011, FERC issued Order No. 1000, which (among other requirements) 

mandates regional transmission planning and interregional coordination. As noted in a recent study for 

the WIRES group:

The analytical approaches applied to interregional [transmission] planning should look 

beyond “base cases” or “business-as-usual cases” and explicitly consider a broader range of 

plausible market conditions, system contingencies, and public policy environments to capture 

the short- and long-term flexibility benefits and insurance value that a more robust 

interregional transmission infrastructure can offer in terms of shielding customers from highcost outcomes.

... we recommend that such futures be evaluated to identify transmission projects that 

address current needs but also provide the insurance and flexibility value to mitigate highcost outcomes across a range of uncertain but not implausible futures.351

Given the many problems that can affect different generation and fuel types, system-wide reliability and 

resilience can be supported by a diverse portfolio of generation resources that limit over-dependence 

on any single fuel or technology type, plus demand-side resources that reduce overall demand and 

better protect customers in the event of a widespread extreme event.

4.5 Reliability and Resilience Looking Forward

Although the BPS is performing reliably today with the current mix of resources, technologies, and loads, 

the entire system remains volatile. Low customer demands and a flatter supply curve mean that many 

generators face continuing economic stress, retirements may continue, and utility-scale and customerside VRE additions (enabled by subsidies and mandates) will continue. These factors and the uncertainty 

about future conditions are making it harder for grid planners and operators to maintain today’s level of 

reliability. 

Any successful strategy to address BPS reliability and resilience going forward should include developing

portfolios of resources that deliver both resource adequacy and ERS to advance reliable grid operations. 

Resource portfolios could be complemented with wholesale market and product designs that recognize 

and complement resource diversity by compensating providers for the value of ERS on a technologyneutral basis. More work is needed to define, quantify, and value resilience; Sandia National 

Laboratories has made efforts to do so, as shown in Figure 4.21.
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Figure 4.21. Sandia National Laboratories’ Resilience Analysis Process352
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5 Wholesale Electricity Markets 

The wholesale electricity market issues outlined in the April 14 memo are central to the future of U.S.

electricity markets and policy. At the same time, they are the subject of intense debate among 

stakeholders with differing regional and economic interests. Noting the wide range of opinion on these 

issues, DOE staff offer three general findings: 

1) Changing circumstances are challenging centrally-organized wholesale markets. Flat demand 

growth, Federal and state policy interventions, and the massive economic shift in the relative 

economics of natural gas compared to other fuels are creating stresses on wholesale electricity 

markets. The centrally-organized markets are successfully achieving reliable and economically 

efficient delivery of wholesale electricity in their short-term operations, but the changing 

circumstances portend potential long-term problems for centrally-organized and, to a lesser extent, 

bilateral markets.

2) New technologies with very low marginal costs, i.e. VRE, reduce wholesale prices, independent of—

and in addition to—the effects of low natural gas prices. To the extent that additional development 

of such resources is driven by subsidies and mandates, their price suppressive effect might place 

undue economic pressure on revenues for traditional baseload (as well as non-baseload) resources 

and could require changes in market design.

353 354 355

3) Markets need further work to address grid resilience. Market mechanisms are designed to 

incentivize individual resources rather than develop balanced portfolios. System operators are 

working toward recognizing, defining, and compensating for reliability- and resilience-enhancing 

resource attributes (on both the supply and demand side), but more work must be done. 

U.S. market structures vary widely, but despite substantial differences between markets, some patterns 

emerge and are worth addressing in response to the April 14 memo.

5.1 Evolution of U.S. Wholesale Electricity Markets

Until the 1970s, investor-owned electric utilities were vertically integrated (i.e., provided generation, 

transmission, and distribution of electricity to their customers at regulated rates and with 

administratively determined profits). This concept was loosely referred to as the “regulatory 
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compact.”

nnn Interspersed with VIEUs were—and still are—over 3,200 cooperatively owned electric 

utilities.ooo 356

 

In the 1920s, policymakers accepted the idea that non-utility companies might be able to generate 

electricity at equal or lower cost than VIEUs, to the benefit of electricity consumers.357 In 1978, Congress 

passed the Public Utility Regulatory Policies Act (PURPA), which introduced competition to the VIEU 

model and set the stage for later regulatory reform of the electricity industry.358 At the time, PURPA was 

largely an effort to curb the electricity industry’s reliance on high-cost natural gas and oil.ppp PURPA 

provided for “increased conservation of electric energy, increased efficiency in the use of facilities and 

resources by electric utilities, and equitable retail rates for electric consumers.” 359 It also made 

developing new generation resources easier—specifically renewable energy and cogeneration 

facilities.360

The Energy Policy Act of 1992 allowed FERC to approve “exempt wholesale generators,” using any fuel 

and any generation technology, to go into the generation business and sell electricity at competitive 

prices. The act also authorized FERC to order transmission owners to provide transmission service.361

Also in 1992, Congress enacted the PTC to incentivize VRE energy production, which Congress has 

extended and modified several times since.362

In 1996, FERC required transmission owners under its jurisdiction to provide open-access transmission 

to the interstate transmission grid through its landmark Order No. 888. Open access means charging all 

similarly situated parties the same rate (including, if applicable, what the utility would charge itself to 

use its transmission facilities) and providing service to all similarly situated parties under the same terms 

and conditions.363 This action by FERC greatly assisted the development of competition among 

wholesale power producers because it meant that utilities would find it difficult to limit access to their 

transmission facilities as a means of protecting their generation assets from competitors. FERC Order 

No. 2000 (issued in December 1999) promoted voluntary participation in RTO/ISOs by further clarifying 

both necessary characteristics of RTO/ISOs and benefits of such participation.364 

Between 1998 and 2006, 23 states made changes to require their VIEUs to divest some or all of their 

generating assets and thus allow competition.365 Divestiture was pursued most aggressively by the 

states with high retail electricity prices (most of New England, New York, the Mid-Atlantic states, and 

nnn “The ‘state regulatory compact’ evolved as a concept ‘to characterize the set of mutual rights, obligations, and benefits that 

exist between the utility and society.’ It is not a binding agreement. Under this ‘compact,’ a utility typically is given exclusive 

access to a designated—or franchised—service territory and can recover its prudent costs (as determined by the regulator) plus 

a reasonable rate of return on its investments. In return, the utility must fulfill its service obligation of providing universal 

access service within its territory. https://www.energy.gov/sites/prod/files/2017/02/f34/Appendix--

Electricity%20System%20Overview.pdf 

ooo Most public power utilities are distribution-only; however, some are vertically integrated. Distribution-only cooperatives 

typically purchase all or some of their electricity at the wholesale level from generation and transmission cooperative utilities. 

ppp Also in 1978, the Power Plant and Industrial Fuel Use Act prohibited “(1) the use of natural gas or petroleum as a[n] energy 

source in any new electric power plant; and (2) construction of any new electric power plant without the capability to use coal 

or any alternate fuel as a primary energy source.” https://www.congress.gov/bill/95th-congress/house-bill/5146 

The Fuel Use Act was mostly repealed in 1987, which “set the stage for a dramatic increase in the use of natural gas for electric 

generation and industrial processing.” https://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/repeal.html
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California) with the hope that competition would bring lower retail consumer prices.qqq 366Generating 

units that had been operating under cost-of-service regulation were sold to merchant plant owners or 

transferred to unregulated, investor-owned utility affiliates. 

This wave of restructuring did not sweep the entire Nation. In large areas—particularly the Southeast 

and the West, apart from the expanding Energy Imbalance Market—the wholesale electricity industry is 

still vertically integrated. In these areas, the wholesale market consists of bilateral transactions. 

Because restructuring did not take hold in all states, a range of organizational structures exist at the 

wholesale level in the United States today, as shown in Figure 5.1. States considered “Partially 

Restructured” below have divested some generation and/or allowed a portion of customers to choose 

their energy provider.

Figure 5.1. Utility Restructuring by State as of May 2017367 

5.2 Wholesale Electricity Markets Today

Over the past two decades, a diverse set of wholesale electricity markets has evolved in different 

regions of the United States. These wholesale markets can be divided into two broad categories. For the 

purposes of this section, regions of the country that have not joined RTO/ISOs are called traditional 

 

qqq Whether this objective has been achieved is mixed in the literature. Availability rates for generation have improved 

significantly and, as predicted, as competition incentivized operators to run their units as efficiently as possible. Dispatch over 

the much broader footprints of RTO/ISOs also increases efficiency and thus reduces costs. PJM notes (July 26, 2017 written 

statement before Subcommittee on Energy, U.S. House Committee on Energy and Commerce) “nearly $2 billion of annual 

savings to customers.” On the other hand, Borenstein’s 2015 review claims “the electricity rate changes since restructuring 

have been driven more by exogenous factors - such as generation technology advances and natural gas price fluctuations - than 

by the effects of restructuring.” See two meta-studies: Severin Borenstein and James Bushnell, “The U.S. Electricity Industry 

after 20 Years of Restructuring,” May 2015, https://ei.haas.berkeley.edu/research/papers/WP252.pdf and James Bushnell, Erin 

T. Mansur, and Kevin Novan, “Review of the Economics Literature on US Electricity Restructuring,” April 2017, for DOE, 

unpublished.
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bilateral markets, while those that have are called centrally-organized markets. These regions are shown 

in Figure 5.2, with RTO/ISOs labeled and colored, and bilateral markets depicted in gray. 

Figure 5.2. The Seven RTOs or ISOs in the United Statesrrr 368

There are currently seven centrally-organized markets operating across the United States. 

The diversity of approaches to market organization and resource adequacy can be visualized along a 

spectrum, as shown in Figure 5.3—from VIEUs with minimal market organization on one end, to fully 

restructured markets without formal resource adequacy requirements on the other. Between vertically 

integrated and energy-only regions, there are diverse approaches to allocating the financial risk of 

generation investment and the responsibility to provide resource adequacy. 

rrr Map redrawn from FERC’s December 2016 website. 
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Figure 5.3. States and Regions along the Spectrum from Traditional to Fully Restructured Electric 

Markets369

In the Southeast and West, bilateral markets are dominated by VIEUs that operate under a regulated 

cost-of-service model. States in these regions retain strong control over electric utility resource 

decisions and oversee resource adequacy, and they consider non-market factors in their oversight of 

utility decisions through a utility’s IRP process. Once approved by state regulators, ratepayers guarantee 

the cost recovery of VIEU generation investments through retail rates (or merchant generators through 

long-term PPAs with utilities). Thus, the financial viability of these generators is not immediately 

exposed to the same price volatility that generators face in market-oriented regions. However, new 

resource decisions in VIEU regions are beginning to account for low natural gas prices, low load growth, 

and zero-marginal cost generation.sss

Public power and rural cooperative utilities also have a significant presence in some regions. Utility asset 

ownership models can vary from vertically integrated to distribution-only. Merchant generators also 

operate within these regions, but most electricity is produced and delivered by the integrated utilities, 

with minimal additional spot transactions.370

In centrally-organized markets, generators offer electricity bids on a day-ahead and real-time basis. The 

RTO/ISO then pools these bids into a single supply curve and calculates the clearing price that matches 

supply to demand, considering transmission limitations for the next interval. This calculation yields a set 

of market-clearing prices, one for each location and time horizon. Centrally-organized markets also 

compensate resources that provide certain ERS through ancillary service markets. Furthermore, in some 

cases, RTO/ISOs provide supplemental revenues to generators that are dispatched out-of-market, such 

as ones that are needed to ensure local reliability. 

 

sss See, for example, 152 FERC ¶ 61,013 (Florida Power & Light Company) or Steve Wright, General Manager, Chelan County 

PUD, a vertically integrated utility in Washington, told DOE staff in a June 19, 2017, conversation that the relatively low 

wholesale prices traditionally seen in the Northwest due to an abundance of low-cost hydro are now further stressed by the 

export of surplus zero-marginal cost California rooftop solar, so much so that he is “finding it hard to even justify spending on 

energy efficiency in [his utility’s] integrated resource plan.”
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RTOs/ISOs operate as a single balancing authority and achieve cost savings by procuring reserves and 

other ancillary services for the system. For example, MISO estimates that because it operates an 

ancillary service market across the entire region, spinning reserve requirements can be based upon the 

entire region’s needs rather than the sum of individual balancing authorities’ spinning reserve 

requirements. By operating the ancillary services market, MISO reduced its average spinning reserves 

requirement from 1,482 MW to 935 MW and saved almost $25 million per year for its members by 

freeing up generation from having to meet the reserve requirement.371

CAISO, MISO, and SPP retain aspects of the bilateral markets, particularly that states still oversee 

resource procurement and resource adequacy of their VIEUs, through the IRP process.372 California, 

MISO and SPP, as well as traditional bilateral market states, incorporate considerations other than shortterm economic efficiency into their resource choices, such as portfolio diversity, job retention or 

creation, environmental protection, and other factors. 

5.2.1 Responsibility for Resource Adequacy and Capacity 

Some states require utilities to build new or subsidize specific power plants outside the RTO/ISO 

resource adequacy processes. Other centrally-organized markets (namely PJM, ISO-NE, and NYISO) have 

implemented capacity markets as a mechanism to provide sufficient revenue for resources to ensure 

resource adequacy. In these markets, the system operator conducts an auction process, and wholesale 

customers procure resources (including generation, energy efficiency, DR, and transmission-enabled 

resource imports) to meet the electricity demands of their customers. These markets can be mandatory 

(PJM Interconnection and ISO New England); voluntary, where states can choose to operate under an 

IRP process and where load-serving entities can satisfy their requirements through a combination of the 

market and/or showing that they have rights to adequate capacity (MISO); or voluntarily backstopped 

by a mandatory process (NYISO). ERCOT does not have a formal resource adequacy requirement. 

5.3 Challenges in Wholesale Electricity Markets 

Centrally-organized markets are now 15–20 years old, and their original designs (even with continual 

and evolving updates) are showing signs of strain from the pace of change now underway in the 

electricity industry. Many of these changes were not foreseen during the restructuring and wholesale 

market designs of the 1990s–2000s. Flat demand growth, flattened supply curves, Federal and state 

policy interventions, and the massive economic shift in the relative economics of natural gas compared 

to other fuels are placing pressures on centrally-organized wholesale electricity markets, resulting in low 

average wholesale energy prices. These markets were designed when supply curves tilted sharply 

upward, demand grew over time, and capacity was not explicitly compensated to make up for 

insufficient revenues from an energy-only market. A 2014 FERC staff report notes: 

A failure to properly reflect in market prices the value of reliability to consumers and operator 

actions taken to ensure reliability can lead to inefficient prices in the energy and ancillary 

services markets leading to inefficient system utilization, and muted investment signals.373
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The issue of revenue insufficiency and generator retirements in centrally-organized electricity markets is 

a complex topic, with causality difficult to assign beyond the individual asset/owner level.ttt Each plant

has its own cost structure, and plant revenues can differ between neighboring nodes in a single market. 

Traditional, bilateral-only wholesale markets are not immune to these issues either, but may not be 

seeing them yet at the same scale as the three eastern RTO/ISOs that have a predominance of merchant 

generation. An issue that is more prevalent in these regions than in regions with bilateral markets is the 

PURPA “must-purchase obligation” that still applies to those regions. After Congress amended PURPA in 

the Energy Policy Act of 2005, many utilities in regions with centrally-organized wholesale markets have 

sought and received from FERC orders terminating their obligations.

374

By contrast, utilities in regions with traditional, bilateral-only wholesale markets remain subject to the 

PURPA requirement to buy power from Qualifying Facilities (QFs) under PPAs, with up to 20-year terms 

and at rates that the applicable state regulator has determined reflect the purchasing utility’s avoided 

costs. In some instances, generation purchased from QFs has displaced utility-owned generation and 

thus reduced utility revenue. PURPA remains a subject of ongoing debate within the industry, as 

evidenced by a discussion during a FERC June 2016 Technical Conference.375

5.3.1 Revenue Insufficiency due to Market Structure: The Missing 

Money Problem

In the mid-2000s it became apparent that merchant generators were failing to recover sufficient 

revenues through the energy-only markets to cover both their variable and fixed costs. The issue 

subsequently became known as the “missing money problem.”uuu In testimony before a 2014 FERC 

technical conference, David Patton, the independent market monitor for ERCOT, ISO-NE, MISO, and 

NYISO, described the issue as stemming from overly-stringent planning reserve requirements:

With reasonable assumptions about capacity cost and energy prices, [the one-day-in-tenyears] reliability standard implies a value of lost load of $100,000 to $200,000 per MWh.

Hence, without substantially inflated shortage prices, energy-only markets cannot provide 

enough revenue to satisfy planning reserve requirements. Additional revenue is needed to 

satisfy these requirements, which is the “missing money” problem addressed by the capacity 

markets.376

William Hogan of Harvard University noted in 2005 that the missing money problem can also be 

attributed to price caps:

The missing money problem arises when occasional market price increases are limited by 

administrative actions such as price caps. By preventing prices from reaching high levels 

during times of relative scarcity, these administrative actions reduce the payments that could 

be applied towards the fixed operating costs of existing generation plants and the investment 

costs of new plants.377

To mitigate the missing money problem, centrally-organized markets have, to varying degrees, utilized 

shortage pricing and capacity markets.

 

ttt The market issues discussed in this section are most pertinent to a merchant generator operating within centrally-organized 

markets that are not subject to regulated rate recovery. 

uuu The first use of this term is attributed to Roy Shanker in his 2003 testimony before FERC. William W. Hogan, Harvard 

University, “’Energy Only’ Electricity Market Design for Resource Adequacy,” September 23, 2005
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Shortage Pricing

Shortage pricing, also referred to as scarcity pricing, seeks to ensure that energy market revenues reflect 

the value consumers place on reliability. It does this through administrative rules that raise prices above 

marginal costs during times of system stress. FERC has actively sought to improve the utilization of 

techniques like shortage pricing. In a 2014 analysis, FERC staff provided a useful overview of the 

rationale for shortage pricing: 

When the system operator is unable to meet system needs, it applies administrative pricing 

rules to ensure that costs, including the costs associated with the failure to meet minimum 

operating reserve requirements, are reflected in market prices. ...Under such conditions, 

prices should rise, inducing performance of existing supply resources and encouraging load 

to reduce consumption so that the system operator would not need to administratively curtail 

load to maintain reliability. 378

All of the Nation’s RTO/ISOs currently employ shortage pricing to some degree; however, the designs 

are not uniform. FERC Order No. 831 raised energy offer caps in jurisdictional RTO/ISOs from $1,000 to 

$2,000/MWh.379 Conditions required to trigger shortage pricing vary from year to year. This variance 

could present challenges to market participants who require a threshold level of certainty to make an 

investment decision. Remarks by market monitors David Patton and Joe Bowring critique the practice of 

relying solely on shortage pricing: 

[David Patton:] Shortage pricing is not like a capacity market where you’re going to get a 

level of revenue that might fluctuate by 10 to 20 percent per year. With shortage pricing, you 

might get 10 years of revenue in one year and then the other nine years the generators are 

going to think they’re going bankrupt.380

[Joe Bowring]: What will happen if you go through eight years of very low revenues under 

scarcity pricing ... and a significant number of units decide to retire because they can’t see 

into the future? They don’t know if [in] the ninth or 10th year there’s going to be $20 billion. 

They retire if the revenues aren’t adequate.

381

Capacity Markets

Four RTO/ISOs currently operate centralized capacity markets: ISO-NE, NYISO, and PJM hold mandatory 

auctions, while MISO’s is voluntary. Capacity markets address the missing money problem by imposing 

resource adequacy requirements on load-serving entities (LSEs). Spees, Newell, and Pfeifenberger 

provide a useful overview of how this process works: 

A resource adequacy [requirement] requires LSEs to procure sufficient generation or 

demand-response capacity to serve their own customers’ coincident peak load plus a 

mandatory planning reserve margin. If each LSE procures their required capacity, then the 

system as a whole will be able to meet its planning reserve margin requirement and target 

resource adequacy level. ... [Capacity] has value as a stand-alone commodity, the demand 

for which is driven by LSEs needing to meet their resource adequacy requirement.382

 

According to the authors, capacity market revenues should in theory ameliorate the missing money 

problem by providing “the incremental payment needed to recover their investment costs in addition to 

the operating profits earned through energy and ancillary service sales.”

383 Figure 5.4 provides a useful 

illustration of how capacity payments are intended to close the missing money gap. 
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Figure 5.4. How Market Prices Allow Resource Costs to be Recovered in a Centrally-organized

Wholesale Market384

 

Revenues from energy sold in the wholesale market pay for a generators' variable costs and some 

portion of fixed costs (indicated by green arrows). The unrecovered portion of fixed cost (missing money) 

is recovered through capacity market revenues (indicated by blue arrow). 

Some observers note that capacity markets may not provide sufficient revenues as originally intended. 

For example, the 2016 PJM Market Monitor’s report finds PJM’s markets can provide adequate revenue 

to support some existing capacity, but the outlook varies widely by technology, fuel choice, time 

interval, and location:

Analysis of the total unit revenues of theoretical new entrant CTs and CCs for three 

representative locations shows that units that entered the PJM markets in 2007 have not 

covered their total costs, including the return on and of capital, on a cumulative basis through 

2016. The analysis also shows that theoretical new entrant CTs and CCs that entered the 

PJM markets in 2012 have covered their total costs on a cumulative basis in the eastern 

PSEG [New Jersey] and BGE [Baltimore] zones but have not covered total costs in the 

western ComEd [Chicago] Zone. Energy market revenues were not sufficient to cover total 

costs in any scenario except the new entrant CC unit that went into operation in 2012 in 

BGE, which demonstrates the critical role of capacity market revenue in covering total 

costs.vvv 385

5.3.2 Revenue Insufficiency due to External Forces

While RTO/ISOs have sought to address the missing money problem as previously defined, newer 

variants of it continue to permeate stakeholder discussions. Economist Severin Borenstein notes that 

the definition has expanded to include the supply curve impact of subsidies:

Money has been going missing for many years, according to owners of power plants.

They’ve used the term for more than a decade to refer to the fact that wholesale electricity 

markets have price caps (mostly between $1,000 and $10,000 per MWh) that constrain how 

 

vvv As part of the review of market performance, the market monitor analyzed the net revenues earned by CTs, NGCCs, coal, 

diesel, nuclear, solar, and wind generating units.
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much sellers can make when supply is tight. Without that income, generators argue, it may 

not be profitable to build new capacity, or extend the life of existing capacity, that is needed 

to meet demand. 

More recently, the definition of missing money has been expanded to include the price 

impacts of subsidized or mandated renewables generation. In California, New York and 

many other states, wind and solar are pushing down wholesale prices and making continued 

operation of some nuclear and fossil fuel generation unprofitable. 386

 

Shifts in the Generation Supply Curve

Changes in the Nation’s generation mix have generally reduced revenues for incumbent baseload 

generators in wholesale markets, as highlighted in QER 1.2: 

[P]rice suppression is occurring in RTO/ISO wholesale markets, with noticeable amounts of 

wind and solar generation (and low-cost gas generation). While passing on savings to 

consumers is desirable, in some regions, these low prices have put pressure on baseload 

units, particularly zero-carbon emissions nuclear generation.387

Put more specifically, shifts in market supply curves have lowered the infra-marginal rentswww earned by 

baseload generators. Crucially, this reduction has occurred because of changes along both axes of the 

supply curve. Along the horizontal (supply) axis, the entry of new resources has pushed the curve to the 

right, resulting in a lower clearing price at the same level of demand. Meanwhile, reductions in marginal 

fuel costs (vertical axis) have lowered the slope of the curve. The net effect of these changes—as 

illustrated by a simulated dispatch curve in ERCOT—is shown in Figure 5.5. 

www Infra-marginal rents are the differences between the market-clearing price and the submitted bid of each generator. 

Generators that bid less than the market-clearing price receive a payment equal to this difference. 
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Figure 5.5. Simulated ERCOT Dispatch Curvesxxx

Changes in fuel costs and the supply mix have impacted market clearing prices, and thus lowered inframarginal rents for incumbent generators. Reductions in natural gas prices have clearly flattened the 

curve, reducing revenues for generation resources. The entry of new, near-zero marginal cost resources 

has also pushed the overall curve to the right. The entry of wind and solar resources is visible in lower 

left. 

Natural Gas and Incumbent Baseload

The frequency with which natural gas sets the price of electricity has increased in many of the Nation’s 

markets. For example, 2017 could mark the first time in PJM’s history that gas is marginal for more

intervals than coal (see Figure 5.6). This transition means that infra-marginal rents that were previously 

based on the marginal cost of coal resources have been supplanted by the marginal cost of natural gas

resources.

 

xxx EIA, analysis performed for DOE using EIA and ABB Ventyx software to show estimated plant-specific estimated production 

costs for July 15 of each year modeled, using then-current delivered energy prices (in 2009 $) within ERCOT and estimated, 

plant-specific heat rates to estimate plant-specific marginal costs of electricity production, June 2017
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Figure 5.6. Type of Fuel Used in PJM (by Real-Time Marginal Units): 2004 through March 2017388

Natural gas is rising as the marginal electricity generation source in PJM. 

The low price of natural gas has resulted in the competitive displacement of coal in many of the Nation’s 

markets. This trend is visible in Figure 5.7 by comparing the 2005 curve to the 2015 version. The 

interspersed nature of the coal and gas generators in the 2015 curve reflects that the two now compete 

for the same runtime. While gas had been a mid-merit source in previous years, it has become more of a 

baseload resource in recent years. The phenomenon is visible on a national level by examining the 

capacity factors of the respective technologies. 

Figure 5.7. Annual Average Capacity Factors of Coal and Natural Gas Generators 
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NGCC generators have seen a steady increase in fleet average capacity factor from 35% in 2005 to 56% 

in 2015; in that year, the NGCC fleet average eclipsed that of coal generators, which has declined from 

approximately 68% in 2010 to 55% in 2015.389

Negative Pricing

Negative pricing events in electricity markets reflect a complex set of economic, reliability, 

environmental, and safety variables. The interaction of these variables differs depending on the region, 

season, and time in question, but negative pricing often reflects some combination of excess generation 

(often exacerbated by must-run requirements), transmission constraints, and economic factors. 

According to analysis from LBNL, negative pricing events have historically been rare at many major 

pricing hubs (less than two percent of total hours in real-time markets in 2016), and have had almost no 

impact on annual average day-ahead or real-time wholesale electricity prices. However, more frequent 

negative pricing has been observed in CAISO, and in constrained hubs that feature a relatively large 

amount of VRE and/or nuclear generation.390 In addition, PJM has observed that “prices go negative at 

nuclear units buses in approximately 2,176 hours – representing 14 percent of off-peak hours.”391

The term economic factors in this case serves as a catchall for those negative pricing events that are not 

the direct result of must-run requirements. EIA provides examples of why generators might choose to 

run, even if it means accepting negative prices: 

Technical and economic factors may drive power plant operators to run generators even 

when power supply outstrips demand. For example: 

 For technical and cost recovery reasons, nuclear plant operators try to continuously

operate at full power.

 Eligible generators can take a 2.2¢/kWh or $22/MWh[yyy]

 production tax credit (PTC) on

electricity sold. This means that some generators may be willing to sell their output for as

low as -$22/MWh to continue producing power. Typically, wind generators are the largest

such group in any region.

 There are maintenance and fuel-cost penalties when operators shut down and start up

large steam turbine (usually fossil-fueled) plants as demand varies over a day or a week.

These costs may be avoided if the generator sells at a loss to attract a buyer when

demand is low.392

As EIA notes, the PTC can create an incentive for wind generators to bid at negative prices. If other 

generators located at nodes in the areas affected by negative prices are unable or unwilling to reduce 

output, they will have to pay the negative price for their output. That scenario has unfolded on some 

buses in PJM, as outlined in comments to DOE from PJM staff: 

Tax and subsidy policies have had an impact on the economics of certain types of 

generation. The Renewable Energy Production Tax Credit and renewable energy mandates 

have had the most significant impact on nuclear generation. Specifically, the nuclear and 

wind generation are competing to clear in the market during off-peak hours when wind 

resources are the strongest and load is reduced. In those off-peak hours, the production tax 

credit has created an incentive for renewable resources to bid negative prices as they must 

run in order to receive their payment from the federal treasury. Since 2014, PJM has seen 

prices go negative at nuclear unit buses in approximately 2,176 hours—representing 14 

percent of off-peak hours.393 [footnotes omitted from original text]

yyy While the PTC value was $23/MWh in 2016, this figure was based upon EIA’s interpretation of the PTC benefit at the time. 

https://www.eia.gov/todayinenergy/detail.php?id=8870
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ERCOT’s market monitor identified 130 negative-priced hours for the entire system in 2016, an increase 

from 50 hours in 2015.394 Negative prices in ERCOT are now on the rise due to subsidized wind, as noted 

by William Hogan and Susan Pope in a recent study filed with the PUC of Texas by Calpine and NRG: 

Prior to the increase in wind and other intermittent capacity in the ISOs, negative prices 

sometimes occurred in the middle of the night, as load dropped and generators needed for 

operation the following day were pinned at their minimum loads. In contrast, the increasing 

incidence of negative prices in ERCOT is caused by the incentive of the owners of wind 

generation capacity receiving the PTC to continue to produce even when the locational price 

is negative.395

In addition to the PTC, VRE may also be incentivized to submit negative bids into markets by demand for 

RECs (to satisfy state environmental mandates and/or corporate sustainability goals). 

Conventional generators also face economic factors that lead them to submit negative bids. Existing 

nuclear plants in the United States, as well as some fossil units, may bid in during these periods to avoid 

costly start-ups and shutdowns.396 For example, steam turbine plants may choose not to cut back their 

production if they are not designed to cycle economically. 

Operational attributes can also create or exacerbate negative prices. For example, hydroelectric plants 

are limited in their ability to curtail output because of environmental and safety reasons. Flood control 

and wildlife regulations are two important reasons this can take place. As this winter’s record 

precipitation gave way to snowmelt this spring, CAISO found itself with an abundance of un-curtailed 

hydroelectricity that competed with solar generation.397 A similar dynamic played out in 2011 following 

significant precipitation in the Pacific Northwest, as shown in Figure 5.8.

zzz

zzz In Figure 5.8, Off-peak is 10 p.m. to 6 a.m. on Monday through Saturday and all hours on Sunday. Mid C is Mid-Columbia, 

COB is California-Oregon Border, and NOB is Nevada-Oregon Border. 
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Figure 5.8. Negative Northwest Off-Peak Daily Spot Prices ($/MWh) in 2011398

5.3.3 State Actions Impacting Wholesale Markets

There is growing concern about the impact of state government intervention in wholesale markets, such 

as the creation of ZEC programs to keep nuclear plants in operation, as well as RPS and other state 

policy requirements. This concern was reflected in comments at the May 1–2, 2017 FERC Technical 

Conference on state policies in the three eastern wholesale markets:aaaa

[Roy Shanker, independent consultant]: It is difficult to identify any element in the wholesale 

electric market (energy, capacity, ancillary services and transmission) that is not being 

directly and materially impacted by discriminatory mandates driven by state policy actions. 

Price taking energy and capacity offers linked to these mandates directly impact price 

formation. The intermittent nature of virtually all RPS resources requires material 

modification of dispatch and significant increases in flexible resources and associated 

ancillary services.399

[William Hogan, Harvard University]: The increasing impact of Federal and state policies to 

support particular technologies, raises questions about the viability of wholesale power 

markets.400

[Susan Tierney, Analysis Group]: These state policies can and often do affect the price of 

electricity in wholesale power markets, and the entry, exit and cost of operations of electric 

generating resources...there is no reason to expect that state decision makers will make 

 

aaaa The full transcript of (and all written statements from) this technical conference is available on FERC’s website. FERC 

Technical Conference, “Docket No. AD17-11-000”, May 1-2, 2017.
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determinations that singularly focus on economic efficiency and the continued viability of 

wholesale capacity-market designs ahead of other all objectives... Already, we see that in a 

market that depends upon the flow of private capital and diversity in the asset mix, some 

suppliers of capacity resources (including demand-response and nuclear generation) have 

recently decided that the markets are not producing financial outcomes consistent with the 

requirements of private capital markets... I remain concerned that the current centralized 

wholesale capacity markets in PJM, NYISO and ISO-NE will not be sustainable, from an 

economic, financial and political point of view and in light of states’ policies and 

preferences.401

[Cliff Hamel, Navigant Consulting]: [P]roblems in the current centralized [capacity] market 

approach are fundamental.402

[Samuel Newell, The Brattle Group]: The centralized wholesale markets do not, however, 

and should not be expected to meet goals they were not designed to meet. Many states now 

have far-reaching carbon and clean energy goals. Yet today’s centralized energy, ancillary 

services, and capacity markets are mostly not designed to differentiate generation resources 

based on their unpriced carbon emissions or other unpriced attributes.403

 

[Lawrence Makovich, IHS Markit]: In summary, out-of-market interventions cause predictable 

distortions and consequences, including: 

1. Reduced market-based cash flows for non-peaking generating resources, causing

lower investment in electric generating production efficiency. 

2. Uneconomic displacement of lower cost energy production causing a shift toward

a less cost-effective fuel and technology mix and resulting in higher overall average 

electricity supply costs. 

3. Less supply diversity causing more generation production cost and availability risk.

4. Premature retirements of low CO2 emitting resources, causing replacement with

higher CO2 emitting resources that subvert market intervention policy goals.404

While this panel of economists commented on these effects on the wholesale markets resulting from 

state policies, members of a panel of state officials at the same FERC Technical Conference clearly said 

their states will continue to pursue their policies: 

[Jeffrey Bentz, New England States Committee on Electricity]: States aren't interested in 

having markets just for the sake of having markets...405

[Angela O’Connor, Department of Public Utilities of Massachusetts] [...] what the legislature 

requires us to do we have to do...406

[Sarah Hofman, Vermont Public Service Board]: [...] we cannot tell what our legislators [what 

to] do. And so they are going to have policies and it doesn't matter what anybody here or any 

place else says, they will have policies that set the stage for what the state wants and that's 

what legislators are for.[...] there is no question that state lawmakers will continue passing 

legislation that sets public policy. It is now our challenge to continue to work together to find 

effective ways to carry out those policies while also continuing to benefit from competitive 

wholesale markets.407

Tony Clark recently expressed similar views on the original policy assumptions behind the creation of 

centrally-organized wholesale markets: 

Affordable power was the goal. The current markets are still procuring affordable power but 

many state public policy makers no longer see that as the only goal. It is little wonder we 

hear some decry that the markets are not delivering what people want. It is because they 

were never designed for job creation, tax preservation, politically popular generation, or 
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anything other than reliable, affordable electricity. To the degree policy makers and elected 

officials have moved the goal posts, it is time to consider rational pathways forward.408

5.4 Wholesale Electricity Markets Looking Forward

Changes in the centrally-organized markets must catch up to the broad technology-driven and policydriven electricity market dynamics identified in the April 14 memo. Overall, centrally-organized

wholesale electricity markets are effective at driving energy prices toward suppliers’ short-run marginal 

costs. However, the revenue insufficiency problem has become more pronounced in recent years. 

Generator profitability could become a public policy concern if so much generation is financially 

challenged that the reliability or resilience of the BPS become threatened. New market structures may 

be necessary to reflect these market dynamics, particularly in an industry in which suppliers with high 

fixed capital costs and relatively low marginal costs often struggle to recover their long-run average 

costs. 

In addition, while markets as currently designed do not explicitly recognize or compensate system 

resilience, RTO/ISOs are considering ways to better support system resilience objectives in the same way 

that they explicitly recognized and administratively incorporated reliability standards into dispatch 

practices in the past. For example, the variety of problems that arose during the Polar Vortex (as 

discussed in Section 4) caused PJM and ISO-NE to change their capacity market rules to ensure 

generator performance during scarcity conditions.409 410

In summary, the debates surrounding wholesale markets are complex and multifaceted, but the 

institutions and the grid itself have historically proven flexible, strong, and able to adapt. Questions 

about revenue sufficiency and resilience must be addressed quickly, before the fast-moving evolution of 

our power system outpaces our ability to understand and manage it responsibly.
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6 Affordability 

The April 14 memo asked whether the loss of coal, natural gas, nuclear, and hydroelectric baseload 

power is making the grid less affordable. There is no widely accepted metric for an “affordable” grid or 

an “affordable” electricity bill. DOE’s GMI defines affordability as “maintain[ing] reasonable costs to 

customers.”411 Typically, the meaning of “affordable” is contextual, i.e. dependent on the size of a 

consumer’s household budget. This indicator of energy affordability can be represented as energy 

burden, which is a household’s annual spending on energy as a percentage of its gross annual income.

412

413

Because electricity is an important energy service, it can be broken out as “electricity burden.”bbbb In 

2011, the median electricity burden for all households was four percent, but it averaged 8.3 percent for 

low-income households and 2.9 percent for non-low-income households.414 415 416 For low-income 

families, more spending on energy bills translates into less spending on other expenses, such as food, 

health care, and education.417 The limited increases in electricity rates suggest that electricity bills have 

not become less affordable for most customers. However, changes in cost allocation and rate designs 

could have disparate effects on bills for different groups of customers. 

For example, utilities raising fixed charges to counterbalance decreases in revenues from energy 

efficiency gains could disproportionately impact low-consumption customers, for whom fixed charges 

comprise a larger portion of the bill. Customers on fixed incomes and those who rely on electricityintensive medical devices may have an acute need to maintain affordability.418Most states and utilities 

offer programs like concessionary rates for these customers, and ensuring affordability options for 

vulnerable customers remains a priority as electricity stakeholders explore market, regulatory, and rate 

reforms to accommodate an evolving grid. 

Low electricity prices can also boost businesses’ competitiveness and bring new economic activity to an 

area, as evidenced by companies locating electricity-intensive industrial facilities, such as server farms, 

to regions with low, stable electricity prices.419 420 421 422 Today, many businesses are more actively 

managing their energy costs by investing heavily in energy efficiency, energy management systems, 

solar PV installations, and direct PPAs with VRE providers.423 Industrial electricity prices are typically 

close to wholesale prices because providing electricity to high-voltage, high-use industrial customers is 

less expensive and more efficient than serving distribution-level customers.424 Thus, low wholesale 

electricity prices can allow businesses and industrial customers to thrive, support job growth, and drive 

economic development.425

 

6.1 Affordability of Generation Portfolios 

The affordability of a given generation portfolio is largely shaped by region- and state- specific market 

structures. Merchant investment decisions (where applicable) and regional resource availability (for 

example, NGCC has a lower levelized cost of electricity (LCOE, the per-MWh cost of building and 

operating assets over their lifetime) in the Gulf States where gas is abundant than it has in the North 

bbbb However, this is complicated by the fact that electricity usage varies significantly from region to region, so the electricity 

burden would be much higher in regions that use electricity for heating and cooling, as is common in the West and South. In 

addition to electricity, energy burden includes direct fuel use, such as natural gas or propane for cooking and heating, and can 

vary based on a household’s activities, appliances, and location. 
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Central states) contribute to regional variation in charges to end-users. 426 The Energy Information 

Administration estimated in the Annual Energy Outlook for 2017 that the BPS (generation and 

transmission) comprises roughly two-thirds of the total average price of electricity. Generation costs 

accounted for 57 percent of the average price of electricity in 2016, compared to distribution’s 32 

percent and transmission’s 11 percent.

427

In vertically integrated areas, state PUCs seek to avoid uneconomic outcomes and ensure affordable 

service to customers428 by requiring VIEUs to submit IRPs in which they consider least-cost, long-term 

plans for providing service including, among other things, LCOE.

429 The IRP must also account for any 

additional state-mandated requirements such as energy efficiency resource standards or RPS.

430

Notably, VIEU assets are usually guaranteed the recovery of investment and operational costs regardless 

of whether they would prove to be cost-competitive in a short-run marginal cost market environment.431

432

By contrast, in some of the centrally-organized markets (e.g., most of the states in PJM, ERCOT, all but 

two in ISO-NE, NYISO, and Illinois for MISO), the generation portfolio is determined by the wholesale 

market itself (subject to any generation and demand-side mandates) rather than a state-overseen IRP by 

the VIEU.

cccc Merchant generators make investment decisions by comparing an asset’s expected lifetime 

costs with the expected revenues from any PPAs, financial incentives such as tax credits, and sales in 

wholesale energy and capacity markets. Lifetime costs considered by merchant generators include fixed 

investment costs and operational costs. 

6.2 The Wholesale-Retail Disconnect

Tracing the relationships between wholesale and retail prices is difficult because ratemaking practices 

vary widely from state to state, and there are many other contributing factors involved besides the 

wholesale cost of electricity.433 434 Retail rates include a variety of charges that are not included in the 

bulk electricity charges passed through by RTO/ISOs or VIEUs. These include components of the 

transmission costs not captured in the RTO prices (such as state-regulated transmission investments), 

payments that the distribution utility makes to merchant transmission suppliers, various fixed charges, 

customer service, state and local sales taxes and franchise fees, and public benefits charges.435

Retail electricity bills can also include additional costs to support state policy goals—such as RPS, energy 

efficiency resource standards, or programs to promote use of distributed energy resources, among 

others.

436 Most utilities have undertaken substantial programs to modernize their distribution systems, 

and a significant subset have invested in infrastructure needed to integrate higher levels of distributed 

energy resources.437 Under established cost-of-service ratemaking principles, these costs are typically 

allocated to retail customers and periodically examined by regulators.

The wholesale-retail electricity price disconnect means that, in most areas, the conventional generation 

retirements can affect wholesale rates but have little or no immediately visible impact on retail rates. 

 

cccc Many state, regional, and Federal policies can impact the expected profits for merchant generators, including environmental 

regulations; carbon trading programs; tax credits; and state procurements, mandates, or other mechanisms that take 

generation or demand-side resources out of markets available to merchants and/or subsidize those resources.
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However, despite the difficulty in attributing retail price impacts to wholesale changes, considering the 

trends in both wholesale and retail prices can provide greater understanding of affordability. 

On average, national retail electricity rates have been roughly flat for more than a decade, and rates 

have closely followed the historical average since 1960.dddd 438 Retail rates in nominal dollars have been 

increasing at a low annual rate for approximately two decades, while the real retail price has stayed 

relatively constant over the last decade, as shown in Figure 6.1. From 2011 to 2016, nominal residential 

prices increased at an average of 1.9 percent annually, about the same rate as overall inflation.439 In 

2016, the national average retail electricity price declined for the first time since 2002, with residential 

customers paying a national average of 12.55 cents/kWh. 

Figure 6.1. Average U.S. Residential Sector Retail Electricity Prices over Time440

dddd The use of national averages for this analysis provides a broad picture, but limits insight into regional and state-level 

impacts of BPS changes that may lead to higher-than-average retail rate increases among some customers and utilities. 

National averages mean little to subsets of ratepayers seeing significant retail rate increases or those who have faced 

consistently high bills. Even use of state-level retail averages can mask exceptions that greatly vary from the average. For 

example, California residents who live near the coast enjoy a temperate climate with limited need for cooling or heating. In 

contrast, those living inland see very hot summers that require high use of air conditioning and thus see high electric bills. A 

more thorough analysis would consider affordability and rate increases at a more granular level. 
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Average retail prices vary widely across states and regions, with New England, California and the MidAtlantic paying the highest rates.441 However, a comparison of electricity rates alone can be misleading; 

for instance, California’s average residential electricity rate is over 18 cents/kWh (one of the highest in 

the Nation), but due to low average residential consumption, the average California electricity bill is only 

$95/month, ranking it in the bottom third of the Nation. By comparison, Washington state has the 

lowest average retail rates in the Nation at less than nine cents/kWh (less than half the average rate in 

California), but because of higher consumption, residential customers in that state see average bills of 

$95/month, the same average electricity bill as in California.

442 443

It is not yet clear what impact recent coal, nuclear, and natural gas plant retirements will have on 

customer bills in the future, nor how the continuing trend of retirements will affect the overall cost of 

the BPS, which will ultimately be borne by ratepayers. Natural gas generation has proven to be a strong 

competitor with coal and nuclear power because natural gas prices have fallen over the past decade. 

Wind and solar generation have also increased, and while their capital costs are much higher than those 

of natural gas (particularly if normalized by capacity factor), their marginal cost is nearly zero.444 Changes 

in the BPS since 2002—lower demand, lower natural gas prices, and growth in VRE—have reduced 

wholesale electricity prices, as shown in Figure 6.2.

445

Figure 6.2. Average Wholesale Electric Costs/MWh Have Fallen between 2002 and 2016446

From 2002–2016, wholesale electricity prices have increasingly tracked natural gas prices, and as natural 

gas generation has increased over time, the differences in price between regions have also decreased 

(e.g., prices in NYISO and PJM are much closer in 2016 than in 2004). 

Figure 6.3 illustrates wholesale prices at electricity trading hubs, emphasizing 2016 prices on a regional 

basis as derived by FERC staff.eeee FERC notes in its 2016 State of the Markets report that prices were 

down in 2016 from 2015, and that prices in PJM were the lowest they have been since the RTO formed 

in 1999.447

 

eeee Derived by FERC staff from S&P Global Intelligence data. Prices are a simple average of day-ahead, on-peak physical prices.
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Figure 6.3. Day-Ahead, On-Peak Wholesale Electric Prices Reach Near-Record Lows in 2016448

FERC’s most recent State of the Markets report shows that all areas of the United States are 

experiencing low wholesale electricity prices. In 2016, prices were highest in the Northeast, Mid-Atlantic, 

and Midwest and were lowest in the Northwest. Historically, wholesale prices would show much more 

regional variation. The dollar values are average 2016 day-ahead on peak prices; the percentages 

indicate the change from 2015 to 2016. 

While wholesale electricity prices have tracked natural gas price trends, the impacts of other generation 

trends on affordability are less obvious.449 Because coal, hydro, and nuclear plants have historically had 

relatively stable and predictable fuel costs, these power plants have provided a valuable hedge against 

the price volatility of natural gas and oil. Today, nuclear, hydro, and VRE all serve as hedges against 

generation whose fuel cost is more volatile and represents a larger portion of the total delivered price 

(i.e. natural gas and oil). For example, the variable operating, maintenance, and fuel costs of 

hydroelectric and nuclear average just $5/MWh and $12/MWh, respectively, compared to $41/MWh for 

NGCC and $34/MWh for coal.450 Increasingly, VRE also performs a price stabilizing role—wind, solar PV, 

hydropower, and geothermal generation offer near zero-marginal-cost electricity. To the degree that 

VRE and nuclear can stabilize the short run cost of bulk power, those resources could also improve the 

month-to-month manageability of customer bills. 

Among the nine regions examined in this study, the CAISO+, Midwest, ERCOT, and Central regions have 

the most non-hydro VRE generation today. RPS compliance costs were found to total $2.6 billion in 
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2014, averaging $12/MWh for VRE and equating to 1.3 percent of average retail electricity bills.ffff 451 The 

actual effects of zero-marginal cost electricity on consumers’ bills is situational, and growth in VRE can 

drive additional costs, including transmission and integration costs.

452 453 Because many utility-scale VRE 

plants are built in locations distant from load centers, they sometimes require major transmission 

additions to connect the remote generation to the rest of the grid and to load centers. Over the past five 

years, a portion of the 24,000 miles of new transmission built (about twice the number of miles added 

from 2006–2010) and $102 billion invested to strengthen the grid and interconnect new generation has 

been made to interconnect VRE.

454 455 Transmission investments (regulated or merchant) can increase 

bulk power costs and therefore increase customers’ retail bills to the extent that they are not offset by 

savings attributable to access to lower-cost generation or reduced congestion costs. 

Higher levels of VRE penetration also require system integration services, such as additional ERS. It is 

unclear how the costs of these integration requirements will affect wholesale electricity costs as VRE 

penetrations continue to increase. In addition, as the PTC for wind generation expires and the ITC for 

residential solar PV installations reduces in the coming years, their costs relative to other resources will 

rise. However, declining wind and solar capital costs and higher productivity will likely somewhat offset 

these losses, albeit to an unknown degree.456 457 458 459

Finally, several states have created subsidies to favor or retain nuclear generation. If such subsidies are 

being funded by taxpayer dollars – like the PTC and ITC – rather than a charge to electricity customers, 

this will affect wholesale costs in some way, but will probably have little discernable effect on the 

customers’ retail electricity bills. However, if subsidies for power plant retention are funded as a direct 

charge to retail electricity customers, electricity bills could rise and affordability could decrease. 

Overall, ISOs and RTOs face many challenges that ultimately affect the allocation of transmission and 

integration costs when they make decisions on how to spread those costs among cost-causers, reliability 

and other service providers, and consumers, as well as decisions on how to keep cost allocation 

practices up to date as the generation mix, transmission capacity, and load evolves over time.460 461 462 463

6.3 Affordability Looking Forward

There appears to be little near-term risk that natural gas prices will rise significantly and thereby reduce 

electricity affordability. However, natural gas is an extractive commodity traded internationally—prices 

are affected by policies impacting how the resource is produced, and prices show periodic regional, 

seasonal, or local price spikes, and even sustained price increases. It is reasonable to expect continuing 

regional differentials between natural gas delivered costs, reflecting differences in proximity to natural 

gas production fields, production costs, and deliverability (including the effects of pipeline or liquefied 

natural gas deliverability constraints). If natural gas prices rise, wholesale electricity costs are likely to 

rise in regions where natural gas remains the marginal fuel in a significant number of hours. This would 

be true for both RTO/ISO and non-RTO/ISO regions. It is unclear how rising natural gas prices and 

 

ffff Studies on RPS compliance costs do not fully capture the “all-in” costs that the ratepayer (and taxpayers) ultimately bear. 

These other costs are harder to measure, but may not be insignificant. They may be harder to quantify for many reasons, such 

as having multiple drivers behind those investments and various distribution-level grid modernization investments (e.g., smart 

meters and others that are touted to aid VRE integration). New transmission (other than the direct transmission 

interconnection charged to the renewable generation project and thus reflected in their PPA), as well as effects of VRE 

variability on the dispatchable fleet, are other examples of costs often not included in grid integration cost studies. Costs of 

various tax and other subsidies are also not counted.
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additional VRE generation would affect the large-scale displacement of coal and nuclear generation, and 

ultimately, electricity affordability for affected consumers. 

The variety of generation portfolios operating throughout the U.S. lends itself to further study. To date, 

limited work has focused on the affordability of the BPS as a system or portfolio—relatively more 

attention has focused on retail electricity prices464 or the stand-alone cost of generation technologies 

(such as LCOE). Some research has focused on analysis of system-wide LCOE,465 but more can be done. 

Looking forward, another potential challenge to affordability is determining how the proliferation of 

distributed PV across much of the Nation is changing the cost structure for non-participating customers. 

A growing body of research considers whether and how distributed PV users continue to benefit from 

their grid connection for balancing services and energy storage, as well as how to reallocate utility 

energy, capital, and system costs and rates fairly among all users. Concerns about more customers 

installing distributed PV under net metering tariffs,gggg which potentially shifts costs and increases the 

burden on non-distributed PV customers, have caused multiple states to re-open their net metering 

tariff processes and, in some cases, implement new policies. However, some studies have quantified the 

retail rate impacts of net metering to all residential customers (i.e., participants and non-participants) 

and found that current and projected levels of net metering have very little impact, especially compared 

to broader drivers of retail rate increases in the electric industry.466

 

gggg According to the EIA, “net metering tariffs enable customers to use the electricity they generate in excess of their 

consumption at certain times to offset their use of electricity from the grid at other times. These tariffs are designed to 

encourage distributed renewable generation. These arrangements describe how an electric utility customer who installs a 

qualifying generator (typically a rooftop solar array, less often a small wind turbine, or a small combined heat-and-power 

system) will be compensated by their utility for the electricity they generate in excess of their consumption.” 

https://www.eia.gov/todayinenergy/detail.php?id=6190
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7 Policy Recommendations

The April 14 memo asked staff to “not only analyze problems but also provide concrete policy 

recommendations and solutions.” To that end, DOE staff prepared a list of recommendations below. 

Some actions fit squarely within DOE’s authority, while others might fall to other government agencies 

or private organizations. 

Wholesale markets: FERC should expedite its efforts with states, RTO/ISOs, and other stakeholders to 

improve energy price formation in centrally-organized wholesale electricity markets. After several years 

of fact finding and technical conferences, the record now supports energy price formation reform, such 

as the proposals laid out by PJM467 and others.

468 Further, negative offers should be mitigated to the 

broadest extent possible.

Valuation of Essential Reliability Services (ERS): Where feasible and within its statutory authority, FERC 

should study and make recommendations regarding efforts to require valuation of new and existing ERS

by creating fuel-neutral markets and/or regulatory mechanisms that compensate grid participants for 

services that are necessary to support reliable grid operations. Pricing mechanisms or regulations should 

be fuel and technology neutral and centered on the reliability services provided. DOE should provide 

technical and policy support that strengthen and accelerate these efforts. 

Bulk Power System (BPS) resilience: DOE should support utility, grid operator, and consumer efforts to 

enhance system resilience. Transmission planning entities should conduct periodic disasterpreparedness exercises involving electric utilities, regional offices of Federal agencies, and state 

agencies. NERC should consider adding resilience components to its mission statement and develop a 

program to work with its member utilities to broaden their use of emerging ways to better incorporate 

resilience. RTOs and ISOs should further define criteria for resilience, identify how to include resilience 

in business practices, and examine resilience-related impacts of their resource mix.

Promote Research and Development (R&D) of next-generation/21st century grid reliability and 

resilience tools: DOE should focus R&D efforts to enhance utility, grid operator, and consumer efforts to 

enhance system reliability and resilience. DOE R&D opportunities include the following activities: 

 Develop grid technical tools to facilitate new-generation technologies’ operations to support 

BPS reliability (e.g., by enabling technologies to provide ERS), and maximize use of the DOE 

national laboratories.

 Expand cooperation on grid reliability across North America, including working with NERC to 

further enhance the reliability of our shared BPS through technical engagement with Mexico 

and Canada.

 With the National Science Foundation, sponsor the development of new open-source software 

for the next-generation electric grid research community.

 Focus R&D on improving VRE integration through grid modernization technologies that can 

increase grid operational flexibility and reliability through a variety of innovations in sensors 

and controls, storage technology, grid integration, and advanced power electronics. The Grid 

Modernization Initiative should also consider additional applications of high-performance

computing for grid modeling to advance grid resilience.

Support Federal and regional approaches to electricity workforce development and transition 

assistance: In partnership with other agencies and the private sector, DOE should facilitate programs 
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and regional approaches for electricity sector workforce development. Unemployed workers nearing but 

not yet eligible for retirement may have difficulty retraining after careers built on specialized skills that 

may be in declining demand. Where possible, Federal agencies should leverage existing government, 

nongovernment, labor, and industry workforce consortia. 

Energy dominance: Executive Order 13783 (Promoting Energy Independence and Economic Growth) 

outlined an approach to promote the clean and safe development of energy resources while at the same 

time minimizing regulatory barriers to energy production, economic growth, and job creation. The Order 

called for a rescission of certain energy and climate related policies, rescinded specific reports, and 

ordered the review of key environmental regulations. While DOE is not the main agency tasked in the 

Order, it should continue to prioritize energy dominance and implementing the Executive Order broadly 

and quickly. 

Infrastructure development: DOE and related Federal agencies should accelerate and reduce costs for 

the licensing, relicensing, and permitting of grid infrastructure such as nuclear, hydro, coal, advanced 

generation technologies, and transmission. DOE should review regulatory burdens for siting and 

permitting for generation and gas and electricity transmission infrastructure and should take actions to 

accelerate the process and reduce costs. Specific reforms could include the following:

 Hydropower: Encourage FERC to revisit the current licensing and relicensing process and

minimize regulatory burden, particularly for small projects and pumped storage.

 Nuclear Power: Encourage the NRC to ensure the safety of existing and new nuclear facilities

without unnecessarily adding to the operating costs and economic uncertainty of nuclear

energy. Revisit nuclear safety rules under a risk-based approach.

 Coal Generation: Encourage EPA to allow coal-fired power plants to improve efficiency and

reliability without triggering new regulatory approvals and associated costs. In a regulatory

environment that would allow for improvement of the existing fleet, DOE should pursue a

targeted R&D portfolio aiming at increasing efficiency.

Electric-gas coordination: Utilities, states, FERC, and DOE should support increased coordination 

between the electric and natural gas industries to address potential reliability and resilience concerns 

associated with organizational and infrastructure differences. DOE and FERC should support wellfunctioning commodity markets for natural gas by expeditiously processing liquefied natural gas export 

and cross-border natural gas pipeline applications.
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8 Areas for Further Research 

DOE staff identified several research topics that are relevant to the April 14 memo and merit further indepth analysis. Some topics may be appropriate for offices within the Department, national 

laboratories, academia, other government agencies, or private organizations. 

Market structure and pricing 

 Study mechanisms for enabling equitable, value-based remuneration for desired grid

attributes—such as ERS, fuel availability, high resilience, low emissions, flexibility, etc.—with

alternative market and non-market structures. This research could assess potentially underrecognized contributions from baseload power plants, using fuel-neutral metrics and values

relevant to analyze all resource options.

 Evaluate ongoing capacity market reforms. Several of the Nation’s electricity markets use

mandatory capacity markets to procure capacity for future years and ensure resource adequacy.

The design of these constructs has been the subject of near-constant debate within the

RTO/ISOs and before FERC. After undergoing substantial changes from 2014–2015, capacity

markets have come under new scrutiny in light of recent actions by restructured states to

preserve or promote certain resources or resource types and to further state policy goals.

 Explore market operations in a higher VRE/low marginal cost system, and examine recent

changes in energy price trends—including the drivers of wholesale electricity prices in the

context of limited load growth—quantifying the relative contributions of fossil fuel prices. With

significant amounts of near-zero marginal cost generation available, security-constrained

economic dispatch of BPS based on marginal costs may not sufficiently compensate resources

for all fixed and variable costs. Academic and other research should be expanded in this area, to

include capacity market reforms and the role of capacity markets in a higher VRE/low marginal

cost system.

Reliability and resilience 

 Develop policy metrics and tools for evaluating BPS-wide provision of resilience and considering

all aspects of the electricity system that contribute to resilience, including regional generation

characteristics, imports and exports, fuel supply and storage, transmission capability, DR,

electricity storage, inertia, and other factors that determine the ability of grid operators to

provide reliable electricity supplies.

 As PJM notes, “criteria for resilience are not explicitly defined or quantified today.”469 Each

RTO/ISO should strive to explicitly define resilience on its system and conduct resource diversity

assessments to more fully understand the resilience of different resource portfolios. Federal,

state, and local work to define and support system-wide resilience is also needed.

 EIA and NERC should examine ways to improve power generator fuel delivery data collection;

additional data on fuel deliveries and potential disruptions would further improve forecasting

necessary for electric reliability planning.
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Cost and affordability 

 Estimate the bulk power system-wide costs of different generation mixes, also considering the

sensitivity of system costs to various fuel price fluctuations. Further, examine the relationship

between wholesale and retail electricity rates to understand the present disconnect.

 On a regular basis, update the EIA analysis of subsidies and support for electricity production

(most recently updated using FY 2013 data).470

Regulatory 

 Explore the potential for utilizing existing Federal authorities under the Federal Power Act and

the DOE Organization Act, among others, to ensure system reliability and resilience.

 Explore costs and benefits of states applying cost-of-service regulation to specific at-risk plants

that contribute to grid resilience. In centrally-organized wholesale markets, these resources may

sometimes be unable to recoup all costs of generating electricity—especially capital investments

that are needed to ensure long-term viability.
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Appendix A: National and Regional 

Profiles 
operational capacity)

Staff Report on Electricity Markets and Reliability U.S. Department of Energy

U.S. National Profile

Retirements, 2002-2017

Notes: 

Capacity values are summer capacity. 

Data for utility-scale resources only (1+ 

MW nameplate capacity). Natural gas 

technologies: CC = combined cycle, CT = 

combustion turbine, ST = steam turbine. 

Ownership type: VIEU = vertically 

integrated electric utility. Map includes 

2017 Q1 actual and Q2-4 announced 

retirements. Prices: Natural gas = Henry 

Hub, Coal = Central App., Electricity = PJM 

Western Hub.

*Total % Capacity Reduction calculation:

retired capacity / (retired capacity + 2016

operational capacity)

2002-2016

100%0

5

10

15

20

25

30

Retirements

(GW)

20%

40%

60%

80% Capacity Mix

100%$0

$5

$10

$15

$20

0%25$

NG

Coal

Elec.

Prices (real 2009$)

$25 $250

$20 $200

$15 $150

$10 $100

$5 $50

coal/gas

$/MMBtu

electricity

$/MWh

100%

20%

40%

60%

80% Generation Mix

0%

20%

40%

60%

80%

2002 2009 2016

Capacity Factors

Coal

Natural Gas (CC)

Natural Gas (CT)

Natural Gas (ST)

Nuclear

Hydro

Wind

Oil

Solar

Other

Energy Sources
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U.S. Department of Energy
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Appendix B: VRE Integration 

Studies 

Numerous technical studies on electricity systems in most regions of the Nation have concluded that 

significantly higher levels of VRE can be successfully integrated without compromising resource 

adequacy.hhhh Demonstrating resource adequacy is essential, but achieving the modeled levels of VRE 

penetration requires a full consideration of “all-in” costs, land use, siting, and other environmental 

impacts; sustainable economics for non-wind and solar resources; for some studies, required changes at 

the distribution level; wholesale market design and organizational changes; spending on relevant 

transmission and distribution grid modernization activities; and ensuring all aspects of operational 

reliability.iiii These caveats are non-trivial, as they would be for any substantial major changes in the 

electric power system. 

Table B-1. VRE Integration Studies 471

Region VRE 

Pen.

Author Study 

Year

Study Title

United States 50% NREL 2012 Renewable Electricity Futures Study

Western 

Interconnection

33% NREL 2013 Western Wind and Solar Integration Study: Phase 2

33% GE Energy 2014 Western Wind and Solar Integration Study Phase 3 –

Frequency Response and Transient Stability

33% GE Energy 2015 Western Wind and Solar Integration Study Phase 3A: 

Low Levels of Synchronous Generation

35% E3 and NREL 2015 Western Interconnection Flexibility Assessment

52% NREL 2015 Renewable Electricity Futures: Operational Analysis 

of the Western Interconnection at Very High 

Renewable Penetrations

CAISO 12% CAISO 2010 Integration of Renewable Resources at 20% RPS

50%# GE Energy 2011 California ISO Frequency Response Study

37% E3 2014 Investigating a Higher Renewables Portfolio 

Standard in California

hhhh However, these studies (particularly those examining high VRE levels) may often assume (or ignore) modeled conditions 

that could be difficult and/or costly to achieve in practice, such as a large transmission buildout that may face siting or other 

obstacles, ability of non-wind and solar plants to remain financially viable and thus available, institutional changes, or, for one 

study, synchronization of all three interconnections.

iiii Operational reliability (which includes ensuring a set of ERS are maintained to help the electric system react to sudden 

stability disruptions or unanticipated losses of system components in real-time) is just as important as the resource adequacy 

aspect of BPS reliability. But modeling all needed aspects of operational reliability is very difficult computationally, and so not 

usually examined in its totality in these studies. For example, NREL in its Renewable Electricity Futures Study states, “The study 

did not conduct a full reliability analysis, which would include sub-hourly, stability, and AC power flow analysis.” In fact, page 

xviii of that study qualitatively concludes “Additional challenges to power system planning and operation would arise in a high 

renewable electricity future, including management of low-demand periods.” http://www.nrel.gov/docs/fy12osti/52409-1.pdf 
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45% NREL 2016 Low-Carbon Grid Study

West 35% GE Energy 2010 Western Wind and Solar Integration Study: Phase 1

17% LBNL, ANL, NREL 2013 Integrating Solar PV in Utility System Operations

30% Xcel Energy 2011 Wind Induced Coal Plant Cycling Costs and the 

Implications of Wind Curtailment for Public Service of 

Colorado

18%* Navigant, 

Sandia, PNNL

2011 Large-Scale Solar Integration Study

17% Idaho Power 2014 Solar Integration Study Report

9% Portland General 

Electric

2014 2013 Integrated Resource Plan: Appendix D PGE 

Wind Integration Study Phase 4

47%* PacifiCorp 2017 2017 Integrated Resource Plan

ERCOT 17% GE Energy 2008 Analysis of Wind Generation Impact on ERCOT 

Ancillary Services Requirements

47% Brattle 2013 Exploring Natural Gas and Renewables in ERCOT Part 

II: Future Generation Scenarios for Texas

Eastern 

Interconnection

30% EnerNex 2011 Eastern Wind Integration and Transmission Study

25%# GE Energy 2013 Eastern Frequency Response Study

30% NREL 2016 Eastern Renewable Generation Integration Study

Central 40% EnerNex et al. 2010 Nebraska Statewide Wind Integration Study

40% Charles River 

Associates

2010 SPP WITF Wind Integration Study

60%#SPP 2016 2016 Wind Integration Study

Central and 

Southeast

20% EPRI and LCG 2011 DOE: Integrating Midwest Wind Energy into 

Southeast Electricity Markets

Southeast 7% PNNL 2014 Duke Energy Photovoltaic Integration Study: 

Carolinas Service Areas

Mid-Atlantic 30% GE Energy 2014 PJM Renewable Integration Study

21% Navigant 2016 Virginia Solar Pathways Project: Study 2 - Solar PV 

Generation System Integration Impacts

Midwest 50% GE Energy 2014 Minnesota Renewable Energy Integration and 

Transmission Study

37%* Northern States 

Power

2015 2015 Resource Plan: Appendix E – Renewable Energy

New York 12% NYISO 2010 Growing Wind: Final Report of the NYISO 2010 Wind 

Generation Study

15% NYISO 2016 Solar Impact on Grid Operations-An Initial 

Assessment

New England 24% GE Energy 2010 New England Wind Integration Study
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Hawaii 20% NREL and GE 

Energy

2013 Hawaii Solar Integration Study

Notes: VRE penetration listed as percentage of annual energy (i.e. MWH, not MW), except where 

marked (# indicates instantaneous penetration, * indicates VRE nameplate as percentage of peak load); 

VRE includes only wind and solar. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Appendix C: Power Plant Cycling 

Traditional baseload power plants were designed to operate primarily at constant output levels with 

limited cycling.472 As the electricity system continues to evolve and market conditions change, these 

plants are increasingly following load or being required to more frequently adjust the load and the 

on/off dispatch of their units. The extra costs incurred to do so can affect a plant’s retirement decision. 

Every time a power plant is turned off and on, the boiler, steam lines, turbine, and auxiliary components 

go through unavoidably large thermal and pressure stresses, which cause damage.473 This damage is 

made worse for high-temperature components by the phenomenon called creep-fatigue interaction. 

While cycling-related increases in failure rates may not be noted immediately, critical components will 

eventually start to fail. Shorter component life expectancies will result in higher plant equivalent forced 

outage ratesjjjj and/or higher capital and maintenance costs to replace components at or near the end of 

their service lives.474 In addition, it may result in shortened overall plant life. How soon these 

detrimental effects will occur depends on the amount of creep damage present and the specific types 

and frequency of the cycling. 

Several VRE integration studies, including those performed by NREL and the Western Electricity 

Coordinating Council, have recognized that high penetration of VRE into the wholesale electricity 

markets could increase cycling of conventional power plants.475 Today, coal unit cycling does occur with 

current levels of wind and solar.kkkk 476 477 478 The retirement of many of the older, smaller coal-fired units 

that have provided cycling operation in the past will require more flexibility in the remaining coal fleet 

through improved technologies.479

General Electric has also studied the effects of cycling on power plant maintenance and operations and 

observes the following: 

 Wear-and-tear cycling costs can increase with the changing power portfolio or fuel

prices.

 These costs are generator-specific. They can impact financial viability of generators.

 Incorporating cycling costs into commitment and dispatch decisions can change these

decisions.

 Solar and wind generation resources have different impacts on cycling.

 Operational and/or physical changes to coal/gas plants can increase flexibility. Retrofits

have the potential to increase overall profitability. 480

The cycling issues described above have similar impacts on gas-fired steam and older, combined-cycle 

generators. Some coal and NGCC units can (and have) made capital investments to improve their cycling 

performance to remain competitive.481

jjjj NERC defines equivalent forced outage rates as “the probability that a unit will not meet its demand periods for generating 

requirements because of forced outages or deratings.” 

http://www.nerc.com/pa/RAPA/Pages/SummerVsWinterEFORdRates.aspx 

kkkk “Existing thermal generation plants are being forced to cycle more with the addition of intermittent wind generation and 

low variable cost base-load generation.” http://www.energy-tech.com/ram/article_65131bb2-42d0-11e6-8c80-

e729cc172758.html 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

Existing U.S. nuclear power plants were designed with a similar goal of operations at a set generation 

output, and—with few exceptions—they were not designed with flexible operation modes. Fuel is 

loaded in 18-month or 24-month cycles, thus keeping the marginal cost of operation low. The U.S. 

Nuclear Regulatory Commission prohibits nuclear power plant control systems from interfacing or being 

automatically controlled from grid network control systems,482 so what limited load following is allowed 

must be scheduled from one to three days in advance and is in small increments of power output.483 

Nuclear units receive no benefit to load following or ramping, as they do not save on fuel costs. Like 

fossil plants, ramping a nuclear plant will also result in more wear and tear due to thermal gradients and 

mechanical stresses and will likely increase capital expenditures. Less restrictive, but still carefully 

controlled, nuclear load following is permitted and utilized in other countries, such as France, for which 

nuclear has a higher percentage of electricity output on the system.

A review of the literature about coal plant cycling by Argonne National Laboratory484 reports that coal 

plant heat rates increase with plant age, while plant availability decreases. Cycling and load following 

exacerbate the effects of plant aging and reduce component life.485 These operational patterns impose 

higher costs (including maintenance and fuel costs), as well as lower capacity factors (Figure 8.1).

llll

Figure 8.1. Average Three-Year Capacity Factors for Retired U.S. Coal Plants486

Plants that have retired since 2010 tended to have lower average capacity factors.

 

llll A lower capacity factor means fixed costs are spread over fewer operating hours (i.e. megawatt-hours), which in turn means 

higher unit costs ($/megawatt-hour).
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Endnotes 

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Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review (Washington, DC: 

DOE, January 2017), https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

2

 Ellen Flynn Giles and Kathy L. Brown, eds., 2015 UDI Directory of Electric Power Producers and Distributors: 123rd Edition of 

the Electrical World Directory (New York, NY: Platts, 2014), vi–vii, 

https://www.platts.com/im.platts.content/downloads/udi/eppd/eppddir.pdf, quoted in Department of Energy (DOE), 

Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review (Washington, DC: 

DOE, January 2017), https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

3

Julia Pyper, “The US Solar Market Is Now 1 Million Installations Strong,” Greentech Media, April 21, 2016, 

https://www.greentechmedia.com/articles/read/The-U.S.-Solar-Market-Now-One-Million-Installations-Strong, quoted in 

Department of Energy (DOE), Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial 

Energy Review (Washington, DC: DOE, January 2017), 

https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

4 “Electric Substations,” Platts, generated March 6, 2009,

http://www.platts.com/IM.Platts.Content/ProductsServices/Products/gismetadata/substatn.pdf quoted Department of 

Energy (DOE), Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review

(Washington, DC: DOE, January 2017), 

https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

5

 Ellen Flynn Giles and Kathy L. Brown, eds., 2015 UDI Directory of Electric Power Producers and Distributors: 123rd Edition of 

the Electrical World Directory (New York, NY: Platts, 2014), vi–vii, 

https://www.platts.com/im.platts.content/downloads/udi/eppd/eppddir.pdf, quoted in Department of Energy (DOE), 

Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review (Washington, DC: 

DOE, January 2017), https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

6

 Ellen Flynn Giles and Kathy L. Brown, eds., 2015 UDI Directory of Electric Power Producers and Distributors: 123rd Edition of 

the Electrical World Directory (New York, NY: Platts, 2014), vi, 

https://www.platts.com/im.platts.content/downloads/udi/eppd/eppddir.pdf, quoted in Department of Energy (DOE), 

Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review (Washington, DC: 

DOE, January 2017), https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

7 “Electric Power Sales, Revenue, and Energy Efficiency Form EIA-861 Detailed Data Files,” Energy Information Administration, 

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Transforming the Nation’s Electricity System: The Second Installment of The Quadrennial Energy Review (Washington, DC: 

DOE, January 2017), https://www.energy.gov/sites/prod/files/2017/02/f34/Quadrennial%20Energy%20Review--

Second%20Installment%20%28Full%20Report%29.pdf. 

8

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10 EIA, Internal Analysis, June 2017. 
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Staff Report on Electricity Markets and Reliability U.S. Department of Energy

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Second%20Installment%20%28Full%20Report%29.pdf. 

60 Michael Mobilia, “Most U.S. Nuclear Power Plants Were Built between 1970 and 1990,” Today in Energy, Energy Information 

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61 “Form EIA-860m: Preliminary Monthly Electric Generator Inventory,” Energy Information Administration, March 2017, 

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62 Energy Information Administration (EIA), "Monthly Update to Annual Electric Generator Report," March 2017, 

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65 Nuclear Energy Institute, Nuclear Energy’s Economic Benefits—Current and Future (Washington, DC: Nuclear Energy Institute, 

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175 Ryan Wiser, Andrew Mills, et al., Impacts of Variable Renewable Energy on Bulk Power System Assets, Pricing and Costs, June 

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180 The Solar Foundation (TSF), National Solar Jobs Census 2015 (Washington, DC: TSF, January 2016), 

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185 Federal Reserve Bank of St. Louis, “Real Gross Domestic Product, Billions of Chained 2009 Dollars, Annual, Seasonally 

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