UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Carbon Pollution Emission Guidelines 

for Existing Stationary Sources: 

Electric Utility Generating Units 

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Docket No. EPA–HQ–OAR–2013–0602

Via email and regulations.gov

December 1, 2014

Comments of Sierra Club and Earthjustice

Joanne Spalding

Alejandra Núñez

Andres Restrepo

Casey Roberts

Elena Saxonhouse

Greg Wannier

Nathan Matthews

Violet Lehrer

Natalie Spiegel

Sierra Club 

85 Second St., 2nd Fl.

San Francisco, CA 94105

joanne.spalding@sierraclub.org

Tim Ballo

David Baron

Abigail Dillen

Earthjustice

1625 Massachusetts Ave., NW

Suite 702

Washington, DC 20036

tballo@earthjustice.org
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TABLE OF CONTENTS

EXECUTIVE SUMMARY ............................................................................................................... ES-1

I. Introduction ............................................................................................................................ 1

A. Emissions of CO2 and Traditional Air Pollutants from Fossil Fuel-Fired EGUs Threaten the 

Public Health and Welfare. ..................................................................................................... 1

1. Harms Associated with Climate Change and Ocean Acidification.................................. 1

2. Climate Stabilization Requires Immediate, Deep Reductions in Emissions from the EGU 

Sector. ................................................................................................................................. 5

3. Reducing Climate Pollution Will Also Reduce Conventional Pollution from Fossil FuelFired Power Plants.............................................................................................................. 6

B. A Stringent Clean Power Plan Is Essential to Meet U.S. International Commitments. ...... 7

C. The Clean Power Plan Reinforces Ongoing Changes in the Utility Sector........................ 12

II. The Clean Air Requires EPA To Regulate CO2 Emissions from Fossil-Fuel Fired Power Plants 

Under Section 111(d)................................................................................................................ 15

A. EPA’s Reasonable Interpretation of Section 111(d) Merits Judicial Deference ............... 15

B. The Industry Interpretation of Section 111(d) Is Textually and Logically Flawed, and Must 

Be Rejected. ...................................................................................................................... 16

C. EPA’s Interpretation of Section 111(d) is Proper In Any Event ........................................ 19

III. EPA’s Determination of the BSER is Technically Feasible and Legally Justified.................... 22

A. Statutory Background: Section 111(d) of the Clean Air Act ............................................. 22

B. EPA Determines the “Best System of Emission Reduction” Under Section 111. ............. 23

1. EPA has Authority to Determine the BSER Based on Consideration of the Statutory 

Factors............................................................................................................................... 24

C. EPA Has Proposed Two BSER Determinations under the Clean Power Plan.................... 26

D. The BSER Can Comprise Building Block 1 Plus Reduced Utilization at Levels Commensurate 

with Building Blocks 2, 3, and 4. ........................................................................................... 27

1. EPA’s Interpretation that the BSER Can Include Reduced Utilization of Affected Sources 

is a Permissible Construction of the Clean Air Act............................................................ 28

2. Section 111 Authorizes EPA to Limit the Quantity of Emissions of Air Pollutants from, 

and Thus to Reduce the Utilization of, Affected Sources. ................................................ 30

E. EPA Must Revise its Proposed BSER Approaches to Include Oil-Fired and Natural Gas-Fired 

Units Under Building Block 1. ............................................................................................... 32

IV. Severability .............................................................................................................................. 34

A. EPA’s Expressed Intent to Make the Building Blocks Severable is Sound. ....................... 34

B. The Clean Power Plan Meets the Requirements for Severability. ................................... 35
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V. The Building Blocks ............................................................................................................... 36

A. Building Block 1................................................................................................................. 36

1. Building Block 1 is Legally and Technically Justified as an Element of BSER. ............... 36

2. As Proposed, Building Block 1 Is Too Conservative and Must Be Strengthened.......... 37

a. EPA's Statistical Analysis of the Performance of Existing Units Demonstrates that 

a Heat Rate Improvement From Better Operation and Maintenance (O&M) of 

Existing Units in Excess of 6 Percent Is “Adequately Demonstrated.” ................. 37

b. The Sierra Club’s 52-Unit Study Independently Confirms that a Heat Rate 

Improvement of Six Percent From Better O&M at Existing Units Is “Adequately 

Demonstrated.” .................................................................................................... 38

c. The Record Adequately Demonstrates That Plant Upgrades Can Reduce Emission 

Rates by an Additional Four Percent. ................................................................... 46

d. EPA Should Employ a Long-Term Baseline for Building Block 1 Rate-Setting and 

Compliance. .......................................................................................................... 50

e. EPA Should Adopt a Far More Robust Compliance and Enforcement Scheme.... 50

f. EPA Should Include Oil and Gas Steam Units in Building Block 1......................... 52

g. EPA Should Determine the Amount of Emission Reductions from Existing NGCCs 

that Should Be Included in Building Block 1. ........................................................ 53

B. Building Block 2................................................................................................................. 57

1. While We Oppose Increased Use of Natural Gas, Building Block 2 Is a Surrogate for CoalPlant Retirements Occurring Over the Long Term. .......................................................... 57

2. EPA Must Improve and Strengthen Building Block 2.................................................... 61

a. When Applying Building Block 2, EPA Should Account for Retirements Occurring 

in the Near Term................................................................................................... 61

b. Under Building Block 2, EPA Should Assume Redispatch of the Highest Emitting 

Units Before Others. ............................................................................................. 63

c. Under Building Block 2, EPA Should Adopt a Regional Redispatch Approach. .... 65

d. EPA Should Incorporate Appropriate NGCC Emission Rates in Its Determination 

of Block 2 Emission Rate Reductions. ................................................................... 68

C. Building Block 3................................................................................................................. 68

1. Building Block 3 is Legally and Technically Justified as an Element of BSER, but EPA Must 

Modify Its Approach to Strengthen It............................................................................... 68

a. Declining Costs of Renewable Energy................................................................... 68

b. Environmental Impacts and Benefits of Renewable Energy ................................ 71

c. Transmission and Integration Requirements of Renewable Technologies.......... 72

d. Renewable Energy Generation is “Adequately Demonstrated”........................... 73
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2. As Proposed, Building Block 3 Is Too Conservative and Must Be Strengthened.......... 76

a. EPA’s Current Proposals for Building Block 3 ....................................................... 78

i. EPA’s Primary Proposal......................................................................................... 78

ii. EPA’s Alternative Approach .................................................................................. 79

iii. Shortcomings with EPA’s Block 3 Approaches...................................................... 79

3. Regional RPS Averages.................................................................................................. 79

4. EPA Fails to Adequately Acknowledge State RE Potential............................................ 80

5. EPA’s Assumption that States Will Begin in 2017 with 2012 Levels of RE Generation Is 

Wrong ............................................................................................................................... 83

a. Comments on EPA’s Alternative Approach .......................................................... 83

b. The Demonstrated Growth Approach .................................................................. 85

i. An Overview of the Proposal ................................................................................ 85

ii. The Demonstrated Growth Approach Achieves Much Greater Renewable Energy 

Development than EPA’s Proposals...................................................................... 87

iii. The Demonstrated Growth Approach is Adequately Demonstrated and 

Economically Reasonable ..................................................................................... 89

6. Comments on EPA’s Specific Issues for Building Block 3.............................................. 93

7. Compliance and Enforcement Considerations Under Block 3...................................... 95

a. Crediting Renewable Energy and Energy Efficiency Towards the Emission Rate. 95

b. The Interstate Nature of Renewable Energy and Energy Efficiency..................... 99

i. Which State or Source Gets Credit for Renewable Energy Generation?.............. 99

8. States and Affected EGUs Should Get Credit for All Renewable Energy Generation 

Regardless of Where Units Are Displaced. ..................................................................... 100

a. EPA Must Clarify How Different Types of Renewable Energy Policies and 

Measures Can Receive Credit for Generation Across State Lines. ..................... 102

9. EPA Should Make Clear What Role RECs Will Play in State Plan Consideration and 

Compliance. .................................................................................................................... 104

a. Double-Counting................................................................................................. 106

10. How Can Multiple States Be Prevented From Taking Credit for the Same MWh of 

Renewable Energy?......................................................................................................... 106

11. Displacement of Fossil Fuel EGUs and Related Double-Counting Issues................. 107

12. Eligible Renewable Energy Compliance Resources.................................................. 108

a. Biomass............................................................................................................... 109

b. Hydropower........................................................................................................ 111

c. Distributed Generation....................................................................................... 112
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i. Policy Mechanisms to Support Distributed Generation..................................... 112

ii. Compliance Demonstration for Customer-Sited Distributed Generation.......... 113

A. Quantifiable and Verifiable ........................................................................................114

B. Non-Duplicative and Permanent................................................................................115

D. Building Block 4............................................................................................................... 116

1. Building Block 4 is Legally and Technically Justified as an Element of BSER. ............. 116

a. Low Costs of Energy Efficiency............................................................................ 116

b. Environmental Impacts and Benefits of Energy Efficiency ................................. 118

c. Energy Requirements of Energy Efficiency......................................................... 118

d. Energy Efficiency is “Adequately Demonstrated.” ............................................. 119

2. EPA’s Building Block 4 Reflects a Level of Energy Efficiency Savings that Can Be CostEffectively Achieved in All States.................................................................................... 122

a. EPA’s Best Practice Level of Performance is Achievable and Sustainable in All 

States................................................................................................................... 122

b. State EE Targets Should Be Based on All Sales in the State, Including Imported 

Electricity............................................................................................................. 124

c. EPA Should Readjust its Goal-Setting Formula to Reduce Dispatch of Fossil Units 

In Accord with Increased Energy Efficiency........................................................ 128

3. Compliance Considerations for Building Block 4 ........................................................ 128

a. Evaluation, Measurement, and Verification....................................................... 129

b. Non-Duplicative .................................................................................................. 130

c. Permanent .......................................................................................................... 132

d. Enforceability ...................................................................................................... 132

e. Which Types of Efficiency Activities May Count Toward Compliance?.............. 134

VI. State Plan Considerations................................................................................................... 136

A. Plan Approaches ............................................................................................................. 136

1. EPA Should Require State Plans to Make Affected EGUs Fully and Solely Responsible for 

the Emission Reductions Required Under the Rule........................................................ 136

2. Rate-Based Targets vs. Mass-Based Targets............................................................... 137

a. Asymmetry Between Mass-Based and Rate-Based Goals Under 

EPA’s Proposal..................................................................................................... 137

b. The Texas Example.............................................................................................. 140

c. The Need for Actual Generation Data and a True-Up Requirement.................. 142

d. Our Approach Prevents Double Counting of RECs ............................................. 144
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B. Compliance and Enforcement of State Plans ................................................................ 144

1. Corrective Measures Can Significantly Reduce Compliance Problems, but Only if EPA 

Provides More Detailed Minimum Requirements for Such Measures........................... 144

2. Unit-Specific Evaluation Periods Should Be One Year for All Affected EGUs, with States’ 

and EGUs’ Progress Reported to EPA Annually. ............................................................. 147

3. EPA Should Require Direct CEMS Monitoring of CO2 Emissions. ............................... 149

4. Affected Units Should Be Required to Submit Engineering Analyses and Reference 

Method Test Results to Confirm the Effectiveness of Compliance Measures............... 150

5. EPA Should Strengthen the Record Retention Requirements.................................... 151

6. EPA Should Confirm What Actions It Must and Will Take if a State Plan or Portion 

Thereof Is Not Submitted or Cannot Be Approved......................................................... 152

7. Criteria for Approving State Plans/Required Elements of Plans ................................ 152

8. EPA Should Reject the Option of Granting Conditional Approval of State Plans....... 153

9. EPA Must Amend Its Proposed Regulations to Ensure That Emissions Standards Are 

Enforceable by Citizens................................................................................................... 153

VII. Environmental Justice..................................................................................................... 154

A. EPA is Required to Perform an Environmental Justice Analysis of the Clean Power Plan 

Pursuant to Executive Order 12898................................................................................ 156

B. It is “Practicable” to Require States to Conduct an Environmental Justice Analysis as a 

Component of Implementation Plans. ........................................................................... 159

C. Methodological Considerations...................................................................................... 160

1. Sample Environmental Justice Analysis of Coal Plants............................................... 165

2. Data Gathering: Available Tools ................................................................................. 172

a. EJView ................................................................................................................. 172

b. EJSEAT ................................................................................................................. 173

c. CalEnviro Screen 2.0 ........................................................................................... 174

d. EJ Screen ............................................................................................................. 175

D. EPA Must Continue to Ensure Meaningful Involvement of Minorities and Low Income 

Communities in this Rule Making. .................................................................................. 175

E. State Plans Must Ensure Compliance with Title VI of the Civil Rights Act...................... 176

F. EPA Must Clarify that State Plans that Allow Uncontrolled or Poorly Controlled CoPollutant Emissions from Individual Sources Are Not Permissible As 

Section 111(d) Emission Guidelines for Pollutants with Localized Health 

and Environmental Impacts............................................................................................ 179

G.EPA Must Require Absolute Reductions of CO2 and Co-Pollutant Emissions from Coal-Fired 

and Natural-Gas Fired Plants in Environmental Justice Communities. .............................. 180
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H. States Must Integrate Environmental Justice Concerns into the Design of Cap-and-Trade 

Compliance Programs......................................................................................................... 180

1. Cap-and-Trade Programs May Heighten the Risk of Co-Pollutant Hotspots.............. 181

2. Cap-and-Trade Programs May Fail to Properly Distribute Co-Pollutant Benefits...... 182

3. To the Extent that EPA Allows Cap-and-Trade Programs for Compliance, the Agency 

Must Require States to Integrate Environmental Justice Concerns into the Design of 

Those Programs. ............................................................................................................. 182

a. Incorporate Environmental Justice Protections at the Statutory or Regulatory 

Level. ................................................................................................................... 182

b. Perform a Cumulative Effects Assessment as Part of Environmental Impact 

Review................................................................................................................. 184

c. Establish Spatial Restrictions on Trading Taking into Account Cumulative 

Effects.................................................................................................................. 184

d. Finance Co-Pollutant Reductions with Revenues from Allowance Auctions. .... 186

e. Other Considerations in Designing a Cap-and-Trade Program........................... 187

i. States Must Set a Stringent Cap. ........................................................................ 187

ii. States Should Not Distribute Free Allowances. .................................................. 187

iii. Offsets Should not be Permitted for Compliance............................................... 187

iv. States Should Impose Heightened Monitoring and Reporting Requirements on 

Facilities Located Near Environmental Justice Communities............................. 188

VIII. Economic Justice............................................................................................................. 188

A. States Must Craft Plans that Make Expanded Use of Renewable Energy and Energy 

Efficiency, While Prioritizing the Creation of Good Clean Energy Jobs. ......................... 189

B. States Should Require Affected Sources to Put in Place Comprehensive Workers’ 

Transition Policies. .......................................................................................................... 192

C. The Federal Government and the States Should Ensure Funding for Workers and 

Communities that Depend on Fossil Fuel-Fired Power Plants. ...................................... 193

IX. A State Carbon Tax as a Compliance Mechanism............................................................... 196

A. A State Carbon Tax is an Effective Means of Compliance .............................................. 196

1. Carbon Taxes Reduce CO2 Emissions......................................................................... 196

2. The Advantages of a Carbon Tax ................................................................................ 198

a. Economic Advantages......................................................................................... 198

b. Administrative Advantages................................................................................. 198

c. Revenue to Offset Impacts on Low Income Households and Fenceline 

Communities....................................................................................................... 198

3. Modeling Carbon Tax for Compliance is Similar to Other SIP Modeling ................... 200
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B. The Proposed Rule Preamble Allows for a State Carbon Tax as a Means of 

Compliance ..................................................................................................................... 201

C. A Carbon Tax Meets All of the Proposed Regulatory Criteria for a State Plan............... 202

D. Regulatory Language and a Carbon Tax.......................................................................... 204

1. EPA’s Proposed Revisions to Subpart B ...................................................................... 204

2. Suggested Changes to Subpart B ................................................................................ 205

X. The Clean Power Plan’s Impacts on Upstream Emissions from Fossil Fuel Production..... 206

A. The RIA Understates The Amount of Methane Emitted by Natural Gas Production. .... 206

B. Methane Emissions from Gas Systems Reinforce the Importance of Renewable Energy, 

Energy Efficiency, and Regulation of Methane, Whether or Not The Clean Power Plan 

Will Lead to Net Decreases in Methane Emissions. ....................................................... 209

C. The Projected Decreases in Coal Mining Methane Emissions Will Not Occur if Coal 

Exports Substitute for Decreased Electricity Sector Coal Demand. ............................... 210

XI. Reliability............................................................................................................................. 211

A. Identified Reliability Needs and Solutions...................................................................... 211

1. Resource Adequacy..................................................................................................... 212

a. Potential for Renewable Generation Build-out.................................................. 213

b. Potential for Transmission Capacity Improvements........................................... 214

c. Potential for Efficiency Improvements............................................................... 216

d. Flexibilities in the CPP......................................................................................... 218

e. Region-Specific Analyses..................................................................................... 218

i. SPP....................................................................................................................... 218

ii. ERCOT.................................................................................................................. 219

iii. PJM/MISO ........................................................................................................... 220

2. Voltage and Frequency Stability ................................................................................. 221

a. Voltage Services.................................................................................................. 222

b. Frequency Services ............................................................................................. 222

3. Resilience Against Large System Shocks..................................................................... 224

4. Utility-Grade Versus Distributed Renewable Generation .......................................... 226

5. Overall Ability to Incorporate High Levels of Renewable Generation........................ 227

B. Policy Conclusions........................................................................................................... 227

1. Delaying Implementation of the CPP.......................................................................... 228

2. Installing a CPP “Safety Valve”.................................................................................... 228

C. A Consensus Vision for the Future.................................................................................. 230
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XII. Munis and Co-ops........................................................................................................... 230

A. Public Power Utilities and Rural Electric Cooperatives Are Capable of Reducing the 

Carbon Emission Rates of their Affected Units................................................................... 230

1. Characteristics of Municipal Utilities and Electric Cooperatives................................ 231

2. Renewable Energy and Energy Efficiency Measures Taken by Municipal Utilities and 

Cooperatives................................................................................................................... 232

a. Renewable Energy .............................................................................................. 233

i. Renewable Energy Success Stories..................................................................... 234

b. Energy Efficiency ................................................................................................. 237

ii. Energy Efficiency Success Stories........................................................................ 239

B. Summary ......................................................................................................................... 240

XIII. Other Issues .................................................................................................................... 241

A. EPA Should Shorten and Accelerate the Rule’s Compliance Schedule and Should 

Commit Now to An Eight-Year Review ........................................................................... 241

B. Non-BSER Measures and the Symmetry Principle.......................................................... 243

C. New Source Review Issues.............................................................................................. 243

D. EPA Has Correctly Based Its Emission Targets on Net Rather than Gross Generation... 245

E. Social Cost of Carbon ...................................................................................................... 246

1. EPA Has Properly Relied On the Federal Government’s Estimates of the Social Cost of 

Carbon............................................................................................................................. 246

2. The True Social Cost of Carbon Is Likely Much Higher Than The Federal Government’s 

Estimates......................................................................................................................... 247

3. The Federal SCC Values Demonstrate That the Clean Power Plan’s Benefits Far Exceed Its 

Costs................................................................................................................................ 249

Figures

Fig. 1- IPCC Emission Scenarios....................................................................................................... 4

Fig. 2- Cross Unit One Daily Average Emission Rate, 2001-2012.................................................. 40

Fig. 3- Powerton Unit 61 Daily Average Emission Rate, 2001-2012............................................. 43

Fig. 4- Powerton Unit 61 Daily Average Emission Rate vs. Gross Daily Load, 2001-2012 ............ 43

Fig. 5- Joppa Steam Unit Two Daily Average Emission Rate, 2001-2012 ..................................... 44

Fig. 6- Joppa Steam Unit Two Daily Average Emission Rate vs. Gross Daily Load, 2001-2012 .... 44

Fig. 7- Bruce Mansfield Unit Three CO2 Emission Rate v Load 2001-2012................................... 45

Fig. 8- Mill Creek Unit One Daily Average CO2 Emission Rate 2001-2012.................................... 48

Fig. 9- Cayuga Unit One Daily Average CO2 Emission Rate 2001-2012......................................... 48

Fig. 10- Killen Station Unit Two Average Daily Emission Rate ...................................................... 51

Fig. 11- Heat Rates of Coal-Fired EGUs v. Natural Gas-Fired Steam EGUs................................... 53
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Fig. 12 Fore River Unit Twelve Daily Average Emission Rate 2006-2012 ..................................... 54

Fig. 13- EPA’s “600 CAMD Data Set”............................................................................................. 55

Fig. 14- West Phoenix Unit 6A Average Daily Emission Rate........................................................ 56

Fig. 15- Age of U.S. Coal-Fired EGUs as of 2025 ........................................................................... 57

Fig. 16 - Age of U.S. Coal-Fired EGUs as of 2025 vs. Generation in 2012 ..................................... 58

Fig. 17- ISO Divisions Across the United States and Canada ........................................................ 66

Fig. 18- Recent LCOE Trends of Wind and PV Solar...................................................................... 69

Fig. 19- LCOE of Different Electricity Generation Resources........................................................ 70

Fig. 20- Generation-Weighted Average Levelized Wind PPA Prices by PPA 

Execution Date and Region....................................................................................................... 71

Fig. 21- U.S. Annual Installed Grid-Connected PV Capacity by Market, 2001-2010..................... 74

Fig. 22- Nationwide Renewable Percentages Under BAU, EPA’s Primary Approach, 

and the Demonstrated Growth Approach................................................................................ 87

Fig. 23- Regional Comparison of Renewable Energy Targets in 2030 .......................................... 87

Fig. 24- Cost Comparison for Rooftop Solar Installations- U.S. vs. Germany ............................... 92

Fig. 25- Backup Costs and the Dispersion of Solar Facilities......................................................... 92

Fig. 26- U.S. Energy Demand, Energy Efficiency Gains, and Energy Supplies............................. 121

Fig. 27- 2013 NOx Emissions (tons) vs. Average Income ............................................................ 170

Fig. 28- 2013 CO2 Emissions (metric tons) vs. Average Income................................................. 170

Fig. 29- 2013 Capacity Factor vs. Average Income ..................................................................... 171

Fig. 30- 2012 Capacity Factor vs. Average Income ..................................................................... 172

Fig. 31- Spatial Trading Restrictions............................................................................................ 185

Tables

Table 1- Bins for Selection of Units............................................................................................... 39

Table 2- Results of the 52-Unit Study ........................................................................................... 40

Table 3- Age of U.S. Coal-Fired EGUs as of 2025 vs. Generation in 2012..................................... 59

Table 4- Emission Goals for Louisiana- EPA’s Approach vs. Environmental Redispatch .............. 64

Table 5- MISO Regional Coal Dispatch Limitation ........................................................................ 67

Table 6- Western States Regional Coal Dispatch Limitation......................................................... 67

Table 7- Comparison of State RPS Targets and EPA Final RE Generation Targets ....................... 82

Table 8- Average Utility Costs of Saved Energy, 2004-2014....................................................... 117

Table 9- 2013 Net Incremental Electricity Savings by State ....................................................... 120

Table 10- State Scores for Energy Efficiency Resource Standards ............................................. 120

Table 11- 2012 Emissions and Generation Data for Texas......................................................... 140

Table 12- 2012 Totals and EPA’s 2020, 2020-2029, and 2030 Targets for Texas....................... 141

Table 13- Data for Texas Coal Plants Nearing Retirement Age .................................................. 141

Table 14- Data from Emission Reduction Scenarios................................................................... 142

Table 15- SO2, NOx, and CO2 Emissions, and Demographics of Large 

Coal-Fired Plants in the U.S..................................................................................................... 167
ES-1

EXECUTIVE SUMMARY

I. Introduction

Global climate change is the biggest environmental, social, and political challenge of our 

time. Unless we act swiftly and immediately to curb emissions of heat-trapping pollutants, 

especially carbon dioxide (“CO2”), we will be unable to mitigate the worst of effects of this 

crisis: rising sea levels, mass plant and animals extinctions, an increasing scarcity of crucial 

natural resources, a greater frequency of extreme weather events, the spread of toxins, pests, 

and pathogens, widespread displacement of peoples, and unprecedented social upheaval. 

Fossil fuel-fired power plants, or electric generating units (“EGUs”), are the single largest source 

of CO2 emissions in the United States and represent a significant percentage of global 

emissions. Any strategy to minimize the impacts of climate change must address CO2 emissions 

from fossil fuel-fired EGUs in the United States.

We applaud EPA for proposing the Clean Power Plan (“CPP”), which represents the first 

direct limitations on CO2 emissions from the U.S. electric sector. The CPP comes at a critical 

moment in the fight against climate change. The United States and China, the world’s two 

biggest carbon polluters, recently announced a joint agreement to cut CO2 emissions 

significantly over the next decade and a half. For the U.S. to be a climate leader on the world 

stage and meet its international commitments, the CPP and similar efforts are crucial. The 

domestic electric sector is also undergoing a major shift away from coal-fired generation in 

favor of lower-emitting resources, with wind and solar generation experiencing rapid growth 

and a steep decline in costs. The CPP both reflects the changing nature of the utility sector and 

helps advance the momentum toward cleaner generation that already exists. 

The combination of four building blocks that constitute EPA’s proposal—heat rate 

improvements at coal-fired EGUs, reduced utilization of coal plants in favor of lower-emitting 

sources, increased development and use of non-emitting resources, and energy efficiency 

investments—is cost-effective, technically achievable, and well-tailored to reflect the complex 

and interconnected nature of the electric system. As such, EPA’s plan is an appropriate exercise 

of the agency’s authority under section 111(d) of the Clean Air Act. However, the urgency of the 

climate crisis and the imperative for the U.S. to lead global efforts to reduce climate pollution 

demands stronger action. EPA must strengthen the CPP and ensure that the rule is maximally 

effective. 

In our comments, we discuss the rule’s legal ramifications and propose a suite of 

improvements to achieve greater CO2 reductions. We also address a number of additional 

topics, including compliance and enforcement issues in state plans, environmental and 

economic justice considerations, grid reliability, and others.
ES-2

II. EPA’s Obligations Under Section 111(d)

Section 111(d) of the Clean Air Act directs EPA to issue emission guidelines for existing 

sources of air pollution that endanger the public health or welfare once EPA has issued new 

source standards for that pollution under section 111(b). States then implement EPA’s 

guidelines through federally approved plans, which include performance standards for covered 

sources of pollution. These standards must reflect EPA’s determination of the best system of 

emission reduction, or “BSER,” that is adequately demonstrated, taking into account the energy 

requirements and non-air environmental impacts of affected sources. While the statute also 

requires EPA to consider costs associated with BSER, courts will not reject a BSER determination 

on economic grounds unless it entails costs that are “exorbitant” and would effectively cripple 

the regulated industry. 

EPA has proposed two alternative approaches for determining the BSER. We offer 

additional support for EPA’s second approach—BSER as the combination of building block 1 

plus the reduced utilization of affected sources, quantified in specific amounts from the 

measures comprised in building blocks 2, 3, and 4. Specifically, the amount of generation from 

the increased utilization of natural gas combined cycle (“NGCC”) units (building block 2) would 

determine a portion of the amount of reduced generation from affected fossil fuel-fired steam 

EGUs, and the amount of generation from the use of renewable energy and avoided emissions 

through demand-side energy efficiency (building blocks 3 and 4) would determine a portion of 

the amount of the generation reduction for all affected EGUs—both coal-fired steam EGUs and 

NGCC units. Under this approach, enforcement would be simpler and more straightforward 

because affected sources would be accountable for the required emissions reductions.

CO2 emissions reductions at fossil fuel-fired EGUs can be achieved by reducing both the 

EGU’s emission rate and its electricity output. Heat rate improvements at affected EGUs are 

aimed at reducing these sources’ emission rate; redispatch to existing and under construction 

NGCC units, renewable energy, and demand-side energy efficiency are aimed at reducing 

affected sources’ output and thus their overall mass CO2 emissions. All of the emission 

reductions measures under consideration, whether implemented directly at the affected source 

or beyond the source, translate into emissions reductions from such sources. The measures 

under the four building blocks are effectively “at the unit” measures that reduce affected EGUs’ 

utilization, because these measures are being and can be implemented or sponsored by owners 

and operators of affected sources. EPA should therefore set the stringency of the emission 

guideline based on the complete universe of those measures. 

Even though EPA’s proposal contemplates including both fossil fuel-fired units and 

stationary combustion turbines in a single category (codified under a new Subpart UUUU), 

failure to include oil- and gas-fired (“O&G”) steam EGUs and NGCCs in building block 1 implies 

that these units are not subject to emission reduction requirements. Therefore, we urge EPA to 

incorporate O&G steam EGUs and natural gas-fired units, both NGCCs and simple cycle 

combustion turbines (“CTs”), in building block 1, and to reformulate its BSER approaches 

accordingly. Under EPA’s second BSER approach, the BSER would include, first, building block 
ES-3

1—heat rate improvements (and other capital investments such as turbine blade replacements) 

on all affected fossil fuel-fired EGUs, and second, a reduced utilization component. The reduced 

utilization component would comprise limiting the dispatch of fossil fuel-fired steam EGUs by 

the amount of available existing NGCC capacity in 2020, and thereafter limiting the dispatch of 

all fossil fuel-fired EGUs by the amount of available renewable energy and energy efficiency.

In the sections that follow, we establish that each of EPA’s proposed BSER building 

blocks, if strengthened in the ways that we suggest, are adequately demonstrated and will not 

impose unreasonable costs on the U.S. electric power generation industry. We note, however, 

that EPA is not proposing that each of the measures in its proposed system of emission 

reductions be met. Instead, EPA proposes a formula that identifies one low cost mix of 

measures that can achieve significant emission reductions and proposes to allow sources, states 

and groups of states flexibility in achieving equivalent reductions. It is this objectively 

determined formula that must meet the statutory tests described above.

III. The Building Blocks

A. Block 1: Heat-Rate Improvements

Heat-rate improvements (“HRI”) at individual fossil-fired units are a cost-effective and 

well-demonstrated method of reducing CO2 pollution. Through enhanced operation and 

maintenance (“O&M”) practices and targeted equipment upgrades, plants can reduce the

amount of fuel needed to generate each megawatt-hour of electricity, thus reducing CO2

emissions. EPA expects that coal-fired EGUs can achieve a six percent reduction in emission 

rates (a figure it admits is conservative) through a combination of O&M improvements and 

equipment upgrades. However, Sierra Club conducted a study of 52 randomly-selected coal 

plants and determined that simply by meeting their best historical performance averaged over 

a one-year period, coal plants can achieve at least a six percent HRI through O&M practices 

alone. Equipment upgrades add an additional four percent HRI, and the data indicate that few 

units have already undergone the kinds of upgrades associated with the largest reductions. 

Therefore, EPA should revise Block 1 to assume a ten percent rather than six percent emission 

reduction through HRI at coal plants. 

As noted above, we also urge EPA to include HRI at O&G steam EGUs and NGCCs in its 

Block 1 reductions. Our data illustrates that O&G steam units can benefit from the same kinds 

of O&M and equipment upgrades that would reduce emissions from coal plants. While NGCCs 

tend to be better operated than steam EGUs, there are still cost-effective equipment upgrades 

available that will reduce CO2 emissions from these facilities. Finally, EPA should cover CTs and 

all other fossil-fired EGUs in the CPP, regardless of capacity factors or function. 

B. Block 2: Redispatch of Coal-Fired and O&G Steam Units

Under Block 2, EPA calculates the emission reductions that could be achieved by 

reducing dispatch of coal-fired and O&G steam EGUs in favor of other resources. Specifically, 
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the agency determines the amount of unused NGCC capacity that is available in each state up 

to a 70 percent utilization rate, then calculates the amount of coal and O&G steam generation 

that could be reduced if the state were to use that excess NGCC capacity for baseload 

generation. Reduced utilization of coal- and O&G-steam units is an appropriate element of 

BSER, since it is achievable, technically demonstrated, and economically reasonable.

We have serious concerns about gas-fired generation. Not only does natural gas 

combustion generate large quantities of CO2, it produces significant upstream methane 

emissions that partially—and perhaps entirely—offset the climate benefits that might 

otherwise accrue from reducing coal combustion. Furthermore, the extraction of natural gas, 

especially through unconventional methods such as hydrofracking and tight-gas extraction, 

have significant water quality and land use impacts. 

However, EPA is clear that Building Block 2 does not mandate redispatch from coal to 

gas. Rather, it simply quantifies the emission reductions that could be achieved through coal-togas switching and leaves it up to the states to achieve these reductions in whatever way is 

feasible. Moreover, Block 2 represents an effective proxy for the reductions available to the 

electric sector through coal plant retirements. Coal-fired EGUs have been retiring at a swift clip 

in recent years, a trend that economists predict will continue apace over the next decade. 

Although the CPP’s emission targets do not directly address coal retirements, Block 2 is 

premised on curtailed use of coal-fired electricity and the emission reductions it quantifies are 

roughly tantamount to those that can be expected from retirements during the plan’s 

timeframe. 

Emission reductions calculated under Block 2 can be increased if the following three 

changes are considered. First, EPA must account for near-term coal retirements in its targetsetting exercise under Block 2. The agency’s goal calculations include data from coal plants that 

have either retired in 2012 or will have retired by the time the compliance period begins. There 

is no justification to include these units in the goal calculations, and removing them would 

ensure that the coal fleet actually in existence as of 2020 will reduce its emissions accordingly. 

To achieve this, EPA should recalculate its state goals at the time each state submits its plan to 

the agency. Second, EPA’s current approach reduces dispatch of coal-fired EGUs (on the one 

hand) and O&G steam units (on the other) in proportion to their existing ratios of generation. 

Instead, the agency should revise its formula such that the higher emitting source group is 

displaced first, and the lower-emitting group is curtailed only if there is additional NGCC 

capacity after coal is entirely displaced. Third, the current proposal calculates redispatch on a 

state-to-state basis. This produces differences among the states based on the amount of 

available NGCC capacity from one state to the next. If EPA were to organize the states into 

redispatch regions, it would smooth out these disparities and provide for greater reductions, 

while also reflecting with greater accuracy the interstate nature of the electric sector.
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C. Block 3: Increased Utilization of Renewable Energy 

We strongly support the use of renewable energy (“RE”) as an element of the CPP. Zerocarbon resources—particularly onshore wind, utility-scale solar, and distributed photovoltaic 

(“PV”) solar—have been generating electricity for decades and have experienced dramatic price 

decreases over the last decade, with the steepest reductions occurring in the last few years. 

These resources are at or near price parity with fossil generation in many areas of the country 

and continue to exhibit very rapid growth in market penetration. Although there is some 

uncertainty about the future of certain tax incentives that have benefited renewable resources 

in recent years, such as the production tax credit and the investment tax credit, we expect that 

wind and solar will remain competitive products into the foreseeable future through robust 

financing mechanisms, research and development gains, and regulatory pressure through the 

CPP and other state and federal programs.

RE is therefore an appropriate—and crucial—component of BSER. In fact, we believe 

that EPA has significantly underestimated the extent of RE penetration that is achievable 

nationwide and in individual states. Building Block 3 currently sets state-level renewable goals 

by calculating regional averages of the renewable portfolio standard (“RPS”) targets in states 

that have such programs. It then determines the amount of yearly growth needed in each state 

to meet that regional average. The agency has proposed an alternative formulation for Block 3 

that bases the state RE targets on the lesser of two values: 1) a national benchmark that 

calculates the development of different renewable technologies in 16 leading states as a 

percentage of those states’ resource-specific technical potentials; and 2) the results of 

integrated planning model (“IPM”) runs calculating the market potential in each state for 

different renewable resources based on development cost reductions.

Both of EPA’s approaches must be improved. The primary approach assumes that an 

average RPS target represents a reliable RE potential for states in that region, when, in fact, this 

target merely reflects the political will that states in each region have thus far exerted toward 

RE development. Hence, a region such as the Southeast has the lowest average of all regions 

(based on the RPS of just one state), even though it has an above-average technical potential 

for renewable generation. Furthermore, the regional RPS averages generate RE targets for 

many states under Block 3 that actually fall below the legally-enforceable RPS goals in those 

states. In addition to a number of flawed assumptions that result in truncated targets, the Block 

3 calculations are based on the unfounded assumption that RE generation will remain constant 

between 2012 and 2017. As for the alternative approach, it selects without justification the 

lesser of the two calculated benchmarks for each state. It also assumes a qualitative 

equivalence between the two benchmarks, even though IPM modeling offers a much more 

analytical and input-based estimate of a state’s renewable potential than the alternative, which 

is based on a rather simplistic ratio of development-to-technical potential for different 

technologies using a single year’s data. And even the IPM-modeled benchmarks suffer from a 

paucity of data for many resources and outdated cost assumptions that significantly 

underestimate the market potential for various renewable resources.
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To improve Block 3, EPA has a number of options available. First, it could retain a 

regional RPS-based approach but correct the flaws we identified above and establish an 

appropriate RE “floor” that each state must achieve regardless of the regional RPS average. 

Second, it could conduct a new round of IPM modeling using the best and most updated cost 

assumptions and resource-specific data to determine the true RE market potential in each 

state. The Natural Resources Defense Council (“NRDC”) has sponsored its own analysis of Block 

3 using IPM modeling that corrects many of the errors in EPA’s proposal, and we urge the 

agency to consider closely the results of NRDC’s study. Finally, the Union of Concerned 

Scientists (“UCS”) has proposed a feasible and effective approach to Block 3 that would nearly 

double the amount of renewable generation achieved through the CPP relative to either of 

EPA’s approaches. The UCS model would require states to maintain (starting in 2017) the level 

of RE growth they achieved between 2009 and 2013. It would also establish an annual growth 

floor of 1.0 percent and annual growth ceiling of 1.5 percent, as well as a total statewide ceiling 

of 40 percent market penetration. We are confident that with available financing mechanisms, 

rapidly declining costs of renewable technologies, and appropriate regulatory pressure, states 

will have little trouble sustaining a consistent level of RE growth between 2017 and the end of 

the CPP compliance period.

Given the complex, interstate nature of the electric system, there are numerous 

questions with regard to how states and sources should receive credit for renewable generation 

and what they should receive credit for. First, we recommend that EPA use the avoided MWh 

approach rather than the avoided CO2 approach for computing the compliance formula. While 

the latter may in theory provide a more accurate picture of the environmental benefits of RE, it 

requires dispatch modeling for which the necessary data is not available, whereas the former is 

far simpler and more transparent, permits greater upfront planning, and allows for 

methodological consistency with existing programs. Second, the agency should grant RE credit 

to states that incentivized the development of the RE, regardless of where the RE is located and 

the electricity is consumed. This will help encourage RE development and will maintain 

consistency with most RPS programs. 

Next, we urge EPA to establish methods to prevent double-counting with regard to RE 

generation that crosses state lines and to address some of the complexities associated with 

renewable energy credits (“RECs”), which are likely to be important compliance tools. While we 

believe that double-counting is not an inherent feature of the rule, the agency must remain 

vigilant against it, requiring states to comprehensively track and verify the amount and source 

of the RE they intend to use in their compliance demonstration. Finally, in terms of resources 

that should qualify as RE, we support distributed solar generation, utility-scale solar, and wind 

power. We also support the development of new small-scale hydropower for compliance 

purposes, although we agree that hydropower should not be included in the target-setting, 

since this would distort the RE goals in certain regions. Similarly, we oppose biomass for both 

goal-setting and compliance. This resource is associated with significant CO2 emissions as well 

as other environmental impacts. Should EPA include biomass in its formula or permit it for 

compliance purposes, it must conduct a rigorous analysis of the true CO2 emissions from these 

sources and solicit additional comments.
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D. Block 4: Increased Use of Energy Efficiency

Energy efficiency (“EE”) is the lowest-cost method of reducing CO2 emissions and is 

generally the first resource to dispatch to the grid. EE measures have been in place for decades 

and have many benefits apart from carbon reduction: they ease pressure on the grid and help 

ensure reliability, they save consumers money on electricity bills (and operators on fuel costs), 

and they reduce criteria pollutant emissions as well as upstream impacts from fossil fuel 

extraction, processing, and transmission. EE is therefore a sine qua non of any national program 

to reduce CO2 from the electric sector, and EPA has rightly included it as an element of BSER in 

Building Block 4.

The agency’s “best practice” approach to Block 4 assumes that states can sustain annual 

incremental EE gains of 1.5 percent per year of retail electricity sales during the compliance 

period. Higher-performing states will begin at the 1.5 percent annual incremental rate 

beginning in 2020, while lower-performing states will begin ramping up their EE investment 

starting in 2017, hitting 1.5 percent no later than 2025. These goals are well-supported and 

achievable in a cost-effective manner in all fifty states. Eleven states already have enforceable 

programs requiring 1.5 percent or greater by 2020, and three states—Arizona, Maine, and 

Vermont—already achieved savings greater than 1.5 percent in 2012. Those states that have 

not thus far achieved significant savings through EE will have little difficulty achieving the 1.5 

percent rate by the date expected under Block 4, since those are the states in which the lowesthanging fruit still remains.

EPA’s approach to Block 3 is a sensible and effective strategy for reducing CO2

emissions, although research suggests that savings greater than 1.5 percent annually may be 

appropriate. We offer two modifications that will strengthen Block 3. First, EPA should remove 

the 1.5 percent ceiling for those states that already have enforceable EE requirements that 

exceed that figure for 2020 or earlier. The agency should not lower the bar below the 

commitments that states have already set for themselves. Second, for net-importing states, 

EPA calculates the number of “negawatt-hours” associated with Block 4 according to the 

percentage of electricity sales originating from in-state generators, rather than all retail sales. It 

does not, however, correspondingly increase the savings that are expected of net-exporting

states, since states cannot control consumer behavior beyond their borders. Yet 

Building Block 4 merely specifies the EE savings that are available in each state, and it is both 

feasible and fair to expect states to reduce their own in-state generation in response to 

reduced electricity demand through EE, rather than shifting some responsibility for curtailing 

generation onto exporting states. Notably, this approach will not actually add any burden to 

importing states that meet their EE targets, since they will receive full credit for their negawatthours, rather than reduced credit under EPA’s current proposal. Together, these modifications 

to Block 4 will produce significantly greater emission reductions than under the agency’s 

current model.

With regard to Block 4 compliance, EPA has offered strong guidance in its CPP preamble 

and technical support documents, and we offer a number of additional suggestions. The agency 
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should first issue comprehensive guidelines or requirements for evaluation, measurement, and 

verification (“EM&V”) procedures, which states will use to ensure that their EE measures are, in 

fact, achieving CO2 emission reductions. We also urge EPA to develop guidelines for 

determining the proper lifespan of an EE measure or program, and to assist states in developing 

REC-like mechanisms for EE credits, which have not yet gained widespread use. As noted above, 

we believe states should receive credit for 100 percent of the savings achieved through in-state 

EE measures, regardless of where the emission reductions occur. Finally, because we believe 

that EGU owners and operators should bear the full responsibility for emission reductions 

under the CPP, we urge EPA to give credit only to those EE measures that an EGU owner/ 

operator can play a role in implementing. While this would encompass the kinds of EE programs 

sponsored by utilities or private parties such as industrial entities, it would not include building 

codes or appliance standards. We support strong building codes and appliance standards, but 

we do not believe they are appropriate compliance mechanisms under the CPP.

IV. State Plan Considerations

A. Affected EGUs Must Be Legally Responsible for All Emission Reductions

In line with the Clean Air Act’s requirements, EPA must ensure that state plans impose 

all of the responsibility for the required emission reductions on owners and operators of 

affected EGUs. State plan requirements must also be federally enforceable against affected 

sources, by EPA and through citizen suits. States that follow a rate-based protocol will need to 

include a mechanism that adjusts the emission rates of individual sources according to 

reductions achieved through EE, RE, and other measures apart from on-site HRIs. This 

mechanism could be a trading system for RECs and other emission reduction credits, or it could 

be a program through which the state administratively allocates emission reduction credits 

across the fleet of affected sources. 

B. Rate-to-Mass Conversions

A key feature of the CPP is that states may choose either rate-based or mass-based 

compliance scenarios. It is critical that any mass-based target generate equivalent emission 

reductions to its corresponding rate target designated by EPA. We propose three guiding 

principles for any state converting a rate-based goal to a mass-based one. First, rate and mass 

are related to one another through a simple formula: mass equals rate times generation. 

Second, “generation” here refers to a state’s regulated generation for each compliance period. 

By “regulated generation,” we simply mean any electricity that could be added to a state’s 

denominator when determining compliance with the rate (megawatt-hours from existing fossil 

and RE generation, and negawatt hours from EE measures). Any state wishing to include EE and 

RE in its rate-to-mass conversion will need to provide the same level of EM&V rigor that would 

otherwise be included for compliance in a rate-based scenario. Third, mass-based states will, at 

the outset, project their electric load for each compliance year, but must update those 

projections during the compliance period to reflect the true quantity of regulated electricity 

generated in that year. This annual “true-up” will ensure that states are neither penalized in 
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their mass targets for having underestimated electric demand from regulated units nor given a 

windfall for having overestimated demand. It is also necessary to ensure that a state’s retired 

units are not later included in the pool of regulated generation, artificially raising its mass cap. 

EPA did not address this necessary true-up in its technical support document discussing rate-tomass conversions, and should reject any mass-based plan that does not include it. 

C. Compliance and Enforcement Issues for State Plans

EPA must strengthen the CPP to ensure strict compliance with the rule’s emission 

targets. First, the agency must require actionable corrective measures in every state plan, set 

appropriate minimum thresholds and standards for the adoption, activation, and 

implementation of these measures, and require states to report publicly the causes of any 

performance deficiency that triggers corrective action. Second, state plans must assess 

individual EGU compliance over a period of no more than one year, and states should be 

required to submit annual, public reports to EPA on the status of their emission reduction 

progress. Third, EPA should not permit sources to estimate emissions through fuel consumption 

calculations, but must require continued monitoring emissions systems at all EGUs. Affected 

EGUs should also be required to submit engineering analyses and reference method test results 

for any compliance measures they wish to use to meet enforceable emission limits. This is 

necessary to ensure that the selected measures are, in fact, effective. Lastly, EPA must 

strengthen record retention requirements and ensure that facilities maintain all records onsite.

With regard to state plan approval, EPA should clarify that it will issue a federal 

implementation plan for any state that lacks an approvable plan of its own within six months 

after the submission deadline. The agency should also make approval of state plan contingent 

on the state’s adequate demonstration that it possesses not only the legal authority to enact 

and enforce the plan, but the resources necessary to implement it as well. EPA must amend its 

proposed regulations to ensure that the state plans include emissions standards that are 

enforceable by citizens. Finally, EPA should abandon the option of conditional plan approval. If 

a plan is not adequate at the time a state submits it, the agency should simply reject it and 

require the state to submit a proposal without deficiencies if it wishes to avoid a federal 

implementation plan.

V. Environmental Justice Considerations

Minority and low-income communities bear disproportionate health and socioeconomic risks from climate change. In the United States, these communities often live near 

dirty power plants and other large industrial facilities, and also in areas vulnerable to climate 

change impacts such as sea-level rise. As climate change worsens, environmental justice 

communities will spend higher proportions of their income as a result of rising food prices or 

increased water scarcity. To ensure that these communities receive the benefits of the CPP, EPA 

must address not only overall carbon emissions reductions, but also co-pollutant implications 

and local communities’ growth. EPA must ensure that, first, these communities do not 

experience increased levels of pollution as a result of the implementation of measures that 
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increase the utilization of certain affected sources. Second, these communities must benefit 

from the positive environmental and health effects that will result from the decreased 

utilization of dirty power plants and the development of renewable energy generation. 

In order to properly integrate environmental justice concerns into the CPP, EPA must 

prepare an environmental justice analysis of the rule, as required under Executive Order 12898. 

To this end, EPA should require states to conduct an environmental justice analysis as a 

component of state plans. This analysis will help to ensure that the different compliance 

measures selected by states under their plans do not cause adverse impacts, and actually 

benefit minority and low income populations. EPA must also ensure that state agencies that 

receive federal funding under Title VI of the Civil Rights Act under state plans comply with their 

obligation not to discriminate on the basis of race, color, or national origin. In the final rule, the 

agency also needs to make clear that emission standards that would allow uncontrolled or 

poorly controlled emissions from individual sources are not permissible as Section 111(d) 

emission guidelines for pollutants with localized health and environmental impacts. Finally, to 

the extent that the CPP allows states to comply through trading of RECs or CO2 allowances, EPA 

must establish guidelines for states to effectively integrate environmental justice concerns into 

the design of these programs in a manner that restricts trading practices that could exacerbate 

hotspots and that provides for investments in clean energy and the revitalization of these 

communities.

VI. Economic Justice Considerations

Investments in energy efficiency and renewable energy to comply with the CPP will 

produce major additional benefits throughout the U.S. economy, making the clean energy 

economy a major new engine of U.S. job creation. Renewable energy has become cost 

competitive with fossil fuels, including coal, oil, and natural gas, as well as with nuclear power. 

In addition to reducing carbon emissions, the ancillary benefits of the CPP—developing 

renewable energy, energy efficiency and a modernized, smart power grid—will, when 

combined with high road employment practices, create millions of good jobs for people who 

desperately need them, especially people from economically and environmentally distressed 

communities. States must take the driver’s seat in crafting compliance plans that expand 

renewable energy and energy efficiency, while also prioritizing the creation of good, clean 

energy jobs to promote state and local economic development and improve community and 

workers’ livelihoods.

There are clear environmental and public health benefits of replacing fossil fuels with 

energy efficiency and renewable energy. Jobs will be created with the CPP, but we cannot 

ignore the fact that some jobs will be lost and specific communities will be affected as we make 

the transition away from fossil fuels. The CPP state implementation process provides 

tremendous opportunities for state and federal policymakers to take concrete policy steps, 

through workers’ transition policies and funding mechanisms, to address the fears of low 

income and working class communities and union representatives in carbon-intensive sectors 

that a market-driven clean energy transition means economic insecurity for them. The 
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government has a key role in helping to drive a fair and just transition to a clean energy 

economy that will maximize investments in economic development, provide security to 

affected workers, and protect the tax base by creating lasting, good jobs in affected 

communities.

VII.Carbon Tax

EPA should amend the proposed regulations to clarify that states may use a carbon tax 

as a compliance mechanism. Numerous studies have demonstrated that a carbon tax is an 

effective means of reducing greenhouse gas emissions. A carbon tax is economically efficient 

and relatively easy to administer. Moreover, it provides revenue that can be used to offset 

electricity rate increases for low income households, to implement EE programs in low income 

communities, and to finance co-pollutant reductions in environmental justice communities.

VIII. Impacts on Upstream Emissions

While the CPP will undoubtedly achieve significant reductions in CO2 emissions at the 

point of combustion, EPA must accurately account for any upstream impacts on greenhouse gas 

emissions that may result from the rule. Of particular concern is methane, a potent heattrapping pollutant that far exceeds the global warming potential of CO2 on both 20- and 100-

year bases. During all phases of natural gas extraction (production, processing, transmission, 

storage, and distribution), methane is emitted by equipment leaks or intentional venting. These 

emissions partially—and, if high enough, entirely—offset the climate benefits of combusting 

natural gas instead of coal to generate electricity. Methane is also released during coal mining, 

when reservoirs previously trapped in ore seams are exposed to the atmosphere.

EPA predicts in its regulatory impact analysis (“RIA”), that while the CPP will increase gas 

production in the short term (leveling out over the long-term), it will reduce coal-mining 

enough such that methane emissions will decline from a business-as-usual scenario. We offer 

three important caveats to that prediction. First, given the magnitude of methane emissions 

associated with gas production (as well as the sizable quantities of CO2 resulting from gas 

combustion), EPA must incentivize the use of EE and RE for plan compliance over gas-fired 

generation. Second, EPA must provide for a rigorous and proper accounting of the actual 

methane emissions associated with fossil fuel extraction. We are concerned that the agency’s 

Greenhouse Gas Inventory and other “bottom-up” analyses significantly underestimate the true 

quantity of methane in the atmosphere resulting from natural gas extraction. The agency must 

address the most recent research, including “top-down” atmospheric studies, and adjust its 

estimates accordingly. Third, EPA must act swiftly to directly regulate methane emissions from 

the oil and gas industry. Emissions from this industry will increase under the CPP (even if EPA is 

correct that overall emissions will decrease), and there is ample support for cost-effective 

regulations that will, in many cases, generate additional revenue for industry through 

conserved gas.
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Furthermore, EPA assumes in its RIA that decreased coal generation will result in a 

proportionate reduction in coal mining. The agency must address the impacts that will occur if 

increased coal exports offset (either partially or wholly) the reductions that would otherwise 

occur in coal mining under the CPP. 

IX. Reliability

Several grid operators and affiliated groups have raised concerns over the number of 

projected retirements of covered units the CPP may necessitate, and how such retirements 

would affect the “reliability” of the power grid. In particular, they have raised concerns that 

retirement of existing units will threaten the grid’s overall resource adequacy, its voltage and 

frequency stability, and its resilience against major grid disturbances. 

The fact that these concerns were raised is not surprising: each time EPA undertakes 

rulemakings affecting the electric generating sector, naysayers cry that the lights will go out. 

The concerns are, however, both exaggerated and unfounded. Most of these same groups have 

been considering the grid impacts of retiring inefficient fossil fuel-burning power plants for 

years, and have responded by redesigning markets and transmission systems to accommodate 

renewable energy and other nontraditional power resources. As a result, we already know how 

to integrate renewable generation resources without disrupting the grid, by ensuring that the 

replacement resources also replace any essential reliability services that may be required 

(indeed, most new renewable facilities are already required to have this capability). Meanwhile, 

electricity storage systems and demand response programs, both of which have seen increasing 

use over the last several years, are well equipped to fill in any shortfalls that may arise. 

In particular, we oppose two specific policy recommendations made by utilities and 

operators: first, to delay implementation of the CPP, which would further delay our necessary 

transition to new and cleaner power sources; and second, to include a “reliability safety valve,” 

which would in effect reward the utilities and affected EGUs who drag their feet by allowing 

them to continue emitting large amounts of greenhouse gases. These policy recommendations 

mirror similar recommendations made each time EPA suggests a new set of rules, but they are 

particularly unnecessary here because the CPP is if anything more responsive to potential 

reliability concerns than several other recent EPA rules. Unlike national standards that are 

imposed inflexibly on individual facilities, the CPP relies on a cooperative federalism model that 

allows states to design their plans to minimize disruptive impacts on the grid. We are therefore 

confident that states working in conjunction with regional grid operators will be able to ensure 

a smooth transition to a cleaner and more efficient power grid over the next five to fifteen 

years.

Finally, we join with these grid operators and other commenters in calling on EPA to 

encourage advanced planning for anticipated supply shifts, and especially to facilitate 

cooperation between states and regional and local grid operators when implementing the CPP. 

Although the grid restructuring necessary to support a shifting resource load is definitely 
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manageable, it will require advanced preparation, and EPA should support that work in 

whatever way it can.

X. Other Issues

A. The Symmetry Principle

EPA has expressed that it may allow states to use non-BSER measures for compliance 

purposes. If it does so, EPA must adhere to what we refer to as the “symmetry principle”: the 

stringency of the state goals must reflect the full set of measures that can be used to comply. 

Thus states should not be allowed to use non-building block measures such as new NGCC units 

or new unplanned nuclear capacity for compliance.

B. The Compliance Timeline and Revised Guidelines

EPA’s current CPP proposal extends the compliance period until 2030, and the agency 

has also solicited comment on an alternative compliance period ending in 2025, with interim 

goals applying between 2020 and 2024. We urge EPA to adopt the shorter time frame, but we 

believe that the state goals proposed for the 2025 option are far too weak. Indeed, our analysis 

of the building blocks demonstrates that the state goals should be much more stringent than 

those included in the 2030 option. EPA should require full compliance by 2025 because the vast 

majority of emission reductions can be achieved early on in the compliance period. In addition, 

we urge EPA to adopt two additional features. First, EPA should advance the compliance 

schedule to begin as early as January 2018 rather than 2020 to capitalize on the changing 

nature of electricity markets and the rapid development of renewable resources. We believe 

that a three-year window is sufficient time for states to begin working toward compliance. 

Second, the agency should engage in a continuous internal review of the rule during the 

compliance period and should commit to issuing a revised set of emission guidelines that would 

take effect in 2026. We also oppose any effort by EPA to relax the stringency of the glide path 

or phase in emission reductions under Building Blocks 1 and 2. States are free to apportion their 

emission reductions across the compliance period however they choose so long as the interim 

and final goals are met. This measure of flexibility provides a sufficient buffer against stranded 

assets and other technical challenges toward achieving compliance, and no additional 

relaxation of the glide-path is necessary.

C. New Source Review

Measures that affected sources implement to comply with the CPP are unlikely to 

trigger New Source Review (“NSR”) permitting requirements. To ensure that sources will not 

generate enough emissions to trigger NSR, states can include in their plans rigorous sourcespecific limits on emissions or operations. EPA may not legally permit states to exempt sources 

from NSR for actions implementing the CPP. Such sources should be subject to emissions limits 

if they modify and increase their emissions and exempting them would put neighboring 

communities at risk. Moreover, exempting sources would encourage “life extension” programs 
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at fossil fuel-fired EGUs that would undermine the goals of both the Clean Air Act, to end the 

grandfathered status of aging plants, and the Climate Action Plan, to transition the U.S. electric 

supply sector to lower carbon intensity technologies.
1

I. Introduction

As EPA has properly concluded in its 2009 Endangerment Finding, the scientific record 

demonstrating that “elevated concentrations of greenhouse gases in the atmosphere may 

reasonably be anticipated to endanger the public health and welfare of current and future U.S. 

generations is robust, voluminous, and compelling.”1Existing electric generating units (“EGUs”) 

are the single largest source of domestic greenhouse gas (“GHG”) emissions. Accordingly, as we 

discuss at length below, EPA must control greenhouse gas pollution from this source category 

under section 111 of the Clean Air Act (“CAA” or the “Act”), 42 U.S.C. § 7411. Significantly 

reducing these emissions from existing domestic power plants is necessary to mitigate the 

serious harms associated with climate change in the United States.

In addition, fossil fuel-fired EGUs are significant sources of smog- and soot-forming 

pollutants, including sulfur dioxide (“SO2”), nitrogen oxides (“NOx”), and fine particulate matter 

(“PM2.5”), as well as hazardous air pollutants such as mercury (“Hg”) and hydrochloric acid 

(“HCl”). In this introductory section, we briefly describe some of the harms associated with both 

greenhouse gas emissions and traditional pollutants, and show why the emissions profile of the 

EGU sector demands expeditious regulation under section 111 to mitigate the impact of climate 

change and protect the public health and welfare from air pollution.

A. Emissions of CO2 and Traditional Air Pollutants from Fossil Fuel-Fired EGUs Threaten 

the Public Health and Welfare.

1. Harms Associated with Climate Change and Ocean Acidification

As discussed in the Endangerment Finding and the Clean Power Plan’s Regulatory 

Impact Analysis (“RIA”),2climate change poses manifold threats to the public health and 

 

1

75 Fed. Reg. 49,556, 49,557 (Aug. 13, 2010) (Endangerment Reconsideration Denial); see also 74 Fed. 

Reg. 66,496, 66,523 (Dec. 15, 2009) (Endangerment Finding); Coalition for Responsible Regulation, Inc. v. 

EPA, 684 F.3d 102, 122—28 (D.C. Cir. 2012) (upholding Endangerment Finding in its entirety).

2

EPA, Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants 

and Emission Standards for Modified and Reconstructed Power Plants (“RIA”), EPA -542/R-14-002 (June 

2014), available at http://www2.epa.gov/sites/production/files/2014-06/documents/20140602riaclean-power-plan.pdf. Several of the assessment reports cited in the Endangerment Finding and RIA (or 

updated versions of those reports) are attached and incorporated by reference. These include the IPCC’s 

Climate Change 2014: Synthesis Report (2014), available at http://www.ipcc.ch/pdf/assessmentreport/ar5/syr/SYR_AR5_LONGERREPORT.pdf, and Climate Change 2013: The Physical Science BasisSummary for Policymakers (2013), available at http://www.ipcc.ch/pdf/assessmentreport/ar5/wg1/WG1AR5_SPM_FINAL.pdf, full report available at

http://www.climatechange2013.org/); the NRC’s Advancing the Science of Climate Change (2010), 

available at http://dge.stanford.edu/labs/caldeiralab/Caldeira_research/pdf/ACC_Science_2010.pdf, 

and Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia

(2011), available at http://www.climatechange-foodsecurity.org/uploads/NRC_climate_impacts.pdf; 

and the USGCRP’s Climate Change Impacts in the United States (Third National Climate Assessment 
2

welfare. A changing climate will increase the incidence and severity of heat waves, which lead 

to temperature-related deaths and enhanced ozone (or smog) formation, a major public health 

problem in its own right.

3

Climate change will also produce heavier precipitation events, 

stronger tropical cyclones, and associated flooding, spreading toxins and diseases and causing 

severe infrastructure damage, social upheaval, and widespread injury and death.4Pathogens 

and pests are expected to disseminate more widely due to changes in those species’ survival, 

persistence, habitat range, and transmission under changing climate conditions.5

In addition, sea level rise is well documented and is very likely to accelerate over the 

coming decades.6Rising seas and extreme weather events will threaten our coastal homes, 

cities, and infrastructure, forcing expensive efforts to protect or relocate critical resource and 

displacing millions of people.

7

Further inland, early spring melts will increase flood risks early in 

the melt season, while shrinking snowpack will cause water shortages throughout much of the 

west.8 Droughts, especially in the western and southern United States, are expected to occur 

more frequently and (along with changing atmospheric chemistry) will likely cause crop damage 

and failure and corresponding food shortages. Forested lands will see more severe fires, pest 

outbreaks, and higher tree mortality, which will likely disrupt timber production.9

Climate change also will threaten natural environments and biodiversity, which offer

humans a wide range of benefits and services, including fresh water, fertile soil, fisheries, 

climate regulation, and aesthetic, cultural, and recreational benefits.10 The combination of 

global temperature increases and other environmental stressors will tax many plant and animal 

species to the point of extinction. Research indicates that climate change and other 

anthropogenic factors are causing the sixth mass extinction of global biodiversity in the last 600 

million years of life on Earth, with current extinction rates 100 to 1,000 times greater than 

 

Report)- Overview (2014), available at http://nca2014.globalchange.gov/highlights/overview/overview, 

full report available at http://nca2014.globalchange.gov/downloads). See also RIA at 4-2—4-3 (listing 

publications).

3

RIA at 4-2—4-8; USGCRP, NCA overview, supra n. 2, at 11; Pfister et al., Projections of Future 

Summertime Ozone Over the U.S., J. of Geophysical Research: Atmospheres (May 5, 2014) (higher 

temperatures increase smog formation in already polluted areas).

4

RIA at 4-6. 

5

Id.; USGCRP, NCA overview, supra n. 2, at 11.

6

RIA at 1-2, 4-3—4-6; USGCRP, NCA overview, supra n. 2, at 7-11; IPCC, Climate Change 2014: Synthesis 

Report, supra n. 2, at SYR-7—8

7

Id.

8

Id. at 1-2, 4-16, 4-13; USGCRP, NCA overview, supra n. 2, at 10-11.

9

RIA at 4-4; USGCRP, NCA overview, supra n. 2, at 11; IPCC, Climate Change 2007: Impacts, Adaptation, 

and Vulnerability (2007), available at 

http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_wg2_report_i

mpacts_adaptation_and_vulnerability.htm, at Ch. 5: Ecosystems, Their Properties, Goods and Services.

10 USGCRP, NCA overview, supra n. 2, at 11-12.
3

historical rates.11 In 2007, the IPCC concluded that by the mid-21st century, 15 to 37 percent of 

plant and animal species worldwide would be committed to extinction if temperatures increase 

1.6 to 1.8 degrees Celsius above late 20th century levels.12 Even species that do not go extinct 

will have to contend with unprecedented ecological conditions, and many will be forced to 

migrate to new and unfamiliar latitudes to survive.13

Independent of climate change, some of the carbon dioxide (“CO2”) emitted via fossil 

fuel combustion is subsequently absorbed by the world’s oceans. Because carbonic acid forms 

when carbon dioxide dissolves in water, rising CO2 emissions are causing the seas to become 

more acidic. The NRC has reported that ocean acidity has increased approximately 30 percent 

since pre-industrial times, and could intensify by three to four times this amount by the end of 

the century if carbon emissions remain uncurbed.14 Increased acidification poses a significant 

threat to the ocean’s critical food webs. Along with increasing surface stratification because of 

warmer surface water, ocean acidification may result in a “widespread decline in marine 

primary production,” doing great damage to the base of the oceanic food chain with potentially 

devastating effects on the food supply for many regions around the globe.15

Greenhouse gas emissions and atmospheric carbon concentrations have continued to 

rise in the years since EPA made its Endangerment Finding. For instance, global greenhouse gas 

emissions are now rising faster than the IPCC’s highest emissions scenario from 2007, as 

illustrated in the figure below, compiled by the European Environment Agency.

 

11 Pimm et al., The Future of Biodiversity, 269 Science 347, 347 (1995); Dirzo and Raven, Global State of 

Biodiversity and Loss, 28 Annual Review of Environment and Resources 137, 137 (2003); Barnosky et al., 

Has the Earth's sixth mass extinction already arrived?, 471 Nature 51 (2011).

12 IPCC, supra n. 9, at 243; see also Clavel et al., Worldwide decline of specialist species: toward a global 

functional homogenization?, 9 Frontiers in Ecology and the Environment 222 (2011).

13 Chen et al., Rapid Range Shifts of Species Associated with High Levels of Climate Warming, 333 Science

1024 (2011).

14 NRC, Advancing the Science of Climate Change, supra n. 2, at 55; see also id. at 56, 59-60; NRC, 

Climate Stabilization Targets, supra n. 2,at 209-210; Hönsich et al., The Geological Record of Ocean 

Acidification, 335 Science 1058, 1058 (2012).

15 Gao et al., Rising CO2 and Increased Light Exposure Synergistically Reduce Marine Primary Productivity, 

2 Nature Climate Change 519, 519 (2012).
4

Fig. 1- IPCC Emission Scenarios16

This graph compares six IPCC emissions scenarios (labeled A1B to B2) with actual 

atmospheric carbon measurements from two sources. In the last decade, global emissions have 

rapidly increased to match, or even slightly outpace, the most aggressive IPCC scenario, A1F1, 

which assumes a “world of very rapid economic growth” with “fossil-intensive” energy 

systems.17

Indeed, several reports and assessments attest that threat of climate change is even 

more pressing than anticipated just a few years ago. For instance, a recent IPCC report notes 

that “satellite-measured sea levels continue to rise at a rate closer to that of the upper range of 

[earlier] projections” and that “the contribution to sea level due to [ice] mass loss from 

Greenland and Antarctica is accelerating.”18 The IPCC’s AR5 and the USGCRP’s Third National 

Climate Assessment reflect similar conclusions with regard to sea level rise based on superior 

modeling and data inputs. 19 As the Climate Assessment authors note, “[c]ontinued warming 

and an increased understanding of the U.S. temperature record, as well as multiple other 

sources of evidence, have strengthened our confidence in the conclusions that the warming 

 

16 “Observed global fossil fuel CO2 emissions compared with six scenarios from IPCC,” available at

http://www.eea.europa.eu/data-and-maps/figures/observed-global-fossil-fuel-co2/ccs102_fig2-3.eps.

17 See IPCC, Climate Change 2007: Synthesis Report (2007) available at

http://www.ipcc.ch/pdf/assessment-report/ar4/syr/ar4_syr.pdf, at 44.

18 IPCC, Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation

(2012), available at http://www.ipcc-wg2.gov/SREX/images/uploads/SREX-All_FINAL.pdf, at 178-79.

19 IPCC, full scientific report for AR5, supra n. 2, at 1140; USGCRP, full NCA report, supra n. 2, at 21.
5

trend is clear and primarily the result of human activities.”20 And in May 2013, a federal 

working group revised its range of monetary values representing the social cost of carbon from 

$7, $26, $42, and $81 per ton of CO2 emitted in 2020 to $12, $43, $65, and $129, respectively, a 

reflection of the continuous upward assessment of the harms posed by climate change.21

2. Climate Stabilization Requires Immediate, Deep Reductions in Emissions from the 

EGU Sector.

CO2 emissions from power plants remain the single largest source of U.S. greenhouse 

gas pollution and are a significant component of global emissions. Without emissions controls 

for this sector, it will be impossible to stabilize atmospheric greenhouse gas emissions at a safe 

level. EPA’s Inventory of Greenhouse Gas Emissions and Sinks reports that electricity generation 

was responsible for 2,022 million metric tons of CO2 in 2012, 37.5 percent of annual domestic

emissions.22 A full three-quarters of U.S. electricity sector emissions come from coal-fired EGUs, 

with most of the remainder coming from natural gas-fired units. 23 Given the dominance coal 

combustion in the U.S. electricity sector, EPA must act rein in emissions from coal-fired plants 

and encourage their replacement with renewable energy and demand reductions from 

efficiency investments. Immediate action is critical if we are to transition to an electricity sector 

that minimizes our impact on global climate change.

Domestic action to combat climate change will have benefits that extend far beyond our 

borders. As of 2012, the United States was responsible for approximately 13.4 percent of global 

anthropogenic GHG emissions and 15 percent of CO2 emissions).24 The U.S. power sector alone 

contributed approximately 4.5 percent of worldwide GHG emissions and over 6 percent of all 

CO2 emissions.25 Steep cuts from large sources like the U.S. power sector are therefore critical 

to prevent truly disastrous climate impacts. As the NRC’s 2011 report on climate stabilization 

 

20 USGCRP, full NCA report, supra n. 2, at 21.

21 IWG, Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866 (Nov. 2013), available at 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/social_cost_of_carbon_for_ria_2013_upda

te.pdf, at 2. While we believe that the IWG’s updated figures fundamentally underestimate the true cost 

of carbon emissions, they nonetheless reflect the same trend as seen in the scientific literature: as 

research on climate change continues to amass, our awareness and assessment of the many threats it 

poses to our world grows as well.

22 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990—2012, EPA 430-R-14-003 (Apr. 15, 

2014), available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory2014-Main-Text.pdf, Table 2-1.

23 Id. at Table 3-5.

24 European Union Emission Database for Global Atmospheric Research (EDGAR), GHG (CO2, CH4, N2O, 

F-gases) emission time series 1990-2010 per region/country, available at

http://edgar.jrc.ec.europa.eu/overview.php?v=GHGts1990-2010, and CO2 time series 1990-2012 per 

region/country, available at http://edgar.jrc.ec.europa.eu/overview.php?v=CO2ts1990-2012.

25 According to the EDGAR database, global GHG emissions in 2010 were 50,101 million metric tons 

CO2e.
6

emphasizes, worldwide emissions reductions on the order of 80 percent by the century’s end 

are necessary to prevent temperatures from exceeding 2 degrees Celsius above pre-industrial 

levels.26 The IPCC has determined with “high confidence” that “[d]elaying mitigation efforts 

beyond those in place today through 2030 is estimated to substantially increase the difficulty of 

the transition to low longer‐term emissions levels and narrow the range of options consistent 

with maintaining temperature change below 2°C relative to pre‐industrial levels.”27 Without 

swift and significant emissions controls for the U.S. power sector, the odds of preventing the 

most extreme effects of climate change are virtually nil.

3. Reducing Climate Pollution Will Also Reduce Conventional Pollution from Fossil 

Fuel-Fired Power Plants

Combusting fossil fuels—particularly coal—not only drives global climate change, but 

also emits numerous air pollutants into the atmosphere that have serious ramifications for 

public health and wellbeing. Coal plants are the leading source of SO2 emissions in the United 

States, with an average unit emitting between 7,000 (if controlled) and 14,000 (if uncontrolled)

tons per year.28 Once emitted into the atmosphere, SO2 forms PM2.5, or soot, which can cause 

asthma attacks, chronic obstructive pulmonary disease, stunted lung development, lung cancer, 

stroke, heart attack, and congestive heart failure.29 Fossil plants also emit PM2.5 and PM2.5 

precursors directly into the atmosphere, and while control technologies exist to limit these 

emissions, substantial emissions still result from the operation of well-controlled units.

Coal combustion is also a major source of NOx

30

, with a typical coal-fired plant emitting 

between 3,000 (if controlled) and 10,000 (if uncontrolled) tons per year.31 These compounds 

interact with volatile organic compounds (VOCs) in the presence of sunlight to form ground 

level ozone, a highly toxic and reactive pollutant. At times ozone can also interact with other 

atmospheric matter to form a smoky fog of deadly pollutants known as smog.32 SO2 and NOx

will travel great distances and react in the atmosphere to form very fine nitrate and sulfate 

particles. As components of the overall PM2.5 mix, these emissions cause significant pulmonary 

and cardiovascular ailments and lead to increased rates of missed work, hospitalization, and 

premature death.33 Furthermore, coal-fired EGUs are responsible for more than half of the 

human-made emissions of mercury, a dangerous neurotoxin that can lead to developmental 

 

26 NRC, Climate Stabilization Targets, supra n. 2, at 10.

27 IPCC, Climate Change 2014: Mitigation of Climate Change- Summary for Policymakers (2014), 

available at http://report.mitigation2014.org/spm/ipcc_wg3_ar5_summary-forpolicymakers_approved.pdf, at 13.

28 Union of Concerned Scientists (“UCS”), Environmental impacts of coal power: air pollution, 

http://www.ucsusa.org/clean_energy/coalvswind/c02c.html (last visited Nov. 12, 2014).

29 Id.; Lockwood, et al., Physicians for Social Responsibility, Coal’s Assault on Human Health (Nov. 2009), 

available at http://www.psr.org/assets/pdfs/psr-coal-fullreport.pdf, at vii-viii, x, and generally.

30 NOx refers to a mix of different oxides of nitrogen, primarily NO2 and NO3.

31 UCS, supra n. 28.

32 Lockwood, supra n. 29, at 10.

33 Id. at x, 10-11, 17, 24; see also RIA at 4-14—4-22.
7

delays and permanent cognitive impairment in fetuses and children.34 Finally, coal-fired plants 

that are not properly controlled can emit significant quantities of other hazardous air 

pollutants, including toxic heavy metals such as lead and cadmium, carbon monoxide, volatile 

organic compounds, and arsenic.35

All told, pollution from coal plants causes tens of thousands of premature deaths, 

emergency room visits, and heart attacks each year, and hundreds of thousands of asthma 

attacks.36 This amounts to over $100 billion in annual health care costs.37 EPA has issued 

regulations to reduce these emissions, but until we transition to genuinely clean energy, the 

lives and health of countless Americans remain at risk. 

Natural gas-fired power plants also emit significant amounts of conventional pollutants, 

especially NOx. Even with modern pollution controls, natural gas-fired power plants contribute 

to reduced air quality and harm public health. Older natural gas-fired plants with lower 

efficiencies and less effective pollution controls result in more significant environmental and 

health impacts. These harmful impacts are particularly acute for local communities that live in 

close proximity to power plants.

Any effort by EPA to reduce greenhouse gas emissions from power plants will 

necessarily reduce other harmful pollutants from fossil generators as well. The agency must 

take action to secure the health and wellbeing of the American public.

B. A Stringent Clean Power Plan Is Essential to Meet U.S. International Commitments.

The Clean Power Plan has important international implications. It is integral to achieving 

President Obama’s international commitment to reduce U.S. carbon emissions. President 

Obama’s recent pledge to achieve more ambitious GHG emission reductions by 2025 will 

require a stronger Clean Power Plan. Along with other federal GHG regulations, it will play a 

vital role in achieving the new emissions reduction target. A strong plan will bolster U.S. 

leadership as a leader on climate change and help strengthen its position in international 

climate negotiations. 

In its 2014 synthesis report, the IPCC warns that without immediate action to curb GHG

emissions, climate change will have dire and irreversible impacts worldwide.38 Climate change 

is no longer a distant threat, but is being felt around the globe, and immediate and significant 

carbon emission reductions are needed to curtail warming of the planet. “Science has spoken. 

 

34 Lockwood, supra n. 29, at 11, 30-32; UCS, supra n. 28.

35 UCS, supra n. 28.

36 Sierra Club, Fact Sheet: The Health Costs of Coal—It Isn’t Just Dirty, It’s Making Us Sick, available at 

http://vault.sierraclub.org/designarchive/factsheets/beyondcoal/106%20Coal%20Health/high106_coalh

ealth_factsht.pdf.

37 Id.

38 IPCC, 2014 Synthesis Report, supra n. 2.
8

There is no ambiguity in the message,” said U.N. secretary general, Ban Ki-moon at the report’s 

launch. “Leaders must act. Time is not on our side.”39

Despite mounting evidence of the dire consequences of inaction, U.S. action on climate 

change has been stymied on the congressional level for years, with failed cap-and-trade 

legislation in 2009 and continued resistance to all forms of action from lawmakers beholden to 

fossil fuel interests. This has left the U.S. in a precarious position in international climate 

negotiations. It has created the impression among other countries that the U.S. is not serious 

about climate change and has provided an excuse for them not to take ambitious action to 

reduce emissions themselves. 

President Obama has responded to the legislative gridlock by taking steps to address 

climate change through executive action. In Copenhagen in 2009, he pledged that the U.S. 

would reduce its GHG emissions in the range of 17 percent below 2005 levels by 2020.40 To 

achieve this goal, the Obama Administration has taken several important regulatory actions to 

reduce carbon emissions from different sources, including adopting new fuel economy 

standards for vehicles, proposing carbon pollution standards for new power plants and 

modified and reconstructed power plants, and proposing the Clean Power Plan for existing 

power plants.41

President Obama has also taken several steps to limit the use of hydrofluorocarbons 

(“HFCs”), which are potent greenhouse gases. In 2013, the U.S. and China agreed to work 

together to phase down the consumption and production of HFCs, and G-20 leaders followed 

by expressing support for the same. In early 2014, the U.S., Canada, and Mexico, submitted a 

 

39 Carrington, D., The Guardian, IPCC: rapid carbon emission cuts vital to stop severe impact of climate 

change (Nov. 2, 2014), available at http://www.theguardian.com/environment/2014/nov/02/rapidcarbon-emission-cuts-severe-impact-climate-change-ipcc-report.

40 Appendix I to the Copenhagen Accord, U.S. Quantified economy-wide emissions targets for 2020 (Jan. 

28, 2010), available at 

http://unfccc.int/files/meetings/cop_15/copenhagen_accord/application/pdf/unitedstatescphaccord_a

pp.1.pdf.

41 Kahn, D., California: Schwarzenegger, Brown rally climate activists and policymakers to influence Paris 

talks, Climatewire, (Sept. 8, 2014), available at

http://www.eenews.net/climatewire/stories/1060005373/feed. See generally 2017 and Later Model 

Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards, 

Final Rule, 77 Fed. Reg. 62,624 (Oct. 15, 2012); Standards of Performance for Greenhouse Gas Emissions 

from New Stationary Sources: Electric Utility Generating Units, Proposed Rule, 79 Fed. Reg. 1430 (Jan. 8, 

2014); Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility 

Generating Units, Proposed Rule, 79 Fed. Reg. 34,959 (June 18, 2014); and Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units, Proposed Rule, 79 Fed. Reg. 

34,830 (June 18, 2014).
9

North American proposal to amend the Montreal Protocol to impose limits on HFCs.42 The 

Montreal Protocol has been hugely successful in almost eliminating the use of 

chlorofluorocarbons (“CFCs”) and other man-made ozone-depleting chemicals that are also 

potent GHGs, but these chemicals have been replaced with HFCs, many of which are even more 

powerful climate forcers. Alternatives to HFCs that are not climate warming agents are now 

available, and EPA recently proposed two new rules under its Significant New Alternatives 

Policy (“SNAP”) program to phase out certain HFCs and promote safer alternatives.43

Additionally, in September 2014, President Obama announced new private sector 

commitments and executive actions to reduce emissions of HFCs.44 U.S. GHG emissions are

currently nine to ten percent below 2005 levels, and the U.S. is making significant progress 

towards meeting its Copenhagen commitment.

In November, President Obama and President Xi Jinping of China reached a 

groundbreaking agreement to limit greenhouse gas emissions, with China committing for the 

first time to cap carbon emissions and the U.S. pledging deeper emissions reductions through 

2025. In the agreement, President Xi Jinping pledged to cap China’s rapidly growing carbon 

emissions by 2030, or earlier if possible, and to increase the share of China’s energy mix derived 

from non-fossil fuel sources to 20 percent of the country’s energy mix. This will require China to 

deploy 800-1,000 gigawatts of non-fossil fuel-fired power, such as wind and solar, by 2030—

more than the generation capacity of all the coal-fired power plants that currently exist in China 

today and close to the total current electricity generation capacity in the U.S.45 President 

Obama announced a target to cut U.S. carbon emissions 26 to 28 percent below 2005 levels by 

2025, which represents significantly steeper reductions than the 2020 target the U.S. 

committed to in the Copenhagen Accord.46 The U.S.-China agreement has been well-received 

around the globe. European Union leaders indicated that the new commitments by China and 

the U.S. will provide an important boost to the climate negotiations in Paris in December 

 

42 U.S. EPA, Ozone Layer Protection, Recent International Developments Under the Montreal Protocol, 

2014 North American Amendment Proposal to Address HFCs under the Montreal Protocol, 

http://www.epa.gov/ozone/intpol/mpagreement.html (last visited Nov. 21, 2014). 

43 Protection of Stratospheric Ozone: Change of Listing Status for Certain Substitutes Under the 

Significant New Alternatives Policy Program, Proposed Rule, 79 Fed. Reg. 46126 (Aug. 6, 2014); 

Protection of Stratospheric Ozone: Listing of Substitutes for Refrigeration and Air Conditioning and 

Revision of the Venting Prohibition for Certain Refrigerant Substitutes, Proposed Rule, 79 Fed. Reg. 

38,811 (July 9, 2014).

44 The White House, Fact Sheet: Obama Administration Partners with Private Sector on New 

Commitments to Slash Emissions of Potent Greenhouse Gases and Catalyze Global HFC Phase Down, 

(Sept. 16, 2014), available at http://www.whitehouse.gov/the-press-office/2014/09/16/fact-sheetobama-administration-partners-private-sector-new-commitments-.

45 The White House, Fact Sheet: U.S.-China Joint Announcement on Climate Change and Clean Energy 

Cooperation, (Nov. 11, 2014), available at http://www.whitehouse.gov/the-pressoffice/2014/11/11/fact-sheet-us-china-joint-announcement-climate-change-and-clean-energy-c.

46 Id.; Lederman, J., U.S., China Unveil Ambitious Climate Change Goals, U.S. News & World Report (Nov. 

11, 2014), available at http://www.usnews.com/news/articles/2014/11/11/china-and-us-unveilambitious-climate-change-goals. 
10

2015,47 where nations will negotiate an international agreement on greenhouse gas emission 

reduction targets that will come into effect after 2020.48 The European Council has already 

committed to a binding target for the EU of at least a 40 percent reduction in greenhouse gas 

emissions by 2030 compared to 1990 levels.49 In October 2014, the Council called on all 

countries in the EU to develop ambitious greenhouse gas emissions reduction targets and 

policies well in advance of the Paris Conference.50 With the U.S., China, and Europe - the 

world’s top three emitters of greenhouse gases - leading the way, other countries will be more 

likely to follow suit. Commitments from the U.S., China, and the EU give other nations an 

incentive to set their own reduction targets in preparation for international climate 

negotiations in December 2015. The U.S.-China agreement also positions the U.S. well for this 

year’s Conference of the Parties in Lima, Peru, where negotiators will prepare the text of the 

climate agreement that will be finalized in Paris.

President Obama has also pledged $3 billion to the Green Climate Fund to help the most 

vulnerable nations reduce their emissions and adapt to climate change. Several other countries 

have also pledged significant funds, with the total reaching $9.3 billion at a recent conference in 

Berlin (closing in on a $10 billion minimum target for 2014). The fund is designed to help those 

countries least to blame for climate change that are being disproportionately impacted by its 

consequences, and will be dispersed over four years starting in 2015. This action represents a 

positive step towards a meaningful international climate agreement, and will help diffuse 

tensions between developed and developing nations that have complicated negotiations in the 

past.51

 

47 Nakamura & Mufson, China, U.S. agree to limit greenhouse gases, Washington Post (Nov. 12, 2014), 

available at http://www.washingtonpost.com/business/economy/china-us-agree-to-limit-greenhousegases/2014/11/11/9c768504-69e6-11e4-9fb4-a622dae742a2_story.html.

48 Langley & Roberts, The International Implications of the New EPA Clean Power Plan Proposed Rule, 

Brookings, (June 4, 2014), available at 

http://www.brookings.edu/blogs/planetpolicy/posts/2014/06/04-implications-epa-clean-power-planlangley-roberts.

49 1990 U.S. greenhouse gas emissions levels are considerably lower than 2005 U.S. levels--6,183 

compared to 7,195 million metric tons of CO2e. See EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990-2011, EPA 430-R-13-001 (Apr. 12, 2013), available at

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf, 

at Figure ES-1. 

50 European Council, Remarks by President Herman Van Rompuy following the first session of the 

European Council (Oct. 23, 2014); European Council, Conclusions on 2030 Climate and Energy Policy 

Framework (Oct. 23 and 24, 2014). 

51 Goldenberg, S., Obama’s $3bn for climate fund could kickstart action on global warming, The Guardian 

(Nov. 14, 2014), available at http://www.theguardian.com/environment/2014/nov/14/obamas-3bnclimate-fund-could-kickstart-action-global-warming; Countries pledge $9.3bn for Green Climate Fund, 

The Guardian (Nov. 20, 2014), available at 

http://www.theguardian.com/environment/2014/nov/20/countries-pledge-93bn-for-green-climatefund.
11

The Clean Power Plan will play a critical role in meeting the U.S. target for more 

stringent GHG emission reductions and provide an incentive for other countries to reduce their 

carbon pollution. With President Obama’s latest commitment, carbon emissions reductions in 

the early years of the Clean Power Plan’s proposed compliance period will be essential. A

stronger Clean Power Plan is essential to assure that the U.S. reaches its international climate 

targets for 2020 and 2025. Yet industry and several states are advocating for a more gradual 

“glide path” that would give utilities additional years to start achieving the reductions from 

Building Blocks 1 and 2. States are already given significant flexibility because they are allowed 

to use averaging over the entire compliance period. Delaying the phase-in of Blocks 1 and 2 

would weaken EPA’s proposed interim targets, and delay long needed carbon pollution 

reductions. The interim targets should not be relaxed, but strengthened and, indeed 

accelerated. As discussed below, the Clean Power Plan’s compliance deadline should end in 

2025 and the agency should revise and strengthen the standard afterwards. Not only is a 

stronger Clean Power Plan needed to help meet the more ambitious 2025 target that the U.S. 

has agreed to achieve, but a commitment to early reductions is also vital to U.S. credibility and 

leverage over the critical next 12 months. 

According to the United Nations Environment Programme’s 2014 Emissions Gap Report, 

even with the U.S., China, and EU’s recent pledges to limit GHG pollution, the world is not on 

track to achieving the emissions reductions needed to keep global temperature increases below 

2 degrees Celsius above preindustrial levels by 210052 and avoid the worst impacts of a 

changing climate.53 Further immediate action, such as heavy investments in renewable energy 

and energy efficiency,54 is needed to keep global average temperature rise below the 

internationally agreed 2 degrees Celsius goal to avoid the most devastating consequences of 

climate change. Moreover, a strong Clean Power Plan alone will not be enough to achieve the 

reductions set out in the U.S.’ pledge;

55 other federal regulatory standards being implemented 

under the Obama Administration will play an important role in significantly reducing GHG

pollution. The proposed regulations limiting carbon emissions from new and existing power 

plants, combined with other regulatory actions, such as the new fuel economy standards for 

vehicles, mercury and air toxics standards, ozone standards, initiatives to reduce methane 

emissions from the oil and gas industry, and efforts to boost energy efficiency and renewable 

energy standards at the state level, are all needed to achieve the Obama administration’s 

pledge, cement US leadership, and help keep global temperature rise below the internationally 

agreed 2 degree Celsius goal.

 

52 See generally United Nations Emission Program (“UNEP”), The Emissions Gap Report 2014: A UNEP 

Synthesis Report (Nov. 2013), available at 

http://www.unep.org/publications/ebooks/emissionsgapreport2014/.

53 International parties agreed to this temperature rise limit at the Cancun Climate Change Conference in 

November 2010. See United Nations Framework Convention on Climate Change, Cancun Climate Change 

Conference – November 2010, http://unfccc.int/meetings/cancun_nov_2010/meeting/6266.php (last 

visited Nov. 30, 2014).

54 See UNEP, supra n. 52, at Ch. 4.

55 Id. at Ch. 3, p. 31.
12

The greenhouse gas emissions reductions required to meet the more stringent 2025 

targets are achievable with the implementation of a stringent Clean Power Plan in combination 

with other critical federal regulatory actions.

C. The Clean Power Plan Reinforces Ongoing Changes in the Utility Sector.

A key aspect of EPA’s Clean Power Plan proposal is that it will exert regulatory pressure 

in the same direction toward which the utility sector is already swiftly moving. Indeed, it is 

difficult to overstate the transformation that U.S. energy markets have undergone in recent

years. Most significantly, the U.S. is decisively shifting away from coal as the primary generation 

source of base-load electricity, a trend that is evident in the most recent data.56 The U.S. has

seen older and less-efficient existing coal-fired power plants continuing to retire since 2012 due 

to increased competition with other generating resources and impending environmental 

regulations. Between 2008 and 2013, U.S. utilities retired approximately 20 GW of coal-fired 

capacity,57 with approximately 11.3 GW retired in 2012 alone.58 As of November, 2014, utilities 

had announced firm plans to retire some 75 GW of coal-fired generating capacity (or to convert 

it to natural gas) by 2021.59 And according to a recent market study, a further 17 GW is “at risk” 

of retirement due to competition with low-cost natural gas.60 As coal-fired capacity has 

declined, so has generation from the coal-fired fleet: in 2013, coal-fired EGUs accounted for 

39.1 percent of U.S. generating output—slightly higher than the low of 37.4 percent reached in 

2012, but still representing a 20 percent decline in market share since 2006.61

The decline in U.S. reliance on its coal generation has coincided with rapid domestic 

expansion of zero- and lower-carbon generating unit development and electricity generation.

For example, April 2013 saw a record amount of electricity generated from U.S. wind resources 

of over 17,000 GWh—nearly as much wind-generated electricity produced in one month as U.S. 

wind resources delivered in all of 2005.62 From 2011 to 2013, electricity delivered to the grid 

from wind generators increased by at least 28 percent (from a total of 120,177 GWh in 2011, to 

 

56 EIA, AEO2014 Early Release Overview (Dec. 16, 2014), available at

http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2014).pdf (hereinafter “AEO2014 Early Release”), at 

2, Fig. 3.

57 NERC, 2013 Long-Term Reliability Assessment (Dec. 2013), available at

http://www.nerc.com/pa/RAPA/ra/Reliability Assessments DL/2013_LTRA_FINAL.pdf, at 35.

58 EIA, Electric Power Annual, Table 4.6 (Dec. 2013), available at 

http://www.eia.gov/electricity/annual/pdf/epa.pdf.

59 Gilbert & Gelbaugh, Coal Under Fire: Assessing Risk Factors and Market Impacts for Upcoming Coal 

Retirement Decisions (SNL Energy, Dec. 2013); see also Appendix A.

60 Id.

61 EIA, Short-Term Energy Outlook (Jan. 2014), at 21, available at

http://www.eia.gov/forecasts/steo/archives/Jan14.pdf. 

62 EIA, Electric Power Monthly (Feb. 2014), Table 1.1.A, available at 

http://www.eia.gov/electricity/monthly/current_year/february2014.pdf.
13

a total of 167,665 GWh in 2013).63 Similarly dramatic has been the expansion of solar energy, 

which increased in generation capacity by 418 percent between 2010 and 2014.64 The lead 

solar industry association forecasts that at current prices, it will take only two years to install 

the next 20 gigawatts of solar capacity, compared to the 40 years it took to install the first 20 

gigawatts.65 2014 solar capacity installations are nearly double those of 2013.66 Energy 

efficiency also grew rapidly during this period: utility and private spending on energy efficiency 

investments increased to over $12 billion in 2012,67 and in 2011, first-year energy savings 

reported by utilities totaled 22 million MWh—an increase of approximately 22 percent yearover-year.68

Looking ahead, forecasts indicate that the shift from coal to cleaner sources of energy 

will continue. For example, EIA predicts in its Annual Energy Outlook 2014 Early Release 

Overview that total domestic coal-fired capacity will decrease by over 15 percent from 2012 to 

2040.69 EIA attributes this trend to slower growth in electricity demand, competition from zeroand low-carbon resources,70 and economic changes resulting from more stringent 

 

63 Id.

64 EIA, Electricity Monthly Update (Apr. 2014), available at 

http://www.eia.gov/electricity/monthly/update/archive/april2014/.

65 See Opening Remarks by Rhone Resch, President and CEO, Solar Energy Industries Association, at Solar 

Power International 2014 (Oct. 20, 2014), available at http://www.seia.org/news/rhone-resch-openingremarks-spi-2014.

66 See EIA, Electric Power Monthly – August 2014, Table 1.1.A. Net Generation from Renewable Sources: 

Total (All Sectors), 2004-August 2014 (Year to Date), available at 

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_1_01_a.

67 Business Council on Sustainable Energy, 2014 Sustainable Energy in America Factbook (Feb. 2014), 

attached as Ex. 1, at 4.

68 American Council for an Energy–Efficient Economy, 2013 State Energy Efficiency Scorecard (Nov. 

2013), attached as Ex. 2, at 30.

69 AEO2014 Early Release, supra n.56 at 14.

70 EIA defines “renewable energy” as “energy resources that are naturally replenishing but flow-limited. 

They are virtually inexhaustible in duration but limited in the amount of energy that is available per unit 

of time. Renewable energy resources include biomass, hydro, geothermal, solar, wind, ocean thermal, 

wave action, and tidal action.” EIA, Glossary, http://www.eia.gov/tools/glossary/(last visited Nov. 30, 

2014). Notably, while many of these generating choices are zero carbon-emitting, unfortunately all 

biomass-fueled energy cannot be assumed to be “carbon neutral” or zero-emitting, or even low carbonemitting in some instances. For example, burning chipped whole trees to generate electricity has the 

same or higher tons CO2/MWh output as burning coal. See, e.g., Manomet Center for Conservation 

Sciences, Massachusetts Biomass Sustainability and Carbon Policy Study, Report to the Commonwealth 

of Massachusetts Department of Energy Resources (Walker, ed.) (National Capital Initiative Report No. 

NCI-2010-03) (2010), available at http://www.mass.gov/eea/energy-utilities-clean-tech/renewableenergy/biomass/biomass-sustainability-and-carbon-policy-study.html (demonstrating using modeling 

that the combination of greater carbon emissions per unit energy from biomass than fossil fuels, 

combined with the lost forest carbon sequestration associated with additional fuel harvesting, produce 

net CO2 emissions that greatly exceeded those from fossil fuels—a “carbon debt” that takes decades to 

more than a century to pay off).
14

environmental regulations.71 Similarly, NERC anticipates that 31.5 GW of net coal-fired capacity 

will retire by 2023.72

EPA notes in the preamble to the proposed rule that as coal-fired plants retire, current 

power sector economics suggest that they will likely be replaced with new renewable projects, 

energy efficiency savings, and combined cycle gas generation. Most of these new lower 

emitting electricity sources currently have much lower construction and operating costs than 

coal-fired EGUs,73 and this trend is also likely to continue in the coming years.74 As a result of 

these cost disparities, EIA’s latest Annual Energy Outlook forecasts only 2.5 GW of additional 

planned coal-fired generating capacity through 2040, with nearly 90 percent of this capacity 

consisting of projects that are already under way.75 Similarly, the International Energy Agency 

(“IEA”) World Energy Outlook 2013 predicts that over three-quarters of the capacity 

replacements for retired units in the U.S. will come from wind, solar, or NGCC units. EIA also 

expects generation from renewables to be higher than was estimated in 2013 across most of 

the projection period,76 with renewable sources accounting for almost a third of the growth in 

generation resources from 2012 to 2040 as they become more cost-competitive with other 

fuels.77 Indeed, EIA projects that renewables will remain the fastest-growing source of electric 

generation through 2040.78

In sum, the shift in the electricity generating sector from coal to lower-emitting 

resources has continued at a rapid pace in recent years, and forecasts of fuel costs, capital 

costs, and other power sector trends continue to indicate that conventional coal-fired power 

plants will represent a shrinking percentage of generation over the foreseeable future. In this 

sense, the Clear Power Plan largely reflects changes that are already happening in the electric 

sector, as do the individual state targets included in the proposal. For instance, Washington’s 

emission target for 2030 is 215 lbs CO2/MWh—ostensibly, a very low number—but this simply 

represents the fact that all but one of Washington’s coal plants have already retired, with the 

 

71 AEO2014 Early Release, supra n.56 at 14. The Reference case includes implementation of MATS and 

CAIR, as well as market concerns about GHG emissions, which dampen the expansion of coal-fired 

capacity. Id.

72 NERC, supra n. 56 at 10.

73 EIA, Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants (Apr. 2013), available 

at http://www.eia.gov/forecasts/capitalcost/, at 6 (reporting that even the lowest-cost coal-fired EGU 

configuration has capital costs that are nearly three times higher than an advanced NGCC and 33 

percent higher than onshore wind on a per-kW basis).

74 AEO2014 Early Release, supra n. 56 at 14.

75 EIA, Annual Energy Outlook 2014 (May 2014) available at http://www.eia.gov/forecasts/AEO/, at 

Table A9; see also 79 Fed. Reg at 1,478.

76 Id. at 15.

77 Id. at 14. 

78 Id. at Table A8 (showing average annual growth of 1.7 percent for renewable generation through 

2040).
15

remaining facility announced for retirement.79 EPA’s proposal will therefore advance the pace 

at which the electric sector is changing, but will not fundamentally alter the direct of that 

change.

II. The Clean Air Requires EPA To Regulate CO2 Emissions from Fossil-Fuel Fired Power 

Plants Under Section 111(d)

A. EPA’s Reasonable Interpretation of Section 111(d) Merits Judicial Deference

EPA’s Legal Memorandum correctly describes the history of the different House and 

Senate-enacted versions of §111(d)(1).80 The House version (which is the version presented in 

the U.S. Code) provides for standards of performance for existing sources “for any air pollutant 

(i) [1] for which air quality criteria have not been issued or which is not included on a list 

published under [CAA section 108(a)] or [2] emitted from a source category which is regulated 

under [section 112].” Because power plants are a source category regulated under section 112 

for mercury and other hazardous air pollutant (“HAP”) emissions, see 77 Fed. Reg. 9,304 (Feb. 

16, 2012) (final Mercury and Air Toxics [“MATS”] rule), some industry groups have argued that 

the foregoing language precludes EPA from issuing section 111(d) performance standards of 

performance for emissions of any pollutants (including CO2) from existing power plants. The 

Senate version, which also appears in the enacted (i.e., Statutes at Large) version of the 1990 

amendments, requires standards of performance “for any air pollutant . . . which is not included 

on a list published under section 108(a) or 112(b) (1)(A)” of the Act. 

In the Legal Memorandum, EPA correctly concludes that the enactment of these 

conflicting versions creates an ambiguity that EPA is authorized to resolve under step 2 of the 

test articulated in Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 842-844 (1984).81 The agency then 

offers a reasonable interpretation of the provisions as together excluding from regulation under 

section 111(d) not all pollutants, but only and specifically HAPs that are both listed under 

section 112(b) and emitted by sources (such as power plants) that are regulated under section 

112.82 Under EPA’s construction, therefore, the agency may not regulate power plant mercury 

emissions under section 111(d), since mercury is a listed HAP and power plants are regulated 

under section 112 by the MATS rule, but it must regulate power plant CO2 emissions under 

section 111(d), since CO2 is not a HAP listed under section 112(b), notwithstanding the MATS 

rule. 

 

79 See TransAlta, Centrallia, http://www.transalta.com/us/2011/10/centralia-wa/ (last visited Nov. 21, 

2014).

80 EPA, Legal Memorandum for Proposed Carbon Pollution Emission Guidelines for Existing Electric Utility 

Generating Units (June 2014), available at http://www2.epa.gov/sites/production/files/2014-

06/documents/20140602-legal-memorandum.pdf, at 20-27.

81 Id. at 25.

82 Id. at 26-27.
16

EPA’s proposed construction is consistent with the context and evolution of section 

111(d), and it is necessary to consider the 1990 Clean Air Act Amendments against this legal 

backdrop. See McFarland v. Scott, 512 U.S. 849, 856 (1994) (“Congress legislated against this 

legal backdrop . . . and we safely assume that it did not intend for the express requirement of 

counsel to be defeated in this manner”). Historically, section 111 has served a gap-filling 

function to ensure that EPA had a mechanism to regulate dangerous air pollutants that were 

not already covered under the criteria pollutant or HAP programs. Prior to the 1990 

Amendments, the HAP exclusion under section 111(d) applied only to pollutants “not included 

on a list published under”§112”—not to categories of sources that emitted those pollutants. 42 

U.S.C. §7411(d)(1)(1977); Public Law 95-95. There is nothing in the structure or history of the 

1990 Amendments to suggest that Congress meant to drastically broaden that exclusion, which 

has always functioned simply to ensure that EPA’s section 111(d) rules do not encompass 

pollutant emissions already subject to regulation under Act’s criteria pollutant or air toxics 

provisions for existing sources. EPA is therefore well within its authority to interpret the 

Amendments as preserving the function and scope of section 111(d) that existed prior to 1990, 

and is correct to interpret the statute to permit regulation of CO2 emissions from existing EGUs 

under section 111(d).

B. The Industry Interpretation of Section 111(d) Is Textually and Logically Flawed, and 

Must Be Rejected.

Far from signaling an intent to dramatically alter the statute by greatly restricting (or, 

indeed, erasing) the scope of section 111(d), the structure and context of the 1990 

Amendments signal the opposite concern: that EPA was not proceeding diligently enough to 

limit harmful air pollution. Indeed, in rejecting an interpretation put forth by some industry 

advocates that would prevent EPA from regulating under section 111(d) all "HAP or non-HAP 

emitted from a source category regulated under section 112," EPA has affirmed that

[s]uch a reading would be inconsistent with the general thrust of the 1990 

amendments, which, on balance, reflects Congress’ desire to require EPA to 

regulate more substances, not to eliminate EPA’s ability to regulate large 

categories of pollutants like non-HAP. Furthermore, EPA has historically 

regulated non-HAP under section 111(d), even where those non-HAP were 

emitted from a source category actually regulated under section 112. See, e.g., 

40 CFR 62.1100 (California State Plan for Control of Fluoride Emissions from 

Existing Facilities at Phosphate Fertilizer Plants). We do not believe that Congress 

sought to eliminate regulation for a large category of sources in the 1990 

Amendments and our proposed interpretation of the two amendments to 

section 111(d) avoids this result.

70 Fed. Reg. 16,032 (Mar. 29, 2005) (footnote omitted).

Moreover, the Supreme Court has held that, where dealing with conflicting statutory 

provisions, it is appropriate to adopt a construction that is “more consonant with the functions 
17

sought to be served by the Act” and that does not “impute to Congress a purpose to paralyze 

with one hand what it sought to promote with the other.” Clark v. Uebersee Finanz-Korp, 332 

U.S. 480, 489 (1947); see also Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. Ruckelshaus, 719 F.2d 

1159, 1165 (D.C.Cir.1983) (“A statute should ordinarily be read to effectuate its purposes rather 

than to frustrate them.”). Here, the ends that the Act seek to advance are the protection of 

public health and welfare from air pollution, a goal clearly disserved by an interpretation that 

would bar EPA from curbing harmful CO2 pollution under section 111(d). 42 U.S.C. §7401(b)(1). 

To read the statute as foreclosing existing-source standards of performance for any pollutant 

emitted by a source category regulated under section 112 would, as a practical matter, render 

section 111(d) inoperative as to virtually all pollutants, since the sources regulated under 

section 112 emit virtually every pollutant imaginable that might be subject to section 111(d) 

standards. The industry reading would thwart the Act's—and section 111's—core purpose of 

protecting public health and welfare, see §§7401(b)(1), 7411(b)(1)(A), since it would allow 

entire classes of pollutants (in this case, CO2) to go unregulated, no matter how harmful to the 

public health and welfare they may be. To imply that Congress gave EPA the choice of 

regulating power plant emissions of either CO2 or mercury, but not both, makes a mockery of 

the statute and its goal of protecting the public health and welfare.

The industry reading of section 111(d) would not even serve the purpose that some

industry advocates have attributed to it—avoiding duplicative regulation of pollutants that are 

already being regulated under sections 108 or 112—because CO2 is not being regulated under 

either of those two other sections. Thus, the net result of such a misguided reading would be 

no regulation of CO2 emissions from existing power plants under any Clean Air Act program. To 

allow such a harmful pollutant to fall through the regulatory cracks based on the mere fortuity 

that EPA has decided to control emissions of some other pollutant from that source not only 

contravenes the Act's and section 111’s health-and-welfare protective purpose, but also makes 

no sense. Time and again, the Supreme Court has declined to interpret statutes—including the 

Clean Air Act—in such a fashion. See e.g., Engine Mfrs. Assn. v. South Coast Air Quality 

Management District, 541 U.S. 246, 255 (2004) (rejecting reading that "would make no sense"); 

Desert Citizens Against Pollution v. EPA, 699 F.3d 524, 527-28 (D.C. Cir. 2012) (EPA permissibly 

rejected interpretation that "would have the anomalous effect of changing the required 

stringency of non- § 112(c)(6) HAPs at a given area source . . . simply on the fortuity that the 

non-§ 112(c)(6) HAPs in question shared a source with one or more § 112(c)(6) HAPs") 

(emphasis added); Roberts v. Sea-Land Services, 132 S. Ct. 1350, 1359-60 (2012) ("Under 

Roberts' reading, two employees who earn the same salary and suffer the same injury on the 

same day could be entitled to different rates of compensation based on the happenstance of 

their obtaining orders in different fiscal years. We can imagine no reason why Congress would 

have intended, by choosing the words “newly awarded compensation,” to differentiate 

between employees based on such an arbitrary criterion.").

The industry reading also ignores clear statutory evidence that Congress intended 

sections 111 and 112 to work in unison, not disharmony. Congress expressly directed that the 

source categories to be regulated under section 112 be consistent with the list of source 

categories regulated under section 111. 42 U.S.C. §7412(c)(1). This cross-reference would serve 
18

no purpose if Congress had intended that HAP regulations under section 112 would prohibit 

EPA from regulating any and all emissions, HAP and non-HAP alike, from those sources under 

section 111(d). In this regard—and in effectively dismantling an entire Clean Air Act program—

the industry reading would contravene the fundamental canon that statutes are to be 

construed to give all words and provisions effect. See, e.g., Northwest Austin Mun. Utility Dist. 

No. One v. Holder, 557 U.S. 193, 211 (2009) (rejecting statutory interpretation that would 

render a provision “all but a nullity . . . It is unlikely that Congress intended the provision to 

have such limited effect.”) (citation omitted); TRW v. Andrews, 534 U.S. 19, 29, 31 (2001) 

(rejecting reading that would “in practical effect" render statutory provision “entirely 

superfluous in all but the most unusual circumstances . . . . It is a cardinal principle of statutory 

construction that a statute ought, upon the whole, to be so construed that, if it can be 

prevented, no clause, sentence, or word shall be superfluous, void, or insignificant. Were we to 

adopt Andrews' construction of the statute, the express exception would be rendered 

insignificant, if not wholly superfluous.”) (citations and internal quotation marks omitted); 

Mayle v. Felix, 545 U.S. 644, 662 (2005) (rejects reading under which statutory limitations 

period “would have slim significance”). Along these same lines, the industry reading would 

effectively treat the 1990 Amendments as an implied repeal of section 111(d). Courts generally 

reject claims of implied repeal, and will only accept them when there is “overwhelming 

evidence” and “when the earlier and later statutes are irreconcilable.” E.M. AG Supply v. 

Pioneer Hi-Bred International, 534 U.S. 124, 137, 141-42 (2001) (citations and internal quotation 

marks omitted). Neither condition applies in this instance.

Nor is there any evidence that Congress meant to strip section 111(d) of its utility in 

such a cryptic manner. If Congress had meant to significantly restrict the applicability of section 

111(d)(1), it would have said so clearly. See Board of Trustees v. Roche Molecular Systems, 131 

S. Ct. 2188, 2198-99 (2011) (“[I]f Congress has intended such a sea change . . . it would have 

said so clearly”); Whitman v. Am. Trucking Ass’ns, 531 U.S. 457, 468 (2001) (“Congress . . . does 

not alter the fundamental details of a regulatory scheme in vague terms or ancillary provisions -

- it does not, one might say, hide elephants in mouseholes.”). This point is particularly salient in 

the case of the 1990 Clean Air Act Amendments, which were universally understood to tighten, 

not loosen, the statute’s pollution control measures. See, e.g., Remarks of President Bush Upon 

Signing S. 1630, 26 Weekly Comp. Pres. Doc. 1824 (Nov. 19, 1990) (reprinting the President’s 

signing statement of Nov. 15, 1990) (“This legislation isn’t just the centerpiece of our 

environmental agenda. It is simply the most significant air pollution legislation in our nation’s 

history, and it restores America’s place as the global leader in environmental protection.”). To 

assert that a landmark bill praised for its environmental stringency actually eviscerates key 

provisions of the statute sub silentio borders on the absurd, and EPA is correct to reject this 

flawed reasoning in favor of a construction that actually advances the statute’s goals. See 

Griffin v. Oceanic Contractors, Inc., 458 U.S. 564, 575 (“[I]nterpretations of a statute which 

would produce absurd results are to be avoided if alternative interpretations consistent with 

the legislative purpose are available.”); American Water Works Assn v. EPA, 40 F.3d 1266, 1271 

(D.C. Cir. 1994) (where reading of statute would lead to absurd results, statute has no plain 

meaning and is proper subject of construction by agency and courts).
19

In short, given the conflicting amendments, EPA is authorized to adopt a reasonable 

interpretation of the statute. Northeast Hosp. Corp. v. Sebelius, 657 F.3d 1, 11 (D.C. Cir. 2011) 

("We are thus faced with two inconsistent sets of statutory provisions. Northeast points us to 

provisions that tie entitlement to payment and state that once a person enrolls in Part C, 

payments are no longer made under Part A. The Secretary points us to other provisions that 

assume it is possible to be both entitled to benefits under Part A and enrolled in Part C. Under 

these circumstances, we conclude that the Medicare statute does not unambiguously foreclose 

the Secretary's interpretation."); Chevron, 467 U.S at 842-43. And, for reasons stated above, 

EPA's interpretation comports with the context, history, structure, and purpose of the Clean Air 

Act. As such, its construction should merit judicial deference in any legal proceeding challenging 

its authority to regulate CO2 emissions from existing EGUs under section 111(d).

C. EPA’s Interpretation of Section 111(d) is Proper In Any Event.

Alternatively, if the 1990 House and Senate language were to be deemed in 

irreconcilable conflict (i.e., if the conflicting amendments cannot both be given literal effect, 

and if EPA lacks authority to adopt a reasonable interpretation to resolve the conflict), then 

both chambers’ 1990 amendments to section 111(d) must fail. In that scenario the language 

would revert to the pre-1990 version, which authorizes §111(d) regulation of any air pollutant 

"for which air quality criteria have not been issued or which is not included on a list published 

under section 7408(a) or 7412(b)(1)(A) of this title.” Since CO2 are listed neither under §7408(a) 

nor §7412(b), under this scenario as well EPA would be authorized to promulgate section 

111(d) guidelines for power-plant CO2 emissions.

Finally, even if the House amendment were deemed to be the only applicable 

amendment, the same outcome should obtain. First, the Supreme Court has recently noted 

EPA's practice of adopting context-appropriate interpretation of the Clean Air Act phrase "air 

pollutant." Utility Air Regulatory Group v. EPA (“UARG”), 134 S. Ct. 2427, 2439-42 (2014). For 

example,

[t]he Act authorizes EPA to enforce new source performance standards (NSPS) 

against a pre-existing source if, after promulgation of the standards, the source 

undergoes a physical or operational change that increases its emission of “any 

air pollutant.” § 7411(a)(2), (4), (b)(1)(B). EPA interprets that provision as limited 

to air pollutants for which EPA has promulgated new source performance 

standards. 36 Fed.Reg. 24877 (1971), codified, as amended, 40 C.F.R. § 60.2; 40 

Fed.Reg. 58419 (1975), codified, as amended, 40 C.F.R. § 60.14(a).

Id. 2440 (emphasis in original). Similarly here, a context-appropriate reading of "any air 

pollutant," when used with the phrase "emitted from a source category which is regulated 

under section 7412," would encompass only an air pollutant listed under section 112 that is 

emitted from such a source category. 
20

Considered from another angle, sources are not regulated in the abstract, but regulated 

with regard to specific pollutants. Hence, any interpretation of the phrase “regulated under 

section 7412” must include an implied phrase indicating what the source in question is being 

regulated with regard to. Under the industry interpretation, this implied phrase is “with regard 

to any pollutant,” i.e., “emitted from a source category which is regulated under section 7412 

[with regard to any pollutant].” A much more rational interpretation would include the implied 

phrase “with regard to HAPs,” i.e., “emitted from a source category which is regulated under 

section 7412 [with regard to any HAPs],” which not only effectuates rather than frustrates the 

purpose of the statute, as discussed above, but accords with the kind of contextuallyappropriate reading of the statute described in UARG.

An examination of the historical context surrounding the House language militates in 

the same direction. Prior to the 1990 Amendments, EPA had been tasked with listing hazardous 

air pollutants for regulation under section 112. The pre-1990 language of section 111(d) 

reflected this fact insofar as it referenced the “list published under section . . . 7412(b)(1)(A).” 

Frustrated with the agency’s slow progress on this front, Congress took it upon itself to list 190 

HAPs by statute and then delegated to EPA the authority and responsibility to regulate 

emissions of those HAPs on a source-by-source basis. It is for this reason that the House 

amendment deleted the pre-1990 references to the list of HAPs, which was now defined by 

statute rather than EPA regulation, and replaced it with a reference to source categories, which 

were now the subject of EPA regulation for the HAP emissions. Given this historical context, it is 

clear that the House language was meant to preserve the status quo, under which EPA could 

not regulate a source’s HAP emissions under section 111(d) if it was already doing so under 

section 112, rather than silently introduce a new and massive exclusion into the statute that 

effectively rendered section 111(d) a dead letter.

Second, the literal language of the House amendment favors EPA’s interpretation of the

statute. As EPA recently observed in a legal brief opposing the industry interpretation of section 

111(d), 

even if one disregards the Senate amendment and considers only the House 

amendment, as Petitioner and amici advocate, that text does not unambiguously 

say what Petitioner and amici believe it says. In fact, a truly “literal” reading (see 

Amici Br. at 4) results in precisely the opposite conclusion.83

The relevant portion of section 111(d), as amended by the House, contains a string of three 

exclusionary clauses, separated from each other by “or”: 

The Administrator shall prescribe regulations . . . under which each State shall 

submit to the Administrator a plan which establishes standards of performance

for any existing source for any air pollutant [1] for which air quality criteria have 

not been issued or [2] which is not included on a list published under section 

 

83 Response to Petition at 28, In re: Murray Energy Corp., No. 14-1112 (D.C. Cir. Nov. 3, 2014).
21

7408(a) of this title or [3] emitted from a source category which is regulated 

under section 7412 of this title . . . .

42 U.S.C. § 7411(d)(1) (emphasis and internal numbering added). Because Congress used the 

conjunction “or” rather than “and,” the three exclusions arguably should be viewed as 

alternatives, rather than requirements to be imposed simultaneously. See U.S. v. Woods, 134 

S.Ct. 557, 567 (2013) (“Moreover, the operative terms are connected by the conjunction “or.” 

While that can sometimes introduce an appositive . . . its ordinary use is almost always 

disjunctive, that is, the words it connects are to ‘be given separate meanings.’”).84 In other 

words, section 111(d) “literally” provides that the Administrator may require states to establish 

standards for an air pollutant so long as either air quality criteria have not been established for 

that pollutant, or one of the other two remaining criteria is met. Air quality criteria have not 

been issued for CO2. Thus, under a truly literal reading of section 111(d)(1) as amended by the 

House, whether power plants have been regulated under section 7412—and for what 

pollutant—is irrelevant: the CO2 regulations at issue are authorized.

To compound the ambiguity, the third exclusionary clause in the House’s version of 

section 7411(d)(1), which provides the basis for the industry interpretation of section 111(d), 

differs from the first two in that it does not contain a negative:

[EPA may require states to submit plans establishing standards for] any air 

pollutant [1] for which air quality criteria have not been issued or [2] which is not

included on a list published under section 7408(a) of this title or [3] emitted from 

a source category which is regulated under section 7412 of this title . . . .

42 U.S.C. § 7411(d)(1) (emphasis and internal numbering added). The industry argument 

presumes that the negative from the second clause was intended to carry over into the third 

(i.e., implicitly inserting another “which is not” before “emitted from a source category”), but 

that is not what the text actually says; instead, it states that EPA may require standards for “any 

air pollutant . . . emitted from a source category which is regulated under section 7412.” 42 

U.S.C. § 7411(d)(1). Thus, read literally, the House’s version of section 7411(d) means the exact 

opposite of what petitioners and amici argue, and provides that EPA may regulate emissions of 

a pollutant from a source category where that category is regulated under section 7412. Other 

observers have made this argument as well:

As amended by the House amendment language, §111(d) would direct EPA to 

regulate, through state plans, “any air pollutant (i) for which air quality criteria 

have not been issued or which is not included on a list published under Section 

7408(a) of this title or emitted from a source category which is regulated under 

 

84 Merriam Webster’s Dictionary defines “or” as “a function word [used] to indicate an alternative 

<coffee or tea> <sink or swim>.” See Merriam Webster, Definition of “Or,” 

http://www.merriamwebster.com/dictionary/or (last visited Nov. 19, 2014).
22

Section 7412 of this title . . . .” The use of the conjunction “or” to join the two 

“which” clauses in (i) is most naturally read such that only one of the “which” 

conditions must be met in order for EPA to have regulatory authority under 

§111(d). This reading would provide EPA authority to regulate an existing source 

for any air pollutant that is not a criteria pollutant, regardless of the meaning of 

the “or emitted” clause that is the subject of the two competing 1990 CAA 

Amendments.85

As discussed above, the history, purpose, and structure of the Clean Air Act, of the 1990 

Amendments, and of section 111(d) all persuasively show that EPA may regulate CO2 emissions 

from existing EGUs under section 111(d). Accordingly, under any acceptable heuristic, the Clean 

Power Plan is an appropriate exercise of EPA’s authority under that provision of the statute and 

is on firm legal footing.

III. EPA’s Determination of the BSER is Technically Feasible and Legally Justified.

A. Statutory Background: Section 111(d) of the Clean Air Act

Section 111(d) of the Clean Air Act requires EPA to issue regulations that establish a 

state implementation plan procedure whereby states establish standards of performance for 

any existing source for any air pollutant to which a standard of performance would apply if such 

existing source were a new source. 42 U.S.C. §7411(d)(1)(A). Section 111(d) provides that this 

procedure must be similar to the state implementation plan process for regulating criteria 

pollutants under Section 110 of the Act. Id. §7411(d)(1). Section 111(d) Implementing 

Regulations, promulgated by EPA in 1975, establish a process for adoption and submittal of 

state plans, allocating responsibility for the various steps in this process to EPA or the states. 40 

C.F.R. §§ 60.20-60.29.86

First, concurrently upon or after proposal of standards of performance for the control of 

a designated air pollutant from new sources, EPA must issue a draft guideline document 

containing information pertinent to the control of the designated pollutant from existing 

sources. Id. §§ 60.22(a). The guideline document must include, among other information, an 

“emission guideline that reflects the application of the best system of emission reduction 

(considering the cost of such reduction) that has been adequately demonstrated for designated 

facilities, and the time within which compliance with emission standards of equivalent 

 

85 Nordhaus & Gutherz, Regulation of CO2 Emissions From Existing Power Plants Under §111(d) of the 

Clean Air Act: Program Design and Statutory Authority, 44 ELR 10,366, 10,377 n.89 (May 2014). 

Additional support for construing section 111(d) to permit standards of performance for such emissions 

appears in Konschnik, K., EPA’s 111(d) Authority – Follow Homer and Avoid the Sirens, LegalPlanet (May 

28, 2014),http://legal-planet.org/2014/05/28/guest-blogger-kate-konschnik-epas-111d-authorityfollow-homer-and-avoid-the-sirens/ (incorporated herein by reference).

86 Standards of Performance for New Stationary Sources, State Plans for the Control of Certain Pollutants 

from Existing Facilities, 40 Fed. Reg. 53,340 (Nov. 17, 1995). 
23

stringency can be achieved.” Id. § 60.22(b)(5). Second, each state must adopt and submit to 

EPA a plan establishing standards of performance or “emission standards” for the designated 

pollutant which, as a general rule, shall not be less stringent than the corresponding emission 

guideline. Id. §§ 60.23(a)(1), 60.24(c). Third, EPA must approve the states’ plans, or issue a plan 

for any state that fails to submit a satisfactory plan, or that fails to submit a plan within the time

prescribed. Id. §§ 60.27(b)-(c).

In this rulemaking, the proposed Clean Power Plan is EPA’s draft guideline document, 

published after EPA’s proposed standards of performance for new fossil fuel-fired EGUs issued 

in January 2014, and concurrently with the proposed standards of performance for modified 

and reconstructed EGUs.87 The guideline document contains (1) an assessment of technical 

potential and reasonableness of costs of EPA’s proposed systems of emission reduction or 

“building blocks,” (2) the agency’s determination that the “best system of emission reduction” 

(“BSER”) includes, or makes use of, those four building blocks, and (3) its proposed emission 

guidelines or “state goals,” computed through the application of the BSER to each state’s 

affected sources on a state-wide basis.

B. EPA Determines the “Best System of Emission Reduction” Under Section 111.

States must develop plans that establish standards of performance for existing sources 

under Section 111(d). 42 U.S.C. § 7411(d)(1)(A). Section 111(a)(1) of the Act defines “standard 

of performance” as “a standard for emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of the best system of emission reduction 

which (taking into account the cost of achieving such reduction and any non-air quality health 

and environmental impact and energy requirements) the Administrator determines has been 

adequately demonstrated.” Id. § 7411(a)(1). The regulatory definition of “emission guideline,” 

which is similar to the statutory definition of “standard of performance,” provides that the 

guideline must reflect the application of the BSER. 40 C.F.R. § 60.22(b)(5). The definition has 

three key elements: first, the standard of performance and the emission guideline must reflect 

the application of the BSER; second, the agency must consider costs, as well as health, 

environmental, and energy impacts; and third, the BSER must be adequately demonstrated.

Neither the Act nor the Implementing Regulations define the term “best system of 

emission reduction,” but the statute does make it clear that it is EPA’s task to make this 

determination. As the agency notes in its Legal Memorandum to the Clean Power Plan, while 

the D.C. Circuit has not interpreted or reviewed EPA’s interpretation of Section 111(d), during 

the past four decades it has issued a number of decisions concerning several aspects under 

Section 111(b) rule makings, in particular regarding the statutory definition of “standard of 

 

87 Clean Power Plan, 79 Fed. Reg. 34,830; Standards of Performance for Greenhouse Gas Emissions From 

New Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg. 1,430 (Jan. 8, 2014); Carbon 

Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating Units, 

79 Fed. Reg. 34,960 (June 18, 2014). 
24

performance,” which applies to both new and existing sources.88 EPA so recognized in the 

preamble to its Implementing Regulations:

“[T]he general principle (application of best adequately demonstrated control 

technology, considering costs) will be the same in both cases, the degrees of 

control represented by EPA’s emission guidelines will ordinarily be less stringent 

than those required by standards of performance for new sources because the 

costs of controlling existing facilities will ordinarily be greater than those for 

control of new sources.”

40 Fed. Reg. at 53,341 (emphasis added).

1. EPA has Authority to Determine the BSER Based on Consideration of the Statutory 

Factors.

The legislative history of Section 111 and the D.C. Circuit’s interpretation of the term 

“best system of emission reduction” show that EPA has authority to determine the BSER for 

both new and existing sources. The statutory factors impose important limits on EPA’s 

discretion to make this determination—the agency must determine the “best” system 

considering the degree of emissions reductions such system may generate,89 as well as other 

factors (costs, non-air quality health impacts, and environmental impacts) required by the 

statute). 

Congress added Section 111 to the Clean Air Act in 1970. In Section 111(a)(1), Congress 

defined the term “standard of performance” as “a standard for emissions of air pollutants 

which reflects the degree of emission limitation achievable through the application of the best 

system of emission reduction that the EPA determines has been adequately demonstrated.” 

Pub. L. No. 91-604, § 111, 84 Stat. 1676 (1970) (emphasis added).

In 1970 Congress amended Section 111(a)(1) to require that the standard of 

performance for new sources “reflect the degree of emission limitation and the percentage 

reduction achievable through application of the best technological system of continuous 

emission reduction” taking into consideration costs, non-air quality health and environmental 

impacts, and energy requirements. Pub. L. No. 95-95, § 109, 91 Stat. 685 (1977) (emphasis 

added). Congress defined the term “technological system of continuous emission reduction” as 

“a technological process for production and operation by any source which is inherently lowpolluting or nonpolluting.” Id. (emphasis added.) Congress, however, did not impose this 

restriction on existing sources, and made it clear that “standards for existing sources should be 

 

88 EPA, Legal Memorandum, supra n. 80, at 10-11. 

89 See Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (“[T]he Senate would 

have required that standards reflect ‘the greatest degree of emission control which the Secretary 

determines to be achievable through application of the latest available control technology, processes, 

operating methods, or other alternatives.’” (emphasis added.))
25

based on available means of emission control that were not necessarily technological.” H.R. 

Rep. No. 95-564 (1977) (Conf. Rep.) (emphasis added).

In the 1990 Clean Air Act Amendments, Congress repealed the requirement that the 

best system of emission reduction be “technological,” going back to the original requirement 

enacted in 1970 that required the standard of performance to be based on the application of 

the “best system of emission reduction,” which must take into account costs, non-air quality 

health and environmental impacts, and energy requirements, and must be adequately 

demonstrated. Pub. L. No. 101-549, § 403, 104 Stat. 2399 (1990). As noted, today this definition 

applies both to new and existing sources.90 Thus, the “best system of emission reduction” is not 

limited to technological controls implemented directly at the affected sources. As we explain 

below, the BSER allows for reliance on a “system” that may include measures to decrease 

emissions by reducing the utilization of those sources, so long as EPA adequately considers the 

required statutory factors.

The D.C. Circuit has held that a “best system of emission reduction” that is “adequately 

demonstrated” is “one which has been shown to be reasonably reliable, reasonably efficient, 

and which can reasonably be expected to serve the interests of pollution control without 

becoming exorbitantly costly in an economic or environmental way.” Essex Chem. Corp. v. 

Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973). The performance standard must be “achievable 

because it has been achieved.” Natural Res. Def. Council v. EPA, 655 F.2d 318, 330 (D.C. Cir. 

1981) (citing cases). But “[w]hile not at the level that is purely theoretical or experimental, [the 

standard] need not necessarily be routinely achieved within the industry prior to its adoption.” 

Essex Chem. Corp., 486 F.2d at 433-34. “‘Adequately demonstrated’ does not mean that 

existing [sources] must be capable of meeting the standard; to the contrary, ‘(s)ection 111 looks 

toward what may fairly be projected for the regulated future, rather than the state of the art at 

present.’” Nat’l Asphalt Pavement Ass’n v. Train, 539 F.2d 775, 787 (citing Portland Cement 

Ass’n, 486 F.2d 375 at 391. Recognizing the “technology-forcing” character of the statute, the 

Court has reasoned that “EPA does have authority to hold the industry to a standard of 

improved design and operational advances, so long as there is substantial evidence that such 

improvements are feasible and will produce the improved performance necessary to meet the 

standard.” Sierra Club, 657 F.2d at 364.

After EPA identifies the emission levels that are achievable with adequately 

demonstrated systems of emission reduction, the agency must “weigh cost, energy, and 

environmental impacts in the broadest sense at the national and regional levels and over time 

as opposed to simply at the plant level in the immediate present.” Id. at 330 (D.C. Cir. 1981).

The statutory factors which EPA must weigh are “broadly defined and include within their ambit 

subfactors such as technological innovation.” Id. at 346. EPA’s choice of a given standard “will 

be sustained unless the environmental or economic costs of using the technology are 

exorbitant.” Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (citing Nat’l 

Asphalt Pavement Ass'n, 539 F.2d at 786). EPA’s standards of performance will meet the cost 

 

90 EPA, Legal Memorandum, supra n. 80, at 6-8. 
26

test unless the costs of meeting them “would be greater than the industry could bear and 

survive.” Portland Cement Ass’n v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975).

C. EPA Has Proposed Two BSER Determinations under the Clean Power Plan.

In this rulemaking, EPA is proposing two alternative approaches for determining the 

BSER, each of which is based on four sets of measures or “building blocks” that EGU owners and 

operators, as well as states have for several years been implementing for the purpose of 

reducing emissions of air pollutants, including CO2, from these sources.91 These proposed 

measures, and the resulting proposed BSER determinations, are in accordance with President 

Obama’s instruction to EPA to “ensure, to the greatest extent possible, that [EPA] ... develop 

approaches that allow the use of market-based instruments, performance standards, and other 

regulatory flexibilities; [and] ensure that the standards enable continued reliance on a range of 

energy sources and technologies.”92

The proposed building blocks are: (1) Building Block 1: reducing the carbon intensity of 

generation at affected coal-fired steam EGUs through heat rate improvements; (2) Building 

Block 2: reducing emissions from coal-fired steam EGUs by substituting generation at those 

EGUs with generation from less carbon-intensive affected EGUs, namely, existing and “under 

construction” natural gas combined cycle units (“NGCCs,” also known as combined cycle gas 

turbines, or CCGTs); (3) Building Block 3: reducing emissions from affected EGUs by substituting 

generation at those EGUs with expanded low- or zero-carbon generation, including renewable 

energy and nuclear generation; and (4) Building Block 4: reducing emissions from affected EGUs 

through demand-side energy efficiency. The first BSER approach comprises the combination of 

all four building blocks, and the second BSER approach consists of Building Block 1 plus the 

reduced utilization of affected EGUs, quantified in specific amounts through the application of 

Building Blocks 2, 3, and 4.

The recognition of the integrated nature of the electric grid is central to both BSER 

approaches. Whether Building Blocks 2, 3, and 4 are components of the BSER or not, the 

electric grid includes all generators (coal-fired steam EGUs, natural gas-fired EGUs, renewable 

generators) and electricity consumers.93 If a generator is not available or if demand increases, 

the grid operator dispatches other generation facilities or increases output. Similarly, when 

demand decreases due to the implementation of demand-side energy efficiency, the grid 

 

91 Id. at 10. 

92 Presidential Memorandum -- Power Sector Carbon Pollution Standards, Section 1(c) (June 25, 2013), 

available at http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandumpower-sector-carbon-pollution-standards.

93 EIA, What Is the Electric Grid and What Are Some of the Challenges It Faces, September 16, 2014, 

available at http://www.eia.gov/energy_in_brief/article/power_grid.cfm; Doniger, D., Questions and 

Answers on the EPA’s Legal Authority to Set “System-Based” Carbon Pollution Standards for Existing 

Power Plants under Clean Air Act Section 111(d), NRDC Issue Brief, (Oct. 2013), available at

http://www.nrdc.org/air/pollution-standards/files/system-based-pollution-standards-IB.pdf, at 5.
27

operator instructs generation facilities to reduce their output.94 In addition, power plant 

owners take into account the existence and operation other units in the grid in making 

decisions to construct, modify, and retire individual generation units.

According to EPA, a BSER determination that recognizes the integrated nature of the 

electric system is consistent with the way in which the industry addresses resource planning 

issues. In regulated states, utilities generally develop integrated resource plans that set forth 

their strategies for meeting future demand for electricity services in a cost-effective manner. 

These plans may include measures from Building Blocks 2, 3, and 4. In non-regulated states, 

independent system operators (“ISOs”) and regional transmission organizations (“RTOs”) 

administer capacity auctions where owners of existing EGUs, developers of renewable capacity, 

and developers of demand-side resources all compete to provide potential resources for 

meeting projected electricity demand. 79 Fed. Reg. at 34,881.

Below we offer additional support for EPA’s proposed second approach—BSER as the 

combination of Building Block 1 plus the reduced utilization of affected sources, quantified in 

specific amounts from the measures comprised in Building Blocks 2, 3, and 4. Enforcement 

would be simpler and more straightforward under this approach because affected sources 

would be accountable for the required emissions reductions; no separate oversight and 

enforcement of a multitude of dispatch, renewable energy, and energy efficiency measures 

would be needed.

D. The BSER Can Comprise Building Block 1 Plus Reduced Utilization at Levels 

Commensurate with Building Blocks 2, 3, and 4.

Under the second BSER approach, EPA proposes that the BSER entails not only 

improving the efficiency of affected fossil fuel-fired EGUs through supply-side improvements, 

but also reducing their utilization through the implementation of lower or zero-emitting 

generation and through electricity demand reductions. Specifically, EPA proposes that the BSER 

consists of Building Block 1 plus the reduction of CO2 emissions from affected fossil fuel-fired 

EGUs achievable through reductions in generation that are quantified through the 

implementation of measures in Building Blocks 2, 3, and 4. Id. at 34,889. The amount of 

generation from the increased utilization of NGCC units (Building Block 2) would determine a 

portion of the amount of reduced generation from affected fossil fuel-fired steam EGUs, and 

the amount of generation from the use of renewable energy and avoided emissions through 

demand-side energy efficiency (Building Blocks 3 and 4) would determine a portion of the 

amount of the generation reduction for all affected EGUs—both coal-fired steam EGUs and 

NGCC units.95

EPA explains that this approach meets the BSER criteria because reduced generation is 

technically feasible due to an affected source’s ability to limit its own operations, and because 

 

94 Konschnik & Peskoe, supra n. 290, at 4. 

95 EPA, Legal Memorandum, supra n. 80, at 80-81. 
28

of the emissions reductions that would be achieved from the application of all the measures 

involved, its reasonable cost, its promotion of technological development and, in particular, the 

fact that this approach would contribute to maintain the reliability of the system through the 

demand reductions that would result from the implementation of demand-side energy 

efficiency measures.96

In the power sector, CO2 emissions reductions at fossil fuel-fired EGUs can be achieved 

by reducing both the EGU’s emission rate and its electricity output. Heat rate improvements at 

affected EGUs are aimed at reducing these sources’ emission rate, and annual emissions limits 

can address the potential of a rebound effect from improving the efficiency of generation at 

fossil fuel-fired sources. As long as the EGU does not increase its output significantly, these 

measures will lead to a reduction in the EGU’s CO2 emissions. In addition, re-dispatch to existing 

and under-construction NGCC units, renewable energy, and demand-side energy efficiency are 

aimed at reducing affected sources’ output and thus their overall mass CO2 emissions.97

The distinction between “inside the fence line” and “beyond the fence line” measures is 

largely artificial and not meaningful.98 All of the emission reductions measures under 

consideration, whether implemented directly at the affected source or beyond the source, 

translate into emissions reductions from such sources. Because of the integrated nature of the 

grid, the implementation of these measures allows affected EGUs to reduce their output, and 

thus, their own CO2 emissions.99 In other words, CO2 emissions reductions are occurring at the 

affected sources due to changes in generation at those sources.100 Therefore, all of the 

measures EPA is considering under the four Building Blocks are effectively “at the unit” or 

“inside the box” measures that reduce affected EGUs’ utilization, because these measures are 

being and can be implemented or sponsored by owners and operators of affected sources.101

And because all of these measures are “inside the box,” EPA should set the stringency of the 

emission guideline based on the universe of those measures. 

Basing the BSER in whole or in part on “reduced utilization” has support under other 

Clean Air Act programs as well as precedent under EPA’s prior 111(d) rulemakings.

1. EPA’s Interpretation that the BSER Can Include Reduced Utilization of Affected 

Sources is a Permissible Construction of the Clean Air Act.

EPA’s interpretation that the BSER can include the reduced utilization of affected 

sources is a permissible interpretation of the Act. The legislative history of the 1970 Clean Air 

 

96 Id. at 15. 

97 Nordhaus & Gutherz, supra n. 85, at 10,381. 

98 Id. at 10,383, n. 133.

99 Id. 

100 Monast et al., Regulating Greenhouse Gas Emissions from Existing Sources: Section 111(d) and State 

Equivalency, 42 ELR 10,206, 10,209 (2012).

101 EPA, Legal Memorandum, supra n. 80, at 77-78. 
29

Act Amendments “indicates that Congress recognized that emitting sources could comply with 

pollution control requirements by reducing production, including retiring.” Id. at 34,889. In its 

proposed amendments, the Senate’s Committee of Public Works stated that the protection of 

public health, as required by the national ambient air quality standards and the emission 

standards for hazardous air pollutants, would require major action throughout the country, 

whether in the form of technology controls or retirements: “[m]any facilities may require major 

investments in new technology and new processes. Some facilities may need altered operating 

procedures or a change of fuels. Some facilities may be closed.” S. Rep. No. 91-1196 (1970) 

(emphasis added).

During its deliberations, the Senate Committee raised concerns with respect to basing 

the ambient air standards on the concept of technical feasibility, concluding, nevertheless, that 

existing sources should either meet the required standard or close down:

“In the Committee discussions, considerable concern was expressed regarding 

the use of the concept of technical feasibility as the basis of ambient air 

standards. The Committee determined that 1) the health of people is more 

important than the question of whether the early achievement of ambient air 

quality standards protective of health is technically feasible; and, 2) the growth 

of pollution load in many areas, even with application of available technology, 

would still be deleterious to public health.

Therefore, the Committee determined that existing sources of pollutants either

should meet the standard of the law or be closed down, and in addition that new

sources should be controlled to the maximum extent possible to prevent 

atmospheric emissions.”

S. Rep. No. 91-1196, at 2-3 (1970) (emphasis added).

The legislative history thus suggests that Congress intended for EPA to impose 

stringent standards under different Clean Air Act programs that, as a practical matter, 

could result in reduced utilization of the sources or entities regulated under those 

programs.

Congress itself has established standards under the Act whose practical effect 

has been the reduced utilization, including the closure, of some of the regulated units.

For example, under Title IV’s Acid Rain Program, Congress imposed a tonnage limitation 

on SO2 emissions from affected electric generating units through the use of allowances, 

which had to be implemented in two phases: Phase I, in effect between 1995 and 1999, 

covered the dirtiest large generating units (also called “Table A” units), and Phase II, 
30

which went into effect in 2000, covered the rest of the electric generating units in the 

country. 42 U.S.C. § 7651c(a)(1).102

Title IV required Table A units that elected to comply with Phase I “by reducing 

utilization of the unit as compared with its baseline or by shutting down the unit,” to 

submit a reduced utilization plan that specified the unit(s) that would provide electrical 

generation to compensate for the reduced output at the affected unit, or a 

demonstration that the reduced utilization would be accomplished through energy 

conservation or improved unit efficiency. Id. § 7651g(c)(B). A Table I unit thus could 

designate any Phase II unit as a “compensating unit” if the latter was in the Table I unit’s 

dispatch system or had a contractual arrangement with the Table I unit.103 Several 

utilities complied with the Act using this provision, among other compliance options.104

For example, Georgia Power Company designated ten Phase II units under Phase I and 

employed a reduced utilization plan that provided for increased unit efficiency and 

sulfur-free generation.105

Interpreting the term “best system of emission reduction” under Section 111 as 

including measures to decrease emissions by reducing the utilization of affected sources is 

consistent with the Act’s primary purpose of encouraging air pollution prevention by states (as 

well as the federal and local governments). Id. § 7401(c). In its findings and declaration of the 

Act’s purposes, Congress provided “that air pollution prevention (that is, the reduction or 

elimination, through any measures, of the amount of pollutants produced or created at the 

source) and air pollution control at its source is the primary responsibility of States and local 

governments.” Id.§ 7401(a)(3) (emphasis added).

2. Section 111 Authorizes EPA to Limit the Quantity of Emissions of Air Pollutants 

from, and Thus to Reduce the Utilization of, Affected Sources.

As noted above, Section 111 of the Act defines “standard of performance” as a standard 

for emissions of air pollutants which reflects the degree of emission limitation achievable 

through the application of the best system of emission reduction that the EPA determines has 

been adequately demonstrated. 42 U.S.C. § 7411(a)(1) (emphasis added). In addition, the 

Implementing Regulations prescribe that the emission guideline must reflect the application of 

the BSER that has been adequately demonstrated for existing sources, and the time within 

which compliance with “emission standards” of equivalent stringency can be achieved. 40 C.F.R. 

§ 60.22(5).

 

102 See Montero, Voluntary Compliance with Market-Based Environmental Policy: Evidence from the U.S.

Acid Rain Program, J. of Political Econ. 107:5 (1999), attached as Ex. 3, at 6.

103 EIA, The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update, 

DOE/EIA-0582(97) (Mar. 1997), attached as Ex. 4, at 1. 

104 Id. See also Montero, supra n. 102, at 12.

105 EIA, The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities, supra n. 104, 

at 19. 
31

Although Section 111 and the Implementing Regulations do not define the terms 

“emission limitation” or “emission standards,” Section 302(k) of the Act defines both terms as a 

requirement established by the states (in the case of emission standards) or by EPA “which 

limits the quantity, rate, or concentration of emissions of air pollutants on a continuous basis, 

including any requirement relating to the operation or maintenance of a source to assure 

continuous emission reduction...” 42 U.S.C. § 7602(k) (emphasis added). Authority to limit the 

quantity of emissions logically carries with it the power to interpret the BSER as involving 

requirements to reduce the utilization of affected sources. 

In prior emission guidelines under Section 111(d) and Section 129 of the Act, EPA has 

determined that the BSER included measures implemented outside the source’s boundaries 

that reduced their utilization and thus their emissions. For example, EPA has required affected 

incinerators to develop waste management plans in order to reduce the amount of waste that 

is incinerated at those sources. Subpart Ec, which contains the emission guidelines for existing 

hospital, medical, and infectious waste incinerators, requires state plans to include waste 

management plan requirements that are “at least as protective” as the applicable requirements 

for new sources of the same type. 40 C.F.R. § 60.35e. Such requirements, contained in Subpart

Ec, the standards of performance for new waste incineration facilities, provide that the owner 

or operator of an affected facility must prepare a waste management plan for separating solid 

waste components from the health care waste stream in order to reduce the amount of toxic 

emissions from incinerated waste. 40 C.F.R. § 60.55c.

In addition, Subpart DDDD, the emission guidelines for commercial and industrial solid 

waste incineration units, requires affected sources to submit waste management plans that 

identify “both the feasibility and the methods used to reduce or separate certain components 

of solid waste from the waste stream in order to reduce or eliminate toxic emissions from 

incinerated waste.” 40 C.F.R. § 60.2620. Similar requirements apply to “other” solid waste 

incineration units under Subpart FFFF. 40 C.F.R. § 60.3012.

Waste management measures under all these regulations are intended to reduce 

emissions through the reduction of inputs. In the preamble to the final emission guidelines for 

existing hospital, medical, and infectious waste incinerators, EPA explained that through the 

development of waste management programs, health care facilities “can achieve significant 

reductions in their waste stream, reduce the volume of waste to be incinerated, and thereby 

reduce the amount of air pollution emissions associated with that waste.”106 Thus, the agency 

has previously contemplated that certain measures that are not implemented directly at the 

affected source can be used to reduce inputs in the combustion process, and thus the 

utilization of these sources, without altering the technology by which those sources produce 

and control emissions of air pollutants.107

 

106 Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: 

Hospital/Medical/Infectious Waste Incinerators, 62 Fed. Reg. 48,348, 48,359. 

107 Nordhaus & Gutherz, supra n. 85, at 10,373. 
32

EPA’s regulation of hospital, medical, and infectious waste treatment has increased the 

costs of incineration and, as a practical matter, has caused the closure of incinerators in favor of 

alternative compliance options.108 The number of hospital, medical, and infectious waste 

incinerators decreased from over 2,000 units in the mid-1990s to 57 in 2008.109 In addition, 

medical incinerators have increasingly contracted more commercial waste companies to 

manage their waste instead of incinerating it in-house, as used to be done in the past.

Outsourcing waste management to commercial waste treatment companies today is the most 

common compliance option for medical incinerators.110

The availability of waste management measures for compliance has also resulted in a 

decrease in the percentage of medical waste incinerated.111 As costs of incineration have 

increased, incineration unit owners or operators have used alternative treatment methods, 

such as training staff to segregate waste more effectively, and autoclaving followed by disposal 

of the treated waste in landfills.112 These two trends have also contributed to reduce the share 

of hospital, medical, and infectious waste being incinerated, and thus the utilization of these 

units.113

E. EPA Must Revise its Proposed BSER Approaches to Include Oil-Fired and Natural GasFired Units Under Building Block 1.

Under Building Block 1, EPA has estimated an average six percent improvement of the 

coal-fired steam EGUs in each state. EPA proposes to base this estimate on coal-fired steam 

EGUs only because the potential for reductions is “significantly greater” from these EGUs. 79 

Fed. Reg. at 34,859. Even though potential heat rate improvements in NGCCs are not as 

significant as in coal-fired steam EGUs,114 EPA should also estimate heat rate efficiency 

upgrades from natural gas-fired units, and make this type of efficiency upgrades available for 

compliance by these sources. Stationary combustion turbines are also a regulated source 

 

108 EPA redeveloped the 1997 emission guideline for these incinerators in response to the D.C. Circuit’s 

concerns about the methodology employed to calculate the MACT floors under Section 129. The agency 

identified that, under the re-developed standards, autoclaving, commercial medical waste disposal, and 

hauling of medical waste to municipal waste combustors would likely be used as alternative compliance 

options. Memorandum from T. Holloway to K. Patel, U.S. EPA, Revised Compliance Costs and Economic 

Inputs for Existing HMIWI (July 6, 2009), attached as Ex. 5, at 12-13.

109 Heller & Nourani, Economic Impacts of Revised MACT Standards for Hospital/Medical/Infectious 

Waste Incinerators, Final Report, RTI Project No. 0209897.002.036 (Oct. 2008), attached as Ex. 6, at 2-

16. 

110 Id. at 2-17.

111 Id. at 2-16.

112 Id. at 3-3

113 Id. at 2-16.

114 Burtraw & Woerman, Resources for the Future, Technology Flexibility and Stringency for Greenhouse 

Gas Regulations, Discussion Paper 13-24 (July 2013), available at

http://www.rff.org/RFF/Documents/RFF-DP-13-24.pdf, at 9. 
33

category under Section 111, and under EPA’s proposal they would not be subject to emission 

reduction requirements in the form of reductions in carbon intensity.

EPA needs to estimate achievable heat rate improvements, not just from existing and 

under-construction NGCCs currently covered under Building Block 2, but also from existing 

simple-cycle combustion turbines (“CTs”). As we explained in our comments to EPA’s proposed 

carbon pollution standards for new EGUs, new small combustion turbines would not covered 

under the Section 111(b) standard if they operate at capacity factors of less than 33 percent.115

We urge EPA to finalize a Section 111(b) standard that covers these new CTs, and to also cover 

all existing CTs under the Section 111(d) emission guideline. As EPA notes, measures to improve 

affected sources’ heat rates are a common and well-established practice in the industry. Heat 

rate improvements cause fuel to be used more efficiently, thus reducing the adverse impacts 

associated with the disposal of coal combustion solid waste products. 79 Fed. Reg. at 34,882. 

There is no reason why EPA should not factor the potential for heat rate improvements of 

natural gas-fired EGUs in setting the stringency of the standard, which would result in greater 

environmental benefits than currently estimated under Building Block 1.116

Even though EPA’s proposal contemplates including both fossil fuel-fired units and 

stationary combustion turbines in a single category (codified under a new Subpart UUUU), 

failure to include oil- and gas-fired (“O&G”) steam EGUs and NGCCs under Building Block 1 

implies that these EGUs are not subject to emission reduction requirements. Section 111(d) 

requires state plans to include “standards of performance for any existing source,” and thus, 

EPA’s BSER determination is for the affected sources—coal-fired, oil-fired, and natural gas-fired 

units alike. We urge EPA to incorporate oil- and natural gas-fired units to Building Block 1, and 

to reformulate its BSER approaches accordingly.

Under EPA’s second BSER approach, the BSER would include, first, Building Block 1—

heat rate improvements (and other capital investments such as turbine blade replacements) on 

affected coal- and O&G-fired steam EGUs, NGCCs, and CTs, and second, a reduced utilization 

component. The reduced utilization component would comprise limiting the dispatch of fossil 

fuel-fired steam EGUs by the amount of available existing NGCC and CT capacity in 2020, and 

thereafter limiting the dispatch of fossil fuel-fired EGUs (steam EGUs, NGCCs, and CTs) by the 

amount of available renewable energy and energy efficiency.

In the sections that follow, we establish that each of EPA’s proposed BSER building 

blocks, if strengthened in the ways that we suggest, are adequately demonstrated and will not 

impose unreasonable costs on the U.S. electric power generation industry. We note, however, 

that EPA is not proposing that each of the measures in its proposed system of emission 

reductions be met. Instead, EPA proposes a formula that identifies one low cost mix of 

 

115 See Sierra Club, et al., Comments on Standards of Performance for Greenhouse Gas Emissions from 

New Stationary Sources: Electric Utility Generating Units, EPA-HQ-OAR-2013-0495-9514 (May 9, 2014), 

attached as Ex. 7, at 55. 
34

measures that can achieve significant emission reductions and proposes to allow sources, states 

and groups of states flexibility in achieving equivalent reductions. It is this system—an 

objectively determined formula that sets broad goals, coupled with a mechanism to allow 

states working with sources in their state to devise the most reasonable means of meeting 

those broad goals—that must meet the statutory tests described above.

IV. Severability

The proposed rule expressly states EPA’s intent that the various building blocks that 

constitute the BSER be severable, so that in the event that a court were to invalidate the 

agency’s finding with respect to any particular building block, EPA would find that the BSER 

consists of the remaining building blocks. EPA proposes that the state goals that would result 

from the combination of the remaining building blocks would be computed from the data 

included in the Goal Computation TSD and its appendices, using the computation methodology 

described in the preamble and that TSD. 79 Fed. Reg. at 34,892. This proposed approach is 

sound, and consistent with the case law on severability discussed below.

A. EPA’s Expressed Intent to Make the Building Blocks Severable is Sound.

Agency intent is the touchstone of an inquiry into whether a regulation or other agency 

action is severable. See, e.g., Davis Cnty. Solid Waste Mgmt. v. EPA, 108 F.3d 1454, 1459 (D.C. 

Cir. 1997); North Carolina v. FERC, 730 F.2d 790, 795–96 (D.C. Cir. 1984); Iowa Utils. Bd. v. 

F.C.C., 120 F.3d 753, 819 (8th Cir. 1997), as amended on reh'g (Oct. 14, 1997), aff'd in part, rev'd 

in part sub nom. AT & T Corp. v. Iowa Utilities Bd., 525 U.S. 366 (1999). In Davis, operators of 

existing municipal waste combustor (“MWC”) units which had municipal solid waste (“MSW”) 

capacities below 250 tons/day, but which were located at a plant with an aggregate MSW 

capacity above 250 tons/day, challenged EPA's 1995 standards under Sections 111 and 129 of 

the Clean Air Act. 108 F.3d at 1455. In its initial opinion, the D.C. Circuit vacated the 1995 

standards in their entirety; however, on EPA’s petition for rehearing on the remedy, the Court 

held that the standards would be vacated only as applied to small MWC units and cement kilns, 

leaving the performance standards and emission guideline for large units other than cement 

kilns in place. Id. at 1455, 1460.

In amending its prior ruling, the Court inquired whether EPA intended the regulation at 

issue to be severable, and whether there was “substantial doubt” that EPA would have adopted 

the severed portion on its own. The Court found that EPA intended the regulation to be 

severable, because it was “clear that the EPA would have adopted the standards for large MWC 

units even without the standards for small MWC units and cement kilns.” Id. at 1459. The Court 

noted that “[t]he 1995 standards for large and small MWC units [were] not in any way 

‘intertwined,’ [and that] they operate[d] entirely independently of one another.” Id. at 1459 

(quoting Telephone & Data Sys. v. FCC, 19 F.3d 42, 50 (D.C. Cir. 1994)); see also Arizona Pub. 

Serv. Co. v. U.S. E.P.A., 562 F.3d 1116, 1122 (10th Cir. 2009) (“[a] regulation is severable if the 

severed parts operate entirely independently of one another, and the circumstances indicate 

the agency would have adopted the regulation even without the faulty provision.”) The 
35

inclusion of a severability clause in a regulation creates a presumption that an invalid portion is 

severable. High Country Conservation Advocates v. U.S. Forest Serv., No. 13-CV-01723-RBJ, 2014 

WL 4470427 (D. Colo. Sept. 11, 2014).

In the Clean Power Plan, the proposed building blocks operate independently of one 

another. EPA has analyzed each building block individually, providing an assessment of 

technical potential, costs, and a description of data inputs used as the basis for the 

computation of the proposed state goals. 79 Fed. Reg. at 34,858-75. The proposal’s technical 

support documents explain the rationale and derivation of these values.117 EPA has also 

explained why each of the individual building blocks meets the statutory factors to qualify as 

components of the BSER under the agency’s first BSER approach, and why each of the building 

blocks can serve as the basis for quantifying the amounts of reduced utilization from affected 

EGUs under its second BSER approach. Id. at 34,881-84.

In addition, in its proposed computation methodology, EPA has added each of the 

building blocks to the formula separately, calculating the 2012 emission rate for covered 

sources, and then adjusting the formula to reflect the application of each building block: first, 

adjusting the coal emission rate to reflect a six percent heat rate improvement; second, 

increasing NGCCs’ generation values up to a maximum of 70 percent, while decreasing 

generation values for coal and oil/gas-fired steam EGUs proportionately; third, adding 

estimated total generation from renewables and covered nuclear; and fourth, adding estimated 

total generation avoided from implementation of demand-side energy efficiency. The Goal 

Computation TSD annexes contain the state level data, calculations, and emission rates used to 

derive the interim and final goals, for both the main proposal (ending in 2030) and the 

alternative (ending in 2025). The proposal itself provides EPA’s intent that the various building 

blocks be severable. Id. at 34,892.

B. The Clean Power Plan Meets the Requirements for Severability.

Where an agency intends the provisions of a rule to be severable, invalidation of one 

provision does not warrant invalidation of the entire rule as long as the remaining provisions 

can operate sensibly without the stricken provision. MD/DC/DE Broadcasters Ass'n v. F.C.C., 253 

F.3d 732, 734 (D.C. Cir. 2001).

As noted above, EPA has expressly stated its intent that the regulation be severable. In 

addition, the rule can operate sensibly even if with the invalidation of one or more of the 

building blocks. The regulation can serve the goal of reducing carbon emissions from affected 

 

117 EPA, Goal Computation TSD, Docket ID No. EPA-HQ-OAR-2013-0602 (June 2014), available at

http://www2.epa.gov/sites/production/files/2014-06/documents/20140602tsd-goal-computation.pdf. 

EPA, Technical Support Document: GHG Abatement Measures, No. EPA-HQ-OAR-2013-0602 (June 10, 

2014) (hereafter, “Abatement Measures TSD”), available at

http://www2.epa.gov/sites/production/files/2014-06/documents/20140602tsd-ghg-abatementmeasures.pdf,
36

EGUs without a stricken building block--each building block independently accomplishes some 

level of carbon dioxide reduction, and each can operate regardless of whether any of the others 

are in place. Because the goal computation formula is additive, EPA can easily recalculate the 

state goals to reflect any invalidation of one or more building blocks.

V. The Building Blocks

A. Building Block 1

1. Building Block 1 is Legally and Technically Justified as an Element of BSER.

There is little controversy that heat rate improvements (“HRI”) at individual fossil-fired 

EGUs are legally permissible elements of a BSER determination. During the lead-up to EPA’s 

Clean Power Plan, there has been and continues to be considerable debate over the extent to 

which EPA may include measures “outside-the-fence” of individual units when developing 

pollution control regulations under section 111(d), as opposed to “inside-the-fence” 

measures—those that can be implemented entirely within the engineering, design, or 

utilization of an individual unit. What nearly all parties—including utilities, industry groups, and 

EGU owners and operators—agree on is that EPA may include entirely inside-the-fence 

measures in a BSER formula. Heat rate improvements at individual EGUs, which are the basis 

for Building Block 1, are precisely such measures since they can be implemented on-site at each 

individual unit.

More specifically, the HRI that EPA has proposed for Block 1 meet the legal standards 

for a BSER determination under section 111. First, these measures are achievable and 

adequately demonstrated. EPA expects units to achieve the HRI under Block 1 through two 

well-demonstrated techniques: enhanced operation and maintenance practices and a number 

of specific equipment upgrades that have been identified in the technical literature and 

undertaken at plants around the world.118 We discuss these methods in more detail below, and 

provide documentation showing that the HRI specified under Block 1 are not only achievable, 

but are overly conservative and must be strengthened. Furthermore, the operating and 

maintenance improvements and equipment upgrades that inform the Block 1 HRI will have no 

non-air quality environmental impacts, nor will they adversely affect the nation’s energy 

requirements. 

Finally, as EPA notes in its Abatement Measures TSD, the costs associated with the Block 

1 HRI will not be exorbitant, particularly in light of the fact that the fuel savings associated with 

increased EGU efficiency will offset these costs in considerable part.119 Our recommended 

improvements to Building Block 1 will not alter this picture dramatically. We demonstrate that 

units will be able to improve their heat rates by at least six percent (as opposed to EPA’s 

predicted four percent) through operating and maintenance techniques, which are associated 

with very low costs. While equipment upgrades are more expensive than operating and 

 

118 Abatement Measures TSD at 2-30 to 2-35.

119 Id. at 2-36 to 2-40.
37

maintenance modifications, EPA’s analysis shows that these costs are still well within the range 

of what is reasonable. We believe that the agency has overestimated the extent to which the 

nation’s coal plants have already implemented some of these upgrades (in particular turbine 

blade replacements), so we expect that units can achieve a four percent (as opposed to two 

percent) HRI improvement through those measures. While this may yield marginally higher 

aggregate costs than EPA’s predictions, they are nonetheless economically reasonable and will 

produce greater savings in conserved fuel.

For these reasons, HRI are a legally appropriate component of EPA’s BSER 

determination. Below, we discuss in more detail how the agency can improve Building Block 1 

to ensure greater emission reductions through HRI.

2. As Proposed, Building Block 1 Is Too Conservative and Must Be Strengthened.

a. EPA's Statistical Analysis of the Performance of Existing Units Demonstrates 

that a Heat Rate Improvement From Better Operation and Maintenance (O&M) 

of Existing Units in Excess of 6 Percent Is “Adequately Demonstrated.”

In determining the appropriate target under Building Block 1, EPA first examined the 

level of emission reductions that has been demonstrated at existing units, then determined the 

additional reductions that have been demonstrated to be achievable from plant upgrades.120 In 

quantifying the O&M component of Block 1, EPA reasonably considered the level of 

performance that each unit has demonstrated in the past. The agency first looked at the hourly 

average heat rate for essentially all (96 percent) of the units in the system between 2002 and 

2012, correcting for differences in heat rate that could be correlated to temperature and load.

EPA then calculated what would happen to the average heat rate at each unit if the heat rate at 

every given hour were reduced by a specified percentage of the difference between the heat 

rate for that hour and the average heat rate for the top 10 percent of all hours for that unit.

EPA reports that a fleet wide improvement of 1.3 percent would result if units, on average, 

reduced their heat rate by 10 percent of the difference between the average and top decile 

heat rates and that reducing heat rates by 50 percent of that difference would produce a 6.7 

percent improvement fleetwide.

EPA acknowledges that its selection of 30 percent of the difference between the 

average and top decile heat rates (resulting in a 4 percent heat-rate improvement fleet wide) is 

conservative, justifying its selection with the observation that it is in the middle of the range (10 

to 50 percent) that EPA chose to analyze. Notably, EPA does not justify its choice of a range to 

analyze. Had the agency chosen to analyze a range of 30 to 70 percent, for instance, the midpoint of its chosen range would be 50 percent. EPA acknowledges that a 50 percent reduction 

in the difference between the fleet’s average and top decile rates would yield a 6 percent heat 

rate improvement fleet-wide. The agency rationalizes its decision to select a lower figure of 30 

 

120 The discussion in this paragraph and the two that follow references 79 Fed. Reg. at 34,860-61 and 

EPA’s Abatement Measures TSD at 2-30 to 2-35.
38

percent by analogizing to a standard based on a three-year rolling average rather than a rolling 

annual average. EPA notes that plants would achieve a 6.7 percent heat-rate improvement if 

they were to meet their top rolling annual average over the 11-year study period and a 3.9 

percent improvement if they were to meet their best rolling three-year average. These 

numbers correspond fairly closely to the 6 and 4 percent improvements that would result from 

50 and 30 percent reductions (respectively) in the difference between the annual and top decile 

heat rates. EPA then states that a hypothetical selection of the three-year rolling average would 

be more appropriate than a rolling annual average due to potential differences in weather and 

load; hence, it avers that a 30 percent reduction between the average and top decile heat rates 

(analogous to a three-year rolling average) is a superior target than a 50 percent reduction 

(analogous to a rolling annual average). 

EPA’s reasoning here is flawed. As noted above, EPA already controls its data pool for 

temperature and capacity factor. To select a more lenient standard in order to smooth out 

difference in weather and load is, in effect, double controlling for these variables, and is a 

methodological error. Furthermore, in actuality, differences in temperature profiles and loads 

from one year to the next are relatively small and are not large enough to justify the EPA 

accommodation. EPA’s analogy to annual vs. three-year rolling averages is inappropriate, and 

the agency has not justified its decision to select a 30 percent rather than 50 percent reduction 

between the average and top decile heat rates as the basis for its calculations. The agency 

correctly focuses on annual averages. Here, too, differences in annual temperature profiles and 

load are relatively small and are not large enough to justify the EPA accommodation. 

Accordingly, each of EPA’s analyses demonstrates that a 6 percent fleet-wide improvement is 

achievable and that its choice of 4 percent is overly conservative.

b. The Sierra Club’s 52-Unit Study Independently Confirms that a Heat Rate 

Improvement of Six Percent From Better O&M at Existing Units Is “Adequately 

Demonstrated.”

In order to analyze the true extent of the heat rate improvements available through 

operation and maintenance practices, the Sierra Club conducted a preliminary review of the 

detailed operating records for individual coal-fired EGUs maintained in EPA’s Air Markets 

Program Database (“AMPD”).121 The AMPD data revealed a number of occasions where there 

was a significant and sudden unexplained change in plant operating efficiency that did not 

appear to be related to boiler load or a gradual degradation of performance with age.122

Accordingly, the Sierra Club conducted additional comprehensive research—“the 52-Unit 

Study”—to determine whether the initially observed characteristics are common throughout 

the coal-fired fleet and to quantify the adverse impact on GHG emissions associated with the 

observed efficiency variances.

 

121 See EPA, Air Markets Program Data, www.ampd.epa.gov (last visited Nov. 28, 2014).

122 These data are attached as Appendix 1, which we are delivering to EPA separately in a flash drive.
39

In the 52-Unit Study, the Sierra Club examined the long term variability in the 

performance of a representative number of randomly selected coal-fired power plants. In order 

to assure that the selected plants provided an accurate representation of the generation of 

electricity by the coal-fired EGU population as a whole (which would not be the case if focused 

on a large number of lightly used or smaller plants), the 52 Unit Study first grouped each plant 

into a specific “bin” based on its generation in 2012 as reported to EPA’s AMPD. 123 It then 

identified a proportionate number of randomly selected plants within each generation bin for 

further study. Selection was based on applying the standard random number generator in 

Microsoft Excel to each bin of units. Additional “standby” candidates were initially identified in 

each bin in case some of the initially identified candidates were excluded from the study.124 The 

study did not attempt to ensure that units of different designs (such as stoker, wall-fired, or 

circulating fluidized bed units) were equally represented in the sample pool, but information 

about each unit’s design, age, installed pollution controls and capacity factor were captured for 

use in further analysis. We note that the average capacity of units in the study was 597MW and 

the average capacity factor for those units was 0.61. Table 1 provides a profile of each of the six 

generation bins in the study.

Table 1: Bins for Selection of Units

Annual Unit 

Generation

Number of Units Total Generation 

(MMWh/yr)

Number in 

Study

0.1- 1 million MWh 361 174 6

1-2 million MWh 125 179 6

2-3 million MWh 102 253 9

3-4 million MWh 114 395 14

4-5 million MWh 50 221 8

5-9million MWh 42 253 9

For each selected unit, the study captured daily average performance data between 

January 1, 2001 and December 31, 2012 for heat rate, generation, CO2 emission rate, fuel 

consumption, and criteria pollutant emissions, as well as facility data such as the date of first 

commercial operation, maximum capacity, and installed pollution controls. The data permit a 

reasonably objective determination of the temporal variation in carbon emission rate 

(CO2/MWh) at subject plants. The study reports rolling annual averages125 of the daily average 

emission rates in order to minimize the effect of weather and load, to represent long-term 

trends, and to reflect the likelihood that EPA’s guidelines will be based on annual average 

 

123 AMPD data are presented on a gross electric output basis and so do not include the additional 

variability that might be associated with the operation of pollution control devices.

124 Three units were excluded from the study because emission and generation data for the full study 

period was not available. Replacements were selected from the same bin employing the random 

numbers initially generated for that bin.

125 To calculate a unit’s rolling annual average, we calculate its average daily emission performance over 

each consecutive period of 365 operating days for the interval of the study.
40

emissions. To illustrate data from one facility in the study, Figure 2 depicts the daily average 

emission rate at Cross Unit One during the 12-year study interval. 

Fig. 2- Cross Unit One Daily Average Emission Rate, 2001-2012

Table 2: Results of the 52-Unit Study

State Plant Name 2001-

2012 

Lowest

Rolling 

Annual

Average

95th 

Percentile

Lowest

Rolling 

Annual

Average

2001-

2012 

Aver

age

Percent 

ImprovementLowest Rolling 

Annual

Average

Percent 

Improvement95th 

Percentile

Lowest Rolling 

Annual 

Average

Nameplate 

Capacity 

(MW)

AR White Bluff 2026 2049 2175 6.85% 5.79% 900.0

CO Rawhide 1869 1877 2067 9.58% 9.19% 293.6

CO Craig 1919 1927 1982 3.18% 2.77% 534.8

FL Crystal River 1981 2004 2100 5.67% 4.57% 739.2

IA George Neal 

North

1943 1968 2044 4.94% 3.72% 549.8

IA Ottumwa 2118 2147 2322 8.79% 7.54% 725.9

IL E D Edwards 2006 2088 2199 8.78% 5.05% 136.0

IN F B Culley 1880 1916 2214 15.09% 13.46% 265.2

IN Cayuga 1736 1747 1878 7.56% 6.98% 531.0

IN Merom 1936 1961 2070 6.47% 5.27% 540.0

IN Gibson 1726 1736 1817 5.01% 4.46% 667.9

KY H L Spurlock 1732 1779 1894 8.55% 6.07% 357.6

KY Mill Creek 1654 1676 1794 7.80% 6.58% 355.5
41

KY Ghent 1840 1849 1934 4.86% 4.40% 556.5

LA Big Cajun 2 1956 1961 2126 8.00% 7.76% 619.0

MI Dan E Karn 1976 1989 2043 3.28% 2.64% 136.0

MO Rush Island 1705 1845 1910 10.73% 3.40% 621.0

MO Iatan 1940 1949 2152 9.85% 9.43% 726.0

MT Colstrip 2092 2140 2279 8.21% 6.10% 358.0

Navaj

o

Four Corners 1752 1773 1862 5.91% 4.78% 818.1

NC Belews Creek 1677 1688 1765 4.99% 4.36% 1080.1

ND Milton R 

Young

2105 2126 2244 6.19% 5.26% 477.0

NE Sheldon 2091 2141 2323 9.99% 7.83% 108.8

NE Nebraska City 1911 1926 1982 3.58% 2.83% 651.6

NY Somerset 

Operating 

1740 1759 1845 5.69% 4.66% 655.1

OH Muskingum 

River

1835 1840 1887 2.76% 2.49% 237.5

OH FirstEnergy W 

H Sammis

1723 1733 1854 7.07% 6.53% 190.4

OH Walter C 

Beckjord

1763 1770 1945 9.36% 9.00% 244.8

OH J M Stuart 1773 1777 1919 7.61% 7.40% 610.2

OH Cardinal 1741 1758 1831 4.92% 3.99% 615.2

OH Miami Fort 1585 1650 1894 16.31% 12.88% 557.1

PA PPL Brunner 

Island

1538 1548 1641 6.28% 5.67% 405.0

PA Hatfields 

Ferry Power 

Station

1716 1794 1941 11.59% 7.57% 576.0

PA Keystone 1733 1740 1811 4.31% 3.92% 936.0

PA Keystone 1803 1809 1842 2.12% 1.79% 936.0

PA Conemaugh 1682 1707 1802 6.66% 5.27% 936.0

PA FirstEnergy 

Bruce 

Mansfield

1659 1687 1811 8.39% 6.85% 913.7

SC Cross 1737 1826 1998 13.06% 8.61% 590.9

TN Cumberland 1784 1815 1941 8.09% 6.49% 1300.0

TX Harrington 1810 1849 2190 17.35% 15.57% 360.0

TX Fayette 

Power 

Project

1920 1937 2016 4.76% 3.92% 615.0
42

TX W A Parish 1877 1891 2015 6.85% 6.15% 734.1

TX Martin Lake 2092 2113 2183 4.17% 3.21% 793.2

TX J K Spruce 1921 1980 2157 10.94% 8.21% 878.0

VA Clinch River 1660 1692 1803 7.93% 6.16% 237.5

WV Mt Storm 1945 1954 2052 5.21% 4.78% 570.2

WV John E Amos 1773 1782 1879 5.64% 5.16% 1300.0

WY Jim Bridger 1956 2001 2119 7.69% 5.57% 577.9

WY Laramie River 

Station

2107 2153 2265 6.98% 4.94% 570.0

AR Independenc

e Unit One

2050 2058 2121 3.35% 2.97% 900.0

IL Powerton 

Unit Six

1871 1923 2182 14.25% 11.87% 892.8

IL Joppa Unit 

Two

1866 2040 2116 11.81% 3.59% 183.3

AVERAGE 1,851 1,882 2,005 7.60% 6.07% 597

We note that EPA proposes a single HRI target to be applied, on average, to all 

remaining coal-fired units in a state and then allows the state to determine whether to apply 

the HRI targets at all. This approach provides more than enough flexibility to rebut any industry 

argument that individual units might not be able to meet a single proposed HRI target. 

Moreover, EPA need not set a standard that every unit can achieve. To the extent that EPA 

declines to set the standard based on the lowest rolling annual average, however, EPA could set 

the HRI based on a calculation of the 95th percentile of the lowest rolling annual average 

emission rate (instead of the lowest rolling annual average emission rate) for each of the 

affected EGUs in a given state over a long term (such as 2001-2012) and an additional four 

percent reduction of that rate to reflect the improvements to be expected from the hardware 

upgrades we discuss below. This emission rate, multiplied by the generation from each unit in 

the year that the target rate is calculated, would determine the weighted average emission rate 

that is the Block 1 heat rate improvement for the state.126

In the 52-Unit Study, the Sierra Club also examined the extent to which the fleet’s daily 

average emission performance varied with respect to load over the 12-year interval. At some 

units, (such as Powerton Unit 61, as shown in Figs. 3 and 4), there were very large differences in 

emission rates at the same daily load and, indeed, over all load ranges.

 

126 As we discuss below, we recommend that EPA base its goal calculations on generation data from the 

year immediately prior to each state’s submission of its final, approvable plan.
43

Fig. 3- Powerton Unit 61 Daily Average Emission Rate, 2001-2012

Fig. 4- Powerton Unit 61 Daily Average Emission Rate vs. Gross Daily Load, 2001-

2012127

At other units, including Joppa Steam Unit Two (see Figs. 5 and 6 below), variation in emission 

performance over most load ranges was far smaller. Detailed plots for each unit in the study are 

presented in Appendix 1. These data support a conclusion that factors other than load are 

responsible for significant variation in the reported efficiency of many existing coal-fired EGUs.

 

127 In these figures each marker represents the load and emission rate for a single day.
44

Fig. 5- Joppa Steam Unit Two Daily Average Emission Rate, 2001-2012

Fig. 6- Joppa Steam Unit Two Daily Average Emission Rate vs. Gross Daily Load, 2001-

2012
45

Fig. 7- Bruce Mansfield Unit Three CO2 Emission Rate v Load 2001-2012

Here, it may be observed that the Bruce Mansfield emission rates trend up at lower load as one 

would expect. But what is notable is the fact that at and near full load, where this plant 

normally operates, the daily emission rate varies from less than 1,500 lbs CO2/MWh to 2,000 

lbs CO2/MWh. If load, weather and the laws of physics are not the controlling factors, the

question naturally arises as to whether the observed variances may be reasonably be inferred 

to be due to differences in O&M cycles and practices. We believe that these factors are most 

likely the cause of the variances and that EPA is justified in making such an inference in the 

absence of compelling information to the contrary. These variances are different from the 

consistent, systematic improvements in efficiency that one might expect from installation of 

combustion optimization tools or equipment upgrades. Since the study population is randomly 

selected and biased toward units that produce the most generation128 (and presumably are 

maintained better than units that are dispatched less frequently), a conservative estimate for 

the average expected plant improvement through better operation and maintenance of 

existing equipment is six percent. Under the relevant case law the standard does not have to be 

achievable by every single source. 

The results of the 52-Unit Study (provided in Table 2 above) demonstrate that, on 

average, plants have achieved and maintained for a year an emission rate that is 7.60 percent 

better than their long term (12-year) average. The difference between the 95th percentile figure 

 

128 The study population included only six of 361 units (1.7 percent) that generated between 0.1 and 1 

million MWh/yr, but 9 of the 42 units (21 percent) that generated more than 5 million MWh/yr.
46

and the long-term average is 6.07 percent. The use of rolling annual averages minimizes any 

short term efficiency variations based on weather, load, or equipment upgrades. Because there 

are differences in the year-over-year variation experienced at different units, broadly applicable 

factors, such as basic principles of thermodynamics or weather do not appear to be dominant, 

since such factors would create similar variation across all units. The Load v. Rate plots in the 

52-Unit Study reveal a large difference in emission rates even at or near full load.

The several analyses by EPA and the National Energy Technology Laboratory (“NETL”) 

and the Sierra Club 52-Unit Study each confirm that the O&M component of Block 1 should not 

be less than a 6 percent improvement over the long term average for the source.

c. The Record Adequately Demonstrates That Plant Upgrades Can Reduce 

Emission Rates by an Additional Four Percent.

In evaluating the equipment upgrades expected under Building Block 1, EPA provides an 

extensive literature review and discusses the leading technical analysis by the NETL129 and other 

relevant documents.

130 Based on its review, the agency selected four specific technologies on 

which to base the Block 1 heat-rate improvements: economizer replacements, acid dew point 

controls, variable frequency drives for use with fans, and turbine blade overhauls.131 In 

addition, the technical literature identifies the following upgrades for existing coal-fired EGUs 

that EPA does not include in its Block 1 calculations: condenser cleaning, intelligent soot 

blowers, electrostatic precipitator modifications, boiler feed pump rebuilds, air heater and duct 

leakage controls, neural networks, modifications of criteria pollutant control systems (selective 

catalytic reduction equipment and flue-gas desulfurization configurations), and advanced 

packing at cooling towers.132

Describing the four equipment upgrades underscoring its Block 1 methodology, EPA 

concludes that

[t]he remaining four methods are higher cost heat rate improvement items that 

we believe properly fall into the category discussed here as upgrades. Using an 

average of the ranges of potential Btu improvements estimated by Sargent & 

 

129 See, e.g., Dep’t of Energy (“DOE”)/NETL, Improving the Thermal Efficiency of Coal-Fired Power Plants 

in the United States, DOE/NETL Technical Workshop Report (Feb. 24-25, 2010), attached as Ex. 8; NETL, 

Office of Systems, Analyses and Planning, Improving the Efficiency of Coal-Fired Power Plants for Near 

Term Greenhouse Gas Emissions Reductions, DOE/NETL-2010/1411 (Apr. 16, 2010), attached as Ex. 9;

See Phillips & Levine, Fern Engineering, Gas Turbine Performance Upgrade Options, available 

at http://www.fernengineering.com/pdf/gt_upgrade_options.pdf; Ginter & Bouvay, GE Energy, Uprate 

Options for the MS7001 Heavy Duty Gas Turbine (2006), available at http://site.geenergy.com/prod_serv/products/tech_docs/en/downloads/ger3808c_r31.pdf.

130 We have reviewed and summarized a number of published reports that address these issues. See

Appendix 2. 

131 Abatement Measures TSD at 2-33, 2-35.

132 Id.
47

Lundy for the four upgrade methods, upgrades, as defined here, could provide a 

4% heat rate improvement if all were applied on an EGU that has not already 

made these upgrades. . . . The equipment upgrades results are supported by 

numerous studies and by the EPA’s analysis of the costs and associated 

improvements in heat rate that can be attributed to equipment and system 

upgrades.133

EPA declines to adopt a four percent reduction in heat rate because of uncertainty as to the 

extent to which these technologies have been adopted while acknowledging that this approach 

is conservative:

We considered that a 4% reduction in heat rate might be achieved on a coalsteam unit by applying the four higher cost upgrade actions described in Table 2-

13 above. However, because details of current actual unit configurations are 

unknown, and some units may have applied at least some of the upgrades, we 

conservatively estimate the heat rate improvement potential for upgrades at 

2%.134

EPA need not—and, indeed, may not—vary from its technically sound determination 

that an additional four percent heat rate reduction is demonstrated through equipment 

upgrades, especially where it can either directly determine or infer from existing data the 

extent to which these techniques have been employed in the industry. The agency still has time 

to issue an information request under section 114 of the CAA to the five or six largest operators 

of coal-fired power plants if comprehensive information is not provided in their comments. 135

Several of the most effective upgrades, such as turbine upgrades,

136 can only be 

performed during extended outages and may require either major or minor CAA permitting.

EPA can by itself determine the number of permits (if any) that have been issued for such 

projects. Additionally, it is likely that the long-term emission profile of a unit undergoing such 

an upgrade would show a significant emission rate reduction immediately following an 

extended outage and that this improvement would be sustained for several years. Notably, the 

emission profiles of only a small percentage of the plants in the 52-Unit Study demonstrate this 

characteristic. Some units, such as Mill Creek Unit One, do show the emission profile that one 

would expect following a significant upgrade. 

 

133 Id.

134 Id.

135 By limiting the request to fewer than nine persons, delays associated with the Paperwork Reduction 

Act may be avoided. 44 U.S.C. § 3502(3)(a)(i) (statute applies to information requests submitted to “ten 

or more persons”).

136 Upgrading with advanced components is an entirely different technology than a “refurbishment” of 

existing equipment that might occur every 10 years.
48

Fig. 8- Mill Creek Unit One Daily Average CO2 Emission Rate 2001-2012

Other units, such as Cayuga Unit One, show a significant improvement that is not

sustained over the long term, suggesting that whatever upgrade led to the improvement 

needs to be renewed or maintained.

Fig. 9- Cayuga Unit One Daily Average CO2 Emission Rate 2001-2012
49

The data suggest that only four of the 52 units demonstrate a significant, sustained

long-term improvement in CO2 emission rates, such that one might conclude that they had 

undergone capital upgrades that yielded a sustained and substantial improvement in 

performance.137 This indicates both that operation and maintenance practices alone (rather 

than equipment upgrades) can account for the six percent emission reduction indicated by 

the 52-Unit Study and that such upgrades have not been undertaken at most plants. While a 

number of facilities completed turbine blade replacement projects approximately 15 years

ago, those units may well be due for additional upgrading after 20 years, in line with the 

compliance schedule for the Clean Power Plan.

Moreover, published reports by industry demonstrate the relative infrequency of 

these types of projects to date. Siemens asserts that over the past 20 years, it and 

companies that it has acquired—Westinghouse and Parsons Steam Turbine—have 

upgraded turbines at 214 units comprising 88 GW of capacity worldwide.138 Siemens also 

asserts that GE and Alstom have upgraded only two turbines each and MHI only two

turbines worldwide.

139 However, information in other documents suggests that GE and 

Alstom may have upgraded 30 or 40 units each.140 While Siemens may not be correct in its 

determination of the number of turbines upgraded by its competition, it can be presumed 

that Siemens knows how many turbines it has upgraded between 1992 and 2012. This 

information supports a conclusion that turbine upgrades to achieve efficiency 

improvements are not common worldwide or in the United States.

We recognize that some plant operators may object that an incremental emission 

reduction of four percent based on equipment upgrades overestimates what the fleet is 

actually capable of achieving. We urge the agency to reject this argument. As our study 

indicates, few plants have actually invested in the equipment upgrades that Building Block 1 

contemplates, and a four percent heat rate improvement from such upgrades is entirely 

reasonable. While no company is obliged to comment on an EPA proposal, where an operator 

or trade association submits a comment and makes a generalized assertion but fails to provide 

specific information that can be presumed to be in its possession, EPA may take note of the 

omission.

 

137 Mill Creek One, Big Cajun Unit Three, Harrington Unit One and Rawhide Unit One appear to 

demonstrate the expected emission profile.

138 Strunk & Kundu, Siemens, Renovation, Modernization and Life Time Extension Measures on Steam 

Turbines, presentation delivered at Power-Gen India & Central Asia 2012 (Apr. 2012), attached as Ex. 10, 

at 25.

139 Id.

140 See, e.g., Lesiuk, J.F., GE Power Systems, Steam Turbine Uprates, GER 4199 (Oct. 2000). This 

report asserts that at the time of publication there were over 40 GE turbines with advanced 

steam path design (the precursor to GE’s Dense Pack system) in operation. While the article 

focuses on upgrades to existing turbines, it is not known how many of the 40 turbines cited are 

installed at new facilities, rather than as upgrades to existing turbines. 
50

d. EPA Should Employ a Long-Term Baseline for Building Block 1 Rate-Setting and 

Compliance.

The emission data attached hereto as part of the 52-Unit Study demonstrate that 

selecting a single year’s emission data to calculate the HRI expected under a rule can result in 

an unfair allocation to certain individual units. For some units, 2012 represented the best 

performance year over the past decade, while other units had relatively high emission rates in 

2012. At least one state has commented that the unusual status of an individual unit in 2012 

has a significant impact on its calculated BSER emission rate.141 EPA has asked whether it should 

address this problem by permitting states or sources to choose 2010 or 2011 as a baseline year 

instead of 2012. This option is not an appropriate solution to the allocation problem. Any state 

or source that is allowed to choose its preferred baseline year will inevitably select the year 

that minimizes its own compliance obligation. This will invariably reduce the effectiveness of 

the standard, and, since it is unnecessary, will result in a rule that does not reflect the best

system of emission reductions.

Our approach to Building Block 1 resolves the allocation problem without degrading the 

efficacy of the standard. As discussed above, EPA could calculate Building Block 1 emission 

reductions on the basis of the difference between a source’s best rolling annual average rate 

and its long term (2001-2014) emission rate, as set out above and an additional four percent 

reduction based on available plant upgrades. This approach minimizes the impact of any 

particular year of operation and, since it is largely based on improved operation that has 

already been demonstrated by the source, is feasible. States can thereafter allocate compliance 

obligations among in-state sources to address any issues that might remain.

e. EPA Should Adopt a Far More Robust Compliance and Enforcement Scheme.

EPA has proposed to entirely abandon its traditional reliance on reference method 

testing. While we support continuous emission monitoring systems (“CEMS”), we note that the 

level of heat rate improvement (six to ten percent) assumed under Block 1 is not significantly 

larger than the calibration requirements for the continuous monitors. In addition, EPA’s 

different data sets contain unexplained and, at times, technically incredible emission data 

reported by utilities. By way of example, the operators of Killen Station Unit Two142 reported a 

gross CO2 emission rate of less than 1,500 lbs CO2/MWh for over a year in 2005-2006 (see Fig. 

10 below), an emission rate that is neither technically possible for that type of facility nor 

sensible in light of the unit’s performance in proximate years. 

 

141 See Comments Submitted by John Line Stine, Commissioner, Minnesota Pollution Control Agency, On 

EPA’s Proposed Guidelines for Greenhouse Gas Emissions from Existing Sources: Electric Utility 

Generating Units, Dkt. No. EPA-HQ-OAR-2013-0602-17900 (Sept. 16, 2014), at 1.

142 This unit was randomly selected for inclusion in the 50-Unit Study but was excluded from the 

calculations of the average improvement percentages because of this anomaly.
51

Fig. 10- Killen Station Unit Two Average Daily Emission Rate

In the past, EPA has permitted sources to rely on fuel sampling rather than CEMS data 

for compliance purposes. EPA should reject this option. First, fuel sampling is well known to be 

less accurate that CEMS data and will not serve as an adequate substitute. Second, under state 

programs adopted pursuant to the Clean Power Plan, emission data will be used to establish 

and enforce programs with a significant environmental impact and will form the basis of 

tradable emission credits. These data and the credits on which they are based will be far more 

valuable in the future than they are today. For this reason, EPA should work with states and 

sources in the coming years to clean up the existing data sets and tighten the technical 

installation requirements for CO2 CEMS to ensure that accurate and unbiased data are 

produced.

It is our understanding that in the early years of the Acid Rain program, industry 

satisfied a substantial portion of its compliance obligation simply by “recalibrating” the existing 

monitoring equipment. EPA should adopt measures to ensure that the HRI anticipated under 

Building Block 1 are real and not illusory. This would include (1) reference method or other 

upgraded testing either as a relative accuracy test audit (“RATA”) requirement or as a 

standalone test requirement; (2) identification of the specific measures undertaken to achieve 

and maintain the claimed heat rate improvement; and (3) correlation of the recalibrated result 

with the required improvement.143

EPA has proposed that sources should be able to choose from among several potentially 

available reference methods, but has solicited comment on whether EPA should require 

 

143 If it is determined that the monitor is reading at least three percent high (or low), a correction should 

be made both to the emission limitation that is based on that monitor and to the test result so that 

correcting the monitor error does not alter the source’s compliance status.
52

operators to use the reference method that provides the most accurate results for the specific 

source.144 The difference in cost between the available reference methods is quite small in the 

overall scheme and we are aware of no possible reason why EPA should permit a source to use 

any method that is less accurate than the published methods. Indeed, EPA should contemplate 

extending sampling times and volumes to improve accuracy over current Reference Method 2 

variants.

EPA has also asked whether electricity used during startup or when the unit is not 

producing electricity for the grid should be included in the determination of net electric output.

EPA’s regulations define operating day as any day in which fuel is being combusted,145 so

electric usage times when a unit is completely idled would not be included in the calculation, 

but electric usage by pumps, fans, and other components during startup, or for maintaining a 

unit at a hot or warm idle readiness state, are part of the normal process of generating 

electricity and should be included. Exempting this use of electricity unwisely promotes the use 

of plants designed for baseload operation in inefficient load-following service.

f. EPA Should Include Oil and Gas Steam Units in Building Block 1.

In its current proposal for Building Block 1, EPA assumes heat rate improvements will 

occur at coal-fired EGUs only. The agency has articulated no basis for excluding oil and gas 

(“O&G”) steam units from Block 1’s emission reductions, in spite of the fact that some of these 

units exhibit very high heat rates, as illustrated in Fig. 11 below. The data presented also shows 

that there is a greater disparity among heat rates at gas-fired steam units than among the coalfired fleet.

 

144 Often, the most accurate reference method depends on the shape of the stack at the point where the 

monitor is located.

145 40 C.F.R. § 60.41b.
53

Fig. 11- Heat Rates of Coal-Fired EGUs v. Natural Gas-Fired Steam EGUs

EPA has sufficient data to determine the difference between the best rolling annual

average emission rate and the long-term average at each O&G steam unit. This would permit 

the same determination of an O&M-based heat rate improvement for those units as we have 

already proposed for coal-fired EGUs based on the 52-Unit Study. Furthermore, there is no 

reason to believe that plant upgrades, such as turbine blade replacements, would be any less 

effective at EGUs based on the differences in the fuel that generated the steam. Accordingly, 

any determination of BSER for the entire fleet of regulated EGUs must cover O&G steam units

under Building Block 1.

g. EPA Should Determine the Amount of Emission Reductions from Existing 

NGCCs that Should Be Included in Building Block 1.

EPA has also excluded NGCCs from the goal-setting calculations under Block 1. Our review 

of EPA’s AMPD data suggests that opportunities for O&M based reductions for much of the NGCC

fleet that operates at approximately 850 lbs CO2/MWh emission are smaller than for the coalfired fleet. However, the potential for emission reductions may be significant. This issue deserves

far more evaluation than EPA has thus far provided.

The emission profile of the Fore River Generating Station Unit Twelve, selected at random 

by the Sierra Club, provides an example of the potential performance improvements that might 

be anticipated were EPA to conduct a full evaluation. Other units have shown smaller variation. 

We have not compiled data reflecting the profile of the overall fleet.
54

Fig. 12- Fore River Unit Twelve Daily Average Emission Rate 2006-2012

Fore River Unit 12’s emission profile is similar to that of coal-fired units. The long term 

average performance of this unit was 831 Lb/MWh. It’s best annual average performance was 3.4 

percent better at 803 Lb/MWh and its 95th percentile rolling annual average was 805 Lb/MWh, 

3.2 percent better than it’s long term average. This unit’s 2012 emission rate of 855 Lb/MWh is 

6.7 percent higher than its 95th percentile low rolling annual average.

In addition to variation in performance of “better” units, the NGCC population includes a 

number of very high emitting units that deserve additional scrutiny. The following chart is taken 

from EPA’s selection of “new NGCCs”. It is provided to illustrate the difference in performance of 

“better” units, shown above, and high emitting NGCCs not yet evaluated by EPA. 
55

Fig. 13- EPA’s “600 CAMD Data Set”

While we have not yet fully evaluated the extent to which heat rate improvements at 

NGCCs should be incorporated in the Block 1 calculations, it seems clear that those calculations 

should include some improvements to NGCC units. The technical literature146 concerning 

efficiency degradation at NGCCs suggests ongoing O&M efficiency improvements can be achieved 

based on enhanced turbine cleaning operation and regular turbine maintenance.

In addition, the data we have reviewed to date shows degradation in monthly CO2

emission rates at some units (see Fig. 14, below for data from West Phoenix Unit 6A) that may be 

related to the use of the unit without the heat recovery steam generator or to some other 

significant malfunction, suggesting that this issue merits a detailed evaluation. 

 

146 Fig. XX displays the performance data reported by EPA for the 73 units (“EPA Data Set”) converted 

from gross to net emissions by application of a 3 percent correction factor in the NSPS rulemaking. See

Memorandum from OQAPS to EGU, Design Data for New Combined Cycle Facilities, Document ID No. 

EPA-HQ-OAR-2011-0660-0068, (Apr. 12, 2012), attachment entitled "Gas Turbine World Performance 

Specifications.” 
56

Fig. 14- West Phoenix Unit 6A Average Daily Emission Rate

In addition to O&M improvements, there are a number of potential equipment 

upgrades that operators of gas-fired combustion turbines can undertake in order to reduce 

emissions. These include the following:

o Adding heat recovery steam generators (“HRSGs”) to combustion turbines that 

operate more than 1,200 hours per year;

o Installing inlet air chilling or cooling at units that operate at warm temperatures;

o Using inlet air chilling or cooling preferentially to duct burners for increased power; 

and

o Using supplemental solar thermal units to heat the feedwater to the HRSG.

Accordingly, EPA should study the heat rate improvements that can achieved through 

enhanced O&M practices and equipment upgrades at gas-fired units and should incorporate 

these improvements into its final emission guidelines.

We note here that EPA must regulate emissions from all fossil fuel-fired EGUs that 

deliver electricity to the grid, including simple-cycle CTs, peakers, and low capacity factor units. 

We acknowledge that most CTs, peakers, and other low capacity-factor units were not included 

under EPA’s 111(b) rule, which is a prerequisite to coverage under 111(d). In our 111(b) 

comments, argued that EPA must cover all fossil units that deliver electricity to the grid in that 
57

rule.147 We reiterate that point here, and urge the agency to include any such units in the pool 

of EGUs covered under the CPP as well. We also reaffirm and incorporate by reference our 

stance in the 111(b) context that EPA must close off all loopholes relating to EGU definition and 

fuel usage to ensure that facilities do not evade regulation through technicalities.148 The agency 

must foreclose the loopholes we identified in our comments and ensure that the CPP covers 

any unit that would be regulated under the amended 111(b) rule if it were new.

B. Building Block 2

1. While We Oppose Increased Use of Natural Gas, Building Block 2 Is a Surrogate for 

Coal-Plant Retirements Occurring Over the Long Term.

It is well documented that the U.S. coal-fired EGU fleet is aging and faces continued 

economic competition from renewable sources and gas-fired generation, as well as increasing 

public opposition to the use of high-emitting fossil fuels for energy. There is little doubt that the 

sector will continue to experience a large number of retirements and declining capacity factors 

for those units that remain in the near future.

149 Due to a number of factors, including the 

changing economics of the energy sector, a large wave of coal retirements will occur in the 

coming years. The Energy Information Agency (“EIA”) projects 60GW of retirements in the next 

few years.150

Fig. 15- Age of U.S. Coal-Fired EGUs as of 2025

 

147 Sierra Club et al., supra n. 115, at 43-65, 94-101.

148 See id. at 43-70.

149 See EPA, 2012 Coal Unit Characteristics, National Electric Energy Data System (NEEDS v4.10MATS) 

frame (EPA, December 2011) with additional information EPA, 2013, available at 

http://www.epa.gov/airmarkets/images/CoalUnitCharacteristics2012.xls.

In these presentations, data for idled or reserve units that generated less than 100 GWh of electricity in 

2011 have been excluded.

150 See, e.g., EIA, Planned coal-fired power plant retirements continue to increase (Mar. 20, 2014), 

available at http://www.eia.gov/todayinenergy/detail.cfm?id=15491.
58

As Fig. 15 above illustrates, the median age of a coal-fired unit in 2025 (assuming no 

retirements) will be 52 years, whereas the average design life assumed at the time of these 

units’ construction was 30 to 40 years. A review of approximately 300 coal units that retired 

between 1993 and 2012 indicates that the average age at the time of its retirement is 53 

years.151 This figure is comparable to the coal fleet that the Sierra Club’s Beyond Coal Campaign 

has actively tracked since 2010. The average age of retirement for units tracked by the Sierra 

Club that have already retired is 54 years.

This estimate of average retirement age is consistent with the prevailing engineering 

analysis. The highly respected engineering text Steam, Its Generation and Use by Babcock 

&Wilcox notes that unit availability sharply declines after 25 years and assigns a typical life of 

25 years for the superheater, 30 years for the reheater, 35 years for the economizer, and 40 

years for the lower furnace.152 “Life extension” of a unit by replacing these major components 

is sometimes feasible, but is not “routine maintenance” and normally will (and should) trigger 

the application of more rigorous environmental requirements. U.S. coal-fired generation is

expected to decline even more dramatically in the following decade, since there will be 

relatively few coal-fired units under 40 years old by 2025.

Fig. 16 - Age of U.S. Coal-Fired EGUs as of 2025 vs. Generation in 2012

 

151 This list is based on EIA Form 860 Y2012 submissions and covers retirements between 1993 and 2012, 

plus one retirement from 1970.

152 Stultz and Kitto, eds., Babcock & Wilcox Co., Steam: Its Generation and Use (40th ed. 1992), Ch. 46-2, 

46-4, Table 1.
59

Table 3- Age of U.S. Coal-Fired EGUs as of 2025 vs. Generation in 2012

Fig. 16 and Table 3 show that by 2025, the units responsible for 758 GWh in 2012 (47 percent of 

the coal-fired generation that year) will have retired or will be over 50 years old and nearing 

retirement.

153 This assessment is consistent with several analyses by the Brattle Group154 and 

others.155

EPA does not directly address this important issue in the process of establishing BSER.

Instead, the agency projects a reduction in generation from coal-fired EGUs as a result of what 

it terms “gas redispatch” under Building Block 2. However, EPA does not propose to regulate 

the dispatch of NGCCs, but rather to limit the dispatch of coal-fired EGUs. Under this concept,

EPA assumes for purpose of target-setting that the dispatch of existing coal-fired EGUs will be 

reduced by the amount of underutilized NGCC capacity that is available in the state. See, e.g.,

79 Fed. Reg. 34,862-66. EPA is clear that it does not expect that compliance with the target set 

using the coal/gas redispatch will actually occur by the full amount of excess gas capacity that is 

available for redispatch.

156 Indeed, when EPA analyzed the likely compliance path that would be 

the least cost solution to its target rates, its IPM model predicted a substantial number of coal 

plant retirements in lieu of added utilization of existing NGCCs.157

 

153 In 2012, when this cohort was 40 to 50 years in age, the capacity factor started to decline to a level 

associated with “old” units.

154 Aydin, et al., The Brattle Group, Coal Plant Retirements Feedback Effects on Wholesale Electricity 

Prices (Nov. 2013), attached as Ex. 11; Celebi, et al., The Brattle Group, Potential Coal Plant Retirements: 

2012 Update (Oct. 2012), attached as Ex. 12.

155 See, e.g., Union of Concerned Scientists, Ripe for Retirement: The Case for Closing America’s Costliest 

Coal Plants (Nov. 2012), attached as Ex. 13, at 17-18. 

156 See, e.g., 79 Fed. Reg. at 34,863 (“Although producing over 1,400 TWh of generation in 2020 from 

existing NGCC units is not actually required, because states may choose other abatement measures to 

reach the state goals, the EPA nevertheless believes that producing this quantity of generation from this 

set of NGCC units is feasible.”) (emphasis added).

157 See EPA, EPA Analysis of the Proposed Clean Power Plan, Supplemental Documentation for the 

Proposed Clean Power Plan: IPM Run Files, 

Unit Age 

(years)in 2025

Capacity 

(GW)

2012 

Generation 

(GWh)

2012 Capacity 

Factor

<20 8.3 52,954 .75

20-30 3.9 25,204 .69

30-40 22.4 138,247 .70

40-50 99.7 637,786 .73

50-60 102.2 530,063 .59

60-70 39.9 164,032 .47

>70 15.5 64,312 .47
60

EPA set the total reduced coal utilization under Building Block 2 at 376 GWh/yr—a 26 

percent reduction from 2012 coal-fired generation levels.

158 This figure is reasonably close to 

the 425 GWh/yr of coal-fired generation that would occur if all units that are older than 50 

years in 2020 (the proposed effective date of the coal/gas redispatch) were to retire, as 

depicted in Fig. 16 and Table 3 above. As the Brattle Group study cited above points out, the 

rate of “voluntary” coal plant retirements is highly dependent on future natural gas prices 

which are impossible to predict.159 Moreover, plant operators and state regulators are unlikely 

to assign a probability of closing a plant by a certain date until a final determination is made.

For this reason, EPA has made a rational determination not to base its goal-setting calculations

for reduced utilization of coal-fired EGUs based on retirements directly, but instead on the 

availability of underutilized NGCC capacity.

We have serious reservations about the use of natural gas as a replacement for coal. As 

we discuss in Section X, a significant body of evidence indicates that methane leaks associated 

with nonconventional production of natural gas (such as shale or tight gas extraction), as well 

as with the processing, transmission, and distribution phases of the industry, may cause climate 

change impacts on a par with those of coal combustion. In the Clean Power Plan, however, we 

emphasize that EPA does not require any source or group of sources to increase the use of 

natural gas. Instead, the agency uses the existence of underutilized NGCC capacity to mandate 

a reduction in the amount of coal-fired generation. As such, we view the Building Block 2 

exercise as a surrogate or proxy for an estimation of the amount of reduction in coal-fired 

generation that is feasible through retirements or reduced utilization. Building Block 2 

generates far more reduction in coal-fired generation than any other element in the proposal, 

and does so by 2020—the beginning of the compliance period. Building Block 2 also has the 

favorable attributes of being objectively determined using current data and of being 

demonstrably feasible. Further, it results in a set of target emission rates that are likely to meet 

or exceed the reductions that would flow from “business as usual” retirements and 

curtailments.

Therefore, we emphasize that displaced coal should be replaced with renewable energy 

and energy efficiency (as opposed to natural gas) to the greatest extent possible. We believe 

the agency has significantly underestimated the impact of recent RE cost reductions and the 

growth in momentum in that sector and strongly suggest that EPA set a more aggressive set of 

EE/RE targets. While we support the use of a limitation on coal-fired EGU dispatch under 

Building Block 2 for target setting, we intend to work with our state partners to ensure that 

compliance under state plans does not lead to increased use of natural gas.

 

http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html (last visited Nov. 16, 

2014).

158 These calculations are based on data included Appendix 1: Proposed Goals to the Goal Computation 

TSD, available at http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-state-goal-datacomputation_1.xlsx.

159 See generally Aydin, supra n. 154.
61

2. EPA Must Improve and Strengthen Building Block 2.

a. When Applying Building Block 2, EPA Should Account for Retirements 

Occurring in the Near Term.

EPA’s Building Block 2 calculation assumes that emissions from units that retired in 2012 

(the base year) or that will retire (according to their operators) in the next few years are 

relevant for purposes of setting a baseline. However, the rule’s proposed compliance period 

will not begin until 2020. By including business-as-usual retirements in the target-setting 

exercise, EPA fails to identify the best system of emission reductions, since states with recent or 

imminent coal plant retirements may face relatively more lenient standards than other states.

We urge the agency not to allow states to ignore near-term changes in the generation mix, 

including the large number of retirements expected to occur between 2012 and 2017 or 2018,

when final state plans are due.

Under EPA’s approach, generation from fossil fuel-fired steam EGUs is expected to be 

reduced in equal measure to the excess NGCC capacity that is available for redispatch. For 

example, in Virginia, redispatch to underutilized NGCC units would generate approximately 6 

million MWh, so the state is expected to reduce its coal-fired generation160 by that same

amount. Virginia’s coal-fired generation amounted to 13.6 million MWh in 2012, but only 10.3

million of those MWhs were generated by units that are expected to continue operating past 

2015.

161 After a 6 million MWh reduction, the units that continue to operate can either 

generate 7 or 4 million MWh depending on whether or not EPA accounts for near-term coal 

retirements in its final guidelines. This is a much more substantial difference in stringency than 

the range of options under consideration for Building Block 1: a one-percent difference in heat 

rate improvements at these Virginia units is comparable to 40-70,000 MWh of generation 

reduction.162

 

160 In Virginia, 98 percent of fossil fuel-fired steam generation is coal-fired, so the Block 2 reductions are 

borne almost entirely by coal units. 

161 See Goal Computation TSD, Appendix 7: Individual Unit Data, available at

http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-plant-level-data-unit-levelinventory_0.xlsx. As these data show, Virginia coal plants generated 13.6 million MWh in 2012. 

Excluding the units that have been announced for retirement—Bremo Bluff, Chesapeake, Clinch River, 

Glen Lyn, Hopewell, and Yorktown—reduces this figure to 10.3 million MWh.

162 If near-term coal retirements are removed from EPA’s goal-setting formula, as we advocate, we 

recognize that some of Virginia’s excess NGCC capacity may be reduced for redispatch starting in 2020, 

since those units may increase utilization to replace the lost generation from the near term coal 

retirements. However, Dominion Energy, which services the Commonwealth, has announced its intent 

to procure new NGCC generation in the near future, which would leave substantial capacity at existing 

NGCCs available for redispatch. See Dominion, Dominion North Carolina Power's and Dominion Virginia 

Power's Report of Its Integrated Resource Plan Before the North Carolina Utilities Commission and the 

Virginia State Corporation Commission, Dkt. No. E-100, Sub 141, Case No. PUE-2014-00087 (submitted 

Aug. 29. 2014).
62

Tennessee’s situation also illustrates this point. As of this writing, three coal-fired units 

in Tennessee that were included in EPA’s goal-setting calculation have either retired or have 

announced plans to retire prior to the 2020 compliance period: Allen Steam Plant, Johnsonville

Fossil Plant, and John Sevier Fossil Plant.

163 These three facilities generated approximately 7.5 

million MWh in 2012,164 and Tennessee’s 2030 target emission rate under the Clean Power Plan

is 1,163 lbs CO2/MWh. Under Building Block 2, EPA calculates that Tennessee can redispatch 

approximately 3.3 million MWh annually from existing coal plants to existing gas plants if it 

scales up its gas-fired generation to a 70 percent capacity factor. But because the three retired 

(or retiring) units noted above will be removed from the state’s generation mix regardless of 

the rule, the state can simply bypass the reductions needed satisfy Building Block 2. Even if 

Tennessee were to replace the 7.5 million MWh produced by these retiring units with 

generation from new combined-cycle gas plants (which we urge EPA not to permit for use as a 

compliance mechanism), it could avoid redispatching any existing gas units entirely and still 

achieve a final emission rate of 1,111 lbs CO2/MWh if it adopted the measures specified under 

Blocks 1, 3 and 4. In fact, these three retirements would give the state enough of a compliance 

margin that it could reduce its heat rate improvements at existing coal plants to just two 

percent and still meet its final target, assuming full compliance with Blocks 3 and 4. On the 

other hand, if these three plants were simply deleted from both EPA’s target-setting process 

and from a determination of state compliance, Tennessee would need to find some other way 

of achieving the emission reductions under Block 2, which would be determined by the thenavailable excess NGCC capacity.

EPA should improve the fairness and effectiveness of the proposal by excluding nearterm “business-as-usual” plant retirements from the determination of BSER and the state 

emission targets. The most accurate process would be for EPA or each state to calculate the 

state’s Building Block 2 target based on the most recent available data when the state submits 

its compliance plan for the agency’s approval. Thus, if Tennessee were to submit its plan to EPA 

in 2016, the agency would use 2015 data rather than 2012 data to calculate Tennessee’s 

interim and final target emission rates. If the state took an extra year and submitted its plan in 

2017, EPA would use 2016 data. This would ensure that plants that existed as of 2012 but have 

retired since that time are not included in either the target-setting or compliance-determining 

process. It would also ensure the use of the most accurate information concerning available 

underutilized NGCC capacity for purposes of calculating the enforceable state emission targets.

Moreover, EPA should delete from its target calculations and compliance determinations any 

still-existing plants with legally enforceable retirement obligations in place at the time the 

 

163 See Madeline Faber, TVA announces decision about Memphis' Allen Fossil Plant, Memphis Bus. J. 

(Aug. 21, 2014), available at http://www.bizjournals.com/memphis/news/2014/08/21/tva-announcesdecision-about-memphis-allen-fossil.html?page=all; Tenn. Valley Auth., Johnsonville Fossil Plant, 

http://www.tva.com/sites/johnsonville.htm (last visited Nov. 11, 2014); Tenn. Valley Auth., John Sevier 

Fossil Plant, http://www.tva.com/sites/johnsevier.htm (last visited Nov. 11, 2014).

164 See Goal Computation TSD, Appendix 7: Individual Unit Data, supra n. 161.
63

compliance period begins. This would ensure that Building Block 2 is fully effective in states like 

Tennessee.

Our recommended approach for plant retirements would have the added benefit of 

resolving uncertainties regarding combined cycle plants that are currently under construction. 

These plants are defined as NGCC units that were in existence as of the effective date of the 

section 111(b) proposal—January 8, 2014—but that were not operating as of 2012. Under EPA’s 

current approach, 15 percent of the generating capacity of an under-construction NGCC is 

included in Building Block 2’s redispatch scenario, whereas the other 55 percent is reserved “to 

meet other system needs presumed to have motivated the construction of the ‘under 

construction’ NGCCs”—namely, to replace recent or imminent coal retirements.165 However, by 

using 2015 or 2016 data as a baseline, any facilities under construction as of January 2014 will 

likely be in operation and can simply be considered existing NGCC units. As such, any 

underutilized capacity can be included in the redispatch scenario described in Building Block 2. 

b. Under Building Block 2, EPA Should Assume Redispatch of the Highest Emitting 

Units Before Others.

Building Block 2 reflects EPA’s determination that a certain percentage of generation 

from a state’s existing steam EGUs (either coal-fired units or oil- or gas-fired boilers) can be 

replaced with generation from existing and under-construction NGCCs. EPA’s emission targets

assume that an operator can reduce the annual emissions from a coal-fired power plant simply 

by operating the unit less. In order to provide a reasonable assurance of system reliability, EPA 

limits the reduced dispatch of steam EGUs to the amount of generation that existing NGCCs 

could provide if they operated at 70 percent of their capacity. The manufacturers of these units 

have confirmed their technical ability to operate at 70 percent capacity factors, and eGRID data 

reveal that 94 NGCCs operated at capacity factors of 70 percent or higher in 2012.166 We 

therefore support EPA’s technical determination that states can scale down utilization of their 

steam EGUs consistent with an increase in NGCC dispatch up to a 70 percent capacity factor 

without jeopardizing electric system reliability.

However, EPA must reconsider the way it allocates reduced dispatch among the coal 

and O&G steam fleets. EPA’s current proposal follows a proportionate redispatch model with 

regard to coal and O&G steam units. Rather than targeting the coal units, which are generally 

the highest emitters, EPA limits the dispatch of all steam EGUs in proportion to their share of 

the state’s 2012 generation. This approach, which EPA fails to justify or explain, results in a less 

stringent emission limitation, since existing O&G steam units generally emit 20-30 percent less 

CO2 per MWh than existing coal-fired plants. For instance, in Louisiana, the average emission 

rate of coal-fired EGUs is 2,323 lbs CO2/MWh, whereas the average rate of O&G steam units is 

 

165 Goal Computation TSD at 12.

166 EPA, Data File: Unit-Level Data Using the eGRID Methodology (XLS) (June 2014), available at

http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-egrid-methodology_0.xlsx.
64

1,581 lbs CO2/MWh.167 By preserving the historical ratio of coal-to-O&G steam in its standardsetting process, EPA fails to apply the best system of emission reductions. Instead, EPA should 

employ an environmental dispatch limitation for Building Block 2, which would assume that 

dispatch of the highest emitting sources, typically coal-fired EGUs is limited first, while the O&G 

steam fleet would reduce its dispatch only if additional NGCC capacity (up to 70 percent) 

remained after coal generation is reduced to zero.168

For example, in Louisiana, an environmental dispatch limitation approach would reduce 

the state’s final emission target by approximately 6.5 percent (see Table 4 below), which is

greater than the reductions for that state expected under Building Block 1.

Table 4- Emission Goals for Louisiana- EPA’s Approach vs. Environmental Redispatch

Expected 2020 

Emission Rate 

(lb/MWh)

Interim 2020-2029 

Goal (lb/MWh)

Final 2030 Goal 

(lb/MWh)

Louisiana Emission 

Targets- EPA’s Proposal

1,015 948 883

Louisiana Emission 

Targets- Environmental 

Dispatch Limitation 

Approach

949 887 826

On a national level, this approach to dispatch limitation would reduce CO2 emissions by 

around 12 million tons per year, approximately one-sixth of the reduction that will be through 

Block 1’s heat rate improvements across the nation’s coal-fleet.169 In addition, an 

environmental approach to dispatch limitation could expect simple cycle gas-fired combustion 

turbines (“CTs”) that operate at capacity factors more suited for lower-emitting NGCCs (i.e., 

load-following and base load uses above a 10 percent capacity factor) to reduce dispatch in 

favor of available NGCC capacity. This would reduce the use of natural gas and would cut 

emissions even further. 

Environmental dispatch limitation is therefore an easily achievable and straightforward 

way for EPA to bolster the Clean Power Plan’s efficacy and achieve greater CO2 reductions. We 

are aware of no advantages to the proportionate redispatch protocol described in EPA’s rule, 

 

167 See Goal Computation TSD, Appendix 1- Proposed Goals, supra n. 161 (including 2012 emissions data 

for each state and calculating reductions under each building block).

168 In a handful of states, the O&G steam fleet is higher-emitting on average than the coal fleet, and 

would hence limit their dispatch first under the approach we describe in this section.

169 EPA describes the Building Block 1 emission reductions as occurring prior to application of Building 

Block 2, but in its calculation of state emission targets, the agency applies the 6 percent heat rate 

improvements to the amount of coal-fired generation that is assumed to remain after the curtailments 

under Building Block 2. By our calculation, then, Block 1’s heat rate improvements will reduce emissions 

nationwide by 72.6 million tons of CO2.
65

and the agency has not explained (nor provided record support for) its decision. Therefore, if 

the Clean Power Plan is to reflect the best system of emission reduction, as the Clean Air Act 

requires, EPA must adopt the environmental dispatch limitation approach we have described in 

this section.

c. Under Building Block 2, EPA Should Adopt a Regional Redispatch Approach.

EPA’s current model for Building Block 2 limits NGCC utilization to the point at which all 

of the electricity generated by steam-driven fossil plants has been replaced with electricity from 

NGCC units, even if the latter have not reached a 70 percent capacity factor. This occurs in 

states with excess NGCC capacity and little existing coal-fired generation. EPA’s approach also 

limits coal-fired EGU dispatch in coal-reliant states with no or limited in-state NGCC facilities 

such as Kansas and Kentucky, even though customers in those states are served by gas-fired 

units in neighboring states that dispatch without regard to state lines. By contrast, some states 

with considerably less carbon-intensive electricity sectors must undertake significant changes 

to their generation mix to meet Block 2’s reduction assumptions. For example, Oklahoma 

produced roughly equal amounts of coal- and NGCC-fired generation in 2012, and its 

obligations under Block 2 assume a full 50 percent reduction in coal-fired generation starting in 

2020. 

In its recent NODA, EPA solicits comment on whether a regional rather than statespecific structure for Block 2 could ease these disparities. See 79 Fed. Reg. at 64,547. We 

support a regional approach because it would more accurately calculate the availability of 

underutilized NGCC capacity nationwide and more fairly assign emission reduction obligations 

across the states. Existing power plants are, in reality, components of a complex and 

interconnected electricity grid that stretches across state lines. EPA’s final guidelines will 

embody the best system of emission reduction if the state goals reflect the full extent of 

emission reductions available to coal-fired units, whether the NGCC excess capacity is in the 

same state or a neighboring one. The map of independent system operators (“ISOs”) is 

presented in Fig.14 below.
66

Fig.17- ISO Divisions Across the United States and Canada

To provide one example, ISO-NE, New England’s regional transmission organization, includes 

300 generating plants and 8,000 miles of transmission lines. Within each ISO system, plant 

dispatch and electricity flows are determined not by individual state regulators but by ISO-NE 

rules and bidding activities. These factors—not state lines—should determine the actual 

amount of existing NGCC capacity that is available for redispatch under Block 2.

In the following table we present a calculation of the coal dispatch limitation that occurs 

if the available existing NGCC capacity in nine states that are served by the Midwest 

Independent System Operator (“MISO”) are considered as a group. A regional allocation of 

redispatch under Block 2 would produce little change in the overall limitation on coal 

generation, but would provide for a more even allocation of emission reduction obligations 

between “low impact” states, such as North Dakota and Indiana, and “high impact” states, such 

as South Dakota, Michigan and Minnesota. This approach would also facilitate regional 

cooperation by limiting the difference between rule’s impact on states that are “winners” and 

those that face a more challenging regulatory burden.

170

 

170 A regional approach to coal dispatch limitation will also provide for more equitable treatment of coalfired units on lands of the Navajo Nation and of the Ute Tribe of the Uintah and Ouray Reservation, 

which lack NGCC capacity entirely. We will submit comments on EPA’s supplemental proposal for Indian 

lands and U.S. Territories by the December 19, 2014 submission deadline.
67

Table 5- MISO Regional Coal Dispatch Limitation

State Historical Coal 

Generation (MWh)

EPA's Proposed 

Coal Generation 

(MWh)

Regional Dispatch 

Coal Generation 

(MWh)

South Dakota 2,923,161 958,046 2,460,084

North Dakota 28,186,691 28,186,691 23,721,453

Michigan 53,210,780 41,091,564 44,781,313

Indiana 87,213,268 83,034,543 73,397,244

Illinois 79,166,165 66,157,723 66,624,936

Missouri 72,939,512 65,012,570 61,384,687

Wisconsin 32,112,721 24,062,122 27,025,535

Iowa 33,055,156 26,779,114 27,818,673

Minnesota 21,989,584 10,699,001 18,506,070

SUM 410,797,038 345,981,374 345,719,995

Applying the same concept to five of the states served by the Western Electric 

Coordinating Council (“WECC”) results in an additional 11 million MWh of reduced coal 

generation (see Table 6 below). It also redistributes the allocation of compliance obligations

between Montana and Wyoming, on the one hand, which share none of the Building Block 2 

burden under EPA’s plan, and Nevada, on the other hand, which would otherwise be expected 

to eliminate all of its existing coal-fired generation.

Table 6- Western States Regional Coal Dispatch Limitation

State Historical Coal 

Generation 

(MWh)

EPA's Proposed 

Coal Generation 

(MWh)

Regional Dispatch 

Coal Generation 

(MWh)

Wyoming 42,907,427 42,617,555 32,131,352

Utah 27,332,140 20,797,210 20,467,753

Montana 14,447,406 14,447,406 10,818,982

Nevada 4,133,662 0 3,095,505

Idaho 0 0

SUM 88,820,635 77,862,171 66,513,592

The preceding tables are intended to be illustrative; to simplify the calculation process 

we have assumed that all of the units in the states are part of MISO or WECC (which is almost 

but not completely correct). Moreover, we recognize that it may be more appropriate to 

organize and evaluate generating capacity on a sub-regional basis. The concept we recommend 

is for EPA to evaluate the available underutilized capacity on the basis of how the electric 

generation and transmission system actually works, rather than on the basis of state 

jurisdiction. Once a dispatch limitation is determined for each coal-fired unit in a given system, 
68

each unit’s assumed available limitation can then be incorporated in the calculation of the 

emission targets for the state in which that unit is located.

d. EPA Should Incorporate Appropriate NGCC Emission Rates in Its Determination 

of Block 2 Emission Rate Reductions.

In its proposal, EPA assumes that the fossil-steam generation curtailed under Block 2 will 

all be replaced by existing NGCC capacity in the state at the current emission rates of those 

units. In our comments on Block 3 we demonstrate that EPA should assume that at least some 

of the displaced fossil-steam generation is replaced by renewable generation. As we show 

above, however, it is also reasonable and appropriate to require some level of HRI for NGCCs, 

especially high-emitting existing NGCCs. Accordingly, whether or not EPA explicitly adopts Block 

1 HRI as we suggest, the agency should base emission levels for any NGCC replacement capacity 

that it assumes on reasonable HRI at those units in determining Block 2 emission rate 

reductions.

C. Building Block 3

1. Building Block 3 is Legally and Technically Justified as an Element of BSER, but EPA 

Must Modify Its Approach to Strengthen It.

Renewable energy generation, either as a component of the BSER or as a measure to 

quantify reduced utilization from affected EGUs, is a cost-effective system of emission 

reduction. It also has much lower environmental impacts than fossil fuel-fired generation and is

adequately demonstrated, as shown by the experience of states and utilities that have 

implemented renewable energy policies and programs over the course of years and decades. It 

is therefore wholly appropriate as an element of the Clean Power Plan.

a. Declining Costs of Renewable Energy

Renewable energy must play a central role in any regulatory program designed to 

reduce CO2 emissions from the nation’s electric sector. Not only are RE resources fully capable 

of replacing fossil fuel-fired generation from a technical standpoint, these clean technologies 

have undergone dramatic price reductions in both the long- and near-terms, and are now at or 

near grid parity with, or are cheaper than, fossil-fired options in many parts of the country. This 

trend will only increase in the coming years as wind and solar technology become increasingly 

economical in both the U.S and around the world.171

 

171 See, e.g., Deutsche Bank, Solar- 2014 Outlook: Let the Second Gold Rush Begin (Jan. 6, 2014), attached 

as Ex. 14, at 8 (indicating that solar energy has reached grid parity in at least 10 states without additional 

state subsidies with another 12 states fast approaching grid parity; this could grow to as many as 47 

states by the end of 2016); Citi, Energy 2020: The Revolution Will Not Be Televised as Disruptors Multiply

(July 28, 2014), attached as Ex. 15, at 41 (“Solar has reached socket (residential) parity in many global 

regions at the residential level with more to come, and utility scale parity expected over the next few 
69

Abundant research documents a large decline in the prices of wind and solar generation 

in recent years. Lazard’s most recent estimate of the levelized costs of different generation 

resources shows that wind prices have decreased on average by 58 percent and utility-scale 

solar photovoltaics (“PV”) have decreased 78 percent over the last five years.172 These 

significant decreases are primarily the result of technological improvements that have enabled 

projects to operate at higher capacity factors, as well as a decline in the price of inputs in the 

manufacturing supply chain.173 Specifically with respect to wind, turbine prices have decreased 

substantially in recent years due to improved turbine technologies and more favorable 

contractual terms for turbine purchasers, as well as continued technological advancements 

(such as increased rotor diameters and hub heights) that are improving the projects’ capacity 

factors.174 With respect to solar, lower prices of inverters and racking systems have contributed 

to this decrease.175

Fig. 18- Recent LCOE Trends of Wind and PV Solar176

Renewable generation, particularly wind power, has become more cost-effective than 

conventional generation resources in many circumstances. The left blue bars in Figure X below 

represent the lower end and the red bars represent the higher end of the current unsubsidized 

 

years. Besides pure economics, the need for utilities to diversify their fuel mix is crucial to insulating 

them from volatility and the likely upward movement in gas prices over the longer term, a need that was 

well documented as we surveyed electric utilities in the US.”); Press Release, Bloomberg New Energy 

Finance, Onshore Wind Energy to Reach Grid Parity by 2016 (Nov. 10, 2011), attached as Ex. 16.

172 See Lazard Ltd., Lazard’s Levelized Cost of Energy Analysis—Version 8.0 (Sept. 24, 2014), attached as 

Ex. 17, at 9.

173 Id.

174 DOE, 2013 Wind Technologies Market Report (Aug. 2014), attached as Ex. 18, at 47-48.

175 Solar Energy Indus. Assoc. (“SEIA”), U.S. Solar Market Insight Report, 2013 Year-in-Review: Executive 

Summary (2014), attached as Ex. 19, at 5.

176 Lazard, supra n. 172, at 9.
70

costs of different generation resources, including utility-scale wind and solar, NGCC units, 

nuclear plants, conventional coal-fired power plants, and integrated gasification combined cycle 

(“IGCC”) units. While utility-scale solar is still more expensive than natural gas, it is currently 

competitive in more than ten states. Analysts estimate that, in these grid parity states, installed 

capacity growth will grow about 300 percent in the next four years due to improved economics 

of solar, including the availability of low cost financing and solar leasing.

177

Fig. 19- LCOE of Different Electricity Generation Resources178

Wind power purchase agreement (“PPA”) prices have also reached all-time lows. 

According to the Department of Energy (“DOE”), the national average levelized price of wind 

PPAs has fallen from $70/MWh in 2009 to $25/MWh in 2013.179

 

177 Deutsche Bank, supra n. 171, at 8. Deutsche Bank also estimates that, even with a lower tax credit (10 

percent), solar would reach price parity with conventional electricity in more than half of the country—

36 states—in 2016. Id., at 9.

178 Prepared with data from Lazard, supra n. 172, at 2.

179 DOE, supra n. 174, at 58.
71

Fig. 20- Generation-Weighted Average Levelized Wind PPA Prices by PPA Execution 

Date and Region180

b. Environmental Impacts and Benefits of Renewable Energy

Renewable technologies such as wind and solar emit no carbon in their operation.

Renewable energy actually reduces emissions of CO2 and other air pollutants such as NOx, SO2, 

Hg, and PM insofar as renewable generators displace or reduce the utilization of fossil fuel-fired 

units.181 EPA has estimated that the implementation of its proposed building blocks, which 

include incremental renewable energy generation, would result in CO2 emissions reductions of 

30 percent below 2005 levels.182 However, as we discuss below, UCS estimates that higher 

levels of renewable energy deployment in target-setting would result in even larger 

decreases—approximately 40 percent, assuming that renewables primarily displaced natural 

gas.183 If renewable generation instead displaced coal, the amount of carbon reductions would 

be considerably larger still.

184

Renewable generation has reduced non-air environmental impacts, particularly when 

compared to fossil fuel-fired generation. Solar technologies have “very low operating costs and 

require minimal non-solar inputs.”

185 In addition, solar PV panels installed on rooftops have no 

land use impacts.186 For utility-scale solar energy, the land-use impacts “vary from region to 

region” and depend on the approaches taken to avoid or mitigate those impacts during project 

 

180 Id. at 59.

181 DOE, SunShot Vision Study (Feb. 2012), at 2.

182 RIA at 3-20, Table 3-6.

183 Union of Concerned Scientists (“UCS”), Policy Brief: Strengthening the EPA’s Clean Power Plan

(October 2014), attached as Ex. 20, at 4.

184 Id.

185 DOE, supra n. 174, at 1.

186 Id. at 4-5.
72

development.187 With regard to water impacts, solar PV significantly reduces water 

consumption from the conventional electricity generation it displaces, as it requires very little 

water for the occasional washing of panels.188 Water impacts of concentrated solar power 

(“CSP”) depend on the type of cooling technology used; if CSP is deployed with dry or hybrid (as 

opposed to wet) cooling towers, water use can be reduced by 40 to 97 percent as compared to 

wet cooling.189 In addition, wind generation does not produce solid waste or require cooling 

water. 79 Fed. Reg. at 34,883. 

Renewable energy technologies also help to diversify the energy mix and reduce the 

economic risks associated with overreliance on natural gas. Wind PPAs, for example, currently 

exhibit a “high degree of long-term price stability,” with average prices holding steady through

2031.190 Similarly, multi-decade solar energy PPAs allow utilities to lock in low prices for many 

years. In contrast, natural gas prices can be “quite volatile . . . and difficult to lock in for any 

significant duration,” making it difficult to capitalize on the low prices of gas in the long term.191

While the short-term risk of gas prices can be hedged using conventional financial instruments 

and investment techniques, these options are not effective for longer-term hedging.192 In 

contrast, wind and solar contracts “provide ample long-term hedge value . . . [and] are, on 

average, competitive natural gas fuel savers.”

193

c. Transmission and Integration Requirements of Renewable Technologies

Recent developments in transmission line construction and best practices in renewable 

energy dispatch are helping to address any reliability concerns with respect to wind energy.

Although inadequate transmission capacity can hinder both new and existing wind projects, 

recent developments in transmission line expansion mitigate these concerns.194 Over 3,500 

miles of transmission lines came online only in 2013 and investor-owned utilities made 

transmission investments of $17.5 billion.195 There are currently 15,000 miles of transmission 

lines and over 170 projects in various stages of development in the U.S., worth more than $60 

billion in potential investments.196 The Edison Electric Institute has estimated that 76 percent of 

this new transmission capacity “would—at least in part—support the integration of renewable 

 

187 Id. at 16.

188 Id. at 15.

189 Id.

190 Bolinger, Mark, Lawrence Berkeley Nat’l Lab. (“LBNL”), Revisiting the Long-Term Hedge Value of Wind 

Power in an Era of Low Natural Gas Prices, LBNL-6103E (March 2013), attached as Ex. 21, at 4-13, 22.

191 Id. at 8, 10.

192 Id. at 3, 4, 22.

193 Id. at 21.

194 DOE, supra n. 174, at 66-67. 

195 Id. at 66.

196 Id. at 66-67. 76 percent of which would—at least in part—support the integration of renewable 

energy
73

energy.”

197 AWEA has also identified fifteen near-term transmission projects that, if completed, 

could support almost 60 GW of additional wind capacity.198

Of particular significance is the Competitive Renewable Energy Zones (“CREZ”) project in 

Texas.199 Completed in 2013, the CREZ includes “almost 3,600 circuit miles of transmission lines 

and was designed to accommodate up to 18,500 MW of total wind power capacity,”200 and 

ERCOT reports that this project has largely resolved the problem of wind-related congestion 

between West Texas and other areas.

201 Other recent examples include the One Nevada 

transmission project, the Southern Nevada Intertie Project, and the Southwest Intertie Project 

North, each 500-kV and spearheaded by LS Power or an affiliate.

202 Offshore wind would also 

ease transmission constraints along the East Coast. In Maine, Emera Maine and Central Maine 

Power recently entered into a memorandum of understanding to explore the development of 

transmission projects to support 2,100 of wind capacity.203 And because offshore wind is loadfollowing, it can help lower grid congestion at peak demand periods.

As DOE reports, “[e]xperience in operating power systems with wind energy is . . .

increasing worldwide, leading to an emerging set of best practices.”204 These practices have 

helped balance concerns regarding the variable nature of wind generation. For example, all 

ISOs and RTOs (as well as many utilities) now use centralized wind energy forecasting systems, 

a “vital [tool] for meeting reliability requirements and efficient scheduling of resources.”205

Furthermore “ISOs continue to refine scheduling and commitment processes, including updates 

like the MISO look-ahead commitment, the incorporation of wind into dispatch at MISO, the 

flexible ramping constraint at the CAISO, and sub-hourly exchange between markets.”206 Recent 

integration studies have estimated lower costs of wind integration than previously assessed; for 

example, Portland General Electric’s estimates of integration costs have decreased from 

$11/MWh to less than $4/MWh.207

d. Renewable Energy Generation is “Adequately Demonstrated.”

Renewable energy technologies are “adequately demonstrated” for the purposes of a 

BSER analysis under section 111. Wind and solar resources have been deployed by states, 

 

197 DOE, supra n. 174, at 66.

198 American Wind Energy Association (“AWEA”), U.S. Wind Industry Annual Market Report Year Ending 

2013, “Transmission,” available at

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=6316&RDtoken=9132&userID=.

199 DOE, supra n. 174, at 67-68. 

200 Id. at 67

201 Id.

202 Id. at 68.

203 Id.

204 Id. at 69.

205 Id.

206 Id. at 71.

207 Id. at 70. 
74

utilities, and merchant generators. These technologies have been growing rapidly and are 

becoming more cost-effective strategies for CO2 emission reductions than approaches that 

continue to rely on conventional generation resources.

In 2010, solar energy provided less than 0.1 percent of U.S. electricity demand,208 but 

solar installed capacity is now growing faster than any other renewable generation resource.

Continued research and development, market forces, and state and federal policies “have

helped reduce PV prices sharply and . . . have positioned the U.S. PV market for rapid future 

growth.”

209 In addition, solar has enormous technical potential. Solar resources in the U.S. are 

“mostly good to excellent” at about 1,000 to 2,500 kWh/m2/year.210 Seven states in the U.S. 

Southwest (Arizona, California, Colorado, Nevada, New Mexico, Texas, and Utah) have “some of 

the best solar resources in the world.”

211

Grid-connected PV has grown significantly since the early 2000s in residential, 

commercial, and utility-owned applications, as shown in Fig. 21.

212 The utility market segment 

increased markedly between 2009 to 2010,

213 and growth has been particularly significant in 

recent years in Arizona, California, Colorado, New Mexico, New Jersey, New York, and 

Nevada.214

Fig. 21- U.S. Annual Installed Grid-Connected PV Capacity by Market, 2001-2010215

 

208 DOE, supra n. 181, at 3. 

209 Id. at 4.

210 Id. at 34.

211 Id. at 4-5, 25, 36-37.

212 Id. at 28.

213 Id.

214 Id.

215 Id.
75

Wind technologies also evolved significantly in the last 15 years. The average nameplate 

capacity of newly installed wind turbines in 2013 was 1.87 MW, 162 percent higher than in 

1998-1999.216 Average hub heights and rotor diameters have also scaled during this period. The 

average hub height of wind turbines installed in 2013 was 80 meters, 45 percent greater than in 

1998-1999.217 Average rotor diameters have increased even faster; the average rotor diameter 

in 2013 was 97 meters, 103 percent greater than in 1998-1999.218 Larger turbines are driving 

higher capacity factors for wind projects and allowing for increased generation from these 

resources.

219

Renewable portfolio standards (“RPS”) have been a major driver of renewable energy 

deployment in the U.S. Twenty-nine states and the District of Columbia have established RPS 

programs extending in most cases through 2020 or 2025.220 Five additional states have 

voluntary renewable energy goals.221 California has the most ambitious RPS in the country, 

requiring investor-owned utilities, electricity service providers, and community choice 

aggregators to purchase 33 percent of their electricity from renewable energy resources by 

2020.222 Spain and Germany have set target shares of energy from renewable resources for 

their gross energy consumption for 2020 that are even more stringent than EPA’s proposal.

RPS programs in the U.S. have contributed to build robust markets for the supply of 

renewable generation technologies. States with mandatory RPS programs “have collectively 

deployed approximately 46,000 MW of new renewable energy capacity through year-end 

2012.”223 Thirteen states installed a total of 1,087 MW of new wind energy capacity in 2013, 

and a total of 61,110 MW was operational at the end of that year in thirty-nine states and 

Puerto Rico.224 In that same year, solar PV reached 4,751 MW, nearly fifteen times the capacity 

installed in 2008.225 410 MW of CSP capacity were also installed in 2013.226 According to SEIA, 

more solar capacity was installed in 2012 and 2013 than in the thirty years prior, and these 

 

216 DOE, supra n. 174, at 30. 

217 Id.

218 Id.

219 Id. at 30, 41.

220 Bingaman et al., Stanford Steyer-Taylor Center for Energy Policy and Finance, The State Clean Energy 

Cookbook, A Dozen Recipes for State Action on Energy Efficiency and Renewable Energy (2014), attached 

as Ex. 22, at 31.

221 Id.

222 Cal. Exec. Order No. S-14-08 (Nov. 17, 2008), available at http://gov38.ca.gov/index.php?/executiveorder/11072/ .

223 Heeter et al., NREL/LBNL, A Survey of State-Level Cost and Benefit Estimates of Renewable Portfolio 

Standards, No. NREL/TP-6A20-61042/LBNL-6589E (May 2014), attached as Ex. 23, at iv.

224 AWEA, U.S. Wind Industry Annual Market Report Year Ending 2013, “U.S. Capacity & Generation,” 

available at

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=6305&RDtoken=35392&userID=.

225 SEIA, supra n. 175, at 3.

226 Id. at 4.
76

trends are expected to continue.227 Bloomberg New Energy Finance estimates that by 2030, the 

global power mix will evolve from today’s system, in which two-thirds of our electricity comes 

from fossil fuel combustion, to one in which over half of all generation is produced by 

renewable resources.228 And NREL has estimated that given today’s commercially available 

technologies, “[r]enewable energy resources . . . could adequately supply 80% of total U.S. 

electricity generation in 2050 while balancing supply and demand at the hourly level.”229

Markets for renewable energy certificates, which facilitate investment in renewable 

energy, are also well-established. Renewable energy has been traded for nearly two decades, 

during which time states have developed “integrated electronic tracking systems and 

standardized approaches to trading and establishing ownership of renewable energy.”

230 RECs 

were used initially in the 1990s “as a means of accounting for energy procurement obligations 

like renewable portfolio standards (RPS), or power-source disclosure programs where load 

serving entities were required to inform their customers about the sources of electricity relied 

on to provide service.”231 Today, REC procurement is a common practice in states with 

mandatory RPS programs and with voluntary markets.232 Federal and state agencies, ISOs and 

RTOs, and electricity market stakeholders rely on RECs to establish ownership and 

environmental attributes of those resources.233 There are currently ten regional REC tracking 

systems in the country, which are used to demonstrate compliance with RPS programs.234

2. As Proposed, Building Block 3 Is Too Conservative and Must Be Strengthened.

In spite of the environmental benefits and increasing affordability of renewable energy, 

renewable energy resources remain largely untapped nationwide. According to estimates 

produced by the DOE’s National Renewable Energy Laboratory, no state has achieved more 

than .01 percent of its technical potential for utility-scale solar energy (which includes both 

solar thermal stations and photovoltaic arrays).235 Onshore wind generation has achieved 

greater market penetration, with five states exceeding ten percent of their technical potential 

 

227 Id.

228 Bloomberg New Energy Finance, 2030 Market Outlook: Global Overview, 

http://bnef.folioshack.com/document/v71ve0nkrs8e0/who42hnkrs8fo (last visited Nov. 16, 2014).

229 NREL, Renewable Electricity Futures Study: Executive Summary (2012), attached as Ex. 24, at 14.

230 Quarrier & Farnsworth, Center for Resource Solutions/Regulatory Assistance Project, Tracking 

Renewable Energy for the U.S. EPA’s Clean Power Plan: Guidelines for States to Use Existing REC Tracking 

Systems to Comply with 111(d) (June 25, 2014), attached as Ex. 25, at 3.

231 Id. at 4.

232 Id.

233 Id.

234 Id. at 5.

235 These percentages were derived from data provided in the data file for EPA’s Technical Support 

Document: Alternative Renewable Energy (RE) Approach (“Alternative RE TSD”) (June 2014), available at 

http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-proposed-re-alternativeapproach.xlsx.
77

and two states exceeding 25 percent.236 However, a full 29 states have implemented less than 

one percent of their technical potential for onshore wind, and a full eleven states had no 

installed wind capacity at all as of 2012.237 If the United States is to develop its renewable 

energy capacity at a level needed to avoid the worst effects of climate change, EPA must 

provide the proper regulatory drivers.

It is therefore not only appropriate but imperative that EPA include as one of the 

cornerstones of the Clean Power Plan increased generation from RE sources. However, both 

EPA’s primary and alternate proposals for Building Block 3 will provide only minimal increases in 

RE generation nationwide beyond what can be expected in a business-as-usual (“BAU”) 

scenario. EPA’s proposals, with respect to renewable energy, do not reflect the best system of 

emission reduction, but rather the status quo system of emission reduction.

There are a number of ways in which EPA could modify Building Block 3 that would 

more appropriately reflect the best system of emissions reduction. EPA could correct several 

flaws in its RPS-based approach to setting the Building Block 3 targets, as described below. EPA 

could also refine its Alternative RE approach to update the cost and capacity assumptions used 

in the IPM modeling and eliminate the benchmark development rate cap that serves as an 

artificial cap on the RE potential of states. The Natural Resources Defense Council has 

undertaken IPM modeling using updated information, which yielded far higher RE targets that

EPA should consider adopting.

Finally, EPA should consider a proposal by the Union of Concerned Scientists (“UCS”) 

that reformulates the renewable energy components of Building Block 3 based on 

demonstrated growth rates of RE. The UCS approach approximately doubles the amount of 

generation nationwide from these resources by 2030 without incurring significantly greater 

costs. UCS released a report238 on October 14, 2014 describing its proposal and will be 

submitting to EPA a separate set of comments that provide a comprehensive analysis of its 

proposal. We support UCS’s demonstrated growth approach and offer several comments on it 

below.

Below, we discuss EPA’s current proposals for assessing the BSER level of renewable energy 

potential for each state and then canvass the shortcomings of EPA’s two approaches for RE.

With respect to EPA’s Alternative RE approach, we discuss improvements to the IPM modeling 

evaluated by NRDC. Next, we describe in more detail an alternative proposal, based on UCS’s 

demonstrated growth approach, and explain how this RE model would avoid the shortcomings 

of EPA’s two options. Finally, we directly address several of the questions posed in the 

preamble regarding RE.

 

236 Id.

237 Id.

238 See UCS, supra n. 183.
78

a. EPA’s Current Proposals for Building Block 3

i. EPA’s Primary Proposal

EPA’s primary proposal for Building Block 3 is discussed in its Federal Register preamble 

at 79 Fed. Reg. 34,866-70 and is given comprehensive treatment in the agency’s Clean Power 

Plan technical support documents. We therefore discuss these programs only in brief. For the 

purpose of setting RE targets, EPA’s primary Block 3 proposal establishes six multi-state regions 

based primarily on North American Electric Reliability Corporation (“NERC”) regions and 

Regional Transmission Organizations (“RTOs”). EPA then averages the 2020 RE percentage 

requirements in the renewable portfolio standards (“RPS”) for the states in each region that 

have such programs and multiplies that average percentage by each region’s 2012 baseline (i.e., 

the total electricity generation in the region in 2012). The resulting product is the 2030 regional 

RE target. EPA then calculates the annual percentage growth that the region would need to 

meet each year between 2017 and 2030 in order to meet its 2030 regional target (assuming 

that the region’s total RE generation starting in 2017 is the same as its 2012 baseline). Each 

state is then expected to increase its RE generation each year between 2017 and 2030 

according to the average growth factor in its region.

Notably, each state’s expected RE generation is capped when it reaches what EPA has 

called its “maximum state target,” expressed as the average 2020 RPS percentage for the 

state’s region multiplied by the state’s total generation in 2012.239 So as not to confuse these 

limits with actual targets, we will refer to these as “maximum RE amounts.” For example, in the 

Western region, which includes California, the regional growth factor is 6 percent annually.240 If 

California begins its annual 6 percent increase in 2017, it hits its statewide target of 41,150,704 

MWh in 2022, at which point its expected annual growth drops to zero. California’s maximum 

RE amount represents the average RPS percentage requirement for 2020 in the Western states 

(21 percent) multiplied by California’s total 2012 generation (approximately 200 million MWh). 

By contrast, another state in the Western region, Wyoming, has a maximum RE amount of 

approximately 10.2 million MWh, but applying the 6 percent regional growth factor between 

2017 and 2030 yields only 9.4 million MWh of renewable generation in Wyoming. Hence, 

because the state is only expected to satisfy the regional growth requirements, rather than its 

maximum RE amount, it falls short of that maximum amount by some 800,000 MWh.

 

239 See EPA, Technical Support Document: GHG Abatement Measures (“Abatement Measures TSD”), No. 

EPA-HQ-OAR-2013-0602 (June 10, 2014), available at http://www2.epa.gov/carbon-pollutionstandards/clean-power-plan-proposed-rule-ghg-abatement-measures, at 4-19 (“If, as the growth factor 

is applied annually, a state reaches an RE generation level that equals or exceeds the regional RE percent 

generation target, their RE generation target is made equal to the RE percent generation target as 

applied to that state’s 2012 generation and is kept at that level for the remainder of the time period. If a 

state’s RE generation in 2012 has already exceeded the regional RE target, their annual RE generation 

levels are held to the regional RE target for all years in the 2017-2029 time period.”).

240 For both the California and Wyoming examples, we used data provided in the Proposed Renewable 

Energy (RE) Approach data file for the Abatement Measure TSD, available at 

http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-proposed-re-approach.xlsx.
79

ii. EPA’s Alternative Approach

EPA has also developed an alternative approach to Building Block 3 based on each 

state’s technical and market potentials for RE development.241 Under this approach, EPA would 

establish national benchmark development rates for different renewable technologies. To 

calculate these benchmarks, EPA establishes the development rate in each state for four types 

of RE resources by calculating the ratio of the state’s actual generation from that resource 

compared to NREL’s technical potential for that resource. The agency then averages the 

development rates for the 16 leading states for each technology to ascertain a national 

benchmark development rate for each technology, which is then applied to each state’s 

technical potential. EPA also calculates an IPM-modeled market potential for each resource 

based on assumed cost reductions for the development of each resource. The state’s target is 

then set based on whichever figure is lower—the national benchmark for a given resource as 

applied to that state or the IPM-modeled market potential. 

iii. Shortcomings with EPA’s Block 3 Approaches

EPA’s current regional RPS-based approach for Building Block 3 falls short in several crucial 

regards. Most importantly, EPA’s approach simply will not catalyze the investment in, and 

development of, renewable technology to the extent that it must. According to the agency’s 

own estimates in its Regulatory Impact Analysis, the current proposal will increase generation 

from renewable sources by only 2 percent above BAU in 2030.242 This does not meet the best 

system of emission reduction standard, but rather represents the status quo without taking into 

account any of the technological and market dynamics that will likely drive further RE 

development over and above current BAU forecasts.

3. Regional RPS Averages

One problem with EPA’s approach is that it incorrectly assumes that averaging the RPS 

requirements of the states in a given region actually reflects the full level of RE investment that 

is reasonably achievable for that region. In fact, this is often far from the case. For example, the 

North Central region covers nine states—Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, 

North Dakota, South Dakota, and Wisconsin—and has an average RE percentage requirement 

for 2020 of 15 percent, which is driven by the RPS requirements in five of these states: Illinois, 

Michigan, Minnesota, Missouri, and Wisconsin. Yet three of the four states that do not have 

RPS requirements—Iowa, North Dakota, and South Dakota—are among the nation’s leading 

states in onshore wind development, generating approximately 25, 15, and 24 percent 

(respectively) of their total in-state electricity from wind in 2012. But because there are no RPS 

requirements in Iowa and the Dakotas, the RE target for the North Central region does not 

reflect the robust performance of wind-generated electricity in those states. While there is 

 

241 See 79 Fed. Reg. at 34,869-70 and Alternative RE TSD.

242 See RIA at Table 3-11.
80

some merit to EPA’s view that RPS policies represent the judgment of state legislatures about 

what level of renewable energy development is feasible, this does not hold true for states 

without RPS policies, since zero RE is not a reasonable judgment as to the state’s potential for 

economic RE.

As another example, the Southeast has the lowest average RE percentage 

requirement—only 10 percent—which is based on the RPS requirements of just one state: 

North Carolina. According to NREL’s technical potential analysis, states in the Southeast region 

could generate over 30 million GWh annually from utility-scale solar stations.243 Yet in 2012, 

these states generated just 348 GWh from solar plants, a tiny fraction of their technical 

potential and less than .04 percent of the total electricity generated in these states.244 There 

are neither technological nor economic barriers to increased penetration of renewable 

resources in the Southeast market; rather, the problem is one of political will and inertia based 

on decades of reliance on fossil fuels. By relying on just a single state’s RPS requirements to 

direct the renewable investment of nine states, EPA’s approach largely entrenches the status 

quo rather than considering whether greater renewable penetration is achievable.

In calculating the regional target based on state RPS programs, EPA had to decide how 

to handle the facts that different states have targets set for different years and that not all 

states have 2030 targets. However, the way that EPA chose to deal with this was arbitrarily

conservative. The agency derived a “2020 effective RE Level” for each state RPS, interpolating 

for those states without a specific target for 2020. It then established the average 2020 

effective RE level for each region as the 2030 target for that region.245 Thus, EPA effectively 

ignored the many state RPS goals for the years beyond 2020 that are more ambitious than the 

“effective 2020” targets. Even if one were to accept EPA’s rationale that the judgment of state’s 

legislature is a proper estimate of the full level of RE achievable in that state, there is no reason 

to take the states’ average judgment about what level is achievable in 2020 and make that a 

2030 target.

4. EPA Fails to Adequately Acknowledge State RE Potential

Another problem with EPA’s current model for Block 3 is that it does not apportion 

renewable investment among the states in each region in a way that assures the “best” system. 

On the one hand, states are not expected to meet their maximum RE amounts by 2030. Rather, 

states are only expected to achieve the regional growth factor for each year between 2017 and 

2030. To take one example,246 Illinois’s maximum RE amount for 2030 is about 29.9 million 

MWh; this figure represents 16 percent (i.e., the regional RE percentage in 2030 for the North 

 

243 EPA, Proposed Renewable Energy (RE) Approach data file, supra n. 240.

244 Id; see also EPA, Abatement Measures TSD, supra n. 239 (showing that these states generated a total 

of 986,000 GWh in 2012).

245 See Abatement Measures TSD at 4-11.

246 For the Illinois examples, we used data provided in the Proposed Renewable Energy (RE) Approach

data file for the Abatement Measures TSD; see n. 240, supra.
81

Central Region) of the state’s total 2012 generation. Yet Illinois is only expected to meet the 

North Central region’s annual growth factor of 6 percent, which would yield just 17.8 million 

MWh of renewable generation by 2030, a figure 40 percent lower than Illinois’s maximum RE 

amount.

On the other hand, states that meet their RE amounts before 2030 are not expected to 

produce additional renewable generation. For instance, North Dakota’s247 obligations to 

increase RE generation end in 2018, when it hits its maximum RE amount of 5.5 million MWh, 

whereas continued application of the 6 percent annual growth factor would double this figure

by 2029. This effect is particularly dramatic for states like Iowa, whose 2012 generation from RE 

exceed their maximum RE amounts. Hence, even though Iowa produced 14.2 million MWh of 

renewable electricity in 2012, its 2030 RE target is just 8.6 million MWh. EPA has requested 

comment on whether the 2012 RE baseline should be considered a floor for renewable energy 

generation as part of Building Block 3 to address the situation just described in Iowa. 79 Fed. 

Reg. at 34,868. EPA’s resolution of this issue depends on its final decision about how to credit 

renewable energy, which is discussed in further detail below. If EPA chooses to retain its 

preferred methodology of crediting each state with the renewable energy that it has 

“implemented,” then the baseline RE should be recalculated to reflect that compliance criteria.

On the other hand, if EPA credits a state with all of the renewable energy generation within its 

borders, then no state should be assumed to lose RE generation as part of its state target 

calculation.

Not only does EPA’s approach truncate a state’s RE growth before it reaches its 

maximum RE amount, it frequently cuts off a state’s RE growth far short of the state’s own RPS 

requirement. As Table 7 below indicates, for the substantial majority of states with enforceable 

RPS requirements (which are indicated in red), the Clean Power Plan sets targets that fall far 

short of those states’ RPS obligations. States whose CPP target percentages are at or above 

their maximum RPS level are indicated in green. EPA’s approach must, at a minimum, assume 

that states reach their own independently-set RPS targets.248 Failing to account for states’ 

existing RPS levels in establishing RE targets falls well short of meeting EPA’s BSER obligation by 

effectively assuming, without offering any justification, that binding state laws will be violated.

 

247 Id.

248 RPS programs sometimes allow for technologies to count as “renewable” that are not low-carbon, 

such as certain types of biomass, natural gas, or even “clean coal.” To the extent that these technologies 

are part of the RPS structure at the state level and would not qualify as a low- or zero-carbon resource 

under EPA’s proposal, there is justification for EPA’s goals falling short of state RPS targets.
82

Table 7- Comparison of State RPS Targets and EPA Final RE Generation Targets249

The case of Hawaii illustrates several problems with EPA’s approach. For both Alaska 

and Hawaii, EPA set 2030 regional targets based on the Southeast region, the lowest of the 

continental targets at 10 percent.

250 Thus, EPA’s 2030 RE target for Hawaii is just 10 percent, 

despite the fact that as of 2012, renewable energy already made up 9 percent of Hawaii’s retail 

sales.

251 EPA’s target for Hawaii is also only one quarter of the state’s own RPS target of 40

 

249 The data in this table derive from EPA’s Abatement Measures TSD, Tables 4-2 and 4-8. Furthermore, 

Minnesota enacted a 1.5 percent solar energy minimum threshold, which is additive to the state’s 

existing 30 percent RPS depicted in Table 4.2. See DSIRE, Minnesota, Incentives/Policies for Renewables 

& Efficiency, http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=MN14R (last visited 

Nov. 30, 2014). 

250 79 Fed. Reg. at 34,867.

251 See Abatement Measures TSD at Table 4-1.
83

percent by 2030. While EPA’s instinct not to subject Hawaii to unreasonable targets based on 

its geographic isolation is understandable, the agency’s approach to Hawaii completely ignores 

the state’s strong historical RE growth and legally binding RPS targets.

5. EPA’s Assumption that States Will Begin in 2017 with 2012 Levels of RE Generation 

Is Wrong.

In setting the state targets, EPA expects states to begin increasing their RE generation 

according to the regional growth factors starting in 2017, using each state’s 2012 baseline as its 

2017 generation level of RE. EPA states that this approach “assumes neither improvement nor 

decline in performance”252 between 2012 and 2017, as though this assumption were perfectly 

neutral. In fact, this assumption is simply insupportable. As the agency accurately notes 

elsewhere, renewable energy generation is growing very quickly; in 2012 alone, installed wind 

capacity increased by nearly 28 percent and installed solar PV grew by over 83 percent.

253 There 

is no basis to assume that renewable energy generation will not grow tremendously between 

now and 2017. Setting the 2017 starting point five years behind RE growth under a BAU 

scenario is not consistent with EPA’s obligation to rely on the best system of emission 

reduction. If the agency chooses to keep the basic framework of this approach, it must assume 

growth of RE generation at a rate of no less than 1 percent per year between 2012 and 2017. 

This recommendation is based on the demonstrated growth data compiled by UCS, which we 

discuss in detail below.254

a. Comments on EPA’s Alternative Approach

EPA’s alternative approach would not produce markedly different results from its 

primary approach in terms of nationwide renewable penetration. Excluding existing 

hydropower, the alternative approach would result in approximately 12 percent generation 

from renewable resources by 2030, the same result as the primary proposal. However, the two 

approaches produce rather different results from one region to the next: the alternative would 

generally achieve higher RE growth in the eastern states than the primary approach, lower 

growth in the central states, and similar growth in the western states. 

Like its primary approach, EPA’s alternative model for Block 3 has several significant 

shortcomings. For instance, EPA’s IPM modeling assumes much higher prices for renewable 

generation going forward, and therefore underestimates the market potential for these 

technologies in the future. The Natural Resources Defense Council has developed alternative 

IPM runs using updated cost and capacity factor information for various renewable energy 

resources that show much higher levels of potential than EPA’s IPM runs NRDC constructed 

“Updated Cost and Performance” runs of the IPM model using current levelized cost figures for 

 

252 Id. at 4-17.

253 Id. at 4-7 (citing DOE 2012 Renewable Energy Data Book).

254 We also recommend below that EPA adjust the baseline RE levels and starting RE performance based 

on a state’s “sponsored RE.” See infra at 99-102.
84

wind and solar after finding that EPA’s cost figures were 46 percent higher than the current 

average cost.255 NRDC also increased the capacity factor of wind energy by 10 percent based on 

recent LBNL data, and reduced the capacity value of solar photovoltaic from 20 to 16

percent.

256 Finally, NRDC used lower and more current figures regarding the total cost of energy 

efficiency programs—ranging from 4.7 to 6.4 cents per kWh, and allowed the model to select as 

much energy efficiency as appropriate in the economically optimized generation mix.257 Based 

on these refinements, the IPM model produced a total of 469 TWh of renewable generation 

nationwide in 2030, compared to EPA’s 278 TWh.258 The model also selected 609 TWhs of 

energy efficiency in 2030, compared to 469 TWhs in EPA’s scenario. Moreover, the model 

generated savings over a business as usual scenario of $6.4-9.4 billion in 2030, compared to 

EPA’s estimated cost of $7.3 and 8.8 billion.259 While the level of increased RE generation is 

likely affected by the higher level of EE selected by IPM under NRDC’s scenarios, using updated 

cost and capacity factor assumptions still yielded a 60 percent increase in 2020 RE generation 

over EPA’s case, and a 44 percent increase for 2030.260

In addition to EPA’s IPM inputs not reflecting current information, EPA’s use of a 

technical potential benchmark to limit the IPM-derived economic potential is flawed. The IPM 

modeling is a sophisticated tool that dynamically accounts for cost and performance of 

different renewable technologies, and transmission and integration costs. By contrast, the 

technical potential benchmark rate is a somewhat crude metric that takes a single year of 

renewable energy development rates as a cap on future development, thereby ignoring widely 

forecasted improvements in the economics of renewable resources. It makes little sense to 

discard the superior IPM results based on lower estimates of potential from the technical 

potential benchmark, especially when EPA has relied on IPM results in many prior Clean Air Act 

rulemakings.

If EPA chooses to retain this feature of the Alternative RE model, it must update the 

NREL technical potential estimates that it uses, which do not reflect some of the recent 

developments in technology and engineering that will allow for greater renewable 

development. To provide one clear example, NREL’s wind potential estimates are based on 80-

foot wind maps, whereas new, taller turbine technology increases the potential in lower-wind 

 

255 Yeh, S., NRDC Issue Brief: The EPA’s Clean Power Plan Could Save Up to $9 Billion in 2030 (Nov. 2014), 

available at http://www.nrdc.org/air/pollution-standards/files/clean-power-plan-energy-savings-IB.pdf, 

at 1.

256 Id. at 2, Table 1.

257 Id. at 2. In contrast, EPA had represented energy efficiency in the model by reducing the load forecast 

by the amount of the state targets and had used costs of 8.5 to 9 cents per kWh.

258 Id. at 1, Table 4. Results reported are for state-level compliance; NRDC also evaluated a regional 

compliance scenario that yielded slightly lower levels of RE generation in 2030.

259 Id. at 2.

260 Id. at 4.
85

areas.261 The cost of solar energy has also declined significantly in the past several years, which 

is not reflected in the inputs EPA used.

Finally, because EPA’s alternative methodology sums the potential across renewable 

energy technologies, it is hampered by the lack of data for specific technologies. For example, 

because the market potential for distributed generation cannot be tested with the current IPM 

framework, which only accounts for centralized generation, EPA omits the rapidly growing 

rooftop solar sector from its analysis.262 The agency also omits offshore wind, despite its 

significant promise, because there are currently no operational offshore wind facilities from 

which to determine a baseline development rate.

In short, EPA’s primary and alternative approaches to renewable energy do not 

adequately stimulate the market for these technologies. To be sure, these approaches are 

adequately demonstrated and provide reasonable expectations of what states can achieve in 

terms of both technology and economics. Yet section 111 requires the best system of emission 

reduction, and as we describe below, much more can be achieved in terms of renewable 

growth without significant cost impacts, and EPA must strengthen Block 3 accordingly. 

b. The Demonstrated Growth Approach

i. An Overview of the Proposal

As noted above, we believe that the reformulation of Building Block 3 developed by the 

Union of Concerned Scientists is superior to either of EPA’s approaches.

263 This approach 

includes three key features. First, the demonstrated growth rate approach is consistent with 

EPA’s methodology for energy efficiency targets under Building Block 4 by setting benchmarks 

for incremental renewable energy growth in each state, ranging from 1.0 to 1.5 percent

annually in total electricity sales. These benchmarks are based on demonstrated RE growth 

from 2009 to 2013, and states are expected to begin meeting their annual growth targets in 

2017 (although the first year of compliance remains 2020). Second, the demonstrated growth 

approach assumes full compliance with enforceable RPS requirements in the states that have 

them, such that any state will be required to meet either its benchmark or the requirements in 

its RPS program, whichever is greater. Third, this proposal accounts for actual and expected RE 

development in the states between 2013 and 2017. Hence, the annual benchmark for a given 

state starting in 2017 applies the 1.0 to 1.5 percent incremental growth rate to the projected 

2017 RE generation in that state. By contrast, EPA’s approach relies on 2012 RE data as its 

starting point. Under the demonstrated growth model, RE generation is expected to reach 23

percent of total electricity sales nationwide by 2030 (not counting existing hydropower), 

 

261 See, e.g., Southern Alliance for Clean Energy, Low Wind Speed Case Study: Arkansas Wind Energy 

Resource (Oct. 2014), attached as Ex. 26.

262 Alternative RE TSD at 3.

263 See generally UCS, supra n. 183. All of our subsequent description of the demonstrated growth 

approach references this document.
86

compared to 10 percent under business as usual and 12 percent under EPA’s current 

formulation of Building Block 3.

To derive the annual growth targets for each state, UCS first examined EIA data from the 

most recent five years available (2009-2013) to determine the average growth rate of RE 

among the states. These data revealed that, on average, states increased their renewable share 

of electricity sales during this interval by 1.0 percent annually. The years between 2009 and 

2013 are appropriate as a benchmark period for several reasons. First, these years represent 

the most recent demonstrated performance of renewable penetration into the electricity 

market, and thus provide a reasonable set of expectations for continued development. It 

accounts for the recent rapid growth in wind and solar technologies, but by averaging over five 

years also eases fluctuations in development due to uncertainty around federal tax credit 

expirations and extensions. Furthermore, the 2009-2013 interval captures much of the historic 

development spurred by state RPS policies—a key driver of RE growth as EPA has identified.

This proposal expects states whose annual RE growth was less than 1.0 percent during 

the benchmark period to begin scaling up their renewable development in 2017 until they meet 

the 1.0 percent annual growth rate by 2020 and continuing meeting that target each year until 

2030. The fifteen states that met or exceeded the 1.0 percent growth in RE between 2009 and 

2013 are expected to maintain their 2009-2013 average growth rate each year between 2017 

and 2030 (or 2025, if EPA adopts a shorter compliance period), but in no case is a state 

expected to sustain a growth rate above 1.5 percent. For instance, Texas achieved a 1.1 percent

annual growth rate in RE during the benchmark period and is expected to maintain that same 

growth rate from 2017 to 2025/2030.264 North Dakota, on the other hand, which achieved an 

annual growth rate of 5.8 percent in 2009-2013, is expected to maintain RE growth at 1.5

percent annually from 2017 to 2025/2030. Furthermore, as indicated above, any state whose 

own RPS policies require greater RE development than application of our target growth rates is 

expected to meet the requirements of its RPS.

Finally, the baseline generation from which each state’s RE growth begins is its 

projected RE generation in 2017, which is determined by adding projected generation from 

wind and utility-scale solar projects that will be under construction by 2016 to the actual RE 

generation data from 2013. This is far more realistic than EPA’s counterfactual assumption of 

zero renewable energy generation growth between 2012 and 2017. 

 

264 UCS developed its state targets to sustain this growth through 2030, the end of EPA’s proposed 

compliance period. As discussed in Section XIII.A, we believe that EPA should adopt a shorter 

compliance period and reevaluate its BSER determination after eight years, consistent with its review 

schedule for 111(b) standards for new sources. 42 U.S.C. § 7411(b)(1)(B).
87

ii. The Demonstrated Growth Approach Achieves Much Greater Renewable 

Energy Development than EPA’s Proposals

The demonstrated growth model corrects flaws in EPA’s proposals for Building Block 3 

and enables the calculation of renewable energy targets that reflect BSER. As the figures on the 

following page illustrate, UCS estimates that a demonstrated growth approach would result in 

23 percent renewable generation nationwide by 2030 compared to 12 percent under either of 

EPA’s proposals, with improvements in every region of the country.

Fig. 22- Nationwide Renewable Percentages Under BAU, EPA’s Primary Approach, and 

the Demonstrated Growth Approach265

Fig. 23- Regional Comparison of Renewable Energy Targets in 2030266

 

265 UCS, supra n. 183, at 3.

266 Id. at 5.
88

It is worth emphasizing that the figures above assume that no state will be required to 

increase its RE generation above 40 percent of all in-state electricity sales.267 Under the 

demonstrated growth approach, only nine states will reach 40 percent, and only eleven will 

meet or exceed 35 percent renewable energy generation. With the exception of the single-state 

region of Hawaii, which will hit the 40 percent ceiling, overall RE generation in any of the 

regions designated under EPA’s plan will not approach 40 percent. 

Although the UCS approach includes this ceiling on RE growth, we believe that states 

with strong renewable resource profiles can meet and exceed 40 percent by 2030, and grid 

operators’ own evaluations show that they can already manage high levels of RE generation. A 

study for PJM completed in March 2014 indicates that “with adequate transmission expansion 

and additional regulating reserves, [it] will not have any significant issues operating with up to 

30% of its energy provided by wind and solar generation.”268 Additionally, an ongoing, multiphase NREL study has found that up to 35 percent renewable energy can be integrated into the 

Western Interconnection without the need for extensive infrastructure changes; instead, better 

forecasting, broader coordination, and improved operating practices will allow for 

integration.269 Indeed, Germany—the most populous, industrialized, and economically robust 

country in Europe—already produces 30 percent of its electricity from renewable resources and 

is on target to hit 40 percent by or before 2030, an extremely rapid increase over its 6.3 percent

rate in 2000. Should EPA adopt a demonstrated growth approach, the 40 percent ceiling 

proposed by UCS is not unreasonable, even while it may be unnecessary. Furthermore, if the 

agency selects a compliance period ending in 2025, as we advocate, the issue becomes moot, 

since no state would hit 40 percent by that year under our proposed approach in any event. 

In addition to doubling the amount of renewables expected by 2030, the demonstrated 

growth approach has several other advantages over EPA’s approach. First, unlike the EPA 

proposal, the demonstrated growth model accounts for distributed generation (“DG”). DG has 

shown exceptional growth in recent year: for instance, UCS reports that the number of rooftop 

solar installations grew by an average of more than 50 percent per year between 2008 and 

2013.270 The price of a typical household system dropped by almost 30 percent between 2010 

and 2013, even while the capacity of such systems across the United States more than tripled in 

that time.271 DG also represents one of the most significant areas for growth of renewable 

electricity in the coming years. According to a recent study published by Navigant Research, 

 

267 Our discussion of the UCS approach in this paragraph references data included in the spreadsheet 

entitled UCS RE Building Block State-Level Data, attached as Appendix 3.

268 GE Energy Consulting, PJM Renewable Integration Study: Executive Summary Report (Mar. 31, 2014),, 

at 6-7. 30 percent renewable was the highest level of renewable energy studied.

269 See, e.g., Lew & Brinkman, NREL, The Western Wind and Solar Integration Study Phase 2: Executive 

Summary, NREL/TP-5500-58798 (Sept. 2013), available at

http://www.nrel.gov/docs/fy13osti/58798.pdf. For more discussion on renewable integration, see

Section XI.A5.

270 Rogers & Wisland, UCS, Solar Power on the Rise: The Technologies and Policies Behind a Booming 

Energy Sector (Aug. 2014), attached as Ex. 27, at 1.

271 Id.
89

worldwide revenue from DG is expected to grow from $97 billion in 2014 to more than $182 

billion by 2023.272

Second, the demonstrated growth approach expects that states with RPS targets will at 

least meet those targets. EPA’s approach sets targets for many states that fall short of their 

legally enforceable RPS targets, even though it uses those RPS requirements as the basis for its 

regional targets. Third, and relatedly, while EPA’s plan effectively forces laggard states to begin 

making progress on RE development, it imposes few (and in some cases no) additional 

obligations on states with excellent and highly economic renewable energy resources that have 

already shown leadership in developing those resources. The UCS approach would require all

states to continue developing renewable resources at an historically appropriate rate. Finally, 

the demonstrated growth approach is based on what states have actually been achieving in 

recent years, whereas EPA’s model looks instead to what state legislatures and environmental 

agencies have decided is politically expedient. EPA’s formulation of the best system of emission 

reduction must be based on empirical evidence about what is possible within the electrical 

system at reasonable cost, and the UCS approach amply satisfies this standard.

iii. The Demonstrated Growth Approach is Adequately Demonstrated and 

Economically Reasonable

A demonstrated growth approach to renewable development is a proper element of 

BSER not only because it will achieve significant CO2 reductions at affected EGUs, but because it 

is both adequately demonstrated and economically reasonable as well. The very name of this 

proposal is testament to that fact: it is based on rates of RE growth that have actually been 

demonstrated nationwide in the last five years, and simply expects that states can and will 

continue to develop their renewable resource portfolios at the same rate going forward. 

Notably, 11 of the 15 leading states that have achieved growth rates at or above the national 

benchmark of 1.0 percent growth from 2009 to 2013 have achieved that same rate or higher 

over a 10-year period, from 2004 to 2013, indicating that the national benchmark rate already 

has been shown to be sustainable over relatively long periods. 

The growth during the 2009-2013 period reflects not only support from state renewable 

energy incentives, but also from the federal government through the production tax credit 

(“PTC”) and the investment tax credit (“ITC”). While the PTC has been an important policy for 

supporting wind energy development, there has been uncertainty each year regarding its 

renewal, which has tempered its impact on wind energy growth. Should the current PTC be 

eliminated, there will likely be a period of adjustment that will at least temporarily result in 

reduced installation rates. However, wind energy is an increasingly competitive product, as 

seen through the recent levelized cost data cited above, and the wind industry will likely adopt

financial mechanisms (such as yield cos and master limited partnerships) to replace its historical 

 

272 Press Release, Navigant, Revenue from Distributed Generation is On Pace to Surpass $182 Billion by 

2023 (Sept. 4, 2014), available at http://www.navigantresearch.com/newsroom/revenue-fromdistributed-generation-is-on-pace-to-surpass-182-billion-by-2023.
90

reliance on tax equity financing. We strongly support a certain and robust PTC at current levels 

in order to facilitate maximum clean energy development. But even in the event of a reduced 

or discontinued tax credit, we believe wind energy will be a pivotal tool to meet the standards 

laid out in the CPP. Moreover, solar energy is growing at a very fast rate and will be close to grid 

parity soon (supra); thus, solar energy technologies can be expected to fill in if wind 

development slows. Indeed, in a recent analysis by the Electric Reliability Council of Texas 

(“ERCOT”), the independent system operator found that solar would dominate the renewable 

energy added to the system in a Clean Power Plan compliance scenario, with 12.5 GW of solar 

added by 2029.273 Indeed, even under a baseline scenario without the Clean Power Plan, ERCOT 

anticipated that twice as much solar would be installed as new natural gas plants.274 While 

Texas has relatively high solar insolation, it has lagged in development of its solar energy 

resources compared to other states with less solar insolation that have already seen high levels 

of solar growth thanks to robust incentive programs, such as Massachusetts, New Jersey, and 

New York.275 Considering that EPA’s renewable energy targets for states are well below their 

technical potential for solar energy development, solar energy will be a valuable complement 

to wind energy in helping all states reach their targets. 

Taking all of these factors together, combined with the tremendous incentive that the 

Clean Power Plan itself will create, it is wholly reasonable to expect the leading states to 

continue developing renewable resources at a rate that comports with their recent 

performance, and to ask non-leading states simply to begin meeting the national average of RE 

growth over the last five years.

In spite of the fact that NREL’s state-by-state technical potentials for different 

renewable technologies are outdated at this point and underestimate the general potential 

from various sources (such as taller wind turbines), these figures nevertheless represent 

reasonable estimates of the maximum renewable generation that can be achieved in each 

state. If each state were required to meet the demonstrated growth targets described above, it 

would realize no more than a tiny fraction of its overall NREL-designated technical potential. 

UCS has conducted a regional analysis and has determined that the West, North Central, and 

South Central regions would all achieve just 0.2 percent of their technical potentials for RE 

development via the demonstrated growth approach, and the Southeast, East Central, and 

 

273 ERCOT, Analysis of the Impacts of the Clean Power Plan (Nov. 17, 2014), at Table 3 (Capacity 

Additions by 2029).

274 While ERCOT used EIA AEO 2014 forecasts of the capital costs for most generation technologies, it 

found that solar capital costs were declining much more rapidly than indicated by EIA based on 

information from Lazard, a confidential report by Greentech Media and Solar Energy Industries 

Association, and another confidential report by Citi Research. See ERCOT, supra n. 273, at 4, nn.3-5. 

ERCOT estimates that solar capital costs will decline from just under $2500 per kW in 2014 to under 

$1500 in 2029—a 40 percent decline.

275 See SEIA, State Rankings by Q2 2014 PV Installations, http://www.seia.org/research-resources/solarindustry-data (last visited Nov. 26, 2014).
91

Northeast regions would hit 0.5, 1.6, and 2.2 percent, respectively.276 A regulatory program that 

expects only such a small percentage of the RE development that is technically achievable 

according to the federal government’s best estimates is easily feasible and adequately 

demonstrated under section 111 of the Clean Air Act.

As far as costs go, UCS conservatively estimates that the demonstrated growth 

approach would have only a marginal increase in electricity prices above EPA’s proposal. Using 

NREL’s Renewable Energy Deployment System (“ReEDS”) model, UCS found that its proposal 

would achieve a nationwide average of 23 percent of electricity sales from RE while increasing 

average retail electricity prices nationwide by no more than 0.3 percent annually through 2030 

(with some regional variation).277 Decreased reliance on natural gas under an aggressive RE 

scenario would in turn yield savings both in the electricity and gas sectors. Given that 

consumers will feel little to no noticeable effect in the cost of electricity under the UCS 

approach, there is every reason to believe that utilities in both regulated and restructured 

states will easily absorb the regulatory costs of this proposal. In regulated states, utilities will 

continue to receive guaranteed returns on prudent capital expenditures, while utilities in 

market-based systems will pass on minor costs to consumers without significant reductions in 

demand. Section 111 merely requires that a BSER not impose “exorbitant” costs that would 

cripple the regulated industry, and the additive costs of UCS’s demonstrated growth approach 

are far from exorbitant, whether considered by themselves or in conjunction with the overall 

regulatory design of the Clean Power Plan. 

One reason for the modest costs of the demonstrated growth approach is scaling 

effects. That is, the more widespread a particular technology or method of generation 

becomes, the less costly it is to produce, install, and operate. This can result from traditional 

economies of scale, reductions in administrative burdens and other “soft costs” due to 

increased public support for the technology, and “next-of-a-kind vs. first-of-a-kind”-type 

benefits. DOE’s SunShot initiative aims for a 75 percent reduction in the cost of solar generation 

by 2020 by funding innovative technology development and reducing soft costs.278 As of 2014, 

DOE is already 60 percent of the way toward achieving this goal.279 Several studies have shown 

that rooftop solar installations in Germany, which has been a leading proponent of DG, are 

considerably cheaper than they are in the United States, due in large part to more efficient 

installation practices, reduced administrative costs, and other practical strategies.280 The figure 

 

276 UCS, UCS Approach for Strengthening the Renewable Targets in EPA’s Clean Power Plan (Oct. 2014), 

attached as Ex. 28, at 14.

277 UCS, supra n. 276, at 5.

278 See DOE, SunShot Initiative Mission Statement, http://energy.gov/eere/sunshot/mission (last visited 

Nov. 16, 2014).

279 Id.

280 See, e.g., Rocky Mountain Institute/Georgia Tech Research Institute, Reducing Solar PV Soft Costs: A 

Focus on Installation Labor (Dec. 2013), attached as Ex. 29; Solar Freedom Now, A Roadmap for 

Reducing Rooftop Solar Costs by 50%: Less Paperwork = More Solar (March 2013), available at 

http://www.climateactionprogramme.org/images/uploads/documents/Reducing_Rooftop_Solar_Costs.

pdf.
92

below, reproduced from a report authored by the Rocky Mountain Institute and the Georgia

Tech Research Institute, compares the cost of installing rooftop solar arrays in Germany versus 

the United States, and illustrates the cost savings that can be achieved through more efficient 

installation techniques.

Fig. 24- Cost Comparison for Rooftop Solar Installations- U.S. vs. Germany281

An additional feature of renewable energy is that the system integration costs decrease 

as these resources become more dispersed due to system-wide reductions in the variability of 

generation. While an individual renewable source has variability of generation, a larger pool of 

such resources distributed across a broad geographic area (such as a metropolitan region) have 

less variability and require lower backup or ancillary services costs. The following chart, 

adapted from an NREL study, depicts the relationship between backup costs and the dispersion 

of utility-scale solar plants:

Fig. 25- Backup Costs and the Dispersion of Solar Facilities282

 

281 Rocky Mountain Inst. and Georgia Tech. Research Inst., supra n. 280, at 5.

282 Farrell, Democratizing the Electricity System: A Vision for the 21st Century Grid (June 2011), attached 

as Ex. 30, at 21. 
93

This issue is discussed further in the reliability section of our comments; see infra, 

Section XI.

As these studies indicate, the demonstrated growth approach is likely to incur fewer 

backup costs than current predictions suggest as a result of scaling effects and reduced backup 

costs from greater dispersion of renewables. Additionally, the experience in Germany makes 

clear that ample opportunities exist to reduce renewable costs by adhering to more efficient 

protocols and reducing administrative hurdles. Because the demonstrated growth is both 

economically reasonable and adequately demonstrated, it is an appropriate component of 

BSER for the Clean Power Plan.

Thus, a demonstrated growth approach will achieve significantly greater development 

of renewable energy at little added cost by either 2025 or 2030, depending on the length of the 

compliance period. We strongly urge EPA to adopt this approach or one similar in order to 

maximize the role that clean energy will play in reducing CO2 emissions from our electricity 

sector. However, if EPA nevertheless decides to retain the basic approach it laid out in its rule 

proposal, EPA should make the changes discussed above to comply with the BSER mandate in 

the Clean Air Act.

6. Comments on EPA’s Specific Issues for Building Block 3

In addition to these recommendations, we address two issues for which EPA requested 

comment in its preamble. First, EPA asks what role hydropower should play in Building Block 3. 

See 79 Fed. Reg. at 34,869. We agree with EPA’s decision not to include existing hydropower in 

Building Block 3, since opportunities for increased generation from this resource are very 

limited in comparison to other renewable technologies. However, the agency asks whether new 

hydropower electricity (either newly constructed projects or increased generation from existing 

projects) should count toward compliance. Id. We believe that there are promising 

opportunities to increase electricity generation at existing facilities, unpowered dams, and runof-river projects.283 These types of technologies already qualify under many state RPSs that do 

not allow existing hydropower to count towards compliance.284

Second, EPA asks whether “the difference between a state’s RE generation target and its 

2012 level of corresponding RE generation does not exceed the state’s reported 2012 fossil 

 

283 See generally DOE, An Assessment of Energy Potential at Non-Powered Dams in the United States

(Apr. 2012), available at http://www1.eere.energy.gov/water/pdfs/npd_report.pdf.

284 See DOE, DSIRE, Washington Renewable Energy Standard, www.dsireusa.org (last visited Nov. 30, 

2014) (allowing post-1999 incremental hydropower that does not involve new diversions or 

impoundments to count towards compliance); Oregon Dep’t of Energy, Oregon’s Renewable Portfolio 

Standards: Hydropower in the Oregon RPS (July 2013), available at 

http://www.oregon.gov/energy/RENEW/docs/Hydroelectricity%20and%20the%20Oregon%20RPS%20Fa

ct%20Sheet.pdf,(detailing limitations on use of existing hydropower capacity).
94

fuel-fired generation.” Id. at 34,868-69. This issue only affects Washington, whose 2012 fossil 

generation (9.4 million MWh) is less than the amount of new generation from renewables the 

state would produce if it met its RE generation target under Block 3(15.9 million MWh). We see 

no reason to limit the amount of new RE expected of Washington based on its 2012 fossil 

generation. That strategy might make sense if EPA’s plan supposed that each and every new 

MWh from RE were to replace a MWh from an existing fossil unit, but that is not the case: at 

least some of that new RE generation will meet demand growth rather than displace existing 

fossil generation. Washington also imports some power from neighboring states, much of 

which is from fossil generating units.285 And even if that additional 15.9 million MWh of clean 

energy were to displace all fossil-fired generation and exceed the state’s demand growth, 

Washington could sell any additional clean electricity to nearby states, such as Montana and 

Wyoming, which lack strong renewable industries. Finally, it is worth noting that under EPA’s

current plan, Washington is not expected to actually meet its state RE target, but need only 

meet the regional growth factor. As such, Block 3 only expects Washington generate an 

additional 9.5 million MWh from RE, which is only marginally higher than its 2012 fossil 

generation of 9.4 million MWh. If the agency decides to retain its proposal for Block 3, we urge 

it to require all states to meet their RPS targets, as noted above, rather than simply the regional 

growth factors.

Finally, EPA has requested comment on whether it should adjust the way it has 

incorporated Building Blocks 3 and 4 into the BSER calculation. See 79 Fed. Reg. at 64,547-48. In 

incorporating Building Block 2, EPA reduced the dispatch (and emissions from) all steam EGUs 

based on the amount of increased generation by natural gas combined cycle units. EPA reduced 

the dispatch of coal and oil & gas steam units proportionately. However, EPA did not reduce the 

dispatch of any fossil unit based on increased generation by renewable energy resources, or 

decreased load resulting from increased demand-side energy efficiency. Instead, EPA simply 

added the megawatt-hours of RE and EE savings to the denominator of the emission rate. The

result is target emission rates that do not reflect reality in any way, and are higher than they 

would be if reduced dispatch was incorporated.

We support EPA’s proposed revision to the goal computation methodology. In reality, 

fossil EGUs will dispatch less when load is reduced, and when low-cost, must-take renewable 

energy generation is available. The combination of adding RE and EE to the denominator of the 

rate and reducing emissions from fossil units results in a lower rate overall. How much the rate

declines is highly sensitive to what assumptions EPA makes about which fossil units are 

displaced. If EPA’s emission rate targets do not include this effect, then they will be artificially 

high (less stringent). Thus, a state could actually do less in all building block categories than EPA 

anticipates, and still reach its target. This possibility reveals that the emission rate does not 

properly reflect the best rate of emission reduction.

 

285 See Washington Dep’t of Commerce, Washington State Electric Utility Fuel Mix Disclosure Reports for 

Calendar Year 2012 (July 2013) at 13 (Avista utility purchase of 950,000 MWh from Montana’s Colstrip 

coal plant), 238 (Puget Sound Energy purchase of 3.7 million MWh from Colstrip).
95

EPA seeks comment on the assumptions it should make in displacing fossil generation in 

the emission rate. EPA proposes several options, including: proportional displacement of all 

fossil, displacement of highest-emitting units first, or displacement of coal-fired EGUs first. 

Consistent with our comments regarding EPA’s methodology for displacement of steam EGUs 

under Block 2, we believe that EPA should first remove from the formula the generation by the 

highest-emitting units, which are typically coal-fired. This environmental dispatch constraint 

will yield the lowest target and is therefore the best system of emission reduction.

We recognize that EPA’s proposed rule would allow states to take credit for renewable energy 

generation attributable to measures in the state’s plan even when it does not result in 

displacement of in-state EGUs. Likewise, we have advocated that EPA allow states to take credit 

for energy efficiency savings directly attributable to their EE programs, regardless of where the 

emission reductions actually occur. Once fossil displacement is factored into the state’s target, 

the state will have some incentive to design RE and EE measures in a way that causes 

displacement of in-state high-emitting units, so that the state also receives that emission 

reduction benefit. Designing RE and EE measures in a way that avoids the need for operation of 

baseload coal-fired plants will also reduce the difference between the environmental dispatch 

required to implement the rule, and economic dispatch practices.

7. Compliance and Enforcement Considerations Under Block 3

Above, we discussed how EPA’s inclusion of RE as a component of BSER is wellsupported by the tremendous growth of the renewable sector, states’ increasing enactment of 

renewable portfolio standards and similar policies, and the demonstrated emission reductions 

associated with RE generation. EPA has highlighted in the Preamble and State Plans TSD several 

unique compliance issues that arise with renewable energy, which we will address in this 

section. These issues are as follows: First, how can renewable energy generation be credited 

towards the state and compliance entity’s emission rate in a way that is quantifiable and 

verifiable? Second, how should EPA and the states address conflicts created by the interstate 

nature of renewable energy so as to ensure that emission reductions claimed by each state and 

compliance entity are non-duplicative? Finally, which of the resources typically thought to fall 

into the category of “renewable energy” are appropriate as compliance measures?

a. Crediting Renewable Energy and Energy Efficiency Towards the Emission Rate

Both renewable energy and energy efficiency reduce the need for operation of affected 

EGUs in order to meet the economy’s electricity requirements. EPA has requested comment on 

how these zero-carbon MWs and avoided MWhs should factor into a state or source’s emission 

rate. 79 Fed. Reg. at 34,919. This issue fits within the framework of how RE and EE meet the 

“quantifiable” requirement for an emission standard. We believe that it is important that the 

mechanism for factoring these resources into the state or source’s rate286 be straightforward 

 

286 Throughout this section, we refer to the emission rate of a “state or source.” As discussed above, we 

believe that enforceable responsibility to fully achieve the rate should fall on the owners and operators 

of affected sources. Therefore, it is most technically appropriate to understand which source takes 
96

and allow states and sources to readily forecast the compliance payoff of specific EE and RE 

policies. Any methodology that is highly resource-intensive or uncertain will discourage states 

from making RE and EE a significant part of their plans and will favor increased natural gas 

redispatch and new gas construction. We believe that the only time a state needs to specifically 

identify the fossil EGU displaced by renewable energy is to avoid double-counting across ratebased and mass-based states.

EPA proposes two options for crediting RE and EE: the avoided MWh approach and the 

avoided CO2 approach. Under the “avoided MWh” approach, whatever unit or state is taking 

credit for the renewable energy generation will add those MWhs to the denominator of its 

emission rate. Under the “avoided CO2” approach, the amount of avoided CO2 emissions 

attributable to the renewable energy is calculated based on one of a variety of methodologies 

that EPA has described, and that value is then subtracted from the numerator of the unit’s or 

state’s emission rate. For example, EPA has suggested that the avoided CO2 emissions could be 

based on the average or marginal emission rate of the power pool or region in which the 

renewable energy was generated, system dispatch modeling, or tools such as AVERT.287 Under 

the avoided CO2 approach, a MWh of RE or EE that displaces higher-emitting affected EGUs 

would contribute more to a state or compliance entity’s efforts to reach its targets.288

While both approaches have merit, we believe that the avoided MWh approach is 

preferable for several reasons. First, the avoided MWh approach is consistent with how EPA has 

calculated the targets for both Building Blocks 3 and 4. Maintaining a consistent methodology 

across target-setting, plan development, and compliance demonstration will provide states and 

sources with greater certainty about how to incorporate renewable energy and energy 

efficiency into their plans. Switching to a different methodology for compliance might mean 

that even if a state enacted an RPS at the level of the 2030 RE target identified by EPA, that RPS 

might not have the impact EPA has anticipated on the state’s emission rate. 

Second, the avoided MWh approach allows states to predict with much more certainty 

the impact of their renewable energy and energy efficiency measures on their plan 

performance demonstration. The avoided CO2 approach requires a calculation of the CO2

emissions avoided by each MWh generated from a renewable resource both prospectively 

(during plan development) and retrospectively (when assessing plan performance). EPA has 

proposed a range of methodologies for estimating avoided CO2, ranging from the relatively 

 

credit for renewable energy and will be able to adjust its rate accordingly. However, in the sense that 

states will be responsible for developing plans and implementing policies to foster renewable energy 

development, it is also accurate in certain contexts to speak of a state as taking credit and making 

adjustments to the state emission rate.

287 See EPA, State Plans Considerations TSD (“SPC TSD”), Docket ID No. EPA-HQ-OAR-2013-0602 (June 

2014), available at http://www2.epa.gov/sites/production/files/2014-06/documents/20140602tsdstate-plan-considerations.pdf, at 22-23.

288 The methodology for accounting for RE and EE, discussed in this section, is distinct from how direct 

emissions of carbon dioxide from affected sources will be measured.
97

simple power pool average to more complicated modeling of dispatch planning and capacity 

expansion.289 These methodologies are in use for various purposes and were discussed in EPA’s 

Roadmap for Incorporating EE/RE Policies and Programs into State and Tribal Implementation 

Plans.

290 EPA has also taken important steps in recent years to support the development of new 

tools, such as AVERT, to aid in converting avoided MWhs to avoided carbon emissions. 

The accuracy of these methodologies for identifying the displaced fossil fuel unit 

increases with their complexity and the resources required to execute them properly. However, 

no methodology is 100 percent accurate, especially on the longer time horizons involved in the 

Clean Power Plan, which will require states to forecast power system dynamics 14 years out. In 

2030, and in yearly July 1 filings from 2020 to 2030, states will be required to compare actual 

emission performance with the projections in their state plans. 79 Fed. Reg. at 34,907. The 

actual fossil EGUs displaced, and therefore the actual tons of CO2 avoided, may differ 

significantly due to unanticipated factors like new or retiring generation, generation or 

transmission outages, unexpected changes in load, or unusual weather. Id. at 34,907. In 

contrast, an avoided MWh approach allows a state to implement a policy designed to bring 

about a certain level of renewable energy generation and remain confident that if that policy 

works properly, the state will be on track to meet its goals.

The use of an avoided MWh approach will also be more transparent to the public and to 

EPA. If system dispatch and capacity planning models are used as part of plan development and 

performance evaluations, stakeholders seeking to review the plan or assess the state’s 

compliance will have to procure expensive licenses to work with these models. While accurate 

accounting of actual CO2 reductions attributable to specific EE/RE measures would be helpful, it 

is not necessary to satisfy the “quantifiable” requirement for emission standards under Section 

111(d). Quantification of MWhs alone, and treatment of those MWhs as zero-carbon 

generation that is part of the overall system, satisfies this condition.291 We believe that EPA 

should, where possible, streamline the methodology for states to incorporate renewable 

 

289 Id. at 24-32. EPA’s EE/RE Roadmap suggests that projections of the impacts of RE and EE policies 

extending more than five years require more sophisticated tools to understand how generation and the 

transmission system will change over time. See EPA, Roadmap for Incorporating Energy 

Efficiency/Renewable Energy Policies and Programs into State and Tribal Implementation Plans, 

Appendix I: Methods for Quantifying Energy Efficiency and Renewable Energy Emission Reductions, EPA456/D-12-001j (July 2012), at I-32. Thus, while EPA offers a number of simplified methodologies, it 

appears that the ten year compliance period, combined with a four year gap between state plan 

development and beginning of the compliance period, will require capacity expansion modeling, in 

addition to system dispatch. This increases greatly the expertise and resources need to develop the 

state plans, and the difficulties for stakeholders and EPA staff in reviewing the proprietary model inputs 

and outputs.

290 See EPA, EE/RE Roadmap Manual, http://epa.gov/airquality/eere/manual.html (last visited Nov. 17, 

2014).

291 Konschnik & Peskoe, Harvard Law School, Environmental Law Program- Policy Initiative, Efficiency

Rules: The Case for End-Use Energy Efficiency Programs in the Section 111(d) Rule for Existing Power 

Plants (Mar. 3, 2014), attached as Ex. 31, at 11-14.
98

energy into their plans. The one instance in which it is necessary to identify the unit displaced 

by renewable energy or energy efficiency is if that unit may be subject to a mass limitation, 

which could give rise to double-counting if not addressed. This situation is discussed further 

below.

If EPA were to require states to use dispatch modeling to forecast emission reductions, 

there could be another practical barrier to estimating avoided CO2 from renewable energy with 

substantial accuracy. Dispatch modeling requires information on the day and time the 

renewable energy was generated or the MWh was saved. However, existing REC tracking 

systems, which are likely to be a central part of compliance with the CPP, do not maintain 

information on the day and time that an RE megawatt hour was generated.292 Generation 

profiles from different types of renewable energy resources are available to assess the 

likelihood that a particular MWh was generated during a certain hour, which could allow for 

better estimates of the displaced unit. Likewise, most energy efficiency program administrators 

do not gather information on when a particular renewable energy measure is actually saving 

energy on the system, though estimates can be developed based on the type of energy 

efficiency measure.293 For example, more efficient air conditioners can produce savings 

primarily during the hottest hours of a summer day, whereas CFL or LED lightbulbs will produce 

more savings evenings and in the darker winter months. While we believe that these sorts of 

tools for estimating the timing of EE savings or RE production are well-demonstrated and 

reliable, they add further layers of complexity to the avoided CO2 approach.

In contrast, most state RE and EE targets are either already designed around MWh 

targets or are based on percentage of load, which can be readily converted to MWhs. In most 

states, the officials implementing these programs have limited experience or lack tools to 

convert those MWh savings to avoided CO2 emissions. While these challenges can be 

overcome, we believe there is benefit in maintaining a metric with which state regulators are 

familiar and for which implementation is less resource-intensive and more certain.

The avoided CO2 approach does, however, have some advantages. This approach is 

fundamentally more accurate in calculating how much CO2 is being reduced through RE and EE 

measures. In contrast, the avoided MWh approach simply credits the MWh of renewable 

energy with the average emission rate of the state’s affected EGUs (for assessing adequacy of 

the state’s plan), or the emission rate of whichever affected EGU happens to acquire the RE 

 

292 Most REC systems track only the month and year of generation, while the ERCOT system makes 

available only the quarter and year. See Appendix 4. States must also be careful to note the date of 

generation, not the date that the certificate was issued, which sometimes lags the time of generation. 

Id.

293 See Shenot, J,, Regulatory Assistance Project, Quantifying the Air Quality Impacts of Energy Efficiency 

Policies and Programs (Aug. 2013), available at 

http://www.raponline.org/document/download/id/6680%E2%80%8E; Shenot, J., Regulatory Assistance 

Project, Calculating Avoided Emissions Should be a Standard Part of EM&V and Potential Studies, ACEEE 

2014 Summer Study Paper (Aug. 2014), available at

https://www.aceee.org/files/proceedings/2014/data/papers/8-192.pdf, at 8-372 to 8-373.
99

credit (for compliance purposes). Under the avoided CO2 approach, not every MWh of RE or EE 

is equivalent—those that displace higher-emitting affected EGUs would be more valuable to 

states and compliance entities. Thus, there would be an incentive for states and compliance 

entities to design RE and EE measures that achieved the greatest reductions in carbon 

emissions.294 In the interest of curbing carbon at the lowest possible cost, applying the avoided 

CO2 method would help generate better information about which RE and EE measures are most 

effective at reducing carbon emissions.

In conclusion, while both the avoided MWh approach and the avoided CO2 approach 

could be part of a quantifiable and verifiable emission standard for RE and EE, we believe that 

the avoided MWh approach would be less expensive and complicated for state agencies to 

implement, and also for stakeholders and EPA to review. For these reason, we primarily 

endorse the avoided MWh approach while still acknowledging the benefits of the avoided CO2

approach.

b. The Interstate Nature of Renewable Energy and Energy Efficiency

With few exceptions, the electricity market is not constrained by state lines. However, 

renewable energy is distinct in that states have enacted policies that stimulate development of 

renewable energy in other states to serve the enacting state’s load. Because so many state RPSs

allow out-of-state renewable energy resources to count towards compliance, and because so 

much renewable energy in fact crosses state lines pursuant to these policies, EPA has properly 

recognized a particular need to address the interstate aspect of renewable energy.

There are two key aspects of the interstate renewable energy issue that EPA should 

address in the final rule and concurrent guidance. The first question is which state or source 

should be permitted to include the renewable energy generation in its adjusted emission rate 

(more informally, which state or source gets “credit”). The second question is how to avoid 

double-counting when renewable energy is generated in one state, but the actual energy or 

associated credit is transferred into another state.

i. Which State or Source Gets Credit for Renewable Energy Generation?

As EPA notes, renewable energy generation has strong interstate characteristics. RE may 

be generated in one state and sold to purchasers in a different state, all the while displacing an 

affected EGU in yet a third state. States that have implemented renewable portfolio standards 

in most circumstances impose no restrictions on the geographic location of the RE resources 

that their utilities use to meet those standards. Other state policies to promote renewable 

energy development, such as production tax incentives or property tax exemptions, apply by 

 

294 The negative view of this potential is that states and compliance entities could manipulate their 

chosen models to forecast higher avoided CO2 than would actually occur, which would lead to fewer 

carbon emission reductions overall.
100

design to resources built within state borders, regardless of where the electricity generated by 

those resources ultimately flows.

EPA has put forward two methods for determining which state receives credit for 

renewable energy generation. EPA’s primary proposal is that “a state could take into account all 

of the CO2 emission reductions from renewable energy measures implemented by the state, 

whether they occur in the state or in other states.” 79 Fed. Reg. at 34,922. According to EPA, 

“this proposed approach for RE acknowledges the existence of RECs that allow for interstate 

trading of RE attributes and the fact that a given state’s RPS requirements often allow for the 

use of qualifying RE located in another state to be used to comply with the state’s RPS.” Id.

EPA’s alternative proposal is that states can take credit only for emission reductions 

occurring within the state as a result of its renewable energy policies. See id. In other words, 

the renewable energy measures must cause displacement of in-state affected EGUs in order to 

be included in the state’s compliance showing. EPA’s proposal also recognizes that multi-state 

platforms obviate much of the need to allocate renewable energy to particular states. Id.

For the reasons discussed below, we support EPA’s primary proposal but believes that 

significant clarification is needed regarding the underlying principles to provide states with 

sufficient guidance about what renewable energy generation they will be able to count in their 

plans and compliance showings. 

8. States and Affected EGUs Should Get Credit for All Renewable Energy Generation 

Regardless of Where Units Are Displaced.

We believe that states should be able to take credit for emission reductions that occur 

out of state so long as reductions will not be double-counted by states reporting on achieved 

plan performance. In the next section, we offer suggestions as to what demonstration states 

should make with respect to double-counting. Here, we discuss why it is important for states to 

receive credit for emission reductions in other states that result from the implementing state’s 

policies. The primary reason to we advocate this approach is that it is consistent with existing 

practices and will promote efficient development of the nation’s renewable energy resources.

As EPA notes, most existing state renewable energy policies, specifically RPS programs, 

allow utilities to count renewable energy generation that occurs in other states. These policies 

are also generally not concerned with whether the renewable energy procured displaces instate resources. In adopting this stance, state legislatures have recognized that energy is an 

interstate commodity and that limiting RE procurement to in-state resources could prevent 

utilities from seeking the least-cost renewable energy options that may be available. Indeed, 

limiting utilities to in-state renewable resources could increase the cost of compliance with the 

rule, at least in the short run. Limiting states to in-state resources would also prevent any state 

from taking credit for generation by offshore wind facilities in federal waters, even if a utility 

purchases the generation and RECs from that wind resource. Such a limitation would also fail to 

make the optimal use of existing transmission system resources. RE projects should be located 

where the best renewable energy resources are, and where available transmission capacity 
101

facilitates moving the generation to load. Attempting to locate RE resources where they will 

cause reduced dispatch of a particular EGU is difficult and not likely to lead to the least-cost 

option.

As noted above, there are many factors that can affect where generation from fossil 

EGUs will be displaced by renewable energy generation: the displaced unit can vary from 

season-to-season and from hour-to-hour, depending on load characteristics, outages at other 

generators, and transmission system limitations. It would be highly resource intensive for states 

to forecast the extent to which a particular renewable energy project will actually reduce instate emissions.295 If a state could only take credit for RE generation that displaced in-state 

units, unanticipated new generation or retirements over the ten-year compliance period could 

change which fossil unit is displaced by RE generation, such that a wind farm for which a state 

could previously take credit is later no longer available to the state as a compliance measure. 

This uncertainty would make it less likely for a state to include significant RE measures as part 

of its plan in comparison to measures that would carry less uncertainty, such as increased gas 

dispatch of existing NGCCs. EPA’s proposed policy of allowing states to take credit for 

renewable energy regardless of where displacement occurs will minimize this uncertainty and 

promote the use of RE in state plans.

Finally, EPA’s proposal properly rewards states that implement strong RE policies, rather 

than states that happen to have high renewable energy potential or states with marginal units 

less likely to be dispatched under a high-renewable scenario. It is far easier for states to design 

policies that will incentivize a certain amount of RE generation than to anticipate exactly which 

EGUs are displaced by that renewable energy. Likewise, affected EGUs that are subject to 

enforcement under this rule may purchase renewable energy credits or otherwise promote the 

development of renewable energy; to also require that this RE displace emitting generation in a 

specific location is too high a hurdle and may hinder the efficient development of these 

resources.

We do note that there is a potential difference between the options for establishing RE 

potential for the purpose of goal setting and how EPA will determine compliance. In target 

setting, EPA set the baseline for each state based on the amount of renewable energy 

generation physically occurring in a state.

296 EPA then calculated a current RE performance level 

by dividing in-state RE generation by total in-state generation to yield a percentage.297 EPA’s 

methodology does not account for whether that renewable energy had been “implemented” by 

the state, or whether the RECs corresponding to that generation are held in-state. Thus, some 

states may have a higher or lower baseline of RE generation and RE performance level than 

they would be able to report for compliance purposes today.

 

295 The same is true for displacement caused by energy efficiency savings, which are discussed further 

below.

296 See Abatement Measures TSD at 5 (noting the 2012 net generation by state).

297 Id.
102

Our proposed solution is to apply the UCS recommended percentage targets using the 

amount of creditable RE in a state. Should EPA finalize its proposed approach that states can 

take credit for renewable energy that they have implemented, as we recommend, EPA may also 

want to consider modifying how the baseline RE generation and the starting RE performance 

level is determined for each state. As an alternative to setting the baseline based on current instate RE generation, EPA could require states, working with their utilities and affected EGUs, to 

undertake an accounting of what renewable energy generation they would be able to take 

credit for under EPA’s rule as of the date they submit their state plan. This would most often be 

in-state RE generation less RECs “owned” by out-of-state persons and plus any RECs generated 

out-of-state but owned by in-state persons. We refer to this as the state’s “sponsored 

renewable energy.” The “denominator” for determining the starting RE performance level and 

target level of performance would be the overall consumption of electricity in the state in the 

starting and compliance year(s).298 This is similar to and consistent with our proposal for Block 4 

set out below.

State targets would then increase from the sponsored RE baseline and RE performance 

level according to whichever methodology EPA settles on for Building Block 3. This approach 

would allow states that currently export a lot of renewable energy, such as North Dakota and 

Iowa, to establish a more accurate baseline. Likewise, it would ensure that states which import 

large amounts of renewable energy start at a higher RE baseline and are not allowed to 

backslide or remain stagnant during the early years of the plan performance period. While 

auditing the state’s current level of sponsored RE would be a significant undertaking, states will 

already need to do this in order to design a state plan that achieves their RE targets. 

By undertaking this process at the outset of plan development, EPA will have an 

opportunity to resolve at the outset questions about how states will allocate credit for projects 

with multiple sources of policy support. In designing their plans, states would have greater 

certainty about how different renewable energy policies will work within their plans. This 

undertaking will also serve as an opportunity for EPA to test the sufficiency of the existing REC 

trading systems for compiling this type of information, allowing any needed refinements to 

those systems to be made in time for the plan performance period.

a. EPA Must Clarify How Different Types of Renewable Energy Policies and 

Measures Can Receive Credit for Generation Across State Lines.

As noted above, EPA proposes that “a state could take into account all of the CO2

emission reductions from renewable energy measures implemented by the state, whether they 

 

298 EPA states in the Abatement Measures TSD at pp. 4-5 that “[c]onsistent with the design of a number 

RPS policies, RE “performance” is measured here as the share of total generation.” We note that many 

RPS policies are expressed as a percentage of a load-serving entities retail sales, as opposed to in-state 

generation. 
103

occur in the state or in other states.” 79 Fed. Reg. at 34,922.299 The agency further lists a 

number of different policies that states could implement to promote renewable energy and use 

for compliance purposes. These includes RPSs, direct incentive programs, production and 

property tax incentives, workforce training subsidies, and research and development funding, 

to name a few.300 Many utility-scale renewable energy projects make use of multiple state and 

national programs in order to successfully finance a project. EPA states that “production-based 

tax incentives have been among the most important incentives used by states and utilities to 

help achieve RPS requirements, as well as to spur additional production and use of renewable 

energy.”301

For example, the developer of a wind farm in state A could sign a power purchase 

agreement with a load-serving utility in state B, which the State B utility will use for compliance 

with state B’s RPS. However, the wind farm might also receive production tax credits from state 

A. Both state A and state B’s policies played some role in making the state A wind farm 

economically viable, or in “implementing” that wind farm, to use EPA’s terminology. Under the 

proposed rule, both states would have some claim to credit for the generation from this wind 

farm. 

EPA should provide guidance to states for assessing the relative contribution of different 

state policies to a particular renewable energy project.302 For example, the credit could be 

apportioned based on financial analysis of the contributions of each state’s policy to the 

viability of a renewable energy project; or, credit could go solely to the holder of the renewable 

energy credit associated with generation from that wind farm. While some states may work out 

these problems among themselves through multi-state accounting agreements, some form of 

guidance or default allocations would provide more certainty for states, utilities, and renewable 

energy developers. We encourage EPA to further develop and describe what it means for a 

state to have “implemented” a renewable energy measure in light of the interactive nature of 

state and federal policies promoting clean energy.

 

299 EPA defines “renewable energy measure” to mean both renewable energy requirements and 

incentives, and individual installed RE systems. SPC TSD at 60 n.85. This broad definition complicates the 

interpretation of what it means to “implement” a measure.

300 SPC TSD at 60-61.

301 Id. at 61.

302 EPA states at one point that if the “renewable energy generation resulting from production-based tax 

incentives [is] used for RPS compliance . . . then it should not be counted separately in a state plan from 

MWh generation used to comply with a state RPS.” Id. at 72. While we agree that the full MWh 

generation from a project should not be counted under the production-based tax incentive and under 

the RPS, it is not necessarily the case that the RPS has the better claim to the generation. This is 

especially important where the RPS is the policy of a different state than the tax incentive, as in the 

example above.
104

9. EPA Should Make Clear What Role RECs Will Play in State Plan Consideration and 

Compliance.

EPA’s proposed rule makes several references to renewable energy credits (“RECs”), but 

never comprehensively describes the function they may serve in compliance. RECs will likely 

play a key role in how states and utilities claim credit for renewable energy generation and how 

they will avoid double-counting.

RECs are currently traded on nine exchanges across the country.303 Each REC represents 

one MWh of generation and is tracked within the exchange by a unique serial number along 

with information such as the year of generation, the type of RE resource generating the REC, 

and the location where generation occurred. These exchanges represent to buyers that each 

REC is unique and therefore serve the purpose of verifying and auditing REC generators. RECs 

are sold both to utilities seeking to show compliance with a state RPS and also into the 

“voluntary” market, which comprises businesses and other private entities wishing to increase 

the sustainability of their operations or make green power claims. The voluntary market 

currently comprises a little less than half of the total market for RECs in the United States.

In general, ownership of RECs is negotiated as a private contractual matter between an

RE generator and the purchaser of the output. RECs can be sold either bundled with the 

underlying energy or unbundled. In the latter case, the renewable energy is on paper stripped 

of any zero-carbon or zero-pollutant characteristics and referred to as null energy. To avoid 

double-counting, it is essential that if one compliance entity claims ownership of a REC, the 

corresponding null energy not be used for another entity’s compliance demonstration. Bundled 

RECs reduce this risk, since the recipient of the electricity and the REC holder are the same 

entity. Many PPAs involve the sale of bundled RECs, meaning that the PPA price covers both the 

REC and the delivered energy.

However, some RE purchases and policies do not involve the transfer of RECs. For 

example, some renewable energy generators sell electricity into wholesale markets rather than 

to a particular generator through a PPA. This is true, for instance, of wind farms in the ERCOT 

regions of Texas. These farms do not sell bundled RECs, since there is no identified purchaser of 

their electricity. Instead, their RECs are sold on the exchanges as unbundled credits to 

purchasers who want RECs for either compliance or voluntary purposes.

Unbundled RECs are also generated from distributed generation when the utility to 

which the resource is interconnected has elected not to purchase the REC. For example, the 

Public Utilities Regulatory Policy Act (“PURPA”) requires utilities to purchase the output from 

small renewable energy generators, called qualifying facilities (“QFs”). However, the Federal 

Energy Regulatory Commission (“FERC”) has held that a sale of this nature does not necessarily 

 

303 See Quarrier & David Farnsworth, supra n. 230.
105

encompass any RECs; instead, whether the RECs transfer to the utility is left up to state law.304

Thus, RECs generated by a QF do not always transfer to the utility, even though the utility 

purchases the power.305 These RECs could then be sold on the REC exchanges, creating a 

possible double-counting situation if the interconnected utility seeks to take credit for this null 

power.

Likewise, many net metering customers are not required to transfer the RECs generated 

by their systems to the utility.306 Thus, while the state’s net metering policy or related 

incentives could be viewed as “implementing” some amount of rooftop solar development, the 

utility might not hold the RECs that have been generated, which may even have been

transferred to an out-of-state third party. However, utilities could quantify and verify the 

distributed generation on their system through a mechanism other than RECs, so long as no 

other state claimed 111(d) credit for a REC from a particular distributed generation source. 

Compliance issues with distributed generation are discussed further below.

Most federal or state legislation that provides financial incentives for the development 

of renewable energy is silent about the ownership of associated RECs.307 RE projects that 

receive state financial incentives often retain the associated RECs rather than transfer them (or 

a portion thereof) to the incentive program administrator.308 This is in part because the state’s 

objective is to allow renewable energy projects to maximize other revenue sources, such as REC 

sales, so that state subsidies can eventually be reduced. It is also because RECs have historically 

had little value to state incentive program administrators. States might have difficulty claiming 

credit under the Clean Power Plan for these kinds of RE policies if RECs become viewed as the 

sine qua non of entitlement to RE credit. States thus need guidance on whether they will able 

to claim credit for tax incentives and other financial assistance programs if they do not require 

RE generators to transfer their RECs as a condition of receiving financial assistance.

 

304 Morgantown Energy Assocs., “Notice of Intent Not to Act and Declaratory Order,” 139 FERC ¶ 61,066 

(Apr. 24, 2012).

305 For example, a recent order by the Utah Public Service Commission held that because the price paid 

to QFs represents only energy and capacity value, and not the renewable attributes, the QFs retains the 

RECs and may sell them on a registry. PacifiCorp Large Renewable QF Avoided Costs, Docket No. 12-035-

100, Order on Phase II Issues, Aug. 16, 2013.

306 Distributed generation should be eligible for compliance only if EPA’s target setting methodology 

includes distributed generation. UCS’s demonstrated growth approach does include distributed 

generation, and since we support that alternative, we offer comments on how DG can be accounted for 

in compliance.

307 A study done on behalf of LBNL in 2006 surveys REC ownership relating to various state renewable 

energy policies. Holt, et al., Ernest Orland Lawrence Berkeley Nat’l Lab., Who Owns Renewable Energy 

Certificates? An Exploration of Policy Options and Practice, LBNL-59965 (Apr. 2006), available at 

http://emp.lbl.gov/sites/all/files/REPORT%20lbnl%20-%2059965.pdf.

308 Id.
106

In the absence of a new nationwide tracking service for RE generation, the existing REC 

system will be heavily used by states and sources seeking to demonstrate compliance. This 

presents several issues, summarized below, which EPA should anticipate and offer guidance on:

 Must states offering tax incentives or other financial assistance obtain a portion of the 

RECs from projects they fund in order to claim any credit under the CPP?

 Over 50 percent of the RECs currently sold through exchanges are entered into the 

voluntary market. If this trend continues, this represents 50 percent of the current 

renewable energy generating capacity that may not be available for CPP compliance.

 If EPA requires states to adjust their emission rate based on avoided CO2 emissions, 

more precise information about the time and location of generation will be needed than 

is currently tracked in the REC systems. Most exchanges currently track only the month 

of generation. This is not detailed enough information to use in a dispatch model or 

AVERT to estimate avoided CO2 emissions, as EPA has suggested it might require.

 REC trading systems should track the date of commercial operation of a particular 

renewable energy resource to allow states and EPA to assess whether the RE generation 

comes from a resource eligible for compliance. Likewise, REC trading systems must 

provide sufficient detail about the type of renewable energy resource that generated 

the electricity in order to allow states and EPA to assess whether it is an eligible 

compliance resource. This will be necessary if EPA allows only some biomass or 

hydropower resources to be eligible, for example, or if states choose to limit the kinds 

of resources that qualify as renewable in their plans.

a. Double-Counting

EPA has asked whether its proposed approach to interstate allocation of renewable 

energy presents double-counting concerns, and what states must show to demonstrate that no 

other state has claimed credit for the same renewable energy generation. There are two 

aspects of the double-counting question. The first is whether the MWhs of renewable energy 

will be included in the adjusted emission rate for more than one source or state. The second is 

whether the fact that displacement of affected units occur in one state, while credit for that 

renewable energy is taken by another state, constitutes a form of double-counting.

10. How Can Multiple States Be Prevented From Taking Credit for the Same MWh of 

Renewable Energy?

We believe that existing REC trading systems are the most promising mechanism to 

avoid double-counting of renewable energy generation. These systems assign unique identifiers 

to each MWh of generation and have well-established protocols for verification.

Because the nature of REC tracking systems is to ensure that each MWh is claimed only 

once, RECs are a natural tool to be adapted for use in the Clean Power Plan to avoid double-
107

counting of renewable energy. For each compliance demonstration period, a state or 

compliance entity would have to submit a list of REC serial numbers that it holds for the 

compliance year in question, and verify that to its knowledge, no other state or compliance 

entity is claiming credit for that same REC. REC system operators should collaborate to make 

available a unified web-based tool available to stakeholders and EPA to verify the origin and 

trading history of a particular REC using the serial number.

If any state or compliance entity seeking credit for renewable energy generation must 

produce a REC, there is almost no risk of direct double-counting. Making RECs the sole currency 

for including RE generation in a state or utility’s compliance plan does, however, as discussed 

above, require changes to existing state policies to effect transfers of RECs or negotiation 

among states about REC ownership from RE projects that have benefitted from multiple states’ 

policies.

EPA should also assess what type of verification measures each of the REC tracking 

systems has in place. For example, EPA should gather and make available data on how the 

system operator verifies the claims of generators, how often meters must be tested, whether 

generators are subject to occasional inspection, and other means of ensuring the accuracy of 

the RECs generated and preventing fraud. EPA may also want to consider requiring REC system 

operators to undergo initial and periodic audits. None of these suggestions should be taken to 

indicate distrust of the validity of existing REC systems, but rather that EPA should exercise due 

diligence in understanding and, if necessary, strengthening the safeguards built into these 

systems which will factor heavily into CPP compliance.

If EPA determines that existing REC verification procedures are not adequate to ensure 

accuracy and avoid fraud, it should work with the RE generators and REC tracking system 

operators to bring those procedures up to standard. In the meantime, EPA must not allow RECs 

generated through such systems to count towards CPP compliance. This can be ensured by 

requiring the REC tracking system operator to add a field to the system indicating whether the 

REC meets EPA’s data quality standards.

11. Displacement of Fossil Fuel EGUs and Related Double-Counting Issues

Every MWh of renewable energy generation leads to one fewer MWh of generation by a 

higher cost generating unit, typically a fossil fuel plant.309 The unit displaced is the one with the 

highest marginal operating cost, setting aside transmission constraints and other operational 

constraints such as ramp rates. Due to the interstate nature of the electrical system, the 

generating unit displaced by RE will not always be in the same state that implemented the RE 

measure, or the same state where the RE is physically located.

 

309 This equivalence does not account for the small difference in line losses depending on the proximity 

of each resource to load.
108

When an affected EGU is displaced due to RE generation, this reduces the mass 

emissions from that unit, but does not reduce that unit’s emission rate. Unless the unit takes 

credit for the RE generation by adding it the denominator (or subtracting avoided CO2 from the 

numerator), the reduced dispatch alone does not help that unit meet its emission rate target. 

Therefore, there is no double-counting in a state with rate-based targets if the entity taking 

credit for RE generation does not also operate the displaced EGU.

At the state level, there are some modest effects on the overall emission rate due to this 

displacement, but they can be positive, negative, or neutral, depending on which unit is 

displaced. If a coal plant in one state is displaced by renewable energy that is credited to 

another state, the first state’s emission rate will go down slightly, all else being equal, since 

more efficient natural gas combined cycle combustion will then make up a larger percentage of 

the generation factored into the rate in comparison to coal.

310 If a natural gas combined cycle 

plant is displaced, the state’s emission rate could actually go up slightly if the aggregated 

emissions rate of the remaining resources is higher than that of the displaced gas plant. EPA’s 

current proposal, which we advise against, is to exclude peaking plants from the BSER rate. If 

EPA retains that approach, then the displacement of a simple cycle peaking turbine by 

renewable energy will have no effect on the state’s emission rate from displacement alone.

The possibility that an affected unit is displaced in a state different than the state that 

takes credit for the renewable energy generation may be seen to raise concerns about doublecounting. We understand that there may be both displaced generation and the creation of 

RECs, but we do not consider this to be double-counting. So long as all states involved in the 

scenario employ rate-based plans, there are no double-counting concerns. Similarly, if any state 

within the same ISO or RTO has adopted a mass-based system, there will be no double-counting 

of renewable energy so long as EPA adopts the annual true-up procedures we recommend for 

mass-based targets; see Section VI.A.2, infra.

12. Eligible Renewable Energy Compliance Resources

A wide variety of energy-producing technologies are sometimes characterized as 

“renewable” under various state laws. EPA must clarify that these technologies will qualify for 

Clean Power Plan compliance as a “renewable energy resources” only if they emit zero carbon 

dioxide. Because EPA’s methodology for crediting renewable energy involves either adding RE 

MWhs to the denominator of the emission rate or subtracting the emissions avoided at a 

displaced fossil EGU from the numerator, it would not be appropriate for EPA to allow states to 

credit in this way purportedly renewable resources that generate carbon emissions. Specifically, 

EPA should exclude from its definition of renewable resources technologies such as “clean” 

coal, waste coal, combustion of municipal solid waste and pulping process byproducts (black 

 

310 However, many states have emission targets that are below the emission rate of a typical NGCC unit. 

In these states, it will be of little assistance toward achieving the target if the state’s affected gas plants 

make up a larger fraction of the overall covered emissions after a coal unit is displaced by renewable 

generation.
109

liquor), and biomass-generated fuels.311 To implement this limitation, EPA should require REC 

tracking systems to add a field verifying whether a particular RE resources is eligible for CPP 

compliance. REC tracking systems already contain fields to track eligibility for particular state 

RPS requirements, so should have no difficulty adding such a field for the CPP once provided 

with a definition by EPA.

Below, we offer further comments regarding why biomass should be excluded as a 

renewable energy technology. We also discuss EPA’s treatment of hydroelectric resources and 

distributed generation technology.

a. Biomass

EPA has proposed that, although biomass fueling of EGUs is not included as part of 

BSER,312 it would be an eligible measure for reducing CO2 emissions from EGUs. EPA seeks 

comment on whether measures to increase the use of biomass-derived fuels at affected EGUs 

would be appropriate to include in a state plan to achieve CO2 emission reductions from 

affected EGUs. 79 Fed. Reg. at 34,923. We do not believe that biomass combustion should 

count as a low-carbon generating resource.

At the EGU, burning biomass generates more CO2 emissions than even coal combustion. 

A 2011 analysis by the Partnership for Policy Integrity found that wood combustion generates 

213 lbs CO2/MMBtu, compared to 205.3 lbs CO2/MMBtu for bituminous coal.313 Utility-scale 

biomass boilers are also only about 25 percent efficient, which is lower than either average coal 

or gas boilers.314 Likewise, co-firing of biomass with coal decreases a facility’s overall 

efficiency.315 Therefore, when considering only carbon emissions at the stack, biomass is far 

 

311 If EPA agrees that such technologies should be excluded as compliance measures, then it should also 

exclude those technologies from its target setting process.

312 While EPA does not separately focus on biomass as part of its BSER determination, most states 

identify biomass as an eligible renewable energy resource for the purpose of their renewable portfolio 

standards. However, despite this, only 0.16 percent of the electricity generated in the United States 

comes from biomass-fueled units. See EIA, Biomass for Electricity Generation, 

http://www.eia.gov/oiaf/analysispaper/biomass/ (last visited Nov. 19, 2014); EIA, Electric Power 

Monthly with Data for August 2014 (Oct. 2014), available at

http://www.eia.gov/electricity/monthly/pdf/epm.pdf.

313 Partnership for Policy Integrity (“PFPI”), Carbon Emissions from burning biomass for energy, 

http://www.pfpi.net/carbon-emissions (last visited Nov. 30, 2014). PFPI refers to EIA 1605 data for 

natural gas and coal, and emission information for wood biomass comes from ORNL’s Bioenergy 

Feedstock Development Programs.

314 Id. (citing data from EIA and air permit reviews). See also Georgia Pub. Serv. Comm’n, Georgia Power 

Plant Mitchell Unit 3 Biomass Conversion Cancellation: Decision Review Findings (June 5, 2014) (noting 

Georgia Power testimony that converting from coal to biomass firing would increase the facility heat 

rate).

315 See Elec. Power Research Inst., Biomass Cofiring Update 2002: Final Report, No. 1004319 (July 2003).
110

from a low-carbon energy source and should not be allowed as a zero- or low-emitting resource 

eligible as a Building Block 3 compliance measure.

The claims made in favor of biomass as a low-carbon energy resource depend on the 

life-cycle carbon balance of biomass combustion, namely that the growing of biomass materials 

sequesters carbon from the atmosphere, rendering it a carbon-neutral fuel. EPA is very familiar 

with the controversy over whether biomass-derived fuels can be considered carbon-neutral.316

A panel of the independent Scientific Advisory Board released an assessment in 2012 of EPA’s 

proposal for accounting for carbon emissions from biomass combustion within the greenhouse 

gas PSD permitting program,317 and EPA is currently revising its guidance for PSD permitting of 

biomass combustion.

However, it would be inconsistent with the overall framework of the Clean Power Plan 

for EPA to account for the life-cycle carbon emissions of biomass-derived fuels. The agency has 

not looked at the life-cycle carbon impacts of other fuels, but rather only at the stack emissions 

from coal- and gas-fired units. If EPA were to allow biomass to be treated as a low-carbon 

emission source, that would amount to a backdoor carbon offset scheme, which EPA has 

otherwise prohibited.318 Furthermore, if the agency were to grant biomass status as a lowcarbon resource based on life-cycle impacts, it would then also have to factor in the life-cycle 

carbon impacts of coal and gas production. 

Even if EPA were to look beyond stack emissions, the case for biomass as a low-carbon 

fuel is unclear and highly dependent on the sourcing and processing of the fuel.319 Biomassderived fuels have low energy value relative to fossil fuels, and transportation and processing of 

large quantities of the biomass can negate any carbon benefits the fuel might provide. In 

addition, even where commitments are made to sustainably source biomass, such as using only 

agricultural waste products, compliance with these commitments must be carefully monitored 

to ensure that non-sustainable fuel crop biomass is not used if the primary supply runs low. 

 

316 See Deferral for CO2 Emissions from Bioenergy and Other Biogenic Sources Under the Prevention of 

Significant Deterioration (PSD) and Title V Programs (“Deferral Rule”), 76 Fed. Reg. 43,490, 43,493 (July 

20, 2011); EPA, Office of Air and Radiation, Office of Atmospheric Programs, Climate Change Div., 

Accounting Framework for Biogenic CO2 Emissions from Stationary Sources (Nov. 2014).

317 EPA Science Advisory Board (“SAB”), SAB Review of EPA’s Accounting Framework for Biogenic CO2

Emissions from Stationary Sources, EPA-SAB-12-011 (September 28, 2012).

318 See PFPI, The Role of Biomass Energy in EPA’s Greenhouse Gas Rule (July 1, 2014), available at

http://pfpi.net/wp-content/uploads/2014/08/PFPI-GHG-rule-writeup-August-7.pdf, at 14 (citing 

Projecting EGU CO2 Emission Performance in State Plans TSD at 37: “For emission budget trading 

programs that regulate EGUs and include offsets, which we define here as emissions reductions from 

sources not regulated by the trading program, emissions reductions from offsets would not be counted 

when evaluating CO2 emission performance of affected EGUs, because those reductions would not come 

from those affected EGUs.”).

319 See id.; Manomet Center for Conservation Sciences, Biomass Sustainability 

and Carbon Policy Study (June 2010), conducted for the Massachusetts Dep’t of Energy Res., available at

http://www.mass.gov/eea/docs/doer/renewables/biomass/manomet-biomass-report-full-hirez.pdf.
111

Finally, the time scale over which biomass resources sequester carbon is far slower than the 

rate at which carbon is emitted during combustion, rendering biomass a poor strategy for 

reducing atmospheric carbon levels in the coming decades. For these reasons, we believe that 

the carbon benefits of biomass fuels are too unreliable for these fuels to be part of a state’s 

compliance strategy. 

However, if EPA determines otherwise, it must provide guidance about how to calculate 

the overall carbon emissions associated with biomass production and combustion, a task 

already underway at the agency. EPA cannot assume, as it has stated in the proposed rule, that 

“broadly speaking, burning biomass-derived fuels for energy recovery can yield climate benefits 

as compared to burning conventional fossil fuels.” 79 Fed. Reg. 34,924. Any estimate of carbon 

emission reduction will be highly dependent on the source of the biomass and the conditions of 

its combustion, and EPA must establish standards for monitoring these factors which states 

must follow if seeking to use biomass as part of the plan. EPA recently released its Revised 

Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, which will undergo 

further review by the SAB.320 If EPA intends to apply this framework to the Clean Power Plan, 

we believe there should be an opportunity to submit additional public comments on that issue.

b. Hydropower

We support the omission of existing hydropower resources from the 2012 renewable 

energy baseline due to the distortions that it would cause in the northwest region’s renewable 

energy baseline. Alternatively, as EPA suggests in its NODA, if annual growth factors were 

calculated based on state-level rather than regional-level data, the potential for large amounts 

of hydropower in Washington, Oregon, and Idaho would not affect the growth factors for other 

states within the western region. As neither Washington nor Oregon allow most existing 

hydropower to be counted towards compliance with the state’s RPS, it would be somewhat 

contradictory for EPA to include hydropower in those states’ renewable energy baselines. 

Finally, omitting hydropower from the baseline avoids creating further incentive for these 

states to retain unnecessary and ecologically disruptive dams.

As is the case in Washington and Oregon, it is common for RPSs throughout the country 

to exclude large existing or new hydropower. A 2013 report by the Clean Energy States Alliance 

surveyed hydropower provisions in state RPSs and noted that many disqualify older dams, 

those larger than 30 MW, or the technology used (impoundment versus run-of-river).321 These 

exclusions reflect both an awareness of the adverse impacts of large hydropower and a desire 

to stimulate the growth of new RE resources.

 

320 See EPA, Carbon Dioxide Emissions Associated with Bioenergy and Other Biogenic Sources, 

http://epa.gov/climatechange/downloads/Framework-for-Assessing-Biogenic-CO2-Emissions.pdf (last 

updated Nov. 21, 2014).

321 Stori, Val, Clean Energy States Alliance, Environmental Rules For Hydropower In State Renewable 

Portfolio Standards (Apr. 2013), available at http://www.cesa.org/assets/2013-

Files/RPS/Environmental-Rules-for-Hydropower-in-State-RPS-April-2013-final-v2.pdf.
112

We agree that future development of certain hydropower resources, including nonpowered dams not appropriate for removal and well-designed run-of river-resources, can 

provide low-cost baseload renewable energy, and should be available to states and compliance 

entities. We do not support all new hydropower development, especially large projects that 

disrupt hydrological systems, destroy habitat and jeopardize protected species. However, we 

do not believe that it is within the scope of this rule for EPA to impose limits on which 

hydropower resources should be available for compliance, other than excluding existing 

hydropower as it has proposed.

c. Distributed Generation

Distributed solar generation (“DG”) is a major area of renewable energy growth in the 

United States.322 EPA correctly recognizes that feed-in tariffs and net metering are policies that 

promote distributed generation, and could be used as compliance measures.

323 However, EPA 

must include this resource in its target-setting and provide further guidance on this issue 

especially with respect to customer-sited DG. First, EPA should clarify that load-serving utilities 

should not receive credit for all DG interconnected with its system, but rather must have in 

place a policy that incentivizes DG, such as rebates or a favorable tariff structure, to take credit 

for that DG. Second, EPA should offer guidance on how DG can meet the requirements of an 

emission standard by being quantifiable, verifiable, non-duplicative, and enforceable.

i. Policy Mechanisms to Support Distributed Generation

Distributed generation comes in two basic forms: generation at a customer’s home or 

business, and stand-alone systems. Customer-sited DG is intended primarily to meet the 

customer’s own load and exports to the local distribution system only when generation exceeds 

load. Many utilities compensate for this export through net metering, which credits all exports 

at the retail electric rate, nets those credits against the customer’s purchases from the grid, and 

then either bills the customer for any shortfall or rolls the surplus over to the following month’s 

bill. The simplicity and fairness of net metering has been a leading source of growth in 

distributed solar generation. Some utilities offer less favorable terms to DG customers by 

compensating for exports at less than the retail rate, or not rolling over excess from month to 

month. These sorts of arrangements should not be characterized as creating incentives for 

distributed generation. In these circumstances, the customer is installing a distributed 

generation system at their own cost, without support from the state or utility. 

Value-of-solar tariffs are a new compensation mechanism in which 100 percent of the 

distributed solar generation is metered (rather than only the export), and the rate paid for each 

kWh generated is based on the sum of avoided utility, environmental and social costs offered 

 

322 Distributed wind is also interconnected with the utility’s system, but not nearly at the scale of 

distributed solar.

323 SPC TSD at 69, 80.
113

by the solar generation. In a few instances, feed-in tariffs are used to compensate customersited generation, but feed-in tariffs are more common for stand-alone DG systems.

Stand-alone DG is generally compensated through either a feed-in tariff, or under 

PURPA’s mandate that distribution utilities purchase the generation from qualifying facilities.324

EPA’s State Plans Considerations TSD describes the compliance issues with feed-in tariffs 

thoroughly, but fails to recognize some of the complexities presented in the fast-growing area 

of customer-sited solar that is typically net metered.

We recommend that a utility should not receive credit simply for having distributed 

generation interconnected with its system—it is essential that the utility have offered some 

kind of incentive. Extensive experience in states has shown that distributed solar is most likely 

to be installed where net metering is available, and that special fees on net metering customers 

or failure to roll credits over from month to month stifle DG development. Offering customers a 

rebate of a percentage of the installation cost of their system, or performance-based incentives 

is also helpful to DG growth.325 Feed-in or value of solar tariffs that are less than the retail rate, 

or that fail to offer sufficient long-term price guarantees do not incentivize DG. Therefore, DG 

installed under these circumstances should not be credited to the utility. Another new model 

being proposed in some states, including Arizona, is for the utility to directly own and install 

distributed generation at its customers’ locations. Since the utility owns the system, it would 

clearly be able to use that system’s output for compliance purposes. Finally, the high upfront 

capital costs associated with distributed generation lend themselves to investment by third 

parties, including compliance entities. Especially for EGUs that are not part of a vertically 

integrated utility, we believe that offering rebates for a substantial portion of the installation 

cost of a rooftop solar system should be an approved compliance measure.

ii. Compliance Demonstration for Customer-Sited Distributed Generation

For distributed generation measures to qualify as an enforceable emission standard, the 

emission reductions must be quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. We offer the following comments regarding how distributed generation can meet 

these criteria.

 

324 PURPA is a federal policy implemented by the state utility commissions, which determine the fair rate 

for energy and capacity that should be paid to renewable qualifying facilities. EPA should clarify whether 

renewable energy purchased by a utility pursuant to PURPA qualifies as a compliance measure, since it is 

pursuant to a preexisting federal mandate.

325 See Bird et al., NREL, Distributed Solar Incentive Programs: Recent Experience and Best Practices for 

Design and Implementation, NREL/TP-6A20-56308 (Dec. 2012), available at 

http://www.nrel.gov/docs/fy13osti/56308.pdf.
114

A. Quantifiable and Verifiable

EPA defines quantifiable to mean “capable of reliable measurement, using technically 

sound methods, in a manner that can be replicated.” In the State Plans Considerations TSD, EPA 

notes that DG systems are not always metered for total generation, only exported energy.326

Unlike utility scale generation, or larger distributed generation systems installed based on 

PURPA or feed-in tariffs, distributed generation units do not typically have revenue-grade 

metering but rely on inverter readings of generation instead.327 In many cases it would be 

prohibitively expensive to retrofit installed DG systems with revenue-grade metering, or require 

those meters on all future installed systems, given their small size. We urge EPA to include in 

the final rule specific requirements for reliably quantifying and verifying distributed generation 

without a requirement for revenue-grade metering

Not all REC tracking systems permit distributed generation systems that lack revenuegrade metering to register as REC generators. If a DG system meets the requirements to 

register its RECs, and those requirements meet EPA’s standards for data quality, then we 

believe it is appropriate for the utility to use those RECs towards compliance (assuming the 

utility has acquired the RECs, see below). The suggestions that we make below regarding 

alternative measurement and verification for DG systems should be used only where revenue 

grade metering is absent or RECs cannot otherwise be registered.

Capacity-based estimates can provide a solid basis for quantifying DG system output. 

These estimates should take into account the size, orientation and vintage of the system, as 

newer systems are slightly more efficient. All customers wishing to install solar DG must sign an 

interconnection agreement with the utility that involves payment of a fee, inspection of the 

customer’s system, and an evaluation of the safety of interconnecting with the distribution grid. 

Data from these interconnection agreements could readily be used by the utility to quantify the 

installed capacity on its system, and the utility could gather any additional information needed 

regarding the orientation and shading of the system during the on-site inspection that occurs as 

part of interconnection. An increasing number of utilities are using tools such as Clean Power 

Research’s PowerClerk to manage their distributed generation applications.328 Solar Anywhere 

and similar solar irradiance data sets, combined with engineering information regarding size 

and orientation of panels provide very accurate forecasts of likely generation. These forecasts 

have been validated by metering of in-place systems, and are relied upon by private investors 

that fund rooftop solar through third-party leases to provide high-quality information about the 

 

326 SPC TSD at 80.

327 For DG supported by feed-in tariffs or standard contract QFs, the utility should already have revenuequality metering regarding generation, and be reporting power purchased through these vehicles to the 

PUC. EPA generally indicates that this level of record-keeping, as supervised by the PUC, will suffice.

328 See Clean Power Research, PowerClerk, http://www.cleanpower.com/products/powerclerk/ (last 

visited Nov. 16, 2014).
115

likely revenues from a system.329 Utilities regularly rely on capacity-based estimates of 

generation for load forecasting purposes.

If EPA allows the use of capacity-based estimates, it must require rigorous verification of 

those estimates with spot metering at a statistically-valid sampling of sites. EPA should also 

state whether the utility or other entity seeking credit for DG can validate capacity-based 

estimates using sophisticated software resources that report to owners and utility whether 

they are getting the expected generation from their systems or whether the system is 

experiencing a malfunction or needs maintenance. EPA should offer guidance on these and 

other methods for verifying capacity-based estimates of distributed generation, but must 

impose some kind of additional validation measures.

When the generation of a distributed system is considered, the utility or other entity 

claiming credit should account for the fact that DG avoids line losses due to its proximity to 

load. This should be factored in when determining the effective generation levels of these 

systems.

B. Non-Duplicative and Permanent

To ensure that DG is not being double-counted, EPA should address two issues in the 

final rule. First, some load-serving utilities treat distributed generation as a load-side resource—

that is, adjusting load forecasts to reflect anticipated growth in customer-sited generation.330 If 

the utility does so, then the full capacity-based generation of the DG should not also be 

counted by the utility for Building Block 3 purposes. 

Second, if the load-serving utility does not receive the RECs for exported generation, 

there is a risk of double-counting as these RECs could be registered by the rooftop system 

owner and sold elsewhere.331 Load-serving utilities do not always receive RECs from the 

customer-sited generation. In some states, RECs are transferred to the utility without any 

additional payment, whereas in other states, the utility receives the RECs only if it has offered 

an incentive to the customer at the time of solar installation. In other states (or for certain 

utilities within states), the customer retains the RECs.332 Thus, in states where RECs are not 

 

329 See Solar Anywhere, Data, https://www.solaranywhere.com/Public/SelectData.aspx (last visited Nov. 

19, 2014).

330 See Sterling et al., NREL, Treatment of Solar Generation in Electric Utility Resource Planning, NREL/TP6A20-60047 (Oct. 2013), available at http://www.nrel.gov/docs/fy14osti/60047.pdf. As part of this 

study, a survey of utility IRP practices showed that “most utilities today treat DG as a net load impact 

rather than as a [supply] resource. Id. at 25.

331 Not all customer-sited DG systems will be able to register with REC trading systems, depending on 

the eligibility requirements of the particular system.

332 IREC’s Freeing the Grid project produces an annual report, Best Practices in State Net Metering 

Policies and Interconnection Procedures, describing each state’s policy based on the best information 

available at that time. The most recent report was published in November 2014; see Auck, et al., 

Interstate Renewable Energy Council/Vote Solar, Freeing the Grid 2014: Best Practices in State Net 
116

currently transferred to the utility, the utility will need to amend its rules (or seek a change in 

state law) to take possession of those RECs. This will likely require paying some extra value for 

the RECs, which are currently a separate source of revenue for DG system owners.

Finally, in order for DG measures to meet the permanence requirements, utilities should 

be required to keep accurate records regarding installation dates of DG systems and their 

anticipated service life. EPA must require regular, comprehensive auditing of in-place systems

to ensure that damaged or disconnected systems are no longer counted towards the utility’s 

compliance.

In conclusion, we believe that distributed generation will be an important compliance 

tool for the Clean Power Plan due to its rapidly expanding adoption, assuming that EPA has 

included it in setting the targets. However, EPA must offer further guidance about the policy 

issues unique to distributed generation, including those topics highlighted above. Without 

detailed guidance and some assurance about what kinds of distributed generation policy tools 

will count for compliance, states may choose less environmentally beneficial tools rather than 

DG to achieve their target emission rates.

D. Building Block 4

1. Building Block 4 is Legally and Technically Justified as an Element of BSER.

Like renewable energy, energy efficiency is a cost-effective system of emission reduction

that is adequately demonstrated, as evidenced by the experience of states and utilities that 

have implemented these policies and programs for years. EE also imposes minimal 

environmental costs and reduces overall energy requirements. As such, it is an appropriate 

element of BSER.

a. Low Costs of Energy Efficiency

In its proposed rule, EPA concluded that the costs of demand-side energy efficiency 

measures reflected in its best practices scenario and the associated CO2 reductions are 

reasonable and will result in reductions in electricity bills by the end of the compliance period.

79 Fed. Reg. at 34,872-75. These estimates, however, are very conservative, particularly since 

energy efficiency is well recognized as a cost-effective (and in most cases the least-cost) 

method to reduce greenhouse gases.333 The costs associated with the best practices scenario 

were estimated based on the average energy efficiency program costs per unit of first-year 

energy savings, the ratio of program to participant costs, and the life times of the energy 

efficiency measures. These factors are reflected in EPA’s estimated levelized cost per MWh of 

saved energy (“LCOSE”) of $85/MWh to $90/MWh ($2011) over the compliance period. Id. at 

 

Metering Policies and Interconnection Procedures (Nov. 2014), available at

http://www.slideshare.net/VoteSolar/ftg-2014-finalreport.

333 Konschnik, supra n. 85 at 2. 
117

34,874. As the agency itself notes, this estimate is very conservative, and leads to higher costs 

when compared with most utility and state analyses. Id.

The American Council for an Energy Efficient Economy (“ACEEE”) reviewed utility sector 

energy efficiency program costs between 2009 and 2012 for seven states, and found that 

energy efficiency programs, together with participant costs, amount to an average cost of 

$0.054/kWh or $54/MWh ($2011).334 While these costs correspond to the average of the years 

2009-2012 vis-à-vis EPA’s levelized forecast for 2020-2030, EPA’s estimates are too high when 

compared to energy efficiency cost trends assessed by ACEEE in recent years. The average 

utility costs of saved energy in (“CSE”) in ACEEE’s recent reviews are the following:

Table 8- Average Utility Costs of Saved Energy, 2004-2014335

ACEEE’s Review CSE Range Median/Average Cost

M. Kushler, et. al. (2004)336 $0.023-$0.044/kWh $0.03/kWh

Friedrich et. al. (2009)337 $0.016-$0.033/kWh $0.025/kWh

Molina (2014)338 $0.015-$0.048/kWh $0.28/kWh

ACEEE’s most recent values are only slightly higher than the average CSE 2009 review 

value ($0.025/kWh), and slightly lower than the average CSE 2004 value ($0.030/kWh).

Likewise, in analyzing the benefits of energy efficiency as a compliance mechanism, ICF has 

estimated an incremental value of additional energy efficiency of $0.012/kWh in 2030 when 

compared to a scenario where 2012 energy efficiency savings and spending remain constant 

($2013).339 These trends and estimates do not support EPA’s high cost estimates of energy 

efficiency during the proposed compliance period.

EPA has also assumed a cost escalation factor representing the possibility of increased 

costs associated with higher incremental efficiency savings. 79 Fed. Reg. at 34,874. ACEEE’s 

latest review actually compares CSE values to relative electricity savings thresholds (i.e. savings 

as a percentage of applicable retail electricity sales), finding only a weak correlation between 

the two values, which “cast[s] doubt on the hypothesis that programs with higher electricity 

savings levels are associated with higher CSE values.”340 Some experts actually suggest that the 

 

334 Molina, Maggie, ACEEE, The Best Value for America’s Energy Dollar: A National Review of the Cost of 

Utility Energy Efficiency Programs, Report No. U1402 (March 2014), attached as Ex. 32, at 23. 

335 See generally id.

336 Kushler et. al., ACEEE, Five Years In: An Examination of the First Half-Decade of Public Benefits Energy 

Efficiency Policies, Report. No. U041 (Apr. 2004), attached as Ex. 33, at 30.

337 Friedrich et. al., ACEEE, Saving Energy Cost-Effectively: A National Review, ACEEE, Report No. U092 

(Sept. 2009), attached as Ex. 34, at 5-6.

338 Molina, supra n. 334, at 18-19.

339 Pickles et al., ICF International, EPA’s 111(d) Clean Power Plan Could Increase Energy Efficiency 

Impacts, Net Benefits, and Total Value (Oct. 28, 2014), attached as Ex. 35, at 5. 

340 Molina, supra n. 334 , at 29-30.
118

increasing penetration of information technology may result in energy efficiency resources 

becoming progressively cheaper.341

b. Environmental Impacts and Benefits of Energy Efficiency

Energy efficiency measures entail several “non-energy” benefits in addition to the 

anticipated energy savings, which “range from reduced maintenance costs and lower waste of 

both water and chemicals to increased product yield and greater product quality.”

342 These 

benefits are sufficiently large so that they can diminish the payback period of the energy 

efficiency measures.343 In addition, savings through energy efficiency “can mitigate health and 

environmental effects associated with the extraction, processing, and transportation of fossil 

fuels.”344 EE resources are therefore not only among the least-cost options for reducing CO2

emissions, they impose no independent non-air environmental impacts and actually reduce 

those impacts from other sources.

c. Energy Requirements of Energy Efficiency

The most widely recognized energy-related benefit of demand-side energy efficiency is 

energy savings from decreased electricity demand. By reducing demand, energy efficiency 

contributes to grid reliability, primarily in terms of supply adequacy. Energy efficiency measures 

implemented within a particular service area or region can reduce the base load, the amount of 

energy required to be supplied, and the peak power demand.345

Efficiency can also contribute to reliability at the level of local transmission and 

distribution (“T&D”) networks by decreasing the likelihood of failures at those points in the 

system. The benefits of using energy efficiency to defer investments in T&D associated to 

address load growth can be substantial. Deferrals of T&D investments can occur as a result of 

efficiency programs that were not undertaken primarily to defer T&D upgrades. For example, in 

the past Consolidated Edison (“Con Ed”) reduced its projected T&D capital expenditures after 

adjusting 10-year load forecasts for each of its distribution networks to reflect the expected 

impacts of system-wide efficiency programs.346 But, in some instances, energy efficiency 

programs have been geographically targeted for the specific purpose of deferring such 

investments. For example, between 2003 and 2010, Con Ed employed geographically targeted 

 

341 Laitner et al., ACEEE, The Long-Term Energy Efficiency Potential: What the Evidence Suggests, ACEEE 

Report No. E121 (Jan. 2012), attached as Ex. 36, at 11.

342 Id. at 10.

343 Id., at 10-11.

344 Konschnik, supra n. 85 at 7.

345 Raynolds & Cowart, Alliance to Save Energy/Regulatory Assistance Project, The Contribution of Energy 

Efficiency to the Reliability of the U.S. Electric System (May 26, 2004), attached as Ex. 37.

346 Neme & Sedano, Energy Futures Group/Regulatory Assistance Project, US Experience with Efficiency 

as a Transmission and Distribution System Resource (Feb. 2012), attached as Ex. 38, at i.
119

efficiency programs to defer upgrades in more than one third of its distribution networks, with 

the resulting savings providing more than $300 million in net benefits to ratepayers.347

d. Energy Efficiency is “Adequately Demonstrated.”

Demand side energy efficiency programs have a long record of achieving energy savings.

Customer-funded energy efficiency programs provided by electric utilities have existed since 

the 1970s, and utility sector energy efficiency has evolved to become a top priority utility 

system resource.”348 Several states have established policies that mandate energy efficiency as 

first resource in the loading order of electric utility resources, as well as requirements that 

states should capture “all cost-effective energy efficiency.”349 Twenty-six states have adopted 

energy efficiency resource standards (“EERS”) that establish specific energy savings targets for 

utilities or independent statewide program administrators, while several others have 

established short-term energy efficiency goals.350

Since the early 2000s, energy efficiency programs have grown at an accelerated rate. In 

2006, total spending was $1.6 billion; by 2010, total budgets for electric customer energy 

efficiency programs grew to $4.6 billion; and in 2013, total budgets for these programs reached 

$6.3 billion.351 These expenditures are yielding significant energy savings. In 2009, the national 

total annual savings from these programs were 13,147 TWh or almost 0.4 percent of total 

energy sales, with five states saving 1 percent or more during that year.352 Funding for 

customer energy efficiency programs is expected to continue rising, particularly in those states 

that have been minor players in this industry.353 A large portion of these projected increases in 

spending are expected to come from the Southeast, which historically has had relatively low 

levels of funding for energy efficiency.354

Energy efficiency is becoming increasingly important because of concerns with fuel price 

volatility, increased cost of construction of new power plants and doubts about the ability to 

finance and secure cost-recovery of these projects; shrinking reserve margins leading to 

reliability questions; and more stringent environmental regulations, including regulations to 

reduce carbon emissions to address climate change. Energy efficiency is now also being used as 

a competitive resource. For example, in New England, energy efficiency can compete in the 

 

347 Id. at ii-iii. 

348 York et al., ACEEE, Three Decades and Counting: A Historical Review and Current Assessment of 

Electric Utility Energy Efficiency Activity in the States, Report No. U123 (June 2012), attached as Ex. 39, 

at 26.

349 Id.

350 Gilleo et al., ACEEE, The 2014 State Energy Efficiency Scorecard, Report No. U1408 (Oct. 2014), webbased version available at http://www.aceee.org/state-policy/scorecard, at 21. For details on these 

programs in different states, see Bingaman, supra n. 220, at 11.

351 Gilleo, supra n. 350, at v.

352 York, supra n. 348, at 2.

353 Id. at 28.

354 Gilleo, supra n. 350, at 19. 
120

forward capacity market, and FERC is analyzing how to incorporate energy efficiency in 

wholesale markets. Energy efficiency is also being used specifically as a greenhouse gas 

reduction strategy. The Regional Greenhouse Gas Initiative (“RGGI”) includes explicit provisions 

for credits for energy efficiency that generate funding for energy efficiency savings.355 This track 

record provides valuable insights on the future potential of energy efficiency as a resource and 

as a carbon reduction option.

In its proposal, EPA estimates that, for the best practices scenario, states can achieve 

incremental energy savings of 1.5 percent of annual retail sales over a period of years starting 

in 2017 and, at the latest, by 2025. 79 Fed. Reg. at 34,872. As discussed below, while a 1.5 

percent rate is a reasonable estimate that is adequately demonstrated, EPA should consider 

whether states can achieve a higher rate through utility efficiency programs. In its most recent 

“Scorecard,” ACEEE found that six states achieved or exceeded this level of savings in 2013, as 

shown in Table 9 below:

Table 9- 2013 Net Incremental Electricity Savings by State356

State 2013 Incremental Net Savings 

(MWh)

% of Retail Sales

(2013)

Rhode Island 161,831 2.09%

Massachusetts 1,116,442 2.05%

Vermont 99,074 1.78%

Arizona 1,317,329 1.74%

Hawaii 159,056 1.67%

Michigan 1,284,863 1.51%

Of these states, EPA assumes that Rhode Island will achieve a 1.5 percent savings rate 

until 2021, and Hawaii will do so until 2025. Massachusetts, Vermont, Arizona, and Michigan 

are assumed to reach this rate in 2020.357 Additional states currently have annual savings 

targets for the period 2014-2020 that are equal or higher than EPA’s proposed estimate:

Table 10- State Scores for Energy Efficiency Resource Standards358

State Approx. Annual Savings 

Target (2014-2020)

Approx. % of Retail Sales 

Covered by EERS

Massachusetts 2.6% 86%

Arizona 2.4% 56%

Rhode Island 2.3% 99%

Vermont 2.0% 100%

Maryland 1.6% 100%

 

355 Id. at 26-27.

356 Id. at 33.

357 Abatement Measures TSD at Appendix 5-4.

358 Gilleo, supra n. 350, at 38-39.
121

Maine 1.6% 100%

Minnesota 1.5% 86%

Colorado 1.5% 57%

Of the additional states in this list, only for Maine and Minnesota does EPA assume that 

these states will reach the target during their EERS period (2017 and 2020, respectively), while 

for Maryland and Colorado EPA assumes that these states will not hit the 1.5 percent annual 

savings rate until 2021.359 Therefore, while we agree with EPA that a 1.5 percent incremental 

annual savings rate is achievable, we suggest that the agency consider whether states can 

achieve a higher target through utility efficiency programs.

Figure 1 illustrates the level of new energy supply that would have been needed in the 

absence of productivity gains due to energy efficiency (from 1970 through 2010).360 The chart 

shows that in 1970, Americans consumed an estimated 68 quadrillion BTUs (quads) for all uses 

of energy. Had the country continued to rely on 1970 market structure and technologies to 

maintain economic growth, in 2010 we would have consumed an estimated 210 quads of 

energy resources. In fact, the actual level of consumption estimated for 2010 was just short of 

98 quads.361 Part of these reductions in consumption is due to the implementation of energy 

efficiency measures, and the opportunities further demand reductions through efficiency 

remain abundant.

Fig. 26- U.S. Energy Demand, Energy Efficiency Gains, and Energy Supplies362

 

359 Id.

360 “Energy efficiency” here refers to both a change in market structures as we move away from energyintensive industries to services industries, as well as actual energy efficiency measures: more efficient 

lightning and consumer products, greater fuel economy in vehicles, and more efficient power plants and 

industrial processes. Id., at 3, fn. 4.

361 Id. at 3-4.

362 Id. at 5.
122

2. EPA’s Building Block 4 Reflects a Level of Energy Efficiency Savings that Can Be CostEffectively Achieved in All States

As described previously, EPA’s decision to include demand-side energy efficiency as part 

of the best system of emission reduction is legally sound and reflects the broad treatment of 

energy efficiency as an electric system resource on par with generation. EPA’s methodology for 

developing the energy efficiency targets as part of Building Block 4 is also generally sound, 

though several improvements should be made.

a. EPA’s Best Practice Level of Performance is Achievable and Sustainable in All 

States.

In brief, EPA looked at the demonstrated level of energy efficiency achieved by PUCsupervised EE programs across the states, identified the top-performing states, and determined 

the best practice level of performance. EPA then determined what it believed to be a 

reasonable rate of incremental growth in EE savings, and applied that rate of growth to each 

state’s beginning level of performance in 2017 until the state reaches the best practice level of 

performance.

EPA set the best practice level of performance at 1.5 percent--meaning that a state’s EE 

programs reduce its retail electric sales of electricity by 1.5 percent annually. This is the peak 

rate of annual load reduction that a state is expected to achieve, even if that state has EE 

program targets higher than 1.5 percent. EPA based this level on the observed performance of 

EE programs in three states--Arizona, Maine and Vermont—and the fact that nine additional 

states are expected to reach this level of savings by 2020.363

In determining what level of energy efficiency should be deemed the “best practice,” 

EPA should keep in mind that the current utility revenue structure in most states provides a 

significant disincentive to implementing strong energy efficiency programs. The primary way 

that a load-serving utility can elevate profits is to increase electricity sales above forecasts 

made during the utility’s last rate case.364 Thus, the utility has a deeply ingrained motivation not 

to reduce electricity sales, which is commonly referred to as the “throughput incentive.”

Although some states have instituted decoupling to some extent—a policy that breaks the link 

between electricity sales and utility revenue recovery—for the majority of utilities in the 

country, it is counter to the utility’s business logic to implement energy efficiency programs.

States have developed ways to overcome the utilities’ reticence, such as offering incentives for 

achievement of EE targets, or imposing penalties for failure to meet them. But in general, the 

picture of EE program achievement in recent years reflects this significant barrier, and should 

 

363 Abatement Measures TSD at 5-33, Tables 5-8 & 5-9.

364 See Regulatory Assistance Project, Revenue Regulation and Decoupling: A Guide to Theory and 

Application (June 2011), available at 

http://www.raponline.org/docs/RAP_RevenueRegulationandDecoupling_2011_04.pdf.
123

be viewed as a conservative estimate of what is achievable with a proper incentive structure for 

utilities.

A number of other factors inhibiting energy efficiency are reflected in the data EPA used 

to set the EE targets. EE achievement has also been hampered by the lack of long-term political 

support in many states. In some states, like Arkansas, targets are set for only three-year 

periods, leaving utilities unable to optimize their planning for longer-term programs. Other 

states impose cost caps that limit the amount a utility may spend on utility programs, even if 

limiting spending means the utility will not achieve its targets.365 Still others, such as Texas, 

have designed their programs to focus on peak demand reduction, rather than overall energy 

savings. While peak demand reduction programs are highly valuable to ratepayers and require 

sophisticated implementation and EM&V, they would not necessarily show up in the EIA-861 

data as significant load reductions.

The 1.5 percent best practice level of performance is sustainable. EPA appropriately 

notes the long history of strong EE progress in the Pacific Northwest.366 A recent review of 

energy efficiency potential in Rhode Island, found that annual energy efficiency targets as high 

as 2.5 percent remained feasible over the next ten-year period.367 There are many markets that 

most energy efficiency programs have not even begun to tap, including multi-family homes, 

rental property, and mobile homes. As utilities develop programs serving these markets, new 

opportunities for savings will arise.368

While we believe that 1.5 percent is attainable for all states, we believe that it is 

unlawful for EPA to cap a state’s performance at 1.5 percent if existing state law requires a 

higher target. For example, Arizona utilities are expected to achieve 2.5 percent savings 

annually beginning in 2016.369 Several Colorado utilities will achieve 1.66 percent savings by 

2019. Illinois utilities are required to achieve 2 percent savings in 2015 and thereafter. Maine 

has an approximate target of 1.6 percent for 2020.370 Massachusetts has a target of 2.6 percent

by 2015. Rhode Island mandated that its utilities achieve 2.5 percent savings by 2014. Just as it 

was contrary to the CAA for EPA to set state renewable energy targets below their established 

RPS targets, EPA cannot set state EE targets below established standards.371 In addition, when 

 

365 See Downs & Cui, ACEEE, Energy Efficiency Resource Standards: A New Progress Report on State 

Experience (Apr. 2014), Report No. U1403, at 9.

366 Abatement Measures TSD at 5-38.

367 Rhode Island Public Utilities Commission, Proposed Energy Efficiency Savings Targets for National 

Grid's energy efficiency procurement for the period 2015 - 2017 consistent with Least Cost Procurement, 

Docket No. 4443 (filed Sept. 26, 2013), available at 

http://www.ripuc.org/eventsactions/docket/4443page.html.

368 Downs & Cui, supra n. 365 at 23.

369 All targets listed in this paragraph are from Downs & Cui, supra, at Appendix A.

370 Maine’s EE program administrator—Efficiency Maine—is required to pursue all cost-effective energy 

efficiency, rather than a specific numeric target.

371 We recognize that the state targets cited above do not apply to 100 percent of electricity sales in 

state, and therefore may require some adjustment when applied as a floor.
124

EPA sets the 2017 start level of performance for each state, those levels cannot be below the 

mandates already established in that state. EPA sets the 2017 levels equal to the 2012 level of 

savings, which does not reflect the progress on EE expected in many states.

EPA’s alternative best practices level of performance—1 percent—is far below the costeffective EE potential. That this alternative target is excessively conservative is demonstrated 

by the number of states already achieving higher levels of performance and the number of 

states with plans to exceed that level of performance by 2020. In addition, a meta-analysis of 

45 studies of efficiency published in August 2014 (after publication of the proposed rule) found 

that “average annual maximum achievable savings range from 0.3 percent to 2.9 percent with a 

median of 1.3 percent.”372 Importantly, this study also found that assessments of potential 

savings did not vary by geography.373 When considering the value of energy efficiency potential 

studies for target setting, EPA should keep in mind that estimates of achievable EE are heavily 

dependent on energy prices and the utility’s avoided costs. In other words, the level of energy 

efficiency that is cost effective is higher in a world where states must reduce the carbon 

emissions from their utility sector, rather than one where carbon emissions are unconstrained, 

which is typically the world reflected by existing potential studies. 

b. State EE Targets Should Be Based on All Sales in the State, Including Imported 

Electricity.

In factoring emission reductions from energy efficiency measures into the state targets, 

EPA tracks whether a state is a net importer or net exporter of electricity. If the state is a net 

importer, EPA scales down the amount of avoided generation demand resulting from those EE 

measures in order to “reflect an expectation that a portion of the generation avoided by the 

demand-side energy efficiency would occur at EGUs in other states.” 79 Fed. Reg. at 34,896.374

For example, EPA’s 2030 emission target for Florida assumes the state can use energy efficiency 

measures to reduce demand by 9.98 percent from 2012 electricity purchases (multiplied by a 

transmission loss factor of 1.0751), which in Florida amounts to savings of approximately 23.7 

million MWh. In-state generation accounted for approximately 90 percent of Florida’s 2012 

electricity purchases, with the remaining 10 percent imported from other states. Accordingly, 

EPA reduces Florida’s expected energy savings of 23.7 million MWh figure by 10 percent, and 

adds the resulting total—approximately 21.3 million MWh—to the state’s denominator.

 

372 Neubauer, ACEEE, Cracking the TEAPOT: Technical, Economic, and Achievable Energy Efficiency 

Potential Studies, Report No. U1407 (Aug. 2014), Executive Summary attached as Ex. 40, at v.

373 Id.

374 EPA makes this adjustment to reflect that not all of the state’s EE savings will result in emission 

reductions at in-state units. However, regardless of whether a state is a net importer or a net exporter, 

its EE programs can affect dispatch of out-of-state EGUs, since reduced load will lead to reduced 

operation of whichever EGU on the system is marginal at the time the load reduction occurs.
125

On the other hand, EPA does not “scale up” generation avoided from EE measures in 

states that are net exporters of electricity. For instance, Alabama is a net exporting state: in 

2012, its in-state generation exceeded its in-state electricity purchases by approximately 50

percent, indicating that a third of the state’s generated electricity was exported to other states. 

EPA’s target assumes that Alabama can implement energy efficiency measures that save 9.5 

percent of 2012 generation figures by 2030. This amounts to a demand reduction of roughly 8.8 

million MWh, which is added to Alabama’s denominator. Notably, EPA does not increase this 

figure by 50 percent to account for the fact that Alabama exports a third of its generated 

electricity to other states, even while it decreases the energy savings figure achieved in net 

importing states as described above.

EPA’s asymmetrical approach to imports and exports means that large swatches of 

electricity that can be avoided by Building Block 4’s EE measures are effectively “stranded”: the 

state targets simply do not account for these reductions. In Alabama, this amounts to about 2.4 

million MWh that is removed from the state’s denominator; nationwide, the total is 

approximately 41 million MWh. EPA must remedy this situation and set appropriately stringent 

state targets that account for all the electricity generation that can be avoided by the EE 

opportunities the agency has identified in Building Block 4.

The simplest and fairest “fix” to this problem is to avoid scaling down the obligations of 

importing states, and to recalibrate those states’ targets to account for 100 percent of the 

demand reduction achieved through EE measures. It is important to remember that the EE 

targets specified in Building Block 4 merely specify what is achievable in each state—they 

include no assumptions about how the responsibility for implementing those measures should 

be distributed across the state’s utilities or affected EGUs. It is therefore both feasible and fair 

to assign responsibility to in-state generators for achieving the level of EE savings specified in 

Building Block 4.

375 The only other approach that would avoid stranded EE savings would be to 

require exporting utilities to implement efficiency measures in other states, which would raise 

both legal and logistical challenges.376

Our recommended approach would make EPA’s methodologies for renewable energy 

and energy efficiency consistent. EPA does not adjust the state’s renewable energy target to 

reflect that many of the emission reductions resulting from the state’s RE measures will be at 

out-of-state facilities, and should treat energy efficiency savings the same way. Just as many 

 

375 We recognize that in many states, EE programs are implemented by load-serving utilities that do not 

also own generation. Even in states with vertically integrated utilities, there are some independent 

power producers (also known as merchant plants) that are not affiliated with load-serving utilities. 

Where there is not common ownership between the party currently implementing the EE program and 

the affected EGU, the state will need to either administratively allocate or auction EE savings generated 

by those programs, or adopt a tradable credit mechanism to enable affected EGUs to acquire the credits 

needed to achieve their target emission rates.

376 EPA requests comment on the alternatives approaches of adjusting both importing and exporting 

states, and making adjustments to neither. 79 Fed. Reg. at 34,879. To be clear, we support the 

alternative of making no adjustment to the EE targets based on import/export status.
126

states allow out-of-state RE to be used for RPS compliance, states with energy efficiency 

programs do not distinguish among where the savings occur. The objective of EE programs is to

produce savings for customers by reducing the need to purchase electricity and reducing the 

load-serving utility’s capacity requirement and delaying upgrades to the transmission and 

distribution system. It does not matter where the electricity would have been purchased 

from—the ratepayers save in any case. Therefore, EPA should follow the same rationale with EE 

target setting as it did for RE, and accommodate existing state programs that are indifferent to 

where resources are acquired or emission reductions are realized.

EPA’s approach also relies too heavily on the net importation factor from a single year in 

setting state targets for 2030. The percentage of energy that a state imports or exports can 

change significantly from year to year, as units enter and exit the system and new transmission 

lines are built. As the state of Oregon has pointed out, hydroelectric production is highly 

variable,377 which could cause major swings in a state’s export-to-import ratio. Basing the 

state’s target on its export-to-import ratio for one year could lead to targets that are either too 

high or too low. The simplest solution is for EPA to include 100 percent of the EE potential in 

the target and to allow states to count 100 percent of those savings towards compliance.

In conjunction with this adjustment to the goal-setting methodology, we also 

recommend that EPA allow states to take credit for 100 percent of their EE savings, rather than 

discounting the savings for net importing states. Notably, our recommendation to remove the 

EE scale-down factor for net importing states will impose no additional burdens on any state 

that in fact meets the EE components of its state goal. For instance, in the case of Florida, while 

its target will be more stringent under our approach due to the additional 2.4 million MWh in 

its denominator, the state would count 100 percent of the MWh avoided due to EE when 

determining compliance with its designated target, rather than 90 percent. Because the scaledown factor would be removed both from the target-setting and compliance-determination 

calculations, Florida would have no more difficulty complying with a rule that does not include 

the scale-down factor than one that includes it.

In fact, if an importing state exceeds the level of EE implementation specified in Building 

Block 4, our accounting method would give that state an added benefit. If Florida were to avoid 

30 million MWh through EE measures, our proposed method would allow the state to add all 

30 million MWh to its compliance denominator, 6.3 million MWh more than the 23.7 million 

MWh that Building Block 4 would add to the state’s target denominator. Under EPA’s scaledown approach, Florida would add 27 million MWh to its compliance denominator (90 percent

of 30 million), while its target denominator would include 21.3 million MWh (90 percent of 23.7 

million), a difference of 5.7 million MWh. Hence, under our approach, Florida would gain more

additional credit in its compliance denominator by exceeding its EE targets than it would under 

EPA’s scale-down method.

 

377 Oregon Dep’t of Envtl. Quality, State of Oregon Comments on Clean Power Plan, Docket No. ID EPAHQ-OAR-2013-0602-20678 (Oct. 16, 2014), at 5.
127

The only states that will be required to meet an additional burden under our method 

are those states that fall short of EPA’s target EE goals. In the example above, if Florida were to 

avoid 20 million MWh through EE measures rather than EPA’s assumed 23.7 million MWh, our 

method will tabulate this as a 3.7 million MWh shortfall that the state must make up for 

through other emission reduction measures. Under EPA’s downscaling method, EPA will only 

add 21.3 million MWh to the target denominator and will credit Florida with 18 million MWh 

avoided—a difference of 3.3 million MWh. Hence, under our proposed system, this state will 

need to make up a 3.7 million rather than 3.3 million MWh shortfall.

By eliminating the problem of “stranded EE assets,” our method has the benefit of 

encouraging states to implement EE measures that exceed EPA’s targets and discouraging them 

from falling short of those targets. Since EE is, in the aggregate, the most economically efficient 

way of reducing carbon emissions, our proposal will improve the rule’s overall costeffectiveness. We emphasize that our method does not actually revise EPA’s assumptions about 

each state’s capacity to implement EE—rather, it simply ensures that those figures are correctly 

tabulated in each state’s goals and provides the proper incentives for states to meet those 

goals.

Using a tool developed by MJ Bradley & Associates,378 we evaluated the impact of our 

method on state targets. Twenty-four states had final targets made more stringent by this 

change, as follows:

 For 8 states, final target rates decrease by 1 percent or less (AK, FL, HI, KY, LA, 

MS, NV, RI)

 For 11 states, final target rates will decrease by between 1.1 and 5 percent (CO, 

GA, MA, MN, NJ, NY, NC, OH, SD, TN, WI)

 Only 5 states will see their final target rates decrease by more than 5 percent, 

specifically:

o Virginia: 6.9 percent

o Maryland: 9.6 percent

o Idaho: 23.9 percent

o Delaware: 7 percent

o California: 5.1 percent

Clearly, the impact of this adjustment is largest for the state of Idaho, which would need 

to achieve a final adjusted emission rate of 184 rather than 228. However, as noted above, 

Idaho would at the same time benefit from being allowed to count 100 percent of its energy 

efficiency savings towards its state goal.

 

378 M.J. Bradley & Associates Clean Power Plan Evaluation Tool (2014 version 2). The tool is available at 

www.mjbradley.com. 
128

c. EPA Should Readjust its Goal-Setting Formula to Reduce Dispatch of Fossil 

Units In Accord with Increased Energy Efficiency

As discussed above, EPA has requested comment on whether it should adjust its goalsetting formula such that expected fossil-fired generation decreases to the same extent that RE 

generation and EE savings increase. We reiterate here that we believe EPA should, indeed, 

make this change, which will ensure greater emission reductions and reflect the true nature of 

electricity dispatch. For more discussion of this topic, see pp. 94-95, supra.

3. Compliance Considerations for Building Block 4

We strongly support the use of energy efficiency programs as part of states’ efforts to 

achieve compliance with their targets. Energy efficiency is widely recognized as the least-cost 

electric system resource—rather than imposing new expenses for the state to come into 

compliance, customers will actually experience lower bills if the state’s plan includes a strong 

energy efficiency component.379

EPA has stated that to count towards compliance, each part of the emission standard, 

including energy efficiency, must be quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. For energy efficiency, these criteria can be interpreted generally as follows:

 Quantifiable and verifiable: Are sufficiently rigorous EM&V procedures in place to 

enable the reliable measurement of savings in megawatt-hours and to calculate avoided 

CO2 emissions if required by EPA?

 Non-duplicative: Is another state also using those same avoided megawatts hours or 

avoided emissions towards their compliance with the Clean Power Plan?

 Permanent: Are the savings from an installed measure ongoing during the year in which 

the state seeks to use them for compliance? 

 Enforceable: is there an entity with federally enforceable commitments to procuring 

energy efficiency savings?

EPA’s proposed rule, technical support documents, and existing guidance do an 

excellent job of describing how energy efficiency meets these criteria. We offer comments on a 

few of the keys issues below. We also urge EPA to reconsider its proposal to only allow states to 

count energy efficiency savings that occur at in-state affected EGUs.

 

379 See generally Molina, supra n. 334.
129

a. Evaluation, Measurement, and Verification

Many of these criteria are encompassed in the evaluation, measurement and 

verification (“EM&V”) procedures already used to demonstrate savings from EE programs. The 

fundamental purpose of EM&V programs is to identify megawatt-hours saved as a result of EE 

programs. Program evaluators take steps to ensure that the savings realized would not have 

otherwise occurred, which is critical in order for the savings to be non-duplicative. These 

existing procedures lend themselves well to the purposes of the Clean Power Plan.

We agree with EPA that further guidance is needed to assist states in designing 

compliant EE programs, but in addition to such guidance, minimum standards for state EM&V 

programs are essential to prevent overly permissive approaches from undermining the 

achievement of the emission reductions in the CPP. Some states, especially those that are 

already achieving high levels of annual energy savings, have had several years to develop and 

test EM&V procedures for a wide array of EE measure types. However, for states that lag in 

developing this critical system resource, minimum standards and additional guidance will be 

needed on what types of energy efficiency programs can count towards compliance, and what 

will constitute adequate EM&V to demonstrate savings from those programs. EPA’s Roadmap 

for the Inclusion of Renewable Energy and Energy Efficiency in State and Tribal Implementation 

plans is an excellent start on such guidance. EPA and the states can also look to the many 

excellent collaborative efforts to develop EM&V standards, including NREL’s Uniform Methods 

Project,380 the State & Local Energy Efficiency (“SEE”) Action Network,381 Northeast Energy 

Efficiency Partnership’s EM&V forum382 and the Pacific Northwest’s Regional Technical 

Forum.383

EPA proposes a qualitative hierarchy regarding the level of EM&V uncertainty for 

different types of EE programs.384 To encourage states with weak or nonexistent energy 

efficiency programs to make that a key part of their plans from the very beginning of the 

compliance period, we agree that it would be helpful for EPA to set out a predefined list of 

programs that have well-developed EM&V protocols backed by significant experience. EPA 

should not limit the states to these types of EE programs,385 as that would stifle innovation, but 

laying out a clear path for states with less experience will be extremely helpful in the early years 

of compliance.

 

380 See NREL, Uniform Methods Project, http://www.nrel.gov/extranet/ump/(last visited Nov. 21, 2014).

381 See, e.g., SEE Action Network, Energy Efficiency Program Impact Evaluation Guide (Dec. 2012).

382 See Northeast Energy Efficiency Partnerships, EM&V Forum, http://www.neep.org/initiatives/emvforum (last visited Nov. 30, 2014).

383 Northwest Power and Conservation Council, Regional Technical Forum, http://rtf.nwcouncil.org/ (last 

visited Nov. 24, 2014).

384 SPC TSD at 48.

385 Id. at 50.
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With respect to verification, EPA notes that “adequate monitoring, recordkeeping and 

reporting requirements [must be] in place to enable the state and the Administrator to 

independently evaluate, measure, and verify compliance with [the standard.]” 79 Fed. Reg. at 

34,913. Often the data collected by the independent consultant, contractor, or other entity 

providing EM&V services to the state commission are not presented with the final report 

summarizing the achieved savings. These data will need to be made available to the agency and 

other stakeholders, along with complete descriptions of how the data were treated to arrive at 

the final savings number, in order to allow independent verification. Alternatively, because 

these data can be voluminous and difficult for a non-expert to interpret, the agency may want 

to require EE program administrators to undergo occasional audits of EM&V practices by a wellregarded third party.386

A final issue relating to quantifiability is whether existing EM&V procedures allow states 

to determine the avoided CO2 emissions associated with those savings. As EPA notes in the 

State Plans TSD, some EE program administrators report only annual energy savings, while 

others estimate seasonal or hourly savings based on the nature of installed measure. If hourly 

savings are available or can be readily estimated, this would enable more precise estimates of 

avoided CO2. However, as explained in the Renewable Energy Compliance section, we believe 

that calculating avoided megawatt-hours is sufficiently rigorous to credit both RE and EE in 

state plans. If EPA determines that states must calculate the avoided CO2 associated with each 

megawatt-hour saved, the agency should identify which methodologies are most appropriate 

for this purpose and how hourly savings data can be estimated if not generated through the 

state’s EM&V plan. As discussed further below, states may need to identify specifically which 

affected EGUs dispatched less as a result of the savings from their EE programs. EPA must offer 

detailed guidance on how this can be done with a reasonable degree of certainty.

b. Non-Duplicative

EPA explains that an emission standard is non-duplicative if it is not incorporated into 

another state’s compliance plan. In part to avoid duplication, EPA has proposed that states 

should receive credit for energy efficiency programs only to the extent that they cause 

reductions at in-state affected EGUs. Id. at 34,922. As EPA explains elsewhere, states may take 

into account “only those CO2 emission reductions occurring in the state that result from 

demand-side energy efficiency programs and measures implemented by the state.”387 We 

discuss earlier (see pp. 124-27, supra) why EPA should include 100 percent of each state’s 

energy efficiency potential in BSER. Here, we discuss why EPA should allow states to use all of 

their achieved EE savings to demonstrate plan performance and how to avoid double-counting 

in doing so.

 

386 We believe that the energy efficiency registry proposed by the Climate Registry, discussed below, 

would be very helpful in establishing uniform standards and promoting transparency.

387 SPC TSD at 87.
131

EPA’s proposal to count only EE savings resulting in reduced emissions at in-state units 

would require both ex ante and ex post determinations of whether EE programs resulted in 

reduced dispatch of in-state EGUs. Alternatively, EPA suggests that net importing states could 

discount their EE savings by their net import factor (i.e., if the state imports 30 percent of its 

energy, it could only count 70 percent of its EE savings for compliance).388

We believe that allowing net importing states to count only a percentage of their EE 

savings will be a major disincentive to states employing EE as part of their plans. EPA seems to 

believe that because EE is so cost-effective, states will adopt it even if allowed to count only a 

fraction of their savings towards their Clean Power Plan goals.389 We agree that states should 

adopt aggressive energy efficiency savings targets to save their ratepayers money, regardless of 

whether those savings will contribute to the state’s plans. In reality, however state 

decisionmakers on energy issues will focus on complying with the Clean Power Plan after the 

rule is finalized, and may set aside or ignore any initiative not substantially contributing to the 

state’s plan. Moreover, states will be seeking to minimize the costs of complying with the Clean 

Power Plan, and this discounting of EE savings may influence the state to consider other 

options. Furthermore, EPA’s proposed approach would create “lost avoided MWhs,” which 

were caused by one state’s programs, but were realized in another state. In such a case, neither 

state could take credit for those emission reductions, effectively increasing the cumulative cost 

and administrative burden of CPP compliance across the country.

EPA’s primary position—that states can take credit for EE savings only if they result in 

emission reductions at in-state EGUs—would create uncertainty for states. A state may project 

that its EE programs will result in in-state emission reductions, but find in conducting its ex post 

plan performance analysis that a percentage of the reductions occurred out of state, and not be 

able to take credit for those reductions. Such a framework will make it unnecessarily difficult 

for states and discourage them from using EE as a compliance measure. The proxy approach 

where the state would use a net importation factor might give states somewhat more certainty, 

but has its own flaws. If a state reduced its annual EE savings by their net importation factor for 

the current year, states could be faced with being able to count less of their EE savings than EPA 

accounted for in the target, if the state is importing more power than it was in 2010.

We advocate that EPA allow states to take credit for 100 percent of the savings resulting 

from their EE programs. Doing so will enable states to maximize the impact of the most costeffective resource available for reducing carbon emissions. Unlike with renewable energy, 

where there is a risk that a competing claim may be staked by the state where the RE resource 

is located, or by the purchaser of “null power,” when all states are rate-based there is no 

reason that another state would lay claim to those reductions, since they would only be 

 

388 Id. at 92.

389 See 79 Fed. Reg. at 34,876, n.188 (“Given the extremely low cost of CO2 emission reductions 

achievable through demand-side energy efficiency programs, implementation of such programs is likely 

to reduce CO2 emissions at reasonable cost even for a state whose own affected EGUs achieve only part 

of the CO2 emission reduction benefit from the state's demand-side energy efficiency efforts.”). 
132

identified by the entity implementing the EE program. Even where a fossil unit is displaced in a 

state other than the state taking credit for the EE, that will not result in double counting so long 

as EPA adopts the annual true-up procedure that we recommend for states with mass-based 

limits, as discussed on p. 108, supra. Because the mass-limited unit will have less generation 

factored into its rate-to-mass conversion, its overall mass target will be lower, neutralizing the 

benefit it received by having its emissions reduced due to an out-of-state EE program. No 

double-counting occurs due to displacement of affected EGUs in rate-based states for the 

reason we describe in the Renewable Energy Compliance section, supra.

c. Permanent

EPA has stated that “An emission standard is permanent if the standard must be met for 

each applicable compliance year or period, or replaced by another emission standard in a plan 

revision, or the state demonstrates in a plan revision that the emission standard is no longer 

necessary for the state to meet its required emission performance level for affected EGUs.”390

In EPA’s 2012 Roadmap for Incorporating EE/RE Policies and Programs into State and Tribal 

Implementation Plans, the agency says that permanent EE savings are those that continue 

through the attainment year or in the case of 111(d), the compliance period.

In the energy efficiency world, this is captured by the concepts of “measure life” and 

“persistence,” which includes both the retention of an EE measure and its performance 

degradation.391 All EE measures have a limited life based on the lifetime of the underlying 

technology. In very rare cases, the life of an installed measure may be cut short, such as where 

a customer uninstalls the measure, or its savings potential degrades due to improper 

maintenance. For an EE measure to be permanent, it must be in place and generating savings 

during the compliance year. Therefore, states must ensure that EM&V protocols for ratepayerfunded energy efficiency programs address and report on persistence, which impacts the 

cumulative savings of the program. EPA guidance should address appropriate EM&V techniques 

for assessing the persistence of energy savings.

d. Enforceability

Enforceability is a key question for energy efficiency components of a state plan. While 

some energy efficiency programs are implemented by vertically integrated utilities that also 

own and/or operate affected EGUs, others are implemented by distribution-only utilities, by 

third-party administrators, or by state agencies. States have landed on different strategies for 

implementing their EERS, resulting in a wide variety of entities having obligations under state 

law. 392 However, the common feature of all of these programs is that they are funded by 

 

390 79 Fed. Reg. at 34,913.

391 NREL, The Uniform Methods Project: Methods for Determining Energy Efficiency Savings for Specific 

Measures (Jan. 2012 – March 2013), attached as Ex. 41, at 13-3.

392 See Sedano, R., Regulatory Assistance Project, Who Should Deliver Ratepayer Funded Energy 

Efficiency? (Nov. 2011), attached as Ex. 42.
133

ratepayers, and therefore supervised by the state public utility commission or other governing 

body (in the case of municipal utilities and electric cooperatives implementing their own EE 

programs).

As noted earlier, we believe that the operators of the affected EGUs in a state must be 

collectively responsible for fully achieving the state goal and that the measures to ensure 

compliance must be federally enforceable against those EGUs. In addition, entities 

implementing the EE programs can but need not be subject to federal enforceability under the 

Clean Power Plan, unless that entity also happens to own or operate an affected EGU (i.e., a 

vertically integrated utility). To the extent that the compliance entities use energy efficiency 

avoided megawatt-hours in order to achieve their emission target, they can acquire those EE 

credits from the EE program administrator, under guidelines established by the state and 

approved by EPA.Whether the state chooses to allocate non-tradeable credits, or set up a 

tradeable crediting system is its choice based on its existing state laws and considerations.

The details of the EE program must be specified in the state’s plan so that EPA can 

ensure that adequate EE savings credits will be available. Most critically, the EM&V 

requirements must be described in adequate detail for EPA and other stakeholders to assess 

whether they are sufficiently rigorous to establish savings attributable to the program. To 

ensure the availability of efficiency credits, state EE standards must contain penalties for noncompliance and self-correction mechanisms. Some ratepayer-funded energy efficiency 

programs allow the implementing utility to make up for shortfalls in one year with overperformance in the next. Allowing EE program administrators too much flexibility within a plan 

period could lead to inadequate EE credits being available in a given year; states must consider 

how these plan periods align with the Clean Power Plan’s two-year check-in schedule.

The allocation of energy efficiency credits to affected EGUs will require more active 

state involvement than the distribution of renewable energy credits, at least in the early years.

Currently, there is no platform for verification and trading of energy efficiency credits, 

equivalent to the REC trading systems for renewable energy. EPA must establish standards to 

ensure that EE savings are demonstrated through EM&V meeting the best standards and are 

not claimed by multiple parties.

A REC equivalent for energy efficiency has been discussed over the years, but has never 

taken hold in the same way as RECs. Some REC tracking systems, including NEPOOL-GIS, NAR, 

and NC-RETS, track energy efficiency savings, but the other systems have not incorporated this 

feature. In the late 2000s there was substantial interest in developing a tradeable market for EE 

credits.393 The state of Connecticut had a limited intrastate EE trading market for several years, 

 

393 See, e.g., Friedman & Bird, Energy Savings Certificate Markets: Opportunities and Implementation 

Barriers (July 2009), attached as Ex. 43; Hamrin et al., Center for Resource Solutions, The Potential for 

Energy Savings Certificates (ESC) as a Major Tool in Greenhouse Gas Reduction Programs (May 2007), 

attached as Ex. 44.
134

but it is not clear whether that market remains active.394 Some barriers to a viable market for 

energy savings credits have been identified, including: (1) high transactions costs, including the 

cost of EM&V, and (2) the absence of a nationwide standard-setting body for certification of 

ESCs (as exists for RECs).395

The Climate Registry, a nonprofit organization of states, provinces and tribal 

governments, has proposed that an energy efficiency registry be established to facilitate the 

use of EE for Clean Power Plan compliance.396 This registry would serve as a platform for 

consolidation of EM&V tools, aggregate data for consistent reporting to EPA, and would 

“provide clear and transparent attribution and ownership of energy savings” to serve as the 

foundation of a trading platform for energy efficiency credits among states. We support the 

creation of such a registry, which will ease the administrative burden on states, facilitate 

stakeholder review, and allow trading of energy efficiency credits which will ultimately expand 

the market for energy efficiency.397 Regardless of what system is used, EPA must adopt rules to 

specify minimum criteria to ensure that EM&V procedures are fully adequate and enforceable 

and reflect the best demonstrated system.

e. Which Types of Efficiency Activities May Count Toward Compliance?

EPA’s Block 4 target is primarily based on evidence that twelve states have either 

achieved annual incremental savings rates of 1.5 percent (as shown on data reported on EIA 

Form 861), or have established requirements for utilities to achieve that savings rate.398 That 

target reflects savings achieved through EE programs that are supervised by public utility 

commissions, whether implemented by load-serving utilities or by third-party administrators or 

state agencies. EPA’s target does not include appliance standards, building codes, building 

energy benchmarking requirements, or other non-PUC-supervised programs, although EPA 

refers to the availability of such measures as further reason that a 1.5 percent annual target is 

achievable.

399 EPA chose to base Building Block 4 on PUC-supervised EE programs because data 

about the savings in those programs have been reliably and widely tracked for years through 

EIA form 861.400

 

394 See Friedman & Bird, Energy Savings Certificate Market, supra n. 393, at 9; CRS, Potential for ESC, 

supra n.393, at 36. 

395 See Friedman & Bird, Energy Savings Certificate Market, supra n. 393, at 7.

396 See The Climate Registry, Statement- Establishing an energy efficiency registry as a tool for state 

compliance under U.S. EPA's Clean Power Plan (Sept. 22, 2014), attached as Ex. 45.

397 While we do not believe that private-sector EE activities, such as ESCOs, should be eligible for 

compliance, see infra, we support including protocols for these EE activities in the registry. Those credits 

would then be available to voluntary markets, and would enable EPA to gather further data on the 

potential for these activities for when it revisits the 111(d) standards in 2025, as we suggest.

398 79 Fed. Reg. at 34,872.

399 Abatement Measures TSD at 5-31.

400 To the extent that PUC-supervised EE programs have included measures relating to building code 

implementation, the program data would reflect savings from those measures. Misuriello et al., ACEEE, 
135

PUC-supervised EE programs are an ideal tool for compliance with the Clean Power Plan 

because they are integral to the load-serving utility’s planning about which resources it will use 

to serve that load. The load-serving utility incorporates the projected savings from these 

programs into the forecasts that it uses to determine how much and what type of energy and 

capacity to purchase or supply. The fact that these energy efficiency savings are a system 

resource, just like generation, is why ratepayers are required to pay for it, just as they would 

any other resource. Ratepayer-funded EE programs have been widely adopted by legislatures or 

public utility commissions as a way to reduce electricity rates and avoid having to make major 

new capacity or transmission investments. In this sense, EE programs that are integrated with 

the load-serving utilities’ planning to serve customers are fundamentally part of the same 

system as affected EGUs.

EPA has implied that states will be allowed to use building codes, state appliance 

standards, tax credits and benchmarking requirements as compliance tools.401 Because we take 

the position, as stated earlier, that the responsibility for compliance with the Clean Power Plan 

should rest entirely on the affected EGUs, we believe that the only appropriate compliance 

measures are those that the owner or operator of an EGU can play a role in adopting or 

implementing. If EPA makes compliance obligations rest entirely on the affected EGUs, then

building code or state appliance standard adoption and implementation should not be allowed 

as compliance options. To be clear, we support stringent building codes and appliance 

standards, but because only the state can adopt and enforce these measures, rather than the 

regulated entity, they are not suitable for CPP compliance under the approach we believe is 

correct, which holds the affected EGUs responsible for all compliance.

402 These types of 

measures will be an important tool for the United States in achieving the economy-wide carbon 

emission reduction targets recently agreed to. For more discussion of the US-China climate 

agreement, see section I.B, supra.

Another category of EE activities not accounted for in EPA’s Building Block 4 is privatelydelivered energy efficiency, such as energy savings performance contracts, industrial energy 

efficiency and privately contracted-for efficiency that has traditionally not been accounted for 

in ratepayer-funded energy efficiency programs. In a white paper released in May 2014 by the 

National Association of Clean Air Agencies (“NACAA”), National Association of Regulatory Utility 

Commissioners (“NARUC”), and the National Association of State Energy Officials (“NASEO”), 

urges EPA to “encourage states to develop a clear path for inclusion, crediting, and 

 

Building Energy Code Advancement through Utility Support and Engagement, Report No. A126 (Dec. 

2012).

401 79 Fed. Reg. at 34,872.

402 Insofar as a public utility commission approves measures related to building codes as part of a 

ratepayer-program, as already happens in some places, those building code–related savings could 

indirectly be part of the state’s Clean Power Plan performance demonstration. See Misuriello et al., 

supra n. 400.
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administrative review” of these activities.403 Although EPA’s Building Block 4 target is based on 

ratepayer-funded EE programs, EPA does note that it considered EE activities outside of 

ratepayer-funded programs as further assurance that a 1.5 percent annual target is achievable.

In contrast to building codes and state appliance standards, this category of EE activities is 

something that the owners and operators of EGUs can implement, by offering the upfront 

capital needed to weatherize, retrofit, and upgrade buildings for efficiency purposes. In 

addition, there is a large market of unmet demand for weatherization of low-income homes 

and small businesses, which affected EGU operators could serve by offering financing or 

outright grants. Because similar measures are offered through ratepayer-funded EE programs, 

there are already well-established EM&V protocols for retrofits, weatherization, and 

replacement of inefficient appliances.

VI. State Plan Considerations

A. Plan Approaches

1. EPA Should Require State Plans to Make Affected EGUs Fully and Solely 

Responsible for the Emission Reductions Required Under the Rule.

Under the Clean Air Act, owners and operators of affected sources are the entities 

responsible for meeting the state performance goals that are established under a section 

111(d) rule. The Act explicitly provides for state plans requiring affected sources to be the 

entities legally responsible for achieving the required emission standards: section 111(d)(1) 

requires that EPA ensure that each state submits a plan that “establishes standards of 

performance for any existing source” within its borders. 42 U.S.C. § 7411(d)(1)(A) (emphasis 

added). Emission limits that are federally enforceable against affected EGUs clearly fall within 

the definition of a “standard of performance.” See id. § 7411(a)(1) (defining a “standard of 

performance” as “a standard for emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of the best system of emission reduction 

. . . adequately demonstrated”). This approach has worked well for prior iterations of standards 

of performance for existing sources, and EPA and state authorities must not stray from the 

rule’s mandate: each state plan must be structured such that the state’s fleet of affected EGUs 

are legally responsible for the full quantity of emission reductions specified in the state plan, 

and will be subject to federal enforcement actions if they fall short of their obligations under 

the state plan.

It is true that the Clean Power Plan quantifies the emission reduction obligations of 

affected EGUs in part by considering the extent to which other sources of generation (or 

demand reduction) can fill in the gaps created by reduced dispatch of affected units. However, 

this does not provide a legal nor technical justification for shifting any degree of responsibility 

for emission reductions away from affected sources onto other entities, such as EE portfolio 

managers or operators of renewable energy resources. As noted above, section 111(d) is quite 

 

403 See NARUC et al., Principles for Including Energy Efficiency in 111(d) of the Clean Air Act, 

http://naruc.org/Publications/Energy-Efficiency-Principles.pdf.
137

clear: sources are subject to 111(d) standards of performance, and neither EPA nor a state can 

avoid the statute’s command. 

Accordingly, states will need to take an active role in crafting state plans that apportion 

emission reduction obligations across their fleets of affected units and in administering such 

programs. This point is particularly important for states that choose to adopt a rate-based 

protocol, since emission reductions achieved through measures other than on-site heat rate 

improvements—EE, RE, and other techniques that allow for reduced dispatch of affected fossil 

units—will not be reflected in the emission rates of the affected EGUs. Therefore, rate-based 

states will need to include a mechanism in their implementation plans that adjusts the emission 

rate at affected units to account for non-HRI emission reductions. These mechanisms may 

include trading markets for RECs (which already exist) or energy efficient credits (which are not 

yet widely used), or programs by which states administratively apportion emission reduction 

credits across the fleet of affected units. EPA discusses some of these options in the rule 

preamble. See 79 Fed. Reg. at 34,900-02. 

We note here that section 111(d) does not prevent states from imposing obligations on 

non-affected entities so long as it ensures that affected EGUs are ultimately responsible for all 

emission reductions. For instance, a state plan may require a distribution utility that owns no 

affected EGUs to sponsor EE measures that will reduce demand from affected facilities in the 

state. If it fails to implement or fund these EE programs, the state may impose penalties on the 

utility. What a state may not do, however, is shift responsibility away from affected EGUs and 

onto other entities. Affected sources must be subject to federally enforceable emission limits 

that cover all the required reductions, and states must craft their plans to ensure that affected 

entities can claim proper credit for emission reductions that are not automatically reflected in 

their source-specific emission rates.

2. Rate-Based Targets vs. Mass-Based Targets

a. Asymmetry Between Mass-Based and Rate-Based Goals Under EPA’s Proposal

As EPA has emphasized, one of the Clean Power Plan’s key features is to permit states to 

translate their rate-based emission goals into equivalent mass-based tonnage caps. As we 

discuss below, EPA must ensure in its final rule that any mass-based translation is truly 

equivalent to a corresponding rate-based goal. Otherwise, states may pursue compliance 

pathways that would satisfy a mass-based goal while falling short of a rate-based goal, 

effectively making end-run around EPA’s emission limitation targets.

The rate of CO2 that is emitted over any period of time by a defined group of affected 

EGUs can be calculated as the mass of CO2 emitted by those sources divided by the net 

electricity they generate over the same period of time. Since the amount of generated 

electricity is at least as well known as the amount of CO2 those sources emitted, there should 

be no difference between a mass-based and rate-based standard, all other factors being equal. 

Indeed, the relationship between these metrics is provided by a simple equation: mass = rate 
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times generation (M = G*R). If generation remains fixed, then M and R will always be directly 

proportional; hence, any standard based on one should be no different than a standard based 

on the other.

However, as the plan is now written, there is a critical asymmetry between rate-based 

and mass-based standards. Under the current proposal, a state’s compliance with EPA’s ratebased limit is calculated as a ratio of the direct measurements of CO2 emitted by affected EGUs 

during the compliance period to the state’s actual “regulated generation” during that same 

period. By regulated generation, we refer to electricity produced by existing affected EGUs as 

well as electricity from new and existing renewable units, a percentage of new and preserved 

nuclear generation, and electricity avoided due to energy efficiency measures. On the other 

hand, under a mass-based regime, while compliance is based on a state’s actual emissions from 

its affected EGUs, the mass-based limit itself is computed at the outset of the compliance 

period (i.e., when the state submits its plan to EPA) based either on a fixed level of generation 

(such as 2012 generation) or an assumed or projected level of future generation.

This is problematic because a state’s projected level of regulated generation will 

ordinarily be higher than the actual generation level. First, it is technically difficult to predict a 

state’s mix of electricity resources more than a few years into the future. Second, it is similarly 

difficult to project the rate of demand growth over an extended interval, and states will be 

more likely to overestimate rather than underestimate future electricity demand in order to 

reflect economic optimism. Finally, as a result of the M = G*R relationship, higher projections of 

regulated generation correspond to higher mass-based targets, so states will have an incentive 

to overestimate future electricity generation in order to relax their compliance burdens.

For these reasons, a state’s mass-based limit (based on a level of projected generation) 

will normally be higher (and hence easier to comply with) than a rate-based standard that is 

based on actual generation. According to the M = G*R equation, a larger ‘G’ will yield a larger 

‘M’ (and thus a higher mass-based cap) if ‘R’ remains constant. If the state opts to use a fixed 

generation figure from (for example) 2012, the problem is even more stark, since the pool of 

regulated generation is assumed to remain constant for the next 18 years, which is almost 

certainly incorrect.

As an illustration, consider a state that generates all of its electricity from existing fossilfired EGUs (coal, gas, and oil units). The state then reduces generation from each of its existing 

sources by 50 percent and replaces the lost electricity with new, unregulated404 fossil 

generation. The mass of emissions will be cut in half while the rate is unchanged. By the same 

token, if generation from each existing source were doubled, the mass would also double while 

the rate again remained constant. Accordingly, whether a rate-based or mass-based regime is 

environmentally preferable depends, at least in part, on whether regulated generation (that is, 

 

404 By “unregulated,” we do not mean that these sources are entirely free from regulations; rather, we 

mean that their emissions and generation are not included in goal-setting or compliance determinations 

under the Clean Power Plan.
139

generation that would be included in a state’s denominator when calculating its emission rate) 

will increase or decrease over time relative to expectations.

In a rate-based system that requires reductions over time—such as the Clean Power 

Plan—the only available compliance option a state has is to replace higher-emitting generation 

with lower-emitting generation. Under the current proposal, if electricity from coal-fired 

sources is replaced by generation from existing gas units, both the generation and the 

emissions from those gas units are included in the calculation. However, if new gas generation 

is used to replace existing fossil-fired generation, neither the emissions nor the generation from 

the new gas units are included in the state’s compliance calculation—that is, these sources do 

not produce “regulated generation.” Hence, when a new fossil unit replaces an existing fossil 

unit, the state will necessarily reduce its regulated CO2 tonnage while its emission rate will vary 

only a small amount depending upon the remaining mix of generation. If the retiring unit emits 

more CO2 on average than the remaining fleet, the overall rate will go down marginally; if it 

emits less, the rate will increase marginally. A mass-based protocol therefore encourages states 

to replace retiring fossil units with new fossil units in a way that a rate-based regime does not.

In contrast to new fossil sources, new renewable sources and EE measures do produce 

“regulated generation”—that is, they are factored into states’ rate-based compliance 

denominators. The more EE and RE a state implements, the more its compliance denominator 

grows and the faster it approaches its target rate. Accordingly, under a rate-based standard, 

states have a greater incentive to replace retiring fossil plants with new renewables or EE, 

which will lower the state’s emission rate, as opposed to new gas units, which do not increase 

the state’s compliance denominator. It appears, therefore, that a rate-based regime is 

environmentally preferable, since it incentivizes states to replace retiring fossil units with RE 

and EE rather than new gas, whereas a mass-based protocol does not offer the same incentives.

To ensure that the Clean Power Plan achieves the maximum intended emission 

reductions, EPA must foreclose any possibility that a mass-based plan provides a less rigorous 

compliance path than its rate-based corollary. Some might argue that including new NGCC

generation as both a component of BSER and a compliance option would help address this 

problem, since states could no longer shift generation from regulated to unregulated fossil 

units and thereby artificially reduce their mass emissions. However, we urge EPA not to credit 

new NGCC for either goal-setting or for compliance, since it could encourage states with higher 

emission targets to opt for new gas units at the expense of new renewables and efficiency, 

which are environmentally preferable. Furthermore, this approach would not solve the 

problems inherent in projecting regulated generation years into the future; it would simply add 

a new category of sources to the pool of what may be considered regulated generation.

We therefore propose that EPA reject any call to adopt new gas for goal-setting and 

compliance purposes. Instead, we propose a new “accounting” method by which EPA can 

ensure that rate-based and mass-based targets provide identical environmental benefits. As 

discussed above, mass and rate are directly proportional according to the equation M = G*R. In 

theory, then, there should be no difference between a standard based on M and a standard 
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based on R so long as ‘G’ is correctly tabulated. Accurate accounting requires two things. First, 

‘G’ should include the sum total of “regulated generation” in a state—generation from existing 

affected units, new and existing RE, the designated percentage of a state’s nuclear generation, 

and “negawatts” produced through EE measures. In other words, ‘G’ is simply the denominator 

used to calculate a state’s compliance rate. Second, ‘G’ must be updated each year to ensure 

that a state’s projections of regulated generation are accurate, and account for any 

unanticipated or unprojected reduction in electricity from regulated sources.

In its current form, EPA’s proposal falls short in that it does not specify what year’s 

regulated generation should serve as ‘G,’ nor does it require states to adjust their mass-based 

targest to account for any unanticipated losses in regulated generation resulting from fossil 

retirements. These shortcomings permit states simply to shift generation from existing fossil 

plants to new gas units that have effectively the same emission rate as existing gas units. As 

written, the current mass-based option reduces the amount of RE and EE that a state will need 

to comply with its emission targets and all but guarantees that “regulated generation” will 

decline over time. If EPA instead were to require that states recompute M = G*R each year to 

capture the actual ‘G’ that has been produced in the state for that year, each state’s state’s 

mass-based and rate-based targets will be environmentally equivalent.

b. The Texas Example

The current generation mix in Texas provides a clear illustration of the phenomenon we 

describe above. Table 11 depicts the 2012 data for Texas by source category.

Table 11- 2012 Emissions and Generation Data for Texas

In Table 12, we compare Texas aggregated 2012 data with EPA’s targets for 2020, 2020-

2029, and 2030. For the rate-to-mass conversion, we set ‘G’ at Texas’s 2012 regulated 

generation of approximately 379 million MWh. This assumes that Texas’s pool of regulated 

electric generation remains constant between 2012 and 2030. The state’s 2030 final targets are 

highlighted in blue.
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Table 12- 2012 Totals and EPA’s 2020, 2020-2029, and 2030 Targets for Texas

As Table 12 illustrates, EPA has set Texas’s final rate-based target for 2030 at 791 lbs 

CO2/MWh. Setting ‘G’ at 379 million MWh, ‘M’—Texas’s mass-based target—equals 

approximately 150 MMT CO2 for 2030. Next, we aggregated data from ten existing coal-fired 

plants that are over 40 years old and therefore nearing retirement age. The data for these 

plants are provided in Table 13 below.

Table 13- Data for Texas Coal Plants Nearing Retirement Age

We then evaluated two emission reduction scenarios, data for which are depicted in Table 14: 

 Scenario 1: Texas would implement Building Blocks 1 and 2 and would credit its existing 

(as of 2012) renewable generation and its preserved nuclear generation, but would 

neither implement any EE measures nor construct any new RE units, nor would it retire 

any of the 10 coal plants.
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 Scenario 2: Texas would retire the 10 coal plants and would replace them with new 

NGCC units. It would also credit preserved nuclear capacity and 2012 RE generation, but 

would not otherwise implement any of the four building blocks measures. Hence, there 

would be no heat-rate improvements, no redispatch, no newly constructed RE, and no 

EE measures implemented.

Table 14- Data from Emission Reduction Scenarios

Table Q illustrates that under a mass-based regime, Texas can achieve significantly 

greater emission reductions by simply retiring the 10 aging coal plants and replacing them with 

new NGCC units than by implementing Building Blocks 1 and 2, even though these two 

scenarios would produce nearly equal results under a rate-based protocol. In fact, Texas can 

fully comply with and even exceed its mass-based limit of 150 MMT under scenario 2, which 

would result in net regulated emissions of approximately 141 MMT, even while its emission 

rate (977 lbs CO2/MWh) would be significantly higher than its final rate-based target of 791 lbs 

CO2/MWh. 

Under Scenario 2, overall electricity generation from regulated entities drops from 379 

million MWh to 288 million MWh. If the 93 million MWh that had been generated by the 10 

retired coal units is replaced by new gas-fired generation, neither the electricity nor the 

associated emissions will be included when calculating the state’s emission rate, since (as 

discussed above) new gas-fired electricity is not counted as “regulated generation.” But unless 

there is some mechanism that requires Texas to readjust its mass-based goal to account for the 

fossil retirements, the 91 million MWh factor into the state’s calculation of its mass-based goal 

at the same time that the emissions associated with those 91 million MWh simply disappear 

from the equation.

c. The Need for Actual Generation Data and a True-Up Requirement

EPA can—and must—rectify this flawed regulatory design by basing each state’s mass 

targets limit on the actual regulated generation in that state during the compliance interval, 

with a period of time after the end of the year to allow sources to “true up” any shortfall by 

overcomplying or purchasing allowances, similar to the Acid Rain Program’s compliance 

protocol. In the example above, Texas’s final mass-based goal of 150 MMT CO2/year was 

initially calculated by multiplying the final rate (791 lb CO2/MWh) by its initially predicted 
143

regulated generation of 379 million MWh. Recalculating this figure using the actual regulated 

generation—288 million MWh—would yield a final mass-based target of approximately 114 

MMT CO2/year. The state’s final and interim targets would thus be recalculated annually to 

reflect the actual regulated generation figures, as opposed to a figure predicted at the time the 

state submits its plan to EPA. This method is the only way of ensuring that the stringency of a 

state’s mass-based program is the same as EPA’s rate-based proposal.

Alternatively, one could determine a mass-based limit by projecting regulated 

generation based on the prior year’s figures, rather a long-term projection. Either of these 

approaches might, in fact, be called “rate-based,” as they do not provide a definite and 

predetermined cap on emissions that remains in place through the duration of the regulatory 

period.405 However, planning concerns for states wishing to follow a mass-based approach are 

no greater than they would be for rate-based states. Instead, the advantage of these 

approaches is that they still allow trading of mass-based allowances for compliance. It has been 

argued that mass-based programs provide the certainty of a hard cap on emissions, but in fact, 

programs such as RGGI are successful only where member states adjust the cap on a reasonably 

regular basis. The same should be true of EPA’s Clean Power Plan, and readjustment must be 

annual to ensure that rule does not privilege a mass-based approach over rate-based protocol 

(or vice versa). This approach we recommend would simply identify the glide path for such 

readjustments. 

Compliance planning for both mass- and rate-based programs offer opportunities for 

states to effectively “game the system” if the planning cycle is overly long. Even program 

managers operating in good faith are unlikely to incorporate voluntary plant retirements into 

compliance plans until those retirements are announced by the operators. As indicated above, 

PUCs engaged in integrated resource planning cannot generally forecast future developments 

more than a few years into the future with the kind of specificity necessary to inform 

investment decisions. As we discuss in more detail in Section XIII.A, these factors argue for 

shorter compliance periods than suggested by the EPA’s proposal—perhaps an overall 

compliance period of 8 years to match the section 111(b)’s review period, with an interim 

compliance date of 4 years.

It bears noting that various commenters—including EPA in its preamble—have 

suggested that mass-based approaches are advantageous in that they obviate the need for 

rigorous EM&V of EE measures that ensure effectiveness, since they determine compliance 

based only on CO2 emissions measured at the stacks of affected EGUs. This viewpoint overlooks 

the fact that a state must determine its regulated generation in order to calculate a mass-based 

target in the first place. If a state chooses not to verify its EE measures through adequate EM&V 

procedures, it cannot include those measures the pool of regulated generation—or ‘G’—by 

which it translates its rate target to its mass target through the equation M = G*R. If the state 

omits those negawatt hours from ‘G’, its final mass-based target will be lower than it would 

 

405 Determination of compliance with rate-based programs in any given year necessarily includes 

determining mass emissions for that year.
144

otherwise have been, and hence the state will have more difficulty achieving compliance. 

Accordingly, states wishing to receive credit for their EE measures must partake in EM&V 

regardless of whether they follow a rate- or mass-based protocol.

d. Our Approach Prevents Double Counting of RECs

Our recommend method of converting rate-based to mass-based goals has an added 

benefit of preventing states from double counting RE credits. In a rate-based system that uses 

projected rather than actual regulated generation and that does not require an annual true-up, 

a state need only show that its mass emissions do not exceed the tonnage cap for the 

compliance year. A state may have achieved the necessary reductions in part by investing in 

new renewable generation, but nothing in the rule as written prevents a utility from selling the 

RECs that are attached to those same renewable sources that have helped the state achieve 

compliance. Therefore, the purchasing state will receive credit for the REC even after the selling 

state has used that renewable source to achieve compliance with the standard.

Under our approach, states will need to recalculate their emission targets each year to 

reflect actual regulated generation, which included any electricity produced by renewable units. 

If a state has sold a REC linked to any given RE generator, it will not be permitted to include 

those megawatt-hours in its ‘G’ figure for the M = G*R calculation, and it will therefore have a 

more stringent mass-based target. States thus have a choice: they can either sell a REC 

associated with a renewable unit to another state and receive payment, or they can include the 

electricity generated by that source during the true-up process to raise their mass ceiling, but 

they cannot do both. Double counting of RECs is therefore avoided, and the rule achieves 

greater environmental benefits as a result.

B. Compliance and Enforcement of State Plans

1. Corrective Measures Can Significantly Reduce Compliance Problems, but Only if 

EPA Provides More Detailed Minimum Requirements for Such Measures.

EPA’s proposal to have states build corrective measures into their plans is an essential 

strategy for reducing the risk of non-compliance with the unusually long averaging times in the 

Clean Power Plan. Absent some mechanism for ensuring that states remain on track, the 

proposed 10-year compliance period406 creates the potential for a pile-up of violations in 2030, 

when a final determination of compliance with interim goals is made. For EPA to wait until then 

to require the development of additional plan measures would unnecessarily delay emission 

reductions, and the need for states to incorporate remedial measures into their plans would 

only add to this delay. The failure to achieve projected emission performance in the early years 

of a state plan may also indicate structural problems with the plan (e.g., inaccurate modeling 

results) that could render compliance with the state goals impossible. Moreover, because EPA 

proposes to allow states to define their own emission reduction trajectories between 2020 and 

 

406 As discussed in section XIII.A, infra, we support an accelerated and shortened compliance schedule.
145

2029, there is a risk that many state plans will defer making the most significant cuts until the 

later years of the interim period. Procrastination of this nature, together with any unaddressed 

failures to achieve the more modest early reductions, could lead to a critical shortage of 

available measures in the later years to ensure compliance with EPA’s targets. 

Because corrective measures have such an important role to play in ensuring that states 

achieve the CPP’s performance goals, additional requirements for corrective measures are 

crucial if they are to be effective compliance tools. EPA must expand corrective measures to all 

plans, set minimum thresholds and standards for the adoption, activation, and implementation 

of these measures, and providing greater transparency in exposing the causes of any 

deficiencies in state plan performance.

All state plans must ensure that affected EGUs are responsible for all the emission 

reductions required under the rule and thus subject to federal enforcement actions, as 

discussed above. To supplement to federal enforceability, corrective measures are necessary to 

ensure that plan deficiencies are fixed swiftly and soon after they occur. We are concerned, 

however, that EPA underestimates the full value of corrective measures. Under the proposed 

rule, “self-correcting” plans need not include corrective measures. See 79 Fed. Reg. at 34,952 

(proposed 40 C.F.R. § 60.5740(a)(7), requiring corrective measures only for plans that do not 

rely on emission limits on affected EGUs to achieve all state goals). EPA describes self-correcting 

plans as those which “would assure interim performance and full achievement of the state 

plan’s required level of emission performance through requirements that are enforceable 

against affected EGUs.” Id. at 34,907. However, just because an emission standard in a state 

plan may be enforceable against affected EGUs does not mean that violations of the standard 

will actually be enforced in a way that assures the state plan’s emission performance goals are 

achieved. For example, an enforcement action may result only in civil penalties and not in 

reductions in future emissions from an EGU. In that case, the excess emissions from the 

violating EGU may throw the state off course from achieving a performance goal. Future year 

requirements for affected EGUs in the state plan may need to be adjusted to correct this 

deviation, and such adjustments are functionally no different than the corrective measures EPA 

has proposed for any plans that are not self-correcting. 

To effectively serve their intended purpose, corrective measures must be actionable 

when a state submits its plan to EPA. The agency has proposed to leave to the states the 

decision whether to adopt corrective measures into their regulations prior to submittal, or 

whether to wait until after a deficiency is discovered before taking legislative or administrative 

action to codify the corrective measures in the plan. The proposed rule offers that “it may be 

challenging for states to fully adopt corrective measures in advance to address the possibility 

that their plan will not perform as projected.” 79 Fed. Reg. at 34,907. However, even if states 

have difficulty identifying potential corrective measures, EPA has not identified what about the 

mere codification of those measures—in tandem with the adoption into state codes of other 

plan provisions—poses a special challenge. Furthermore, EPA recognizes that “[l]egislative 

and/or regulatory action to adopt corrective measures after a deficiency is discovered will take 

significant time.” Id. There is no reason to allow states to delay the adoption of corrective 
146

measures until after a deficiency occurs, or to make the implementation of corrective measures 

that states have already identified in their plans unenforceable. By analogy, the Act requires 

SIPs for nonattainment areas to “provide for the implementation of specific measures to be 

undertaken” if the area fails to make timely progress toward attainment of standards, and 

further requires that such measures “shall be included in the plan revision as contingency 

measures to take effect in any such case without further action by the State or the 

Administrator.” 42 U.S.C. § 7502(c)(9)(emphasis added). The same sort of approach is 

warranted for the section 111(d) plans at issue here, if they are to ensure the “best system” of 

emission reductions. See also id. § 7511a(c)(9).

EPA must also establish a deadline for states to begin implementing corrective measures 

once their actual emissions or emission rate exceeds projections. Although the agency has not 

proposed such a deadline in the rule proposal, see 79 Fed. Reg. at 34,952 (proposed 40 C.F.R. § 

60.5740(a)(7)(ii), requiring only that state plans include “a process and schedule for 

implementing such corrective measures”), it suggests that two years after a state reports a 

deficiency in its annual performance update may be a suitable deadline. Id. at 34,912. Because 

states will likely have notice of the deficiency well in advance of the reporting date, an 

additional two years for implementing corrective measures is unnecessary and irrational. As 

noted above, the Act requires immediate triggering of contingency measures where 

nonattainment areas fail to meet progress targets. There is no reasoned basis for allowed a 

more delayed approach under section 111 plans. Only the incremental corrective measures 

would need to be implemented anew, not the entirety of the plan. Any delay longer than six 

months would therefore be excessive for undertaking corrective action.

Another facet of this compliance approach that requires clarity is the minimum amount 

of corrective measures that plans must include. EPA’s proposal requires that such measures be 

available to remedy plan deficiencies, but has not specified any minimum requirements. 79 Fed. 

Reg. at 34,952 (proposed 40 C.F.R. § 60.5740(a)(7)(ii)). The agency also seeks comment on 

whether corrective measures must be sufficient to remediate deficiencies or merely to ensure 

the future achievement of the state’s goals. See 79 Fed. Reg. at 34,908. At a minimum, 

corrective measures must serve to fully remedy any shortfall in plan performance as measured 

over the two-year period over which EPA will evaluate states’ progress in meeting their goals. 

Therefore, if EPA retains its proposed 10 percent deficiency as the trigger for corrective 

measures, states must develop corrective measures that achieve improvements in excess of 10 

percent of their annual targets. Otherwise, the corrective measures would not fully correct the 

deficiency that triggered them. To ensure the availability of sufficient corrective measures to 

avoid the need for a SIP call, EPA should require state plans to include fully adopted corrective 

measures adequate to provide at least double the deficiency trigger percentage for each year of 

the plan, plus an additional menu of contingency measures that will be triggered progressively 

if the doubled trigger percentage is not sufficient to compensate for the full shortfall.

EPA must also clarify that the criteria for corrective measures are as rigorous as those 

concerning plan measures that are not contingent on a deficiency. For example, the 

effectiveness of the corrective measures selected for inclusion in the plan should be evaluated 
147

through the same process that states use for other plan projections: they must be quantifiable, 

verifiable, non-duplicative, permanent, and enforceable. Additionally, monitoring, reporting, 

and recordkeeping requirements for corrective measures must be sufficient to assure 

compliance.

The trigger for corrective measures must be set low enough to assure compliance. 

Although the agency has proposed a 10 percent deficiency as the trigger for corrective 

measures, it has solicited comment on a range of values, suggesting that five to 15 percent may 

be appropriate for states with corrective measures adopted into their regulations and five to 10 

percent for states without codified measures. See id. at 34,907. Because many states are 

unlikely to adopt plans that overcomply with EPA’s goals, it is important to keep states as close 

as possible to the emission reduction trajectory laid out in their implementation plans. Even a

five percent deficiency may prove impossible to overcome without additional plan measures to 

make up the deficit in subsequent years. 

Finally, EPA has proposed that a state would only have to determine and report its 

reasons for deficient performance if it elects to wait until after it discovers the deficiency before 

incorporating the plan’s corrective measures into its regulations. Id. EPA has not justified this 

stance, and information about the cause of the shortcoming would have significant value. 

Publishing the reasons for deficient performance could provide early notice to other states and 

the public of problems that may surface in many plans, such as lower-than-expected benefits 

from certain energy efficiency incentive programs for particular kinds of equipment. The 

benefits this information outweigh the modest analytical and reporting burden that it may 

impose on states who have experienced a plan deficiency, and EPA should require all states 

that report a deficiency to make public its cause.

2. Unit-Specific Evaluation Periods Should Be One Year for All Affected EGUs, with 

States’ and EGUs’ Progress Reported to EPA Annually.

EPA has proposed to allow differing unit-specific evaluation periods for rate-based and 

mass-based state plans (up to one year for the former and up to three years for the latter). Id.

at 34,956 (proposed 40 C.F.R. § 60.5820 definition of “compliance period”).407 Although not 

clearly stated, EPA’s rationale for this disparity appears to be the fact that the mass-based RGGI 

program utilizes a three-year evaluation period, whereas a three-year averaging time for 

emission rates would be execssive. See 79 Fed. Reg. at 34,881, 34,922. However, even if it were 

appropriate for EPA to tailor its emission guidelines to fit the programs states have already 

 

407 By “evaluation period,” we mean the interval over which a state determines whether an affected 

EGU has complied with an applicable rate- or mass-based emission target included in the state plan. EPA 

refers to these unit-specific evaluation periods as “compliance periods” in its proposed regulations. 

However, throughout these comments, we use the term “compliance period” to refer to a different 

concept: the interval during which the Clean Power Plan targets will apply (2020-2030 or 2020-2025 

under the current proposal). To avoid confusion, we refer to the unit-specific interval for determining 

compliance with an emission target as an “evaluation period” instead of a “compliance period.”
148

adopted, accommodating the enforcement periods in existing state programs could seriously 

undermine the enforceability of the CPP’s state goals. 

EPA has proposed requiring states to report performance data to the EPA annually by 

July 1, and that beginning in 2022, states would include in their reports a comparison of actual 

performance to projected performance, with each comparison covering the preceding two-year 

interval. Allowing some states to apply a three-year evaluation period to their affected sources, 

in tandem with the proposed rule’s requirement that affected EGUs report hourly CO2

emissions and net electric output for each evaluation period, see 79 Fed. Reg. at 34,955 

(proposed 40 C.F.R. § 60.5805(c)), would render unworkable the annual comparison of actual 

and projected performance under the plan. Apparently recognizing this, the proposed rule 

states that EPA “may also approve regular, periodic emission comparison checks with a 

different frequency or comparison period to reflect the design of a state’s programs (e.g., 

compliance periods for EGUs under an emission limit).” 79 Fed. Reg. at 34,907. In other words, 

the comparisons that are crucial to evaluating the success of state plans in reducing emissions 

may only be required every three years for some states. 

The proposed rule does not explore the drawbacks of allowing less frequent comparison 

checks for some states, despite the significant value in maintaining a uniform approach with 

annual comparisons. The annual comparison checks that EPA has proposed will provide a 

crucial opportunity for the agency and the public to assess the progress of all states in meeting 

their goals. Staggering some of these checks or using different comparison periods would 

complicate the task of ensuring the integrity of the reported results, by (for example) 

identifying possible instances of double-counting, particularly for EE or RE measures with 

interstate effects. Requiring a unit-specific evaluation period of one-year for all states may 

require changes to some existing state programs, but these changes would be modest and are 

necessary to generate a uniform set of performance data for assessing the progress of all states 

in meeting the CPP’s goals. 

Similarly, EPA’s suggestion to require state progress reports only every two years 

overlooks the crucial role that annual reporting plays in informing the public of the Clean Power 

Plan’s success or failure toward achieving its goals. See id. at 34,914. Each element of the 

annual report described in proposed 40 C.F.R. § 60.5815 is needed to present an accurate 

picture of states’ progress.

Finally, EPA requested comments on whether electronically submitted reports from 

affected entities should be provided to EPA or only to the relevant state authorities. See id. at 

34,910-11. Requiring affected sources to report to EPA in addition would help the public 

evaluate the progress that individual units achieve toward reducing emissions, the performance 

of different states, and the effectiveness of the plan as a whole. A central clearinghouse of unitspecific data would help interested citizens avoid having to negotiate the multiple different 

interfaces and software functionalities on which state agencies may rely. For these reasons, EPA 

should require annual state progress reports and should require affected EGUs to submit 

electronic reports to states and EPA alike.
149

3. EPA Should Require Direct CEMS Monitoring of CO2 Emissions.

EPA proposes to allow facilities to determine compliance with an applicable standard by 

either monitoring emissions directly or by estimating emissions based on fuel consumption.

Proposed 40 C.F.R. §§ 60.5535, 60.5540.408 Direct monitoring of emissions, especially using 

continuous emission monitoring systems (“CEMS”), is generally more accurate than estimations 

of emissions using fuel consumption, as EPA has previously acknowledged.409 In fact, all or 

virtually all existing coal‐fired plants already use CEMS to comply with existing reporting 

requirements under the Clean Air Act’s Acid Rain Program and Greenhouse Gas Reporting 

Rules.410 Accordingly, requiring coal plants to use CEMS for the Clean Power Plan will improve 

reporting accuracy while imposing little (if any) additional burden on industry. We urge EPA to 

require CEMS not only at coal plants, but at all units reporting CO2 emissions under the CPP.

The value of CEMS data is illustrated by analysis of plants for which EPA has both CEMS 

and fuel‐based emission estimates. Power plants within the Clean Air Act’s Acid Rain Program 

report CO2 emissions to the EPA, and essentially all, if not all, coal‐fired plants do so using 

CEMS, while most oil‐ and gas‐fired plants use site‐specific emissions calculations.411 The Energy 

Information Administration (“EIA”) also calculates emissions for these plants, but uses fuel 

consumption data rather than the CEMS information.412 These parallel data sets allowed U.S. 

Geological Survey scientists to compare measured and estimated emissions for 2,900 plants, 

including the 828 plants that report using CEMS measurements (which are almost entirely coal 

plants).413 The researchers found significant divergences between the two data sets. Overall, 

the fuel consumption data provided an average emission rate estimate that was 4.6 percent 

lower than the CEMS data.414 This result masks even greater divergences in estimates at 

 

408 It appears that EPA inadvertently omitted a third provision relating to using fuel consumption to 

estimate emissions. Proposed 40 C.F.R. § 60.5535(c) refers the option of “determin[ing] . . . C02 mass 

emissions are by monitoring fuel combusted in the affected EGU and periodic fuel sampling as allowed 

under § 60.5525(c)(2),” but the proposal does not contain a section 60.5525(c)(2).

409 See, e.g., EPA, Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions 

Proposed Rule (Sept. 2009), available at 

http://www.epa.gov/ghgreporting/documents/pdf/archived/EPA-HQ-OAR-2008-0508-2229.pdf, at 5‐15 

to 5‐21; Schakenbach et al., U.S. Office of Atmospheric Programs, Fundamentals of Successful 

Monitoring, Reporting, and Verification under a Cap‐and-Trade Program, 56 J. of the Air & Waste Mgmt. 

Ass’n 1576, 1581 (Nov. 2006), available at http://www.epa.gov/airmarkets/captrade/docs/fundamentals.pdf.

410 Ackerman & Sundquist, Comparison of Two U.S. Power‐Plant Carbon Dioxide Emissions Data Sets, 42 

Environmental Science & Technology 5,688,5,690 (June 2008), available with password at 

http://pubs.acs.org/doi/abs/10.1021/es800221q (“Currently, all coal‐fired units use CEM systems”). 

411 See 40 C.F.R. §§ 75.10(a)(3) (CO2 monitoring options); 75.13 (CEMS requirements).

412 Ackerman & Sundquist, supra n. 410, at 5,688.

413 See id. at 5,689.

414 Id.
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individual plants.415 The discrepancy is likely due to the inherent inaccuracy of fuel sampling for 

coal plants. Samples are typically taken from different parts of the fuel pile, and the calculations 

do not take into account environmental conditions at the time of fuel use, such as wet or frozen 

coal.

As for natural gas, EPA’s fuel sampling procedures include a determination of the 

relationship between fuel flow and load for the unit.416 This requires the operator to measure 

the fuel consumption and generation of the unit on an hourly basis for 168 hours, then to 

calculate the average fuel consumption per unit of generation. However, EPA’s procedure 

allows a source to exclude as “nonrepresentative” any hour in which the unit is “ramping up or 

down” (defined as a variation in load of greater than 15 percent) or is operating at low load 

(defined as any hour in which the load is in the lower 25 percent of the units normal range of 

operation). The effect of this procedure is to effectively exempt periods of low or changing load 

from regulation. As EPA has previously recognized, emission rates are ordinarily higher during 

these periods of operation than during steady-state, near full-load conditions. Since the excess 

CO2 generated under these conditions contributes to climate change and can be reduced by 

minimizing low load and ramping activities, these emissions should be included in determining

the unit’s emissions. 

4. Affected Units Should Be Required to Submit Engineering Analyses and Reference 

Method Test Results to Confirm the Effectiveness of Compliance Measures.

Under the Acid Rain Program, sources were afforded the opportunity to choose a 

baseline year from among several years for determining the baseline emission rate. If EPA were 

to adopt this approach for the Clean Power Plan, sources would likely select the year with the 

highest emitting rate, and any emission reductions under Block 1 via heat rate improvements 

would be largely illusory. However, choosing either the average or the reported lowest 

emission rate, which might be five percent less than the average rate, would lead to concerns 

that the requirement is infeasible. Moreover, the heat rate achieved by the unit is partially 

dependent on the load factor of the unit, which is a function of weather, dispatch priority, and 

other factors.

To address these concerns, we suggest that each source should be required to submit 

an engineering analysis of the measures that it intends to undertake to achieve the required 

 

415 The study authors expressed this overall variability by calculating the absolute relative difference. The 

systemic 4.6 percent underestimate included above is the “signed relative difference”, which is 

generated by adding up all the paired differences, positive or negative (e.g., ‐5+5+1=1) and dividing by 

the number of data pairs – and the average absolute difference, which is calculated by adding the 

absolute value of those differences (e.g. 5+5+1=11), and so measures the total variation between the 

pairs because oppositely‐signed differences do not cancel each other out. Using these methods, while 

the signed relative difference between matched pairs was 4.6 percent, the corresponding absolute 

relative difference was 17.1 percent.

416 Alternatively the source operator may calculate the gross heat rate of the unit, but may still exclude 

ramping and low load operation. 40 C.F.R. Pt. 75, Appendix D 2.1.7
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efficiency improvement and conduct reference method tests before and after implementing 

those measures to document that the required improvement has been attained.417 To aid in 

identifying the most cost-effective hardware upgrades and to minimize gaming by regulated 

entities, detailed reporting of the cost and performance of engineering upgrades should be 

required and made publicly available. Thereafter, CO2 CEMS and enhanced fuel input and 

electrical output monitoring would be employed, along with annual reference method testing, 

to document that the required improvement is being maintained. A Compliance Assurance 

Monitoring (“CAM”) response plan would require an engineering analysis and additional 

measures to be adopted if the source’s compliance margin fell below a set value.

5. EPA Should Strengthen the Record Retention Requirements.

EPA’s proposed rule would require affected sources to retain compliance records on site 

for only two years, after which records could be retained “off-site and electronically.” 79 Fed. 

Reg. at 34,955 (proposed 40 C.F.R. § 60.5805(b)(1)). The effect of this seemingly innocuous 

provision is to reduce the efficacy of onsite inspections and make compliance determinations 

only possible through information requests authorized under section 114 of the CAA and 

analogous state provisions (where they exist). Section 114 information requests by EPA’s 

enforcement office have often been the subject of controversy, as well as attempted 

interference by Congress.418 State and local officials are particularly reliant on onsite 

inspections to ensure regulatory compliance. If they have the authority to conduct documentintensive offsite investigations, they use it only rarely. The prospect of essential information 

being stored at a remote location, which may lie outside the jurisdiction of the state or local 

authority, and in formats that may be difficult to access, presents a significant obstacle to 

enforcement (including citizen enforcement pursuant to section 304 of the Act), especially in 

the current era of shrinking EPA and state agency enforcement budgets.419 Moreover, EPA has 

not identified any particular (or even generalized) basis for its proposal to permit offsite storage 

after two years. Technological advances have reached the point where a year’s worth of data, 

including scanned PDF documents, can be stored on a single flash drive, negating earlier 

arguments about space requirements.

To facilitate the expeditious review of needed information, EPA needs to adopt 

additional requirements covering record retention. For example, under the subpart 98 

reporting program for GHGs, records may be stored off site only “if the records are readily 

available for expeditious inspection and review.” 40 C.F.R. § 98.3(g). In addition, for any records 

 

417 Such tests might be conducted at two or more load points, e.g., 100 percent and 80 percent. 

418 EPA’s Office of Air and Radiation has also demonstrated a reluctance to apply to the Office of

Management and Budget for permission under the Paperwork Reduction Act to employ section 114

requests to obtain information needed for rulemaking development.

419 EPA’s Fiscal Year (FY) 2014–2018 Strategic Plan announced significant and troubling cuts to the

agency’s enforcement program, including reductions in in-person inspections and civil cases. See EPA,

Fiscal Year 2014–2018 EPA Strategic Plan (Apr. 10, 2014) at 73, available at 

http://www2.epa.gov/sites/production/files/2014-09/documents/epa_strategic_plan_fy14-18.pdf.
152

stored electronically, “the equipment or software necessary to read the records shall be made 

available, or, if requested by EPA, electronic records shall be converted to paper documents.” 

Id. To properly implement the CAA’s citizen suit provisions, EPA must clarify that “readily 

available” means available on demand, not just to EPA, but to state and local authorities, 

irrespective of jurisdiction over the site where the records are stored, and to the general public. 

See 42 U.S.C. § 7410(a)(2)(F)(requiring states to correlate emissions monitoring reports “with 

any emission limitations or standards established pursuant to this chapter, which reports shall 

be available at reasonable times for public inspection”) (emphasis added). Because these 

requirements apply to CO2 emissions data from power plants under the GHG reporting 

program, extending their application to the Clean Power Plan will ensure consistent 

requirements and will impose little, if any, additional burden. See id. § 98.47.

6. EPA Should Confirm What Actions It Must and Will Take if a State Plan or Portion 

Thereof Is Not Submitted or Cannot Be Approved.

EPA has proposed that in the absence of an approvable state plan, the agency will 

develop a federal plan “according to [40 C.F.R. § 60.27.]” 79 Fed. Reg. at 34,951 (proposed 40 

C.F.R. § 60.5720). Although the proposed rule therefore appears to apply the deadlines for a 

federal plan codified in section 60.27, EPA should clarify in the final rule that is the case. Section 

60.27(d) provides that EPA must promulgate a federal plan “within six months after the date 

required for submission of a plan or plan revision” if the agency determines that a state has 

failed to submit a plan or plan revision, or if it disapproves any portion of a state plan or 

revision. Because the proposed rule only supersedes the requirements of subpart B of 40 C.F.R. 

Part 60 to the extent they are inconsistent with the proposed rule, see 79 Fed. Reg. at 34,951 

(proposed 40 C.F.R. § 60.5700), the federal plan deadline in 40 C.F.R. § 60.27(d) appears to 

govern any federal plan needed under the CPP. This six-month deadline also appears to provide 

the timetable for state action to correct any plans that EPA has disapproved, in whole or in part. 

EPA should clarify that the deadline also governs state action to amend any plans determined 

by EPA to be inadequate subsequent to their initial approval by the agency.

7. Criteria for Approving State Plans/Required Elements of Plans

State plans must include a showing that the state will have adequate resources and 

authority to implement and enforce the plan. EPA has proposed that state plans must include 

“[m]aterials demonstrating the state’s legal authority to carry out each component of its plan,” 

but has not expressly included a requirement that states also have adequate resources to 

implement and enforce the plan’s requirements. 79 Fed. Reg. at 34,952 (proposed 40 C.F.R. § 

60.5740(a)(11)(i) For example, EPA’s Part 51 regulations require that state implementation 

plans must include

a description of the resources available to the State and local agencies at the 

date of submission of the plan and of any additional resources needed to carry 

out the plan during the 5-year period following its submission. The description 
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must include projections of the extent to which resources will be acquired at 1-, 

3-, and 5-year intervals.

40 C.F.R. § 51.280; see also 42 U.S.C. § 7410(a)(2)(E). A similar demonstration should be 

required for plans under the CPP. Id. Merely having the legal authority to implement and 

enforce plan provisions is not sufficient if the state lacks the resources (or will not commit 

adequate resources) to carrying out the plan.

8. EPA Should Reject the Option of Granting Conditional Approval of State Plans.

EPA seeks comment on using the Clean Air Act’s conditional approval mechanism, 42 

U.S.C. § 7410(k)(4), for state plans. As described in the proposed rule, this would allow EPA to 

approve state plans that fail to meet all requirements, so long as the state commits to curing 

the deficiencies within one year. See 79 Fed. Reg. at 34,916-17. Because EPA is proposing to 

require states to submit their initial plans in June 2016, there should be no need to apply the 

Act’s conditional approval process to the state plans proposed to meet the Clean Power Plan’s 

emission goals. EPA will have an opportunity to review the state’s initial plan to identify issues 

that may foreclose approval if adopted into the plan. Making conditional approvals available 

would only reward states that fail to submit plans meeting all requirements by the applicable

deadline. Moreover, the extended one-year timeframe for states to correct their conditionally 

approved plans would conflict with the six months EPA’s current regulations provide for states 

to address the presumably more wide-ranging plan deficiencies that result in disapproval of the 

plan by EPA. 

9. EPA Must Amend Its Proposed Regulations to Ensure That Emissions Standards Are 

Enforceable by Citizens.

EPA has proposed a regulation which would mandate that each state plan include 

emissions standards that satisfy certain criteria, including the requirement that emission 

standards must be “enforceable with respect to each affected entity.” Proposed 40 C.F.R. § 

60.5780(a). The proposed regulation provides that an emission standard is “enforceable against 

an affected entity if,” among other things, “[t]he Administrator and the state maintain the 

ability to enforce violations and secure appropriate corrective actions pursuant to sections 

113(a) through (h) of the Act.” Id. § 60.5780(f). The proposed regulation omits any requirement 

that the emission standards are enforceable by citizens. The Clean Air Act provides that citizens 

may sue for violation of “an emission standard or limitation under this chapter,” 42 U.S.C. § 

7604(a), and defines “[e]mission standard or limitation under this chapter” to include “any 

requirement under section [111] or [112] of this title,” id. § 7604(f)(3). However, if the state 

plans establish emission standards without ensuring that citizens have the ability to enforce 

violations and secure appropriate corrective actions pursuant to section 304 of the Act, citizens 

may not be able to enforce those standards as a practical matter. EPA must cure this omission.

Correcting the proposed regulations by including a requirement that emission 

standards be enforceable by citizens would also be consistent with longstanding EPA practice, 
154

as reflected in the existing enforcement guidance which the proposed rule describes as 

“serv[ing] as the foundation for the types of emission limits that the EPA has found can be 

enforced as a practical matter.” 79 Fed. Reg. at 34,909. Specifically, the guidance provides that 

emission reductions that create obligations for sources are considered enforceable if, among 

other things, “[c]itizens have access to all the emissions-related information obtained from the 

source [and] can file suits against the source for violations.”420 Similarly, reductions achieved 

through energy efficiency or renewable energy actions for which a party other than a source 

bears responsibility are considered enforceable if, among other things, “[c]itizens have access 

to all the required activity information from the responsible party [and] can file suits against the 

responsible party for violations.”421

VII. Environmental Justice

Minority and low-income communities bear a disproportionate risk from climate 

change. The IPCC’s Fifth Assessment Report concludes that climate disruption will hit lowincome neighborhoods and people of color the hardest. According to the IPCC, “[m]any key 

risks constitute particular challenges for the least developed countries and vulnerable 

communities, given their limited ability to cope.”422 These risks are both health-related and 

socio-economic. In the United States, minority and low income communities often live near 

dirty power plants and other industrial facilities. For example, 60 percent of African Americans 

and Latinos nationwide reside in communities with toxic waste sites. These communities are 

also more likely to live near busy highways, all of which leads to higher risk of air pollutionbased illnesses.423 Researchers have found that African-Americans and Latinos are also more 

likely to reside in areas vulnerable to climate change impacts such as sea-level rise, flood risk, 

and wildfire risk, and that median household incomes are inversely related to these 

vulnerability risks.424 As climate change worsens, minority and low income communities will 

also bear the burden of spending higher proportions of their income as a result of rising food 

prices or increased water scarcity.425

The Clean Power Plan has a great potential to reduce carbon emissions. Carbon 

pollution standards aimed at reducing CO2 emissions from existing power plants can also 

 

420 EPA, Guidance on State Implementation Plan (SIP) Credits for Emission Reductions from Electric-Sector 

Energy Efficiency or Renewable Energy Measures (Aug. 2004), available at 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf, at 6.

421 Id.; see also 79 Fed. Reg. at 34,909 n. 283 (citing this guidance).

422 IPCC, Climate Change 2014: Impacts, Adaptation, and Vulnerability: Summary for Policymakers

(2014), at 13.

423 Truong, V., Addressing Poverty and Pollution: California’s SB 535 Greenhouse Gas Reduction Fund, 49 

Harvard Civil Rights-Civil Liberties L. Rev. 493, 498 (2014), attached as Ex. 46.

424 English et al., Racial and Income Disparities in Relation to a Proposed Climate Change Vulnerability 

Screening Method for California, The International Journal of Climate Change: Impacts and Responses, 

Vol. 4, Issue 2 (Apr. 2013), attached as Ex. 47, at 1-18.

425 Truong, V., Addressing Poverty and Pollution: California’s SB 535 Greenhouse Gas Reduction Fund, 

supra n. 423. 
155

reduce emissions of criteria and hazardous air pollutants, including sulfur dioxide (SO2), 

nitrogen oxides (“NOx”), particulate matter (“PM”), and mercury (“Hg”). SO2 causes the 

formation of fine particle pollution (“PM2.5”) and NOx is an ozone (“O3”) precursor. These copollutants contribute to increased risk of premature death, heart attacks, increased incidence 

and severity of asthma, and other health effects. They also contribute to acid rain, overfertilization of ecosystems, ozone damage to trees and crops, and the accumulation of Hg in 

fish. Policies intended to address climate change by reducing CO2 emissions that also decrease 

emissions of SO2, NOx, and PM2.5, can have significant co-benefits.426

In order to ensure that the most vulnerable communities receive the benefits from a 

comprehensive policy to reduce carbon emissions and address climate change impacts, the 

Clean Power Plan must also address the environmental justice aspect of the equation. It is 

critical for EPA to adopt a holistic approach that recognizes multiple dimensions, including copollutant implications and local communities’ growth. Thus, care must be taken to ensure that 

environmental justice communities do not experience increased levels of pollution as a result of 

the implementation of measures that increase the utilization of certain affected sources. 

Likewise, these communities can, and must benefit from the positive environmental and health 

effects that will result from the decreased utilization of dirty power plants and the 

development of renewable energy generation. 

As we describe below, in order to properly integrate environmental justice concerns 

into the Clean Power Plan, EPA must prepare an environmental justice analysis of the rule, as 

required under Executive Order (“EO”) 12898. Such an analysis will help to ensure that the 

different compliance measures selected by states under their plans do not cause adverse 

impacts, and actually benefit minority and low income populations. 

Environmental protection is also a civil rights and social justice issue.427 EPA must ensure 

that state agencies that receive federal funding under Title VI of the Civil Rights Act comply with 

their obligation not to discriminate on the basis of race, color, or national origin. Although EPA 

and the federal government have taken great steps to bring environmental justice issues to the 

forefront, minority and low income communities continue to face great environmental and 

 

426 Driscoll et al., Co-Benefits of Carbon Standards, Part 1: Air Pollution Changes Under Different 111d 

Options for Existing Power Plants, Harvard School of Public Health/Syracuse University (May 27, 2014), 

attached as Ex. 48, at 2.

427 Civil rights are just one part of human rights. Every individual has a human right to be treated fairly 

and equally by state and private actors, to enjoy their rights to health, food, equal pay, and decent 

working conditions, among others. Environmental justice should contribute to further these rights. See, 

e.g., Harden, M., Advocates for Environmental Human Rights, The Need for Human Rights Advocacy to 

Overcome Injustice: Lessons from the Environmental Justice and Climate Justice Movement, U.S. Human 

Rights Network (Dec. 5, 2013), available at

http://www.ushrnetwork.org/sites/ushrnetwork.org/files/environment_justice_framing_paper_-

_ushrn.pdf. 
156

socio-economic burdens.428 This year, which marks the 20th anniversary of EO 12898 and the 

40th anniversary of the Civil Rights Act, EPA should take concrete actions to address these 

challenges in the Clean Power Plan. 

EPA also needs to make clear that emission standards that would allow uncontrolled or 

poorly controlled emissions from individual sources are not permissible as Section 111(d) 

emission guidelines for pollutants with localized health and environmental impacts. Finally, for 

states that opt to comply with the Clean Power Plan through trading of renewable energy 

credits or CO2 allowances, EPA must establish guidelines for states to effectively integrate 

environmental justice concerns into the design of these programs in a manner that restricts 

trading practices that could exacerbate hotspots and that provides for investments in clean 

energy and the revitalization of these communities. 

A. EPA is Required to Perform an Environmental Justice Analysis of the Clean Power Plan 

Pursuant to Executive Order 12898.

Executive Order (“EO”) 12898, Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations, provides that “[t]o the greatest extent 

practicable and permitted by law ... each Federal agency shall make achieving environmental 

justice part of its mission by identifying and addressing, as appropriate, disproportionately high 

and adverse human health or environmental effects of its programs, policies, and activities on 

minority populations and low-income populations in the United States.” Exec. Order No. 12898, 

§ 1-101. In addition, under the Order, all federal agencies, including EPA, “shall collect, 

maintain, and analyze information assessing and comparing environmental and human health 

risks borne by populations identified by race, national origin, or income ... [and] shall use this 

information to determine whether their programs, policies, and activities have 

disproportionately high and adverse human health or environmental effects on minority 

populations and low-income populations.” Id. § 3-302(a).429

The language of §§ 1-101 and 3-302 indicates that EPA is required to perform an 

analysis to identify and address adverse impacts on minority and low-income populations from 

the Clean Power Plan, “to the greatest extent practicable and permitted by law.” Id. § 1-101. 

See Coal. for Advancement of Reg'l Transp. v. Fed. Highway Admin., 2014 WL 3882677, at *16 

(6th Cir. Aug. 7, 2014) (recognizing compliance with the “procedural and substantive 

requirements for evaluating environmental justice impacts in Executive Order 12898”) 

(emphasis added); Mid States Coal. for Progress v. Surface Transp. Bd., 345 F.3d 520, 541 (8th 

Cir. 2003) (“[t]he purpose of an environmental justice analysis is to determine whether a 

 

428 See, e.g., Bullard et al., Barbara Jordan-Mickey Leland School of Public Affairs, Texas Southern 

University, Environmental Justice: Milestones and Accomplishments: 1964-2014 (Feb. 2014), available at

http://www3.law.harvard.edu/orgs/els/files/2014/02/Environmental-Justice-Milestones.pdf.

429 Indian tribes are entitled to the same protections discussed in this section. We will address such 

protections in our comments to EPA’s supplemental proposal to the Clean Power Plan regarding carbon 

pollution standards for existing power plants in Indian Country and U.S. territories.
157

project will have a disproportionately adverse effect on minority and low income 

populations.”). 

Further, “incorporating environmental justice into rulemaking” is one of EPA’s focus 

areas under its “Plan EJ 2014,” the agency’s roadmap for integrating environmental justice into 

its programs and policies.430 The EPA’s Action Development Process: Interim Guidance on 

Considering Environmental Justice During the Development of an Action (“ADP Interim Process 

Guide”) and the draft Technical Guidance for Assessing Environmental Justice in Regulatory 

Analysis (“EJ Technical Guidance”), the latter which EPA recently issued for public comment,431

“provide direction on how regulatory actions can be responsive to E.O. 12898 as well as EPA’s 

EJ policies432 and Plan EJ 2014.”433

EPA has not performed the analysis required by Section 1-101 of the Order and the 

agency’s EJ policies.434 The agency only highlights the co-benefits of the Clean Power Plan in 

terms of emissions reductions from criteria and hazardous air pollutants, as detailed in its 

Regulatory Impact Analysis, and then states that, because it “cannot exactly predict how 

emissions from specific EGUs would change as an outcome of the proposed rule due to the 

state-led implementation ... it is not practicable to determine whether there would be 

disproportionately high and adverse human health or environmental effects on minority, low 

income, or indigenous populations from this proposed rule.” 79 Fed. Reg. at 34,950. 

However, EPA does identify two ways in which the proposed guidelines may result in 

increased emissions of criteria or hazardous air pollutants. First, coal-fired EGUs that increase 

their utilization due to the implementation of supply-side efficiency improvements may 

increase their emissions of criteria and hazardous air pollutants. EPA concludes that it “has 

considered the potential for such increases and the environmental justice implications of such 

 

430 EPA, Office of Environmental Justice, Plan EJ 2014 (Sept. 2011), available at

http://www.epa.gov/environmentaljustice/resources/policy/plan-ej-2014/plan-ej-2011-09.pdf, at 4-5.

431 Technical Guidance for Assessing Environmental Justice in Regulatory Analysis, 78 Fed. Reg. 27,235 

(May 9, 2013).

432 EPA’s EJ policies issued pursuant to EO 12898 prior to these guidance documents include: The EPA’s 

Environmental Justice Strategy (1995); Environmental Justice Implementation Plan (1996); 

Environmental Justice: Guidance Under the National Environmental Policy Act (1997); Final Guidance for 

Incorporating Environmental Justice Concerns in EPA’s NEPA Compliance Analyses (1998); Toolkit for 

Assessing Potential Allegations of Environmental Justice (2004); and Memo from Stephen L. Johnson: 

Reaffirming the U.S. EPA’s Commitment to Environmental Justice (2005). See EPA’s Action Development 

Process: Interim Guidance on Considering Environmental Justice During the Development of an Action

(“ADP Interim Process Guide”), OPEI Regulatory Development Series (July 2010), available at

http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-07-

2010.pdf .

433 EPA, Draft Technical Guidance for Assessing Environmental Justice in Regulatory Analysis (“Draft EJ 

Technical Guidance”), Post-Internal Agency Review Draft (Apr. 2013), available at

http://www.regulations.gov/#!docketDetail;D=EPA-HQ-OA-2013-0320, at v.

434 RIA at 7-9 to 7-13.
158

increases,” but does not explain what those environmental justice implications are and how it 

has addressed or mitigated these potential impacts in the proposal. Id. at 34,949. EPA must 

provide a detailed explanation in the final rule. 

Second, natural gas-fired EGUs that increase their utilization due to operation at higher 

capacity factors would operate for more hours in the year, emitting pollutants with localized 

effects. However, EPA notes that because they emit no Hg, natural gas-fired EGUs would not 

increase methylmercury concentrations. In addition, these plants would not cause higher peak 

concentrations of PM2.5, NOx or ozone than is already occurring because peak hourly or daily 

emissions generally would not change, “but increased utilization may make periods of relatively 

high concentrations more frequent.” Id. at 34,950. Citing studies by DOE/NETL that provide that 

natural gas-fired plants have negligible SO2 and particulate matter emissions, and that their 

NOx emissions are ten times lower than a subcritical or supercritical coal-fired boiler, EPA 

concludes that local air quality “is likely to be affected very little.” Id. EPA, however, has not 

adequately explained why re-dispatch will not result in higher emissions of criteria air 

pollutants in the vicinity of gas-fired plants that increase their output.

EPA should prepare an expanded environmental justice analysis of the Clean Power Plan

that adequately supports these conclusions and that identifies any specific disproportionate 

impacts or “EJ concerns” (as defined in the ADP Interim Process Guide). In other words, as the 

agency’s own guidance provides, EPA should assess in detail whether any aspect of the 

proposed rule (most obviously, the increased utilization of fossil fuel-fired EGUs—both of coalfired and natural gas-fired plants) would create new disproportionate impacts or exacerbate 

existing disproportionate impacts on minority or low-income populations, and also, whether 

any aspect of the proposed rule (for example, increased renewable energy generation) would 

“[p]resent opportunities to address existing disproportionate impacts on minority, low income, 

or indigenous populations that are addressable through the action under development.”435 If 

the proposed rule would result in environmental or socio-economic impacts, or would add to 

cumulative impacts to minority and low-income populations that already face environmental 

hazards, EPA should include measures to avoid or mitigate these impacts in the final rule. If, 

after performing the analysis, EPA concludes that no such impacts would result, the agency 

should adequately support the basis of its conclusions.436

 

435 EPA, ADP Interim Process Guide, supra n. 432, at 6.

436EPA’s draft EJ Technical Guidance provides that EPA’s regulatory analyses of a policy aimed at 

strengthening an environmental standard have often assumed that there would be no environmental 

justice concerns because the regulation is expected to reduce environmental burdens. This is also the 

case with the proposed Clean Power Plan. In the guidance, EPA recognizes that “this assumption may 

lead to erroneous conclusions,” and thus recommends preparing a basic analysis that supports 

conclusions with regard to potential distributional effects, in order to improve the transparency of the 

rulemaking process and provide the public with more complete information regarding the expected 

effects of the policy. EPA should (at the very least) follow its own guidance in this respect. EPA, Draft EJ 

Technical Guidance, supra at n. 433, at 37.
159

EPA has done comprehensive environmental justice analyses in the context of other 

rulemakings in the past. After finalizing the 2008 Definition of Solid Waste (“DSW”) rule, EPA 

committed to conduct an expanded environmental justice analysis in response to stakeholders’ 

concerns about the rule’s potential impact on communities. The agency developed a sound 

methodology to identify potential hazards to communities from the recycling of hazardous 

secondary materials and the facilities that “may take advantage” of the rule.437 After mapping 

these facilities against the demographics of the surrounding communities, EPA determined that 

certain population groups would be disproportionately affected by the increased risk of adverse 

impacts, and incorporated means to mitigate these impacts, for example, by closely monitoring 

the facilities that notify under the rule.438 EPA should follow its own guidance and draw useful 

lessons from this precedent in preparing an environmental justice analysis of the Clean Power 

Plan. Below we suggest a two-phase process for developing such an analysis.

B. It is “Practicable” to Require States to Conduct an Environmental Justice Analysis as a 

Component of Implementation Plans.

In the proposal, EPA is essentially leaving the decision on how to avoid the creation of 

environmental justice impacts to the states, but without giving them any guidance on how to 

do so. The proposal generally provides that a state can take steps to avoid increased utilization 

of particular EGUs, and thus avoid increased emissions of regulated pollutants with localized 

environmental effects. To the extent that states take this course of action, EPA concluded that 

“there would be no new environmental justice concerns in the areas near such EGUs.” 79 Fed. 

Reg. at 34,949. 

In acknowledging that some NGCCs may not be equipped with NOx emissions controls 

such as selective catalytic reduction, EPA concludes that “[d]epending on the specificity of the 

state CAA section 111(d) plan, the state may be able to predict which EGUs and communities 

may be in this type of situation and to address any concerns about localized NOx 

concentrations in the design of the CAA section 111(d) program, or separately from the CAA 

section 111(d) program but before its implementation.” Id. EPA also contemplates that any 

environmental justice impacts that result from the implementation of the emission guideline 

will be dealt with “ex-post,” i.e. after rule making has been completed, because “existing 

tracking systems” will inform EPA and the states of which EGUs have increased their utilization 

significantly, to enable them to prioritize efforts in assessing changes in air quality in the vicinity 

of such EGUs.” Id. By declining to analyze environmental justice impacts because of uncertainty 

about the content of state plans, EPA is failing to effectively integrate environmental justice 

considerations into this rule making, as required in accordance with EO 12898 and pursuant to 

its own policies and guidelines. 

While EO 12898 is addressed directly to the activities and policies of federal agencies, 

EPA could determine that, in the context of this rule making, it is “practicable” under EO 12898 

 

437 EPA, Plan EJ 2014, supra at n. 430, at 5.

438 Id.
160

to require states to conduct an environmental justice analysis as part of the development of 

their implementation plans. The Clean Power Plan differs from other rules EPA has issued under 

Section 111 insofar as it does not mandate the installation of specific control technologies to 

achieve the required emission reductions; rather, states have flexibility to comply with the 

required state goals through the combination of building blocks that makes the most sense 

depending on their particular circumstances. This is why EPA cannot at this point predict with 

certainty which coal-fired and which natural gas-fired plants will increase or decrease their 

utilization as a result of the implementation of Building Blocks 1 and 2. Therefore, the agency 

should require states to provide this information as part of the submission of their plans. EPA 

could also require owners or operators of affected sources to provide necessary information to 

assist in the development of state plans, as authorized to do so under Section 114 of the Act. 42 

U.S.C. §7414(a)(i)(1). The information will enable it to prepare a full-fledged environmental 

justice analysis as instructed under EO 12898, which the agency should complete before state 

plans’ approval. This requirement would also further EPA’s obligation to collect and analyze 

information on environmental and human health risks borne by populations identified by race, 

national origin, or income, as mandated under Section 3-302(a) of the Order.

An environmental justice analysis should thus be one of the state plan components, and 

effective integration of environmental justice concerns should be one of the approvability 

criteria. To this end, EPA should provide guidance to states on how to prepare this analysis and 

address these concerns in their plans. We suggest the agency to review its own EJ guidance and 

the methodology followed in the draft environmental justice analysis to the DSW rule in order 

to assess what steps of the environmental justice analysis EPA can undertake at this point, and 

what steps and information it should require states to undertake and provide, as exemplified 

below.

C. Methodological Considerations

As noted above, in the draft environmental justice analysis of the DSW rule, EPA 

developed a sound methodology to identify potential hazards to communities from the 

recycling of hazardous secondary materials. EPA could follow this methodology and its own 

guidance to define the parameters of the environmental justice analyses that states should 

prepare as part of their plans, which will inform EPA’s own environmental justice analysis to be 

prepared after plan submission and before approval. The DSW Rule analysis used a 6-step 

approach, aimed at identifying affected areas and enacting targeted requirements to improve 

both oversight and accountability for hazardous materials recycling. The six steps, in summary, 

are the following:439

 Step 1: Hazard characterization

 Step 2: Identification of potentially affected communities

 

439 EPA, Environmental Justice Analysis of the Definition of Solid Waste Rule: Draft for Public Comment

(June 30, 2011), available at http://www.regulations.gov/#!documentDetail;D=EPA-HQ-RCRA-2010-

0742-0004, at ii.
161

 Step 3: Demographics of potentially affected communities

 Step 4: Identification of other factors that affect vulnerability in potentially affected 

communities

 Step 5: Information synthesis: assessment of disproportional impact

 Step 6: Identification of potential preventive and mitigation strategies

EPA, with assistance from the states can and should perform this analysis. We believe 

that, at this point, EPA can readily perform Step 1 of this methodology. As noted above, in the 

proposal EPA briefly describes the potential adverse impacts resulting from the application of 

Building Blocks 1 and 2. These “hazards” should be characterized in greater detail. Using readily 

available tools (as we describe below), EPA could also perform steps 2 and 3 of the above 

methodology to construct its guidance to states, but may require them to provide specific 

information on steps 2 through 4. With the information that states provide in their plans, EPA 

should complete all steps and develop a full-fledged environmental justice analysis. We explain 

this in more detail below.

EPA can generally assess the co-pollutant implications of the generic application of 

Building Blocks 1 and 2 to coal-fired and gas-fired plants that are sited in areas where minority 

and low income communities reside. Utilizing its unit-level data,440 EPA can select plants with 

large nameplate capacity or high capacity factors, or plants in coal- or gas-heavy states, which 

(hypothetically) may apply Building Blocks 1 and 2, and assess their emissions of CO2 and 

criteria air pollutants. EPA should then “map” these facilities against the demographics of the 

surrounding communities, to find out whether these areas have high percentages of minority or 

low income populations in proximity (i.e. within a certain radius) from these plants. By way of 

example, below we provide a list of large (>100 MW) coal-fired plants and their emissions of 

CO2 and other co-pollutants, with a brief analysis of environmental justice-related implications 

that can be made from this data. EPA can obtain information on pollution controls from 

multiple sources, such as EPA NEEDS, which provides information on SO2, NOx, PM, and Hg 

controls, and EIA Form 860, which contains these data in addition to cooling information.

With this information, EPA should determine whether the implementation of Building 

Blocks 1 and/or 2 would result in disproportionate or adverse impacts on these communities. 

EO 12898 does not define the term “disproportionate,” but other agencies’ guidance offers 

some direction. CEQ’s Environmental Justice Guidance under NEPA discusses several factors to 

consider in determining “disproportionately high and adverse human health effects,” including 

whether the health effects are significant or above generally accepted norms; whether the risk 

or rate of hazard exposure by a minority or low income population to an environmental hazard 

is significant and appreciably exceeds or is likely to appreciably exceed the risk or rate to the 

general population or other appropriate comparison group, and whether health effects occur in 

 

440 EPA, Data File: 2012 Unit-Level Data Using the eGRID Methodology, supra n. 166.
162

a minority or low-income population affected by cumulative or multiple adverse exposures to 

environmental hazards.441

The focus on specific pollutants, however, does not account for cumulative effects, i.e., 

“the impact[s] on the environment which result from the incremental impact of [an] action 

when added to other past, present, and reasonably foreseeable future actions regardless of 

what agency (Federal or non-Federal) or person undertakes such other actions. Cumulative 

impacts can result from individually minor but collectively significant actions taking place over a 

period of time.” 40 C.F.R. § 1508.7442 As EPA itself notes, minority and low income populations 

are in many instances affected by multiple environmental hazards, such as industrial facilities, 

landfills, poor housing, leaking underground tanks, pesticides, and incompatible land uses. 

Analyzing the effects from these multiple stressors would allow “a more realistic evaluation of a 

population’s risk to pollutants.”443 EPA should draw on its own Framework for Cumulative Risk 

Assessment and prior cumulative impacts analyses, such as the one prepared in the context of 

the DSW rule. EPA may also rely on its own guidance for the agency’s review of NEPA 

documents. Although focused on the analysis of projects on ecological resources, the agency 

could consider the same principles as applied to socioeconomic and human health issues, 

particularly with respect to the identification of areas cumulatively impacted by a given 

measure, the delineation of geographic and time boundaries, the identification of all relevant 

past activities into the affected environment, the utilization of qualitative and quantitative 

thresholds to determine degradation and cumulative impacts, and the incorporation of 

mitigation measures to avoid or reduce the severity of those impacts.444

EPA has undertaken significant efforts to develop research on cumulative impacts, and 

should draw from this research in assessing the potential cumulative impacts of the proposed 

rule. There are many programs and tools to evaluate different components of risk assessments, 

for example, the Community-Based Technical Support Forum, an EPA workgroup on technical 

issues that supports community-based risk assessments; EPA’s Community Action for a 

Renewed Environment (“CARE”) program, which addresses risk mitigation needs, and the Office 

of Research and Development’s (“ORD”) National Exposure Research Laboratory’s (“NERL”), 

which develops and applies exposure models and tools to conduct cumulative exposure 

assessments, both with respect to health impact and other stressors.445 NERL is also developing 

 

441 Council on Environmental Quality, Environmental Justice: Guidance Under the National Environmental 

Policy Act (Dec. 10, 1997), attached as Ex. 49, at 26.

442 EPA, Office of Fed. Activities, Consideration of Cumulative Impacts In EPA Review of NEPA Documents, 

EPA 315-R-99-002 (May 1999), available at 

http://www.epa.gov/compliance/resources/policies/nepa/cumulative.pdf, at 2. 

443 EPA, ADP Interim Process Guide, supra n. 432, at 8.

444 EPA, Consideration of Cumulative Impacts, supra n. 442, at 5-19.

445 ORD and NERL have also developed models to estimate children’s cumulative exposures to chemicals. 

See Zartarian et al., ORD/NERL’s Model to Estimate Aggregate and Cumulative Exposures to Chemicals: 

SHEDS – Multimedia Version 4 (Jan. 13, 2011), available at 

http://ghhidetroit.cus.wayne.edu/blog/file.axd?file=2011%2F1%2FSHEDS_Presentation_01-13-

2011_clearance.pdf.
163

the Community-Focused Exposure and Risk Screening Tool (“C-FERST”), which will help identify 

environmental issues and prioritize exposure and risk reduction efforts based on EPA’s best 

available information.446 Furthermore, EPA’s Community Cumulative Assessment Tool (“CCAT”), 

currently under development, will use information from C-FERST in order to inform the public 

about the process and complexities of assessing cumulative impacts.447 To the extent EPA needs 

more community-level information to prepare a comprehensive “cumulative effects” analysis, it 

should ask the states to provide it in their own environmental justice analyses in state plans.448

If EPA found environmental justice impacts from the general application of Building 

Blocks 1 and 2 to these plants, the agency should, to the extent practicable, incorporate in the 

final rule a range of additional measures that states can incorporate in their plans to mitigate 

these impacts. These measures could be revised when EPA finalizes its environmental justice 

analysis. For example, EPA could provide that, as part of compliance, states could require 

affected sources to site additional monitors in locations where minorities and low-income 

communities reside to address any risks of increased exposure to air pollutants. State plans 

could also provide for enhanced reporting and record-keeping requirements on these plants.

As for plants that do not have certain types of controls installed (for example, NGCCs 

without selective catalytic reduction controls, as EPA itself notes), states could require 

installation of such controls in plants with high capacity factors that are sited in these 

communities. In planning for retirements or reduced dispatch as part of state plan 

development, states should be instructed to ensure that the co-pollutant benefits of reduced 

operations accrue in environmental justice communities. Implementation plans must also 

contain effective enforcement mechanisms against violators. States would decide on the 

specific measures to incorporate in their actual plans, but they must ensure that these 

requirements effectively address environmental justice concerns in order for EPA to approve 

them. The environmental justice analysis of the DSW rule provides useful lessons on how EPA 

has effectively integrated environmental justice considerations in rule making.

In the proposed DSW rule, for example, EPA acknowledged that the destination of the 

waste generated from the rule was not random; rather, some communities would be more 

affected than others. The rule’s implementation would have resulted in a concentration of 

hazardous waste recycling facilities near low income communities and communities of color, 

increasing adverse public health conditions to these vulnerable communities. EPA’s 2010 re-

 

446 Zartarian et al., The EPA’s Human Exposure Research Program for Assessing Cumulative Risk in 

Communities, J, of Exposure Sci. and Envtl. Epidemiology (Apr. 15, 2009), attached as Ex. 50, at 352-355.

447 EPA, Plan EJ 2014, Progress Report (Feb. 2014), available at

http://www.epa.gov/environmentaljustice/resources/policy/plan-ej-2014/plan-ej-progress-report2014.pdf, at 23.

448 In a separate rulemaking, EPA should issue a cumulative impacts standard that fully recognizes the 

existence of these effects on minority and low income communities, providing guidance to states, or any 

other obligated entity under its rules, to identify and address cumulative impacts in all their programs, 

policies, and activities.
164

examination of the 2008 DSW rule identified areas in the existing regulations that could be 

improved to better protect these communities by ensuring better management of hazardous 

waste, since the 2008 rule had scaled back federal oversight of management of the waste. EPA 

effectively integrated environmental justice concerns in the regulations in various ways in the 

new proposed DSW rule. For example, the 2010 proposal required heightened storage and 

record keeping requirements compared to the 2008 proposal. Companies that sent their 

hazardous materials offsite for recycling would have to abide by tailored storage standards, and 

would be required to send their materials to a permitted hazardous waste recycling facility. The 

rule also required all forms of hazardous waste recycling to meet requirements designed to 

ensure materials are legitimately recycled and not being disposed of illegally. EPA established 

these requirements by assessing multiple scenarios in order to try to reflect how different types 

of hazardous waste would be managed, based on its interim guidance on how to incorporate 

environmental justice, and making sure there was opportunity for public involvement. 

The ADP Interim Process Guide provides that an environmental justice analysis includes 

not only the consideration of burdens to minorities and low-income populations, but also the 

distribution of the positive environmental and health consequences of the agency’s actions.449

EPA has already quantified the co-benefits of the Clean Power Plan in terms of emissions 

reductions from criteria and hazardous air pollutants, but has also acknowledged that its 

benefit-per-ton estimates “may not reflect the local variability in population density, 

meteorology, exposure, baseline health incidence rates, or other local factors for any specific 

location.450 Independent research has confirmed that carbon pollution standards on existing 

power plants that incorporate flexible compliance options (including, for example, demand-side 

energy efficiency) can result in great co-benefits in terms avoided premature deaths, hospital 

admissions, and heart attacks. This research has assessed the geographic distribution of those 

co-benefits, with all lower 48 states receiving some benefit.451 EPA should assess the 

geographic distribution of the co-benefits of the rule, and when feasible, information on these 

benefits should be disaggregated by race, ethnicity, and income,452 in order for EPA to assess 

the distribution of benefits of the proposed rule on minority and low income populations.

In assessing all the potential impacts and benefits, EPA could provide a qualitative 

assessment as part of its guidance in the final rule, and require states to provide a quantitative 

assessment of these impacts in connection with the compliance measures included in their 

plans. As EPA details in its draft EJ Technical Guidance, a quantitative assessment would allow 

EPA to more rigorously assess the manner in which emissions and health effects will be 

distributed among minority and low income groups during implementation.453 Such an 

 

449 EPA, ADP Interim Process Guide, supra n. 432, at 3. 

450 RIA at ES-16.

451 Schwartz et al., Health Co-Benefits of Carbon Standards for Existing Power Plants, Part 2 of the CoBenefits of Carbon Standards Study, Harvard School of Public Health/Syracuse University/Boston 

University (Sept. 30, 2014), attached as Ex. 51, at 3.

452 Draft EJ Technical Guidance, supra n. 433 at 3.

453 Id. at 37.
165

assessment is feasible if each state provides specific environmental justice-related information 

associated to its selected compliance pathway. 

1. Sample Environmental Justice Analysis of Coal Plants

In 2012, the National Association for the Advancement of Colored People (“NAACP”), in 

conjunction with the Little Village Environmental Justice Organization and the Indigenous 

Environmental Network, analyzed criteria air pollutant emissions from coal-fired plants in 

conjunction with demographic factors, concluding that a number of coal plants in the United 

States had “a disproportionately large and destructive effect on the public’s health, especially 

on the health of low-income people and people of color,”454 who are more likely to be 

disproportionately affected by climate change. NAACP’s “Coal Blooded” report gave each 

individual plant a score based on five different factors, including SO2 emissions, NOx emissions,

the total population living within 3 miles of the plant, the median income, and the percentage 

of people of color among the total population living within 3 miles of the plant.455 NAACP’s 

“Environmental Justice Performance” (“EJP”) score was calculated based on the data collected, 

using both an exposure score and a demographic score multiplied to obtain a cumulative score.

In assembling the list of coal-fired power plants used in the study, NAACP used EIA’s 

2008 “Existing Electric Generating Units in the United States” database and filtered it out to 

obtain 601 coal-fired (or partially coal-fired) power plants. Using only plants that have a 

capacity greater than 100 MW (as well as leaving out plants that had, as of July 1, 2011, been 

fully decommissioned, had converted to other fuel stocks, or were fully non-operational from 

2007 to 2010), NAACP obtained a list of 378 coal-fired power plants for analysis.456

Demographic data was based on the 2000 census report.

In this analysis, NAACP found that 6 million Americans living near coal plants had an 

average income of $18,400, in comparison to the $21,857 average income nationwide, and of 

those 6 million Americans, 39 percent were people of color.457 While the 75 plants that 

received a grade of “F” only produced 8 percent of the total electricity, they accounted for 14 

percent of overall SO2 emissions and 13 percent of NOx emissions.458 The average per capita 

income of the people living within 3 miles of these 75 plants (roughly 4 million people) was 

$17,500, and nearly 53 percent were people of color.459

 

454 NAACP, Coal Blooded: Putting Profits Before People (Nov. 2012), attached as Ex. 52, at 9.

455 Id. at 33.

456 Id. at 86.

457 Id. at 15.

458 Id. at 27.

459 Id.
166

Sierra Club has expanded this analysis, incorporating the data from NAACP’s Coal 

Blooded report and analyzing emissions from a list of 384460 coal-fired power plants. Using the 

data from the NAACP’s report as a starting point, we have then included generation data from 

EIA and emissions data from EPA for both years 2012 and 2013, as well as CO2 emissions for all 

years under analysis. Demographics information in this sample still corresponds to the 2000 

census, rather than the newer 2010 census data. Since the 2000 census, population has 

increased approximately 27.3 million.461 Over the last decade, however, there has been a 

slower increase in population growth (approximately 3.5 percent), with much of that increase 

coming from the South and Western regions.462 Emissions information in this sample does 

correspond to the most recent data from EIA. While demographic data is not the most recent, 

we hope this example provides EPA with a methodology of the initial steps of an environmental 

justice analysis (i.e. identification of hazards, mapped against demographic information). EPA 

should perform this analysis both for coal-fired and gas-fired plants. As we discuss below, EPA 

can draw demographic data from a variety of tools. 

A partial version of our analysis (depicting only 2013 emissions) is shown below. The full 

analysis is attached as Appendix 5. The figure below shows 50 plants in our study with the 

lowest per capita average income within three miles of the plant.

 

460 The NAACP report lists 378 plants in its analysis. However, some of these plants are actually two 

separate plants as identified in EIA, so we have broken out these groupings in this dataset for more 

clarity.

461 Id. at 1.

462 U.S. Census Bureau, Population Distribution and Change: 2000 to 2010, 2010 Census Briefs (March 

2011), available at http://www.census.gov/prod/cen2010/briefs/c2010br-01.pdf, at 1.
167

 

463 The data in this table derive from AMPD data, NAACP’s Coal-Blooded report, supra n. 454, and Sierra 

Club’s internal analysis.

Table 15- SO2, NOx, and CO2 Emissions, and Demographics of Large Coal-Fired Plants in the 

U.S.463

State

Plant 

Name

2013 

SO2

Emissi

ons 

(tons)

2013 

NOx

Emissi

ons 

(tons)

2013 CO2

Emissions 

(metric 

tons)

Pop. 

Within

3 Miles

3-

Mile 

Avg. 

Inco

me

% of 

State 

Avg. 

Incom

e

3-Mile 

POC 

Pop.

Overa

ll 

Rank Grade

NM Escalante 951 3036 1,631,803 372 6701 38.8% 90.2% 18 F

NM Four 

Corners 10706 35434 11,704,484

488 6762 39.2% 94.9% 11 F

TX Harrington 14309 4890 5,949,094 4724 9134 46.6% 46.3% 39 F

TN Allen 9992 1937 4,295,754 2589 9412 48.5% 99.2% 16 F

SC Williams 909 1485 2,786,621 4496 9653 51.4% 32.6% 60 F

AZ

H Wilson 

Sundt 

Generatin

g Station

1372 1272 588,943 56609 1025

8

50.6% 74.7% 13 F

SC Cross 6687 4513 12,349,14

8

1068 1062

6

56.5% 76.3% 29 F

OH Lake Shore 1058 308 261,789 103333 1086

6

51.7% 90.6% 6 F

IL Crawford 0 0 0 373690 1109

7

48.0% 83.9% 1 F

LA Rodemach

er

11320 4622 7,628,231 1237 1115

4

66.0% 66.7% 58 F

NC

Edgecomb

e Genco

LLC

100 873 326,003 4370 1173

5

57.8% 67.2% 31 F

NC

W H 

Weathersp

oon

5 13 1,609 10450 1186

7

58.4% 50.3% 40 F

NM San Juan 6055 16817 11,301,56

7

937 1198

2

69.4% 74.9% 45 F

SC Canadys 

Steam 7789 1279 733,737 943 12127

64.5% 45.2% 91 DSC Wateree 5548 1472 2,791,544 367 1242

2

66.1% 82.8% 38 F

AZ Coronado 843 9952 6,431,282 313 1247

0

61.5% 33.4% 117 D

PA

Colver 

Power 

Project

2756 887 0 1980 1252

3

60.0% 2.1% 187 C

SC Urquhart 5 201 564,793 7464 1262

3

67.2% 77.2% 30 F

OH Killen 

Station 7885 6401 3,471,845 441 12788

60.9% 2.9% 216 C+
168

WI Valley 3468 1041 870,418 209421 1285 260.4% 66.0%4F

IN R 

Gallagher 2495 1200 620,541 60333 1286 8

63.1% 60.8%8F

VA Clover 2262 8417 5,859,241 837 1291 653.9% 48.4% 76D-

KY Green 

River 19998 2272 977,874 2462 1292 1

71.4% 9.8% 179C

CO Pawnee 12467 3740 3,296,108 1200 1296 453.9% 25.9% 101D

MD

AES 

Warrior 

Run 

Cogenerati

on Facility

1236 560 1,474,035 10914 1298 250.7% 10.7% 89D-

MI River 

Rouge 9214 3008 2,182,711 68262 1303 7

58.8% 65.3%7F

OH J M Stuart 11542 8674 12,564,88 23781 1309 462.3% 13.7% 80D-

AZ Cholla 5065 8649 7,478,704 1076 1309 664.6% 27.3% 120D

FL

Indiantow

n 

Cogenerati

on LP

1264 1124 732,998 3403 1310 760.8% 68.2% 34F

AZ Springervil

le 7939 7304 10,802,01 8

142 1325 565.4% 31.0% 146 D+

IL

Baldwin 

Energy 

Complex

4803 4960 12,162,72 24121 1341 958.1% 51.7% 44F

KY Paradise 21524 7739 12,008,05 5593 1342 774.2% 6.6% 214 C+

VA Clinch 

River 3994 1020 927,182 1271 1347 2

56.2% 1.8% 172C-

OK Sooner 14380 8222 5,812,930 130 1355 576.8% 44.8% 139 D+

AL Gadsden 1526 414 192,348 24955 1360 074.8% 49.9% 37F

OK AES Shady 

Point LLC 2422 1363 6

77.3% 19.0% 141 D+

MS

Red Hills 

Generatin

g Facility

3159 2019 3,586,888 830 1366 586.2% 26.1% 233 INC

CO Cherokee 2584 5172 3,019,206 61559 1368 256.9% 64.4%9F

LA Dolet Hills 14612 3167 3,350,443 412 1376 781.4% 50.3% 124D

PA Conemaug h6408 18171 10,511,27 82729 1380 066.1% 1.3% 165C-

AL Greene 

County 32833 4878 2,470,243 480 1382 1

76.0% 78.8% 59F
169

In analyzing the data, one can make the following conclusions: First, 197 of the 384 coal 

plants identified in the NAACP report fall under the low income threshold of $17,505 per capita, 

as defined by the U.S. Department of Education.464 From these 197 plants, an average of 51.6 

percent of the people (then) living within 3 miles of the individual plants are people of color. 

The average per capita income of the people living within 3 miles of these 197 plants 

(approximately 2.94 million people) was $14,532.84, compared to an average of $22,158.91 per 

capita income of the people living within 3 miles of the other 187 plants (approximately 3 

million people). Out of all of the 197 plants that fall below the low income threshold, the five 

plants with the lowest per capita income within the 3-miles area around the individual plants 

include Plants Escalante and Four Corners in New Mexico, Plant Harrington in Texas, Allen Plant 

in Tennessee, and Plant Williams in South Carolina, all of which were surrounded by 

communities with income of less than $10,000 per capita. 

Across the board, these 197 plants produced more CO2, SO2, and NOx emissions overall 

in both 2012 and 2013 compared to the 187 other plants in the study that are above the low 

income threshold. Specifically, these plants produced on average 33 percent more NOx 

emissions, 21 percent more SO2 emissions, and 11 percent more CO2 emissions than the other 

187 plants in 2013, and 24 percent more NOx emissions, 11 percent more SO2 emissions, and 9 

percent more CO2 emissions in 2012. This means that these 197 plants we identified as under 

the low income threshold would be causing adverse impacts in low income communities in 

comparison with the rest of the plants identified in the study.

The graphs below show that, based on all of the 384 plants in the study, as average 

income increases, emissions (of NOx and CO2, respectively) decrease, as seen from the negative 

slope of the best fit lines. Conversely, emissions are higher in lower income areas. 

 

464 U.S. Dep’t of Education, Federal TRIO Programs Current-Year Low-Income Levels, 

http://www2.ed.gov/about/offices/list/ope/trio/incomelevels.html (last visited Nov. 24, 2014).

UT Huntingto

n

2409 7482 6,220,976 249 1385

5

76.2% 12.5% 253 INC

NE North 

Omaha 12237 6258 3,592,614 43133 13858

70.7% 56.7% 17 F

OK Hugo 10878 3348 3,360,726 712 1398

0

79.2% 17.7% 229 INC

OR Boardman 13967 4038 3,601,219 233 1398

2

66.8% 48.6% 99 DTX Oklaunion 3809 7266 4,099,987 193 1400

4

71.4% 32.8% 155 CUT Utah 

Smelter 752 14013

77.1% 22.8% 195 C

OK Chouteau 2277 1402

6

79.5% 26.2% 128 D+
170

Fig. 27- 2013 NOx Emissions (tons) vs. Average Income

Fig. 28- 2013 CO2 Emissions (metric tons) vs. Average Income

In addition, the average capacity factor for the 197 plants that fall below the low income 

threshold is higher overall for both years 2012 and 2013 than the other 187 plants in the study. 

Of the plants in the study, the average capacity factor in 2012 was 42 percent, and in 2013 it 

y = -0.1696x + 7378

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 10000 20000 30000 40000 50000

NOx Emissions (tons)

Average Income

2013 NOx Emissions (tons) Linear (2013 NOx Emissions (tons))

y = -67.378x + 5E+06

0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

0 10000 20000 30000 40000 50000

CO2 Emissions (metric tons)

Average Income

2013 CO2 Emissions (metric tons) Linear (2013 CO2 Emissions (metric tons))
171

was 39 percent.465 The graphs below show that, for all of the 384 plants in the study, the 

capacity factor decreases as the average income increases. This lower capacity factor correlates 

to less operation, and thus less pollution in the areas that have a higher average income. On the 

other hand, areas that have a lower average income see, on average, a higher capacity factor, 

indicating that those plants are being run more frequently, and thus polluting more. 

Fig. 29- 2013 Capacity Factor vs. Average Income

 

465 The 2013 capacity factor might change slightly since not all generation data has been reported yet.

y = -6E-06x + 0.5001

-10%

0%

10%

20%

30%

40%

50%

60%

70%

80%

0 10000 20000 30000 40000 50000

2013 Capacity Factor

Average Income
172

Fig. 30- 2012 Capacity Factor vs. Average Income

Obtaining emissions information and mapping them against demographic criteria is a 

good first step to identify highly polluting plants and potential adverse burdens placed on 

minorities and low income communities. This type of finding would aid EPA and the states in 

deciding how to properly integrate environmental justice considerations in this rule making, 

incorporating targeted measures so that emissions reductions actually occur in environmental 

justice communities. 

2. Data Gathering: Available Tools

In commencing an environmental justice analysis, EPA could utilize a variety of readily 

available tools to collect environmental and demographic information. Below we highlight 

some of these tools, along with their strengths and weaknesses. 

a. EJView

One tool that could aid EPA in determining which communities would be 

disproportionately impacted by the Clean Power Plan is EPA’s own mapping tool “EJView” 

(formerly known as the Environmental Justice Geographic Assessment Tool). The tool allows 

users to create maps and generate detailed reports based on the geographic areas and data 

sets they choose. The EJView homepage describes multiple factors that have the potential to 

affect the selected communities, including demographics, health, environmental, and facilitylevel data (such as air emissions data from The Air Facility System and water discharges tracked 

y = -8E-06x + 0.5623

-20.00%

0.00%

20.00%

40.00%

60.00%

80.00%

100.00%

0 10000 20000 30000 40000 50000

2012 Capacity Factor

Average Income

2012 Capacity Factor vs. Average Income
173

through EPA’s permit compliance system).466 This tool would be particularly useful to gather 

information on cumulative impacts. In order to generate a cumulative health impacts 

assessment of the Clean Power Plan, for example, EPA can obtain data from the tool by 

selecting the specific map contents and generating a detailed depiction of individual 

communities. The tool incorporates the following data: Hazardous Waste (“RCRAInfo”), Toxics 

Release Inventory (“TRI”), Superfund (“CERCLIS”), Brownfields (“ACRES”), nonattainment areas, 

demographic data based on the 2010 US Census Population and Housing 100 percent count 

database, health information from the National-Scale Air Toxics Assessment (“NATA”), and 

other monitoring data, thus creating a more aggregated database incorporating multiple 

factors.467

b. EJSEAT

“EJ SEAT”, a tool designed by EPA’s Office of Enforcement and Compliance Assurance, 

assigns scores to every census tract in the country (approximately 65,000 tracts) by using an 

index compiled from 18 indicators which are grouped into 4 different categories 

(environmental indicators, human health/health indicators, compliance indicators, and 

social/demographic indicators).468 EPA uses data available nationwide at the census tract level, 

which must come from federally recognized sources. Environmental indicators derive from 

information from the NATA and the Risk Screening Environmental Indicators (“RSEI”) records, 

and are therefore largely air-focused. The information obtained in the dataset is normalized 

prior to combining the indicators, done by setting the lowest value of the indicator to zero and 

the highest to 100. This process is conducted on a state-by-state basis rather than for the 

United States as a whole. As defined by EPA’s Office of Enforcement and Compliance 

Assurance, the top-scoring 20 percent of the census tracts in each state could be potential 

environmental justice areas that are facing disproportionate impacts. 

Some of the strengths of the tool are that it is a nationally consistent screening tool that 

follows a systematic approach, and it combines a wider range of data than EPA traditionally 

uses for environmental justice analyses.469 We believe that EJ SEAT could be used to identify 

environmental justice communities where targeted emissions reductions under the Clean 

Power Plan will be needed. And, in particular, during compliance, this tool could also be helpful 

to evaluate whether or not the Clean Power Plan has been effective in improving 

environmental justice in those particular areas. For example, the tool can be used to find out 

whether pollution prevention efforts have focused on environmental justice areas, and whether 

sufficient grants have been provided to these communities.

 

466 EPA, EJView, http://epamap14.epa.gov/ejmap/entry.html (last visited Nov. 24, 2014).

467 EPA, EJView, Description of Map Features, http://epamap14.epa.gov/ejmap/help/help.html?tab=3

(last visited Nov. 24, 2014).

468 Schulman & Harris, EPA, EJSEAT: A Screening Tool for EJ Concerns, Strengthening Environmental 

Justice Research and Decision Making Symposium, (Mar. 18, 2010), available at

http://www.epa.gov/ncer/events/calendar/2010/mar17/presentations/andrew_schulman.pdf, at 4-5.

469 Id.
174

While the tool has clear strengths, it also has weaknesses that should be acknowledged, 

so that the agency supplements these gaps with other tools and information from other 

sources. One of the issues with the data collection methods is that the human health category 

is hard to quantify because only a few indicators are “available at the census tract level across 

the nation in a way that is accessible due to privacy issues.”470 In addition, this tool does not 

capture communities smaller than 4,000 people due to census tracts, so that it may not capture 

some tribal communities.471 Finally, in the compliance indicator there is no distinction between 

serious violations significantly impairing air or groundwater, and violations with no material 

environmental impact. In addition, since state enforcement differs from state to state, what 

might be cited as a violation somewhere might be ignored elsewhere.

c. CalEnviro Screen 2.0

The California Communities Environmental Health Screening Tool (“CalEnviroScreen 

2.0”) is a tool used to identify communities that are disproportionately burdened by different 

sources of pollution, and EPA could maximize the use of this tool for an environmental justice 

analysis of the Clean Power Plan in California. The specifics of this tool could also provide useful 

lessons to other states in gathering and assessing the information they would be required to 

submit as part of their plans.

CalEnviroScreen 2.0 measures adverse environmental impacts by using 19 different 

indicators including pollution burden, socioeconomic vulnerabilities, public health risk factors, 

among other indicators, which can be used to assess areas most heavily impacted by pollution. 

The demographic data is derived from roughly 8,000 census tracts (using the 2010 census) 

throughout the state and then assembled into an interactive map.472 The tool compiles all of 

these different indicators when evaluating a particular location, and ranks zip codes statewide 

for comparison. By dividing regions by census tracts rather than just the roughly 1,800 zip codes 

in the state, CalEnviroScreen 2.0 has the ability to provide an impartial accounting of 

circumstances in areas that potentially have a smaller number of residents, thus making it 

possible to obtain a more in-depth analysis. Using these indicators, the tool has the ability to 

take into account socioeconomic characteristics, health statistics, and environmental exposure 

to give a much more precise indication of the environmental risks faced by these vulnerable 

populations. The tool can thus provide guidance to state and local policymakers on where to 

best direct their resources and programs. 

 

470 Nat’l Envt’l Justice Advisory Council (“NEJAC”), Meeting Transcript (Sep’t 19, 2007), available at 

http://www.epa.gov/compliance/ej/resources/publications/nejac/nejacmtg/nejac-meet-trans091907.pdf. 

471 Note, however, that NEJAC’s evaluation of the tool raised doubts that it can ultimately meet the 

needs of both the agency and the broader environmental justice community, so that it is important to 

be aware of its shortcomings. Id.

472 California Envt’l Protection Agency, Designation of Disadvantaged Communities Pursuant to Senate 

Bill 535 (Oct. 2014), attached as Ex. 53, at 13.
175

CalEnviroScreen 2.0, unlike EJSEAT, is available to the public, whereas EJSEAT is limited 

to internal use by the EPA. CalEnviroScreen 2.0’s guidance document notes that the tool should 

mostly be used in planning for compliance and use by local and regional governments.473

Furthermore, the tool will be used to help implement SB 535 which, as we explain below, would 

distribute funds generated by California’s AB32 allowance auctions, allocating 25 percent of the 

available funds to projects that provide benefits to disadvantaged communities, with no less 

than 10 percent of the proceeds being used to directly benefit disadvantaged communities.474

Because the tool helps to prioritize abatement projects and resources for clean-up, the 

California Environmental Protection Agency (“CalEPA”) additionally plans to use the resource to 

aid in administering its Environmental Justice Small Grant Program.475

d. EJ Screen

EJScreen, a screening and mapping tool used by EPA, will be available to the public in 

late 2014. EJScreen compiles “EJ indexes” using demographic information (at the census tract 

level and group block level) and environmental indicators in order to identify specific 

communities that may be disproportionately burdened by a given environmental harm.476

There are 12 different environmental indicators and seven demographic indicators.477 Like 

EJSEAT, EJScreen will be a nationally consistent environmental justice screening tool. EJScreen 

can be used to identify where specific environmental risks occur in certain communities. A 

report generates all 12 environmental indicators in one area, while a map provides one 

environmental indicator at a time over a wider area. EPA could use this tool to identify 

disproportionately burdened communities using the different environmental indicators.

D. EPA Must Continue to Ensure Meaningful Involvement of Minorities and Low Income 

Communities in this Rule Making.

Executive Order 12898 requires federal agencies to conduct their “programs, policies, 

and activities that substantially affect human health or the environment, in a manner that 

ensures that such programs, policies, and activities do not have the effect of excluding persons 

(including populations) from participation in, denying persons (including populations) the 

benefits of, or subjecting persons (including populations) to discrimination under, such 

programs, policies, and activities, because of their race, color, or national origin.” § 1-101. In 

 

473 California Envt’l Protection Agency, California Communities Environmental Health Screening Tool, 

Version 2.0, Guidance and Screening Tool (Oct. 2014), attached as Ex. 54, at 5.

474 See Cal. Health & Safety Code §§ 39710-39723 (codifying SB-535 California Global Warming Solutions 

Act of 2006: Greenhouse Gas Reduction Fund).

475 California Envt’l Protection Agency, supra n. 473, at 5.

476 EPA, EJSCREEN Fact Sheet, available at 

http://icma.org/en/icma/knowledge_network/documents/kn/Document/306760/EPA_EJSCREEN_Fact_

Sheet, at 1.

477 EPA, EJSCREEN: Environmental Justice Screening Tool, available at 

http://www.epa.gov/air/caaac/pdfs/ejscreen_102914.pdf, at 12. 
176

addition, the Order seeks to promote public participation by requiring federal agencies to 

“ensure that public documents, notices, and hearings relating to human health or the 

environment are concise, understandable, and readily accessible to the public,” and 

encouraging them to “translate crucial public documents, notices, and hearings relating to 

human health or the environment for limited English speaking populations.” § 5-5.

In furtherance of these requirements, EPA’s guidance provides that minority and low 

income communities must have an adequate opportunity to participate in decisions about a 

proposed activity that will affect their health or their environment, and their concerns must be 

considered in the agency’s decision-making process.478 The inability of these communities to 

participate in this process constitutes an “EJ concern” that may itself contribute to 

disproportionate impacts. To avoid such impacts, EPA must engage these communities early in 

the process through targeted outreach efforts, in a manner that overcomes any lack of trust, as 

well as any language, communication, and information barriers.479

In the context of this rule making, EPA has hosted webinars, conference calls, and 

workshops for environmental justice communities on August 27, September 9, and October 30, 

2014. EPA indicates that it “has taken all comments and suggestions [from these communities] 

into consideration in the design of the emission guidelines.” 79 Fed. Reg. at 34,950. We ask EPA 

to describe in the final rule what these (and any other suggestions submitted during the 

comment period) are and how they have been addressed. We also commend EPA for arranging 

these targeted sessions, and urge the agency to continue to provide these communities with 

opportunities for meaningful involvement in the rule making process, and to actively seek their 

input in the development of a comprehensive environmental justice analysis of the Clean 

Power Plan. 

E. State Plans Must Ensure Compliance with Title VI of the Civil Rights Act.

Title VI of the Civil Rights Act (“Title VI”), Section 601, provides that “[n]o person in the 

United States shall, on the ground of race, color, or national origin, be excluded from 

participation in, be denied the benefits of, or be subjected to discrimination under any program 

or activity receiving Federal financial assistance.” 42 U.S.C. § 2000d. Title VI “reaches 

unintentional, disparate-impact discrimination as well as deliberate racial discrimination.” 

Guardians Ass’n v. Civil Service Com’n of City of New York, 103 S.Ct. 3221, 3227 (1983) 

(emphasis added). Section 602 of the statute requires every federal agency and department 

empowered to grant financial assistance to issue regulations to effectuate the provisions of 

Section 601. Id. § 2000d-1. 

In addition, Executive Order 12250, Leadership and Coordination of Nondiscrimination 

Laws, directs federal agencies to issue appropriate Title VI implementing directives, either in 

the form of policy guidance or regulations consistent with the requirements prescribed by the 

 

478 EPA, ADP Interim Process Guide, supra n. 432, at 3.

479 Id. at 9. 
177

Department of Justice’s Assistant Attorney General for Civil Rights. Exec. Order No. 12250, § 1-

402. The presidential memorandum accompanying EO 12898 also requires federal agencies 

providing funding to programs or activities that affect public health or the environment to 

comply with Title VI of the Civil Rights Act.480

EPA’s implementing regulations forbid recipients481 of federal funds from using “criteria 

or methods of administering [their] program[s] or activit[ies] which have the effect of 

subjecting individuals to discrimination because of their race, color, national origin, or sex.” 40 

C.F.R. § 7.35(b). These regulations also preclude a recipient of federal funds from choosing a 

site or location for a facility that would result in discriminatory effects. 40 CFR § 7.35(c). Other 

EPA’s regulations mandate that state agencies that receive federal funds maintain Title VI 

compliance programs for themselves and other recipients that obtain federal assistance 

through such programs. 28 C.F.R. § 42.410. 

State agencies implementing the Clean Power Plan (i.e., state air or environmental 

protection agencies) who receive funding from EPA are responsible for ensuring that funded 

activities (for example, permitting processes) that become part of compliance plans under the 

Clean Power Plan conform to Title VI requirements. If any program or measure in a state plan 

that was funded by EPA resulted in discrimination on the basis of race, color, or national origin, 

those agencies would be in violation of Title VI, and aggrieved persons would be entitled to file 

an administrative complaint with EPA. 40 C.F.R. § 7.120. With respect to the administrative 

complaint procedure, we reiterate EPA’s need to make modifications to the complaint 

investigation and resolution process in a manner that ensures meaningful participation of 

environmental justice communities and effective enforcement of Title VI complaints.482

In addition, if compliance cannot be achieved voluntarily, the regulations authorize EPA 

to deny, suspend or terminate funding to the particular program under which the agency has 

found discrimination. EPA may also refer the matter to the Department of Justice to get 

 

480 Memorandum from President Clinton Executive Order on Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations (Feb. 11, 1994), available at

http://www.epa.gov/swerffrr/documents/executive_order_12898.htm. 

481 The regulations define “recipient” as “any State or its political subdivision, any instrumentality of a 

State or its political subdivision, any public or private agency, institution, organization, or other entity, or 

any person to which Federal financial assistance is extended directly or through another recipient, 

including any successor, assignee, or transferee of a recipient, but excluding the ultimate beneficiary of 

the assistance.” 40 C.F.R. § 7.25.

482 Letter from Center on Race, Poverty & the Environment, The City Project, Conservation Law 

Foundation, Earthjustice, Environmental Justice League of Rhode Island, Humansynergyworks.org, New 

Mexico Environmental Law Center, NRDC, Sierra Club, West End Revitalization Association, Inc., Marc 

Brenman, and Patrice Lumumba Simms to EPA Administrator Gina McCarthy (Nov. 5, 2013), attached as 

Ex. 55.
178

compliance. 40 C.F.R. § 7.130.483 EPA should make use of this authority if any program in a state 

plan funded by EPA resulted in a Title VI violation.

Meaningful public involvement is also necessary to ensure recipients’ compliance with 

Title VI. As EPA notes in its Title VI’s “Recipient Guidance,” early and inclusive public 

involvement of environmental justice communities in the permitting process is critical to ensure 

that the use of federal funds does not discriminate against these communities on the basis of 

race, color, or national origin.484 In this guidance, EPA has suggested specific public involvement 

approaches in the permitting process that could also apply to the process of developing and 

implementing state plans under the Clean Power Plan. 

First, funding recipients could prepare a “public involvement plan” with the 

participation of environmental justice communities, to ensure that state plan development 

efforts address the issues that are important to these communities.485 Second, recipients could 

equip communities with appropriate tools such as information materials, training sessions 

(including in other languages, if there are non-English speaking communities), and grants to 

ensure their active and effective participation in the plan development process.486

Finally, during plan implementation, funding recipients should work to ensure that local 

authorities integrate environmental justice concerns early in the process, which will require 

acknowledging communities’ concerns about existing facilities near residential areas; working 

with the relevant authorities to ensure that data on demographics and location of existing 

facilities in communities are considered before making any siting decisions; and working with 

those authorities to identify locations for new facilities that avoid net increases in pollution in 

communities with disproportionately high exposure or that already host a number of 

facilities.”487

As we discussed above, effective integration of environmental justice concerns should 

be one of the approvability criteria for state plans. This includes requirements on recipients of 

EPA’s funding; i.e., state implementing agencies, to comply with non-discrimination obligations 

under Title VI and EPA’s implementing regulations. We urge the agency to address these 

obligations of recipient agencies in the final rule, including options for meaningful public 

 

483 Draft Title VI Guidance for EPA Assistance Recipients Administering Environmental Permitting 

Programs (Draft Recipient Guidance) and Draft Revised Guidance for Investigating

Title VI Administrative Complaints Challenging Permits (Draft Revised Investigation Guidance), 65 Fed. 

Reg. 39,650, 39,696-97 (June 27, 2000).

484 Title VI Public Involvement Guidance for EPA Assistance Recipients Administering Environmental 

Permitting Programs (Recipient Guidance), 71 Fed. Reg. 14,207, 14,210 (Mar. 21, 2006).

485 Id. at 14,211.

486 Id. at 14,213.

487 Id. at 14,214-15. This would be the case, for example, if EPA allowed new gas-fired power plants as a 

compliance measure under state plans. However, we believe that EPA should not allow new gas for 

compliance, as we discuss in Section XIII.B.
179

involvement, so that states construct their implementation plans in a manner that ensures 

compliance with Title VI. 

F. EPA Must Clarify that State Plans that Allow Uncontrolled or Poorly Controlled CoPollutant Emissions from Individual Sources Are Not Permissible As Section 111(d) 

Emission Guidelines for Pollutants with Localized Health and Environmental Impacts.

EPA needs to make clear that emission standards that allow uncontrolled or poorly 

controlled emissions from individual sources are not permissible as Section 111(d) emission 

guidelines for pollutants with localized health and environmental impacts.

Under the Clean Power Plan a state might choose to adopt building block measures that 

have the effect of reducing CO2 emissions from some EGUs while allowing emissions from 

others to increase. Although such approaches have advantages in controlling well-mixed 

pollutants like CO2 that do not present localized health and environmental threats, they would 

raise serious concerns if applied to pollutants that do present such threats. Applying similar 

approaches to Section 111(d) rules for air toxics, criteria pollutants, and other pollutants with 

localized impacts (collectively, “hotspot” pollutants) would create significant risks to people 

living near the emitting sources and to ecosystems near such sources. These risks are of 

particular concern to people in communities that are disproportionately impacted by emissions 

from power plants and industrial sources.

Accordingly, EPA needs to make clear that any flexible approaches it has proposed 

under the Clean Power Plan will not apply, and are not transferrable to, emissions of hotspot 

pollutants from power plants and other sources that are, or may be subject to rules under 

Section 111(d). According to EPA itself, it is significant that CO2 is a global pollutant and 

therefore the location of the emissions (and emission reductions) does not affect the impact on 

climate change of an amount generated at any given source in any one location.488 The fact that 

CO2 becomes well-mixed in the air “means that CO2 emissions may be reduced anywhere within 

the electricity grid and still achieve the intended climate benefits. This allows EPA to determine 

that a system is the ‘best’ based on the total emission reductions the system would achieve 

rather than basing the determination on the emissions reductions achieved at each individual 

affected source.”489 The same is plainly not true for hotspot pollutants, however, where the 

location of emissions (and emission reductions) do matter. For such pollutants, EPA would not 

be able to determine that a system is “best” if it allowed an individual source to emit at 

uncontrolled or poorly controlled levels, or to rely on reductions at other sources in lieu of 

reducing its own emissions. 

That Section 111(d) rules need to protect against localized health impacts is supported 

by the Act’s language and purpose. Protection of public health and welfare is a central purpose 

of the Act. 42 U.S.C. §7401(b)(1). A source category is listed for regulation under Section 111 

 

488 Legal Memorandum, supra n. 80, at 48.

489 Id. at 48-49.
180

only if EPA finds that it causes, or contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare. 42 U.S.C. § 7411(b)(1)(A). Thus, Congress 

was plainly concerned about the health and welfare impacts of the emissions to be controlled. 

Given the statutory focus on protecting public health and welfare, a system of emission 

reduction that fails to protect against impacts on health and welfare cannot be deemed “best” 

under the statute, and therefore, flexible compliance approaches should not be allowed in 

other regulations of criteria or hazardous air pollutants.

G. EPA Must Require Absolute Reductions of CO2 and Co-Pollutant Emissions from CoalFired and Natural-Gas Fired Plants in Environmental Justice Communities.

Under the Clean Power Plan, EPA is giving states flexibility to require affected sources to 

meet the required emission rate through a range of carbon emission reductions measures 

included in the different building blocks—for example, a coal-fired plant could improve its heat 

rate, or it could purchase renewable energy credits (“RECs”). In the case of affected sources 

located in or near environmental justice communities, however, EPA must require absolute 

reductions of CO2 and co-pollutant emissions directly from the plants (both coal-fired and 

natural gas-fired plants), to avoid creating or exacerbating co-pollutant hotspots.

To this end, as we explain below with respect to a cap-and-trade program, spatial 

restrictions can be imposed on the trading, in this case of renewable energy credits (“RECs”), by 

sources located in or near environmental justice communities. This can be done by delineating 

zones where the flow of RECs is prohibited or limited, to ensure that adverse impacts on these 

communities from trading are minimized. EPA’s own guidance suggests that these zones can be 

defined in terms of non-attainment areas.490 We suggest that those zones should be defined in 

terms of hotspots that take into account cumulative impacts. Once state agencies have 

delineated these zones, they could forbid or limit REC purchases that allow dirty plants to 

increase or maintain their co-pollutant emissions in these zones. In this way, coal-fired and gasfired plants in environmental justice communities would have to reduce their emissions rather 

than purchase RECs.

H. States Must Integrate Environmental Justice Concerns into the Design of Cap-andTrade Compliance Programs.

EPA’s proposal provides states with flexibility to convert the rate-based state goals to 

mass-based goals, in order to accommodate programs such as the Regional Greenhouse Gas 

Initiative (“RGGI”) and California’s Global Warming Solutions Act (“AB32”) for compliance under 

the rule (as well as other similar programs other states decide to create for compliance 

purposes). 79 Fed. Reg. at 34,897. The proposal explains that emissions trading would allow 

affected sources whose emissions are higher than the assigned emission standard to comply by 

 

490 EPA, Office of Air and Radiation, Tools of the Trade, A Guide to Designing and Operating a Cap and 

Trade Program for Pollution Control (June 2003), available at

http://www.epa.gov/airmarkets/resource/docs/tools.pdf, at 3-22.
181

purchasing allowances through the trading program. Id. at 34,892. To the extent that EPA 

decides to allow emissions’ trading in the final rule, and states decide to incorporate an 

allowance trading program in their state plans, they must effectively integrate environmental 

justice considerations as they design such a program. 

Cap-and-trade programs are widely regarded as having the capacity to generate large 

emissions reductions. Market-based systems, however, are focused on achieving reductions in 

the most efficient and cost-effective manner, without regard to the spatial distribution of those 

reductions. If EPA allows these programs for compliance, states that opt for CO2 allowance 

trading systems must integrate environmental justice considerations into the design of these 

programs in order to avoid the risk of co-pollutant hotspots and ensure environmental justice 

communities receive the benefits of those reductions, as we explain below. By properly 

integrating environmental justice concerns, the overall emissions reductions achieved by a capand-trade program would benefit low income communities, whose health is more likely to be 

affected from increased pollution levels and who have fewer resources to move out of 

vulnerable areas.491

Given the flexibility available to states in implementing the Clean Power Plan, it is likely 

that states will consider other compliance measures that pose a similar risk of exacerbating copollutant hotspots or depriving environmental justice communities of the benefit of copollutant reductions. Implementing Building Block 2, for example, might reduce coal plant 

pollution in some communities while increasing gas plant pollution in others. A state carbon tax 

is a potential compliance mechanism that offers the possibility of addressing these impacts by 

creating a revenue stream that the state could use to finance co-pollutant reductions and other 

measures to ensure that the benefits of the Clean Power Plan accrue to environmental justice 

communities.

1. Cap-and-Trade Programs May Heighten the Risk of Co-Pollutant Hotspots.

Allowing affected sources to comply through the purchase of CO2 allowances may 

heighten the risk of co-pollutant hotspots. While, as noted above, CO2 is a global pollutant that 

does not itself create adverse local impacts, the combustion that generates CO2 also generates 

criteria pollutants such as SO2, NOx, ozone precursors, and hazardous air pollutants that can 

contribute to create or perpetuate pollution in minority and low income communities which, in 

many cases are home to the country’s dirtiest plants.492 The degree of harm from co-pollutant 

emissions varies depending on the population’s density and exposure to cumulative pollution 

impacts.493 While many co-pollutants are regulated under other Clean Air Act programs and 

may already be controlled by existing permits, those requirements do not fully eliminate 

 

491 Kaswan, Environmental Justice and Domestic Climate Change Policy, 38 Envtl. L. Rep. News & Analysis 

10,287, 10,293-94 (May 2008), attached as Ex. 56. 

492 Id. at 10,298. See also NAACP, Coal-Blooded, supra n. 454.

493 Kaswan, Climate Change and Environmental Justice: Lessons from the California Lawsuits, 5 San Diego 

J. Climate & Energy L. 1, 23 (2013-2014), attached as Ex. 57.
182

harmful pollution or ensure that actual emissions under a cap-and-trade program will not 

increase. For example, permitted facilities could increase their actual emissions by operating at 

higher capacity factors and still remain within the terms of their permits. While the risk of 

hotspots exists with and without a cap-and-trade program, the ability to purchase CO2

allowances under such a program could lead to increased emissions that would otherwise not 

have occurred.494

2. Cap-and-Trade Programs May Fail to Properly Distribute Co-Pollutant Benefits.

While cap-and-trade programs may achieve large emissions reductions, they may fail to 

distribute the benefits of co-pollutant reductions to environmental justice communities. 

Communities located near plants that reduce CO2 emissions and purchase fewer allowances (or 

that do not purchase allowances) will benefit from reduced emissions of co-pollutants, while 

communities near facilities that purchase more allowances and do not reduce their emissions 

will not. Even if a facility only maintains its level of emissions, without increasing it, the relevant 

community will not have obtained a benefit from the co-pollutant reductions that would result 

from the Clean Power Plan. If the higher-emitting facilities are located in minority and lowincome communities, then the program could contribute to intensify environmental justice 

impacts.495

3. To the Extent that EPA Allows Cap-and-Trade Programs for Compliance, the 

Agency Must Require States to Integrate Environmental Justice Concerns into the 

Design of Those Programs.

If EPA allows compliance through cap-and-trade programs in the final rule, the agency 

must require states to effectively integrate environmental justice concerns into the design of 

those programs in order to address the risk of co-pollutant hotspots and the distribution of 

benefits of co-pollutant reductions. Relevant statutes or regulations creating the cap-and-trade 

program must provide for environmental justice protections, which will enable the design of an 

allowance trading program that addresses these communities’ concerns. Below we suggest two 

ways of incorporating these concerns: first, limitations on trading to address hotspots, and 

second, the utilization of revenues from allowance auctions for the benefit of environmental 

justice communities.

a. Incorporate Environmental Justice Protections at the Statutory or Regulatory 

Level.

If states opt for a cap-and-trade program for compliance, they will likely need to pass a 

statute or regulation to create it. And when they do so, they must incorporate principles that 

provide the authority for integrating environmental justice into the design of the program. 

California’s AB32 provides a good example of how to integrate environmental justice 

 

494 Kaswan, Environmental Justice and Domestic Climate Change Policy, supra n. 491, at 10,300-01. 

495 Id. at 10,302.
183

considerations into the design of a cap-and-trade program at the legislative level, provided the 

legislative program is correctly implemented. AB32 adopted a holistic approach that required 

the California Air Resources Board (“CARB”), the implementing agency, to adopt regulations 

that ensured reductions not only of greenhouse gases, but also of co-pollutants, and mandated 

the program to ensure benefits for environmental justice communities. 

Specifically, AB32 provides that, before enacting a cap-and-trade program, the CARB 

had to consider “the potential for direct, indirect, and cumulative emission impacts from these 

mechanisms, including localized impacts in communities that are already adversely impacted by 

air pollution,” and to design the compliance mechanism in a manner that prevents “any 

increase in the emissions of toxic air contaminants or criteria air pollutants.” Cal. Health & 

Safety Code § 38570(b)(1)-(2). In adopting the relevant regulations, CARB was required to 

“[c]onsider overall societal benefits, including reductions in other air pollutants, diversification 

of energy sources, and other benefits to the economy, environment, and public health,” and to 

“[e]nsure that activities undertaken to comply with the regulations do not disproportionately 

impact low-income communities.” Id. § 38562(b)(2)-(6). 

The law also mandated the creation of an environmental justice advisory committee 

(“EJAC”), comprised of “representatives from communities in the state with the most significant 

exposure to air pollution, including, but not limited to, communities with minority populations 

or low-income populations,” to advise it in developing a scooping plan. Id. § 38591(a). CARB is 

also required to ensure that the cap-and-trade program directs public and private investments 

toward the most disadvantaged communities in the state, and to provide an opportunity for 

community institutions to participate in, and benefit from state-wide efforts to reduce 

greenhouse gas emissions. Id. § 38565.

The manner in which this legal authority is implemented is critical to ensure that 

measures to address environmental justice concerns are adequately executed. While providing 

for the relevant protections in the statute, AB32 is also a good example of how a program that 

provides legislative protections may still not address environmental justice concerns 

adequately. In California, environmental justice advocates pushed back on the development of 

a cap-and-trade program because CARB did not adequately consider alternatives, as required 

under California land use laws. EJAC’s lack of funding was also a major issue. Environmental 

justice advocates have worked tirelessly to ensure AB32 incorporates the concerns of these 

communities, including through the promotion of additional legislative solutions to mitigate 

potential harms and create benefits for these communities, as explained below.496

California’s AB32 thus provides valuable lessons to other states in the design of a capand-trade program at the legislative level. From a practical perspective, however, resources are 

not available in every environmental justice community, and the degree of public engagement 

may not be the same as in California, precisely due to lack of resources. Particularly in those 

 

496 See Kaswan, Climate Change and Environmental Justice, supra n. 493; Truong, Addressing Poverty and 

Pollution, supra n. 423.
184

regions, EPA must step up and advance the concerns of environmental justice communities 

through targeted information efforts and the provision of financial resources that enables their 

meaningful participation in the development of a cap-and-trade program.

b. Perform a Cumulative Effects Assessment as Part of Environmental Impact 

Review.

As we discussed above with respect to the performance of an environmental justice 

analysis, the focus on specific pollutants does not factor in the cumulative effects on minority 

and low income communities, who are often subject to a multiplicity of environmental and 

socio-economic impacts. States that opt to comply with the Clean Power Plan through a capand-trade program must prepare a cumulative impact assessment as part of their 

environmental impact assessment of such a program, following existing methodologies and 

EPA’s own guidelines that the agency should provide in the Clean Power Plan. This analysis will 

help inform the exact design of the trading program in a manner that avoids the incidence of 

hotspots and that distributes the benefits from trading to these communities. 

c. Establish Spatial Restrictions on Trading Taking into Account Cumulative 

Effects.

As EPA has noted in its guidance on the design of a cap-and-trade program for pollution 

control, one design approach to address hotspots is to introduce spatial restrictions on trading 

of allowances. If unacceptable pollutant concentrations are expected to occur in a particular 

area, “trading restrictions could be imposed by introducing ‘zones’ where net flows of 

allowances into the sensitive area are prohibited or discounted by an appropriate amount.”497

This would require the relevant state agencies to delineate those zones by identifying areas 

with high levels of pollution or areas that contain environmental justice communities, the types 

and levels of emissions in those areas, and the size of the relevant zones according to different 

criteria.498 An example of trading restrictions by spatial trading zones is the Los Angeles’ 

Regional Clean Air Incentives Market (“RECLAIM”) program, which employed two trading 

zones—sources in the downwind zone were precluded from trading allowances with zones in 

the upwind zone.499

 

497 EPA, Tools of the Trade, supra n. 490 at 3-22.

498 Kaswan, Environmental Justice and Climate Change Policy, supra n. 491, at 10,305.

499 EPA, Tools of the Trade, supra n. 490 at 3-21. 
185

Fig. 31- Spatial Trading Restrictions

Spatial trading zones can be defined according to a variety of criteria. Size can be 

evaluated in broad terms, for example, as non-attainment areas (as depicted in Fig. 31 above), 

or in terms of specific adverse impacts suffered by these communities; i.e., as hotspots. 

Hotspots can be further delineated not only in terms of proximity impacts, but also of 

cumulative impacts. Non-attainment zones would be administratively easier to designate, but 

they could fail to adequately address the localized effects from pollution in environmental 

justice communities. Zones that more accurately reflect the pollution impacts suffered by these 

communities would enable a more targeted program, but this would require state agencies to 

obtain detailed information about the distribution of pollution. As we discussed above, an 

environmental justice analysis would provide states and EPA with adequate information to 

define the size of these zones in terms of hotspots. 

Once state agencies have defined these zones, they could impose restrictions such as 

forbidding the trading of allowances that increase, or that simply maintain, co-pollutant 

emissions in these zones, particularly by the dirtiest plants. States could also discourage trading 

by introducing an obligation to maintain a greater number of allowances per ton of emissions in 

these zones,500 or by charging higher allowance prices to facilities located in these areas. The 

latter approach would not prohibit trading, but would make it more expensive to trade in those 

zones. This would provide these sources with an incentive to reduce their own emissions rather 

than purchase allowances.501

 

500 Id. 

501 Kaswan, Environmental Justice and Climate Change Policy, supra n. 491 at 10,306. 
186

d. Finance Co-Pollutant Reductions with Revenues from Allowance Auctions.

If allowances under a cap-and-trade program are auctioned, states should use a portion 

of these revenues to address the reduction of co-pollutants in environmental justice 

communities through other measures outside of the cap-and-trade mechanism. These revenues 

could be used to finance targeted investments in demand-side energy efficiency, renewable 

energy, and in projects to revitalize environmental justice communities.502 Residents of 

environmental justice communities should participate in the selection of the activities to be 

funded. 503

In California, for example, SB 535 mandates the California Department of Finance 

(“DOF”) to allocate 25 percent of AB32 auction revenues to projects that provide benefits to 

disadvantaged communities, with at least 10 percent to be spent directly in those 

communities.504 The bill requires CalEPA to identify disadvantaged communities based on 

geographic, socioeconomic, public health, and other environmental hazard criteria, including 

“[a]reas disproportionately affected by environmental pollution and other hazards that can lead 

to negative public health effects, exposure, or environmental degradation,” and “[a]reas with 

concentrations of people that are of low income, high unemployment, low levels of 

homeownership, high rent burden, sensitive populations, or low levels of educational 

attainment.”505

A companion bill, AB 1532, required the Department of Finance, in consultation with 

CARB and any other relevant state entity, to develop a three-year investment plan and to 

submit it to the Legislature for approval. Subsequently, the DOF will allocate funding to these 

programs through the annual budget process. In developing the investment plan, the bill 

requires DOF to ensure that the revenues facilitate the achievement of greenhouse gas 

reductions in the state (for example, through energy efficiency and renewable energy 

generation), foster job creation by promoting emissions reductions projects carried out by 

California workers and businesses, and direct investments towards the most disadvantaged 

communities and households in the state. The bill also mandates a public process to determine 

how to allocate these revenues; specifically, it required CARB to hold at least two public 

workshops in different regions of the state and one public hearing prior to DOF submitting the 

investment plan.506

Once again, California provides a useful lesson on the need to implement legislative 

mandates properly. The funding allocations from SB535 were delayed when the Governor 

 

502 See AB32 Environmental Justice Advisory Committee, Initial Recommendations to Inform 

Development of the 2013 to the AB32 Scoping Plan (Aug. 6, 2013), attached as Ex. 58, at 5.

503 See Truong, Addressing Poverty and Pollution, supra n. 423; Kaswan, Environmental Justice and 

Climate Change Policy, supra n. 491, at 10,306.

504 Truong, Addressing Poverty and Pollution, supra n. 423. 

505 Id. at Section 2. 

506 Cal. Health & Safety Code § 39716. 
187

borrowed the cap-and-trade funds, ignoring the state’s investment plan.507 It is critical that 

states implement the programs they create to improve the health and environment of low 

income communities. If these investment programs become part of the state plan, EPA should 

require their compliance as part of the overall plan reporting process. EPA should require states 

to submit detailed information that shows that the earmarked funds are being used in projects 

that benefit environmental justice communities.

e. Other Considerations in Designing a Cap-and-Trade Program

i. States Must Set a Stringent Cap.

The cap should be stringent enough to ensure emissions’ reductions that truly achieve 

the state goal. Under the Acid Rain Program, stringent reduction requirements enabled 

significant reductions in SO2. More recently, under California’s AB32 the cap in 2013 was set at 

2 percent below the emissions level forecast for 2012. The cap declined 2 percent in 2014 and 

will decline 3 percent annually from 2015 to 2020.508

In addition, and related to the above requirement, states must not over-allocate 

allowances. The RECLAIM trading program for criteria pollutants provides a good example of 

the consequences of over-allocation—large utilities subject to the program purchased 

allowances instead of adopting control technology, which failed to generate emission

reductions.509

ii. States Should Not Distribute Free Allowances.

While several cap-and-trade programs (such as AB32)510 provide for free allocation of 

allowances during the initial stages, we believe that states should auction these allowances and 

should not distribute them for free.511 Requiring sources to pay for the right to pollute would 

force them to internalize these costs, and would reduce the potential for windfall profits. It 

would also provide revenues to address environmental justice concerns, as discussed above.512

iii. Offsets Should not be Permitted for Compliance.

In the proposal, EPA specifies that it is not proposing that out-of-sector GHG offsets 

could be applied to demonstrate CO2 emission performance by affected EGUs in state plans. 

But the agency does raise the possibility that “emission limits for affected EGUs that are 

included in state plans could still include provisions that provide the ability to use GHG offsets 

 

507 Truong, supra n. 423, at 518.

508 CARB, Overview of ARB Emissions Trading Program (Oct. 20, 2011), attached as Ex. 59, at 1.

509 Kaswan, Environmental Justice and Climate Change Policy, supra n. 491, at 10,296.

510 CARB, Overview of ARB Emissions Trading Program, supra n. 508, at 1.

511 See AB32 Environmental Justice Advisory Committee, Initial Recommendations, supra n. 502, at 5.

512 Kaswan, Environmental Justice and Climate Change Policy, supra n. 491, at 10,307.
188

for compliance with the emission limits, provided those emission limits would achieve the 

required level of emission performance for affected EGUs.” 79 Fed. Reg. at 34,910.

Although existing GHG cap-and-trade programs like AB32 and RGGI513 allow the use of 

offsets, EPA must not allow states that design an allowance trading program for compliance 

with the Clean Power Plan to reduce emissions through offsets. Allowing regulated facilities to 

purchase allowances from outside the cap-and-trade program’s scope would enable those 

facilities to continue emitting or would increase emissions of co-pollutants without a 

corresponding decrease in emissions from other facilities covered by the program, and 

environmental justice communities would not obtain the benefits of co-pollutant reductions.514

In addition, use of certain offsets, such as those resulting from biological carbon sequestration 

(for example, forestry), would complicate emissions’ monitoring, as these projects are difficult 

to verify.515

iv. States Should Impose Heightened Monitoring and Reporting Requirements 

on Facilities Located Near Environmental Justice Communities.

Once the cap-and-trade program is in place, state regulators should monitor facilities 

located in or surrounding these communities to ensure compliance with their obligations under 

the program. These facilities could be required to install additional monitors, and to report 

specific information on the emissions of co-pollutants tied to the purchase of allowances. 

Environmental justice communities should be encouraged to report any actions by facilities that 

they believe are in violation of these requirements, and should have access to information on 

these firms’ trading transactions and reports on emission levels.

VIII. Economic Justice

Investments in energy efficiency, clean energy, and other measures to comply with the 

Clean Power Plan will produce major additional benefits throughout the U.S. economy, making 

the clean energy economy a major new engine of U.S. job creation. Renewable energy has 

become cost competitive with fossil fuels, including coal, oil, and natural gas, as well as with 

nuclear power. In addition to reducing carbon emissions, the ancillary benefits of the Clean 

Power Plan--developing renewable energy, energy efficiency and a modernized, smart power 

grid—will, when combined with high road employment practices, create millions of good jobs 

for people who desperately need them, especially people from economically and 

environmentally distressed communities.

 

513 CARB, Overview of ARB Emissions Trading Program, supra n. 508; RGGI, CO2 Offsets, 

http://www.rggi.org/market/offsets (last visited Nov. 25, 2014). For programs that allow offsets, such as 

RGGI and AB32, the corresponding emissions standard should be more stringent than the state goal to 

account for those reductions.

514 Kaswan, Environmental Justice and Climate Change Policy, supra n. 491, at 10,302.

515 Id. at 10,298.
189

There are clear environmental and public health benefits of replacing fossil fuels with 

energy efficiency and clean energy. However, we cannot ignore the fact that specific jobs will 

be lost and specific communities will be affected as we make the transition away from fossil 

fuels. These economic impacts will affect certain communities, states, and regions much more 

than others, and we need to ensure that the growth of the clean energy sector reaches those 

most in need of the economic benefits of that growth. The Clean Power Plan state 

implementation process provides tremendous opportunities for state and federal policymakers 

to take concrete policy steps to address the fears of low income and working class communities 

and union representatives in carbon-intensive sectors that a market-driven clean energy 

transition means economic insecurity for them. Government has a key role in helping to drive a 

fair and just transition to a clean energy economy that will maximize investments in economic 

development, provide security to affected workers, and protect the tax base by creating lasting, 

good jobs in impacted communities.

A. States Must Craft Plans that Make Expanded Use of Renewable Energy and Energy 

Efficiency, While Prioritizing the Creation of Good Clean Energy Jobs.

Renewable energy and energy efficiency resources are making up an increasing 

percentage of America’s energy mix. In the past few years, renewable energy has experienced 

great growth and has become cost-competitive with fossil fuels, with wind prices decreasing 

overall on average by 58 percent and solar photovoltaics by 78 percent over the last five years, 

primarily due to technological improvements that have enabled projects to operate at higher 

capacity factors, as well as due to a decline in the prices of inputs in the manufacturing supply 

chain.

516 Wind turbine costs, for example, have decreased 30 percent since 2008.517 These 

trends will continue and renewables will increasingly become more cost-competitive than fossil 

fuels. In addition, energy efficiency programs have grown at an accelerated rate since the 

2000s, from total spending was $1.6 billion in 2006 to $6.3 billion in 2013.518 These 

expenditures are yielding significant energy savings. Funding for customer energy efficiency 

programs is expected to continue rising in the future. As a result of this expansion, jobs in these 

industries are experiencing, and will continue to experience great growth. 

Numerous sources have noted clean energy’s potential for job creation. A report by the 

Worldwatch Institute and the Center for American Progress noted that renewable energy 

creates more jobs per unit of energy produced and per dollar spent than fossil fuel technologies 

do.519 The Metropolitan Policy Program at Brookings has also found that, as far back as 2010, 

2.7 million people were employed in the clean energy sector whereas only 2.4 million people 

 

516 Lazard, supra n. 172, at 9.

517 Int’l Renewable Energy Agency, Rethinking Energy 2014 (Sept. 2014), available at 

http://www.irena.org/rethinking/Rethinking_FullReport_web_print.pdf, at 15.

518 Id. at v.

519 Worldwatch Institute & Center for American Progress, American Energy: The Renewable Path to 

Energy Security (Sept. 2006), available at http://www.worldwatch.org/files/pdf/AmericanEnergy.pdf, at 

10.
190

were employed in the fossil fuel sector.520 In addition, AWEA reported that in 2012 more than 

80,000 Americans were already employed full-time in the wind industry sector.521 Finally, 

analysis by the Center for American Progress has concluded that twice as any medium and high 

credentialed jobs are being created in the clean energy industry in comparison to the fossil 

fuels’ industry,522 and clean energy investments generate about 3.2 times the number of jobs as 

does investing the same amount of money in the fossil fuel sector.523 Thus, clean energy jobs 

pay more overall, and those jobs are of better quality.

Carbon standards for existing power plants that include significant investments in both 

renewables and demand-side energy efficiency also have the potential for robust job growth. 

NRDC’s proposal for how the EPA could shape these standards, which includes a significant 

expansion of energy efficiency, concludes that limits on carbon pollution from power plants 

have the potential to save Americans $37.4 billion on their electric bills by 2020 while creating 

more than 274,000 jobs.524 Because clean energy investments require more employment per 

unit of activity, others have noted that investments in clean energy will result in a net increase 

of 2.7 million jobs.525 In order achieve this goal Pollin and Boyce have called for reducing energy 

consumption 30 percent by 2030 through efficiency improvements as well as renewable 

resources.526 Other academics have also concluded that hundreds of thousands of jobs can be 

created by California further expanding energy efficiency programs.527 In sum, renewable 

energy and energy efficiency contribute to create safer, long-term jobs while providing power 

at a lower cost.

 

520 Muro et al., Metropolitan Program at the Brookings Institute, Sizing the Clean Economy: A National 

and Regional Green Jobs Assessment (July 13, 2011), available at 

http://www.brookings.edu/research/reports/2011/07/13-clean-economy, at 4, 19.

521 Assessing the Efficiency and Effectiveness of Wind Energy Incentives: Joint Hearing Before the 

Oversight Subcomm. and Energy Subcomm. of the H. Comm. on Science, Space, and Technology, 114th

Cong. (Apr. 26, 2013) (statement of Rob Gramlich, CEO of AWEA), available at 

http://science.house.gov/hearing/oversight-subcommittee-and-energy-subcommittee-joint-hearingassessing-efficiency-and, at 1.

522 Pollin et al., Center for American Progress/PERI, The Economic Benefits of Investing in Clean Energy: 

How the Economic Stimulus Program and New Legislation can Boost U.S. Economic Growth and 

Employment (June 2009), available at http://cdn.americanprogress.org/wpcontent/uploads/issues/2009/06/pdf/peri_report.pdf, at 38.

523 Id.

524 NRDC, New Carbon Pollution Standards Can Save American Households $13 Billion on Electric Bills, 

Create 274,000 Jobs, http://www.nrdc.org/air/pollution-standards/state-benefits.asp (last visited Nov. 

24, 2014).

525 Pollin & James Boyce, PERI, An Egalitarian Program for Building a Clean-Energy U.S. Economy, 

Discussion Paper Prepared for Labor Network for Sustainability Conference (Jan. 16, 2014), attached as 

Ex. 60, at 5.

526 Id. at 1.

527 Roland-Holst, D., U.C.-Berkeley, Energy Efficiency, Innovation, and Job Creation in California (Oct. 

2008), attached as Ex. 61, at 4.
191

The Clean Power Plan can help accelerate the clean energy economy and create good 

jobs by allowing states to achieve their targets through the implementation of renewable 

energy generation and energy efficiency. The proposal would result in increased clean energy 

sector jobs and an estimated decrease of about nine percent in electricity bills by 2030. 79 Fed. 

Reg. at 34,934. The flexibility granted to states to achieve their targets with more renewable 

energy and energy efficiency than EPA has estimated for purposes of its state goals’ calculation 

means a higher potential for new jobs in solar installation, wind infrastructure development, 

and construction of homes and businesses that are more energy-efficient, among other job 

options. Median wages are 13 percent higher in clean energy jobs than the median United 

States wages.528

These projections are borne out in practice by new research which shows that, in 

California, strong federal and state clean energy policies, combined with high road employment 

practices, have resulted not only in substantial carbon emissions reductions but in stable, 

family-sustaining careers.529 As a result of these policies, California’s use of electricity from 

renewable sources increased from 11 percent in 2008 to nearly 20 percent in 2013. During the 

same time period, the report finds that more than 15,000 new jobs have been created by 

California’s solar construction boom, with workers building solar arrays earning on average 

$78,000 a year plus health and other benefits.530

California’s experience supplies a road map for states seeking to develop state plans 

that combine carbon emissions reductions with the creation of good jobs and economic 

development. The report lists three key ingredients for success. The first ingredient, strong 

federal action, included the Obama Administration’s American Recovery and Reinvestment Act 

(ARRA) of 2009, which reserved more funds for clean energy than had been done at any time in 

our nation’s history, loan guarantees that helped solar energy to take off in the depths of the 

Great Recession, and the Federal Business Energy Investment Tax Credit, which provides a 30 

percent credit to residential, commercial, and utility scale solar systems. The second ingredient, 

California’s aggressive climate change policies, includes AB 32, which requires a steep reduction 

in greenhouse gas emissions, and SB X1-2, which expanded California’s RPS to an ambitious 33 

percent target by 2020.531

The third vital element of the equation mentioned in the report was “high road” job 

creation and construction policies: utility-scale solar projects that receive federal subsidies fall 

under the Davis-Bacon Act, which requires that prevailing wages and benefits be paid. 

Furthermore, California is not a right-to-work state and as a result prevailing wages in 

 

528 Muro, et al, supra n. 520, at 23.

529 Philips, P., U.C.-Berkeley, Environmental and Economic Benefits of Building Solar in California (Nov. 

10, 2014), available at

http://laborcenter.berkeley.edu/environmental-and-economic-benefits-of-building-solar-in-californiaquality-careers-cleaner-lives/.

530 Id. at 3. 

531 Id. at 4. 
192

construction tend to be the collectively bargained rate that includes good wages with decent 

benefits and contributions to apprenticeship training. As the report notes, “the California solar 

boom has not only prepared California for a future of energy independence, it is preparing a 

new generation of California blue-collar workers for a future of skilled and productive work and 

a life of financial security”.532

The report contrasts California’s “high road” employment practices with work on some 

federally-subsidized solar projects in right-to-work states, where nonunion rates prevail: “in 

these cases, workers are often obtained from temporary labor agencies; they earn low wages 

with limited benefits and they have little access to training or career advancement. In 

California, by contrast, strong unions and strong prevailing wage laws combine to create green 

construction projects that also build the skills of the local construction labor force and improve 

the career opportunities of many new entrants into the industry”.533

Thus, States must take the driver’s seat in crafting compliance plans expand renewable 

energy and energy efficiency, while also prioritizing the creation of good, clean energy jobs to 

promote state and local economic development and improve community and workers’ 

livelihoods.

B. States Should Require Affected Sources to Put in Place Comprehensive Workers’ 

Transition Policies.

For a number of years, the electric sector has been moving away from coal towards 

natural gas and renewable energy. In our joint comments to EPA’s 111(b) proposal, we 

documented that coal generation fell from over 2 billion MWh in 2007 to 1.58 billion MWh in 

2013. Older and less-efficient power plants have and continue to retire due to competition with 

other generation resources and environmental requirements, with approximately 20 GW of 

coal retired between 2008 and 2013.534 The EIA estimates that, regardless of any impending 

environmental regulations, there will continue to be a shift away from fossil-fuel-fired 

generation towards a renewable energy economy.535 The EIA predicts that by 2040, renewables 

will account for almost one third of the growth of generation resources.536

In the course of developing their plans to achieve the state goals under the Clean Power 

Plan, states should continue to move away from coal, which is no longer economical and results 

in major environmental harms. In incorporating policies to continue to move away from coal, 

states must also establish measures to ensure that owners and operators of coal-fired power 

plants that will reduce or terminate their operations protect their workforce and guarantee 

that their workers can transition smoothly to the coming clean energy economy. In other 

 

532 Id.

533 Id.

534 Sierra Club, supra n. 115, at 14-15.

535 EIA, AEO2014 Early Release Overview, supra n. 56, at 2.

536 Id. at 7.
193

words, state plans must require owners and operators of coal-fired power plants to put in place 

comprehensive transition policies to minimize the impacts of potential job losses and 

incentivize their participation in the growing renewable energy economy. To this end, owners 

of power plants that will have to reduce their utilization or close should have policies in place 

specifically geared to workforce development, family-sustaining employment, and livelihood 

guarantees (for example, health care, pensions during some period after job loss, and 

severance packages). As we describe below, this may require government financial assistance.

C. The Federal Government and the States Should Ensure Funding for Workers and 

Communities that Depend on Fossil Fuel-Fired Power Plants.

The federal government and the states should ensure that funding mechanisms are in 

place to support workers, as well as the communities whose livelihoods depend on fossil fuelfired power plants, through the transition process. As UCS notes in its comments to the Clean 

Power Plan, the federal government administers several programs that support worker 

retraining and community development. For example, the Obama Administration designated 

eight counties in southeastern Kentucky as a “Promise Zone”537 to channel federal grants and 

assistance from various federal agencies, including housing, education, economic development, 

agriculture, and safety. The federal government should make use of existing programs (or 

create new programs) to provide targeted resources to affected communities and to help coal 

states diversify their economies. Federal agencies should work with Congress to enact 

legislation that supports displaced workers in the coal mining, coal-fired power plants, and 

related industries.538

In crafting other financing and support programs, a useful precedent to consider is the 

Worker and Community Transition (“WCT”) program, a Department of Energy (“DOE”)-

administered program that took place between 1994 and 2004. WCT targeted communities 

whose livelihoods were heavily dependent on the nuclear industry, and who faced 

displacement due to nuclear retirements. The WCT looked specifically at the communities that 

benefited from the grants.539 WCT provided grants along with other forms of assistance to help 

diversify the economic livelihood of affected communities. Under the program, DOE 

encouraged these groups to develop Community Reuse Organizations (“CROs”) eligible for 

funding to address the impacts in their specific neighborhoods.540 DOE estimated that with the 

 

537 Shear, M., Obama Announces ‘Promise Zones’ in 5 Poor Areas, The New York Times, (Jan. 9, 2014), 

available at http://www.nytimes.com/2014/01/10/us/politics/obama-announces-promise-zones-in-5-

stricken-areas.html?_r=1

538 For more discussion on worker transition issues, see the comments submitted to this docket by UCS. 

539 Pollin, R., Coal Miners and the Green Agenda, New Labor Forum (Jan./Feb. 2014), at 88-89. This 

article is available for purchase at http://nlf.sagepub.com/content/23/1/88.full.

540 Dep’t of Energy, Community Assistance, http://energy.gov/lm/services/propertymanagement/community-assistance (last visited Nov. 24, 2014).
194

funds awarded to these communities, the CROs collectively created a total of 50,934 jobs at a 

cost of $5,719 per job.541

Other reviews of the WCT have concluded that the program was effective, but “the 

most serious problem facing the energy-impacted communities, however, was the lack of a 

basic regional economic development and industrial diversification capacity for most of the 

regions.”542 Although specifically targeting those facing dislocation due to nuclear retiring, the 

program addressed the same type of problem that workers in the coal industry are now facing 

as coal becomes increasingly less competitive vis-à-vis other generation resources and pollution 

caused by coal is subjected to environmental regulations. 

The federal government should take a leading role to ensure economic opportunities at 

the regional level are available to these workers and their communities, particularly in states 

without a strongly diversified economic base. According to an analysis prepared by the staff of 

the BlueGreen Alliance,543 these actions could include:

 Executive Orders:

o Designating EPA and the Departments of Labor, Commerce, Energy, 

Transportation, and Agriculture to provide information on resources already 

available that would connect the need for economic and workforce development 

with areas that are either already experiencing the energy transition or may do 

so soon;

o Ordering EPA and the Departments of Labor, Energy, Commerce, Agriculture, 

Education and Transportation to sign a memorandum of understanding to 

collaborate on linking workforce and communities in regions affected by energy 

transition to jobs, training, education and economic development 

opportunities;544

o Activating the Department of Labor’s Employment and Training Administration 

to assess where resources can be utilized to target communities affected by the 

energy transition;

o Revitalizing and prioritizing the Green Jobs Act elements of the Energy Training 

Partnership grants, and explicitly connecting its mission to supporting 

communities affected by the energy transition;

 

541 Id.

542 Lynch & Kirshenberg, Economic Transition by the Energy-Impacted Communities, Commentary (Fall 

2000), attached as Ex. 62, at 2.

543 BlueGreen Alliance staff, Recommended Next Steps on Integrating Climate Change and Economic 

Development Policies (2013) (unpublished document available from BlueGreenAlliance).

544 Presently existing programs that can support economic development in regions affected by the 

energy transition include Industrial Development Revenue Bonds, Economic Adjustment Assistance, 

Economic Development Agency Planning, Local Technical Assistance Programs, Rural Energy for America 

Program, Clean Renewable Energy Bonds, and a number of the programs within the Economic 

Development Administration, especially those within its Environmentally Sustainable Development 

investment priority. Id.
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o Supporting the importance of collective bargaining to our current and future 

economy; and

o Within the confines of existing law, recreating the Clean Air Employment 

Transition Assistance (Section 326 of Clean Air Act, subsequently repealed by the 

Workforce Investment Act of 1998) through utilization and temporary 

redirection of National Emergency Grant Program to directly target areas 

affected by the energy transition.

 Further appropriations:

o Calling for increased funding for Economic Development Administration’s 

programs (specifically their Environmentally Sustainable Development 

investment priorities), the Department of Labor’s Community Based Job Training 

Grants and Adults and Dislocated Worker Program, and Energy Training 

Partnership grants.

 New legislation:

o Directing worker transition assistance, expanded to include all coal sector 

workers, not only miners, modeled on Sen. Byrd amendment to 1990 Clean Air 

Act Amendments, Climate Change Worker Adjustment Assistance from American 

Clean Energy and Security Act (“ACES”).

States must continue to turn away from fossil fuels by taking advantage of economic 

forces and actively engaging in specific areas experiencing job losses. Thus, they should also 

support the development of strong support plans to help workers and communities in 

transition, which should include financial assistance. For example, one of the objectives in 

Washington State’s SB 5769, along with requiring greenhouse gas emissions reductions from 

large coal-fired electric power generation facilities, is to provide financial assistance to 

communities who are affected by the transition away from coal. The bill fulfils this purpose by 

mandating that the Community Economic Revitalization Board (“CERB”) and the Public Works 

Board each find new projects for redevelopment in the region.545 It also requires qualifying 

facilities to offer financial aid to the affected community that is “equivalent to the amount of 

tax benefits received from the sales and use tax exemptions on coal.”546

States should also engage the private sector and civil society to fund initiatives to 

support workers and their communities. The Solar Community Initiative, administered by the 

World Wildlife Fund and executed by the solar firm Geostellar, provides useful lessons for the 

design of such programs.547 Under that program, employees can install rooftop solar on their 

homes at discounted prices – 35 percent below the national average for solar- and pay 50 

 

545 Wash. S. Bill Report SB 5769 (2011), available at 

http://apps.leg.wa.gov/billinfo/summary.aspx?bill=5769&year=2011 (last visited Nov. 25, 2014), at 5.

546 Id. 

547 Cusick, D., Companies Begin to Offer Discounted Solar Energy as a Worker Benefit, E&E (Oct. 23, 

2014), available at http://www.eenews.net/climatewire/stories/1060007766.
196

percent less than the average grid-delivered electricity in their bills. This is an example of how 

renewable energy companies are beginning to offer solar energy as a workers’ benefit. States 

must work with renewable energy industry stakeholders to expand the availability of these 

programs to workers in affected communities. Solar panels not only reduce consumers’ 

electricity bills; workers whose job is to install solar panels are also increasingly becoming 

aware of how cleaner technologies are replacing dirtier forms of electricity, with environmental 

benefits. This type of incentive offers a way to attract and retain workers to clean energy jobs, 

and also helps pre-qualify people in those jobs for the said benefits.

Energy efficiency can also be channeled towards benefiting affected communities, and 

states should encourage affected sources to invest in these measures. For example, 

weatherization assistance programs can be utilized in low-income and minority areas to help 

shrink the energy affordability gap. According to the DOE, investments in weatherization 

generate $2.51 in energy savings while reducing energy bills by $1.80.548 Policy Matters Ohio 

and Environmental Health Watch has assessed Ohio’s Home Weatherization Assistance 

Program, concluding that it has generated jobs, reduced pollution, and lowered consumers’ 

energy bills by more than 20 percent.549 This will not only create jobs in areas burdened by the 

costs of electric bills (for example, more than 300,000 Ohio households with incomes at or 

below the 50 percent federal poverty level pay over 30 percent of their annual income to 

energy bills550), but it will further promote investment in local economies. 

IX. A State Carbon Tax as a Compliance Mechanism

A. A State Carbon Tax is an Effective Means of Compliance 

1. Carbon Taxes Reduce CO2 Emissions

It is axiomatic that taxation is an effective means of reducing production and 

consumption of whatever is being taxed, and as a result, the literature is thick with studies of

how a carbon tax would reduce CO2 emissions.551 Using a wide variety of models and price 

assumptions, the results are always the same: a carbon tax reduces both greenhouse gas 

emissions in general and EGU CO2 emissions in particular.

For example, MIT’s Emissions Prediction and Policy Analysis (“EPPA”) model shows that 

a $15/ton tax would reduce coal-fired EGU CO2 emissions by almost 15 percent within five 

 

548 Id. at 2.

549 Woodrum & Jacob, Policy Matters Ohio/Environmental Source Watch, Weatherizing Homes of Ohio’s 

Low-Income Families: Reduces pollution, cuts energy bills, creates jobs (Oct. 2014), attached as Ex. 63, at 

1.

550 Id. at 4. 

551 We bear in mind George Orwell’s observation that “we have now sunk to a depth at which the 

restatement of the obvious is the first duty of intelligent men.”
197

years.552 EIA’s National Energy Modeling System (“NEMS”) model demonstrates that a national 

carbon tax starting at $14/ton in 2010 would reduce coal-fired EGU CO2 emissions by 50

percent from the 2030 BAU projections.553 The U.S. Regional Energy Policy Model (“REPM”) 

demonstrates that a national carbon tax starting at $20/ton in 2013 would reduce CO2

emissions by 14 percent from 2006 levels by 2020.554 And the Stanford-NEMS model shows that 

implementing a $20/ton emissions tax in 2014 would, by 2020, reduce EGU CO2 emissions by 17

percent from 2005 levels.555 Going further into the specific application of a carbon tax to coalfired EGUs, other studies show that it is the most effective and cost-efficient way to decrease 

their heat rate (and thus increase their efficiency).556

The most recent example of a carbon tax successfully reducing EGU CO2 emissions 

comes from Australia, which introduced an A$23/ton tax as of July 1, 2012. Within nine months, 

demand for power dropped by 2.2 percent, and the carbon intensity of power on the national 

grid dropped by almost 5 percent, from 1,840 lbs CO2/MWh to 1,740 lbs CO2/MWh.

557 In the 

year ending June 30, 2012, the power sector emissions were 193.5 MMT; the year ending June 

30, 2013, those emissions were 181.3 MMT, a 6.3 percent decrease (Quarterly Update of 

Australia’s National Greenhouse Gas Inventory: June Quarter 2013, p. 3); by March, 2014 (the 

latest period for which there is published data), power sector emissions were further reduced 

to an annual rate of 176 MMT, an overall decrease of 9 percent in less than two years.

Quarterly Update of Australia’s National Greenhouse Gas Inventory: March 2014, p. 6.

Nor does a carbon tax have to be national to be effective: British Columbia (“B.C.”) is 

showing how a carbon tax implemented in just one area of a country successfully reduces 

emissions even if the rest of the country has not adopted it. B.C. implemented the tax on a 

 

552 Metcalfe, G., Brookings Inst.: The Hamilton Proj., A Proposal for a U.S. Carbon Tax Swap, Discussion 

Paper 2012-07 (Oct. 2007), available at 

http://www.brookings.edu/~/media/research/files/papers/2007/10/carbontax%20metcalf/10_carbonta

x_metcalf.pdf. 

553 Shapiro et al., U.S. Climate Task Force, Addressing Climate Change Without Impairing the U.S. 

Economy: The Economics and Environmental Science of Combining a Carbon-Based Tax and Tax Relief 

(2008), available at http://www.sonecon.com/docs/studies/CarbonTaxReport-RobertShapiro-2008.pdf,

at 17.

554 Rausch & Reilly, MIT Joint Prog. on the Science and Policy of Global Change, Carbon Tax Revenue and 

the Budget Deficit: A Win-Win-Win Solution?, Report No. 228 (August 2012), available at 

http://globalchange.mit.edu/files/document/MITJPSPGC_Rpt228.pdf, at 9.

555 Wara et al., Stanford Fed. Energy Policy Lab., Analysis of the Climate Protection Act of 2013, Stanford 

Law and Economics Olin Working Paper No. 459 (June 18, 2013), available at 

http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2392656, at 11.

556 Linn et al., Resources for the Future, Regulating Greenhouse Gases from Coal Power Plants under the 

Clean Air Act, RFF DP 13-05 (Feb. 2013), available at http://www.rff.org/rff/Documents/RFF-DP-13-

05.pdf, at 54.

557 Dennis, G., Clayton Utz, Australia: What has been the effect of Carbon Price on the electricity market? 

http://www.mondaq.com/australia/x/235844/Oil+Gas+Electricity/What+has+been+the+effect+of+the+

Carbon+Price+on+the+electricity+market&email_access=on (last visited Nov. 30, 2014).
198

broad range of fossil fuels (gasoline, diesel, natural gas, heating oil, propane and coal) 

beginning in 2008 at C$10/ton, and increased it C$5 annually until it reached C$30/ton in 2012. 

The results were impressive: by 2011 (the most recent year for which there were data), GHG 

emissions had declined by 10 percent in B.C., compared to a 1 percent decline for the rest of 

Canada. By 2012, while per capita consumption of petroleum fuels increased by 3 percent in

the rest of Canada, they declined by more than 16 percent in B.C.558 Nor did the tax adversely 

affect B.C.’s economy; in fact, during that period, B.C.’s GDP per capita increased more than the 

GDP per capita of the rest of Canada.559

2. The Advantages of a Carbon Tax

a. Economic Advantages

Among economists, there is consensus that a carbon tax is a more economically efficient 

means of reducing CO2 emissions than any of the various regulatory mandates contemplated by 

the proposed rule. In fact, because the regulatory commands contemplated by EPA’s BSER 

building blocks increase the cost of such emissions and those costs will be passed on, to some 

extent, to consumers, they can also be said to impose a price on CO2, albeit one that is 

economically less efficient than a carbon tax.

b. Administrative Advantages 

A carbon tax creates economic incentives for each of EPA’s building blocks by 

discouraging each fuel’s use in exact proportion to its end-use CO2 emissions, and thus 

encourages all emissions reductions that cost less than the tax. However, it is simpler to 

implement and administer than the Building blocks because all affected EGUs are already 

required to monitor and report their CO2 emissions;560 after that, it is a simple arithmetical 

exercise to multiply the reported emissions by the tax rate and send a check to the State 

treasury. A carbon tax thus avoids the need for complex administrative and regulatory action by 

multiple state agencies.

c. Revenue to Offset Impacts on Low Income Households and Fenceline 

Communities

To the extent that carbon reductions increase electricity rates, these costs are 

regressive, i.e., as a share of household income they will fall more heavily on lower-income 

households than on higher-income households. This is because, in general, lower-income 

 

558 Petroleum consumption is the most useful B.C. statistic because B.C. does not have any coal-fired 

EGUs, and its one baseload natural gas-fired EGU—Burrard—is scheduled to shut down in 2016.

559 Beaty et al., The shocking truth about B.C.’s carbon tax: It works, The Globe and Mail (July 9, 2014), 

available at http://www.theglobeandmail.com/globe-debate/the-insidious-truth-about-bcs-carbon-taxit-works/article19512237/.

560 40 C.F.R. § 98.2 (GHG Reporting Rule monitoring requirements).
199

households spend a higher percentage of their income on energy and other goods whose prices 

would be increased by the resulting increase in electricity prices. For example, a $15 carbon tax 

would burden the poorest 10 percent of households on average by about 3.5 percent of annual 

income, almost 7 times greater than the 0.6 percent burden that would fall on the richest 

households.561

Unlike other regulatory mechanisms that could be used to meet the Plan’s targets, 

however, a carbon tax generates revenue that can be used to offset that burden on lowerincome households. One paper estimates that (for a national carbon tax), just 11 percent of the 

revenue would suffice to hold the bottom two deciles of households by income harmless, 18

percent would be enough to protect the bottom three deciles, and 35 percent would suffice to 

cover the entire bottom half of households.562 Carbon tax revenues would enable states to fully 

compensate lower-income households for these regressive effects; states could return this 

revenue by any one of a number of mechanisms, such as lump-sum payments via Electronic 

Benefits Transfer or reductions in state income or other regressive taxes. States could also 

direct carbon tax proceeds to EE programs in low income communities, offsetting any electricity 

rate increases with reduced consumption. 

While cap and trade also generates such revenues (as does ISO-pricing, discussed 

below), a tax has decided advantages over each. A tax is economically more efficient than a cap 

and trade system because (1) it provides price certainty as opposed to the fluctuating cost for 

cap and trade allowances,563 and (2) there is no market for permits that is subject to 

manipulation: “The great potential for fraud attendant on such a system creates significant 

doubt about its effectiveness, as experience has shown in both theory and practice in the 

gyrations of the European ETS.”564 A carbon tax is also administratively superior. A tax requires 

emission reporting and arithmetic; a cap and trade system requires the state to allocate 

allowances, conduct auctions, create an allowance registry, monitor trades and positions, and 

possibly enforce a price floor/ceiling. Moreover, a state could easily expand a tax to cover any 

additional source categories that were regulated under section 111(d); in contrast, it is unclear 

how states could add new source categories to existing cap-and-trade programs. Because the 

Act requires compliance for each source category, states would presumably have to set up 

separate cap-and-trade programs for each regulated source category.

 

561 Mathur & Morris, Brookings Inst., Distributional Effects of A Carbon Tax in Broader U.S. Fiscal Reform

(Dec. 14, 2012), available at 

http://www.brookings.edu/~/media/research/files/papers/2012/12/14%20carbon%20tax%20fiscal%20r

eform%20morris/14%20carbon%20tax%20fiscal%20reform%20morris.pdf, at 6.

562 Id. at 14. 

563 Mankiw, N. G., Smart Taxes: An Open Invitation to Join the Pigou Club, 35 Eastern Economic Journal 

14-23 (2009), available at http://scholar.harvard.edu/files/mankiw/files/smart_taxes.pdf, at 18.

564 Green et al., Am. Enterprise Inst., Climate Change: Caps vs. Taxes (June 2007), at 5.
200

A carbon tax also has advantages over another carbon pricing compliance mechanism 

proposed by Great River Energy and the Brattle Group (“ISO pricing”).565 ISO pricing involves 

ISOs imposing a carbon price on affected EGUs via the bid mechanisms used for wholesale 

electricity markets, which is an economically efficient means of incentivizing dispatch. However, 

this approach has the political problem of potential transfers from rate payers in one state to 

out-of-state entities; a state carbon tax ensures that the revenues remain in-state. A second 

problem is that many states are only partially covered by an ISO; some have more than one, 

some have one or more in addition to areas without an ISO, and some states have no ISO at all.

Addressing such situations in a SIP would greatly increase complexity. And even if ISO pricing 

worked for EGUs, it cannot be extended for any other section 111(d) source categories.

A carbon tax does not eliminate the risk, inherent in the compliance flexibility that 

characterizes the Clean Power Plan, that fenceline communities near dirty power plants will not 

benefit from the co-pollutant reductions that the proposal promises. It offers the possibility, 

however, that revenues could be used to finance co-pollutant reductions in those communities 

as described in section VII.H.3.d of these comments. We urge EPA to adopt those 

recommendations. Moreover, as discussed in section VII.F, EPA would need to make clear that 

a tax approach is not allowable for hotspot pollutants. 

3. Modeling Carbon Tax for Compliance is Similar to Other SIP Modeling

A state choosing the carbon tax option will have to submit modeling that shows how the 

tax will produce the emissions reductions attributed to it under the state’s plan. Modeling the 

emissions effects of regulatory measures is regularly relied on in the SIP process, and the Act 

specifically contemplates its use there (and throughout the Act), e.g., 42 U.S.C. §§ 7410(a)(2)(K), 

7412(k)(3)(D) and (G), 7475(e)(3)(D), 7491(a)(3)(B), 7502(c)(8).

Modeling the emissions effects of a carbon tax is a relatively simple two-step process, 

first calculating the effect of an EGU carbon tax on electricity prices, and then modeling the 

effect of that price increase on generation mix, electricity demand and resulting CO2 reductions.

Electricity pricing and generation demand models are ubiquitous; for example, EPA used the 

IPM model for estimating the costs of this rule, 79 Fed. Reg. at 34,839, and EPA specifically used 

the IPM model to determine the effect of a carbon price to calculate Building Block 2 of the 

BSER – redispatch from coal-fired to natural gas combined cycle power plants – by simulating a 

carbon price of $30/ton.566

 

565 Chang et al., The Brattle Group, A Market-Based Regional Approach to Valuing and Reducing GHG 

Emissions from Power Sector (Apr. 2014), available at 

http://www.brattle.com/system/news/pdfs/000/000/616/original/A_Marketbased_Regional_Approach_to_Valuing_and_Reducing_GHG_Emissions_from_Power_Sector.pdf, at 2-4.

566 Abatement Measures TSD at 3-24.
201

Carbon tax compliance is most easily measured using a mass-based emissions target; 

elsewhere in these comments, we propose a methodology for converting state goals from ratebased to mass-based.

B. The Proposed Rule Preamble Allows for a State Carbon Tax as a Means of Compliance

EPA’s Preamble to the proposed rule emphasizes the flexibility that states will have in 

choosing the means by which they will comply with their targets:

EPA believes that this proposal provides flexibility for states to develop plans 

that align with their unique circumstances, as well as their other environmental 

policy, energy and economic goals. All states will have the opportunity to shape 

their plans as they believe appropriate for meeting the proposed CO2 goals.

79 Fed. Reg. at 34,834. The proposal provides states with latitude to employ a wide range of 

measures, so long as they do the job. Id. at 34,835. Since a carbon tax reduces emissions by 

putting a price on them, they are identical in this respect to “market-based emission limits” that 

EPA specifically describes as acceptable means of compliance, such as the RGGI and AB 32 cap 

and trade systems, e.g.,

[The RGGI] market creates a price signal for CO2 emissions, which factors into the 

dispatch of affected EGUs. A price signal for CO2 emissions also allows sources 

flexibility to make emission reductions where reduction costs are lowest, and 

encourages innovation in developing emission control strategies.

Id. at 34,848

As EPA notes in its State Plan Considerations TSD, “the allowance market establishes a 

price signal for emissions (a market price for emitting a unit of pollution), which triggers broad 

economic incentives for reducing emissions across the covered sector(s) and encourages 

innovation in developing emission control strategies and new pollution control 

technologies.”567 A carbon tax is economically analogous to a cap-and-trade system: both 

encourage regulated entities to change their production processes to reduce emissions to avoid 

paying the emissions-based fee. By raising these costs, a carbon tax thus reduces the incentive 

to burn fossil fuels in exactly the same way that cap and trade does. (However, as noted above, 

a tax is both economically more efficient and administratively simpler than cap and trade.) 

 

567 SPC TSD at 101.
202

C. A Carbon Tax Meets All of the Proposed Regulatory Criteria for a State Plan

While a carbon tax may not meet the proposed definition of an “emission standard,” it 

nevertheless meets all of the required criteria for an “emission standard.” Proposed 40 C.F.R. § 

60.5780(a) requires that each state plan include:

emission standard(s) that are quantifiable, verifiable, non-duplicative, 

permanent, and enforceable with respect to each affected entity. The plan shall 

include the methods by which each emission standard meets each of the 

following requirements in paragraphs (b) through (f) of this section.568

Subsection (b) provides that an emission standard is “quantifiable . . . if it can be reliably 

measured, in a manner that can be replicated.” A carbon tax is the essence of a quantifiable 

emission standard: $X per ton of CO2 emissions. 

Subsection (c) provides that an emission standard is “verifiable with respect to an 

affected entity if adequate monitoring, recordkeeping and reporting requirements are in place 

to enable the state and the Administrator to independently evaluate, measure, and verify 

compliance with the emission standard.” EPA’s Greenhouse Gas Reporting Rule requires 

continuous CO2 emission monitoring of every affected EGU, reporting of those results, and 

imposes stringent recordkeeping requirements. In addition, the proposed Rule itself imposes 

this requirement: proposed § 60.5805(a)(2)(i) requires that “[a]n affected EGU must install, 

certify, operate, maintain, and calibrate a CO2 continuous emissions monitoring system (CEMS) 

to directly measure and record CO2 concentrations in the affected EGU exhaust gases emitted 

to the atmosphere and an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) 

of this chapter.”

Subsection (d) provides that an emission standard is “nonduplicative with respect to an 

affected entity if it is not already incorporated as an emission standard in another state plan 

unless incorporated in multi-state plan.” No state imposes—or could impose—a carbon tax on 

emissions in another state.

Subsection (e) provides that an emission standard is “permanent with respect to an 

affected entity if the emission standard must be met for each compliance period, or unless it is 

replaced by another emission standard in an approved plan revision, or the state demonstrates 

in an approved plan revision that the emission reductions from the emission standard are no 

longer necessary for the state to meet its state level of performance.” A state carbon tax would 

require the affected EGU to pay the tax until such time as it is modified or replaced by an 

approved plan revision. 

 

568 Proposed 40 C.F.R. § 60.5740(a)(6) similarly requires that a state plan contain “[a] demonstration that 

each emission standard is quantifiable, nonduplicative, permanent, verifiable, and enforceable with 

respect to an affected entity.”
203

Finally, subsection (f) provides that an emission standard is “enforceable against an 

affected entity if”:

(1) A technically accurate limitation or requirement and the time period for the 

limitation or requirement is specified;

(2) Compliance requirements are clearly defined;

(3) The affected entities responsible for compliance and liable for violations can be 

identified;

(4) Each compliance activity or measure is enforceable as a practical matter; and

(5) The Administrator and the state maintain the ability to enforce violations and secure 

appropriate corrective actions pursuant to sections 113(a) through (h) of the Act.

A carbon tax meets each of these criteria. It is imposed on each affected EGU at a fixed 

rate of $X per ton of CO2 emissions, payable at a fixed interval (presumably annually) to the 

state in an amount equal to the rate/ton multiplied the amount of emissions. Due to the 

monitoring requirements already imposed under the Reporting Rule, determining compliance 

could not be easier, and a carbon tax is enforceable through each of the mechanisms 

(administrative order, administrative penalty, civil judicial action and criminal action) described 

in CAA section 113.

There is no obstacle to federal government enforcement of a state carbon tax that has 

been incorporated into an approved SIP; federal restrictions such as the Tax Injunction Act 

provide only that federal courts “shall not enjoin, suspend or restrain the assessment, levy or 

collection of any tax under State law”; such laws have “nothing to do with complaints that 

federal courts are causing or allowing states to collect too much money in taxes.” Dunn v. 

Carey, 808 F.2d 555, 558 (7th Cir. 1986) (emphasis in original).

The Act also permits citizen enforcement of a carbon tax. Citizens may sue for violation 

of “an emission standard or limitation under this chapter.” 42 U.S.C. § 7604(a). The Act defines 

“[e]mission standard or limitation under this chapter” to include “any requirement 

under section [111] or [112] of this title (without regard to whether such requirement is 

expressed as an emission standard or otherwise)”; and “any other standard, limitation, or 

schedule established under . . . any applicable State implementation plan.” Id. at § 7604(f)(3) 

and (4). Not only do the regulations deem state measures to be “emission standards”, but a 

state EGU carbon tax could also be deemed “a requirement under section 111” or a “standard” 

or “limitation” established under a SIP. Because the tax itself and the emissions it would be 

applied to have fixed, numerical values, courts would not have the problem sometimes 

encountered in attempts to enforce narrative SIP requirements or goals. See, e.g., Bayview 

Hunters Point v. Metro. Trans. Comm’n, 366 F.3d 692, 701 (9th Cir. 2004)(discussing “the wellestablished rule that courts may only enforce specific SIP strategies, and may not enforce a 

SIP's overall objectives or aspirational goals.”)
204

An issue related to enforceability is what should happen in the event that the tax does 

not achieve the required reductions in any of the relevant periods. Specifically, EPA requested 

comment on:

whether consequences should include the triggering of corrective measures in 

the state plan, or plan revisions to adjust requirements or add new measures. 

The agency also requests comment on whether corrective measures, in addition 

to ensuring future achievement of the state goal, should be required to achieve 

additional emission reductions to offset any emission performance deficiency 

that occurred during a performance period for the interim or final goal.

79 Fed. Reg. at 34,908.

We believe that the best way to deal with this situation in the case of a carbon tax is to 

have the state plan (and the underlying state legislation) provide that, in the event of such an 

emissions reduction shortfall, the tax rate would rise by a specific amount, with the rate 

increase determined by a formula based on the amount of the shortfall. This would allow for 

planning certainty among the affected EGUs and minimum disruption in implementing the 

remedial measure. As a backstop, the rules should require the plan to also include specific 

remedial regulatory mandates adequate to ensure achievement of the target level of 

reductions, such as required emissions reductions from covered EGUs, which would 

automatically take effect if an automatic tax increase mechanism then failed to meet the state 

target. 

Equally important as whether the carbon tax as a regulatory mechanism is quantifiable, 

verifiable, non-duplicative and enforceable, is the question of whether that mechanism will 

result in emissions reductions that meet those criteria. The state’s compliance demonstration 

would need to show that the state was achieving the state goal. Moreover, the automatic 

backstop of an even higher tax rate or regulatory mandates should the state not be in 

compliance should eliminate the possibility of any individual reductions being reversed.

D. Regulatory Language and a Carbon Tax

1. EPA’s Proposed Revisions to Subpart B 

EPA proposes requiring that each state plan include “[i]dentification of emission standards 

for each affected entity, compliance periods for each emission standard, and demonstration 

that the emission standards are, when taken together, sufficiently protective to meet the state 

emissions performance level.” 60.5740(a)(5); 79 Fed. Reg. at 34,952. 

Currently Subpart B defines “emission standard” as “a legally enforceable regulation setting 

forth an allowable rate of emissions into the atmosphere, establishing an allowance system, or 

prescribing equipment specifications for control of air pollution emissions.” 40 C.F.R.
205

§ 60.21(f).569 A carbon tax does not meet this definition, and while EPA has proposed a different 

definition for purposes of the specific rule at issue here, a carbon tax does not appear to meet 

that definition either: 

Emission standard means in addition to the definition in § 60.21, any 

requirement applicable to any affected entity other than an affected source that 

has the effect of reducing utilization of one or more affected sources, thereby 

avoiding emissions from such sources, including, for example, renewable energy 

and demand-side energy efficiency measures requirements.

79 Fed. Reg. at 34,956. The proposed definition presents two problems. First is the introduction 

of a term – “affected source” – that is not defined anywhere in the statute or regulations. EPA 

does define “affected EGU” as “a steam generating unit, an IGCC facility, or a stationary 

combustion turbine that meets the applicability conditions in section § 60.5795.” Id. The 

“applicability conditions” in 60.5795(b) relate to base load ratings, fuels, whether the EGU “was 

constructed for the purpose of supplying” certain amounts of its output to a “utility distribution 

system”, etc. Id. at 34,954. EPA appears to use “affected source” to mean “affected EGU”, e.g., 

“the affected sources -- utility boilers and IGCC units as well as natural gas-fired stationary 

combustion turbines -- . . . .” Id. at 34,855. Note also that EPA proposes to define “affected 

entity” as either “an affected EGU, or another entity with obligations under this subpart for the 

purpose of meeting the emissions performance goal requirements in these emission 

guidelines.” Id. at 34,956.

The more significant problem is the proposed definition’s phrase “other than an 

affected source”. Defining “emission standard” to broadly mean “anything that reduces 

emissions from affected entities” would certainly include a carbon tax, but by then carving out 

the EGUs – the “affected sources” – it leaves the newly-broadened definition applicable only to 

those non-EGU entities that have obligations under this rule. (As discussed previously, we 

believe that the Act requires that, as the regulated entities in this source category, the affected 

EGUs must be legally responsible for achieving the state targets.) In other words, as proposed 

this provision does not appear to include a state carbon tax on affected sources as an “emission 

standard”.

2. Suggested Changes to Subpart B 

We suggest that EPA amend its proposed regulations to allow states the option of imposing 

a carbon tax as part of §111(d) plans to comply with the standard of performance for carbon 

emissions from power plants. 

 

569 The clause “establishing an allowance system” was added in the CAMR rule, 70 Fed. Reg. at 28,606, 

28,649 (May 18, 2005), but the CAMR Rule was vacated in its entirety by New Jersey v. EPA, 517 F.3d 

574 (D.C. Cir. 2008).
206

EPA could accomplish such a result by deleting the phrase “other than an affected 

source” from the proposed definition in 60.5820, as illustrated in strikethrough: 

Emission standard means in addition to the definition in § 60.21, any 

requirement applicable to any affected entity other than an affected source that 

has the effect of reducing utilization of one or more affected sources, thereby 

avoiding emissions from such sources, including, for example, renewable energy 

and demand-side energy efficiency measures requirements.

X. The Clean Power Plan’s Impacts on Upstream Emissions from Fossil Fuel Production

EPA projects that the Clean Power Plan will increase electricity sector natural gas 

consumption through at least 2025.570 The additional gas consumed during this time period will 

stimulate additional natural gas production, which will increase methane and other GHG 

emissions associated with natural gas production and transmission.571 EPA predicts, however, 

that increased methane emissions from natural gas production will be outweighed by 

decreased methane emissions from coal production. In reaching this conclusion, however, EPA 

has substantially understated the amount of methane that will be emitted by this additional gas 

production, and thus the importance of taking action to limit these emissions. The best way to 

limit these emissions is to ensure that renewable energy and energy efficiency, rather than gasfired generation, play the greatest possible role in future electricity generation. It is also 

essential to take strong steps to reduce methane pollution from natural gas production and 

transmission. Thus, to ensure that the Clean Power Plan achieves its full potential as the 

cornerstone of President Obama’s Climate Action Plan, EPA must reduce methane emissions 

from the gas sector by directly regulating methane. In addition, federal action is needed to 

ensure that decreased electricity sector demand for coal leads to corresponding decreases in 

coal production, rather than a shift to coal exports, which would undermine EPA’s conclusion 

regarding a net decrease in methane emissions.

A. The RIA Understates The Amount of Methane Emitted by Natural Gas Production.

As noted above, the RIA predicts that, in all scenarios, the Clean Power Plan will increase 

gas generation in 2020 and 2025, and that this additional gas generation will lead to an increase 

in gas production572 and associated methane emissions.573 The starting point for the RIA’s 

analysis of upstream methane is EPA’s Greenhouse Gas Inventory. According to this Inventory, 

the oil and gas sector is already the third-largest industrial source of greenhouse gas pollution, 

and the largest source of methane emissions.574 In order to assess the impact of changes in 

 

570 RIA at 3-47, Table 3-11 (predicting increased gas use relative to baseline in 2020 and 2025 in all 

scenarios).

571 Id. at Table 3A-6, page 3A-9.

572 Id. at Tables 3A-4 and 3A-5.

573 Id. at Table 3A-6.

574 EPA, supra n. 22, at Table 2-1.
207

production it is useful to look at the emissions per unit of gas production, rather than for the 

whole sector. These emissions are often expressed as a “leak rate” of methane emitted per unit 

of gas produced. The recent EPA Inventories imply a natural gas leak rate of roughly 1.4 

percent.575 The RIA’s estimates of future gas production emissions begin with the Inventory’s 

estimate of current emissions and then add projections for future voluntary and regulatory 

reductions in emissions.576

By using the Inventory as its starting point, the RIA almost certainly significantly 

understates the methane that will be emitted by increased gas production. A growing body of 

published, peer-reviewed research strongly indicates that methane emissions from natural gas 

production are significantly higher than estimated by EPA’s 2013 Greenhouse Gas Inventory, 

which formed the basis for the RIA’s discussion of this issue.577 EPA’s GHG Inventories, like the 

National Energy Technology Laboratory assessment, uses “bottom-up” methods. These 

methods estimate the average emissions from an individual piece of equipment or individual 

event, such as a high-bleed pneumatic device or a well completion, and multiply that percomponent value by an estimate of the total number of components or events of that type. 

A different method of estimating gas production methane emissions is a “top down” 

approach, where researchers measure the methane accumulation in the atmosphere in areas 

where gas production is occurring and then estimate the fraction of this methane attributable 

to gas production. For example, a researcher might measure methane concentrations upwind 

and downwind of gas activity and then subtract out the methane estimated to have been 

emitted from other sources. Certainty in source attribution has increased in recent years as 

scientists are better able to distinguish methane sources based on detected levels of cooccurring compounds such as ethane or isotopic composition of atmospheric methane.

 

575 The RIA relies on EPA’s 2013 Inventory, which estimated emissions through 2011. See RIA at 3A-31. 

The 2013 Inventory implied a leak rate of 1.4 percent of gross withdrawals. Brandt et al., Methane Leaks 

from North American Natural Gas Systems, 343 Science 6172 (Feb. 14, 2014), available at 

http://www.novim.org/images/pdf/ScienceSupplement.02.14.14.pdf,

Supplementary Information at 29. In April 2014, EPA released the updated 2014 Inventory cited above. 

The Department of Energy has determined that the 2014 Inventory also implies that that “roughly 1.4 

percent of [natural gas] is vented routinely or leaked . . . throughout the natural gas supply chain.” Dep’t 

of Energy, Fact Sheet: Natural Gas Greenhouse Gas Emissions (July 29, 2014), available at 

http://energy.gov/sites/prod/files/2014/07/f18/20140729%20DOE%20Fact%20sheet_Natural%20Gas%

20GHG%20Emissions.pdf. The National Energy Technology Laboratory (“NETL”) has similarly estimated 

that, when looking at total domestic natural gas deliveries (including onshore and offshore production) 

to power plants (i.e., omitting much of the distribution sector), leaked methane equals 1.1 percent of 

production. NETL, Life Cycle Analysis of Natural Gas Extraction and Power Generation, DOE/NETL2014/1646 (May 29, 2014) (“NETL Lifecycle Report”), available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Life%20Cycle%20Analysis/NETLNG-Power-LCA-29May2014.pdf, at 36.

576 RIA at 3A-1 to 3A-2, 3A-15 to 3A-30.

577 Id. at 3A-31.
208

An early top-down study, Xiao et al. (2008), estimates that nationwide emissions of 

methane from fossil fuel sources in 2004 were 50 to 100 percent higher than bottom-up 

inventories estimate.578 More recently, Miller et al. (2013), uses atmospheric measurements of 

methane in 2007 and 2008 to estimate that methane emissions from all U.S. sources were 50

percent higher than estimated for that year by the 2012 U.S. GHG Inventory. The study shows 

that oil and gas emissions constitute a significant portion of the observed emissions not 

accounted for in EPA’s Inventory.579 Atmospheric studies examining individual regions have 

found even higher methane emissions in the regions studied. Two studies of Colorado’s DenverJulesberg Basin have concluded that during gas production alone (not including emissions from 

downstream segments of the industry - transmission and distribution), the gas leak rate was 

about 4 percent.

580 The same team of researchers found even higher methane leak rates in 

Utah’s Uinta Basin, estimating escaped methane at 9 ± 3 percent of total production.581 Brandt 

et al. (2014) systematically reviews eleven top-down and a number of bottom-up studies, 

including the studies discussed above (with the exception of Petron et al (2014), which was not 

published at the time of Brandt et al’s review). Brandt et al. demonstrates that for many years 

top-down studies have very consistently shown higher emissions from oil and gas than do 

bottom-up studies. The authors estimate that total U.S. methane emissions from all sources 

were 25 to 75 percent higher than the U.S. GHG Inventory estimated for 2011, and find that oil 

 

578 Xiao et al. Global budget of ethane and regional constraints on U.S. sources, 113 J. of Geophysical 

Research D21,306 (Nov. 5, 2008), available at 

http://onlinelibrary.wiley.com/doi/10.1029/2007JD009415/abstract. Xiao’s result was based on a 2008 

edition of the US GHG Inventory; the latest edition estimates that 2004 emissions were 17 percent 

higher than the 2008 edition estimated, a small difference compared to the 50-100 percent difference 

reported by this paper.

579 Miller et al., Anthropogenic emissions of methane in the United States, 110:50 Proc. Natl. Acad. Sci. 

(USA) 20,018 (Oct. 18, 2013), available at http://www.pnas.org/content/110/50/20018. Specifically, the 

paper states that in moving from the 2012 Inventory to the 2013 Inventory, EPA “decreased its CH4

emission factors for fossil fuel extraction and processing by 25 to 30 percent (for 1990–2011), but we 

find that CH4 data from across North America instead indicate the need for a larger adjustment of the 

opposite sign.” Id. The 2012 Inventory implied a leak rate of approximately 2.4 percent; a 25 percent 

increase brings the leak rate to three percent.

580 The four percent estimate is provided by the more recent of these studies, Petron et al., A new look 

at methane and non-methane hydrocarbon emissions from oil and natural gas operations in the 

Colorado Denver-Julesburg Basin, 119:9 J. of Geophysical Research: Atmospheres 6836 (June 3, 2014), 

abstract available at http://onlinelibrary.wiley.com/doi/10.1002/2013JD021272/abstract. This is 

consistent with an earlier study, by the same lead author, which estimated using top-down techniques 

that 2.3 to 7.7 percent of production was vented in the studied area and concluded more generally that 

“the methane source from natural gas systems in Colorado is most likely underestimated by at least a 

factor of two.” Petron et al., Hydrocarbon emissions characterization in the Colorado Front Range: A 

pilot study, 117:D4 J. Geophys. Res. Atmospheres 4304 (Feb. 21, 2012), abstract available at

http://onlinelibrary.wiley.com/doi/10.1029/2011JD016360/abstract.

581 Karion et al., Methane emissions estimate from airborne measurements over a western United States 

natural gas field, 40:16 Geophysical Research Letters 4393 (Aug. 27, 2013), abstract available at

http://onlinelibrary.wiley.com/doi/10.1002/grl.50811/abstract. 
209

and gas are important contributors to these unreported emissions.582 These top down studies 

provide compelling evidence that the aggregate methane emission estimates based on “bottom 

up” studies, such as the estimates used by the RIA as a starting point here, underestimate oil 

and gas sector methane emissions by a significant margin.

We further note that the RIA does provide quantitative information regarding the future 

emission reductions (voluntary and regulatory) that it assumes will be employed to reduce 

emissions below this starting point. As such, we do not offer comment as to the 

appropriateness of these assumptions.

B. Methane Emissions from Gas Systems Reinforce the Importance of Renewable Energy, 

Energy Efficiency, and Regulation of Methane, Whether or Not The Clean Power Plan 

Will Lead to Net Decreases in Methane Emissions.

While EPA predicts that the Clean Power Plan will increase gas production in 2020 and 

2025, the Clean Power Plan will, of course, likely decrease coal production for domestic 

consumption. The RIA’s predictions regarding upstream methane emissions address changes in 

both coal and gas production. On a per-KWh basis, upstream methane and other non-EGUcombustion emissions associated with natural gas fired electricity generation are significantly 

higher than the corresponding emissions from coal fired generation.583 The RIA predicts that in 

all Clean Power Plan scenarios, however, the decrease in coal generation will be greater than 

any increase in natural gas generation.584 On this basis, the RIA predicts that decreases in 

methane from coal production will exceed increase in methane from gas production in 2020 

and 2025.585 For the reasons stated above, we believe the RIA significantly understates 

methane emissions from natural gas systems. 

While it may be the case that, under the production levels predicted by the RIA, the 

Clean Power Plan will reduce net methane emissions below EIA projected levels in 2025 and 

beyond, a reduction in coal mining methane emissions does not change the fact that methane 

emissions from natural gas systems are a significant contributor to climate change that EPA 

must address. Even if, as the RIA predicts, the Clean Power Plan will uniformly result in net 

decreases in methane emissions, methane from natural gas systems is another source of 

emissions, and thus a source of potential emission reductions, that cannot be ignored.

The most effective and important way to limit the emissions from natural gas systems is 

to limit reliance on natural gas by utilizing renewable energy and energy efficiency as fully as 

possible. Isolated comparison of coal and gas power plant emission rates, and thereby ignoring 

 

582 Brandt, supra n. 575, at 733.

583 Id. at Fig. 4-13. This table compares upstream emissions on a heat content, rather than KWh, basis, 

and therefore does not reflect the greater thermal efficiency of natural gas fired generation.

584 RIA at Table 3-11.

585 RIA at Tables 3A-6 and 3A-7. In 2030 under Option 1, both coal production and gas production 

decrease relative to the base case.
210

the full fuel life cycle, significantly overstates the climate benefit of switching from coal to gas. 

This is doubly true when one considers the recent peer reviewed science indicating that EPA 

significantly underestimates both the tonnage of methane emitted per unit of gas production 

and the climate impact of each ton of methane. As we explained above, numerous top down 

and other studies indicate that actual methane emissions from natural gas systems are much 

higher than estimated by EPA’s GHG inventories. This error is compounded by the RIA’s use of 

an outdated methane global warming potential of 25 on a 100-year timescale.586 This estimate 

is taken from the Intergovernmental Panel on Climate Change’s Fourth Assessment Report. The 

more recent Fifth Assessment Report, released in pertinent part in September 2013, estimates 

that that on the 100-year time scale, a ton of fossil methane has a climate impact 36 times 

greater than a ton of carbon dioxide.587 On a twenty year timescale, the IPCC now estimates 

that a ton of fossil methane emissions has 87 times the impact of a ton of carbon dioxide. 

Because gas fired electricity generation emits more tons of methane per KWh than coal fired 

generation, adopting a higher methane global warming potential further erodes gas’s climate 

advantage over coal. As zero-emitting resources, EE and RE have a tremendous advantage over 

all fossil fuels—including natural gas—from a climate perspective.

Second, to the extent that natural gas is used, EPA must regulate methane emissions 

from gas systems to reduce these lifecycle impacts.588 If, as the RIA predicts, the Clean Power 

Plan increases gas use and production in 2020 and 2025, this will increase the need for prompt 

direct regulation of methane. The fact that the RIA predicts a decrease in gas use under Option 

1 in 2030 does not limit the need for methane regulation. Despite the net decrease, the RIA 

predicts continuing wide use of natural gas in the electricity sector in 2030. Moreover, because 

methane is such a potent greenhouse gas, the increase in emissions in the earlier years of the 

plan will have a significant climate impact.

C. The Projected Decreases in Coal Mining Methane Emissions Will Not Occur if Coal 

Exports Substitute for Decreased Electricity Sector Coal Demand.

EPA acknowledges that, absent further action, increased coal exports may offset the 

decrease in electricity sector coal consumption, limiting the net decrease in coal production and 

associated methane emissions.589 EPA has not, however, included this possibility in its modeling 

or other discussion. In finalizing its regulatory analysis, EPA should at the very least attempt to 

address whether U.S. coal producers would be able to secure international buyers on the coal 

export market to make up for part or all of the reduced domestic demand. Given that industry 

continues to pursue new coal export terminals (as well as increased capacity through existing 

ports) in California, Louisiana, and Oregon, among other places, it seems very likely that any 

 

586 RIA at 3A-5, 3A-9, 3A-10.

587 IPCC, supra n. 2, at 714, Table 8.7. 

588 Cost-effective methods of reducing methane emissions from oil and gas extraction are discussed in 

McCabe et al., Clean Air Task Force, Waste Not: Common sense ways to reduce methane pollution from 

the oil and natural gas industry (Nov. 2014), summary report attached as Ex. 64.

589 RIA at 3A-10.
211

reduction in U.S. coal consumption as a result of EPA's rulemaking would be offset somewhat 

by an increase in coal exports. Since that offset would affect the amount of coal produced and 

the amount of methane emitted from U.S. coal mines, EPA ought to take a serious look at all 

relevant market forces rather than merely qualify its findings under an "uncertainties and 

limitations" disclosure.

In addition, the Administration must consider efforts to limit the potential for coal 

exports to undercut the emission reductions that would otherwise be achieved by the Clean 

Power Plan. For example, as the Clean Power Plan decreases domestic coal demand, the Bureau 

of Land Management could decrease coal leasing on federal lands to commensurately decrease 

supply.

XI. Reliability

As the power grid transitions to a cleaner and more sustainable future, several groups

have raised concerns over the number of projected retirements of covered units the new GHG

standards may necessitate, and how such retirements would affect the “reliability” of the

power grid. The concern that the Clean Power Plan will undermine the ability of utilities and

regional grid operators to reliably provide electricity to consumers is unfounded. Each time EPA

undertakes rulemakings affecting the electric generating sector, naysayers cry that the lights

will go out, yet each of EPA’s actions to reduce pollution from these sources results in a cleaner

environment and an intact electric grid.

The Clean Power Plan is no exception. The cooperative federalism model that forms the

basis of the CPP allows states to design their plans to minimize disruptive impacts on the grid.

We are therefore confident that states working in conjunction with regional grid operators will

be able to ensure a smooth transition to a cleaner and more efficient power grid over the next

five to fifteen years.

In particular, we oppose two specific policy recommendations made by utilities and

operators: first, to delay implementation of the CPP, which would further delay our necessary

transition to new and cleaner power sources; and second, to include a “reliability safety valve,”

which would in effect reward the utilities and affected EGUs who drag their feet and allow

them to continue emitting large amounts of greenhouse gases. However, we join with these

grid operators and other commenters in calling on EPA to encourage advanced planning for

anticipated supply shifts, and especially to facilitate cooperation between states and regional

and local grid operators when implementing the CPP.

A. Identified Reliability Needs and Solutions

When energy experts refer to maintaining the “reliability” of the grid, they generally are

grouping together multiple attributes of the energy distribution system required to keep

electricity flow stable and predictable. These attributes can be split roughly into three different

types of “reliability”: 1) overall resource adequacy, 2) voltage and frequency stability, and 3)
212

resilience against large system shocks. Certain regional grid operators have raised particular

concerns about the ability of a restructured energy system to provide each of these types of

reliability.

In this section, we identify the perceived challenge, provide our evaluation of its

severity, and lay out solutions to the challenge. The conclusion reached throughout this section

is that, although grid operators have come to rely on large traditional power providers to keep

power flowing to consumers, with proper advanced planning they have a plethora of solutions

available to them to meet those needs that don’t require continued reliance on high-emitting

power plants.

1. Resource Adequacy

Resource adequacy refers to the presence (or absence) of sufficient electricity supply

(including “negawatts” from efficiency and demand response) to meet the anticipated

electricity demand in the course of a typical day. This reliability attribute ultimately rests on

bulk power capacity, and the ability of that capacity to predictably produce electricity.

The primary basis for the concerns raised about over overall system capacity is the rate

of anticipated retirements of coal-burning power plants. EPA has calculated that

implementation of the CPP could lead to retirement of an additional 50 GW of coal-based

electricity production over the base case by 2025.590 According to EPA’s BSER formula, lost

generation will be replaced through a combination of capacity factor increases at gas facilities,

increased generation from renewable energy resources, and demand-side energy efficiency.

Renewable generation and efficiency improvements would also replace lost capacity, along

with increased electricity storage and demand response, as discussed further below.

One of the broadest critiques of EPA’s overall calculations has come from NERC, in its

Initial Reliability Review.591 In particular, NERC questions the viability of EPA’s proposed

renewable energy, transmission, and energy efficiency build-out goals. These critiques paint a

needlessly pessimistic view of what is achievable, and run contrary to several studies

demonstrating the potential for renewable energy and energy efficiency to replace existing

generation.

 

590 Some commenters have suggested that the EPA’s expected heat-rate improvements are infeasible, 

and that therefore more coal-burning power plants will need to retire than EPA anticipates. As noted 

elsewhere in these comments, we believe a 9 to 10 percent heat rate improvement requirement is 

justified, but even if certain states or plants cannot meet the 6 percent rate, the flexibility inherent to 

the CPP process will allow them to achieve extra emission reductions elsewhere. 

591 NERC, Potential Reliability Impacts of EPA’s Proposed Clean Power Plan (Nov. 2014) [hereinafter NERC 

Reliability Review].
213

a. Potential for Renewable Generation Build-out

One of NERC’s two main arguments challenging EPA’s expectations for build-out of

renewable power facilities is that EPA’s renewable portfolio standard (RPS)-based formula

overestimates states’ ability to build renewable generation.592 While NERC is correct that the

use of existing RPSs to establish renewables obligations does not perfectly correspond to states’

actual capacity to install wind and solar plants, we believe it understates the potential for

renewable generation build-out, thus artificially lowering states’ renewables obligations. In fact,

EPA’s RPS-based Building Block 3 target barely exceeds the “business as usual” forecasts for

renewable energy development by 2030.593 Thus, EPA’s target is not pushing states toward an

unprecedented level of renewable energy development, but rather toward the level of

renewable energy generation that grid operators should already be forecasting and planning

for. 29 states (including the District of Columbia) have passed mandatory RPS goals, and

another 7 states have voluntary goals. One study looking at states’ compliance with their own

goals found that 21 of 24 states for which data was available had virtually achieved or exceeded

their intermediate RPS goals. 594 (A few states have even exceeded their ultimate RPS goals.595)

Critically, states have historically found it easier to comply with RPS goals over time as

they develop in-state markets and build local expertise in siting and connecting renewable

electricity.596 This trend should only continue as renewable energy becomes more and more

affordable: in 2013, average prices for utility-scale wind and solar power purchase agreements

dropped to all-time lows of $21 and $50 per megawatt-hour respectively, compared to average

whole sale power prices of between $22 and $55 overall.597 Similarly, the Energy Information

Administration’s estimate of the total levelized cost of energy by resource, including installation

and other costs, predicts that wind will be over $15 cheaper than coal per MWh by 2019, and

$8 cheaper than conventional natural gas by 2040. 598 A projection done by Lazard Ltd., a

financial advisory and asset management firm, has concluded that already today wind energy is

at least cost-competitive with, if not cheaper than, both natural gas and coal facilities, with

solar not far behind (within $10/MWh of both gas and coal).599 The consensus expectation in all

 

592 Id. at 11-12.

593 See UCS, supra n. 183.

594 Leon, W., Clean Energy States Alliance, The State of State Renewable Portfolio Standards (June 2013), 

attached as Ex. 65; Barbose, G., LBNL, Renewables Portfolio Standards in the United States: A Status 

Update (Dec. 3, 2012), at 24.

595 Climate Central, Interactive Map Compares States’ Renewable Energy Goals, 

http://www.climatecentral.org/blogs/interactive-map-to-compare-states-renewable-energy-goals (last 

visited Nov. 24, 2014).

596 Leon, supra n. 594, at 6-7.

597 DOE, supra n. 194; Bolinger & Weaver, LBNL, Utility-Scale Solar 2013: An Empirical Analysis of Project 

Cost, Performance, and Pricing Trends in the United States (Sep. 2014), attached as Ex. 66, at 28.

598 EIA, Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy 

Outlook 2014 (Apr. 17, 2014) [hereinafter EIA Outlook], available at 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.

599 Lazard, supra n. 172, at 2.
214

of these reports is that renewable energy prices will continue to drop as renewable

technologies continue to be mainstreamed.600 In short, the market for renewable energy has

surged in a way that was not fully anticipated when states set their RPS goals, so they are no

longer an accurate reflection of what can be accomplished in individual states.

Even ignoring the growing strength and competitiveness of the renewable generation

market, EPA should not be overly concerned about replacing retiring coal plants because

regions with excess (largely cleaner) electricity production will likely end up transmitting that

electricity to regions that find themselves less able to replace retiring dirty power plants (see

transmission discussion below). Moreover, no state is required to achieve the level of

renewable energy development that EPA used in setting its target—states have flexibility to use

a combination of any of the building blocks as compliance measures. EPA is also not requiring

renewable energy to be built within a state for that state to take credit under the Clean Power

Plan. This means that renewable energy can be built wherever it is most economic and there is

available transmission capacity.

b. Potential for Transmission Capacity Improvements

NERC, and other grid operators analyzing the impacts of EPA’s proposal, have

recognized the importance of transmission, and acknowledge that increased transmission

capacity will help the grid transition to renewable energy. But they also dismiss transmission

planning as an excessively long-term solution, arguing that it takes too long to fully install new

planned transmission lines.601 NERC in particular uses an assumed 10-15 year timetable to

justify its calls to delay implementation of the CPP, arguing further that regional grid operators

cannot even begin to plan transmission until state plans are approved under the CPP, which

would give them less than two years to build out the necessary transmission.602

NERC’s use of this supposed transmission “bottleneck” is inapposite for several reasons.

First, transmission lines simply don’t take 10-15 years to build on a regular basis. Although

some lines may take that long, especially when tricky siting issues are involved, there is no

reason it should take that long for most lines; indeed, ERCOT in its analysis of the CPP notes

that major transmission projects can be planned, routed, approved and constructed in five

years.603 ERCOT’s conclusion is more consistent with practice: to pick one example, Prairie Wind

Transmission, LLC, a 108-mile high voltage cable connecting wind resources in Oklahoma and

Kansas to load centers elsewhere within SPP, was conceived in 2008, permitted in 2011, and as

of June 2014 has been put mostly online (with the remaining 30 miles expected to go online by

 

600 Id. at 9-10; see also EIA Outlook, supra n. 598.

601 NERC Reliability Review, supra n. 591, at 20.

602 Id.

603 ERCOT Reliability Review, supra n. 273.
215

the end of the year).604 Furthermore, the process of building out transmission to transport

renewable energy to load centers has already begun in recent years, and will ramp up

significantly if grid operators take appropriate steps to prepare for CPP implementation.

Multiple RTOs are considering transmission improvements already,605 and in particular, Clean

Line Energy Partners is currently working to construct five major transmission lines to move

15.5 GW of largely wind-sourced electricity in the middle of the country out to load centers in

the Midwest, Southwest, and on the West Coast.606

Another major point undermining the severity of NERC’s transmission concerns is that it

misstates the timeline on which transmission projects could be planned, and would be

needed.607 To begin with, there is no reason why states and grid operators need to wait until

plans are approved to begin studying what transmission upgrades may be needed. Grid

operators’ mandates include an obligation to assess and respond to policy developments and

how they will affect the need for generation and transmission608; forthcoming regulatory

obligations such as the CPP therefore give rise to their duty to begin planning for future

transmission needs despite some degree of uncertainty about some details in state plans. On

the other end, although more transmission will certainly be needed in the future, the CPP’s

compliance schedule contemplates a slow ramping of stringency, and transmission

improvements are generally considered to be a mid- to long-term need, rather than an

immediate one. Several regions (especially California) have already incorporated high levels of

renewables without requiring significant transmission infrastructural changes (see discussion

below).

Finally, NERC overlooks numerous alternatives to new transmission projects that also

could resolve its predicted transmission constraints. Such measures include adding lines to

existing transmission corridors, reconductoring, or otherwise upgrading existing facilities. These

types of projects take far less time, both for regulatory approval and construction, and require

no siting process. They are also less expensive than building entirely new transmission lines.

Furthermore, transmission system planners are required to consider non-transmission

 

604 Press Release, Westar Energy, Inc., Prairie Wind Transmission, LLC: New Transmission ‘Super 

Highway’ Connects West, East Kansas and Improves Reliability (June 5, 2014), available at 

http://inpublic.globenewswire.com/releaseDetails.faces?rId=1791122.

605 MISO, Transmission Expansion Plan (2013), available at 

https://www.misoenergy.org/Planning/TransmissionExpansionPlanning/Pages/TransmissionExpansionPl

anning.aspx (last visited Nov. 25, 2014); ERCOT Reliability Review, supra n. 273, at 14-15.

606 Clean Line Energy Partners, Projects Summary, http://www.cleanlineenergy.com/projects (last visited 

Nov. 24, 2014).

607 Tierney, S., Analysis Group, Greenhouse Gas Emission Reductions from Existing Power Plants: Options 

to Ensure Electric System Reliability (May 2014).

608 Fed. Energy Reg. Comm’n (“FERC”), Order No, 1000: Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities, 76 Fed. Reg. 49,842 (Aug. 11, 2011).
216

alternatives to new wires projects,609 such as demand-side management. These projects can be

implemented more quickly and at lower cost than new transmission.

NERC’s evaluation also fails to reflect how energy efficiency will lessen the need for new

transmission infrastructure in general, or how states could design targeted demand-side

management programs to resolve areas of congestion.

c. Potential for Efficiency Improvements

NERC similarly critiques EPA’s assessment of the potential for energy efficiency

improvements, particularly casting doubt on the potential for industrial and commercial

customers to realize future efficiency gains, and on the long-term sustainability of efficiency

improvements.610 The premise for NERC’s contention that industrial and commercial customers

will not be able to achieve the same level of cheap savings as residential customers is that

companies, and particular industrial users, already “are designed to use as little energy as

possible in order to maximize profits of daily operations and may have already invested in

energy efficiency programs, leaving minimal and costly opportunities remaining for incremental

improvement.”611 There is an apparent logic to this assertion, because we expect companies to

maximize their own self-interest, but it has been proven wrong many times. New technologies

and changing cost parameters mean that new energy efficiency opportunities arise continually

for commercial and industrial sectors. Similarly, innovative financing structures are emerging to

improve payback and internal rates of return. Many states have run industrial and commercial

energy efficiency programs for years that continue to produce significant cost effective savings.

Finally, the attractiveness of an investment in energy efficiency by commercial and industrial

facility owners will increase if these entities stand to gain revenue under the CPP for energy

efficiency credits that can be sold to owners of power plants for compliance.

NERC’s argument is based on a misunderstanding of the difference between industrial

firm economics and utility system economics. For a variety of reasons, including ignorance, split

incentives, and financial limitations, commercial and industrial customers will typically pursue

only energy efficiency investments with a short, typically less than two-year, payback period.612

In contrast, a utility seeking to procure the lowest-cost resource over the next decade will find

it advantageous to incentivize measures with longer payback periods that otherwise would not

be implemented. Also, what is a cost-effective measure from an individual consumer’s

perspective does not correspond perfectly to what is cost-effective from a system-wide

 

609 FERC, Order No. 890: Preventing Undue Discrimination and Preference in Transmission Service, 72 

Fed. Reg. 12,266 (March 15, 2007).

610 NERC Reliability Review, supra n. 591, at 14-16.

611 Id. at 15

612 Kwatra & Essig, ACEEE, The Promise and Potential of Comprehensive Commercial Building Retrofit 

Programs, Report No. A1402 (May 2014), at 8-10.
217

perspective—thus there are untapped energy efficiency opportunities in the industrial and

commercial sector. 613

The high potential for efficiency gains in industrial and commercial users was confirmed

recently in a study analyzing a wide range of programs, in 31 states, from 2009 to 2011. That

study found that commercial and industrial participants in efficiency programs achieved

efficiency improvements at a levelized cost of about $21 per megawatt hour, only $3 more than

that achieved in residential programs.614 Commercial and industrial users also achieved

significantly more efficiency gains overall than residential users did from their programs:

commercial programs spent $3.2 billion, more than double the $1.5 billion spent on residential

programs, to achieve double the lifetime gross efficiency savings.615

NERC also claims that the world of efficiency gains is so finite that 1.5 percent gains in

demand-side management cannot be sustained annually until 2030. First, it should be noted

that few states—aside from those that already have ambitious energy efficiency targets—will

be expected to sustain 1.5 percent annual savings over the full interim period.616 On average,

states are not expected to attain the 1.5 percent annual savings rate until 2025. Second, high

levels of savings have been sustained around the country. EPA notes the long-record of high

savings in the Pacific Northwest,617 and California’s history of efficiency improvements alone

belies NERC’s claim. Until about 1975, California’s per-person megawatt-hour use tracked

national usage almost exactly. Since the 1970’s, California’s energy use per person has virtually

flat-lined, at least partially because California in 1977 took the lead in improving building and

appliance efficiency to improve the productivity of its electricity usage.618 In spite of this

leadership, and the significant efficiency gains it has already achieved, California continues to

invest significantly in energy efficiency, and has projected up to 50 percent additional energy

savings for existing homes and commercial structures by 2030.619

Finally, states are not required to sustain this level of savings for any particular period of

time, or to achieve it at all; NERC’s argument mistakes EPA’s target setting with compliance

requirements.

 

613 Nadel & Herndon, The Future of the Utility Industry and the Role of Energy Efficiency (June 2014), 

available for download at http://www.aceee.org/research-report/u1404, at 66-69.

614 Billingsley, at al., LNBL, The Program Administrator Cost of Saved Energy for Utility Customer-Funded 

energy Efficiency Programs (Mar. 2014), attached as Ex. 67, at 28.

615 Id. at 20.

616 Abatement Measures TSD at Appendix 5-4, Sheet “Opt 1 – Incr Savings %.”

617 Id. at 5-10.

618 Alliance Comm’n on Nat’l Energy Efficiency Policy, The History of Energy Efficiency (Jan. 2013), 

attached as Ex. 68, at 20.

619 Id.
218

d. Flexibilities in the CPP

None of the above arguments are meant to imply that every state will meet EPA’s

renewable energy build-out goals, or that every state has the same potential for sustained

energy efficiency improvements. Different states will have different paths to compliance

depending on the existing resource mix in their state, potential for renewable energy, level of

energy savings already achieved, and various other factors. This is the main benefit of the CPP’s

cooperative federalism approach: different approaches will make sense for different regions,

and states are not required to achieve each of the building blocks to ensure compliance with

their obligations. In sum, by focusing so heavily on EPA’s building blocks and identifying

individual situations where certain of those blocks may be difficult to achieve, NERC artificially

compartmentalizes the compliance process, making states’ paths to compliance seem more

daunting than they actually are.

e. Region-Specific Analyses

NERC is not the only entity that has addressed the reliability implications of EPA’s

projected coal plant retirements. In addition to NERC, analyses of the CPP’s impacts on

reliability have been released by The Southwest Power Pool (“SPP”), an RTO operating in Texas,

New Mexico, Oklahoma, Arkansas, Kansas, Missouri, and Louisiana; the Electric Reliability

Council of Texas (“ERCOT”), an ISO operating entirely within Texas; PJM Interconnection LLC

(“PJM”), which serves all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan,

New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the

District of Columbia; and the Midcontinent ISO (“MISO”), which serves all or part of Minnesota,

Wisconsin, Michigan, Ohio, Indiana, Illinois, Missouri, Kentucky, Pennsylvania, North and South

Dakota, Montana, Nebraska, and the Canadian province of Manitoba.

i. SPP

SPP has been one of the most vocal grid operators in voicing concerns with the CPP. Its

October 2014 Reliability Impact Assessment assessed the implications of every anticipated coal

plant retirement in the SPP region, and concluded that those losses, offset by currently planned

or existing wind and natural gas resources, would shrink the region’s “reserve margin” (the

percent by which generating capacity exceeds expected demand) from 13.6 to 4.7 percent by

2020, and to -4.0 percent in 2024.620 Based on these findings, SPP’s comments ask EPA to put

off any compliance with the CPP to 2025, and adopt the “reliability safety valve” proposed by

the ISO/RTO Council (see discussion below).621

 

620 Southwest Power Pool (“SPP”), SPP’s Reliability Impact Assessment of the EPA’s Proposed Clean 

Power Plan 6 [hereafter, “SPP Reliability Review”] (Oct. 2014) at 5.

621 Letter from Nicholas A. Brown, Southwest Power Pool, Inc., to Gina McCarthy, EPA Administrator (Oct. 

9, 2014) [hereafter, “SPP Letter”] at 10.
219

SPP’s conclusion that a resource adequacy crisis would ensue are to be expected given

the analysis it performed: it assumed that almost 15 percent of the region’s power supply

would retire without replacing it with any new power sources or demand-side management

and unsurprisingly, found that reliability would suffer. Those conclusions are not, however,

based in the reality of what CPP is expected to accomplish or how resource planning unfolds:

the CPP objectives will be reached only if states invest in renewable resources, demand-side

management strategies, and other new, low-carbon emitting generation. Nothing in the rule

requires that any of the coal-burning capacity in SPP retire, much less prior to other generation

coming online. We also note that SPP is well-positioned to transition under the Clean Power

Plan, given that it achieved a reserve margin of 47 percent in 2013 and has not had a margin

below 32 percent in the last six years at least (both numbers are far above its 13.6 percent

requirement),622 and that it is located in the heart of our nation’s strongest potential regions for

wind power production. Assuming the SPP and its member states plan for the transition, it

should have no difficulties ensuring resource adequacy.

ii. ERCOT

ERCOT has, like SPP, raised significant concerns relating to the impact the CPP will have

on grid reliability, and it has supported both the delay and the safety valve proposals put forth

by industry groups (see discussion below).623 ERCOT’s critique has less to do with overall

resource adequacy, however, instead focusing on voltage and frequency stability concerns that

we address in the next section.624 Its model predicts retirement of between 5.7 and 7.8 GW of

electricity generation capacity between now and 2029 under the CPP (compared to a baseline

of 2.8 GW of retirements), and addition of 16.9 to 19.3 GW of new generation, about 90

percent from wind and solar alone (compared to baseline of 14.5 GW of new generation, about

two-thirds from wind and solar).625 In other words, ERCOT’s modeling anticipates the net loss of

between 0.2 and 1 GW of capacity resulting from the CPP, and a dramatic shift in resources

from coal to renewables.

ERCOT’s model does predict a capacity constraint sometime between 2018 and 2022,

when coal plants are trying to retire and renewables have not yet been fully built out; but this

should not be a major concern.626 ERCOT's concerns are unfounded because the CPP provides

enough flexibility that, if necessary, coal plants can continue operating early in the compliance

period. ERCOT also has a number of tools available to respond to projected shortfalls. It can and

should supplement already-planned major transmission line improvements with additional

projects serving load centers in the state, and as a last-resort (as ERCOT acknowledges), it can

keep coal plants operating using reliability-must-run contracts to cover identified shortfalls, or

shift generation from existing coal to gas units.

 

622 SPP, 2013 State of the Market (May 2014), at 16-17.

623 ERCOT Reliability Review, supra n. 273, at 2.

624 Id. at 9-14.

625 Id. at 6

626 Id. at 6.
220

Furthermore, although ERCOT does actually predict significant levels of new renewable

generation (unlike SPP’s analysis, which ignored renewables entirely), there are still several

flaws in its modeling assumptions that undermine its overall analysis. Most pointedly, ERCOT

assumed, without any apparent basis for this assumption, that Texas would enact a flat price on

greenhouse gas emissions to meet its obligations under the CPP.627 Meanwhile, the third

scenario applied CPP limits in the most cost-effective way possible, supposedly to determine

the ideal compliance option, but that study requires ERCOT to meet the applicable emission

rate goal every year, thereby failing to take advantage of the 2020-2029 compliance averaging,

which is one of the CPP’s key flexibility mechanisms.628 ERCOT also dismisses that scenario as

unrealistic because it may not be achievable “within the current electricity market design in

ERCOT.”629 This may be true, but there is no requirement that the current market design remain

in place: ERCOT can clearly redesign its market to accommodate faster market changes, and in

fact already is looking into redesigning its ancillary services market to accommodate distributed

generation (and demand response resources).630 ERCOT also assumes efficiency gains of just

over half EPA’s projections by relying on historical trends instead of considering future

potential; and it assumes the current Production Tax Credit (which has incentivized huge wind

build-out in the state) will expire with no replacement, even though that would be an easy way

to continue the current rate of wind generation construction. And finally, ERCOT’s model does

not include any “negawatts” for demand response services, which could be a huge contributor

to the reliability of Texas’s power grid.631 These incorrect baseline assumptions undermine the

utility of ERCOT’s model in predicting future reliability needs.

iii. PJM/MISO

Neither PJM nor MISO has released a comprehensive analysis of the CPP’s impacts on

grid reliability, but they have both released results from models they set up to determine the

impacts of the CPP. Both models indicate that creation of regional compliance plans, rather

than leaving states to achieve individual compliance, could achieve the required reductions at a

significantly lower cost.632 We concur with both RTOs that regional compliance represents a

more flexible compliance pathway for individual states, which would further reduce any

 

627 Id. at 2-3.

628 Id. at 5.

629 Id. at 2.

630 ERCOT, 667NPRR-01 Ancillary Service Redesign 111814 (11/18/2014).

631 ERCOT Reliability Review, supra n. 273, at 3-5.

632 Midcontinent Independent System Operator (“MISO”), GHG Regulation Impact Analysis—Initial Study 

Results [hereafter, “MISO Reliability Review”] (Sep. 17, 2014) at 11 (noting that regional compliance 

options would save $3 billion annually as compared with state-specific plans); Sotkiewicz & AbdurRahman, PJM Interconnection, Inc., EPA’s Clean Power Plan Proposal Review of PJM Analyses 

Preliminary Results [hereafter, “PJM Reliability Review”] (Nov. 2014) at 35-37 (modeling almost $10 

billion in savings for the year 2020 for a regional compliance plan over state-specific plans).
221

reliability concerns in the region. MISO also concludes that utilization of non-building block

compliance options would significantly reduce compliance costs.633

There is little to respond to in either RTO’s releases to-date from a reliability

perspective, but we do also note that the PJM model concludes that already-planned coal plant

retirements will reduce greenhouse gas emissions by a significant amount already, making

compliance with early CPP goals even less daunting. In particular, PJM apparently believes that

six states (Ohio, Pennsylvania, New Jersey, Kentucky, Virginia, and Maryland) will meet their

2020 interim targets simply by following through on planned coal retirements in their states.

634

We disagree with this analysis because we believe PJM used a higher mass cap on emissions

than will be allowed under the CPP, but the analysis nonetheless demonstrates, at least in the

PJM region, that the CPP will not impose any insurmountable burden on those states’ power

grids, and belies PJM’s contention in public forums that policy protections are needed to ensure

grid reliability.635

2. Voltage and Frequency Stability

Another reliability issue raised by several commenters is how the shift away from large

central-station generation will affect voltage and frequency stability on the system. Voltage and

frequency stability services are two major categories of “Essential Reliability Services” (ERSs)

provided to grid operators that are valued above and beyond the power capacity generating

sources can provide. Historically, ERSs have largely been provided by traditional power plants

(especially coal-burning power plants) because, as explained below, large-scale plants are

particularly well suited to providing these services. As a result, grid operators have raised the

prospect of reduced ERSs in the system as a second, distinct reason to oppose regulations that

would result in significant coal plant retirements. NERC and ERCOT in particular have chosen to

tackle this issue head-on in their critiques of the CPP, arguing that added wind and solar

resources on the grid will put a premium on ERSs in a way grids currently are not prepared to

manage.636

These services are important, but these initial reliability reports overstate the

severity of this problem and undervalue the potential for renewables to provide ERSs with

proper planning. Several studies, including a concept paper prepared by NERC’s own ERS Task

Force, have found that properly sited and connected renewable energy services are well

prepared to take on retiring coal plants’ contributions to the burden of stabilizing the power

grid. (Natural gas plants also provide ERSs.) The next few paragraphs lay out the major types of

voltage and frequency stability services, how they are currently provided, and how renewables

and other system solutions can continue to provide them in the future.

 

633 MISO Reliability Review, supra n. 632, at 3.

634 PJM Reliability Review, supra n. 632, at 17-18.

635 Heidorn, R., State Officials Challenge EPA Assumptions on Carbon Rule, RTO Insider (Oct. 20, 2014);

see discussion below for our response to grid operators’ policy recommendations.

636 NERC Reliability Review, supra n. 591, at 25-26; ERCOT Reliability Review, supra n. 273, at 10-11.
222

a. Voltage Services

Voltage services, as their name suggests, help keep the voltage of the power grid stable

over its entire network. Because voltage varies quickly over distances, voltage service providers

largely act locally, and must be distributed throughout the power system. In practice, voltage

support mostly comes down to the grid’s ability to balance “real” power (the usable power on

the grid) with “reactive” power (the unusable power on the grid, also called phantom power).

Collectively, reactive power and real power make up the total power on a given line, so a rise in

one necessarily leads to a drop in another. As a result, if there is too much reactive power on

the grid, end-use equipment absorbs too much reactive power with its real power, and can

overheat before receiving enough real power to operate. If there is not enough reactive power

on the grid, the real power voltage will surge, overcoming equipment insulation and damaging

their machinery. As such, reactive support providers must have the capacity to add or remove

reactive power from the system.

Traditionally, large generators attached to large single power plants have provided this

service by releasing more or less reactive power as needed. This forms the basis for both

NERC’s and ERCOT’s assertions that the loss of significant coal resources will place a premium

on these services.637 These claims are unfounded: NERC’s ERS Task Force has noted that

generators attached to wind or solar plants also can provide both real and reactive power, and

inverters attached to those generators can do so even when the plants are not producing any

electricity.638 In addition, energy storage services can also provide voltage stability services, and

they already do so in several parts of the country.639 (Power storage systems generally have a

critical role to play in preserving the stability of the grid, and their expansion in recent years is

an important development EPA and states should look to harness to help incorporate our

shifting power supply.)

b. Frequency Services

Frequency services are primarily focused on maintaining the system at the standard

frequency (in the United States, this is 60 Hertz, or power cycles/second). There are several

types of frequency services, covering different time frames of need (seconds, hours, days, etc.).

Looking first at day-to-day reliability needs, i.e., excluding periods when there are major

disturbances to the grid, these services can be roughly divided into small-scale immediate

balancing, and longer-term daily load management.

 

637 NERC Reliability Review, supra n. 591, at 25; ERCOT Reliability Review, supra n. 273, at 10.

638 NERC, Essential Reliability Services Task Force, A Concept Paper on Essential Reliability Services that 

Characterizes Bulk Power System Reliability [hereafter, “ERSTF Concept Paper”] (Oct. 2014), attached as 

Ex. 69, at 11-12, n. 10.

639 See, e.g., The Brattle Group, The Value of Distributed Electricity Storage in Texas (Nov. 2014), 

attached as Ex. 70; EPRI, Cost-Effectiveness of Energy Storage in California (June 2013), attached as Ex. 

71.
223

Balancing support services smooth the numerous second-to-second fluctuations that

occur throughout the day. One way small changes are balanced is through possession of high

inertia, which is simply the inherent resistance of certain generators to frequency changes (i.e.

generators with high inertia resist changes in the power cycle speed (Hertz) in either direction).

Coal-burning power plants have massive generators, so they have traditionally provided

significant inertial support on the system. Utility-scale wind and solar plants historically have

not provided this because they use DC generators that don’t connect directly to the grid, but

they can provide “synthetic” inertia when their DC generators are connected to AC inverters,

allowing them to connect directly.640

The other main way ERS providers help balance second-to-second fluctuations in the

system is through quick jumps and drops in power provided to the grid. This requires that

power sources be equipped with electronic “governors” (this type of support is also called

governor response) that allow a central operator to spike or drop power supply from the

generator in a matter of seconds. As with inertial support, renewable sources have not

historically been major providers of governor response, but when properly connected to the

grid it is relatively easy for them to do so, especially in the downward direction (it is possible for

renewables also to provide upward governor responses, but only if their total power output is

curtailed.)641 Thus, between this and the possibility for synthetic inertia, there is no reason to

believe that it will be impossible, or even prohibitively difficult, to maintain balancing support

services as the grid shifts over time.

Daily load management requires that grid operators be able to increase or decrease

power provision to balance frequency to correspond to longer-term fluctuations (both

anticipated and unanticipated) in electricity demand over the course of a day. These reliability

services are provided both by back-up generation facilities (“operating reserves”) and by active

generating facilities capable of ramping power supply up or down for minutes or hours at a

time. Operating reserves are classified depending on how quickly they can come online and

how long they can last,642 and are typically provided by natural gas and other quick-starting and

resource-limited controlled power facilities. Because wind and solar plants constantly harness

available natural resources, they are not well-suited to provide operating reserves; instead,

they are expected to replace power generators that run most or all of the time, and which

provide extensive ramping services to the grid.

Perhaps the most pervasive critique of renewable energy resources from a reliability

perspective is that they are unsuited for providing ramping services because their output is

constrained by meteorology. This critique forms much of the basis for the “reliability concerns”

 

640 ERSTF Concept Paper, supra n. 638, at 8-9.

641 Id. at 6.

642 In order from the quickest and shortest-lasting, to the slowest and longest lasting, these “operating 

reserves” are called regulation reserve, spinning reserve, load-following reserve, non-spinning reserve, 

and replacement or supplemental reserve. Id. at 3.
224

raised by opponents of the CPP and a shifting energy supply.643 It is also needlessly pessimistic.

Wind power plants in particular, but also large-scale solar installations, are already required to

have the capability to provide ramping services as required.644 In fact, NERC’s own reliability

task force noted in its summary that “[s]ome modern utility-scale [renewable energy plants]

have greater ramp control capability for control [sic] than coal-fired conventional generators

(up or down).”645 This is not to say, of course, that it will necessarily be good policy to ask too

much ramping from utility-scale renewable generators, because doing so normally requires

curtailing their power output (which reduces their overall capacity factors); but finding the right

balance is part of the challenge to which EPA rightly expects states and grid operators can and

will respond.

For both of the above types of frequency control services, it also bears mentioning that

electricity storage facilities can be as effective at controlling frequency as they can controlling

voltage on the grid. Furthermore, none of the critiques mention the huge potential of demand

response services, recognized by NERC’s own ERS Task Force,646 which are already heavily

utilized in several parts of the country. These “negawatts” not only reduce overall electricity

usage, they do so on command, meaning that they are and will continue to be critical resources

for easing utilities through rough patches or demand spikes during the day. Demand response

services also require very little infrastructure investment, making them excellent sources of

near- and medium-term reliability services for regions that are particularly concerned about

coal retirements. Of the several critiques we have seen mentioning the potential reliability

impacts of the CPP, there has been little to no recognition of the important role storage and

demand response in ensuring that electricity is provided reliably for years to come.647

3. Resilience Against Large System Shocks

The final system attribute grid operators have identified as endangered by shifting

resource balance on the grid is its ability to respond quickly to large system shocks. These

shocks typically occur when a large generator goes offline unexpectedly, or part of the

transmission system experiences an unplanned outage. ERS providers are generally asked to

respond to major disturbances in two ways: first, by remaining operational in spite of electricity

fluctuations (“ride-through” capability); and second, by being able to start up and help restore

frequency before the grid has returned to normalcy, sometimes without any assistance from

the grid whatsoever (quick-start, sometimes “black-start,” capability).

648 This is one area where

 

643 NERC Reliability Review, supra n. 591, at 25; ERCOT Reliability Review, supra n. 273, at 11-14.

644 ERSTF Concept Paper, supra n. 638, at 8.

645 Id. at 7-8 (further noting that “[l]arge, utility-scale wind and solar plants are already required to value 

the capability to limit production and control ramp rates to support system . . . reliability.”).

646 NERC Reliability Review, supra n. 591; ERCOT Reliability Review, supra n. 273; ERSTF Concept Paper, 

supra n. 638, at 15.

647 See, e.g., NERC Reliability Review, supra n. 591, at 25 (mentioning the potential for storage 

technologies to help, but dismissing them as “not yet . . . commercialized”).

648 ERSTF Concept Paper, supra n. 638, at v, 9-10.
225

transition to cleaner electricity sources will unambiguously help: wind and solar plants are often

more able to ride out disturbances, and return to service more quickly, because they are

already necessarily designed to deal with fluctuating power over time, and they lack

complicated thermal or mechanical systems that require significant amounts of time to

restart.649 In addition, the smaller capacity and more distributed nature of wind and solar plants

address some of the root of the problem—a malfunction at a 50 MW solar facility is less likely

to cause a large system shock than when a 800 MW central-station generator trips offline. 650

Certain commenters have also looked at broad energy trends to highlight system

vulnerabilities that arise when a grid relies too much on one type of resource. In particular,

NERC in its critique of the CPP highlights the 2014 polar vortex, when particularly high demand

for natural gas (for heating homes) strained local grids because pipelines appeared unable to

supply natural gas plants. NERC has raised concerns that increasing the share of electricity

produced by gas-burning power plants would make the grid more vulnerable to disturbances

like that where single events act to reduce the supply of gas over a large region.651 As an initial

matter, the polar vortex did not, in fact, result in widespread power losses in the region, even

though it was by any measure an extreme weather event; and that improved electricity

transmission infrastructure can alleviate the risk that any one region suffers from a power

shortage.

Also, sensible planning and low cost power plant upgrades would have avoided a large

part of the problem. In the aftermath of the polar vortex, it has become clear that a big part of

the problem leading to these capacity constraints was that coal and gas plants were simply

unprepared for these climatic conditions. Most of the plants that were out of service were

unavailable because of operational and mechanical problems like frozen coal stockpiles, boiler

tube failures, and faulty ignition. Some plants, for example, failed to start up in the extreme

cold after being off line for months. (By the end of January, when we experienced another

extreme cold spell, more plants had recovered and were running normally.) Grid operators are

now working on corrective measures to avoid these surprises, including requiring plants to test

and verify their operational capability during the cold winter months. These tests include a

“weekend check” requirement to assure that plants won’t have trouble starting up again after a

prolonged break. Grid operators are also evaluating additional financial incentives to reward

plant operators that deliver higher performance levels.652

Finally, pipeline capacity and gas supplies were not the problem in this situation;

sufficient gas supply was available, but an anomaly in the power and gas markets kept some

gas-fired generators from obtaining sufficient fuel on high-demand days. FERC and regional grid

 

649 Id. at 9-10.

650 Milligan et al., NREL, Cost-Causation and Integration Cost Analysis for Variable Generation, NREL/TP5500-51860 (June 2011), at 3.

651 NERC Reliability Review, supra n. 591, at 9-10.

652 Sustainable FERC Project, The Polar Vortex and the Power Grid: What really happened and why the 

grid will remain reliable without soon-to-retire coal plants (Ap. 2014).
226

operators have recognized this problem, and are working to address it: most recently, in

October 2014 FERC shared its intention to better coordinate daily natural gas and electricity

markets; enable gas-burning power plants to run temporarily on oil during emergencies; and

make other market changes to resolve the issues that led to the capacity crisis during the polar

vortex.653

We also note that that the obvious solution to NERC’s concerns is increased fuel

diversification. As NERC itself acknowledges, “the power industry relies upon diversification of

fuel sources as a mechanism to offset unforeseen events . . . ensure reliability; and minimize

cost impacts”654—but its solution is to continue excessive reliance on coal: MISO, which

encompasses much of the region that was hardest hit by the polar vortex, relies on coal for

over two-thirds of its electricity today. Taking the fuel diversification impetus to its logical

conclusion only strengthens the case for investing in renewable resources, which currently

make up less than a tenth of electricity generation in the same region, and demand-side

resources. Unlike both coal and gas plants, wind and solar plants rely on “fuel sources” that do

not need to be imported from anywhere, and the supply of which is far less likely to be

interrupted uniformly across broad swaths of the country.

4. Utility-Grade Versus Distributed Renewable Generation

One important distinction raised especially by ERCOT in its modeling analysis has been

between utility-scale, concentrated renewable generators, and distributed generation,

especially solar generation, across the grid. As the system is currently structured, grid operators

have “little to no visibility and control of distributed resources,”655 with the result that they

have raised reliability concerns across the country where power consumers look set to install

distributed generation in significant amounts. ERCOT highlights two key changes that will be

required to incorporate this generation without undermining grid reliability:

“To produce accurate solar production forecasts, ERCOT would need to have

information regarding the size and location of distributed solar installations.

Additionally, to ensure grid reliability, there would need to be increased

consideration of operational activities on the distribution and transmission

systems.”656

NERC’s ERS Task Force further notes that lack of control over distributed generation

resources limits their ability to respond to fluctuations on the power grid, reducing their ability

to provide routine frequency stability services or to help restore balance after grid

 

653 Press Release, FERC, Commission Reviews Actions to Improve Cold-Weather Grid Performance (Oct. 

16, 2014), available at 

http://www.ferc.gov/media/news-releases/2014/2014-4/10-16-14-A-4-presentation.pdf, at 3.

654 NERC Reliability Review, supra n. 591, at 9.

655 ERSTF Concept Paper, supra n. 638, at 8.

656 ERCOT Reliability Review, supra n. 273, at 13-14.
227

disturbances.657 We do not agree with ERCOT or NERC that distributed generation represents a

serious reliability concern in the near-term future—to give one example, the 9 to 13.5 GW of

new solar capacity ERCOT’s model anticipates over the next fifteen years is entirely utility-scale

generation658—but to the extent some market changes are needed, we note again that grid

operators are already examining the various changes that may be required.

659

5. Overall Ability to Incorporate High Levels of Renewable Generation

As explained above, grid operators already have the tools necessary to adjust to the 

retirement of coal-burning power plants over the next fifteen years without seriously impacting 

the reliability of the power grid. Because much of the replacement power will likely come from 

renewable resources, this may result in renewable penetration rates of 30 to 40 percent or 

more in several areas of the country by 2030. Several recent studies have addressed this 

contingency specifically, considering whether and how it is possible to incorporate those levels 

of renewable energy using today’s resources and technologies. These studies analyze a wide 

range of renewables incorporation, but their common conclusion is that high levels of 

integration are feasible. For a summary of these studies, please see Appendix 6.

To achieve these levels, the studies variously call for restructuring the energy market, 

advanced transmission planning and installation, increased utilization of demand response 

programs, additional electricity storage installations, incorporation of contingency reserve and 

curtailment capabilities into wind and solar facilities, independent improvements in ancillary 

service providers, and continued limited use of some fossil fuel plants as “peaker” facilities.660

Implementing some or all of these measures will take time and money, but given that they are 

available now there is no reason for EPA not to expect that such a transition is possible. Each of 

these studies was done by grid operators and experts seeking to understand the implications of 

underlying market and policy trends favoring renewable energy development. In other words, 

the process of learning how to integrate large amounts of renewable energy is already 

underway, regardless of the Clean Power Plan. EPA’s rule reflects and to some degree amplifies 

changes that are already happening in the system; it does not cause radically new and 

unprecedented circumstances.

B. Policy Conclusions

Because we are confident that a combination of renewable and demand-side resources, 

with appropriate advanced planning, can resolve all major reliability concerns grid operators 

have raised to EPA, we do not believe that EPA needs to take any measures to ensure that 

electricity is delivered safely and reliably to consumers across the country. Instead, we take this 

 

657 ERSTF Concept Paper, supra n. 638, at 7-8, 14.

658 ERCOT Reliability Review, supra n. 273, at 13.

659 ERSTF Concept Paper, supra n. 638, at 14; ERCOT, 667NPRR-01 Ancillary Service Redesign 111814, 

supra n. 630.

660 See summaries of the various studies attached as Appendix 6.
228

opportunity to respond to calls from utilities and regional grid operators for delayed 

implementation of the CPP, and for a “safety valve” that would exempt states and regions that 

are unable to meet their greenhouse gas emissions targets.

1. Delaying Implementation of the CPP

In response to perceived reliability concerns, NERC has called on EPA to “consider a

more timely approach” to implementation of the CPP.661 This call mirrors similar requests from

SPP, which explicitly asks EPA to extend its proposed compliance schedule,662 and several other

utilities and grid operators, including PJM.663 It is to be expected that grid operators and

especially utilities would want more time to adapt, but any needed system changes anticipated

by EPA’s rule are achievable in the time allotted, and in fact are probably possible on a faster

timeframe. Moreover, grid operators have already begun the process of integrating higher

levels of renewable energy and responding to coal plant retirements caused by the worsening

economics of coal. The CPP provides sufficient flexibility and lead time for utilities and grid

operators to adapt. As noted previously, there are no targets that need to be met in 2020, nor

are any sources specifically subject to continuous emission rate requirements. This absence of

hard mandates early in the compliance period alleviates the need for the requested delays in

implementation of the Clean Power Plan. Finally, unlike other EPA rules, such as the Mercury

and Air Toxics Standards (MATS), that impose continuous emission rate requirements on coal

plants, the Clean Power Plan imposes only annual emission rate constraints (see below for a

more comprehensive comparison of CPP and MATS requirements).

The danger climate change poses to our society is too great to be held hostage to the

apparent reluctance of grid operators to update their policies and infrastructure to

accommodate clean electricity sources. As mentioned elsewhere in these comments, President

Obama’s international commitments, especially the recent U.S. – China agreement, require that

we achieve greenhouse gas reductions at least equal to those required by the CPP from the

power sector; failing to meet those objectives would set back global efforts to mitigate climate

change significantly, when time is already of the essence.

2. Installing a CPP “Safety Valve”

The ISO/RTO Council (“IRC”) has led efforts by grid operators and the power sector

generally to secure a “reliability safety valve”, which would blunt enforcement of the CPP in

certain areas. 664 As proposed, this “safety valve” would subject EPA rules and/or state plans to

a “reliability review,” which could delay enforcement of the rule or program until a long-term

 

661 NERC Reliability Review, supra n. 2, at 29.

662 SPP Letter, supra n. 31, at 8.

663 Heidorn, supra n. 635.

664 See id.; ISO/RTO Council, EPA CO2 Rule—ISO/RTO Council Reliability Safety Valve and Regional 

Compliance Measurement and Proposals [hereinafter “IRC Reliability Review”] (Oct. 2014); NERC 

Reliability Review, supra n. 591, at 22; ERCOT Reliability Review, supra n. 273, at 2.
229

reliability solution is “developed and implemented.”665 Such reviews would be required on a

rolling basis “at multiple stages both prior to the SIP being finalized and approved and at

various steps during its implementation, as necessary.”666 And the rule would allow old coal

plants to remain operational until this long-term solution is put in place.667

Allowing states an explicit reliability “safety valve” as described here is problematic for

several reasons. First and foremost, it is unnecessary for the same reasons given above, and (as

with the proposed CPP implementation delay) it would seriously impact greenhouse gas

emissions by allowing old, dirty plants to continue operating well past when they would

otherwise retire. Beyond that, it would significantly reduce motivation for regional and state

grid operators to actively prepare for changes in customer demand, and related power needs

and supplies of the future. As almost every grid operator has noted, significant advanced

planning, and coordination with states in designing their plans, will be required to ensure

power grids are equipped to manage our changing resource structures. A safety valve provision

would undermine those conversations by removing a base level of accountability, and would

therefore leave us less prepared in the long term. Finally, the provision proposed by IRC would

impose a huge administrative cost on EPA, states, and grid operators, all of which would be

required to go through a reliability determination and approval process at several stages

throughout the plan approval process. Each of these additional administrative decisions could

themselves be subject to challenge by industry or environmental groups, which could make the

CPP implementation process even more difficult than the plan approval process already can be.

We support state coordination with the ISO/RTO and neighboring states in developing their

plans to ensure reliability, but do not believe that the formalized veto process proposed by the

IRC will be constructive. The ISO/RTOs already have mechanisms such as reliability-must-run

requirements as a final measure to ensure system reliability.

The supporters of IRC’s safety valve proposal have justified it in part by comparing it to a

safety valve provision EPA approved in conjunction with its December 2011 rule finalizing

mercury and air toxics (MATS) standards for stationary sources. In finalizing the MATS rule, EPA

also issued a statement of enforcement policy, noting that “where there is a conflict between

timely compliance . . . and electric reliability, EPA intends to carefully exercise its authorities to

ensure compliance with environmental standards while addressing genuine risks to

reliability.”668

The proposed safety valve goes much further than the one in the MATS rule, with no

apparent justification for doing so. But even if it were identical to the safety valve in MATS, CPP

differs in several key ways that remove any possible justification for a safety valve. The CPP

 

665 IRC Reliability review, supra n. 664, at 2.

666 Id. at 3.

667 Id.

668 Giles, C., EPA, Assst. Administrator, Office of Enforcement and Compliance Assurance, Memorandum: 

Enforcement Response Policy for Use of Clean Air Act Section 113(a) Administrative Orders in Relation to 

Electric Reliability and the Mercury and Air Toxics Standard (Dec. 16, 2011).
230

operates through a SIP-like process, which allows states significant flexibility in designing

standards to ensure that emission reductions do not come at the cost of serious damage to grid

reliability. By contrast, the MATS rule sets uniform, national standards and does not allow

states much leeway in enforcing those standards. State plans adopted under the CPP can also

include provisions that allow curtailed plants to operate only when needed to generate reactive

power needed to maintain system reliability. Again by contrast, the MATS rule sets absolute

limits on each individual plant, and does not allow a plant to operate if it cannot comply with

that limit. Finally, the CPP involves a slow ramp-up of emissions standards, and explicitly

anticipates a gradual shift in grid makeup, with identifiable replacement power sources. MATS

standards are fully enforceable on a specific date. Thus, none of the justifications leading EPA to

limit its enforcement of MATS obligations come into play here, and EPA can and should safely

disregard industry scaremongering.

C. A Consensus Vision for the Future

Although we clearly draw different conclusions from certain grid operators and utilities 

on the seriousness of threats to electricity reliability, and on whether policy “fixes” are required 

to ensure grid reliability, we close these comments by highlighting points of consensus. The 

most important message from all commenting parties is that implementation of the CPP is 

expected to contribute to the retirement of significant amounts of coal-sourced electricity over 

the next 15 years. To the extent feasible, EPA should help to ensure that states and grid 

operators plan for those retirements as soon as possible, make sure they fully understand the 

reliability implications of those retirements, and prepare their electricity grids to incorporate 

significantly higher levels of renewable energy.

As part of this, it is critical that state environmental regulatory agencies work closely 

with utilities and grid operators to ensure that states’ individual plans are designed to minimize 

any disruptions to grid reliability. This may involve regional compliance options for states within 

a single RTO, or it may simply involve extensive consultations. Similarly, NERC, which has been 

looking mostly at national grid developments, should work more with regional RTOs, ISOs, and 

utilities to help them identify and respond to predictable changes in their resource mixes.

Although it is certainly possible to manage renewable electricity in a way that minimizes 

disruptions to grid reliability, doing so will require advanced planning and understanding. To 

the extent appropriate, EPA should help facilitate these conversations.

XII. Munis and Co-ops

A. Public Power Utilities and Rural Electric Cooperatives Are Capable of Reducing the 

Carbon Emission Rates of their Affected Units.

EPA has requested comment on whether there are circumstances unique to municipallyowned utilities or rural electric cooperatives affecting the potential to reduce emissions from 

affected units owned or operated by those entities. This is appropriate: of the electricity 

generating units subject to CPP requirements listed in Energy Information Administration 
231

databases for which ownership information is available (2785 out of 4954 total units), a full 36

percent are owned by municipalities, cooperatives, or other public utilities, constituting about 

20 percent of overall coal generating capacity.669 In the context of coal, of the 753 coal units 

whose ownership could be determined, 64 are owned by municipalities, 67 by cooperatives, 

and 17 by other public utilities.670 In other words, EPA cannot afford to ignore this huge section 

of the power sector in this country and still hope to achieve the overall greenhouse gas 

emission reduction goals it has set.

1. Characteristics of Municipal Utilities and Electric Cooperatives

Municipal utilities, or more broadly, “public power utilities” are vertically integrated 

utilities overseen by officials at a city or other local government. Typically state public utility 

commissions exercise no or only limited authority over municipal utilities. Taxpayer-issued 

bonds are the primary source of financial capital for public power utilities. Not all municipal 

utilities own or operate their own generation—some operate only the distribution facilities and 

purchase power on the wholesale market.

Rural electric cooperatives formed out of an effort by the federal government in the

1930s and 40s to electrify rural areas of the country, which had been neglected by traditional

utility models. The Rural Electrification Administration, today the Rural Utilities Service,

provided financing for the development of distribution infrastructure and establishment of

electric services. Rural electric cooperatives come in two types: distribution cooperatives and

the larger generation & transmission coops. Currently, there are approximately 840 distribution

and 65 Generation & Transmission (“G&T”) cooperatives.671 The former do not own or operate

generation, but collectively they own and operate 2.5 million miles of distribution lines, making

up 42 percent of the distribution system.672 Although these lines cover three quarters of the

nation’s land mass, they are concentrated in the sparsely populated middle of the country,

including most of the central plains down to northern Texas, and so they deliver only 11

percent of all power produced in the United States, largely to rural customers, each year.673

These distribution-only cooperatives, as well as municipal utilities that do not own or operate

affected EGUs, will have no compliance obligations under the Clean Power Plan.

 

669 We analyzed which affected EGUs were owned in part by a municipal utility, other political 

subdivision, or rural electric cooperatives using the following data sources: EPA, Data File: Unit-Level 

Data Using the eGRID Methodology, supra n. 166, (for affected EGU identification); EIA 2012 Form 860 

and 861 (for power plant ownership name and type data).

670 Id.

671 National Rural Electric Cooperative Association (“NRECA”), NRECA Co-op Facts & Figures, 

http://www.nreca.coop/about-electric-cooperatives/co-op-facts-figures (last visited Nov. 28, 2014).

672 Id.

673 Id.; NRECA, Full Size Grand T Service Territory, http://www.nreca.coop/wpcontent/uploads/2013/07/FullSizeGandTServiceTerritory.gif (last visited Nov. 28, 2014) [hereafter, 

“NRECA Map”].
232

G&T cooperatives were formed by groups of distribution cooperatives to improve

distribution cooperatives’ ability to negotiate for power and ensure a reliable power supply.

They own and operate generation and transmission facilities, and facilitate local distribution

cooperatives’ purchases of power from the market, providing expertise and additional

bargaining leverage.674 Thus, G&T cooperatives serve a large majority of distribution

cooperatives, and increase the effective size, diversity and geographic range over which grid

optimizing decisions (e.g., dispatch changes, heat rate improvements, emission trading,

renewable energy investments) can be made. In other words, these larger markets give small

rural collectives a greater opportunity to make the changes necessary to reduce greenhouse

gas emissions.

Rural electric cooperatives have access to several sources of federal funding. For

instance, the Rural Utilities Service (“RUS”), a program operated by the U.S. Department of

Agriculture, provides funding, loan guarantees, and administrative support to rural electric

cooperatives to enable them to construct distribution, transmission, and generation facilities.675

As a result, the cost of capital for cooperatives is often lower than that available to investorowned utilities.676 Cooperatives can also obtain funding from the National Rural Utilities

Cooperative Finance Corporation, which raises funds from capital markets to supplement the

loan programs offered by RUS.677

2. Renewable Energy and Energy Efficiency Measures Taken by Municipal Utilities 

and Cooperatives

Some cooperatives and municipal utilities rely on some of the nation’s oldest (and 

therefore least efficient) coal-burning power plants, and have remained reliant on coal even as 

the largest investor-owned utilities have begun to diversify their generation portfolio. As a 

result, the five utilities with the highest average rates of greenhouse gas emissions are four 

G&T cooperatives and one municipal utility (for Omaha, Nebraska).678

 

674 See Texas Elec. Cooperatives, http://www.texas-ec.org/about (last visited Nov. 28, 2014) (“TEC was 

established in 1941 as a coalition of electric cooperatives formed to have greater bargaining leverage 

with power suppliers.”).

675 U.S. Dept. of Ag., USDA Rural Development, http://www.rurdev.usda.gov/UEP_HomePage.html (last 

visited Nov. 28, 2014). This work is authorized under 7 U.S.C. § 901 et seq.

676 Cooperative Research Network, The Changing Cost of Solar Power: Financing Options for Electric 

Cooperatives (Oct. 2013), available at 

https://remagazine.cooperative.com/About/PastIssues/Feb2014/Documents/TheChangingCostofSolarP

owerFinancingOct2013.pdf, at 1.

677 National Rural Utilities Cooperative Finance Corporation, Overview, 

https://www.nrucfc.coop/content/cfc/about_cfc/overview.html (last visited Nov. 28, 2014).

678 Jeff McMahon, 5 Dense Carbon Polluters in EPA Crosshairs, Forbes Magazine (June 1, 2014), available 

at http://www.forbes.com/sites/jeffmcmahon/2014/06/01/5-dense-carbon-polluters-in-epacrosshairs/.
233

However, this fact does not paint a complete picture of publicly owned utilities’ efforts 

to reform their electricity supplies. As detailed below, numerous cooperatives and 

municipalities have taken significant steps to incorporate large quantities of renewable 

electricity into their system mix, and to reduce local demand for electricity through efficiency 

measures. Many of these efforts have been undertaken solely to reduce costs for the city’s 

residents or cooperative members, rather than being required by regulatory mandates. These 

efforts can and must continue; the CPP’s building Blocks 3 and 4 offer huge opportunities for 

savings that will be required for these utilities to meet EPA’s emission reduction goal. 

The following two sections detail efforts by numerous public utilities to acquire 

renewable energy resources and increase efficiency, offer suggestions where appropriate, and 

conclude that cooperatives and municipal (and other public) utilities have numerous tools 

available to significantly improve their generation profiles over the next five to fifteen years.

a. Renewable Energy

Public power utilities and cooperatives are not strangers to renewable energy resources.

As a percentage of total owned generation, public power utilities actually have a much higher

percentage of renewable energy capacity than do investor-owned utilities: 18.5 percent versus

7.82 percent.

679 Thus, there is nothing inherent to the public power model that makes it more

difficult to acquire or utilize renewable energy resources.

In fact, smaller public power utilities are uniquely well placed to incorporate large levels of

renewable energy for several key reasons. The first, and perhaps most compelling, reason for

this is that renewable energy can be built in smaller increments and scaled up as demand from

the utility grows. This makes it a preferable investment especially for small utilities, because it

prevents them from having to commit too many resources to any individual power source.

Municipal utilities are also well-suited to renewable energy projects because renewable

generation projects are characterized by high up-front capital costs and low operation and

maintenance costs. As public entities, municipalities can access low-interest bond funding

models to finance these projects at much lower rates than investor-owned, or other publicly

held, utilities.

Electric cooperatives are also able to take advantage of the long payback timeframes

that come with renewable energy installations, because they have access to unique financing

 

679 The American Public Power Association puts together an annual statistical report, select portions of 

which are available to non-members. The data supporting the above calculations are from the 2014-

2015 Annual Directory & Statistical Report, and specifically, the following tables: “U.S. Electric Utility 

Industry Statistics,” available at 

http://www.publicpower.org/files/PDFs/USElectricUtilityIndustryStatistics.pdf, and “Renewable 

Capacity & Generation,” available at

http://www.publicpower.org/files/PDFs/RenewableCapacityandGeneration.pdf.
234

mechanisms for renewable energy development, including the Clean Renewable Energy Bond

(“CREB”), which is available to electric co-ops, and state and local government to finance

qualifying renewable energy facilities. According to USDA Secretary Tom Vilsack, “[s]ince 2009,

USDA has funded over $1 billion in renewable energy projects that will generate more than 447

MW—enough energy to power 160,603 American homes annually.”680 The National Rural

Utilities Cooperative Finance Corporation recently partnered with the Federated Rural Electric

Insurance Exchange and the National Renewables Cooperative Organization to enable

cooperatives to access tax equity financing for the development of community solar

programs.681 The National Rural Electric Cooperative Association (“NRECA”) is also working with

CFC and fourteen cooperatives from across the country, with support from DOE’s Sunshot

Initiative, to develop a standardized PV system package that will significantly reduce soft costs

for solar PV installations.682 This project, known as Solar Utility Network Deployment

Acceleration, also offers training and technical expertise to help cooperatives with utility-scale

solar projects.

Finally, as highlighted above, cooperatives tend to be concentrated in rural, open areas

of the Midwest and plains states down to northern Texas, which happen to be the areas of

higher onshore wind potential in the United States.683 Thus, these cooperatives are able to take

advantage of the lowest wind prices in the country and already have, as described further

below.

i. Renewable Energy Success Stories 

As a result of the several advantages highlighted above, numerous municipal and

cooperative utilities have achieved great success in acquiring low-cost renewable energy

resources. The following examples are just a few of many examples of municipal utilities making

the prudent decision to take advantage of the low and stable long-term pricing available from

renewable energy generators.

Many public power utilities are on the forefront of renewable energy development.

Austin Energy, a municipal utility that owns a 50 percent share of the 1690 MW Fayette coal

plant, has recently signed a 20-year power purchase agreement for 150 MWs of solar energy at

 

680 Vilsack, T., U.S. Sec’y of Agric., Rural Electric Cooperatives: Leaders in Renewable Energy (May 9, 

2014), available at http://blogs.usda.gov/2014/05/09/rural-electric-cooperatives-leaders-in-renewableenergy/#sthash.SYjfYDfT.dpuf.

681 Press Release, National Rural Utilities Cooperative Finance Corporation, CFC, Federated and NRCO 

Launch Pilot Program to Develop Electric Cooperative Solar Power Projects (Sep. 5, 2013), available at

https://www.nrucfc.coop/content/cfc/news_analysis/news/press_release_09052013.html

682 NRECA, SUNDA (Solar Utility Network Deployment Acceleration) Project, 

http://www.nreca.coop/what-we-do/cooperative-research-network/renewable-distributedenergy/sunda-project (last visited Nov. 28, 2014).

683NRECA Map, supra n. 673; NREL, United States – Wind Resource Map, 

http://www.nrel.gov/gis/pdfs/windsmodel4pub1-1-9base200904enh.pdf (last visited Nov. 28, 2014).
235

record low prices—below 5 cents per kWh.684 This project will be completed in 2016, within 18

months of when the contract was signed, and will provide energy at far less than the prices

Austin Energy currently pays for natural gas, coal, and nuclear energy.685 Similarly, CPS Energy,

a Texas municipal utility serving the San Antonio area, has also signed PPAs for over 400 MW of

solar energy.686 Outside of Texas, in late 2012, the Los Angeles Department of Water and Power

(LADWP) signed two power purchase agreements with two solar power plants in Nevada,

adding up to 460 MW.687 LADWP has also made a commitment to be coal-free by 2025.

688 And

finally, in late 2013, the 51 MW Hancock wind project in Maine announced that it would sell its

output to the Burlington Electric Department, and to the Massachusetts Municipal Wholesale

Electric Company (“MMWEC”), which has 17 member municipal utilities.689

The transition to renewable generation is not limited to large, progressive

municipalities, though: Omaha Public Power District (“OPPD”), which was listed by Forbes as

one of the five most polluting utilities in the country (per MWh generated), has been

aggressively transitioning to renewable energy. With construction of the Grand Prairie Wind

Farm and retirement of three of five units at the North Omaha coal-burning power plant, OPPD

will be generating a third of electricity from wind power; the OPPD Board recently affirmed this

step by publicly committing the utility to at least maintain this level of renewables for 20

years.690 Meanwhile, high-level commitment at smaller utilities can achieve huge results: the

 

684 See Press Release, Recurrent Energy, Recurrent Energy Awarded 150 MW Utility-Scale Solar Contract 

By Austin Energy For Texas Solar Projects (May 15, 2014), available at

http://recurrentenergy.com/press-release/recurrent-energy-awarded-150-mw-utility-scale-solarcontract-by-austin-energy-for-texas-solar-projects.

685 Wesoff, E., Austin Energy Switches from SunEdison to Recurrent for 5-Cent Solar, Greentech Solar 

(May 16, 2014), available at http://www.greentechmedia.com/articles/read/Austin-Energy-SwitchesFrom-SunEdison-to-Recurrent-For-5-Cent-Solar. Austin Energy also has a goal of achieving 35 percent 

renewable energy by 2020. See Austin Energy Resource, Generation and Climate Protection Plan to 

2020, http://austinenergy.com/wps/wcm/connect/d9260888-0811-47a0-99d2-

09b130121317/2012resourceGenerationClimateProtectionPlanto2020.pdf?MOD=AJPERES (last visited 

Dec. 1, 2014).

686 Hill, J., OCI Solar Power Breaks Ground on 400 MW San Antonio Solar Farm, Clean Technica (Mar. 6, 

2013), available at http://cleantechnica.com/2013/03/06/oci-solar-power-break-ground-on-400-mwsan-antonio-solar-farm/.

687 Press Release, Los Angeles Dept. Water & Power, Los Angeles Takes Major Step Toward Clean Energy 

Future as LADWP Board Approves New Solar Power Agreements (Oct. 4, 2012), available at 

http://www.ladwpnews.com/go/doc/1475/1570631/Los-Angeles-Takes-Major-Step-Toward-CleanEnergy-Future-as-LADWP-Board-Approves-New-Solar-Power-Agreements. One PPA is for a 20-year 

term, at about 9.6 cents per kWh, and the other is a for a 25-year term at 9.2 cents per kWh.

688 Id.

689 Press Release, First Wind, MMWEC, First Wind Sign Contract for Hancock Wind Project Energy (Dec. 

13, 2013), available at http://www.firstwind.com/wp-content/uploads/2014/03/MMWEC-PPA-HancockFINAL-121313.pdf.

690 Atkeison & Johansen, Listening to the Future: Omaha Public Power District Works on Maintaining 

Clean, Renewable Energy, Prairie Fire (July 2014), available at 

http://nebraskansforpeace.org/oppd_works_on_clean_energy. 
236

Sterling Municipal Light Department, a public utility providing power to a small Massachusetts

town, has already built out solar projects sufficient to meet 30 percent of its peak load, and was

recognized by the Solar Electric Power Association as the top utility in the country in terms of

solar capacity (in watts) per customer, beating out much larger utilities in more solar-friendly

regions by a huge margin.691

Rural electric cooperatives, both distribution coops and generation & transmission, are

also increasingly making renewable energy part of their portfolios. As NRECA notes, “Co-ops are

making significant investments in renewable resource generation, using loans from the Rural

Utilities Service and other sources. With solar becoming more cost-competitive, solar

development is growing quickly: “with the addition of 144 MW of solar capacity by 2017,

cooperatives will more than double existing solar capacity,” which is currently 95 MW across 34

states.692 Electric co-ops are poised to invest hundreds of millions of dollars in new projects. In

addition, co-ops purchase renewable energy from large projects such as the 31 MW Cimarron

Solar Facility in New Mexico and the 7.7 MW Azalea Solar Power Facility in Georgia.”693

Meanwhile, nearly 40 cooperatives have developed or are planning community solar programs,

recognizing that solar diversifies the fuel portfolio, and helps to build new community

partnerships, which is a key cooperative value.694

But development is not limited to solar or wind power. Powering of existing dams to

provide hydroelectricity has received significant attention in recent years, and has the potential

to add up to 12 GW of new capacity, concentrated at least partially in regions where renewable

energy utilization is otherwise quite low (i.e., the South and Midwest).695 These projects require

an especially long-term investment, for which municipalities and cooperatives are well suited.

For instance, AMP-Ohio, which represents 123 municipal utilities across six states, is currently

developing five hydropower repowering projects in Ohio.696

 

691 Solar Electric Power Association, Sterling Municipal Light: A Small Utility Goes Big on Solar (Oct. 28, 

2014), available at https://www.solarelectricpower.org/utility-solar-blog/2014/october/sterlingmunicipal-light-a-small-utility-goes-big-on-solar.aspx#.VHWarpPF8vY; Solar Electric Power Association, 

Solar Power Stats, http://www.solarelectricpower.org/media/169342/solar-rankings-infographic2013.pdf (last visited Nov. 28, 2014).

692 NRECA, Cooperative Solar: Driven by Cooperative Principles, http://www.nreca.coop/wpcontent/plugins/nreca-interactive-maps/esri-solar-story-map/index.html (last visited Nov. 28, 

2014).

693 Press Release, NRECA, NRECA Unveils Interactive Website Trackign Cooperative Solar Development 

(Nov. 7, 2014), available at http://www.nreca.coop/nreca-unveils-interactive-website-trackingcooperative-solar-development.

694 Id.

695 Hadjerioua et al, DOE, An Assessment of Energy Potential at Non-Powered Dams in the United States 

(Apr. 2012) ,available at http://www1.eere.energy.gov/water/pdfs/npd_report.pdf, at 22-24. 

696 Bishop, N., Water Ways, Int’l Water Power and Dam Construction (June 20, 2008) ,available at 

http://www.waterpowermagazine.com/features/featurewater-ways/. 
237

NRECA has produced an interactive map detailing how hundreds of cooperatives are

diversifying their portfolios using renewable energy.697 According to NRECA, as of April 2014 95

percent of NRECA’s distribution members (794 out of 838) offer renewable energy options to

their 40 million customers.698 These cooperatives collectively own and buy over 5.9 GW of

renewable capacity, including 1.1 GW of owned capacity, and 4.8 GW procured under longterm power purchase agreements.699

b. Energy Efficiency

Public power utilities and cooperatives also have significant advantages over investorowned utilities that should enable them to at least match, and possibly exceed, national energy

efficiency gain averages. Cooperatives are well placed to embark on significant energy

efficiency programs for many of the same reasons they can be leaders in incorporating

renewable generation: they have access to federal funding and development support that can

be harnessed to make them leaders in the efficiency space. For instance, in December 2013 the

U.S. Department of Agriculture expanded its RUS, which (as explained above) provides funding,

loan guarantees, and administrative support to rural electricity cooperatives, by adding an

Energy Efficiency and Conservation Loan Program.700 Under this program, the Department plans

to provide up to $250 million in energy efficiency loans specifically to rural cooperatives in 2014

alone, with more expected in future years.701 As with renewables, cooperatives can obtain

additional funding from the National Rural Utilities Cooperative Finance Corporation, which

raises funds from capital markets to supplement the loan programs offered by RUS.702

In addition to these federal initiatives, many cooperatives are part of broader selfcoordinated energy efficiency efforts, most notably including that orchestrated by Touchstone

Energy. Touchstone Energy, founded in 1998, is a massive alliance of almost 750 local

cooperatives, and acts both as a unified advocate for cooperative utility interests externally,

 

697 See NRECA, Cooperatives & Renewable Energy, http://www.nreca.coop/wp-content/plugins/nrecainteractive-maps/RenewableEnergy (last viewed Nov. 28, 2014).

698 Id.

699 Id.

700 U.S. Dept. of Agriculture, Energy Efficiency and Conservation Loan Program, 78 Fed. Reg. at 73,356 

(Dec. 5, 2013). 

701 Press Release, U.S. Dept. of Agriculture, Agriculture Secretary Vilsack Announces energy Efficiency 

Loan Program to Lower Costs for Consumers, Reduce Greenhouse Gas Emissions (Dec. 4, 2013), 

available at http://www.usda.gov/wps/portal/usda/usdahome?contentid=2013/12/0228.xml.

702 National Rural Utiltiies Cooperative Finance Corporation, Life at CFC, 

https://www.nrucfc.coop/content/cfc/careers_at_cfc/life_at_cfc.html (last visited Nov. 28, 2014); see 

also Press Release, NRECA, Statement on USDA’s New Energy Efficiency Rule (Dec. 4, 2013), available at 

http://www.nreca.coop/statement-usdas-new-energy-efficiency-rule (supporting USDA’s efforts in this 

area).
238

and as a facilitator of inter-cooperative cooperation and standards setting.703 It has been a

leader in developing energy efficiency standards for its cooperatives, through its “Together We

Save” program. Started in 2009, and the first (and to-date the only) utility-driven national effort

to improve energy efficiency, the program offers model efficiency standards, individual

consulting, and other support for local cooperatives seeking to increase energy efficiency at

homes, farms, commercial and industrial facilities, and public facilities (airports, jails, etc.).704

Municipal and public utilities do not always have the same access to rural development

assistance that cooperatives have, but they have other key advantages that should enable them

to achieve significant efficiency improvements more easily than investor-owned utilities. As

with renewable energy, a substantial chunk of energy efficiency investments have long-term

payback windows, and municipal utilities are well suited to make those investments with lowinterest bond issuances. But beyond that, unlike generation projects, which are usually

centralized (the rise of distributed generation notwithstanding) and easily orchestrated by a

single entity, efficiency programs require small improvements by thousands, or even millions,

of individual electricity consumers. Private and cooperative utilities can establish incentive

programs to achieve these gains, but municipal utilities are often directly connected to, or at

least affiliated with, their municipal governments. As a result, they are more likely than other

owners of covered facilities to be able to directly implement local regulations and measures

that can achieve substantial efficiency gains.

As with cooperatives, public utilities also have access to federal and peer assistance to

help implement effective energy efficiency measures. Most notably, the Department of Energy

and EPA are facilitating the State and Local Energy Efficiency Action Network (“SEE Action”),

which is a stakeholder-driven initiative (with municipal utilities like the Los Angeles Department

of Water and Power and Tacoma Power in its executive group along with state utility

commissions and other efficiency experts) that provides state and local governments with tools

and resources to assist in implementing energy efficiency measures.705 SEE Action has

established a goal of achieving all available “cost-effective” energy efficiency improvements by

2020.706

 

703 Touchstone Energy Cooperatives, About Touchstone, 

http://www.touchstoneenergy.com/content/about-touchstone-energy-cooperatives (last visited Nov. 

28, 2014).

704 Touchstone Energy Cooperatives, Together We Save, http://www.togetherwesave.com (last visited 

Nov. 28, 2014); see also Touchstone Energy Cooperatives Business Energy Advisor, Sector Reports, 

http://bea.touchstoneenergy.com/content/sector-reports-0 (last visited Nov. 28, 2014) (detailing 

efficiency improvement options in a variety of sectors).

705 State & Local Energy Efficiency Action Network, Home Page, 

https://www4.eere.energy.gov/seeaction (last visited Nov. 28, 2014).

706 Id.
239

ii. Energy Efficiency Success Stories 

As a result of all of these programs, many cooperatives lead the nation in energy

efficiency efforts. Part of this leadership has come, as might be predicted, from federal

assistance programs. Just over a month ago, the U.S. Department of Agriculture announced

that it had issued its first two loans under the Energy Efficiency and Conservation Loan

Program. The Department will lend $4.6 million to the North Arkansas Electric Cooperative to

fund installation of new geothermal and air pumps, efficient lighting, weatherization measures,

and other efficiency improvements throughout the region. It will lend $6 million to North

Carolina’s Roanoke Electric Membership Corporation to finance improvements to HVAC

systems, appliance replacements, and building improvements.707 Separately, the Alaska Village

Electric Cooperative received a $200,000 grant from the Department of Agriculture Rural

development unit to conduct energy audits of 42 businesses in native communities and identify

key efficiency improvement opportunities.708

Even without federally subsidized programs, however, cooperatives still have achieved

significant energy efficiency gains in recent years. As of 2012, over 96 percent of cooperatives

had energy efficiency programs in place, 70 percent offered financial incentives to promote

additional efficiency, and 73 percent had made public plans to significantly expand their

existing programs over the next several years.709 As with renewable energy, NRECA has

produced an interactive map detailing hundreds of programs run by cooperatives, noting

additionally which ones are part of broader programs like the “Together We Save” program.710

To give just one example, in Minnesota, Great River Energy in 2008 spent $20 million on

conservation and demand response programs, including nearly $7 million spent on lighting and

pump improvements and distributed solar generation, enabling it to reap 636 million kilowatthours of lifetime savings and to reduce summer peaks by nearly 13 percent.

711

Similarly, there are several municipal agencies who have taken positions of leadership in

the field in pushing for significant energy efficiency improvements. Austin Energy has been a

leader for decades in improving energy efficiency; by its own calculations, the utility reduced

demand by 700 MW between 1982 and 2007, and it has set a goal of saving an additional 800

MW of demand by 2020. To accomplish this, the utility spends upwards of $36 million,

composing almost 3 percent of its total budget, capturing energy savings opportunities,

 

707 Johnson, J., USDA Efficiency Program Kicks Off with 2 Co-ops, Electric Co-op Today (Oct. 23, 2014), 

available at http://www.nreca.coop/usda-efficiency-program-kicks-off-with-2-co-ops/.

708 Holly, D., Alaska Co-op Promotes Business Energy Savings, Electric Co-op Today (Aug. 29, 2014), 

available at http://www.ect.coop/efficiency-conservation/energy-efficiency/alaska-co-op-promotesbusiness-energy-savings/73095.

709 NRECA, Electric Cooperatives and Energy Efficiency: A Snapshot, https://www.nreca.coop/wpcontent/uploads/2013/07/ElectricCooperativesEnergyEfficiencySnapshot.pdf (last visited Nov. 28, 2014) 

[hereafter, “NERC Snapshot”].

710 See NRECA, Cooperatives & Energy Efficiency, http://www.nreca.coop/wp-content/plugins/nrecainteractive-maps/EnergyEfficiency/ (last visited Nov. 28, 2014).

711 NERC Snapshot, supra n. 709.
240

including by providing rebates that encourage individual consumers to weatherize their homes,

upgrade lighting, and make other such improvements.712 In California’s Central Valley, the

Sacramento Municipal Utility District is another example of a leading municipal utility in this

area, obtaining large demand reductions with a similar portion of their budget; this effort

notably included a program incentivizing developers to make new buildings up to 30 percent

more efficient than would be required under local energy codes.713 And again, these success

stories are not limited to large municipalities: Holyoke Gas & Electric has one of the most

generous efficiency programs in the country, offering zero-interest loans to both commercial

and residential customers to make various energy efficiency improvements.714

We note additionally that both cooperatives and municipal utilities have been industry

leaders in implementing demand response programs, both to further reduce electricity demand

and to contribute to overall system reliability—cooperatives provide about 10 percent of

electricity sales, but are responsible for almost 25 percent of peak load management capacity,

and 21 percent of customers with demand response capabilities.715 (See our reliability

comments for more information on demand response programs.) Some of this response has

been achieved through innovative market structures that may help guide efforts elsewhere: in

North Dakota, Minnkota Power reduced peak power demand using a power price “traffic light”

alerting members when prices change and inviting them to reduce power usage in response.716

But municipalities have also had significant success simply by providing meaningful funding to

these programs—Fort Collins Utilities, a Colorado municipal utility, has had huge success

developing demand response services, reducing total use by 1.5 percent at a cost of $0.02/kwh

saved (making it the utility’s lowest-cost electricity resource), simply by increasing annual

demand response funding to $5 million a year.717

B. Summary

As this section of our comments demonstrates, there is significant potential for

municipal utilities and cooperatives to meet greenhouse gas emission reduction targets just as

investor-owned utilities and independent power producers will be expected to do. In fact, in

many ways cities and cooperatives are better set-up than investor-owned utilities to achieve

 

712 Freischlag, K., Southwest Energy Efficiency Project, Municipal Utility Energy Efficiency Programs: 

Leading Lights (Mar. 2011), available at 

http://swenergy.org/publications/documents/Municipal%20Utility%20Energy%20Efficiency%20Program

s%20-%20Leading%20Lights.pdf, at 2.

713 Id. at 4.

714 Holyoke Gas & Electric, Commercial Energy Conservation Program, 

http://www.hged.com/customers/save-energy-money/for-business/commercial-energyconservation/default.aspx (last visited Nov. 28, 2014); Holyoke Gas & Electric, Residential Energy 

Conservation Program, http://www.hged.com/customers/save-energy-money/for-home/residentialenergy-conservation/default.aspx (last visited Nov. 28, 2014).

715 NERC Snapshot, supra n. 709.

716 Id.

717 Freischlag, supra n. 712, at 1-2.
241

these reductions through expansive renewable energy and demand side management

programs. EPA did not specifically address the question how to apply the CPP to these energy

providers, and so we ask that EPA allow for further notice and comment on any specific

proposals relating to them.

We support EPA addressing these issues in depth, however, because states often do not

exercise the same level of jurisdiction over municipalities and cooperatives that they do over

investor-owned utilities, making the state plan-driven process less optimal for sources operated

by cooperatives and publicly-owned utilities. We also note that this potential complication

provides additional support to our recommendation, shared elsewhere in these comments, that

enforcement of the CPP fall entirely on sources (and by extension on all utilities, including

municipalities and cooperatives), rather than on states, who have limited control over their

own power infrastructure. We note that NRECA has asserted that the CPP “goes too far, too

fast.”718 However, NRECA’s stated concerns about reliability mirror those shared by other major

grid operators, which we have rebutted elsewhere in our comments.

That said, cooperatives in particular serve some of the poorest and least connected

parts of the United States, and so EPA should explore opportunities to enforce the CPP without

unduly impacting poor communities.719 The CPP offers a significant opportunity for community

investment in energy efficiency and distributed renewable generation, programs which have

the potential to create high-quality jobs, and EPA should work with RUS to ensure that guidance

offered on these types of programs is appropriate for, and well-communicated to,

cooperatives. In addition, EPA should consult with the Rural Utilities Service to understand

whether the framework for RUS’s existing financing tools could be improved in order to

facilitate CPP compliance. For example, RUS may be able to streamline applications for

compliance-related financing to ensure approval in time for Clean Power Plan measures, or

seek further appropriations to make additional financing available. EPA should also consider

other existing mechanisms that already encourage renewables and efficiency build-out, and

explore how harnessing these various support networks can help municipalities and coops to

reduce their greenhouse gas emissions with minimal disruption.

XIII. Other Issues

A. EPA Should Shorten and Accelerate the Rule’s Compliance Schedule and Should 

Commit Now to An Eight-Year Review

While EPA’s primary Clean Power Plan proposal would extend the compliance period 

until 2030, the agency has also solicited comment on an alternative compliance period ending 

in 2025, with interim goals applying between 2020 and 2024. We urge EPA to adopt the shorter 

 

718 Press Release, NRECA, NRECA Statement at EPA’s DC Clean Power Plan Hearing (July 29, 2014), 

available at http://www.nreca.coop/nreca-statement-at-epas-dc-clean-power-plan-hearing.

719 See our environmental justice comments for more information on impacts to poor and diverse 

communities.
242

time frame with two additional features. First, EPA should advance the compliance schedule to 

begin as early as January 2018, rather than 2020. Second, the agency should engage in a 

continuous internal review of the rule during the compliance period and should commit to 

issuing a revised set of emission guidelines that would take effect in 2026.

Under either the 2025 or 2030 formulation of the rule, states are expected to cut their 

CO2 emissions according to the levels provided under Building Blocks 1 and 2 in the first year of 

compliance, while Building Blocks 3 and 4 require incremental cuts spaced out over the 

remainder of the compliance period. What this means is that the substantial majority of 

reductions occur early on in the compliance schedule, while later years contribute relatively 

little in the way of emission cuts. While we approve of the agency’s decision to require steep 

cuts early on, we believe that RE and EE—which are phased in more slowly under Blocks 3 and 

4—will provide much greater opportunities for emission reductions than the rule currently 

anticipates. Renewable technologies in particular are rapidly dropping in price, whereas fossil 

fuels will become increasing expensive between now and 2030. Between now and 2020, we 

expect the changing economics of the electricity sector to make RE investments significantly 

more attractive across the board, including in states that are currently resistant to these 

innovations.

EPA can capitalize on the changing landscape of energy markets by shortening and 

advancing the rule’s compliance schedule while committing to issue updated performance 

standards that will take effect in 2026. The rule currently is scheduled to take effect in 2020, 

but there is no reason that the leading states cannot submit plans by 2016, with approval in 

2017 and a phased-in compliance schedule beginning in 2018. An accelerated schedule will 

both reward states that have and plan to adopt the kinds of policies that will achieve significant 

CO2 reductions while motivating the less-inclined states to draft an approvable plan, lest they 

be subject to an EPA-issued federal plan. 

EPA should then be in a position to commence an internal review of the rule by 2020-21, 

with a proposed revision of the performance standards issuing in 2021-22 and a final rule 

scheduled for 2022-23. States would have up to two years to submit revised plans, allowing for 

a compliance period for the updated standards commencing in calendar year 2026. By adopting 

this accelerated schedule and committing to an 8-year review (similar to the 111(b) approach), 

the agency can ensure that the emission reductions required in the second half of the next 

decade are sufficiently stringent and that the rule remains maximally effective.

We also note here that we strongly oppose any effort by EPA to relax the stringency of 

the glide path or phase in emission reductions under Building Blocks 1 and 2, an issue raised in 

the agency’s recent NODA. See 79 Fed. Reg. at 64,545-46. If EPA preserves the current rule 

schedule, states and utilities will have five years after EPA finalizes the Clean Power Plan and 

two to three years after state plan approval to prepare for implementation. Moreover, under 

the current proposal, the interim goal is based on an average across all years, rather than on 

performance in any specific year, and the final goal need only be attained at the end of the 

compliance period. As such, states are free to apportion their emission reductions across the 
243

period however they choose, so long as the interim and final goals are met. This measure of 

flexibility provides a sufficient buffer against stranded assets and other technical challenges 

toward achieving compliance, and no additional relaxation of the glide-path is necessary, 

irrespective of when the compliance period begins and ends. We therefore urge EPA not to 

accede to any requests that it establish a more lenient pathway toward compliance in the final 

rule.

B. Non-BSER Measures and the Symmetry Principle

EPA has expressed that it may allow states to use non-BSER measures for compliance 

purposes. If it does so, EPA must adhere to what we refer to as the “symmetry principle”: the 

stringency of the state goals must reflect the full set of measures that can be used to comply.

In addition to the emission reduction measures included in EPA’s four building blocks, 

the agency cites a number of other methods for cutting power plant emissions. These include 

fuel-switching or co-firing at individual units, retrofitting existing fossil units with carbon 

capture and storage (“CCS”) technology, constructing new NGCC capacity to replace a portion 

of existing coal-fired generation, and implementing heat rate improvements at existing gasand/or oil-fired EGUs. See 79 Fed. Reg. at 34,875-77. Although it has not included these 

measures as part of its BSER determination EPA has solicited comments on whether states 

should be permitted to implement these or other measures instead of, or in addition to, the 

emission reduction techniques in the building blocks in order to demonstrate compliance with 

their reduction targets. See id. at 34,923.

As we discuss in section V.A.2.f, we urge EPA to include in Block 1 heat rate 

improvements at gas- and oil-fired EGUs in addition to coal-fired EGUs. We also believe EPA 

should consider incorporating grid efficiency upgrades in the EE measures permitted under 

Block 4. Fuel switching and co-firing can reduce emissions at individual units, and EPA should 

include those measures in its BSER calculation for Block 1 if they will be allowed for compliance. 

However, EPA should neither include new NGCC capacity in computing state targets nor should 

it allow states to rely on new NGCC units for compliance. It may be appropriate to exclude 

certain measures that would reduce emissions from the BSER calculation based on a robust 

analysis of cost and energy requirements, while still allowing those measures to count for 

compliance if states or affected sources choose to invest in those measures. That is the 

exception, however. As a general matter, the symmetry principle should control: if a measure is 

available for compliance, it should be included in the BSER calculation.

C. New Source Review Issues

As EPA correctly observes in the proposed rule, measures that affected sources 

implement to comply with the rule are unlikely to trigger New Source Review (“NSR”) 

permitting requirements. See 79 Fed. Reg. at 34,928. EPA requests comment on two issues 

concerning state plans’ relationship with the Act’s NSR provisions: (1) the level of analysis and 

plan requirements that may be needed to ensure that sources will not trigger NSR when 
244

complying with the state’s section 111(d) plan, and (2) whether state plans could include 

provisions determining, as a matter of law, that affected sources’ actions to comply with plan 

requirements would not subject those sources to NSR. 79 Fed. Reg. at 34,928-29. The most 

straightforward way for states to address these issues is to include in their plans source-specific 

limits on affected sources’ emissions or operations that are sufficiently rigorous to ensure the 

sources will not generate enough emissions to trigger NSR. Consistent with EPA’s NSR 

regulations, any such limits must be enforceable as a practical matter. See 40 C.F.R. § 

51.166(b)(4). Therefore, among other things, adequate testing, monitoring, and record-keeping 

procedures would have to be included in the state plan to ensure affected sources remain 

below the NSR thresholds.

Beyond such source-specific restrictions in the state plan, however, states cannot 

lawfully or rationally include in their plans generic provisions that effectively exempt sources in 

advance from NSR. The Act does not authorize such exemptions, nor can EPA allow them, 

regardless of whether the plan’s purpose is to reduce emissions. See 42 U.S.C. §§ 7475, 7479, 

7502(c)(5). EPA attempted to create a similar exemption in its 1992 and 2002 NSR regulations, 

which provided that “environmentally beneficial” pollution control projects would not 

constitute a modification triggering NSR. See 40 C.F.R. §§ 52.21(b)(2)(iii)(h), 52.21(b)(32), 

52.21(z) (2003). The D.C. Circuit invalidated the pollution control project exemption in New York 

v. EPA, 413 F.3d 3, 41-42 (D.C. Cir. 2005), holding that the CAA does not permit EPA to exclude a 

class of activities from being a “modification” that would trigger NSR. Therefore, EPA may not 

permit states to exempt affected sources’ actions to implement the Clean Power Plan from 

triggering NSR.

Moreover, EPA fails to identify any way that states could reliably assure that a system 

providing flexible compliance options such as the Clean Power Plan would foreclose specific 

sources from taking actions that would trigger NSR. Even if states were able to definitively show 

through rigorous analysis that an affected source’s implementation of section 111(d) plan 

provisions would not trigger NSR, including in the plan an exception from NSR as EPA suggests 

would create more problems than it would solve. For example, exempting affected sources’ 

actions to comply with plan requirements from triggering NSR could lead to difficult-to-answer 

questions about whether particular physical changes made at the affected source were 

undertaken to comply with 111(d) plan requirements, or were made for another purpose.

Finally, to the extent that an affected source triggers NSR due to an emissions increase that 

results from a physical change or change in method of operations, exempting that source would

undermine the purposes of the NSR program and put neighboring communities at risk. Such 

sources should be required to comply with NSR requirements, including emission limits based 

on best available control technology (“BACT”).

We would also suggest that there is no Federal or State interest in “ensuring” that the 

NSR provisions of the Clean Air Act are not triggered by sources. The NSR provisions of the Act 

wisely and appropriately require upgrading pollution controls at existing units if those units are 

modified in a way that increases annual emissions. We note that the only projects that are 

likely to increase annual emissions, and thereby trigger the obligation under NSR provisions to 
245

install modern controls, are those projects that reduce forced outages that are endemic in the 

aging U.S fleet. Many of these projects also extend the useful life of existing units. There is no 

valid public policy interest in artificially extending the “grandfathering” of existing units that 

was provided by Congress in 1970 under the expectation that existing units would soon retire 

and no longer emit at unnecessarily high levels.

Nothing in the Clean Air Act prevents owners of older, grandfathered units from 

upgrading and improving the performance of those units, provided the owners (1) install 

modern pollution controls or (2) accept enforceable permit conditions that limit annual 

emissions to levels emitted in recent years of operation. The particular path that operators of 

existing EGUs may take to comply with CAA Section 111(d) obligations and other requirements 

of Federal and State law is their decision – not a Federal or State decision. However, simply 

exempting sources from NSR provisions would encourage “life extension” programs at fossil 

fuel-fired EGUs that would undermine one of the fundamental structures of the Clean Air Act, 

the eventual end to grandfathered status where modifications increase annual emissions. It 

would also undermine the fundamental purpose of the Climate Action Plan – to transition the 

U.S. electric supply sector to lower carbon intensity technologies. The orderly retirement of 

existing units and transition to low carbon electricity generation would be severely disrupted by 

the NSR exemption that has been suggested.

D. EPA Has Correctly Based Its Emission Targets on Net Rather than Gross Generation

Every power plant uses a portion of the electricity it generates (which is called the 

auxiliary or parasitic load) to run internal processes, such as feedwater pumps, cooling fans, and 

pollution reduction systems. A unit’s net generation subtracts the auxiliary load when 

determining how much electricity the unit generates, such that it only accounts for electricity 

actually delivered for sale to the grid. By contrast, gross generation standard does not factor 

out the auxiliary load, but simply calculates the total amount of electricity produced by the 

unit’s generator. EPA has properly calculated all of the emission targets in the Clean Power Plan 

on a net output-based rather than gross output-based standard. By considering only net 

generation, EPA’s plan encourages states to minimize the auxiliary load of their electric fleet 

and maximize internal efficiencies. This will both help curb power plant CO2 emissions and 

reduce the cost of generating electricity for sale to the grid, which will, in term, help contain 

electricity costs to consumers. We therefore strongly support EPA’s decision to use a net rather 

than gross output-based standard for its 111(d) rule and urge the agency to maintain the netbased standard in the final rule.720

 

720 On the other hand, the agency’s 111(b) rule follows a gross output-based standard. We opposed this 

decision in our comments to the agency and reiterate here our belief that all section 111 standards 

should be based on net generation. See Sierra Club et al, supra n. 115, at 106-114.
246

E. Social Cost of Carbon

1. EPA Has Properly Relied On the Federal Government’s Estimates of the Social Cost 

of Carbon.

Calculating the social cost of carbon (“SCC”)—the monetized damages associated with 

an increase in carbon emissions and the corresponding benefits that would result from curbing 

emissions—is a necessary step toward developing regulations that reduce CO2 pollution and 

mitigating the many threats posed by climate change. SCC estimates allow EPA to incorporate 

the social benefits of reducing CO2 emissions into its regulatory analyses and are critical to 

assessing the overall costs of the proposed standards.721

It is important to note that section 111 of the Clean Air Act does not require a traditional 

cost-benefit analysis, but merely a showing that an agency’s determination of BSER does not 

impose costs that are exorbitant or too high for industry to bear. See, e.g. Essex Chem Corp., 

486 F.2d at 437; Lignite Energy Council, 198 F.3d at 930; Portland Cement II, 513 F.2d at 508. 

EPA may broadly consider costs, including the SCC, to make a reasoned determination that the 

benefits of the regulation justify its costs, but the law is clear: section 111 “grant[s] the agency 

a great degree of discretion in balancing” the different factors involved in a BSER 

determination, and “EPA's choice will be sustained unless the environmental or economic costs 

of using the technology are exorbitant.” Lignite Energy Council, 198 F.3d at 933 (internal 

citations omitted). We therefore discuss the benefits of the proposed rule not to indicate that a 

cost-benefit analysis is necessary, but to help demonstrate that the projected costs of 

implementation are not unreasonably high and to underscore the strong public policy rationale 

supporting these proposed standards. 

In analyzing the proposed rule’s benefits, EPA properly relied on the federal 

government’s most recent estimates of the social cost of carbon. Over the course of several 

years, the designated interagency working group (“IWG”) has developed a series of values to 

represent the cost that each metric ton of CO2 emissions will impose on society. The IWG 

utilized three cutting-edge integrated assessment models (“IAMs”)—DICE, PAGE, and FUND—to 

formulate these values. The most recent four SSC estimates for 2020 are $13, $46, $68, and 

$137 (2011$) per metric ton of CO2, reflecting discount rates of 5 percent, 3 percent, 2.5

percent, and the 95th percentile of 3.0 percent values, respectively.722 This range of estimates 

helps to represent the inherent uncertainty in projecting the social cost of carbon decades into 

the future.723

Climate change and its economic consequences are enormously complicated, and 

modeling these processes requires grappling with a large degree of uncertainty. Accordingly, 

 

721IWG, supra n. 725, at 2.

722 RIA at 4-10. In the 2013 TSD, the IWG reports these values in $2007 dollars, so they appear slightly 

lower in that document due to inflation between 2007 and 2011.

723 Id. at 8-11.
247

some simplification of these processes is necessary in order to develop a useful framework for 

modeling the impacts of climate change and the costs associated with those impacts. As the 

IWG has acknowledged, any effort to quantify and monetize climate harms raises deep 

questions of science, economics, and ethics and should be viewed as provisional.724 That being 

said, these three IAMs incorporate decades of peer-reviewed scientific research and a range of 

scenarios for emissions, population growth, and economic activities. Furthermore, these 

modeling systems have been and will continue to be updated to account for the latest advances 

and input from experts in the fields of environmental science and economics.725 The latest SCC 

estimates from November 2013 relies on the most recent versions of each modeling system. 

Among other technical updates, each model for the first time now accounts for damages that 

will result from rising sea levels, which is the primary reason for the updated SCC values’ 

increase over the 2010 estimates.726 The IWG will continue to investigate potential 

improvements to the way in which economic damages associated with CO2 emissions are 

quantified and will periodically refine the federal SCC estimates accordingly.727

Cumulatively, these models represent the best tools currently available for determining 

an appropriate social cost of carbon, and IWG’s efforts pass legal muster from a standpoint of 

federal regulatory law and policy. Moreover, the IWG’s most recently updated estimates 

utilized accepted science, economics, and technical modeling. EPA’s reliance on those estimates 

in support of the proposed rule was therefore reasonable and justified.

2. The True Social Cost of Carbon Is Likely Much Higher Than The Federal 

Government’s Estimates.

Sierra Club and other environmental organizations have proposed revisions to the IWG’s 

approach that would more robustly reflect the full costs that CO2 emissions impose on global 

society.728 Specifically, we continue to advocate for changes to the damage function and 

discount rates utilized in the modeling programs. Climate change is not always a linear process, 

and once the planet crosses a certain temperature threshold, abrupt and irreversible changes 

are likely to occur, causing massive disruption to people and natural systems. The damage 

function used in the modeling platforms calculates the loss of gross domestic product (“GDP”) 

as a quadratic function of increased global surface temperature but does not properly account 

for economic damages that are likely to intensify at a much faster rate once the global surface 

temperature increases past approximately 3 degrees Celsius above pre-industrial levels.729

 

724 IWG, supra n. 725, at 2.

725 IWG, Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under

Executive Order 12,866 (Feb. 2010), attached as Ex. 72, at 1-2, 4, 29.

726 IWG, supra n. 725, at 6-8, 10.

727 Id. at 4; IWG, supra n. 725, at 1-2, 4, 29.

728 See generally, e.g., Sierra Club, Comments on the Interagency Working Group’s (IWG) Technical 

Support Document: Social Cost of Carbon (SCC) for Regulatory Impact Analysis Under Executive Order 

12866 (Docket Not.OMB-2013-0007-0083) (Feb. 25, 2014), attached as Ex. 73 and incorporated by 

reference. herein.

729 For a more detailed discussion of this issue, see id. at 7-9.
248

Additionally, selecting the appropriate discount rate is critically important, as climate 

change is a global phenomenon that occurs over centuries, and small adjustments to the 

discount rate make a large difference over such an extended time frame. We contend that the 

discount rates used in the modeling platforms minimize the social cost of carbon estimates, as 

they do not accord a sufficient measure of equity between current and future generations. 

Rather, they presume a constant measure of positive economic growth even though the models 

predict significant GDP losses due to climate change. Moreover, they do not accurately reflect 

the level of risk aversion that policymakers are likely to exhibit in the face of increasing harm 

from climate change. 730 For these reasons, the IWG’s current approach to the SCC dramatically 

underestimates the true costs of carbon. By reevaluating and reformulating the damage 

function and discount rates, the IWG will generate a much more accurate SCC for federal 

regulators, including EPA, to use in their policymaking. 

It is also important to recognize that many climate change impacts are difficult or 

impossible to quantify in a meaningful way, and it is critical that future estimates account for 

the non-monetizable costs of CO2 emissions. For example, as noted earlier, the IPCC cites 

research indicating that 15 to 37 percent of plant and animal species worldwide may be 

committed to extinction by the mid-21st century if temperatures increase 1.6 to 1.8 degrees 

Celsius above late 20th century levels.731 This would not only have dire economic consequences 

by drastically disrupting the food supply, but would also have immense non-monetizable 

consequences to our natural world and ecological heritage. A quantitative assessment of the 

social cost of carbon—even one that accounts for biodiversity loss—cannot capture the full 

extent of these dire impacts. Similarly, the permanent loss of coastal and island communities 

due to rising ocean levels would have social, cultural, and ethical ramifications that resonate far 

beyond a quantifiable dollar figure, as would many other consequences of climate change. 732

EPA and the IWG acknowledge these and other limitations with the federal SCC analysis, 

including the “incomplete way in which the IAMs capture catastrophic and non-catastrophic 

impacts, their incomplete treatment of adaptation and technological change, uncertainty in 

extrapolation of damages to high temperatures, and assumptions regarding risk aversion.”733

EPA also notes in its RIA that the “SCC estimates are likely conservative,” and the IPCC has 

similarly found it “very likely” that monetized estimates of climate harm such as the federal SCC 

“underestimate the damage costs because they cannot include many non-quantifiable 

impacts.”734 Therefore, comprehensive regulations limiting CO2 emissions, such as the Clean 

Power Plan, will yield benefits that exceed the SCC’s predictions and extend far beyond the 

economic realm. It is critical that EPA bear this in mind as develops its final emission guidelines.

 

730 See id. at 9-15 for further analysis of the discount rate.

731 IPCC, supra n. 9, at 243.

732 See Sierra Club, supra n. 728, at 3.

733 RIA at ES-15. 

734 Id. 
249

3. The Federal SCC Values Demonstrate That the Clean Power Plan’s Benefits Far 

Exceed Its Costs.

Even the current (and overly conservative) SCC estimates indicate that the benefits of 

EPA’s Clean Power Plan proposal are substantial and far exceed its costs.735 Assuming a 3 

percent discount rate, EPA estimates net benefits in 2020 to be $27 to $50 billion (2011$) under 

a state-based approach for the 2030 compliance timeframe.736 By 2030, this range of benefits 

increases to $49 to $84 billion.737 These estimates include the quantified benefits of reduce 

climate harm as well as the health co-benefits from reduced emissions of other harmful air 

pollutants, such as SO2, NOx and PM2.5.

738 By contrast, EPA estimates that the rule’s costs will 

range from roughly $5 and $9 million per year during the compliance period.739 Even without 

taking into account important categories of impacts, such as methane emissions or ecosystems 

effects, it is clear that the estimated climate benefits and human health co-benefits far 

outweigh the compliance costs for all regulatory options and compliance approaches included 

in the proposal.740

In short, the IWG’s most recent SCC estimates point to the proposed rule’s substantial 

regulatory value, and EPA properly incorporated them into its costs analyses. The federal SCC 

values are derived from rigorous, well-tested modeling systems that reflect the cutting edge of 

environmental economic theory. Nevertheless, we also acknowledge the limitations of the 

methods used to calculate the current SCC values and will continue to push for adjustments to 

IWG’s methodology to better reflect the true (monetizable and non-monetizable) costs that 

CO2 emissions impose on global society.

 

735 Id. at 7-2.

736 Id.

737 Id.

738 Id. at 8-2. 

739 Id. at 3-1

740 Id. at 8-3.
250

Respectfully submitted,

Joanne Spalding

Alejandra Núñez

Andres Restrepo

Casey Roberts

Elena Saxonhouse

Greg Wannier

Nathan Matthews

Violet Lehrer

Natalie Spiegel

Sierra Club 

85 Second St., 2nd Fl.

San Francisco, CA 94105

joanne.spalding@sierraclub.org

Tim Ballo

David Baron

Abigail Dillen

Earthjustice

1625 Massachusetts Ave., NW

Suite 702

Washington, DC 20036

adillen@earthjustice.org