Salt River Project Responses to EPA Stakeholder Questions

Existing Power Plant Regulation under Section 111(d)

On September 23, 2013, EPA posted to the agency’s website a series of questions addressing topics the 

agency states are relevant to the potential design of a program to reduce carbon emissions from existing 

fossil fuel-fired generating units under section 111(d) of the Clean Air Act (CAA). Salt River Project 

Agricultural Improvement and Power District (SRP) has reviewed these questions, and this document 

offers SRP’s initial thoughts on the questions posed by EPA. SRP strongly agrees with EPA that the 

agency must engage in a robust discussion with states and other stakeholders regarding the design and 

implementation of the pending 111(d) program to promote maximum flexibility, ensure cost-effective 

solutions, and build upon the leadership of states in achieving carbon reductions over the past decade.

SRP is a political subdivision of the State of Arizona that provides retail electric services to more than 

950,000 residential, commercial, industrial, agricultural, and mining customers in Arizona. SRP is an 

integrated utility, providing generation, transmission and distribution services, as well as metering and 

billing services. SRP relies on a diverse portfolio of owned and purchased generation resources that 

includes coal, natural gas, hydroelectric, nuclear, solar, wind, biomass, and geothermal. SRP is an owner 

and/or operator of six coal-fired power plants located in Arizona, New Mexico, and Colorado, and five 

natural gas-fired power plants located in central Arizona. Given SRP’s ownership and operating interests 

related to fossil-fuel-fired electric generation, SRP has a clear and significant interest in this pending 

action. 

1. What is state and stakeholder experience with programs that reduce 

CO2 emissions in the electric power sector?

SRP Sustainable Portfolio Principles

Like many other utilities, SRP continues to enhance our use of renewable resources and portfolio of 

energy efficiency programs to manage system growth and reduce our system’s carbon emissions 

intensity. SRP strongly encourages EPA to recognize and provide credit for these efforts within the 

framework of the 111(d) emissions guidelines.

In 2004, SRP’s publicly-elected Board of Directors directed SRP to enhance its resource portfolio by 

adding significant amounts of renewable energy and sustainable resources through the development of 

“Sustainable Portfolio Principles” (SPP). The SPP has matured and intensified over the years and now 

requires SRP to ensure that 20% of SRP’s expected retail energy requirements will be met with 

sustainable resources by 2020. This target includes the percentage of retail energy requirements met 

with annual aggregate energy-efficiency savings, pricing measures, hydroelectric generation and other 

renewable generation, including that which is directly attributable to certain customers (such as rooftop 

solar and Community Solar). 

The target for Fiscal Year (FY) 2013 was 10.375% and increases approximately 1.375% per year until 20% 

is reached in FY 2020.1 SRP’s program includes an incentive for early or accelerated acquisition, by 

 1 SRP operates on a fiscal year of May 1 through April 30.
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allowing the environmental attributes of sustainable resources to be banked and applied to future years 

or sold to reduce customer costs. SRP’s target also includes the following annual incremental energy

efficiency savings: 

• FY 2012–FY 2014: 1.50% per year

• FY 2015–FY 2017: 1.75% per year

• FY 2018–FY 2020: 2.00% per year

SRP is currently outperforming the SPP targets. In FY 2013, 11% of SRP’s retail requirements were met 

with sustainable resources and more than 25% of the energy produced by SRP’s resources had no 

associated greenhouse gas emissions. SRP also exceeded its annual incremental energy efficiency target 

of 1.50%, achieving 2.25% in FY 2013.

Investor-owned utilities are regulated by the Arizona Corporation Commission (ACC), and are subject to 

the Renewable Energy Standard and Tariff (REST) approved by the ACC in 2006. Similar to SRP’s SPP 

requirements, these rules require that regulated electric utilities generate 15 percent of their energy 

from renewable resources by 2025. Additionally, the investor-owned utilities have similar energy 

efficiency targets in place through 2020. Each year, Arizona's utility companies are required to file 

annual implementation plans describing how they will comply with the REST rules. The proposals include 

incentives for customers who install solar energy technologies for their own homes and businesses. The 

Commission’s Renewable Energy Standards encourage utilities to use solar, wind, biomass, biogas, 

geothermal and other similar technologies to generate “clean” energy to power Arizona’s future.

Renewable Resources

The table below shows the renewable resource capacity mix that made up the renewable energy 

portion of SRP’s Sustainable Portfolio in FY 2012.

SRP believes that EPA must recognize that renewable energy resources serve differing needs within a 

utility’s generation portfolio and therefore the agency cannot apply general assumptions to how these 

resources might displace traditional fossil generation sources. For example, geothermal is able to 

provide baseload generation by producing emissions-free energy 24 hours a day, seven days a week. 

Solar and wind, on the other hand, are available only when the sun is shining or the wind is blowing. 

Therefore, utilities must plan accordingly for resource availability when adding renewable generation to 

SRP Renewable Energy Mix FY 2012

Source Megawatts (MW)*

Biomass Purchases 13

Community Solar/Large Solar 20

Rooftop Solar 42

SRP and Community Partnership Solar 1

Dry Lake Wind Power Project 1 and 2 

Purchases 127

Wind Purchases 50

Geothermal Purchases** 50

Landfill Gas Purchases 22

Hydropower (owned and purchased) 391

Total 716 MW
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the resource mix. This includes planning for adequate backup, fossil-fuel-fired generation when 

intermittent renewable resources are unavailable.

Energy Efficiency

Energy-efficiency programs contribute to SRP’s overall Sustainable Portfolio goal each year. For FY 2012, 

SRP exceeded the annual incremental energy-efficiency savings goal of 1.5% of retail sales by achieving 

1.81%. During the past few years, SRP has introduced more than 25 new energy-efficiency programs for 

residential and commercial customers. These programs help customers reduce energy use and costs. In 

addition, energy efficiency plays an important role in SRP efforts to meet current and future power 

demand.

As in other states, Arizona’s electricity customers are served by a mix of energy providers including 

public power, investor-owned utilities, rural electric cooperatives, and merchant entities. The 

regulatory structure providing oversight of renewables, energy efficiency and other programs that 

reduce carbon emissions is not uniform and SRP expects this will complicate crediting of such programs 

within the framework of a 111(d) compliance schema. However, the value of these programs to states 

and customers should not be underestimated, and EPA should provide opportunity for stakeholders to 

work together to address the issues necessary to allow crediting of such programs.

Navajo Generating Station Proposed Alternative to Best Available Retrofit 

Technology

EPA is in the process of finalizing a Best Available Retrofit Technology (BART) rule for the Navajo 

Generating Station (NGS) that addresses regional haze. While the BART proposal focuses on the 

reduction of nitrogen oxides (NOx) as a visibility impairing pollutant, a BART alternative proposal 

submitted by a Technical Work Group (TWG) would likely lead to carbon emission reductions.

EPA’s February 2013 Proposal

On February 5, 2013, EPA issued a proposed BART rule for NGS. This 2,250 MW (net) coal-fired baseload 

plant is located on the Navajo Nation in northern Arizona and has six participants: U.S. Bureau of 

Reclamation, Salt River Project, Los Angeles Department of Water and Power, NV Energy, Arizona Public 

Service and Tucson Electric Power. SRP is the plant’s operating agent.

EPA’s February 2013 proposal would impose a plant-wide average NOx emission limit of 

0.055 lb/MMBtu, which would require installation of selective catalytic reduction (SCR) equipment on all 

three units at NGS within five years of the final rule. EPA also proposed an alternative that would give 

the NGS owners credit for early installation of low-NOx burners and separated overfire air (LNB/SOFA) at 

NGS, and allow SCR to be installed on one unit per year between 2021 and 2023. 

Both the EPA’s BART Determination and the BART Alternative require the installation of controls on a 

schedule that is potentially unworkable for the NGS participants and threatens the future viability of the 

plant, due to the complicated nature of the lease agreement for the plant site, the partial federal 

ownership of the plant, and other factors. 

In recognition of the unique and complex nature of this issue, EPA also invited the submittal of other 

BART alternatives that achieve the same or greater emission reductions as EPA’s BART determination. 
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Given the challenges imposed by the schedules proposed by EPA in its BART determination and BART 

alternative, SRP proceeded with development of an alternative BART proposal.

Technical Work Group Agreement

For several months, SRP collaborated with a TWG to develop a BART alternative for submittal to EPA. 

The TWG includes SRP, the Central Arizona Water Conservation District, the Environmental Defense 

Fund, the Gila River Indian Community, the Navajo Nation, the United States Department of the Interior, 

and the Western Resource Advocates. 

The TWG reached an agreement that was submitted to EPA on July 26, 2013 (“TWG Agreement”). The 

TWG Agreement includes a BART alternative (“TWG Alternative”) that would achieve even greater 

emissions reductions than EPA’s BART determination, while providing greater flexibility to the NGS 

participants to resolve the uncertainties facing the plant before having to invest significant capital in 

additional controls.

The TWG Alternative includes two alternatives that both achieve even greater NOx emission reductions 

than EPA’s proposed BART determination. While the BART alternatives currently under consideration 

focus on the reduction of NOx, SRP notes that if EPA proceeds with adoption of either TWG alternative, 

there would also be significant reduction of carbon emissions at NGS due to a commitment to curtail 

coal generation or cease coal generation on one of the plant’s three units. If the TWG alternative is 

promulgated in the final BART rule for NGS, SRP believes that NGS owners should receive credit towards 

compliance with any emissions reductions targets established under Section 111(d).

Research and Development Activities

According to the Electric Power Research Institute (EPRI), “no single technology will suffice in meeting 

[carbon] emissions reduction goals – a diverse portfolio of advanced technologies is needed.” 2

 To this 

end, SRP invests in research on technologies to achieve carbon emission reductions from SRP’s power 

generation fleet. Since 2000, SRP has invested more than $50 million in research and development 

through EPRI and local universities, with a particular focus on topics such as energy efficiency, power 

plant efficiency improvements, renewable resources, and carbon capture and sequestration (CCS).

Through EPRI, SRP has partnered with process developers, the U.S. Department of Energy (DOE), and 

other electric utilities to demonstrate technologies through construction and operation of pilot-scale 

and process validation-scale systems. In addition to validating the process efficacy for removing carbon 

dioxide (CO2), a major goal of the demonstrations is to reduce the large energy requirements – both 

electrical for pumps and compressors; and steam that is extracted from the power generation cycle.

In addition to these demonstration projects, SRP has been supporting EPRI’s strategic research on three 

major activities:

• Process Simulations – These efforts include in-house modeling to identify target properties of 

solvents, solid sorbents, and membranes for CO2 capture; develop new hybrid separation 

schemes; and evaluate third party carbon capture processes.

 2

 Electric Power Research Institute, The Full Portfolio, Electric Perspectives, January/February 2008, Page 51.
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• Materials Development – These efforts focus on development and testing of early stage, novel 

separation materials at laboratory scales.

• Bench- and Pilot-testing – These efforts involve testing of potential capture processes.

EPA should recognize that research and development investments such as those funded by SRP are 

critical to ensuring continued progress in development carbon reduction technologies, but should also 

acknowledge that significant additional work is needed before many of these technologies are market 

ready and cost-effective for commercial deployment at the utility scale.

2. How should EPA set the performance standard for state plans?

SRP understands from review of the statutory provisions of Section 111(d) that states – not EPA – have 

the primary responsibility and authority to establish and implement performance standards for existing 

fossil-fuel-fired electric generation sources. EPA is to establish emissions guidelines that are provided to 

the states that provide direction to the states to set performance standards.

Emissions Guidelines

In establishing the emissions guidelines, EPA is required to define the parameters for states to set 

performance standards for sources using the Best System of Emission Reduction (BSER) that has been 

determined to have been “adequately demonstrated” and is “achievable” for each source type. Section 

111(d) allows for consideration of the cost of achieving such reductions and any non-air quality health 

and environmental impacts and energy requirements that may result. Because the emissions guidelines

must be achievable by each source type, SRP believes EPA must establish separate guidelines for electric 

generating units based upon fuel source and technology. For example, there should be separate 

emissions standard for coal-fired units and natural gas-fired units, and further sub-categorization for 

pulverized and fluidized bed coal-fired boilers, and combined cycle and simple cycle natural gas turbines. 

Currently, there are no GHG controls for existing sources that could serve as the basis for an emission 

standard. EPA may look to setting the standard based upon what can occur within the plant fence line, 

including improvements to unit heat rates. SRP is aware of a desire by some stakeholders to include fuel 

switching and co-firing of coal with lower carbon fuels as a basis for establishing BSER, but SRP believes 

that such a mandate would result in significant economic impact on utility ratepayers and that EPA must 

recognize that alternative fuels are not available in all locations. For example, while there is significant 

natural gas availability in the western U.S., natural gas transmission is limited in some locations (Figure 

1). Similarly, access to biomass fuel for co-firing is extremely limited in the western U.S (Figure 2), and 

may be further constrained by an inability to cost-effectively harvest and ship the fuel to plant locations.

EPA must take into account regional differences in the current generation resource mix as well as 

regional factors that affect future resource development in establishing the BSER. Important baseload 

resources should not be penalized by a BSER that is plainly not achievable due to infrastructure 

constraints.
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Figure 1. U.S. Natural Gas Transportation Corridors, 2008

Figure 2. U.S. Biomass Potential
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In addition to infrastructure constraints, SRP notes that the western U.S. is different in other respects 

that warrant consideration in development of emissions guidelines. For example, there are a number of 

large power plants in the western U.S. generation fleet that have multiple owners. Decisions regarding 

capital investments and operational changes in jointly owned plants can be complicated and timeconsuming efforts due to the differences in the corporate and governance structures of participating 

owners. However, these assets are often critical providers of baseload power to customers, and are not 

easily replaced. Furthermore, these plants, and many other western plants, are located in remote 

locations where they are vital economic engines for the rural communities in which they are located. 

They provide local tax revenue that supports colleges, schools, roads, health care and other necessary

community services. SRP encourages EPA to produce guidelines that accommodate continued 

operation of these valuable western assets.

New Source Review and BSER

In establishing BSER, EPA must account for constraints and costs that may apply as a result of other CAA 

programs. Of particular concern is the effect the New Source Review (NSR) permitting program may 

have on “inside the fence” efficiency projects. Under the current NSR rules, there is a possibility that 

efficiency improvement projects could trigger NSR. SRP believes that the only way to address this issue 

is by providing a clear and direct exclusion from NSR applicability for projects that are undertaken at 

affected sources to improve efficiency and reduce GHG emissions. For example, EPA could change the 

NSR applicability rules to measure emissions increase for efficiency projects in terms of an output-based 

measure (e.g., lb/MWh), thus recognizing that such projects result in decreased emissions. Another way 

to address the issue, short of providing an NSR exclusion, would be to account for the potential cost of 

NSR permitting – which is typically large – in determining BSER, as the CAA requires. At a minimum, EPA 

should make clear that the states may, in their own implementation rules or on a case-by-case basis, 

determine that an efficiency project that would trigger NSR permitting would not be considered BSER, 

because of cost.

State Performance Standards under Section 111(d) 

Section 111(d) of the CAA gives states primacy in developing performance standards to comply with EPA 

guidelines. Although states should have the opportunity to adopt strategies that are best aligned with 

their state energy policy and electric generation resource mix, EPA will need to provide guidance on the 

range of the emissions reduction measures states may use for compliance and what procedures and 

criteria states should use to demonstrate that their plans are satisfactory. Potential flexible, systemsbased measures include actual and planned plant retirements, fleet averaging, renewable energy, 

energy efficiency programs, clean energy standards and emissions trading.

To accommodate the different economic conditions in the states, SRP believes states should have the 

flexibility to use either a mass-based or emission rate-based standard of performance to achieve 

program targets. Either of these systems has the ability to achieve carbon reductions, particularly if 

coupled with incentives for states to grow or enhance energy programs and policies that credit carbon

emissions reductions that take place outside of the plant fence line. It is important that a 111(d) 

program not constrain economic growth. EPA should recognize that it is not necessary for this program 
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to take a more traditional approach to regulation due to the premise that carbon reductions will provide 

global benefit rather than local improvement in ambient air quality. 

SRP also believes it is essential to provide credit for actions that have a co-benefit of carbon reductions. 

For example, the possible retirement or generation curtailment of a unit at NGS could have the effect of 

reducing the carbon emissions from this plant by as much as one-third. As the changes to NGS are being 

undertaken to address NOx, not carbon, there should be no constraints placed on crediting the carbon

reductions under a 111(d) program. 

Credit for Early Action

A number of states, including Arizona, have implemented policies or taken actions that have achieved 

significant carbon emission reductions in advance of Section 111(d) rulemaking. These programs have 

and will contribute to emissions reductions following the adoption of carbon standards for existing 

sources. These early action efforts have been paid for by customers and should be accounted for in 

crediting states for carbon reductions. Recognition by EPA of these early actions in the emissions 

guidelines document, particularly in informing the timeline for compliance established in the guideline, 

is important, as such recognition increases the cost-effectiveness of any given level of emission 

reductions and creates a more consistent and equitable carbon regulatory program among states. 

Regarding setting a baseline from which to measure future carbon emission reductions, SRP agrees with 

other commenters that 2005 would be an acceptable baseline year that would adequately recognize 

previous state actions to reduce carbon emissions through adoption of renewable energy and energy 

efficiency programs. 

3. What requirements should state plans meet, and what flexibility 

should be provided to states in developing their plans?

As stated previously, SRP believes that states should have broad flexibility in developing programs to 

comply with Section 111(d). States should be able to design their own plans and programs for 

compliance, but EPA must make it clear what criteria each plan should meet to be approved by EPA. 

Remaining Useful Life

SRP believes this component of the 111(d) regulatory framework plays a critical part in implementation 

strategy in Arizona and other parts of the western U.S. In general, western coal-based generation is 

newer and has more pollution controls than coal-based generation in other parts of the country. This is 

because western coal-based generation was generally constructed later, and was subject to additional 

pollution controls (and their attendant capital and operating costs) requirements than units developed 

prior to the CAA. Further, numerous western electric generating units have recently been mandated by 

EPA to install additional, expensive pollution controls under the BART provisions of the Regional Haze 

Rule. SRP is extremely concerned about the impacts to our ratepayers from stranded investments if 

carbon standards under 111(d) drive premature retirement of these important baseload assets. Any 
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rulemaking under CAA § 111(d) must allow states to fully consider the “remaining useful life” of each 

source in development of state plans and associated compliance timelines to avoid unfairly and 

disproportionately impacting units that are critical to our customers’ secure energy supply, and 

Arizona’s and other western states’ energy infrastructure. 

Energy Efficiency Programs

EPA faces challenges in incorporating utility energy efficiency programs into the framework of a 111(d) 

regulation as energy efficiency programs are not designed to directly displace specific generation units, 

but rather are a cost-effective way to avoid use of current generation resources or delay construction of 

new generation resources. Certain efficiency programs can also reduce the need to install, upgrade or 

replace transmission and distribution equipment.

By allowing utilities to reduce or manage the energy consumption on their systems, energy efficiency 

programs reduce fossil fuel use and associated carbon dioxide emissions. For this reason, SRP believes 

that EPA should allow states to include energy efficiency programs as a measure to help achieve 111(d) 

performance standards. In addition, EPA should provide states with the flexibility to determine the 

appropriate calculation mechanisms for use in that state, as there will not be uniformity in current 

program accounting across states. Also, states served by multiple utilities may not have uniformity in 

program accounting within the state. For example, some utilities may be subject to specific 

requirements imposed by a public utility commission (e.g., an investor-owned utility), while others may 

be governed by voluntary efforts or an alternate regulatory structure (e.g., a rural electric cooperative or 

public power utility). 

Renewable Resources

SRP believes EPA has already recognized that renewable resources will be an integral part of any 111(d) 

program. A Renewable Portfolio Standard (RPS) program is an important policy mechanism to 

encourage development of renewable energy, and such programs have been adopted by the majority of 

states. These policies require or encourage electricity producers within a given jurisdiction to supply a 

certain minimum share of their electricity from designated renewable resources. Generally, these 

resources include wind, solar, geothermal, biomass, and some types of hydroelectricity, but may include 

other resources such as landfill gas, municipal solid waste, and tidal energy. However, states without 

RPS policies have also seen significant increases in renewable generation over the past few years 

resulting from a combination of federal incentives, state programs, and market conditions. Increases in 

renewable generation have been driven by the availability of federal tax incentives, as well as by state 

RPS policies.

Because utility management of renewable resources varies between systems and between states, EPA 

will need to provide flexibility to states in how renewable resources are incorporated into 111(d) plans. 

As stated earlier in this document, SRP has in place Board-mandated Sustainable Portfolio Principles 

(SPP) that guide integration and use of renewable resources on the SRP system. Based on our 

experience with the SPP, SRP would recommend the following be considered when addressing use of 

renewable resources in a 111(d) program:
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• Hydro-generation must be included as a form of renewable energy regardless of facility size, or 

whether or not it is considered “low-impact” hydro-generation (i.e., it should not matter if 

electricity is generated by natural change in elevation vs. man-made change in elevation).

• Renewables used to meet a greenhouse gas standard should also be creditable towards meeting 

National Ambient Air Quality Standards (NAAQS) for criteria pollutants. As carbon dioxide is not 

a criteria pollutant regulated under the NAAQS provisions of the CAA, criteria pollutant 

reductions that are achieved as a co-benefit of 111(d) requirements should be available for 

crediting in State Implementation Plans prepared for the NAAQS program. 

• SRP believes emission reductions should be assessed using a system-wide emission factor that is 

applied to energy production. In addition, EPA needs to accommodate the contractual 

provisions of purchased power agreements (PPA) for renewable generation where the power 

purchaser has also purchased the “environmental attributes” of the renewable resource

regardless of the resource’s location – i.e., if the purchaser is located in one state and the 

resource is located in a different state, carbon reduction credits need to be preserved per the 

terms of the applicable PPA, and not also counted by the state where the resource is located.

• EPA should allow for “super-compliant” credits to be held in a bank for future use. In Arizona, 

both SRP and ACC-regulated utilities currently take advantage of credit banks.

• EPA should allow program implementation and compliance to occur across a utility’s ownership 

share (including purchased power), so SRP may obtain credit for renewable energy that it 

purchases from other states.

Unit Retirements

Although the timeline for a 111(d) program has yet to be determined, SRP assumes fossil fuel unit 

retirements will occur during the program’s duration. As unit retirements will likely offer the greatest 

opportunity for carbon reductions under a 111(d) program, unit retirements should be creditable in any 

state plan. The absence of crediting could provide the perverse outcome of encouraging marginal 

operation of existing units in order to avoid the costs associated with permitting and construction of 

new sources. Additionally, many coal-fired generating plants are co-owned by several utilities and are 

located outside Arizona. Any credit methodology must take into account these complexities.

Phased Implementation Approach

It is important that a 111(d) program not constrain economic growth. One way EPA could help 

moderate the economic impacts of the program is to apply a phased approach to implementation. SRP 

believes this approach offers promise in creating additional compliance flexibility, and would allow 

states to better tailor 111(d) programs to align with existing renewables mandates, energy efficiency

programs, emissions trading programs, or other mechanisms. It would also allow time for new carbon 

reduction technologies to be tested and made available for commercial deployment.
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Under this approach, states could establish a series of “increments” at a rate- or mass-based level based 

on measures that are more likely to be achievable in the shorter term and in the longer term. For 

example:

• Short-term reductions are based on cost-effective “low-hanging-fruit” (i.e., basic plant efficiency 

upgrades, incorporation of existing renewables and demand-side efficiency programs).3

• Mid-term reductions incorporate additional measures that are more difficult or more capital 

intensive to implement (such as more complex efficiency upgrades, fuel switching, and unit 

retirements). 

• Long-term reductions could include retirement of units that have been identified for longer term 

operation due to significant capital investments made under other EPA programs (e.g., BART, 

CSAPR, and NSR). 

Interstate Cooperation

If EPA allows states to pursue alternative, flexible compliance approaches – such as credit for plant 

retirement, trading and fleet averaging – interstate cooperation in the regulation of carbon emissions 

will be an important design issue. Section 111(d) establishes a process for state-specific plans. SRP has 

ownership in generation and transmission facilities across several states (Arizona, Colorado, and New 

Mexico) and on the Navajo Nation (in Arizona and New Mexico). SRP believes that EPA must 

incorporate provisions into the agency’s 111(d) guidelines that provide explicit incentives to states to 

work together to achieve emissions reduction goals as interstate cooperation will be a crucial 

component in advancing the environmental benefits of the 111(d) program. SRP believes the potential 

for emissions reductions will be constrained, and program costs will increase, if there is no ability to 

design state programs to accommodate system-wide compliance by affected utilities.

Flexible State Plan Development and Approval Schedule

EPA should recognize the significant effort that will be required of states in developing standards that 

protect potential economic growth, but also achieve carbon reductions consistent with EPA’s guidelines. 

EPA should also acknowledge that many states have limited resources available to accomplish this 

significant task, and that those resources are heavily constrained by the need to develop plans for other 

regulatory requirements, such as the NAAQS program. With this in mind, EPA should provide states 

with more than one year develop and submit plans, particularly in cases where the state wishes to work 

cooperatively with other states and jurisdictions in development of an approvable plan. States should 

retain primacy in this process and not be subjected to a federal plan solely due to an inability to meet 

the deadline included in the President’s Climate Action Plan. 

 3 SRP notes that many utilities have already implemented efficiency improvements at existing power plants in 

recent years in association with major pollution control projects driven by other regulatory requirements. While 

additional “low hanging fruit” may still be available, SRP suspects that this universe is small and likely constrained 

by either projected capital costs and/or NSR regulations.
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4. What can EPA do to facilitate state plan development and 

implementation?

EPA should recognize the diversity of individual states and their energy resource mix. It is important that 

EPA minimize regulatory uncertainty by providing clear guidance to states on how to design an 

approvable state plan. EPA should establish criteria for such things as state reduction targets and 

qualifying energy efficiency and renewables programs. EPA guidance should also provide options for 

implementing fleet averaging and trading of emissions for compliance purposes between two or more 

states. EPA should provide a reasonable and achievable timeline for compliance, but also provide states

with guidance on how to craft an approvable alternate timeline. With respect to program emissions 

targets, EPA’s guidance should provide the ability for each state to have a unique emissions target taking 

into account such things as local fuel supply and emissions reductions programs already in place. 

SRP encourages EPA to work closely with states and to provide time and flexibility to allow states to 

develop plans on a reasonable timeline, recognizing resource constraints and the challenges associated 

with this rulemaking effort. This will avoid the need for imposition of federal plans and promote 

effective cooperation and achievement of the emission reduction objectives set forth in EPA’s 

guidelines.