July 27, 2011

Lanelle Bembenek Wiggins

RFA/SBREFA Team Leader

U.S. Environmental Protection Agency

Office of Policy

1200 Pennsylvania Avenue, NW (1806A)

Washington, DC 20460

Re: American Public Power Association Comments to the Small Business Advocacy 

Review Panel for the Utility Greenhouse Gas New Source Performance Standards

Dear Ms. Wiggins:

The American Public Power Association (“APPA”) appreciates the opportunity to submit 

these comments to the Small Business Advocacy Review Panel for the U.S. Environmental 

Protection Agency’s (“EPA” or “Agency”) upcoming regulation under Clean Air Act § 111 

addressing greenhouse gas (“GHG”) emissions from power plants (“Utility GHG NSPS”). As 

we have discussed during our two recent meetings with the Panel, there is no doubt that the 

Utility GHG NSPS will have a significant economic impact on a substantial number of small 

entities. Indeed, that is the very reason that EPA convened a small business review panel for this 

rule. Consistent with its obligations under the Small Business Regulatory Enforcement Fairness 

Act (“SBREFA”), EPA must use all available discretion to ameliorate these adverse impacts. 

We believe that our comments illustrate how elements of the possible rule that are 

particularly problematic for small entities and offer recommendations as to how these problems 

should be solved. We ask that you consider these comments under SBREFA, Unfunded 

Mandates Reduction Act (UMRA) and the various Executive Orders including 12866, 13132

The American Public Power Association (APPA) is the national service organization 

representing the interests of the more than 2,000, not-for-profit municipal and other state and 

local community-owned electric utilities that collectively provide electricity to approximately 45 

million Americans. These utilities, or “public power” systems, are among the most diverse of 

the electric utility sectors, representing utilities in small, medium and large communities in 49 

states (all but Hawaii). Seventy percent of public power systems are located in cities with 

populations of 10,000 or less. APPA was created in 1940 as a non-profit, non-partisan 

organization. Its purpose is to advance the public policy interests of its members and their 

consumers, and to provide member services to ensure adequate, reliable electricity at a 

reasonable price with the proper protection of the environment.
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Overall, public power accounts for about 16% of all kilowatt-hour sales to retail 

electricity consumers in 49 states. Approximately 46% of the megawatt hours of electricity 

produced by public power systems are generated using coal and more than 17% of MWH are 

generated using natural gas. Our utilities have considerable experience in the use of natural gas.

This percentage of gas generation is growing since best practices for system stability dictate that 

the new intermittent resource capacity, such as wind and solar power be backed up at a 1:1 ratio 

by natural gas (mostly new Natural Gas Combined Cycle). In 2008, 27.7% of APPA member 

electric generating capacity (in Megawatts) and 46.4% of generation (in Megawatt-hours) was 

coal based. 

As we have noted from the beginning of our work with the panel, our ability to provide 

informed advice to EPA has been compromised by the Agency’s failure to provide meaningful 

information as to the specific regulatory alternatives that are under consideration. We have been 

provided with only vague and non-specific information as to the nature of the emissions 

standards that are being developed and the potential impacts of these standards on affected small 

entities. As a result, all we can do is guess as to what EPA intends to do and provide advice 

based on these guesses. This violates both the letter and the spirit of SBREFA. We urge you to 

take more time to develop clear regulatory alternatives, conduct analyses to determine the impact 

of these alternatives on small entities, and provide this information to the small entity 

representatives to enable the development and submission of informed advice.

1. EPA should not set output-based GHG emissions limits.

In our second meeting with the Panel, representatives of the National Rural Electric 

Cooperative Association (“NRECA”) provided several charts depicting actual operating 

information for several power plants. The charts from the utility sector presented information on 

a monthly block average basis of average heat rate (Btu/kWh), hours online, CO2 emissions rate 

(lb/mmBtu) and capacity factor (%). Those charts have been re-submitted by NRECA. APPA 

defers to NRECA as a peer on the panel.

These charts show that the average heat rate for each of these units varies significantly 

over time. For example, the chart for Fort Dodge – a natural gas-fired boiler operated by 

Sunflower Electric Power Corporation – shows a range from a low of 11500 Btu/kWh to a high 

of 1,3100 Btu/kWh. This means that the heat rate of this unit can reasonably be expected to 

vary by roughly 2,000 Btu/kWh. Data for the other units presented in Attachment 1 shows

similar variability.

As discussed in the meeting, this variability is not due to poor maintenance or operating 

practices. For Fort Dodge, for example, the variability is attributable to the fact that the unit is 

primarily used to back up wind resources. Serving in this function unavoidably causes the unit 

to operate less efficiently than it would if it did not need to “chase” the constantly-varying wind 

resources. This information shows that an output-based standard would not reasonably 

accommodate real-world variability in efficiency that is caused by unavoidable operating 

conditions.
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We note that several additional concerns with output-based standards were raised during 

our meetings with the Panel. For example, how would an output-based standard accommodate 

differences in parasitic load attributable to different air pollution control schemes employed at 

different plants? Similarly, as discussed in more detail below, certain utility boilers provide 

energy in multiple forms – generating not only electricity, but also heat used in district heating, 

sidewalk deicing, and industrial applications. An output based standard would not easily 

accommodate such units.

We also note that EPA has broad authority to implement work practices in place of 

numeric emissions limitations because CO2 “cannot be emitted through a conveyance designed 

and constructed to ... capture such pollutant.” CAA § 111(h)(2). In other words, because BDT 

does not currently consist of pollution control measures that “capture” CO2, EPA has clear 

authority to implement work practice standards. EPA should take full advantage of this 

authority. Doing so would avoid the need to set emissions limitations in the first instance.

But, to the extent EPA considers setting emissions limitations, EPA should use a form 

other than output-based in order to avoid the problems detailed above.

2. EPA must appropriately accommodate permitted facilities for which construction 

will not have commenced prior to the date of proposal.

Several small entities in the utility sector have recently obtained air permits authorizing 

the construction of new units, but almost certainly will not be in a position to commence 

construction on the new units prior to the date that EPA proposes the Utility GHG NSPS. As a 

result, these units stand to be regulated as new sources under the rule, which creates great 

uncertainty for the projects until the rule is finalized and ultimately may prevent the projects 

from being implemented, depending on the new source standards that are included in the final 

rule.

For example, Sunflower Electric Power Corporation (an electric co-operative that serves 

ably as a “technical expert” on the SER panel) received a PSD permit in December 2011 to 

construct a new coal-fired unit at its Holcomb Station in western Kansas. Similarly, the Holland 

Board of Public Works received a PSD permit in February 2011 to construct a 78 MW 

circulating fluidized bed (“CFB”) unit. It appears that there are just 12 projects in the 

country that are in these circumstances.

By the time an air permit is issued for such projects, years of effort and millions of 

dollars have been invested in the project. Under ordinary circumstances, the owners of such 

facilities would have ample notice of EPA’s plans to develop a potentially applicable NSPS and 

could manage their projects accordingly – either scheduling the commencement of construction 

prior to proposal or factoring potential new requirements into the original design. But, in this 

case, EPA’s rulemaking schedule was announced in late 2010 – barely six months before the 

date of proposal. Moreover, EPA negotiated the rulemaking deadlines in secret with 

environmental petitioners, making it impossible for companies to know ahead of time whether 
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the Agency ultimately would commit itself to a fixed schedule and what milestones would be 

included in such a schedule.

As a result, public power utilities (and private companies) have had essentially no 

opportunity to reasonably or realistically factor potential new source requirements into the 

design of the pending projects. This is extraordinarily unfair to the companies and puts at risk 

projects that are needed to assure reliable electric service in affected areas. EPA must take steps 

to prevent these problems. This is especially critical since some of these 12 pending plants may 

be to replace retiring units. It is very important that the U. S. EPA (and states) recognize the 

convergence of the CSPAR (replacement of the CAIR rule) and the EGU MACT/NSPS rules 

that may cause far greater retirements than the U. S. EPA expected even just a few months ago. 

One approach is simply to defer the NSPS rulemaking schedule to give companies more 

time to factor the rule into their plans. This approach would have the added benefit of giving 

EPA more time to develop regulatory alternatives, analyze these alternatives, and fully consider 

the key issues before issuing a proposed rule.

If the Agency decides to stick with the current schedule to propose the NSPS rule by 

September 30, 2011, then the rule should be structured so that it does not apply to units that 

have been permitted, but for which construction has not yet commenced. There are several 

ways that this could be accomplished. For example, EPA has broad authority to define the 

source category that will be regulated under any particular NSPS. In this case, the source 

category could be defined to exclude these units. As justification, EPA could point out that 

these would be the very newest units in the fleet and, as a result, can reasonably be 

expected to be the most efficient units of their kind. Given the severe consequences of 

regulating these units as new units under the NSPS, adjusting the bounds of the source category 

to exclude these units would be entirely reasonable.

Alternatively, EPA has broad authority to distinguish among various classes of units 

when setting standards for a particular source category. EPA could reasonably create a separate 

class for permitted units for which construction has not yet commenced and then set 

class-specific standards designed to not significantly interfere with the construction of these 

units.

But, however the new NSPS is accomplished, EPA must assure that the upcoming NSPS 

rulemaking will not unreasonably and unfairly threaten the viability of permitted projects when 

they are needed to help replace or augment needed power and maintain local reliability.

3. The Utility GHG NSPS must assure continued diversity in fuel types and power 

plant design.

A “one size fits all” approach will significantly disadvantage small entities because it 

likely will significantly constrain the choice of fuel and boiler design. For example, in our last 

meeting with the Panel, a representative from the Holland Board of Public Works (Michigan)

explained that a CFB design is critical to accomplishing the many needs that must be served by 
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the unit for the municipal utility and broader municipal government. For example, the unit will 

generate electricity, provide heat to deice sidewalks in the wintertime, and likely will be needed 

for district heating in the future. In addition, Michigan imposes a state renewable portfolio 

standard, which the City of Holland intends to meet by co-firing biosolids from the local public 

wastewater treatment plant. Such co-firing will have the added benefit of reducing the amount of 

biosolids that would otherwise need to be land-filled.

In addition, Holland needs only about 80 MW of generating capacity. The small size of 

the unit effectively precludes the application of certain technologies that might be available for 

larger units (such as so-called “ultra-supercritical” boiler designs). Another unique consideration 

for Holland is that coal to fuel the existing and the planned new power plant is received by barge. 

This allows Holland to maintain a commercial harbor designation, which qualifies the city for 

federal funds and assists in maintaining the local tourism industry.

More generally, many small entities are located in parts of the country where natural gas 

supply or the infrastructure needed to deliver that gas is limited or nonexistent. Imposing a 

standard that, for example, is based on the efficiency that can be achieved by a natural gas-fired 

combined cycle gas turbine facility would leave many small entities with no reasonable 

compliance alternatives. APPA has provided its 2010 study “Implications of Greater Reliance on 

Natural Gas for Electricity Generation”1and spoke on these concerns at the first SER meeting in 

June 2011. It is important that the U. S. EPA, U. S. Small Business Administration (SBA) and 

Office of Management and Budget (OMB) recognize that there are many states with inadequate 

natural gas delivery and storage infrastructure. While natural gas pipeline expansions can be built 

over the next four to six years, some of these smaller communities must replace their coal fired 

power plants with either coal or gas where the existing transmission lines exist. In the case of 

smaller towns where the power plant or transmission lines are in the heart of the community, 

some natural gas pipeline expansions, extensions or entirely new pipelines might not be 

permitted to be placed in central parts of the community due to safety concerns. These 

infrastructure and logistical factors must be considered by U. S. EPA and state agencies 

when NSPS is proposed for both new and existing. APPA’s study only looked at additional 

natural gas usage to the states, not to the city gates. So this means that APPA’s chart on page 6

is conservative and that gas usage at individual utilities and on individual natural gas pipelines 

may be much higher. The APPA study did not include the natural gas usage to back up 

intermittent wind and solar so these numbers are actually lower than actual usage when one 

combines the EGU MACT, NSPS pressures and installation of wind and solar power that is 

backed up with natural gas.

 

1

https://appanet.cms-plus.com/files/PDFs/ImplicationsOfGreaterRelianceOnNGforElectricityGeneration.pdf
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Excerpt 
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Like natural gas pipeline, APPA believes that storage of natural gas for the rapid 

deliverability of natural gas to electric utilities within the pipeline is critical for hourly reliability. 

Few states contain high deliverability of natural gas storage facilities due to the limitations of the 

geology. Storage for manufacturing which has predicable daily usage is very different from an 

electric utility. See Figure 15 of the APPA study (page 58).

As these examples of both unique public power communities, their locations, and the 

services that the public power utilities provide to their customers demonstrate, EPA must devise 

appropriate subcategories and/or classes of affected units so that small entities will continue to 

have reasonable flexibility as to the type of generating resources that may be built and operated. 

For example, BDT should be established for different fuel types rather than across fuel types. 

EPA also must consider remaining useful life of the units in establishing § 111(d) existing 

source performance standards.

4. Carbon capture and sequestration is promising but not a promise. CCS is not a 

viable technology that can be factored into the Utility GHG NSPS in this six year 

cycle.
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At our first meeting with the Panel, APPA distributed several papers

2

that provided an 

assessment of the current state of carbon capture and sequestration (“CCS”) as it might be 

applied as an emissions control technology to reduce CO2 emissions from power plants. These 

papers demonstrate that CCS is a promising technology, as evidenced by the several pilot 

projects that are being implemented and are planned to be implemented over the next few years. 

But, CCS will not be demonstrated and commercially available for many years to come. As a 

result, CCS does not constitute BDT for under the Utility GHG NSPS. Attachments 3, 4, 5, and 

6 are copies of the papers that were distributed at the June 2011 meeting. These APPA papers 

provide significant additional data and explanation supporting this conclusion. Copies of these 

papers are attached to the APPA NSPS comments.

5. GHG standards should not be developed for biomass combustion.

EPA recently issued a rule deferring the regulation of biomass-fired combustion units 

under the PSD program for three years. EPA justified this action by explaining:

EPA recognizes that use of certain types of biomass can be part of the national strategy 

to reduce dependence on fossil fuels, efforts are underway at the Federal, State and 

regional level to foster the expansion of renewable resources and promote bioenergy 

projects when they are a way to address climate change, increasing domestic alternative 

energy production, enhancing forest management and creating related employment 

opportunities. We believe part of fostering this development is to ensure that those 

feedstocks with negligible net atmospheric impact not be subject to unnecessary 

regulation. At the same time, it is important that EPA have time to conduct its detailed 

examination of the science and technical issues related to accounting for biogenic CO2 

emission and therefore have finalized this deferral.

3

APPA believes that it makes no sense to regulate biomass GHG emissions under the 

Utility GHG NSPS when EPA has determined that the regulation of such emissions under the 

PSD program is not currently warranted. Therefore, for the same reasons that EPA used to 

justify the PSD biomass deferral, GHG emissions from the combustion of biomass should not be 

covered by the Utility GHG NSPS.

We also note that EPA issued guidance in conjunction with the PSD biomass deferral 

explaining the “reasoning that a Prevention of Significant Deterioration (PSD) permitting 

authority may use to support the conclusion that the best available control technology (BACT) 

for carbon dioxide (CO2) emissions at a bioenergy facility is the combustion of biogenic fuels 

 

2 www.publicpower.org/files/CCS%20White%20Paper%20Links.pdf

3

76 Fed. Reg. 43490, 43492 (July 20, 2011). 
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itself.”4 This guidance was predicated on the observation that “CO2 emissions from bioenergy 

merit unique consideration in the BACT analysis because land-based biomass carbon stocks can 

be replenished more quickly than fossil fuel carbon stocks, and thus these biogenic carbon stocks 

can act as a sink on a shorter time scale than fossil carbon.”5 As a result, combustion of biogenic 

fuels should not be expected to appreciably add to atmospheric CO2 levels.

For this reason, while biomass combustion should not be covered by the Utility GHG 

NSPS, the combustion of biomass (such as co-firing in an existing coal-fired unit) should be

recognized and appropriately accommodated as a compliance technique under the rule.

6. Implementation of NSPS control measures should not trigger further regulatory 

requirements.

EPA should rely on the longstanding NSPS pollution control project exclusion to make 

sure that implementation of GHG NSPS requirements does not trigger further obligations under 

the NSPS program (e.g., transforming an existing source into a new source). Similarly, 

implementation of GHG NSPS requirements should not trigger new source review permitting.

7. EPA may not adopt an NSPS unless it makes a category and pollutant specific 

endangerment and significant contribution finding.

EPA is not authorized to regulate GHG emissions unless and until it makes a finding that 

GHG emissions endanger health or the environment and that affected units significantly 

contribute to the endangerment. A contribution/significant endangerment finding for one 

pollutant under § 111 does not authorize EPA to thereafter regulate any other pollutant.

Thank you for the opportunity to participate on the small entity review panel for the 

Utility GHG NSPS and for the opportunity to submit these comments. 

It is APPA’s strong recommendation that the U. S. EPA hold yet a third meeting on these 

important topics before proposing a NSPS for CO2. 

 

4

See Guidance for Determining Best Available Control Technology for Reducing Carbon 

Dioxide Emissions from Bioenergy Production, U.S. Environmental Protection Agency, Office 

of Air and Radiation (March 2011) at 3.

5

Id. at 6.
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Please feel free to contact me if you have questions or need more information. Due to the 

size of the CCS papers and the natural gas study, those will be sent under another e mail note 

immediately following this letter.

Sincerely,

Theresa 

 Theresa Pugh

 Director, Environmental Services

cc: Mr. David Rostker, SBA

Ms. Cortney Higgins, OMB

Mr. Robert Wayland, EPA

SER Panel Participants

Mr. Bill Wehrum