The National Rural Electric

Cooperative Association

Comments to

The Environmental Protection Agency SER Panel 

On

Rulemaking for Greenhouse Gas Emissions from Electric Utility 

Steam Generating Units

Submitted Electronically to:

Lanelle Wiggins

RFA/SBREFA Team Leader

U.S. EPA

Office of Policy

July 27, 2011

By

Rae E. Cronmiller

Environmental Counsel

4301 Wilson Boulevard, EU 11-249

Arlington, VA 22203-1860

(703) 907-5791 / rae.cronmiller@nreca.coop
NRECA GHG NSPS SER Panel Comments

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Introduction

The National Rural Electric Cooperative Association (NRECA) appreciates the 

opportunity to participate on the EPA’s Small Business Regulatory Enforcement Fairness 

Act (SBREFA) EPA Small Entity Representative (SER) panel to address the Clean Air 

Act (CAA) Section 111 NSPS GHG rulemaking for electric utility generating units 

(EGUs) and to submit our comments as part of the panel’s deliberations and 

recommendations. 

NRECA is the national service organization for more than 900 not-for-profit rural electric 

utilities that provide electric service to approximately 42 million consumers in 47 states 

or 13 percent of the nation’s population. All or portions of 2,500 of the nation’s 3,128 

counties are served by rural electric cooperatives. Collectively, cooperative service areas 

cover 75 percent of the U.S. landmass. 

Electric cooperatives are not-for-profit, consumer-owned private entities incorporated in 

states in which they reside. Sixty-five rural electric generation and transmission 

cooperatives (G&Ts) generate and transmit power to 668 of the 841 distribution 

cooperatives. The G&Ts are owned by the distribution cooperatives they serve. The 

distribution cooperatives not served by a G&T receive power directly from other 

generation sources within the electric utility sector. Fifty-seven percent of the G&Ts and 

all but four distribution cooperatives are “small business entities” as defined by 

SBREFA. Four small business entity G&Ts as SERs are participating on this SBREFA 

panel. NRECA recommendations are below.

TEXT
NRECA GHG NSPS SER Panel Comments

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The panel should have the opportunity to comment on regulatory options presented 

to it by EPA. First, we stress to EPA the difficulty in developing a “sensible” NSPS 

GHG regulatory program for small business entity EGUs under such an unrealistically 

short deadline, less than seven months from start to a proposed regulation. Developing 

NSPS for GHGs involves complexities heretofore not encountered in the NSPS context, 

because unlike other EGU emissions regulated under the CAA, there are no viable 

emissions control technologies applicable to reducing CO2, the main GHG component in 

EGU emissions. In particular, carbon capture and storage (CCS) is not developed 

technology as our comments below address in detail. Therefore, we expect EPA will 

have to rely on energy efficiency and possibly work practice standards as a means of 

Section 111 regulation. However, the SER panel has yet to see a single proposal by EPA 

on options it may be considering. This is very troubling and contrary to EPA’s own 

guidelines stipulated for SER panel input to EPA’s regulatory process.

Section 111 requires that EPA undertake an “endangerment finding” directed at 

whether EGU greenhouse gas emissions endanger public health or welfare. Section 

111(b)(1)(A) clearly requires that EPA issue a proposed regulation addressing the 

endangerment question as a prerequisite to actually regulating EGU GHG emissions. 

EPA has not yet done so.

NSPS provisions and guidelines to states should be technology-based and should not 

establish national or EGU source category-wide GHG mitigation requirements, 

reduction goals, or caps. Section 111 standards and requirements are meant to be 

technology-based and not driven by an overall emissions reduction or mitigation goal. 

NSPS by statutory definition is technology that first and foremost has been “adequately 

demonstrated,” typically referred to as “best demonstrated technology” (BDT). In this 

context, EPA has no broad mandate or even discretionary authority under Section 111 to 
NRECA GHG NSPS SER Panel Comments

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expand an NSPS rule to include provisions incorporating national or source category 

GHG mitigation goals.

Further, EPA cannot require any new or modified source to install and operate any 

particular technological system of continuous reduction to comply with any new source 

standard of performance. Since CO2 emission reduction technology does not 

commercially exist, it follows that EPA cannot impose a fuel choice that has the same 

effect as the mandate of a particular control technology.

NRECA would also point out that the U.S. Congress explicitly considered a cap-andtrade regime last year to address climate concerns and rejected such an approach. We 

believe it ill-advised for EPA to now propose an NSPS regulation that would have the 

effect of imposing a cap-and-trade policy already rejected by Congress. EPA should not 

be implementing an NSPS program in an attempt to trump Congress.

NSPS must represent “best demonstrated technology” (BDT) at the source and 

require nothing more. The intent of Section 111 is to disseminate BDT throughout the 

source category. NSPS provisions cannot be utilized in a top- down methodology where 

BDT requirements are based on or follow an overall source category reduction goal, 

national GHG emissions reduction goal, or GHG intensity averaged over multiple 

sources. Stated differently, NSPS must represent BDT for any single source including 

costs of achieving the standard. For new or modified EGUs, BDT should not effectively 

dictate any particular fuel use such as natural gas over coal or one type of coal over 

another. In other words, BDT must be fuel dependent.

NRECA does not oppose giving a source (emissions unit) the option of satisfying NSPS 

requirements by undertaking actions apart from the source (emissions unit) as long as the 

NSPS is based on source BDT. Stated differently, BDT must be established for a source 
NRECA GHG NSPS SER Panel Comments

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apart from any off-site options or strategies that may be available to some entities. 

NRECA does not oppose allowing NSPS mandates to be achieved by actions apart from 

the emissions unit so long as off-site actions do not effectively influence the source NSPS 

requirements or stringency. Participation in off-site activities must only be at the option 

of the source, not effectively dictated by any NSPS standard of requirement, and not 

economically prejudice none off-site participants. 

NRECA wants to make clear that while some utilities may benefit from an off-source or 

off-site mitigation or offset, many small entities lack economic opportunities based on 

geographic or other location factors to addresses GHGs by incorporating off-site actions. 

For those unwilling or unable to economically undertake off-source actions, factoring 

those options into a source BDT would heavily prejudice those small business entities not 

utilizing off-source options, thus hurting small business entities and not helping them. 

Promulgating an NSPS based on an output standard would be difficult if not 

impossible to implement. Consistent with presentations made to the SER panel and 

attached to these comments, an output derived standard such as CO2/Mwh metric cannot 

realistically be applied to EGUs without accounting for significant and unavoidable 

variabilities. This is the case because, as the attachments show, an EGU heat rate and 

thus the CO2/Mwh rate vary significantly over the EGU operating range and duty cycle to 

which the unit is committed. Moreover, EGU heat rate characteristics and thus the 

corresponding CO2/Mwh rates are largely unit specific, and they can be severely 

impacted by equipment conditions which cannot be quickly or easily remedied. So even 

if such individual unit variability could be accounted for in an output standard, such a 

standard would be source specific.

EPA must reconcile the proposed NSPS including any standards or guidelines with 

its interpretation of New Source Review (NSR) major modification potential 
NRECA GHG NSPS SER Panel Comments

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violations. As previously mentioned, carbon dioxide is the primary GHG associated with 

EGUs and yet there is no available technology to directly reduce carbon dioxide 

emissions from these facilities. While EPA has not expressly said so, presumably EPA 

will be looking at energy efficiency and work practice standards as no other demonstrated 

technologies exist. Many of the current EPA regulatory programs are counter-productive 

to improvements in efficiency. Efficiency improvements are gained by unit changes such 

as turbine upgrades, improvements in boiler configuration, and steam tube, superheater, 

and reheater replacements. And yet, these are all the sort of changes that EPA has 

considered to be NSR major modifications and Clean Air Act violations.

To state the obvious, it would be poor policy for EPA to require EGUs to undertake 

activities to comply with NSPS where such activities trigger NSR violations under EPA 

current policies. EPA must reconcile this conundrum if it requires efficiency 

improvements as part of its NSPS proposal.

NSPS should not function to economically prejudice smaller systems or systems 

utilizing higher carbon content fuels, and must account for the installation of 

additional pollution control devices. NSPS requirements must be based on existing

BDT. This requirement excludes technologies that may be available in the future but are 

not available now. 

For a new or modified facility, NSPS must not result in source “redefinition” in the best 

available control technology (BACT) context. As previously stated in these comments, 

NSPS must be based on BDT. This requirement in practice is tantamount to BACT floor 

technology. EPA guidance on BACT does not require source “redefinition” and the 

statutory definition of NSPS requiring less than BACT precludes source redefinition here.
NRECA GHG NSPS SER Panel Comments

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NSPS must recognize fuel diversity and be cognizant of the fact that different fuels 

utilized by EGUs have different carbon contents, and with current demonstrated 

technologies, utilization of different fuels will yield different GHG emissions. NSPS 

must not effectively dictate fuel switching. For example, fleet averaging based on a 

natural gas derived NSPS could economically prejudice smaller systems that have less 

fuel diversity, operate fewer sources, or utilize coal. As previously stated, an NSPS 

based on fleet averaging is inconsistent with the NSPS statutory provisions. 

Further, unit size, design, and use will dictate unit efficiency. For example, fossil fuel 

units that cycle or follow baseload or renewable generation cannot achieve the same 

overall efficiency as other similarly designed units that do not cycle in this manner. As 

identified at the second SER panel, the efficiencies of existing facilities were established 

long ago during facilities’ design and the tools available to improve efficiencies are 

limited by the existing design operating temperatures and pressures which cannot be 

altered short of reconstruction. In many cases the design is limited by the size of the unit 

and the capital then available for the project. Also, the economics associated with 

installing efficiency improvements on smaller units will be quite different when

compared to installing similar technologies on larger ones. The statutory definition of 

NSPS requires that the standards must account for technology costs, thus NSPS 

requirements for smaller units may be different than for larger ones.

As EPA is well aware, new regulations finalized or likely to be finalized over the next 

several years include the Cross State Air Pollution Rule, the Electric Utility Hazardous 

Air Pollutants Rule, and the Clean Water Act 316(b) cooling water intake structure rule. 

All these regulations will require massive new installations of add-on controls such as 

flue gas desulfurization units (FGDs), selective catalytic reduction units (SCRs), 

baghouses, wet electro-static participators (ESPs), dry sorbent injection, and cooling 

towers. All these devices require significant amounts of energy from their EGUs, and by 
NRECA GHG NSPS SER Panel Comments

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definition these EGUs will become less energy efficient. It is quite plausible many EGUs 

will become notably less energy efficient over the next several years than they are now. 

NSPS requirements must take the continuing addition of these types of controls causing 

EGU energy inefficiencies into account in this rulemaking process. 

Lastly, the statute requires EPA to issue guidance to the states for developing NSPS for 

existing units following a State Implementation Plan (SIP) like process. To carry out this 

mandate, EPA must consider, in addition to the factors listed above, the remaining useful 

life of an EGU and other factors that would affect existing NSPS determinations 

identified during this rulemaking process.

EPA must appropriately accommodate permitted facilities for which construction 

will not have commenced prior to the date of proposed GHG NSPS. Several small 

entities in the utility sector have recently obtained air permits authorizing the construction 

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

on the new units prior to the date that EPA proposes this 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 the rule may prevent the projects 

from being implemented, depending on the new source standards adopted.

It appears that there are just 12 projects in the country that are in these circumstances. 

Under ordinary timelines for developing, proposing, and finalizing an NSPS regulation, 

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, 
NRECA GHG NSPS SER Panel Comments

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EPA negotiated the rulemaking deadlines in secret with environmental petitioners, 

making it impossible for utilities to know ahead of time whether EPA ultimately would 

commit itself to a fixed schedule and what milestones would be included in such a 

schedule.

As a result, these utilities have had essentially no opportunity to reasonably or 

realistically factor potential new source requirements into the design of the pending 

projects in which millions of dollars have already been spent on specific design and other

preparation. This is extraordinarily unfair to these utilities and puts at risk projects that 

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

prevent these inequities.

One approach is simply to defer the rulemaking schedule to give entities 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 EPA decides to stick with the current schedule, 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 
NRECA GHG NSPS SER Panel Comments

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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.

Carbon capture and storage is far from a demonstrated technology. The imposition 

of any NSPS standard for new EGU’s must recognize that commercial control 

technology, as it might be applied to all new EGUs, simply does not exist for CO2. 

Capture technology for current pulverized-coal (PC) fired, circulating fluidized bed 

(CFB) steam generators, and for natural gas combined-cycle (NGCC) facilities is under 

development, and while it may one day be commercially viable, such is not now the case. 

Further, while the gaseous products of combustion from integrated combustion 

combined-cycle (IGCC) facilities may be more CO2 capture-ready, none of the systems 

have ever been constructed at the scale necessary to accommodate the power generation 

facilities being proposed.

NRECA reminds EPA that the issuance of requirements to deploy immature capture 

technology will have the undesirable effect of deferring projects that otherwise will lead 

to needed development1

 1 Deployment of early supercritical pulverized-coal technology, which was an industry supported voluntary 

effort in the mid-1960s, met with criticism of the technology and the subsequent end of its development. 

Only recent wide-spread development of new generation technologies in other countries solved many of the 

problems encountered. An even more severe response to an immature government-mandated requirement 

that can be avoided by de-selecting certain generation technologies and fuels that would otherwise 

represent the best choice will likely have a similar impact. 

of the carbon capture technology desired. NRECA presented a 

handout of 12 proposed facilities, totaling over 8000 MW, for which PSD construction 

permits have been issued and/or extended. Extensive engineering and development costs 

for these facilities have been undertaken and in many situations completed. These 

projects include all three coal-based technologies discussed above, and the individual 
NRECA GHG NSPS SER Panel Comments

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units range in size from 75MW to 900 MW. Some of those projects included the 

introduction of partial carbon capture systems. At least one of them has permit terms 

which are BACT-based efficiency standards for CO2 emissions. Any new unit NSPS 

standard proposed by EPA must not foreclose on these projects, undertaken as good faith 

energy solutions, and which best meet the needs of the individual developers. 

The applicable term EPA must interpret for the purpose of GHG controls is “standard of 

performance,” which Section 111(a) of the Clean Air Act defines 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 nonair quality health and environmental impact 

and energy requirements) the Administrator determines has been 

adequately demonstrated.

NRECA submits that carbon capture and sequestration (CCS) is not yet adequately 

demonstrated. CCS holds the promise of removing in excess of 90 percent of GHG 

emissions from a fossil-fueled EGU. Research has accelerated in recent years but has not 

been conducted to the extent necessary to show that CCS can be deployed in conjunction 

with power plants built in locations across the country. The Department of Energy has 

funded research that has demonstrated a variety of carbon capture technologies on a 

research scale, and demonstrated sequestration of carbon dioxide on a research scale in 

promising geologic formations in various parts of the country. There are two 

commercial-scale integrated gasification combined cycle generating facilities in operation 

in the U.S., which generate power and result in an isolable emission stream of carbon 

dioxide. Commercial-scale quantities of carbon dioxide have been injected into oil and 

gas formations for many years for the purpose of enhancing oil and gas recovery.
NRECA GHG NSPS SER Panel Comments

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Notwithstanding these promising developments, CCS is not yet near a level of maturity 

that would enable its industry-wide deployment as a technological response to a GHG 

NSPS mandate. There are fewer than a handful of sites worldwide at which more than 

one million tons per year of CO2 has been injected, and none at which CO2 has been 

injected at a rate equal to the CO2 generated annually by a relatively small 250 MW 

EGU. There are 320 units of that size or larger in the U.S., comprising the vast majority 

of U.S. coal-fired generating capacity.2

 We do not have the level of experience necessary 

regarding injecting carbon over long term into even one geologic formation, let alone 

possessing the breadth of experience across a range of geologic formations and other sitespecific conditions, necessary to make a determination that CCS has been adequately 

demonstrated. Existing fossil-fueled plants may or may not be located near suitable 

sequestration sites, and if not, CO2 pipeline networks are not widely available, even 

assuming lengthy transport of CO2 would be cost-effective within the BDT context.

The report of the President’s Interagency Task Force on Carbon Capture and Storage 

notes:

The focus of CCS RD&D is twofold: 1) to demonstrate the operation of 

current CCS technologies integrated at an appropriate scale to prove safe 

and reliable capture and storage; and 2) to develop improved CO2 capture 

component technologies and advanced power generation technologies to 

significantly reduce the cost of CCS, to facilitate widespread cost-effective 

deployment after 2020. [Emphasis added].3

 2

“Existing U.S. Coal Plants,” SOURCE WATCH, available at

http://www.sourcewatch.org/index.php?title=Existing_U.S._Coal_Plants (last visited Mar. 17, 2011).

3 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010), at 9.
NRECA GHG NSPS SER Panel Comments

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In short, the President’s task force assumes additional research for a number of years will 

be necessary before CCS can be widely deployed.

Setting aside technical readiness, there are legal and commercial barriers to CCS 

deployment that apply to all facilities, including risk management. The task force report 

states:

Long-standing regulatory programs are being adapted to meet the 

circumstances of CCS, but limited experience and institutional capacity at 

the Federal and State level may hinder implementation of CCS-specific 

requirements. Key legal issues, such as long-term liability and property 

rights, also need resolution.4

As the task force report notes, there are three main sets of issues that constitute 

significant legal barriers to undertaking CCS: regulatory structure, liability and risk 

management, and property rights. It is imperative to recognize that their existence 

hampers the broad deployment of CCS, and frustrates gaining the experience needed to 

determine that CCS has been adequately demonstrated.

EPA recently put in place a regulatory structure under the Underground Injection Control 

(UIC) program to regulate geologic sequestration of CO2. While helpful in many 

respects in providing industry with the parameters that will be required for siting, 

construction, operation, monitoring, and post-closure care of a geologic sequestration 

facility, the UIC rule for geologic sequestration sites leaves key issues essentially 

 4 Id. at 8.
NRECA GHG NSPS SER Panel Comments

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unresolved, which we expect some parties may consider material in determining whether 

to proceed with CCS. 

In particular, EPA declined to clearly indicate or, within the scope of its authority, limit 

the applicability of regulation and liability under the Resource Conservation and 

Recovery Act (RCRA) and liability under the Comprehensive Environmental Response, 

Compensation, and Liability Act (CERCLA or Superfund).

The final rule declined to state that regulation of CO2 injectate as a RCRA hazardous 

waste would not apply. While clarifying that CO2 itself is not a hazardous waste, the rule 

states that “owners or operators will need to determine whether the CO2 stream is 

hazardous under EPA’s RCRA regulations, and if so, any injection of the CO2 stream 

may only occur in a Class I hazardous waste injection well.”5

EPA took no steps in the final rule to limit the applicability of Superfund liability to 

geologic sequestration. The final rule states:

CO2 itself is not listed as a hazardous substance under CERCLA. 

However, the CO2 stream may contain a listed hazardous substance (such 

as mercury) or may mobilize substances in the subsurface that could react 

with ground water to produce listed hazardous substances (such as sulfuric 

acid). Whether such substances may result in CERCLA liability from a 

GS facility depends entirely on the composition of the specific CO2 stream 

 5 Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide 

(CO2) Geologic Sequestration (GS) Wells, 75 Fed. Reg. 77230, 77260 (Dec. 10, 2010).
NRECA GHG NSPS SER Panel Comments

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and the environmental media in which it is stored (e.g., soil or ground 

water).6

The final rule does note that CERCLA’s exemption for federally permitted releases will 

apply, but that “Class VI permits will need to be structured to ensure that they prevent 

potential releases from the well, which are outside the scope of the Class VI permit and 

thus not considered federally permitted releases.”7

Furthermore, other issues in the final rule, such as monitoring that is far more extensive 

than many parties recommended was necessary, may increase the cost of compliance 

sufficiently to deter deployment of CCS.

Regarding liability and risk management, whether geologic sequestration can be 

undertaken cost effectively in connection with an EGU depends in part on whether risk 

management is available for a proximately located sequestration facility. This will 

depend on a variety of site-specific factors. A critical point is that a regulator’s 

willingness to approve a facility may not equate to a risk management entity’s 

willingness to address risk at a site.

Few commercial risk management entities are likely to enter this market, as there are few 

with the expertise and experience in environmental risk management product lines. A 

broad CCS mandate may increase pressure on regulators to approve sequestration sites in 

order to keep viable the continued operation of important generation assets. Decisions 

about financial assurance (risk management), which is required under the final UIC rule, 

will depend on whether risk can be characterized and assessed adequately. We raise this 

 6 Id. 

7 Id.
NRECA GHG NSPS SER Panel Comments

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to emphasize that whether CCS would be available for any given facility at some future 

point is a complex determination based on a range of decisions in which multiple parties 

will be involved.

Further, many interested parties have called for a government role in managing CCS 

risks, which research has shown are an impediment to CCS deployment.8

 Adequate 

demonstration of CCS is likely to depend on developers understanding the boundaries of 

the risk associated with this nascent technology.

Also, there are at least three property issues that must be addressed in conjunction with 

geologic sequestration: rights to the use of pore space for sequestration, rights for 

construction of pipelines for carbon dioxide transportation, and rights to surface access 

for monitoring and remediation.

The carbon dioxide plume from geologic sequestration will spread across an area that 

could comprise many square miles. Even if it so happens that the EGU is located above a 

geologic formation suitable for sequestration, NRECA is not aware of any current case 

where the owner of an electric generating unit also currently holds property rights 

sufficient to accommodate full-scale sequestration over a period of many years. 

Assembling property rights sufficient to conduct large-scale sequestration may be a very 

complicated undertaking. Consider that sequestration in even a moderately populated 

area could require acquisition of property rights from thousands of property owners. 

Even if sequestration would be an activity that would qualify for use of eminent domain 

authority under State law, arranging property rights for the radius of a CO2 plume is 

 8 See Study of Legal Issues Relating to Risk and Liability in Connection with Carbon Capture and Storage, 

CCS ALLIANCE (July 2008).
NRECA GHG NSPS SER Panel Comments

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likely to involve far more property owners than would be the case for a linear facility, 

such as a roadway, transmission line, or pipeline.

Note that whether State eminent domain authority could be applied to construction of 

CO2 pipelines depends both on the circumstances of the project as well as State law. A 

survey of State utility law shows that the availability of eminent domain authority 

depends on issues such as whether the entity that applies to construct the facility is a 

public utility, whether the pipeline is being used to serve end-use customers in the State, 

and whether the facility is to have a public use.9

To summarize, very significant progress must be made across many critical areas before 

CCS could be considered deployable within the EGU sector. Technical, legal, regulatory, 

and financial barriers must be overcome before CCS would be even a candidate for NSPS 

BDT. Overcoming these obstacles will take years and in fact CCS may never be BDT.

 9 Study of Legal Issues Relating to Risk and Liability in Connection with Carbon Capture and Storage, 

CCS Alliance, July 23, 2008, available at www.ccsalliance.net.