## 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, 201 1 By

R ae E. Cronmiller Environmental Counsel 4301 Wilson Boulevard, EU 11

- 249 Arlington, VA 22203

- 1860 (703) 907

- 5791 / rae.cronmiller@nreca.coopNRECA GHG NSPS SER Panel C omments

1 

## 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 mo re 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

- prof it
, consumer

- owne d 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 d istribution 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 ar e “small business entities” as defined by
SBREFA. Four small business entity G&T s as SERs are participating on this SBREFA panel. NRECA recommendations are below.

TEXTNRECA GHG NSPS SER Panel C omments

2 The panel should have the opportunity to comment on regulatory options presented
to i t 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
NSP S for GHGs involves complexities heretofore not encountered in the NSPS context,
because unlike other EGU emissions re gulated under the CAA , there are no viable emissions control technologies applicable to reducing CO 2 , the main GHG component in
EGU emissi ons. In particular
, carbon capture and storage (CCS) is not developed technology as our comments below address in detail . Therefore, w e e xpect EPA will have to rely on energy efficiency and possibly work practice standards as a means of Section 111 regul ation. 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 pre requisite 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 firs t 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 S ection 111 toNRECA GHG NSPS SER Panel C omments

3 expand an NSPS rule to include provisions incor porating 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. Si nce CO 2 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 con sidered a cap

- and

trade 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 Cong ress. 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
anothe r . 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 sourceNRECA GHG NSPS SER Panel C omments

4 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 pr ejudice 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
, a n output derived standard such as CO 2 /Mwh m e tric 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 CO 2 /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 CO 2 /Mwh rates are largely unit specific , and they can be severely impacted by equipment condition s 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 w ith its interpretation of New Source Review (NSR) major modification potentialNRECA GHG NSPS SER Panel C omments

5 violations. As previously mentioned
, c arbon 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, p resumably EPA will be looking at energy efficiency and work practice standards as no other demonstrated technologies exist

. Many of the current EPA regulatory program s are counter

- productive to improvements in efficiency

. E fficiency improvements are gained by unit changes such

as turbine upgrades, improvements in boiler configuration , and steam tube, superheater, and reheater replacements. And yet, t hese 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 violati o ns 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 , an d 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 C omments

6 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 N SPS 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 th e second SER panel, the efficienc ies 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
altere d 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 awa re, 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 the se regulation s 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

tower s. All these devices require significant amounts of energy from their EGUs, and byNRECA GHG NSPS SER Panel C omments

7 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 ar e 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

ex isting 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 determinatio ns 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 obtain ed 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 ne w 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

– b arely six months before the date of proposal. Moreover,NRECA GHG NSPS SER Panel C omments

8 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 schedu le 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 the se 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 h as 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 excl ude 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 uni ts 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 so urce category. EPA could reasonably create aNRECA GHG NSPS SER Panel C omments

9 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 i s 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 CO 2 . 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 p roducts of combustion from integrated combustion
combined

- cycle (IGCC) facilities may be more CO 2 capture

- ready, none of the systems have ever been constructed at the scale necessary to accommodate the power generation facilities being proposed.

NRECA rem inds 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 development 1

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 gen eration 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 1 2 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 incl ude all three coal

- based technologies discussed above, and the individualNRECA GHG NSPS SER Panel C omments

10 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

- ba sed efficiency standards for CO 2 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 m ust 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 applicatio n 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 submit s 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 conduc ted 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 C omments

11 Notwiths tanding 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 milli on tons per year of CO 2 has been injected, and none at which CO 2 has been injected at a rate equal to the CO 2 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 site

specific 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, CO 2 pipeline networks are not widely available, e ven assuming lengthy transport of CO 2 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 CO 2 capture component technologies and advanced power generation technologies to significantly reduce the cost of CCS, to facilit ate widespread cost

- effective deployment after 2020. [Emphasis added]. 3

2 “Existing U.S. Coal Plants,” S OURCE W ATCH , 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 C omments

12 In short
, t he 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 in stitutional 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 se ts of issues that constitute significant legal barriers to undertaking CCS: regulatory structure, liability and risk management, and property rights. I t is imperative to recognize that their existence hampers the broad deployment of CCS, and frustrates ga ining 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 CO 2 . While helpful in many

re spects 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 C omments

13 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 t he 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 CO 2 injectate as a RCRA hazardous

was te would not apply. While clarifying that CO 2 itself is not a hazardous waste, the rule states that “owners or operators will need to determine whether the CO 2 stream is hazardous under EPA’s RCRA regulations, and if so, any injection of the CO 2 stream

ma y 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:

CO 2 itself is not listed as a hazardous substance under CERCLA. However, the CO 2 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 sub stances (such as sulfuric acid). Whether such substances may result in CERCLA liability from a GS facility depends entirely on the composition of the specific CO 2 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 C omments

14 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 permi t 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 dep loyment of CCS.

Regarding l iability and r isk m anagement , w hether 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 continue d 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 C omments

15 to emphasize that wheth er 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

r isks, 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, t here are at least three propert y 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 remediati on.

The carbon dioxide plume from geologic sequestration will spread across an area that could comprise many sq uare miles. Even if it so happens that the EGU is located above a geologic formation suitable for sequestration, NRECA is not aware of any curr ent 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 b e 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 emi nent domain authority under State law, arranging property rights for the radius of a CO 2 plume is

8 See Study of Legal Issues Relating to Risk and Liability in Connection with Carbon Capture and Storage
, CCS A LLIANCE (July 2008).NRECA GHG NSPS SER Panel C omments

16 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
CO 2 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 issue s 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

.