Comments of The General Electric Company

Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units

DOCKET ID NO. EPA–HQ–OAR–2013–0602

RIN: 2060-AR33 79 FED. REG. 34,829 (JUNE 18, 2014)

SUBMITTED DECEMBER 1, 2014

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TABLE OF CONTENTS

Introduction ......................................................................................................................................... 3

I. GE’s interest ........................................................................................................................................................ 3 II. GE’s position on the climate issue ............................................................................................................ 3 III. GE supports the goal of reducing carbon emissions, but believes that several significant modifications to EPA’s proposal are required ....................................................................... 5

Executive Summary ............................................................................................................................ 6

General comments on EPA’s proposed guidelines ....................................................................... 8

I. Recommended modification to BSER definition ................................................................................ 8 II. EPA must address stranded assets ......................................................................................................... 8

a. EPA should use its subcategorization authority to establish standards for facilities that recently made substantial capital investments .............................................................................. 9 b. EPA should acknowledge state authority to grant facility-specific variances ................ 10

III. New Source Review ..................................................................................................................................... 13 a. Existing NSR requirements will impede the ability of EGUs to improve efficiency and comply with the guidelines unless changes are made to the proposal ...................................... 13 b. There are several approaches to NSR that would facilitate compliance with Section 111(d) ....................................................................................................................................................................... 22

IV. Distinguishing 111(b) from 111(d) .......................................................................................................... 26 a. EPA’s final Section 111(d) guidelines should not impose dual regulatory requirements on modified units ................................................................................................................................................ 26 b. While states have the discretion to use new NGCC as an emission mitigation strategy, a decision by EPA to include new sources as part of a BSER determination under Section

111(d) would create significant legal risk. ................................................................................................ 28 V. Accounting for CHP ...................................................................................................................................... 29 VI. Fuel cells ............................................................................................................................................................ 30

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Comments on EPA Building Blocks ............................................................................................... 31

I. Building Block 1: Efficiency improvements ........................................................................................ 31 a. EPA’s estimate of cost effective upgrades across the coal fleet is unrealistic ................. 31 b. EPA should consider operator experience, conditions, and the availability of new technologies when calculating the impact of upgrades ................................................................... 32 c. Comments specific to best practices implementation .............................................................. 34 d. Comments specific to equipment upgrades .................................................................................. 37 e. Estimate of total probable upgrade opportunity ......................................................................... 37 f. Emissions reductions through improvements in system efficiency ..................................... 38

II. Building Block 2: Load shifting ................................................................................................................ 39 a. A 70% NGCC utilization rate is achievable with adequate phase-in time ........................ 39 b. EPA is correct to not include existing NGCC Heat Rate Improvements as part of BSER 41 c. EPA should clearly indicate that NGCC Heat Rate Improvements count toward compliance in State Implementation Plans ............................................................................................ 43 d. GE comments to request for comment in the NODA ................................................................. 43

III. Building Block 3: Renewable generation ............................................................................................ 44 a. Proposed RPS Regional Approach is flawed ................................................................................. 45 b. NODA Regional Approach lacks sufficient detail for comment ............................................. 47 c. Detailed comments on Alternative Approach ............................................................................... 47 d. Proposed RPS Regional Approach to quantifying RE ................................................................ 57 e. Credit for early action .............................................................................................................................. 59 f. Treatment of interstate renewable energy sales ......................................................................... 59 g. Increased RE should displace fossil generation in goal-setting formula ........................... 60

IV. Building Block 4: Energy efficiency ........................................................................................................ 60

Conclusion ........................................................................................................................................ 63

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Introduction

I. GE’s interest

The General Electric Company (GE) is actively involved in all facets of the energy sector.

GE has long manufactured products that are designed to meet stringent emissions standards, while also meeting customer requirements for efficient, reliable generation. GE designs and manufactures industry-leading gas, steam, and wind powered turbines, gasification systems, nuclear power generation technologies and transmission and distribution technologies, including smart grid technologies, which are changing the industry.

GE also invests in, owns, and operates power plants, so we understand the perspective of plant operators and the challenges they face in implementing controls while maintaining the reliability and availability of their units.

GE also services the products we sell and offer upgrades to products that we have sold that increase their efficiency and availability.

No other company offers the depth or breadth of products and services as does GE across fuels and technologies in the electric generation and transmission and distribution sectors. This fact is reflected in GE’s share of the installed base for electric generating units in the United States:

64% (by MW installed) for gas turbines; 50% (by GW/h) for coal-fired steam turbines: 39% (by MW installed) for wind turbines; and 33% (by GW) for nuclear generation.

II. GE’s position on the climate issue

GE has long recognized and acknowledged that climate change is a real problem and that production and use of fossil fuels contribute to the problem. While all scientific issues relating to climate change are not yet fully defined, particularly as to local or regional impacts, we support international and national policies charting a reasonable course to reduce emissions.

GE has acted consistently with our views on climate in the operation of our businesses. GE has—―through our ecomagination® initiative—―taken actions to increase the energy efficiency of our operations and to reduce significantly our emissions of greenhouse gases. Our commitments and performance are as follows:

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Investment in clean-tech research and development: Since 2005, GE has invested about $13B in ecomagination R&D, on track to meet the commitment of $15B through 2015. In February, GE announced the continuation of its ecomagination investment committing to invest an additional $10B to reach a total investment of $25B by 2020.

Increase revenues from ecomagination products: In 2010, GE set an ambitious goal of growing revenues from ecomagination offerings at twice the rate of total company revenue in five years. In 2013, ecomagination met this objective with revenue totaling $28 billion.

Reduce greenhouse gas (GHG) emissions 25 percent by 2015 and improve the energy intensity of operations 50 percent by 2015: GE’s energy efficiency improved 31 percent from the 2004 baseline year (measured as energy/$ revenue). GHG emissions were reduced 32 percent from the adjusted 2004 baseline. Building off this success, in February GE committed to reduce GHG emissions and freshwater use by 20 percent, from the 2011 baseline, by 2020.

Reduce freshwater use by 25 percent and improve water reuse: GE’s freshwater use was reduced 45 percent from the 2006 baseline.

While we support the need for national and international policies and programs to reduce greenhouse gas emissions, GE recognizes that climate change is a difficult and complex issue. Climate change concerns are closely interconnected with the production and use of fossil energy, and affordable, reliable, and secure energy is fundamental to a healthy, growing, and competitive economy. In addition, climate change is a global issue that ultimately requires a global solution, and it is difficult to address on a national basis as unilateral action is perceived to result in a competitive disadvantage.

In our view, assuring affordable, reliable and secure energy is as important as addressing the climate change issue for the simple reason that a healthy, growing economy is essential to having the wherewithal to address climate change. Therefore, we believe that actions to address climate change must be balanced against their potential economic impacts.

We believe strongly that an essential element for a reasonable and cost-effective climate program is an adequate time period for the transition to a lower carbon economy, particularly the power generation sector, where the capital stock has a life measured in decades and the cost of capital investments is measured in billions. In these circumstances, a climate program for the power generation sector must make every reasonable effort to avoid stranding assets if the program is to be cost effective for producers and consumers of electricity.

Finally, GE supports an “all of the above” approach to energy and climate policy. We support increased reliance on renewables and nuclear energy as a means of producing zero carbon electricity and addressing climate change, but we also believe that fossil

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fuels, particularly natural gas, must be a part of our energy portfolio. Simply put, the continued use of low cost cleaner fossil fuels, such as natural gas, is necessary if we are to have a competitive US economy. While we see increased need to rely on natural gas, we also believe that coal is also an abundant and low cost fuel and will continue to be an important part of the global and US energy mix for the foreseeable future.

III. GE supports the goal of reducing carbon emissions, but believes that several significant modifications to EPA’s proposal are required

Increasing the efficiency of coal-fired steam boilers and the use of natural gas, renewable, and nuclear generation are critical steps to reducing carbon intensity in the power sector. GE believes that the proposed carbon pollution guidelines for existing electric generating units represents a good faith effort to achieve these goals, while providing the flexibility required by states and the electric utility industry to reduce emissions in a cost-effective manner without disrupting the reliability of the grid. However, we believe that this rule should be improved to make it more flexible, less burdensome, and more legally defensible.

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Executive Summary

EPA’s proposed Best System of Emission Reduction (BSER) is consistent with the actual operation of the power grid in Building Blocks 1 through 3, but improvements are necessary. Compliance with this system will promote lower emitting generation, and is creative, but States and power-sector stakeholders need more flexibility. EPA should base BSER on the first three proposed Building Blocks, and should remain sensitive to consumer costs. EPA must provide adequate time for the economy to transition to a lower-carbon power generation sector. Capital assets in the power sector have lifetimes typically measured in decades and costs typically measured in billions of dollars. Providing adequate transition time for asset owners to recover investment is critical to avoid economic impingement. EPA must avoid stranding assets, especially those facilities that have recently made substantial capital investments to comply with new EPA programs, such as CSPAR and MATS. Asset owners will not have the confidence to undertake future environmental control retrofits if they are unable to trust that they will be able to recoup their investments. Affording federal relief to plants that have recently implemented environmental controls in response to EPA mandates will prevent consumer cost spikes and other economic fallout. EPA should ensure that New Source Review (NSR) does not discourage efficiency improvement projects necessary for compliance with state plans. EPA should clarify in the proposed guidelines (and modify NSR rules or interpretations accordingly) that efficiency projects undertaken for compliance with State plans do not trigger NSR requirements. Eliminating the NSR impediment to efficiency improvements would encourage innovation and ensure that states and sources maintain compliance flexibility under the proposed guidelines.

Compliance with State plans should not trigger modification/reconstruction under CAA Section 111(b). EPA should clarify that all physical and operational changes (including upgrades) done to comply with Section 111(d) or that improve an EGU’s energy efficiency are exempt from triggering NSPS modification under the pollution control exclusion.

EPA should not impose dual regulatory requirements on units that trigger modification under 111(b). Instead of the proposed dual regulatory approach, EPA should confirm that a source can opt to use the pollution control project exclusion for a

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physical or operational change that improves efficiency or is undertaken to comply with a state’s Section 111(d) plan.

EPA should not include new sources as part of a BSER determination under Section 111(d). Including new sources as part of a BSER determination under Section 111(d) significantly increases the legal risk and uncertainty for the rulemaking given that new and existing sources are regulated under separate provisions in Section 111. Moreover, excluding new sources from the BSER determination would create an important incentive for the construction of new, higher-efficiency NGCC capacity.

EPA’s assumptions in Building Block 1 are unrealistic. A 6% heat rate improvement on average across the fleet is technically possible if costs are not a factor. A 4 to 5 percent gross heat rate improvement on average is economically possible. Because we do not know how many of these improvements are already implemented across the fleet, we believe the actual potential may be less than this range. Realistically, we expect a 1 percent gross heat rate improvement to occur across the fleet. EPA’s assumptions in Building Block 2 are achievable, given adequate phase-in time to allow infrastructure to keep pace with increased gas demand. A 70% utilization rate is technically achievable by NGCC plants today, and will significantly reduce carbon emissions from the power generation sector. Significant capital improvements to midstream infrastructure may be necessary to achieve this level, so EPA should allow for a reasonable phase-in time to accommodate this re-dispatch. NGCC heat rate improvements should not be included in BSER, or for purposes of calculating state emission rates, but should count toward compliance in State Implementation Plans. EPA’s should recalculate Building Block 3 reductions using its alternative approach. GE supports the expanded use of renewable generation to reduce the carbon intensity of the nation’s grid. This is a proven method to reduce carbon pollution at reasonable cost. EPA has underestimated actual potential for renewable resources in many states, particularly wind energy potential. EPA should recalculate Building Block 3 by undertaking a state-by-state analysis of technical and market potential, with some changes to its proposed methodology. EPA should base BSER on Building Blocks 1 through 3. The Agency could account for increased deployment of energy efficiency measures even if it decides to base BSER on Building Blocks 1 through 3. Reduction in demand functions differently than increased lower- and carbon-free generation. Even if energy efficiency is not used to calculate BSER, EPA can and should factor those reductions directly in other parts of the rulemaking package, including in the rule’s impact analysis.

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General comments on EPA’s proposed guidelines

I. Recommended modification to BSER definition

GE agrees that cost-effective technology to control carbon emissions from existing fossil-fired electric generating units does not exist. Therefore, if emissions from the electric power generating sector are to be reduced significantly the only way to do so is to increase the efficiency of existing units; to encourage greater utilization of lower or no carbon emitting technologies; and to promote energy efficiency in the use of electricity. A regulatory system as EPA proposes that seeks to align with the actual operation of the power system holds potential as an effective, workable solution to the problem of reducing emission of carbon from the sector. However, we suggest that EPA base BSER on the first three building blocks, with the revisions suggested below, as such an approach is more consistent with how the power system naturally works. We understand and support efforts to increase demand side energy efficiency, but believe that this tool is better used as a compliance option through State implementation plans. In our view, demand side energy efficiency is outside the “power system” and undermines the coherence of EPA’s “system” based approach to Best System of Emission Reduction (BESR).

II. EPA must address stranded assets

GE believes that provision must be made in the final rule to address the issue of stranded assets, particularly with respect to coal-fired units that have recently installed expensive pollution control equipment to meet other environmental requirements such as the Mercury MATS and CSAPR. Utilities and others, including subsidiaries of our company, have made such investments, and opportunity must be provided to operate these plants profitably for such time as is necessary to recoup those investments. We believe that Section 111(d) of the Clean Air Act requires EPA to provide relief for such facilities either directly in its guidelines or indirectly by authorize states to do so in state implementation plans. The President’s directions to EPA also require EPA to take efforts to comply with environmental requirements into account in developing rules under Clean Air Act Section 111(d). Allowing such relief will also help lessen the costs of this program on consumers of electric power in regions served by such facilities. Having recognized the serious stranded cost implications of the proposed rule, EPA’s recent Notice of Data Availability discusses and requests comment on potential

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alternative options to enable coal-fired facilities like GE’s own Homer City subsidiary to recoup their pollution control investments:

[T]o the extent that stakeholders are concerned that the tools available to states under the proposal may, in some instances, be inadequate to address concerns regarding stranded investments, an additional way to address these concerns may be for the agency to take account of the book life of the original generation asset, as well as the book life of any major upgrades to the asset, such as major pollution control retrofits. For example, in its modeling, the EPA assumes a book life of 40 years for new coal-fired units. The EPA requests comment on whether, and how, book life might be either used as part of the basis for the development of an alternative emission glide path for building block 2 or used to evaluate whether other ways of developing an alternative glide path (such as the phase-in approaches discussed above) would address stakeholders’ stranded investment concerns. The EPA is providing this additional information, arising from stakeholder concerns, to allow additional continued engagement of stakeholders in the comment process.

See 79 Fed. Reg. 64,543, 64,549 (Oct. 30, 2014). We appreciate EPA’s attention to the stranded asset problem in the Notice of Data Availability and the agency’s willingness to consider ways account for the “book life” of major upgrades to covered facilities, including expensive retrofits to achieve compliance with MATS or CSAPR. To this end, GE echoes comments of its Homer City subsidiary and strongly urges EPA (1) to consider subcategorizing and creating separate standards for sources that have made recent capital investments to comply with MATS and CSAPR, and (2) reaffirm states’ established variance authority and expressly identify variance mechanisms by which facilities that have made substantial investments to comply with EPA’s recently promulgated MATS or CSAPR requirements may obtain the relief they need.

a. EPA should use its subcategorization authority to establish standards for facilities that recently made substantial capital investments

EPA could address the stranded asset issue by using its authority under CAA section 111 to “distinguish among classes, types, and sizes” and to consider costs when establishing standards of performance, to develop separate 111(d) standards for existing facilities that since 2010 have made substantial investments in pollution control technologies to

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comply with CSAPR and MATS.1 Standards for this subcategory of sources could take several different forms. EPA could adopt an emission rate standard that it determined sources within the subcategory could reasonably achieve, or, consistent with one of the variance options discussed below (cap-based variance), the agency could establish an annual CO2 emissions cap for such facilities, or criteria for states to use to develop such a cap, that reflects a reduction (e.g., 20%) from 2005 levels. This type of an approach would balance EPA’s dual goals of reducing CO2 emissions and not prematurely stranding assets, particularly those just recently installed to comply with other EPA programs.

b. EPA should acknowledge state authority to grant facility-specific variances

Homer City strongly recommends that EPA acknowledge and, in certain scenarios endorse, states’ authority to issue variances from EPA emission guidelines and to adopt alternative compliance standards and deadlines for facilities meeting certain conditions. CAA section 111(d)(1) provides that EPA “shall permit the State in applying a standard . . . to take into consideration, among other factors, the remaining useful life of the existing source.” Similarly, 40 C.F.R. § 60.24(f) provides that states may apply less stringent standards and longer compliance schedules to individual facilities or “class of facilities” if the state demonstrates: (1) unreasonable cost of control, (2) physical impossibility, or (3) “other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable.”2 It is worth noting that the variance authorized by 40 C.F.R. § 60.24(f)(3) is distinct from and broader than the other two categories, including the concept of a facility’s remaining useful life. We believe that EPA and Pennsylvania should readily rely on this specific regulatory variance authority to allow facilities that have recently made substantial capital investments time to recoup their investments before being subject to the entirety of a state 111(d) plan. EPA should embrace this authority, not shunt it aside. In the preamble to the proposal, EPA takes the position that “no relief for individual facilities would be needed” because EPA’s proposed emission guidelines happen to take the form of “state emission performance goals for the collective group of affected EGUs in a state,” rather than a “presumptive standard of performance that must be fully and directly implemented by each individual existing source within a specified source category.”3 We disagree.

1 Similarly, 40 C.F.R. § 60.22(b)(5) provides that EPA guidelines shall “specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make such subcategorization appropriate.” 2 Emphasis added. 3 79 Fed. Reg. at 34,925.

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However, the form of the emission goal has nothing to do with the ability of a state, under CAA section 111(d)(1) to grant variances which “take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.” EPA cannot circumvent this statutory provision merely by changing how it may choose to prescribe state guidelines. Moreover, we cannot accept the premise that the claimed flexibilities in EPA’s portfolio approach obviate a state’s need to adjust its emission target in account for any source-specific variances granted. Unless states have the ability to adjust their emission targets, variances would be of little utility, since any relief granted to one source would have to be made up by another. To provide meaningful relief and to help address the stranded asset issue, states must have the ability to grant variances and to adjust state emission targets commensurately.4 For its part, EPA could codify criteria for when it would be appropriate for state targets to be adjusted to reflect a variance. For example, EPA could make clear that it supports the issuance of variances to avoid stranding assets and the adjustment of state emission targets to such variances. States could grant general variances to other sources, but they would not be able to adjust their emission limits in response to variances that do not satisfy EPA’s criteria (e.g., when a source has not made a capital expenditure since 2010). Below we set forth two specific variance-based options that EPA should authorize and endorse.

Option 1: Alternative Compliance Schedule

EPA should specify in the final rule that states should grant variances pursuant to 40 C.F.R. § 60.24(f) to coal-fired facilities, like Homer City, that made substantial investments in pollution control technology since 2010 to comply with CSAPR or MATS. A variance under this option would exempt the facility from a state’s base 111(d) program for 20 years from the start of the program. During the variance period, EPA could adjust their applicable emissions target to exclude emissions from those sources operating under the variance. At the conclusion of the variance period, the state would have to readjust its emission target to account for the source and the facility would be required to meet all applicable state plan requirements.

4 See 40 Fed. Reg. at 53,343-44 (preamble to 1975 implementing regulations for section 111(d) (“EPA’s emission guidelines will in effect be tailored to what is reasonably achievable by particular classes of existing sources, and States will be free to vary from the levels of control represented by the emission guidelines [under §§ 60.24(d) and (f)]. In most if not all cases, the result is likely to be substantial variation in the degree of control required for particular sources, rather than identical standards for all sources . . . [I]t is up the States to decide whether less stringent standards [under §60.24(f)] are to be applied permanently or whether ultimate compliance will be required.”).

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As noted above, such an alternative compliance schedule is consistent with discussion of potential ways to consider of the “book life” of major upgrades to a facility in EPA’s recent NODA. The assumed book life for large environmental retrofits, such as the dry scrubbers being installed at Homer City, has traditionally been 30 years. Regulatory analysis underlying both CAIR and CSAPR used a 30 year life for FGDs, as did the MATS Rule.5 While EPA has more recently used 15 years for evaluating book life under CAA section 111(d), EPA can certainly consider the “book life” of major pollution control equipment to be 30 years given the large capital outlays required and substantial operation and maintenance costs. EPA’s endorsement of a 20-year alternative compliance schedule for qualifying sources like Homer City is plainly consistent with the statute and EPA regulations. As discussed above, states may implement alternative compliance schedules pursuant to their § 60.24(f) variance authority, as supplemented by EPA guidance setting forth specific eligibility criteria. Moreover, allowing variances for those facilities that meet reasonable eligibility criteria is consistent with EPA’s own authority to “distinguish among classes, types, and sizes within categories of new sources for the purposes of establishing such standards.”6 Although there is not an explicit corollary to this language in CAA section 111(d), such may be fairly implied in light of EPA’s express power to make such distinctions in establishing standards of performance under section 111(b). Accordingly, EPA should consider such an alternative compliance option and expressly allow states to (1) grant eligible facilities 20-year variances, and (2) implement corresponding adjustments in their state emission targets over the variance period.

Option 2: Emission Caps

A second option would be for EPA to authorize and endorse states to use their variance authority to subject sources to site-specific, annual CO2 caps in lieu of the base 111(d) program. Under this option, facilities would be subject to a CO2 emissions cap that reflects a 20% reduction off of the source’s 2005 emissions. Qualifying facilities would again be those facilities that have made substantial capital investments since 2010 and need time to recoup those investments. Since many coal plants have and will retire after 2005, the emission reductions from those plants is 100 percent. Therefore, coal plants as a group will contribute significant CO2 reductions to achieving supportable reduction targets. The capped facility could operate pursuant to whatever schedule it chooses, provided it stays below the cap. The facility would also be able to run under a cap in any year and utilize the “headroom” under the emission cap in subsequent years. The

5 See, e.g., Documentation Supplement for EPA Base Case v.4.10_FTransport-Updates for Final Transport Rule. EPA 430-K-11-004, June 2011 at 51-51 (applying 30-year book life for pollution control retrofits in CSAPR). 6 42 U.S.C. § 7411(b)(2).

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obvious benefit to the source is that it would have the flexibility to comply with state plan requirements through a permit and operate at full load (when the plant has the lowest heat rate) during select periods of time, as opposed to being subject to a rate. The benefit to the state is that it would obtain a guaranteed mass reduction of CO2 and would maintain the viability of EGUs within the state. We believe that this approach would be permissible under the CPP as proposed, as well as under the variance authority of 40 C.F.R. § 60.24(f). However, we believe it important for EPA to eliminate any confusion by specifically recognizing this in the final rule or accompanying materials as a viable option to avoid stranding assets. States are likely to have more comfort adopting such a measure if EPA speaks to it directly in the final rule.7

III. New Source Review

a. Existing NSR requirements will impede the ability of EGUs to improve efficiency and comply with the guidelines unless changes are made to the proposal

The Proposed Rule is premised on Building Blocks that will require efficiency upgrades

EPA’s first category of approaches to reduce GHG emissions from EGUs, “Building Block 1,” consists of changes to coal-fired steam units that improve their heat rate and operating efficiency. As EPA notes, these changes will increase the efficiency by which the unit converts the energy in the fuel to electric energy, and will lower the amount of carbon dioxide (CO2) emissions per unit of electricity produced.8 EPA estimates suggest that these improvements will yield 97 million ton/year fleet-wide reductions in CO2 emissions,9 approximately 12 percent of the overall reductions required by the proposed guidelines.

EPA also notes that while the potential for heat rate improvements is greater for coal-fired steam EGUs, heat rate improvements have the potential to reduce CO2 emissions from “all types of affected EGUs”.10 GE agrees. EPA’s second category of approaches to reduce CO2 emissions, “Building Block 2,” is based on the re-dispatch of generation from higher emitting fossil fuel-fired EGUs to less carbon intensive fossil fuel-fired EGUs, in particular natural gas combined cycle (NGCC) units that were in operation or

7 EPA recently issued a notice regarding conversion of state emission rates to a state emission cap. See Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg. 67,406 (Nov. 13, 2014). Further explication of how “capped” facilities would be treated within state plans – or potentially outside of state plans – would be beneficial. 8 79 Fed. Reg. at 34,859/col. 1-2 9 EPA, TSD, GHG Abatement Measures, at 2-39 10 79 Fed. Reg. at 34,859/col. 2

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commenced construction as of January 8, 2014. As a result of the increased role of natural gas units, EPA estimates that roughly one-third of the overall CO2 reductions required will come from this re-dispatch to gas.

The increased role of gas-fired generators will result in increased demand for operational efficiency and reliability at existing units. Many existing gas-fired units were put in service years ago and, while highly efficient, have the potential for additional heat rate improvements through the implementation of technology advancements incorporated in more recent NGCC or natural gas simple cycle turbines (SCGT). To facilitate this re-dispatch, achieve optimal performance, and to generate electricity in the most cost effective manner from these existing units, owners and operators will look at upgrade opportunities to improve heat rate and increase efficiency and reliability. In fact, given the enhanced role of gas-fired EGUs will play as a result of the proposed guidelines, the opportunities for equipment upgrades and improved efficiency may be on par, and may even exceed the opportunities available with coal-fired EGUs.

Equipment upgrades at existing fossil fuel-fired gas and steam turbines can significantly improve performance, reliability, and efficiency while reducing emissions

There are significant opportunities for improved performance at each of the three main components of a gas turbine including: the compressor that compresses or squeezes the incoming air; the combustor that burns the fuel; and the turbine that extracts the working energy from the exhaust gas. Increased efficiency will lower CO2 emissions per MWH as well as the emissions of more traditional air pollutants, such as nitrogen oxides (NOx). This is an important objective of the proposed guidelines if the re-dispatch of power envisioned in Building Block 2 causes individual units to generate more power.

In addition to improving efficiency and lowering emissions per megawatt of electricity produced, most if not all of the likely equipment upgrades will also improve the reliability and durability of the unit – an important aspect that cannot be overlooked given their increased role in providing electricity. Reliability and durability of gas units will be key in assuring that states can develop plans that comply with the proposed guidelines without risking service to residential, commercial, or industrial customers. Equipment upgrades also often involve updating controls and software packages that allow for a more responsive system.

Examples of specific upgrade options for gas turbines include the following:

Advanced Gas Path Upgrade (AGP): GE’s AGP is an upgrade option available for simple and combined cycle installations within the footprint of the existing 7F gas turbine. The AGP upgrade lowers fuel consumption while increasing maintenance intervals and extending the life of parts. Located downstream from the combustor, the gas turbine is exposed to extremely high temperatures, so the

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AGP upgrade also includes improved materials and cooling technology that requires less air devoted to cooling. This allows more airflow to be devoted to making energy, thereby improving output and efficiency. The AGP upgrade will also include better sealing technology so less air leaks around the turbine blades, further improving efficiency. Overall, the AGP upgrade has the potential to add about 10 MW to output (depending on the current equipment configuration), while reducing CO2 by more than 2.6 percent. If the AGP upgrade is installed with GE’s OpFlex Suite of software solutions, significant additional emission reductions can occur as a result of up to a 50 percent faster warm/hot start-up time. This results in up to 50 percent fewer emissions during start-up periods. An existing 7F gas turbine with AGP technology generating a net output of 525 megawatts of power can reduce its CO2 emissions by around 11,400 tons per year, which is roughly equal to removing 2,200 cars from U.S. roads.

DLN2.6+ combustor: GE’s Dry Low NOx (DLN) 2.6+ combustion system for the GE 7F gas turbine incorporates advanced technology to increase combustion stability, reduce emissions and improve turndown, and extend outage intervals, thereby reducing the frequency of maintenance outages and improving plant availability. This improved combustor can combust natural gas more efficiently, recovering more energy from the fuel with lower emissions. If combined with an AGP upgrade (described above), the improved combustor can add an additional 4 MWs for a total output gain of approximately 14 MWs (total output approximately 186 MW) and reduce CO2 by an additional 0.2 percent for a total of 2.8 percent.

Compressor Upgrade: The performance of existing NGCC units can be improved with the installation of more advanced compressors. For instance, the 7F.05 high-efficiency gas turbine can achieve efficiency levels of 59 percent in combined cycle mode. This is due in part to the fact that the 7F.05 turbine has a more advanced compressor that is able to pass more air through the turbine and more efficiently compress the incoming air. In addition to improving efficiency, implementing the 7F.05 compressor upgrade on earlier vintage 7F gas turbines will increase durability and overall gas turbine availability. All of these features are critical for the enhanced role of existing NGCC expected under the proposed guidelines. If the 7F.05 compressor upgrade is coupled with other upgrades, namely the AGP upgrade and the DLN2.6+ combustor upgrade described above (items 1 and 2), it can reduce CO2 emissions by an additional 3.8 percent for a total emission reduction of 6.6 percent per megawatt of electricity produced.

GE has also developed and deployed a number of significant steam turbine upgrade technologies that have improved the performance, operation and reliability of steam turbines while reducing emissions. These include:

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GE Energy’s Advanced Design Steam Path (ADSP): Because the efficiency of a unit is largely dependent on the efficiency of the energy conversion in the steam turbine, it is important to minimize aerodynamic and steam leakage losses in the steam path. Introduced in 1995, ADSP has resulted in steam path efficiency improvements ranging from 1.5 to 3 percent. Along with ADSP, GE has also developed advanced-vortex designs, integral cover buckets, and brush seals that create additional improvements in efficiency.

Dense Pack Steam Path Redesign: The design goal of a Dense Pack retrofit is

similar to ADSP; its aim is to put the most efficient steam path into an existing high-pressure outer shell. The Dense Pack upgrade inserts new rotor and stationary components inside the existing turbine shell. The resulting high efficiency steam path produces a lower heat rate and increases output for the same steam flow. The Dense Pack design also has the benefit of reducing particle erosion, such that the improved efficiency is more sustainable. Installation of the Dense Pack Steam Path can be done during a planned outage with minimal disruption.

Low Pressure Service Upgrades: The objective of low-pressure service upgrades

is to recover performance losses attributed to unit aging by installing advanced replacement components. These components increase reliability due to their modern engineering and the reduced likelihood of corrosion. Use of the low-pressure service upgrades expand output and improve heat rate through improved low-pressure section efficiency and reduced exhaust velocities. The low-pressure service upgrades also have the advantage of reduced maintenance costs by eliminating costly rotor repairs.

The mature age of many existing gas turbines and coal-fired steam units suggests that repowering options may have significant appeal and practicality as a compliance approach for the proposed guidelines. Aging existing plants often suffer from reduced reliability, limited OEM support, and rising cost of water and wastewater disposal. Repowering addresses many of these challenges by increasing engine reliability, significantly improving plant efficiency, and reducing emissions. Repowering also allows existing units to retain most of the existing plant infrastructure and can be installed rapidly, with greater OEM support.

Without additional clarifications, NSPS modification requirements may limit deployment of cost-effective compliance options

As discussed in more detail below, despite increases in efficiency, the increased output associated with upgrade projects have the potential to increase emissions of pollutants on an hourly basis, even though emissions per unit of electricity generated (per MW/hr) decreases. Existing NSPS regulations recognize and address concerns regarding the

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potential application of additional requirements for projects designed to control emissions. As explained in GE’s attached October 16, 2014 comments on EPA’s proposed Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating (EGU), 79 Fed. Reg. 34,960 (June 18, 2014), GE supports the Agency’s decision to maintain the NSPS pollution control project exclusion, which excludes from the definition of “modification” the “addition or use of any system or device whose primary function is the reduction of air pollutants.” Although NSPS modification is triggered less frequently than NSR modification, the energy efficiency focus of EPA’s proposed Section 111(d) guidelines could compel a larger number of upgrades at EGUs that could lead to increases in a source’s maximum hourly emission rate – the emissions trigger for NSPS modification.

Given the importance of this issue, GE recommends that the Agency clarify in the preambles to the final Section 111 modification rule and in the final ESPS rule that not only “traditional” pollution control projects—―e.g., installation of scrubbers or baghouses—―qualify for the exclusion, but also physical or operational changes undertaken to comply with CAA Section 111(d) plans. This includes upgrade projects that improve efficiency and, as a result, reduce the amount of CO2, and criteria pollutants such as NOx, and PM2.5 emissions produced per MW of electricity generated. In the case of compliance with Section 111(d), the definition of pollution control must be expanded to encompass all actions aimed at compliance that improve efficiency. While these projects do not always entail the installation of specific pollution control “device,” they involve the “use” of a pollution control “system,” the primary function of which is to reduce CO2 pollution.

Without such an exclusion, the Section 111(d) plans could effectively force existing EGUs to trigger NSPS modification requirements merely through complying with an applicable state plan. Such an approach would put both EGUs and state permitting authorities in an untenable position. To eliminate this concern, EPA should make clear in the final rule that any physical or operational change undertaken to comply with a CAA Section 111(d) plan qualifies as a “pollution control project” and is thereby exempt from the NSPS definition of “modification.”

EPA is incorrect in stating that “few” sources will trigger Prevention of Deterioration (PSD) and Non-Attainment New Source Review (NNSR), collectively referred to as NSR, in complying with the proposed guidelines

NSR is a preconstruction permit program that affects new sources as well as the modification of existing sources. According to EPA regulations, an existing source that undertakes a physical or operational change that results in a “significant” emissions increase will trigger NSR modification. The significance levels vary by pollutant and can

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be as low as an increase of 40 tons per year of NOx emissions or 10 tons per year of fine particulates (PM2.5).

Over the years, the NSR permitting requirements have discouraged many owners and operators from undertaking energy efficiency improvements at their existing units despite the availability of new technologies to enhance performance and efficiency. As noted above, equipment upgrades that would ultimately make the unit more efficient – a 2 to 8 percent increase in efficiency – may also elevate the position of the unit in the dispatch curve, which in some circumstances could lead to emission increases measured on a tons per year basis, thereby triggering NSR. As a result, many projects aimed at improving efficiency, reliability and performance were never undertaken, or were limited to ”like-kind” replacements that did not obtain the full efficiency improvement available from the upgrade but clearly avoided NSR.

EPA incorrectly concludes in the preamble that there will be “few” instances where an NSR permit would be required in response to the guidelines.11 As noted above, EPA’s proposed guidelines require existing coal and oil-fired steam units to improve heat rates – an action that will increase efficiency and output. For many units, this may trigger NSR review unless operational limits are taken which then has the perverse result of not allowing the full effect of the efficiency improvements to be realized. For gas turbines that are being required to dispatch at much higher levels, many operationally and economically beneficial turbine upgrades to improve reliability, performance, and efficiency may also trigger NSR unless capacity limits are taken to restrict full deployment of the efficiency upgrade. History, as well as the likely demands imposed on existing sources under these proposed guidelines, will significantly increase the number of units that could potentially trigger NSR.

Existing NSR requirements will impede the ability of EGUs to improve efficiency and comply with the Section 111(d) guidelines and state plans

Unlike NSPS, NSR rules do not contain an applicability exemption for pollution control projects. For this reason, NSR has represented a substantial impediment to broad implementation of otherwise feasible, cost-effective efficiency upgrade projects. GE’s extensive experience working with utility customers suggests that the fear of triggering NSR will discourage many existing EGUs from making physical or operational changes that would improve efficiency and facilitate compliance with Section 111(d).

For NGCC units, upgrades will generally increase gas turbine output, improve efficiency, and reduce emissions per MW of electricity produced. Overall, the upgrade will yield an approximately 3 percent heat rate improvement resulting in a reduced CO2 emission rate

11 79 Fed. Reg. at 34,928/col. 2-3

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by 36 lbs./MWh. But the potential also exists for a unit to emit more on an annual and even hourly basis whether or not the units is dispatched more often. Thus, even though the emission concentration will remain the same (e.g., 2 ppm NOx pre-upgrade and 2 ppm NOx post-upgrade) and the rate of emission per unit of power will decrease (e.g., by 0.02 lb./MWh), the mass emission rate will increase slightly (e.g., by 0.5 lbs./hr. NOx). Thus, despite the clear benefits, owners have forgone the energy efficiency benefits from the upgrades due to the potential of triggering NSR permitting requirements.

A key aspect of pre-reform NSR that discouraged sources from considering upgrade projects include the current manner in which EPA guidance required emission increases from a project to be determined by comparing baseline actual emissions (highest actual emissions over a 24-month period preceding a change) to future potential emissions. As a result, if the facility operated at a relatively low capacity factor, and the future potential emissions are based on a higher capacity factor, the NSR significant emission levels could easily be triggered. Under the NSR reform rules, which apply in many, but not all, states, an actual-to-projected-actual emission increase test applies. But even that test, as discussed in more detail below, does not effectively and reliably exclude emissions associated with increased utilization from an efficiency upgrade.

Once triggered, the NSR permitting process can have many negative consequences for a source, including construction delays. Experience with the program suggests that major NSR permit reviews can delay projects one to two years beyond the much-shorter minor NSR permitting process. Moreover, because NSR requires case-by-case review, there is often significant uncertainty regarding the likely outcomes, including whether the project will be approved, and what new permit conditions may be attached, including their potential costs. EPA’s existing network of regulatory requirements is also complex and constantly changing. Often customers are faced with the problem of responding to new permit conditions from regulatory changes that occurred following the permit application, creating a difficult do-loop for permit seekers.

Many GE customers have historically expressed a general reluctance to go through the NSR process due to the vagueness of the program provisions and the extensive case law history around the program. All of these reasons have lead customers to install like or in-kind replacement parts instead of technology improvements. Finalizing a Section 111(d) rule without including regulatory changes that address NSR applicability would significantly undermine the ability of EGUs to comply the proposed guidelines.

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Many of EPA’s proffered solutions for avoiding NSR are ineffective and run counter to the objectives of the proposed guidelines

In the preamble, EPA suggests that states will have “considerable flexibility” to prevent the projects from causing an emission increase:12

One of these flexibilities is the ability of the state to establish the standards of performance in their CAA section 111(d) plans in such a way so that their affected sources, in complying with those standards, in fact would not have emissions increases that trigger NSR. To achieve this, the state would need to conduct an analysis consistent with the NSR regulatory requirements that supports its determination that as long as affected sources comply with the standards of performance in their CAA section 111(d) plan, the source's emissions would not increase in a way that trigger NSR requirements.

For example, a state could decide to adjust its demand side measures or increase reliance on renewable energy as a way of reducing the future emissions of an affected source initially predicted (without such alterations) to increase its emissions as a result of a CAA section 111(d) plan requirement. In other words, a state plan's incorporation of expanded use of cleaner generation or demand-side measures could yield the result that units that would otherwise be projected to trigger NSR through a physical change that might result in increased dispatch would not, in fact, increase their emissions, due to reduced demand for their operation. The state could also, as part of its CAA section 111(d) plan, develop conditions for a source expected to trigger NSR that would limit the unit's ability to move up in the dispatch enough to result in a significant net emissions increase that would trigger NSR (effectively establishing a synthetic minor limit). [317] p 34,928

EPA’s specific suggestions include having a state “adjust its demand side measures or increase reliance on renewable energy as a way of reducing the future emissions of an affected source” that may trigger NSR.13 Alternatively, EPA suggests states could develop “conditions” for a source expected to trigger NSR that would “limit the unit's ability to move up in the dispatch enough to result in a significant net emissions increase that would trigger NSR (effectively establishing a synthetic minor limit).”14

While these proposed options have the potential to prevent a source from triggering 12 Id. col. 3 13 Id. 14 Id.

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NSR, they would also eliminate any incentive for an owner or operator to make the required upgrade investment. The key reason to invest in equipment upgrades in mature existing units is to recoup the investment in increased efficiency, lower fuel costs, and greater reliability. EPA’s proposal would ask sources to make the investment but then limit the unit’s hours of operation, effectively impeding the source’s ability to recover its investment. This approach would effectively stop almost all investments in existing units that could trigger NSR, thereby eliminating many of the energy efficiency measures sources would otherwise undertake to comply and increase system reliability.

On a more fundamental basis, the proposed solutions to limit hours of operation also run counter to the objectives the proposed guidelines to reduce CO2 emissions from electricity generation in the most cost-effective manner possible. EPA notes repeatedly in the proposed guidelines that states will have considerable flexibility to design state programs, but then suggests limits on major compliance options, such as improvements in energy efficiency at existing units, even though these options will reduce emissions per megawatt of electricity produced.

EPA’s proposed solution to have the state effectively limit the dispatch of the unit is also problematic because it assumes authorities that many states, as members of regional transmission organizations, do not possess. Currently, the variable operating cost of electric power generation is a key factor in determining which units of a power system are dispatched. Plants with the lowest variable operating costs are generally dispatched first, and plants with higher variable operating costs are brought on line sequentially as electricity demand increases.15 As yet, it is unclear how the requirements of the proposed guidelines will impact the structure and operation of electric markets. Any solution that hinges on such an outcome is highly uncertain and unlikely to encourage needed upfront investment in EGU upgrades.

Further, in the case of NGCC, restricting hours of operation run directly counter to the objective of Block 2, namely re-dispatch to lower CO2 emitting generation. An existing gas turbine EGU would benefit from the increased output, efficiency, and cost effectiveness of deploying an upgrade option. All of these factors, along with the stated objectives of Block 2, would lead to the desired result of increased cost effective gas turbine operation leading to the ultimate goal of reduced grid-wide CO2 emissions. As stated earlier in these comments, NSR permitting poses a direct barrier to deployment of beneficial gas turbine upgrades, and reducing operating capacity to avoid NSR permitting is directly counter to every objective of the proposed rule.

15 EIA, “Electric generator dispatch depends on system demand and the relative cost of operation” at http://www.eia.gov/todayinenergy/detail.cfm?id=7590

http://www.eia.gov/todayinenergy/detail.cfm?id=7590

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b. There are several approaches to NSR that would facilitate compliance with Section 111(d)

Applying NSR to upgrades that improve efficiency or are being implemented to comply with the proposed Section 111(d) guidelines and resulting state plans is both anachronistic and counterproductive. That said, the Agency has available several practical, common sense approaches that are also legally supported under the statute to prevent unintended results from the guidelines and plans. With appropriate changes to the proposal, EPA can implement the NSR program under the CAA and also maintain state and source compliance flexibility, and unleash innovation, without fear of triggering the costs, delays, and uncertainties associated with NSR. EPA should move forward in the final Section 111(d) rule with a clear preamble and corresponding regulatory provisions that would allow sources to upgrade their equipment to improve the efficiency of their overall power production (thus reducing CO2) without triggering NSR.

The Proposed Rule seeks comment on a general approach to resolve concerns about NSR applicability associated with projects undertaken to comply with a state’s CAA section 111(d) plan:

We request comment on whether, with adequate record support, the state plan could include a provision, based on underlying analysis, stating that an affected source that complies with its applicable standard would be treated as not increasing its emissions, and if so, whether such a provision would mean that, as a matter of law, the source's actions to comply with its standard would not subject the source to NSR. We also seek comment on the level of analysis that would be required to support a state's determination that sources will not trigger NSR when complying with the standards of performance included in the state's CAA section 111(d) plan and the type of plan requirements, if any, that would need to be included in the state's plan. P34,928-9.

GE believes that there are approaches that are logically embedded in this general approach that could effectively address concerns associated with NSR applicability. These approaches are discussed below and can be used individually or in tandem to accomplish the result:

Option 1: Interpret “increases” for EGUs on a pound-per-MWh basis

Section 111(a)(4) of the CAA defines “modification” to mean “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” Because neither “increases” nor “amount” is defined in

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the Act, EPA retains discretion to determine what those words mean in the context of the program at issue.16 This discretion provides EPA, and states adopting plans pursuant to the guidelines, with the flexibility to base NSR applicability on a pounds-per-MWh basis, instead of or in addition to annual emissions.

EPA could use a pound-per-MWh emissions test as the sole emissions applicability test for projects undertaken by EGUs. To avoid unintended consequences with projects that do not have a pounds per MWh decrease, EPA could also use a two-step emissions test: EGUs would first determine whether or not a physical or operational change results in an increase in emissions on a pound-per-MWh produced basis; if pound-per-MWh are increased, EPA could then revert to its traditional approach to assessing NSR modification by determining whether the emissions increase in tons per year exceeds de minimis levels for the regulated pollutants.

Option 2: Use the routine maintenance, repair, and replacement exclusion to address NSR applicability concerns associated with efficiency improvement projects.

EPA could take the position that upgrades conducted pursuant to an approved Section 111(d) project to improve efficiency are covered by the routine maintenance, repair, and replacement exclusion. Being required (or at least strongly encouraged) to undertake efficiency improvements in Building Blocks 1 and 2 certainly suggests that the gatekeeper of “routine” has been satisfied.

Option 3: Use state-wide netting (or a state-wide applicability limit) to avoid a determination of emission increases.

Another way of achieving this same outcome could be for EPA to state that sources that are in compliance with an approved statewide plan are employing state-wide netting (or a state-wide applicability limit) as a way of avoiding an emissions increase. Given that EPA is relying on beyond-the-fence-line reductions as part of the BSER under Section 111(d), EPA could also define state-wide netting as a way to avoid triggering NSR. Thus, any source in compliance with these statewide systems that has an emissions increase by itself will not trigger NSR modification because by definition of the state plan, the emission increase is being offset by emission decreases elsewhere in the state. If this approach is selected, it is critical that the netting exclusion be able to apply on a pollutant-specific basis for all pollutants and not be limited to CO2. As discussed above, despite reductions in emissions per unit of electricity generated, efficiency improvement projects have the potential to result in increases in emissions per unit time of multiple pollutants, including NOx and PM. For this reason, any NSR applicability solution, including state-wide netting would need to apply across the range of pollutants emitted.

16 [cite UARG Supreme Court decision on any air pollutant]

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Option 4: Clarify that increases in emissions associated with increased utilization of efficiency projects are properly excluded under the demand growth exclusion.

While current PSD rules provide a regulatory mechanism for excluding certain increases in emissions that result from increased utilization due to product demand growth, this mechanism is currently insufficient to provide regulatory certainty that efficiency projects to comply with an approved state plan under Section 111(d) will not trigger time-intensive and costly PSD permitting requirements.

Current PSD rules provide that the calculation of “[p]rojected actual emissions . . . [s]hall exclude . . . any increase in emissions that results from the particular project, that portion of the unit's emissions following the project that an existing unit could have accommodated during the consecutive 24-month period used to establish the baseline actual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utilization due to product demand growth . . . .”17 This provision establishes two requirements for excluding emission increases associated with demand growth. First, the demand growth emissions must have been capable of being accommodated during the baseline period. Second, the demand growth must be “unrelated to the particular project.” In the first version of EPA rules incorporating this concept, EPA highlighted the causation requirement in the definition of modification for providing the demand growth exclusion.18 However, in the 2002 rulemaking where EPA revisited the demand growth exclusion, EPA explained:

On the other hand, demand growth can only be excluded to the extent that the physical or operational change is not related to the emissions increase. Thus, even if the operation of an emissions unit to meet a particular level of demand could have been accomplished during the representative baseline period, but the increase is related to the changes made to the unit, then the emissions increases resulting from the increased operation must be attributed to the project, and cannot be subtracted from the projection of projected actual emissions.19

Thus, while the 1992 WEPCO rule discussion focused on whether the project caused the increase in emissions, the 2002 rulemaking discussion focuses on whether the emission increases are related to the project and, if so, they must be attributed to the project. This difference in approach is reflected in EPA applicability determination letters preceding and following the 2002 NSR reform rule. For example, in a 2001 applicability letter, EPA stated, “[p]rojected future actual emissions or representative actual annual actual

17 40 C.F.R. § 52.21(b)(41)(ii)(c). 18 See e.g., 57 Fed. Reg. 32,314, 32,327 (July 21, 1992) (“demand growth can only be excluded to the extent it—―and not the physical or operational change—―is the cause of the emission increase.”). 19 67 Fed. Reg. 80,186, 80,203 (Dec. 31, 2002) (emphasis added).

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emissions are determined by calculating only those emissions increases that are caused by the modification.”20 In contrast, more recent applicability determination letters have precluded the use of the demand growth exclusion where the project is related to the emission increases.21

In light of EPA’s interpretation of the current regulatory language, the demand growth exclusion simply fails to provide meaningful relief from PSD applicability concerns for efficiency projects designed to meet improvements in efficiency associated with the proposed ESPS. With amendments to its PSD rules and an accompanying explanation in its rule preamble, however, GE believes that the demand growth exclusion could be appropriately interpreted (with a regulatory revision if necessary) to provide a useful mechanism for clarifying non-applicability of PSD for efficiency-improvement projects designed to meet improvements in efficiency associated with the proposed ESPS. GE believes that this relief could be provided with the following rule changes to EPA’s PSD rule:

Change 40 CFR § 52.21(b)(41)(ii) to add new subsection (b)(41)(ii)(e) as follows:

(e) For projects specifically undertaken to meet efficiency improvements associated with [the proposed ESPS], emission increases resulting from any increased utilization due to product demand growth are deemed to not be related to the particular project.

Change 40 CFR § 51.166(b)(40)(ii) to add new subsection (b)(40)(ii)(e) as follows:

(e) For projects specifically undertaken to meet efficiency improvements associated with [the proposed ESPS], emission increases resulting from any increased utilization due to product demand growth are deemed to not be related to the particular project.

As these options suggest, EPA has many alternatives that it can employ consistent with the CAA that would maintain state and source compliance flexibility and unleash innovation without fear of NSR. EPA should move forward in the final rule with a clear provision that would allow sources to upgrade their equipment and improve the

20 See Letter from Richard Long, Dir., Air and Radiation Program, EPA Region 8 to Gary Helbling, Envtl. Eng’r, N.D. Health Dep’t (Apr. 17, 2001) at Attach. A, 3 available at http://www.epa.gov/region7/air/nsr/nsrmemos/otter.pdf (emphasis added). 21 See e.g., Letter from Greg Worley, Chief, Air Permits Section, EPA Region 4 to Mark Robinson, Plant Manager, Georgia-Pacific Wood Products LLC (Mar. 18, 2002) at 1-2 available at http://www.epa.gov/region7/air/nsr/nsrmemos/demandgrowth.pdf; see also Letter from Dianne McNally, Acting Assoc. Dir., Office of Permits & Air Toxics, EPA Region 3 to Mark Wejkszner, Manager, Air Quality Program, Pa. Dep’t of Envtl. Protection (Apr. 20, 2010) at 4 available at http://www.epa.gov/region7/air/nsr/nsrmemos/psdanalysis.pdf (“the facility must be able to demonstrate that excluded emissions are completely unrelated to the project.”) (emphasis added).

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efficiency of their overall power production without triggering NSPS or PSD/NNSR. To the extent EPA believes any approach to resolve this issue is not sufficiently tied to the proposal, we note that the solicitation of comment was extremely broad such that any of the above are reasonably viewed as a logical outgrowth of the proposed action.22

IV. Distinguishing 111(b) from 111(d)

a. EPA’s final Section 111(d) guidelines should not impose dual regulatory requirements on modified units

In EPA’s June 2014 proposed modification and reconstruction rule, the Agency proposes to keep modified and reconstructed sources in a state’s section 111(d) plan if at the time of modification and reconstruction the source was subject to the state’s section 111(d) plan:

For the reasons discussed in the “Legal Memorandum” . . . all existing sources that become modified or reconstructed sources and which are subject to a CAA section 111(d) plan at the time of the modification or reconstruction, will remain in the CAA section 111(d) plan and remain subject to any applicable regulatory requirements in the plan, in addition to being subject to regulatory requirements under CAA section 111(b).23

Similarly, in the proposed Section 111(d) guidelines, EPA restates this proposal, reiterating that the modified and reconstructed unit would be subject to Section 111(d) and Section 111(b) requirements simultaneously:

The EPA is proposing that an existing source that becomes subject to requirements under CAA section 111(d) will continue to be subject to those requirements even after it undertakes a modification or reconstruction. Under this interpretation, a modified or reconstructed source would be subject to both (1) the CAA section 111(d) requirements that it had previously been subject to and (2) the modified source or reconstructed source standard being promulgated under CAA section 111(b) simultaneously with this rulemaking. It should be noted that this proposal applies to any existing source subject to any CAA section 111(d)

22 Alternatively, EPA can address its proposed approach in the preamble to the final rule and make the changes to rule language in a separate rulemaking. For example, EPA recently announced that it intended to change its PSD rules to facilitate the use of biomass projects under the Proposed Rule. That rulemaking could be expanded to fully implement any NSR remedy that cannot be fully implemented as part of the Proposed Rule. 23 79 Fed. Reg. at 34,963/col. 1.

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plan, and not only existing sources subject to the CAA section 111(d) plans promulgated under this rulemaking.24

While GE understands the initial appeal of this proposal for purposes of ensuring continued emission reductions from existing units, EPA’s proposal creates significant legal risk under the CAA. Section 111(a) is clear in defining a “new source” as “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” Section 111(b)(1)(B) further requires EPA to establish separate standards for new sources within one year of listing the source category: “Within one year after the inclusion of a category of stationary sources in a list under subparagraph (A), the Administrator shall publish proposed regulations, establishing Federal standards of performance for new sources within such category.”

In contrast, existing sources are clearly regulated under Section 111(d), which requires EPA to establish “standards of performance for any existing source for any air pollutant” for which air quality criteria have not been issued or which is not included on a list published under Section 108 of the CAA or emitted from a source category which is regulated under Section 112 of the CAA, but “to which a standard of performance under this section would apply if such existing source were a new source.” EPA cannot regulate the same sources under both provisions. The statute is clear – either a source is “new” subject to standards under Section 111(b), or a source is an “existing” source subject to standards under Section 111(d). This separation is reinforced by the different criteria guiding standard setting for new versus existing sources in each provision. EPA ignores the plain meaning and structure of section 111 by attempting to subject sources to both existing and new standards at the same time.

Instead of proposing dual, simultaneous regulation of modified and reconstructed units that would increase legal risk for the rule, EPA should simply clarify that any physical or operational change undertaken to improve efficiency or comply with a state’s Section 111(d) plan represents a pollution control project and is thus excluded from triggering modification. This would greatly simplify the program and largely address the problem of dual regulation.

While existing sources traditionally have not triggered reconstruction as often as modification, GE anticipates that many existing sources will opt to repower rather than build a new greenfield plant. GE’s October 16, 2014 comments submitted in response to

24 79 Fed. Reg. at 34,903/col. 3

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EPA’s proposed rule for modified and reconstructed sources recommends that the Agency finalize standards that are reflective of what repowered sources can achieve.

If EPA insists on proceeding with the more legally vulnerable approach of keeping reconstructed sources in Section 111(d), the Agency could simplify compliance by establishing that a reconstructed source’s compliance with a state’s 111(d) plan also satisfies Section 111(b) standards for reconstructed units. Alternatively, as noted above in the PSD/NNSR discussion, EPA has similar discretion not to impose NSPS for modified or reconstructed units. In fact, EPA has previously decided not to establish certain NSPS for modified or reconstructed units in specific source categories, including Asphalt Processing and Asphalt Roofing Manufacture (which exempts modified sources from the visible emission standard 40 C.F.R. § 60.472(a)(3)) and Synthetic Fiber Production Facilities (that does not apply to modified facilities 40 C.F. R. § 60.600(c)). Deciding not to impose standards on these units would prevent dual regulation.

b. While states have the discretion to use new NGCC as an emission mitigation strategy, a decision by EPA to include new sources as part of a BSER determination under Section 111(d) would create significant legal risk.

While the Agency’s proposed guidelines do not include new NGCC capacity as part of its BSER determination, EPA requests comment on whether the Agency should consider new NGCC capacity as part of the BSER and on ways to definite appropriate state-level goals:

While the EPA is not proposing that new NGCC capacity is part of the basis supporting the BSER, we recognize that there are a number of new NGCC units being proposed and that many modeling efforts suggest that development of new NGCC capacity would likely be used as a CO 2 emission mitigation strategy. Therefore, we invite comment on whether we should consider construction and use of new NGCC capacity as part of the basis supporting the BSER. Further, we take comment on ways to define appropriate state-level goals based on consideration of new NGCC capacity.25

Later in the proposed guidelines, EPA builds on this request for comments by seeking additional input from the public on how the emission changes from substitution of existing generation by new NGCC should be calculated:

The agency requests comment on how emissions changes under a rate-based plan resulting from substitution of generation by new NGCC for

25 p 34,877/col 1

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generation by affected EGUs should be calculated toward a required emission performance level for affected EGUs. Specifically, considering the legal structure of CAA section 111(d), should the calculation consider only the emission reductions at affected EGUs, or should the calculation also consider the new emissions added by the new NGCC unit, which is not an affected unit under section 111(d)? Should the emissions from a new NGCC included as an enforceable measure in a mass-based state plan (e.g., in a plan using a portfolio approach) also be considered?26

These are both important issues. As discussed above, Section 111 establishes separate regulatory programs for new units (including modified and reconstructed units) under Section 111(b), and for existing units under Section 111(d). In addition to being more legally defensible, excluding new units from Section 111(d) plans would also create an incentive to modernize and build new NGCC capacity that can attain even higher efficiency levels than is achievable with existing units. Requiring states to include new units in existing state plans would increase the legal uncertainty surrounding the rule and discourage investment in new, more efficient capacity.

While the CAA is clear that newly constructed EGUs that commence construction after January 8, 2014 (the date of publication of the proposed NSPS rule for new EGUs under section 111(b)) are regulated under subsection (b), EPA correctly recognizes that states may use new NGCC capacity as a CO2 emission mitigation strategy. This raises important questions regarding how emissions should be calculated under a rate-base or mass-based approach.

If a state employs a rate-based approach under section 111(d), the most appropriate approach would be to allow the megawatt hours generated by these newly constructed units to be included in the denominator for a state’s rate. This approach would be similar to how renewable energy and new nuclear units are treated under EPA’s Proposed Guidelines under section 111(d). For states that use the mass-based approach under section 111(d), the emissions from newly constructed units should not be included in the program at all.

V. Accounting for CHP

Combined Heat and Power (CHP) units are capable of providing overall efficiencies of 60 to 80 percent, leading to improved environmental performance, reduced energy

26 34,924, col.1

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consumption, and improved grid reliability compared with conventional generation. CHP creates less pollution per unit of energy by using the energy potential of fuel inputs twice or three times, yielding half to a third of the emissions that would otherwise result from separate applications.

GE urges EPA to ensure that CHP facilities are not inadvertently subject to regulation under this rule as “affected Electricity Generating Units.” No existing CHP facilities should be subject to regulation under the Clean Power Plan. We suggest excluding highly efficient CHP units that provide greater than 65 percent overall efficiency.

Because CHP units put waste heat to productive use, they can increase a facility’s net energy output without a change to emissions. We believe EPA should incentivize these highly efficient units by allowing facilities to include 100 percent of useful thermal output from CHP when calculating emission compliance. Local applications of CHP also avoid transmission and distribution line losses, which should be consistent with average line losses for the state in which a particular CHP unit is located.

GE supports the Combined Heat and Power Association (CHPA) comments to EPA, and we join with them in encouraging EPA to recognize the benefits of encouraging the expansion and deployment of CHP facilities to the greatest extent practicable.

VI. Fuel cells

EPA should include all-electric fuel cells as a compliance option under this rule

EPA should specifically list all-electric fuel cells as potential compliance options for states to use as they reduce their overall carbon intensity. All-electric fuel cells are deployable as demand-side resources to provide year-round power using natural gas or biogas at efficiencies much higher than those of centralized power plants. Additionally, fuel cells are typically situated close to loads, where they avoid the transmission and distribution line losses associated with centralized generation.

Twenty-two states, two territories, and the District of Columbia already recognize the importance of fuel cells in supporting a lower-carbon future. The California Air Resources Board (CARB) in 2007 qualified fuel cells as “ultra-clean” technology under their existing standard. The New York Public Service Commission qualifies them under their Renewable Portfolio Standard.

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Comments on EPA Building Blocks

I. Building Block 1: Efficiency improvements

a. EPA’s estimate of cost effective upgrades across the coal fleet is unrealistic

In building block 1, EPA suggests that a net heat rate improvement (HRI) of 6% can be achieved in the existing coal-fired steam boiler fleet as a means to reduce C02 emissions.27 According to EPA, this 6% is achievable through implementing best practices in operations and maintenance of these facilities (4% net) and through installation of equipment upgrades (2% net).

We agree there is an untapped potential in the fossil power sector to deploy upgrades and improve operations. For the purposes of our comments, and in general, we consider heat rate improvements from equipment and from operational improvements as part of one category, and our estimates reflect the total impact of both “types” of heat rate improvement.

GE is a major provider of equipment and services to the coal-fired power sector. In fact, around half of the existing fleet runs on GE technology, and over three-quarters of that subset have already deployed upgraded heat rate technology. These upgrades not only improve efficiency and lower CO2 emissions, they also drive better economic performance of units and plants. This potential is restrained by costs and the regulatory burdens triggered by implementing certain measures (e.g. New Source Review).

GE analysis shows a gross 6% heat rate increase across the existing fleet is perhaps technically possible, but only achievable at an unreasonable cost. GE estimates the total economic potential for heat rate improvements in the existing coal fleet to instead be as high as ~4% gross, through a combination of operational and equipment improvements. Because of anticipated market conditions and potential regulatory barriers to implementation, most of these improvements are likely to happen in a 42GW subset of the existing fleet. As a result , we expect to see potential deployment of HRIs to be closer to a 1% gross, on average, across the fleet.

27 We use the term net with regards to EPA’s 6 percent reduction because environmental retrofits in response to other EPA regulations, such as CSAPR and MATS, create a parasitic load on generating plants that increase heat rates. Any heat rate improvement target must first offset these increases in heat rate from 2012 before they achieve the true net reduction in heat rate called for by EPA. According to our estimate, the impact on heat rate for the parasitic load is about 0.5% across the fleet from 2012. As we do not have individual plant data, parasitic load at any individual plant could be higher or lower. Our estimates of heat rate improvement potentials below are stated as “gross” terms as they represent the gain from the heat rate projects and do not offset parasitic load. For comparison purposes to EPA’s estimate, our numbers should be reduced about 0.5%.

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We have included a more in-depth discussion about how we arrived at these conclusions in Appendix A. Effective NSR reform is critical to unlock more potential from existing coal-fired power plants.

We believe EPA should consider several important issues when calculating the impact of heat rate improvements as part of the Agency’s BSER determination.

b. EPA should consider operator experience, conditions, and the availability of new technologies when calculating the impact of upgrades

Advanced technologies to improve heat rate in coal plants have been developed since the 2009 S&L study and should be considered by EPA in its BSER determination

Advanced heat rate improvement strategies leverage technological improvements from new units. New steam turbine units use advanced 3D airfoil and blade technology, enhanced sealing technology to reduce leakages, and improved moisture removal from low pressure turbines. Our experience with new units indicates that these advanced technologies could offer up to an additional 2.0% gross heat rate improvement, where feasibl