Larry A. Boggs 

Director and Senior Counsel 

 Government Affairs 

Corporate Env'l Programs 

General Electric Company 

1299 Pennsylvania Avenue, NW 

Washington, DC 20004-2407 

USA 

T 202 637 4126 

F 202 637 4017 

larry.boggs@ge.com 

June 25, 2012 

Via Electronic Filing and Email 

Mr. Christian Fellner and Dr. Nick Hutson 

Energy Strategies Group 

Sector Policies and Programs Division (D243–01) 

U.S. Environmental Protection Agency 

Research Triangle Park, NC 27711 

fellner.christian@epa.gov 

hutson.nick@epa.gov 

Attention: Docket ID No. EPA-HQ-OAR-2011-0660 

Re: Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: 

Electric Utility Generating Units, 77 Fed. Reg. 22,392 (Apr. 13, 2012) 

Dear Mr. Fellner and Dr. Hutson: 

The General Electric Company (GE) appreciates the opportunity to comment on the 

proposed Standards of Performance for Greenhouse Gas Emissions for New Stationary 

Sources: Electric Utility Generating Units. We look forward to working with the Agency as it 

moves toward promulgation of a final rule. 

Please contact me at larry.boggs@ge.com or (202) 637-4126 with any questions 

regarding these comments. 

 Sincerely,

 /s/

 Larry A. Boggs 
COMMENTS OF THE GENERAL ELECTRIC COMPANY 

PROPOSED STANDARDS OF PERFORMANCE FOR 

GREENHOUSE GAS EMISSIONS FOR 

NEW STATIONARY SOURCES: 

ELECTRIC UTILITY GENERATING UNITS 

77 Federal Register 22,392 

(April 13, 2012) 

SUBMITTED ON JUNE 25, 2012 
 

 

TABLE OF CONTENTS 

Page 

INTRODUCTION AND EXECUTIVE SUMMARY............................................................. 1 

THE PROPOSAL APPROPRIATELY RECOGNIZES THE IMPORTANCE 

OF GAS BUT ALSO MUST PROVIDE A ROLE FOR CLEAN COAL............................... 2 

THE FINAL RULE MUST PROVIDE CERTAINTY TO ALLOW FOR 

INVESTMENT IN CLEANER FUELS AND TECHNOLOGIES ......................................... 3 

I. THE PROPOSED RULE APPROPRIATELY RECOGNIZES 

THE INCREASE ROLE OF NATURAL GAS IN U.S. ELECTRICITY 

 PRODUCTION...................................................................................................... 4 

II. NATURAL GAS TURBINES PLAY A VITAL ROLE IN U.S. 

 ELECTRICITY PRODUCTION.............................................................................. 5 

A. Natural Gas Turbines Provide Critical Operational Flexibility to 

Today’s Electricity Generation and Distribution Systems, 

While Allowing More Efficient Response to Demand Fluctuations............ 5 

B. Natural Gas Turbines Are Uniquely Able to Support Renewable 

Generation ................................................................................................ 6 

C. By Facilitating the Use of Renewable Generation, Gas Turbine 

Technologies Reduce System-Wide Emissions........................................ 6 

III. STANDARD OF NO LESS THAN 1,100 lb/MWh IS NECESSARY TO
 

ACCOUNT FOR ACTUAL OPERATING CONDITIONS AND
 

SITE-TO-SITE VARIATIONS................................................................................ 7 

A. Section 111 of the Act Requires EPA to Take Into Account the 

Expected Operating Performance in Actual Conditions Over the 

Life of the Unit ........................................................................................... 7 

B. EPA’s 5% Allowance to Address Partial Load Situations is 

Insufficient and Not supported by the Record ........................................... 9 

C. Failure to Establish an Achievable Standard will Lead to 

Higher Overall GHG Emissions............................................................... 12 

D. If a 1,000 lb/MWh Standard Is Issued, Alternative Compliance 

 111’s Requirements ................................................................................ 12 

IV. THE PROPOSED SIMPLE CYCLE COMBUSTION TURBINE 

EXEMPTION, WHICH IS BOTH REASONABLE AND NECESSARY 

TO ENSURE RELIABILITY OF THE ELECTRICAL GRID, MUST BE 

MAINTAINED IN THE FINAL RULE ................................................................... 13 

A. GE Supports Issuance of a Specific Simple Cycle Turbine 

Definition and Exemption ........................................................................ 13 

B. Simple Cycle Gas Turbines Are an Essential Part of the Power 

Generation Portfolio in That They Provide: Highly Flexible Power 

Generation, the Ability to Manage Contingencies in the Electrical 

Grid, and Necessary Backup Power ....................................................... 14 
 

 

 

 

TABLE OF CONTENTS (cont’d) 

Page 

C. NGCC Installations, while Flexible, Cannot Substitute 

for Simple Cycle ...................................................................................... 14 

D. The Importance of Maintaining the Broad Simple Cycle Exclusion 

from the Rule is Underscored by the Fact that the Proposed EGU 

Definition Exempting Units that Supply Less than 2,900 Hours to 

the Grid is Insufficient to Address Simple Cycle Units ............................ 15 

E. The Proposed Range of 950 to 1,100 lb/MWh Does Not Reflect 

BSER for Simple Cycle Turbines ............................................................ 16 

F. The Simple Cycle Turbine Exemption Does Not Provide an 

Incentive to Install Simple Cycle in Place of NGCC ................................ 17 

G. The Simple Cycle Exemption Will Not Delay the Installation of 

the Heat Recovery Steam Generator Portion of NGCC.......................... 18 

H. NGCC Plants with a By-Pass Stack Must Not be Subject to 

the Standard When Operated in Simple Cycle Mode.............................. 18 

V. WHILE CARBON CAPTURE IS ACHIEVABLE NOW, EPA SHOULD 

PROVIDE FLEXIBLE COMPLIANCE PERIODS TO REDUCE 

UNCERTAINTIES RELATED TO SEQUESTRATION THAT MAY 

PREVENT INVESTMENT AND TECHNOLOGY ADVANCEMENT.................... 19 

VI. EPA SHOULD AMEND THE KEY PROVISIONS OF THE RULE TO 

ENSURE THAT IGCC CAN BE USED UNDER THE 

ALTERNATIVE COMPLIANCE OPTION............................................................ 20 

A. EPA Should Clarify the Definition of Integrated Gasification 

Combined Cycle Electric Generating Unit to Include the Heat 

 Recovery Steam Generator..................................................................... 20 

B. EPA Should Also Amend the Applicability Requirements for the 

Alternative Compliance Option Under Proposed § 60.5220(b) to 

Specifically Allow IGCC Units as They are Defined in the Rule 

 to Qualify ................................................................................................. 21 

VII. THE FINAL RULE SHOULD INCLUDE A CUMULATIVE 

ROLLING SUM THAT WILL ACCURATELY REPRESENT 

EMISSIONS AND PROPORTIONATELY WEIGH PERIODS 

OF HIGH EMISSIONS AND LOW GENERATION.............................................. 22 

VIII. A GROSS OUTPUT STANDARD SHOULD BE ADOPTED 

OVER A NET OUTPUT STANDARD................................................................. .23 

IX.	 BECAUSE FUEL MONITORING MEETS CLEAN AIR ACT 

 COMPLIANCE REQUIREMENTS AND DOES NOT INVOLVE THE 

MEASUREMENT UNCERTAINTIES AND COSTS OF CONTINUOUS 

EMISSION MONITORS, THE RULE SHOULD ADOPT FUEL
 

SAMPLING AS AN INDEPENDENT COMPLIANCE METHOD.......................... 23 

-ii-
 

 

TABLE OF CONTENTS (cont’d) 

Page 

X. EPA SHOULD ADOPT AN EXEMPTION FOR COMBUSTION 

OF WASTE FUELS SUCH AS BLAST FURNACE GAS AND 

 REFINERY FUEL GAS ....................................................................................... 25 

XI. EPA SHOULD PROVIDE FOR COMPLIANCE CALCULATED 

AS AN AVERAGE OF ALL NEW ELECTRIC GENERATING 

UNITS AT A SINGLE PLANT ............................................................................. 26 

XII. COMBINED HEAT AND POWER FACILITIES WHERE USEFUL 

THERMAL OUTPUT ACCOUNTS FOR 20 PERCENT OF THE TOTAL 

USEFUL OUTPUT SHOULD BE EXCLUDED FROM THIS RULE .................... 26 

XIII. THE POLLUTION CONTROL PROJECT EXCLUSION SHOULD 

 NOT BE ELIMINATED ........................................................................................ 26 

XIV. THE PROPOSED RULE SHOULD BE REVISED TO INCLUDE 

LANGUAGE CLARIFYING THAT THE FINAL STANDARD 

INCLUDED IN THIS RULE FOR NGCC DOES NOT APPLY TO 

PSD PERMITS FOR SIMPLE CYCLE UNITS .................................................... 27 

XV. EPA SHOULD INCLUDE EXPLICIT REGULATORY LANGUAGE 

IN PART 52 PSD REGUATIONS TO CLARIFY THAT 

REGULATION OF CO2 UNDER SECTION 111 TRIGGERS 

THE TAILORING RULE GHG EMISSION THRESHOLDS................................ .27 

CONCLUSION................................................................................................................ 28 

-iii-
 

Introduction and Executive Summary 

General Electric Company (GE) submits the following comments on the 

Proposed Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units, 77 Fed. Reg. 22,392 (April 

13, 2012). GE is a diversified services, technology, and manufacturing company 

with a commitment to achieving customer success, innovation, and worldwide 

leadership in each of its businesses. GE operates in more than 100 countries 

and employs more than 300,000 people worldwide. 

The proposed rule would regulate products manufactured by GE, such as 

gas turbines, and services that it offers, such as methods for improving the 

efficiency of electricity generation. In addition, GE both invests in and operates 

power plants in the United States. 

GE supports EPA’s overall efforts to move the country towards more 

efficient power generation using natural gas and where it can meet appropriate 

standards, coal. GE manufactures products that are designed to meet stringent 

emissions standards and that are extremely efficient. We are able to deploy 

these products quickly to provide reliable power to the nation. Our detailed 

comments provide a series of recommendations aimed at promoting the 

proposed rule’s goals of efficient and reliable power generation, including the 

following: 

 EPA should promote use of natural gas-fired power, which is 

both efficient and reliable; 

 The standard should be set to allow natural gas combined cycle 

(NGCC) turbines to meet the standard during the full range of 

operating conditions and environments and to play a vital role in 

supporting deployment of renewable energy sources like wind 

and solar power; this standard should be no lower than 1,100 

lb/MWh based on a 12 month rolling sum; 

 EPA should maintain the proposed exclusion of simple cycle 

gas turbines for several reasons, including, among others, the 

critical role they play in delivery of electricity across the country; 

 EPA should recognize that integrated gasification combined 

cycle (IGCC) is a proven technology and that the carbon 

capture aspect of carbon capture and sequestration (CCS) is 

available now, but EPA should also provide flexible compliance 

periods to reduce uncertainties related to sequestration; 

 EPA should adopt a gross output standard over a net output 

standard. 

GE’s Products and Services Are Reliable and Promote Energy 

Efficiency: GE’s wide array of service and product offerings are designed to 

meet world demand for abundant, reliable, and efficient energy. GE’s power 
 

 

generation equipment is among the most environmentally clean equipment 

available in the marketplace. GE Energy manufactures gas turbines ranging in 

size from 5 MW up to some 300 MW. These clean-running combustion turbines 

are the most efficient means of generating electricity from fossil fuels 

commercially available. GE Energy provides solutions—from air-cooled heat 

exchangers to wind turbines—that address utilities’ and industrial facilities’ 

toughest challenges. In addition, GE conducts extensive research and 

development to produce technological advances in energy efficiency, reliability, 

and other key operational parameters. 

GE Energy is the only company in the world that develops and deploys a 

full portfolio of energy technologies and solutions to ensure efficient and reliable 

power generation, transmission, distribution, and utilization regardless of fuel 

choice and customer location. GE’s Power Generation business develops and 

deploys highly efficient power generation systems capable of meeting extremely 

aggressive environmental performance standards. These products include gas 

and steam turbines for multiple applications, generators, coal-powered IGCC 

systems with precombustion CO2 capture capability, reciprocating gas engines 

and aeroderivative gas turbines for natural gas and alternative fuels, wind, solar 

and nuclear power. 

With more than 100,000 employees in over 100 countries, GE Energy’s 

diverse portfolio of product and service solutions and deep industry expertise 

help customers solve their challenges locally. We serve the energy sector with 

technologies in such areas as natural gas, oil, coal and nuclear energy; wind, 

solar, biogas and water processing; energy management; and grid 

modernization. We also offer integrated solutions to serve energy- and waterintensive industries such as mining, metals, marine, petrochemical, food and 

beverage and unconventional fuels. 

GE Energy Financial Services (EFS) invests globally across the capital 

spectrum in essential, long-lived, and capital-intensive energy assets that meet 

the world’s energy needs. In the United States, GE EFS owns a controlling 

interest in five power plants (four natural gas-fired plants and one coal-fired 

plant), and has invested preferred equity, lease equity or debt in over 100 other 

power plants, including fossil-fuel-fired plants and renewable energy plants. 

Based in Stamford, Connecticut, GE EFS helps its customers and GE grow 

through new investments, strong partnerships and optimization of its $20 billion 

portfolio of energy assets. EFS has investment commitments totaling over $8 

billion in renewable energy projects, including wind, solar, hydroelectric, landfill 

gas, and other renewable energy technologies.1 

The Proposal Appropriately Recognizes the Importance of Gas But 

Also Must Provide a Role for Clean Coal: The proposed rule appropriately 

recognizes the increasing role that natural gas will play in the nation’s electricity 

1

 For more information on GE EFS, visit www.geenergyfinancialservices.com. 

Page 2 of 28 
production. Not only is natural gas a reliable, versatile, economical, and clean 

source of energy, but it is also in abundant supply, helping to assure long-term 

price stability. The full array of natural gas-fired generation technologies that 

exists also helps promote competitive price levels for power from all available 

fuels. The environmental benefits of gas, including lower greenhouse gas (GHG) 

and criteria pollutant emissions and reduced solid waste generation combined 

with the factors above, make it a natural selection for the next generation of 

power equipment installations. 

At the same time, it is important for EPA to recognize that coal remains an 

abundant natural resource, and it can be utilized in an environmentally 

acceptable manner. For example, GE has invested in bringing IGCC to 

commercial reality. IGCC is well suited to carbon capture as has been proven in 

19 commercial facilities that are using GE gasification technology to capture 

carbon generated from coal and petroleum coke. With respect to this rule, GE is 

ready to offer IGCC commercially at carbon capture efficiencies that will meet the 

proposed standard today. Cleaner coal technologies are being refined not only 

to reduce or store CO2 but also to use it beneficially. CO2 is being increasingly 

recognized as a valuable byproduct of fossil fuel consumption, and coal will serve 

as the primary source to obtain adequate supplies for carbon capture utilization 

and storage (CCUS). The primary application of CO2 utilization is enhanced oil 

recovery. This rule—if crafted to provide flexibility, certainty, and stability that 

permits the beneficial use of coal—can catalyze the continued development and 

deployment of CCUS. Coal can thus serve as an option for a diverse energy 

infrastructure that is tolerant to future upsets in supply and price fluctuations in 

both coal and gas. 

The Final Rule Must Provide Certainty to Allow for Investment in 

Cleaner Fuels and Technologies: Notwithstanding the benefits of lower 

emitting fuels and technologies, investment in new equipment by utilities requires 

a stable regulatory environment—one in which the regulations provide an 

achievable level of emissions control and are simultaneously not significantly 

vulnerable to legal challenge in the courts. The overarching objective of any CO2 

regulation must be the most efficient generation and use of energy while 

maintaining a stable regulatory framework such that market participants believe 

investments will result in a reasonable payback period and not risk the possibility 

of unknown control requirements at the time of investment. 

Accordingly, as EPA is considering its options for this rulemaking, the 

Agency should take into account the significant comments filed and try to 

accommodate the commenters’ concerns the extent to which doing so will 

prevent perpetuation of uncertainty. Indeed, increasing certainty is critical 

because uncertainty tends to limit investment in new technologies. Specifically, 

EPA should consider ways in which the rule can be written to minimize the risks 

of litigation while also meeting statutory requirements and promoting use of 

natural gas, consistent with current trends towards increased natural gas usage 

Page 3 of 28 
for power generation. Promoting certainty for the energy generating sector will 

assist EPA in achieving the proposal’s environmental objectives. By bolstering 

the legal analysis supporting this proposed standard, EPA will promote a rule that 

is more likely to be perceived by regulated entities as likely to survive legal 

challenge, thereby helping to foster investment in clean, efficient energy during 

an appeal period that could last several years. 

I.	 The Proposed Rule Appropriately Recognizes the Increased Role of 

Natural Gas in U.S. Electricity Production. 

The proposed rule correctly predicts that natural gas-fired electric 

generating units (EGUs) will be the “facilities of choice” for the foreseeable future 

due to the low cost of natural gas, the increase in domestic natural gas supplies, 

and the higher cost of coal-fired EGUs. Given recent discoveries of natural gas 

and new technologies to mine gas more efficiently, the U.S. possesses natural 

gas supplies sufficient to power electricity production, while continuing to serve 

manufacturing and residential needs. As illustrated in the figure below, for the 

past two decades, natural gas turbines have dominated capacity additions in 

U.S. electricity production. The abundance of natural gas in the U.S. and the 

availability of highly efficient, reliable, and operationally flexible natural gas-fired 

turbines will assure that natural gas-fired EGUs will be the predominant fossil fuel 

fired technology for the foreseeable future. 

In addition to making economic and energy sense, gas turbines are also a 

better environmental choice for electricity generation. They produce lower 

overall emissions of CO2, criteria pollutants, and hazardous air pollutants than 

other fuels. Compared to the coal-fired fleet, on average, natural gas-fired 

combined cycle generation results in a 50% reduction in CO2 emissions, about a 

Page 4 of 28 
 

 

 

 

 

65% reduction in NOx, and 99% less SOx for the same electricity output2 

Similarly, natural gas combined cycle generation does not produce the metals 

and other hazardous air pollutants associated with coal-fired generation. 

Moreover, the solid waste byproducts of coal-fired units are eliminated with 

natural gas firing. 

Natural gas and the wide array of technologies developed to put this 

resource to productive use will also help fulfill the President’s goal to ensure that 

by 2050, 80 percent of U.S. electricity will come from a diverse set of clean 

energy sources, including wind, solar, biomass, hydropower, nuclear, efficient 

natural gas, and clean coal.3 

II. Natural Gas Turbines Play a Vital Role in U.S. Electricity Production. 

Because natural gas turbine electricity production is versatile, dependable, 

economical, and clean, a wide array of technologies has been developed in this 

area. Gas turbines provide competitive output and efficiency when compared 

with coal and nuclear energy for both intermediate and base-load generation. As 

discussed further below, they also provide the additional benefit of affording 

significant operational flexibility to assure electric reliability and support for 

renewable generation. 

A. Natural gas turbines provide critical operational flexibility to 

today’s electricity generation and distribution systems, while 

allowing for more efficient response to demand fluctuations. 

Gas turbine technology plays an important role within the overall electricity 

generation and distribution system. Electricity demand in any region varies 

significantly each day and across the seasons. Typical electric demand peaks 

during the day when a majority of people and industries are most active and 

reaches a minimum at night. Seasonal peak power demands most commonly 

occur on hot days with increased air conditioning demand and on cold days in 

regions with significant electric heating. As a result, electricity generation must 

be modulated across the electrical supply grid to coincide with this variation in 

demand. While the highly variable daily and seasonal electrical demand may be 

generally predictable, contingencies and errors in prediction mean that 

operational flexibility and quick responses in production are essential. Such 

operational flexibility and rapid response can generally only be achieved with 

highly flexible gas turbines. As a result, gas turbines play a key role in 

maintaining grid reliability by providing a flexible power supply that can be reliably 

dispatched when power is needed quickly. 

2

 US EPA, “Clean Energy” web page, http://www.epa.gov/cleanenergy/energy-and-you/affect/airemissions.html. 3 See Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: 

Electric Utility Generating Units; Proposed Rule, 77 Fed. Reg. 22,392, 22,396 (Apr. 13, 2012). 

Page 5 of 28 
 

 

 

B. Natural gas turbines are uniquely able to support renewable 

generation. 

While the need for operational flexibility is already significant, it will grow 

significantly with the increased use of renewable energy. The use of nonhydroelectric renewable generation has increased considerably in many states 

over the past decade. To date, 30 states, plus the District of Columbia, have 

established Renewable Portfolio Standards (RPS) that require a minimum share 

of electrical generation to be produced from renewable generation. As a result of 

the increased deployment of renewable generation, the short term variability in 

the electrical supply has also increased. Renewable power, especially from wind 

and solar, will be expected to fluctuate hourly and even minute-to-minute with 

changes in wind speed, cloud cover, and other environmental factors. With this 

generation mix, electric supply must be available to quickly compensate for the 

combined variability of demand and fluctuation in the renewable supply. When 

this highly variable renewable energy supply is overlaid on existing alreadyvariable electric demand, the importance of increased operational flexibility for 

each electric generating unit on the grid becomes apparent. 

Gas turbine technology is uniquely capable of providing this operational 

flexibility, especially when compared to nuclear and coal-fired generation 

technologies. An electric supply grid composed of nuclear, coal, gas turbine and 

renewable technologies has traditionally relied on nuclear and coal plants to 

provide relatively steady base load power. The grid, however, will accept all 

available renewable energy from hydro, wind, or solar generation. Because the 

energy from these sources is variable, the grid operator fluctuates generation 

from gas turbine plants to match the variations in renewable generation supply 

and electrical demand. In response to the increased deployment of renewables, 

gas turbine installations are now required to start and stop more often and with 

greater speed in order to supply energy to the grid as quickly as possible to 

compensate for these rapidly changing loads. In this role, the flexible operating 

capability of gas turbines has become an increasingly critical attribute. This 

capability enables the increased deployment of renewables while maintaining 

safe and reliable grid operation. 

C. By facilitating the use of renewable generation, gas turbine 

technologies reduce system-wide emissions. 

Energy generation from renewable sources like wind and solar have zero 

emissions and very low variable cost of generation. However, if flexible 

generation assets, such as gas turbines, are not available, these renewable 

technologies will not be deployed. In other words, gas turbines are an essential 

component of renewable energy sources’ ability to penetrate the market. Failure 

of renewable energy source deployment will result in increased CO2 emissions. 

Any CO2 emission limitations that EPA establishes in this rulemaking, therefore, 

must consider the important role of gas turbine technologies in reducing systemPage 6 of 28 
 

wide emissions. Emission limitations that discourage the use of these 

technologies will adversely impact reliability, renewable deployment, and 

emissions. 

III. A Standard of No Less Than 1,100 lb/MWh Is Necessary to Account 

for Actual Operating Conditions and Site-to-Site Variations. 

EPA proposes a CO2 emission limit of 1,000 lb/MWh-hr4

 based on the 

operation of an efficient natural gas combined cycle plant, but requests 

comments on an emission range from 950 to 1,100 lb/MWh-hr.5 Although the 

proposed limit may be achievable by new NGCC units at optimum load under 

optimal operating conditions, it is unlikely to be achievable over the full range of 

operating conditions for the full life of a unit. Therefore, any standard issued 

must be set no lower than 1,100 lb/MWh on a 12-month rolling basis. Any lower 

standard would present technological challenges, particularly given partial load 

operation, degradation over time, startup and shutdown emissions, diversity of 

location, operating conditions and practices, and geographical and other factors. 

Moreover, to the extent utilities perceive compliance risk, they will be less likely 

to install new NGCC units, thus perpetuating the operation of existing higheremitting units.6 EPA should design its standard to meet the statutory 

requirements but also to encourage deployment and market penetration of loweremitting technologies. Otherwise, any emission benefits obtained by a tighter 

standard will likely be offset by the negative impact of reduced investment in new 

NGCC which would be unable to meet the standard. 

A. Section 111 of the Act requires EPA to take into account the 

expected operating performance in actual conditions over the 

life of the unit. 

While GE’s fleet of gas turbine products when newly installed in a 

combined cycle plant are capable of achieving the proposed emission limitation 

on a standard day in a newly installed (not-yet-degraded) condition (i.e., initial 

unit performance conditions at original installation prior to any performance 

degradation due to operating hours or startup and shutdown cycles), operating 

scenarios exist for which the combined cycle plant would not be able to achieve 

the 1,000 lb/MWh limit. Most notably, during periods of frequent startup and 

shutdown, periods of low load operation, and periods operated on a backup fuel, 

emissions can be expected to exceed 1,000 lb/MWh. Often plants do not 

operate consistently at peak load, such as units that are parked at low load 

overnight to reduce production during times of low demand. Many plants deploy 

supplemental firing (also referred to as duct firing) to boost steam turbine 

4

 77 Fed. Reg. at 22,436 (Proposed Rule 40 C.F.R. § 60.5520(a)). 5

 77 Fed. Reg. at 22,414. 

6

 The proposed emission limit is based on a 12-month rolling average and will encompass all 

potential operating scenarios including base load operation, start-up and shutdown, range of load 

operation, and frequent load fluctuation. 

Page 7 of 28 
 

 

generation during periods of peak demand. This supplemental firing to provide 

peak generation often reduces overall plant efficiency with a resulting increase in 

CO2 emissions per megawatt-hour. In addition, plants with water restrictions 

often must implement less efficient cooling technologies to reduce water 

consumption. These real life operating scenarios must be considered when 

establishing the emission limit. In addition, any standard must reflect the fact that 

a NGCC’s performance degrades over its useful life. 

As stated previously, operational flexibility is an essential attribute and 

requirement for gas turbine-based electrical generating installations. 

Unfortunately, the proposed emission level of 1,000 lb/MWh would have the 

unintended consequence of limiting operational flexibility essential to the 

continued reliable deployment of renewable electricity generation; this will result 

in additional electric generating units needing to be added to meet existing 

demand. When plant owner/operators bid on opportunities to provide power 

generation to grid operators, they must include min-load and max-load levels as 

well as other various cost components. When a plant owner/operator’s bid is 

successful, the grid operator will comply with the bid’s minimum and maximum 

load specifications. If the proposed 1,000 lb/MWh limit is promulgated, plant 

operators will need to bid a narrower range of load to ensure that compliance is 

maintained. As a result, additional capacity will need to be built or less efficient 

capacity will be used that is not subject to the rule because the more efficient 

capacity is not available due to load restrictions. The impact will be additional 

capacity, increased variable electricity cost, and higher total CO2 emissions. 

Moreover, a critical market for NGCC, supporting renewables will be lost 

because, at a 1,000 lb/MWh standard, the load restrictions that would be 

required will not be workable for NGCC to support renewable installations like 

wind and solar. 

Section 111(a)(1) defines the term “standard of performance” as: 

(1) The term “standard of performance” means a standard for 

emissions of air pollutants which reflects the degree of emission 

limitation achievable through the application of the best system of 

emission reduction which (taking into account the cost of achieving 

such reduction and any nonair quality health and environmental 

impact and energy requirements) the Administrator determines has 

been adequately demonstrated.

7 

Thus, NSPS must be “achievable” and “adequately demonstrated.” 

Unfortunately, the proposed standard is not achievable for NGCC when there is 

significant load fluctuation and several startup and shutdown events unless, as 

noted above, significant restrictions on the range of load operation and 

starts/stops are imposed. CO2 emissions during startup are higher because 

there are periods of fuel burn while no energy (MW) is being produced or where 

7

 42 U.S.C. § 7411(a)(1) (emphasis added). 

Page 8 of 28 
a relatively low level of energy is being dispatched to the grid. Start emissions 

are highly variable depending on the temperature of the equipment at the 

initiation of the start. As an example a plant that has shutdown overnight can 

start in generally less than an hour because the equipment is still warm from 

previous operation. If that same plant has been down for a week, a start may 

take upwards of 3 hours to allow the equipment to achieve full operating 

temperature without inducing significant thermal stresses to the equipment. For 

each plant start, the facility must operate for 3 to as much as 8 hours at baseload 

condition to ensure the average value for that operating period is below a 1,000 

lb/MWh limit. 

By setting the limit at the upper end of EPA’s proposed range, i.e., at 

1,100 lb/MWh, EPA will not only take into account the demonstrated achievable 

limitation for NGCC but will also increase the probability of overall CO2 reduction. 

EPA will further enable the development of zero-emission renewable yet variable 

energy sources like wind and solar power, since NGCC are utilized to support 

those applications. NGCC units supporting renewable energy generation service 

require an 1,100 lb/MWh limit, and if EPA finalizes a lower limit, the result that 

should be expected is that fewer renewable power units will be installed. 

In sum, if EPA appropriately takes into account the Section 111 factors, it 

will adopt a 1,100 lb/MWh limit. EPA must consider the overall impacts in its 

evaluation of the complete range of NSPS factors in determining the best system 

of emission reduction. 

B. EPA’s 5% allowance to address partial load situations is 

insufficient and not supported by the record. 

EPA’s efforts at addressing the partial load situation understate the 

impacts. The April 2012 Memorandum regarding Design Data for New 

Combined Cycle Facilities actually acknowledges that at below 80% load, the 

actual heat rate increases significantly and concludes that a 5% heat rate 

increase would be appropriate to account for part-load conditions: 

Operational load is one of the primary factors in the actual 

operating efficiency and CO2 emissions rate of a combined cycle 

power plant. Combined cycle power plants are most efficient when 

operating at full load. At 80 percent load, the actual heat rate only 

increases by approximately 1 percent relative to the design basis 

heat rate. However, below 80 percent load, the heat rate begins to 

increase at a more significant pace. At 60 percent load, the actual 

heat rate increases by approximately 10 percent above the design 

rate. Even though most combined cycle power plants are intended 

to operate at high loads, part-load operation is inevitable with 

Page 9 of 28 
 

 

variable demand. We selected a 5 percent heat rate increase 

relative to the design rate to account for part-load conditions.8 

The 5% allowance is simply insufficient to accommodate the operating realities of 

NGCC plants. 

EPA’s Design Data Memo outlines the methodology by which the 

proposed CO2 emission limit was derived based on NGCC. In evaluating the 

Design Data Memo, GE observes that a number of elements of the analysis 

clearly indicate that a 5% allowance is insufficient and that even the 10% 

efficiency lapse EPA discusses in the Design Data Memo may be insufficient to 

represent NGCC unit performance in real world operating environments over the 

life of a unit. 

The Design Data Memo states that a NGCC plant’s performance 

(efficiency) will lapse as much as 10% at part load and adjusts the values by 5% 

to account for the range of annual operation. New generations of the gas turbine 

fleet are designed to turn down farther in response to customer and electric grid 

demands. At these lower turn down rates, the performance lapse would be 

closer to 15% at those load points. The actual correction factor to account for 

part load operation is highly dependent on the operating requirements of the 

plant. The plant will operate in response to grid requirements, and accordingly 

the plant operator does not fully control the plant operational profile. To account 

for variable and unpredictable operating requirements, the rule should provide at 

least a 10% allowance as compared with the 5% EPA indicates is built into the 

proposed rule. 

While EPA adjusts its predicted emissions level by 1% for annual range of 

ambient temperatures, variation across ambient can be as much as 3% in very 

warm or very cold climates. While the 1% value may well be representative of an 

annual average for many locations, for others that experience consistent 

temperature extremes, it is likely too low.9

 In addition, the assumptions in the 

Design Data Memo for plant operational factors do not account for the range of 

variability to be expected. The annual emission rate must consider 

startup/shutdown, supplemental duct firing operation, and back-up fuel operation. 

While these parameters are difficult to quantify, they are real and must be 

considered in the evaluation of annual emissions. A separate 5% adjustment to 

account for these operational conditions is needed. 

The Design Data Memo also concludes that combined cycle plant 

efficiencies can be improved by installing more efficient HRSGs and that it is 

therefore reasonable to impose a 1,000 lb/MWh standard. While the Design 

8

 Memorandum from OAQPS to Docket, Design Data for New Combined Cycle Facilities, EPAHQ-OAR-2011-0660-0068 (Design Data Memo). 

9

 The assumptions of 5% for degradation, and 125 BTU/KWh for SCR/CO Catalyst are
 

reasonable. 

Page 10 of 28 
 

 

 

Data Memo is unclear on this point, it appears that this statement is intended to 

indicate a more efficient steam turbine bottoming cycle, which includes the steam 

generation by the HRSG, the steam turbine design, and condenser type. The 

Design Data Memo incorrectly concludes that such improvements are readily 

feasible for most or all plant designs and that “selection of combustion turbine 

engine designs would not be affected by this standard.”10 The bottoming cycle is 

matched to the gas turbine to optimize the overall cycle. While it is true that a 

triple pressure steam turbine with reheat will be significantly more efficient than a 

single pressure steam turbine with no reheat, it is not true that it would be 

relatively simple to install a more efficient steam turbine on many of the gas 

turbine plant designs. The Gas Turbine World performance values would 

typically include the highest efficiency bottoming cycle that is available for that 

specific turbine model but would not represent the range of expected designs. 

Certain gas turbine models simply do not have sufficient exhaust thermal energy 

to gain any advantage by installing a more complex steam turbine. Accordingly, 

higher efficiency steam turbine bottoming cycle would not be feasible. 

Further, using EPA’s calculation spread sheet and assumptions, EPA is 

correct that 90% of available NGCC designs can achieve the proposed emission 

limit. The problem is that if the assumptions are not sufficiently representative 

(as we explain above), the achievability of the limit is dramatically affected. 

Indeed, if the assumptions are adjusted by 2% to account for non-optimal site 

designs, such as the use of a lower water usage condenser technology, like an 

Air Cooled Condenser (ACC) in arid climates, then less than 50% of the new 

combined cycle designs would be able to satisfy the proposed standard of 1,000 

lbs/MWh. Moreover, when an additional 5% is included to account for starts, 

stops, duct firing, and other factors less than 35% of the turbines can meet the 

standard. 

This evaluation further bolsters GE’s recommendation that the emission 

limit should be increased to 1,100 lb/MWh and compels the conclusion that the 

1,000 lb/MWh proposed standard is not achievable or demonstrated as required 

under Section 111. It is at the 1,100 lb/MWh level (not the 1,000 level), that 

approximately 97% of new combined cycle designs would be able to achieve 

compliance in light of “real life” plantsite constraints and operational requirements 

(all of which the statute requires the Agency to consider in setting the emissions 

limit). Gas Turbine World supports this conclusion given that Gas Turbine World 

performance values represent the best a plant can achieve newly installed and 

without degradation.11 As discussed above, the Design Data Memo’s 

10 Id. 

11 Gas Turbine World data was used as the performance basis for the plants. For this discussion 

plant performance is specifically referring to plant efficiency. Plant efficiency, heat rate, and CO2 

emissions in lbs/MWh are proportional to one another. While these data are representative of 

achievable performance for NGCC facilities based on optimal performance configurations, many 

facilities have less favorable configurations. For example, the Gas Turbine World performance 

values are based on steam turbine condenser capabilities with once through cooling. The use of 

an air cooled condenser in place of once through cooling (or a cooling tower) significantly reduces 

Page 11 of 28 
 

 

supposition that the 1,000 lb/MWh level can be achieved through higher 

efficiency HRSGs is simply not true. In sum, to account for all of the above 

factors, the tolerance must be increased by 10% to account for site and design 

requirements in the final rule and the limit raised. 

C. Failure to establish an achievable standard will lead to higher 

overall GHG emissions. 

Even if this were a close call, which it is not, the Agency should strongly 

consider establishing a workable limit for these units because when they operate 

at baseload, they provide significant opportunity for emissions improvement as 

compared with other technologies. If the emission limits are not considered 

achievable, however, NGCC will not be installed and higher emitting plants will 

continue in operation. Section 111(a)(1) explicitly provides for the Administrator’s 

consideration of any nonair quality health and environmental impact and energy 

requirements in establishing a standard of performance and the environmental 

impact of relying on established, higher emitting generation is one that should be 

taken into consideration. 

D. If a 1,000 lb/MWh standard is issued, alternative compliance 

options or exemptions must be provided to satisfy section 

111’s requirements. 

If EPA implements the proposed 1,000 lb/MWh standard it must provide 

an alternative compliance option for periods in which plants operate at part-load 

conditions. For example, operations on loads of less than 50% of capacity 

should not be included in the compliance calculations. 

We note that historically, NGCC (along with nuclear and coal 

technologies) provided power to satisfy baseload demand, while simple cycle gas 

turbines provided the operational flexibility desired in the grid to counter 

variations in load forecasts and contingencies. In light of the increased 

development of renewables, however, NGCCs–with their preferable efficiency 

levels–are increasingly used for balancing renewables and providing flexibility. 

NGCCs also have become more flexible as a result, although a combined cycle 

is inherently not capable of maintaining the same extreme level of flexibility as a 

simple cycle gas turbine, both economically and operationally. EPA should 

therefore increase the limit for NGCCs or provide other appropriate alternative 

compliance options to encourage their use in this manner (with the CO2 reduction 

benefits they bring) while also adopting the simple cycle exemption as discussed 

in detail below. 

water usage in arid climates, at the tradeoff of approximately 1.5% percent degradation in site 

performance. This degradation varies with ambient and would be higher in hotter climates. 

Moreover, NGCC plants are moderately less efficient at higher altitudes. A plant installed in 

Denver (mile high) would have a performance lapse of approximately 0.5% compared to a plant 

located at sea level. 

Page 12 of 28 
 

 

IV. The Proposed Simple Cycle Combustion Turbine Exemption, Which 

Is Both Reasonable and Necessary to Ensure Reliability of the 

Electrical Grid, Must Be Maintained in the Final Rule. 

EPA recognizes that because simple cycle turbines do not recover waste 

heat, have frequent startup and shutdown, frequent partial load operation, high 

altitude operation, air (as compared with water) cooling, and degradation, simple 

cycle turbines cannot meet limits in the proposed range.12 Accordingly, EPA is 

not including these units under the proposed standards. It is worth noting that 

without such a provision, there would likely have to be several emission limits 

issued, geared to the different types, classes, and sizes of units as required by 

Section 111 to provide a standard that is adequately demonstrated, higher than 

1,100 lb/MWh, and some significantly higher than 1,100 lb/MWh. 

A. GE supports issuance of a specific simple cycle turbine 

definition and exemption. 

The proposed rule includes a specific exemption for simple cycle 

combustion turbines13 but seeks comment on whether that exemption should be 

maintained. The rule defines simple cycle combustion turbine as follows: 

Simple cycle combustion turbine means a stationary combustion 

turbine that which [sic] does not recover heat from the combustion 

turbine exhaust gases for purposes other than enhancing the 

performance of the combustion turbine itself.14 

Simple cycle combustion turbine installations must be excluded as EPA has 

proposed because, as discussed in detail below, the proposed emission limit is 

not achievable with adequately demonstrated technology given the operating 

modes required for such turbines. Even the most efficient simple cycle gas 

turbine, GE’s LMS100, is only capable of meeting the proposed limit in a newly 

installed and non-degraded condition and under optimal operating conditions. 

Requiring simple cycle gas turbines to meet the NGCC-based limits under 

normal operating conditions would inhibit their installation and could severely 

disrupt grid operation and electricity markets. Reduced use of simple cycle 

turbines could also lead to curtailment of renewable energy and increase net CO2 

emissions. Indeed, if simple cycle turbines were to be covered by this NSPS, a 

separate emission limit would need to be established to satisfy Section 111’s 

requirements for a standard that has been demonstrated to be achievable in 

practice. A 1,000 lb/MWhr (or GE’s recommended 1,100 lb/MWh) limit does not 

meet those statutory criteria. 

12 See 77 Fed. Reg. at 22,411, 22,431-32, 22,440. 

13 77 Fed. Reg. at 22,437 (Proposed 40 C.F.R. § 60.5520(d)). 14 77 Fed. Reg. 22,440 (Proposed 40 C.F.R. § 60.5580). 

Page 13 of 28 
 

Excluding simple cycle turbines is also consistent with the existing 

regulatory framework. Reciprocating engines (RICE) are currently regulated 

under NSPS Subparts IIII and JJJJ. Thus they do not fall under the regulatory 

framework being used for CO2 for gas turbines, and this would create an 

unintended consequence. 

B. Simple cycle gas turbines are an essential part of the power 

generation portfolio in that they provide: highly flexible power 

generation, the ability to manage contingencies in the 

electrical grid, and necessary backup power. 

Simple cycle gas turbine installations are an essential technology solution 

within the overall electrical generation portfolio. Simple cycle gas turbines have 

been used for renewable integration and ensuring grid reliability for several 

decades. These units are highly flexible and capable of: rapid starts and stops; 

multiple start and stop cycles per day; ramping up and down with load to 

maintain frequency of the electrical grid; providing voltage regulation service by 

participating in ancillary services; and providing electricity to the grid within a few 

minutes. In addition, these units can be installed in a much shorter timeframe 

than NGCC units to meet newly arising demand increases or replace plant 

retirements. 

Simple cycle plants operate under a different maintenance philosophy that 

is highly valued by operators of flexible units. Due to their enhanced flexibility, 

they are used to maintain grid frequency and voltage in addition to providing 

contingency power when there is loss of generating units. For these reasons, 

simple cycle gas turbines are widely used throughout the country to ensure 

reliability of the electrical grid. 

C. NGCC Installations, while flexible, cannot substitute for simple 

cycle. 

While NGCC installations are also capable of rapid start and deployment, 

they are not nearly as agile as simple cycle units. Because of the added 

complexity of the associated steam cycle, a combined cycle plant is unable to 

respond as quickly and flexibly as a simple cycle turbine. Further, while many 

simple cycle units are capable of multiple start and stop cycles per day, frequent 

start and stop cycles of NGCC facilities also induce significant thermal stress and 

associated operational cost and reliability tradeoffs which must be considered in 

the plant operation. 

Simple cycle gas turbines are critical to grid stability by supporting highly 

volatile, intra-day or minute-to-minute peaking scenarios, resulting from errors in 

forecasting, integration of an increased amount of zero emissions renewables, 

and unanticipated events resulting from loss in generation or load. In addition, 

these gas turbines are used to maintain the quality of electricity generation 

Page 14 of 28 
 

through voltage, frequency regulation, and backup generation which are used to 

meet stringent North American Electric Reliability Corporation (NERC) and 

Independent System Operator (ISO) guidelines. GE has continually invested in 

technology improvement to reduce the carbon footprint by achieving best-in-class 

efficiencies. Utilization of these simple cycle gas turbines enhances the reliability 

of the electric grid, promotes the integration of an increased amount of 

renewables, and reduces the total amount of CO2 emissions generated by the 

replacement of low efficiency assets with higher efficiency, natural gas burning 

gas turbines. 

The increased flexibility of simple cycle units in comparison with NGCC 

units is reflected in the operation of the power market. NGCC units typically bid 

in the previous day for generation on the following day, while simple cycle units 

can bid on the same day—a mere hour ahead of the demand. In contrast, it 

would be prohibitively expensive for traditional NGCC to bid on the same day. In 

short, NGCC plants are able to respond to grid variability demands, while simple 

cycle units can provide another layer of flexibility for rapid starts, stops, and grid 

fluctuations on a smaller scale than NGCC can provide. This means that any 

final rule needs to ensure that simple cycle turbines can continue to play the vital 

role they currently play in the power generation portfolio. 

In sum, both NGCC and simple cycle gas turbines are essential with 

simple cycle units being critical to provide grid stability and balancing power to 

enable the continued deployment of renewable electric generation. The best 

technology deployment at specific electric generating installations must be 

dictated by the electric grid requirements for that installation, not by regulatory 

limitations that could prove disruptive. 

D. The importance of maintaining the broad simple cycle 

exclusion from the rule is underscored by the fact that the 

proposed EGU definition exempting units that supply less than 

2,900 hours to the grid is insufficient to address simple cycle 

units. 

The proposed rule exempts any EGU that supplies less than one-third of its 

potential electric output capacity (2,900 hours) to the grid.15 EPA requests 

comment on whether this output requirement in the definition would make the 

simple cycle exemption unnecessary: 

The potential electric output requirement in the definition of electric 

generating unit would already exclude facilities with [a] permit 

restricting [sic] limiting operation to less than 1⁄3 of their potential 

electric output, approximately 2,900 hours of full load operation 

annually. The peaking season is generally considered to be less 

than 2,500 hours annually, and we are requesting comment on if 

15 77 Fed. Reg. at 22,439 (Proposed Electric generating unit definition at 40 C.F.R. § 60.5580). 

Page 15 of 28 
 

 

the capacity factor exemption is sufficient such that specifically 

exempting simple cycle turbine is unnecessary.16 

EPA justifies the simple cycle gas turbine exemption in part by stating that 

most simple cycle turbines operate in a peaking capacity and as a result would 

not generate power in excess of one-third of its potential electric output capacity 

(less than 2,900 hours in any year). While it is true that a majority of simple cycle 

turbines do not operate in excess of one-third of their annual capacity, there are 

likely to be specific installations and operating periods in which a plant would 

require the flexibility to operate for annual hours in excess of one-third of its 

potential electric output capacity. Simple cycle units are typically permitted for 

more hours than the expected operating scenario in order to address precisely 

those uncertainties for which they are installed. This may be especially true 

when simple cycle units are increasingly used to support renewable generation. 

As a result, it is likely that utilities will simply forgo ordering many simple cycle 

gas turbines because accepting a permit restriction of 2,900 hours would not fit 

with operational plans and cost needs. The final rule should include both the 

simple cycle definition and the specific simple cycle exemption in order to ensure 

that new simple cycle units can provide the needed operational flexibility. 

E. The proposed range of 950 to 1,100 lb/MWh does not reflect 

BSER for simple cycle turbines. 

As noted above, the simple cycle exemption is essential because of the 

critical role these units play in electric grid reliability. In addition, EPA faces 

significant legal constraints in defining simple cycle units as affected units. 

Section 111 of the Clean Air Act requires EPA to develop a “standard of 

performance” that reflects the degree of emission limitation achievable through 

the application of BSER, taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and energy requirements 

that the Administrator determines has been “adequately demonstrated”.17 In 

developing the standard, EPA reviewed several natural gas- and coal-fired 

technologies and controls, including NGCC, supercritical coal-fired boilers, and 

CCS.18 EPA did not evaluate, nor has it found that this proposed standard is 

adequately demonstrated by, simple cycle turbines.19 

16 77 Fed. Reg. at 22,431-32.
 17 Clean Air Act §111(a)(1) 18 77 Fed. Reg. at 22,417 -18. 19 One example of a unit that would be adversely affected is a unit being installed to meet 

anticipated electricity demand growth in Florida. GE EFS Shady Hills is developing a 400 MW
 

expansion project at adjacent to the Shady Hills power plant that will utilize two new GE 7FA.05
 

simple cycle combustion turbines. EFS Shady Hills was issued a PSD permit on April 6, 2012, 

and the company is in the process of applying to EPA Region IV for a GHG BACT determination. 

EFS Shady Hills expects to receive a GHG BACT determination by Q2 2013 or sooner, and could
 

potentially start construction on the expansion project as early as Q4 2013. 

Page 16 of 28 
 

 

Although the proposed standard may be achievable by some of the most 

efficient simple cycle turbines under optimum load and ISO conditions, a variety 

of real world operating factors make the standard unachievable. Simple cycle 

turbines critical role as peak and back up power units mean they often operate at 

reduced loads and are called upon to quickly ramp up and down production. 

Operation at reduced loads is less efficient for any unit. For example, while a full 

load can achieve 43 percent efficiency, operation at 50 percent load can reduce 

efficiency to 39 percent and increase carbon emissions by 10 percent. Similarly, 

load cycling can also lead to inefficiencies. The performance of simple cycle 

units is also decreased when they operate on backup oil during times when 

natural gas is unavailable. 

If EPA were to remove the simple cycle turbine exemption or impose an 

operating hour restriction, EPA would be required to establish a separate 

standard for simple cycle units that reflects day-to-day in-use performance of an 

array of simple cycle units. 

F. The simple cycle turbine exemption does not provide an 

incentive to install simple cycle in place of NGCC. 

The proposal also requests comment on whether the simple cycle 

exemption would provide a “perverse incentive” to build simple cycle units in lieu 

of NGCC: 

We are also requesting comment on whether the exemption would 

provide a perverse incentive to build less efficient simple cycle 

combustion turbines in order to avoid applicability with the 

proposed rule. While few existing simple cycle turbines presently 

generate greater than 1⁄3 of their potential electric output for sale, 

we are requesting comment on whether the exemption for simple 

cycle turbines would result in the greater use of simple cycle 

turbines for intermediate load applications when more efficient 

combined cycle facilities would have otherwise been built.20 

There is no reasonable basis to conclude that the exemption for simple 

cycle turbines would incentivize parties to install simple cycle turbines in place of 

NGCC. Grid demands and energy market needs will dictate the technology 

choice. There are a range of factors that influence specific gas turbine 

technology choice, including, but certainly not limited to, overall energy demand, 

demand load profile, demand variability (seasonal, daily, and instantaneous 

variability), renewable penetrations, fuel availability, transmission constraints, 

and siting constraints. NGCC units are more efficient and will remain the 

technology of choice for intermediate and base load applications. In contrast, 

simple cycle units used to support renewable and to provide needed operational 

flexibility to the grid will fulfill an important role that cannot be cost-effectively met 

20 77 Fed. Reg. at 22,432. 

Page 17 of 28 
 

 

 

 

with NGCC. As a result, a reasonable and achievable emission requirement for 

NGCC will not provide a disincentive for NGCC plant installation or an incentive 

for simple cycle installation.21 

G. The simple cycle exemption will not delay the installation of 

the heat recovery steam generator portion of NGCC. 

The proposed rule also seeks comment on whether exempting simple 

cycle units will encourage plant owners to delay installing the heat recovery 

generator to their NGCC units: 

In addition, it is our understanding that combined cycle facilities are 

sometimes built in stages with the combustion turbine engine 

installation occurring first and the heat recovery steam generator 

being installed in later years as electricity demand increases. We 

are requesting comment on whether the exemption would 

potentially delay the installation of the heat recovery steam 

generator portion of new combined cycle facilities.22 

The simple cycle exemption should not delay the installation of the heat recovery 

generator. The real value of NGCC is the fuel savings and efficiency realized 

when compared to electricity produced from simple cycle units. In the daily 

operation of electric generating plants, this is a sufficiently significant incentive to 

ensure use of NGCC whenever a fuel savings and higher efficiency can be 

realized in electricity production. Given the significant advantages of NGCC in 

saving fuel and lowering costs, the simple cycle exemption will not delay the 

installation of the heat recovery steam generator. This is especially true if EPA 

sets a appropriate emission level for NGCC units of 1,100 lbs/MWh that reflects 

the daily operational conditions of NGCC units. A tighter standard may have the 

perverse effect of encouraging greater use of simple cycle which would increase 

CO2 emissions overall. 

H. NGCC plants with a by-pass stack must not be subject to the 

standard when operated in simple cycle mode. 

The proposal defines simple cycle and combined cycle units but does not 

recognize that units may be installed with bypass stacks that are capable of 

operating in either simple or combined cycle mode. Operation in simple cycle 

mode may be dictated by electric generation demands for flexible power 

generation or to allow gas turbine operation during periods while the steam 

21 For today’s combined cycle with a bypass stack, simple cycle operation is much less 

economical to operate in steady state mode and facilities tend to operate in combined cycle mode 

with the simple cycle mode as an option for increased flexibility when demanded and increased 

reliability in the event the steam cycle is not available Permitting scenarios are unlikely to permit 

unlimited operation of a combined cycle unit in simple cycle mode (e.g., the same amount of fuel 

would be required to generate 120 MW in simple cycle mode that could generate 180 MW). 22 77 Fed. Reg. at 22,432. 

Page 18 of 28 
 

turbine bottoming cycle is unable to operate, such as during maintenance 

operations. Periods in which a plant with a bypass stack operates in simple cycle 

mode (when the gas turbine exhaust gas bypasses the heat recovery steam 

generator), must be treated as simple cycle operation and be exempt from the 

emission standard. EPA could implement this recommendation by amending the 

definition of “simple cycle turbine” as follows: 

Simple cycle combustion turbine means a stationary combustion 

turbine that which [sic] does not recover heat from the combustion 

turbine exhaust gases for purposes other than enhancing the 

performance of the combustion turbine itself. A combined cycle 

turbine shall be considered a simple cycle turbine when operating 

in simple cycle mode by bypassing the heat recovery steam 

generated through use of a bypass stack. 

V. While Carbon Capture Is Achievable Now, EPA Should Provide 

Flexible Compliance Periods to Reduce Uncertainties Related to 

Sequestration That May Prevent Investment and Technology 

Advancement. 

As carbon sequestration technologies are being developed, flexibility in 

the annual compliance period should be provided to assist units in dealing with 

fluctuations in market demand for CO2. The proposed rule provides a 30-year 

compliance period for sources which will utilize a CCS system. These units must 

meet an average of 1,800 lbs/MWh each year for the first ten years from 

issuance of the rule and an average of 600 lbs/MWh each year for the remaining 

20 years of the 30-year compliance period. The unit must meet 1,000 lbs/MWh 

over the 30-year averaging period.23

 Current CO2 sequestration and utilization technologies have an uneven 

demand that prevents a carbon capture plant from achieving a predictable 

schedule of geologic disposition of its captured carbon. For example, the CO2 

demand and capacity at enhanced oil recovery production facilities is likely to 

vary over the period of recovery operations. An oil field’s demand for CO2 from a 

dedicated CO2 capture plant will be highest during the early years of operation 

and fall off as CO2 emerges and the recycling of CO2 increases. Enhanced oil 

recovery operations also will typically alternate usage of water and CO2 to 

optimize recovery and CO2 storage capacity. Absent the option for an extended 

compliance averaging period, EGUs or combined heat and power (CHP) EGUs 

will not have flexibility to continue revenue-generating operation while remaining 

in compliance. 

Because of these practical, real world constraints, EPA should provide the 

option for flexible compliance periods that are: 

23 77 Fed. Reg. at 22,436 (Proposed Rule 40 C.F.R. § 60.5520(b)). 

Page 19 of 28 
 

 

1) based on multi-year commercial arrangements between the CO2 

producer and offtaker; and 

2) will meet the lb/MWhr emission standard over the contract period. 

For example, such approval should allow for an EGU to operate at a CO2 

emissions intensity lower than proposed 1,000 lb/MWh for an initial portion of the 

compliance period followed by potential periods of operation at an annual 

intensity that may exceed 1,000 lb/MWh. This would recognize the injection 

profiles for enhanced oil recovery projects that exhibit reduced demand as CO2 

recycling increases. For compliance/contractual periods that are less than 30 

years, an EGU would be required to enter into additional sequential CO2 offtake 

contracts. As new contractual obligations are entered into for the offtake of CO2, 

the compliance period will be extended until the end of the 30-year period is 

reached. 

VI. EPA Should Amend the Key Provisions of the Rule to Ensure that 

IGCC Can Be Used Under the Alternative Compliance Option. 

A. EPA should clarify the definition of integrated gasification 

combined cycle electric generating unit to include the heat 

recovery steam generator. 

The proposed rule defines an IGCC EGU as: 

Integrated gasification combined cycle electric utility means a An 

electric utility combined cycle gas turbine combined cycle that is 

designed to burn fuels containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the definition of natural gas. 

The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system construction 

or repair. No solid fuel is directly burned in the unit during 

operation.24 

This definition may be read to refer only to the gas turbine and not the integrated 

HRSG and steam turbine. Excluding the steam turbine’s power output from 

IGCC output calculations would reduce gross output of the unit by approximately 

35 percent resulting in an increased rate of CO2 emissions in lb/MWh without 

increasing actual CO2 emissions. This would result in artificially low efficiency 

numbers for IGCC gas turbines units that share a common steam turbine. The 

definition of IGCC should be corrected to read: 

Integrated gasification combined cycle electric utility means an 

electric utility combined cycle gas turbine combined cycle that is 

designed to burn fuels containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the definition of natural gas. 

24 77 Fed. Reg. at 22,440 (Proposed Rule 40 C.F.R. § 60.5580). 

Page 20 of 28 
The Administrator may waive the 50 percent solid-derived fuel 

requirement is waived during periods of the gasification system 

startup, construction, or repair and during periods when the 

transport and storage systems for captured CO2 are not available. 

No solid fuel is directly burned in the unit during operation. 

Gas turbines employed in IGCC plants have dual fuel capability. This means 

they are able to fire on either 100% coal-derived synthesis gas (syngas) or 

natural gas, or combinations thereof (co-firing) from 10% to 100% of either 

natural gas or syngas. With respect to startup, IGCC turbines require that only 

natural gas be used up to approximately 30% of full load before commencement 

of firing on syngas. This operational restriction is necessary to prevent damage 

from combustor flashback and flame-holding at the combustor head that can 

occur due to the hydrogen in syngas. 

The capability of IGCC turbines to use 100% natural gas also provides a 

unique ability for an IGCC plant to continue power generation in the event that 

disposition of its captured CO2 to either sequestration or enhanced oil recovery 

facilities is either significantly curtailed or interrupted. When operating on natural 

gas, the IGCC combined cycle is able to achieve the CO2 standard for 

conventional natural gas combined cycle units. Including this as an acceptable 

mode of operation in the rule will help to mitigate some of the risks of CCS that 

are external to the IGCC plant itself while assuring compliance with the rule's 

performance standard. 

The IGCC definition may also be read to refer to only one turbine. IGCC 

turbines, similar to NGCC units, are commonly configured to have multiple gas 

turbines sharing a common steam turbine. Under Subpart KKKK, emissions from 

multiple gas turbines sharing a common steam turbine are combined for 

compliance determinations. The proposed rule should contain a similar provision 

for IGCC and NGCC units. A section should be added to 40 C.F.R. § 60.5520 

stating: 

Multiple gas turbines with separate exhaust stacks sharing a 

common steam turbine shall determine compliance with the 

standard by measuring the combined emissions from their stacks, 

or fuel usage. 

B. EPA should also amend the applicability requirements for the 

alternative compliance option under proposed § 60.5520(b) to 

specifically allow IGCC units as they are defined in the rule to 

qualify. 

As currently drafted, the alternative 30-year compliance option under 

proposed § 60.5520(b) would make IGCC units, as proposed to be defined, 

ineligible for this alternative compliance option. IGCC is defined under proposed 

Page 21 of 28 
 

 

 

 

§ 60.5575 as a unit "designed to burn fuels containing 50 percent or more solid 

derived fuel not meeting the definition of natural gas." The preamble refers to 

IGCC as an option that may be used to meet the standard for the first ten years 

of the 30 year compliance period that use solid derived fuel or that burn natural 

gas along with coal and solid derived fuels.25 This statement, however, is not 

consistent with the provisions in the proposed rule governing the 30-year option. 

Specifically, the alternative compliance option provided under proposed 

§ 60.5520(b) would only allow IGCC utilizing CCS if the affected EGU uses “coal 

or petroleum coke for fuel and is designed to allow installation of a CCS system." 

As noted above, this applicability requirement conflicts with the definition 

of IGCC as a unit that is “designed to burn fuels containing 50 percent or more 

solid derived fuel not meeting the definition of natural gas.” As a result, many 

IGCC units that burn some natural gas or solid derived fuels would seem to be 

ineligible for the 30-year alternative compliance option. Proposed § 60.5520(b) 

should therefore be revised to allow IGCC units that burn solid derived fuel and 

allow for the use of up to 50 percent natural gas. 

VII. The Final Rule Should Include a Cumulative Rolling Sum That Will 

Accurately Represent Emissions and Proportionately Weigh Periods 

of High Emissions and Low Generation. 

The proposed rule requires sources to sum the hourly CO2 emissions for 

the operating month and divide by the total hourly gross energy output for that 

month. A more accurate representation of the CO2 emission performance of an 

EGU is calculated through a rolling 12 month sum that measures compliance at 

the end of each month by summing all emissions (lbs CO2 emitted) over the prior 

12 months, and dividing by the total generation (MWh) over the same period. 

This calculation method will provide a true representation of the annual 

performance of an EGU by appropriately weighting periods of lower generation 

output. 

As proposed, the monthly quotient is added to the previous 11 operating 

month quotients and divided by 12 to determine a 12 month rolling average.26 

This proposed calculation will weight each monthly average evenly and 

potentially result in significant distortions to the emissions performance of the 

EGU by giving disproportionate weight to high emission/low generation periods. 

For example, a plant may run for only 2 hours in a given month with a CO2 

emission level of 1200 lb/MWh CO2 and the following month run continuously 

each day for a total of 720 hours of operation and have an emission level of 950 

lb/MWh. Under the proposed rule, this would result in an inaccurate average of 

1075 lb/MWh for that 2 month period. If the average were calculated by adding 

the total lbs of CO2 and dividing by the total MWh over the two month period, the 

emission rate would be 951 lb/MWh. This value represents the true average of 

25 77 Fed. Reg. at 22,406. 26 77 Fed. Reg. at 22,438 (Proposed Rule 40 C.F.R. § 60.5540). 

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this operating period. The 12 monthly rolling CO2 average must be revised to be 

calculated based on the total CO2 emissions divided by the total MW-hrs of 

generation calculated on a monthly basis. 

VIII. A Gross Output Standard Should Be Adopted Over a Net Output 

Standard. 

EPA proposes the use of a gross output based emission standard, but 

solicits comments on a net output based standard. EPA should adopt a gross 

output standard over a net output standard for several reasons: With respect to 

reducing regulatory reporting burden, a net basis would be inconsistent with the 

gross output reporting requirements for CO2 under 40 C.F.R Part 75. Also, at 

this stage of CCS development preceding first-of-a-kind deployment of integrated 

carbon capture in coal plants, there are many candidate technologies and 

process configurations that will have varying net-to-gross output ratios. If it were 

to adopt a net output standard and not jeopardize the advancement of CCS, EPA 

would need to accommodate the various capture technologies, types of coal, 

types of coal plants and other environmental factors that determine net output. 

Given that there are no coal plants in operation with integrated carbon capture, 

there is no data to fully validate net-to-gross corrections or especially how these 

will change over time. 

Differences in basic technology and process configurations will require 

either a burdensome case-by-case determination of net-to-gross output 

corrections to derive appropriate net-based standard levels, or alternatively, 

identifying and segregating auxiliary loads between those that are, or are not, 

used to generate additional output or enhance performance. An example of the 

latter would be the apportionment of oxygen separation load to a Claus unit 

producing sulfur or sulfuric acid as a useful byproduct in an IGCC plant. Difficulty 

in apportionment will be compounded in cases where IGCC is configured as a 

poly-generation unit producing a saleable fuel or chemical product in addition to 

providing electrical output to the grid. Moreover, the gross methodology does not 

factor into the emissions rate added parasitic loads from emissions control 

retrofits. In addition to avoiding the complexity and cost of installing and 

maintaining remote power metering equipment, gross output is conveniently 

measured, monitored and consistent with reducing regulatory reporting burden. 

IX. Because Fuel Monitoring Meets Clean Air Act Compliance 

Requirements and Does Not Involve the Measurement Uncertainties 

and Costs of Continuous Emission Monitors, the Rule Should Adopt 

Fuel Sampling as an Independent Compliance Method. 

Proposed § 60.5540 provides two options for demonstrating compliance 

and determining excess emissions with the CO2 emissions limit. Under proposed 

§ 60.5540(a) a facility may use a CO2 continuous emissions monitoring system 

(CEMS) and under proposed § 60.5540(b), a facility may use “fuel sampling” to 

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demonstrate compliance using a monthly F factor and monthly fuel consumption. 

EPA seeks comment on whether the use of CO2 continue emission monitoring 

systems (CEMS) including stack gas flow rate monitoring should be required for 

all new affected facilities, including those burning exclusively natural gas and/or 

distillate oil.27 

The fuel sampling approach should be maintained as an option in the final 

rule. Fuel sampling is an accurate alternative to CEMs and should be adopted. 

In its Mandatory Reporting of Greenhouse Gases rulemaking, EPA found that 

CEMS were not required to provide sufficiently accurate data, stating that the rule 

provided a “relatively high degree of certainty” while also taking “advantage of 

existing practices at facilities.”28 Thus, not requiring CEMS for all units subject to 

this rule would be consistent with EPA’s practice under other regulations. 

Moreover, the determination of CO2 emissions through monitoring of fuel 

combustion and periodic fuel sampling is actually far superior to CEMS for 

several reasons. The calculation of CO2 emissions through the measurement of 

fuel consumption is far more accurate than corresponding measurements using a 

CEMs system because it measures fuel flow and assumes all carbon in the fuel 

is oxidized to CO2. The calculation of CO2 emissions is a stoichiometric 

calculation of each carbon entering the equipment in the fuel will be emitted from 

the stack as CO2. In addition, plant owners and operators have a strong 

incentive for accuracy in measuring fuel because plants are charged for fuel 

consumption. 

In contrast, with CEMs there are inherent calculation uncertainties, 

especially during periods of transient operation (i.e., starts, shutdowns, and rapid 

load changes). To develop an accurate mass emission rate estimate, CEMs 

must measure CO2 concentration and volumetric flow rate of the gas in the 

exhaust stack. Most commercially available CEMS systems generate data on a 

one-minute average basis, and under current EPA CEMS Performance 

Specifications, only one valid reading is required every fifteen minutes. Plant 

operational parameters, especially for NGCC plants, vary significantly within a 15 

minute, or even 1 minute period, data generated during these events will be 

highly suspect and could have significant, and unquantifiable, uncertainty. Use 

of CO2 CEMS also adds another monitoring system which results in additional 

cost and equipment to maintain and routinely certify. The measurement of CO2 

based on fuel flow is simpler and inherently more accurate because there are 

less sources of uncertainty. 

We also note that proposed § 60.5535(c) needs clarification. It reads: 

If you determine the your affected EGU’s CO2 mass emissions rate 

by monitoring fuel combusted in the affected EGU and periodic fuel 

27 77 Fed. Reg. 22,430. 28 Mandatory Reporting of Greenhouse Gases, Proposed Rule, 74 Fed. Reg. 16,448, 16,475 

(Apr. 9, 2010). 

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sampling as allowed under § 60.5525(c)(2), you must use the 

procedures specified in 40 CFR part 75, appendix G.29 

Although this section seems to allow fuel consumption monitoring, for authority it 

refers to § 60.5525(c)(2) which does not exist in the proposed rule. EPA should 

clarify this section of the rule to confirm that fuel consumption monitoring is an 

acceptable approach. 

X. EPA Should Adopt an Exemption for Combustion of Waste Fuels 

Such as Blast Furnace Gas and Refinery Fuel Gas. 

Included in the definition of “gaseous fuel” are refinery fuel gas, process 

gas, and coke oven gas.30 Given the extensive programs the agency has 

adopted to encourage the recovery of such gases and use for power generation, 

it would be inappropriate for EPA to subject these fuels to the requirements of 

this rule. EPA should adopt an exclusion for any process byproduct gases that 

are not produced for the purpose of electrical generation, including, but not 

limited to refinery fuel gas, process gas, blast furnace gas, landfill gas, and cokeoven gas. 

These “waste” gases are generated as part of industrial processes or from 

natural decomposition in landfills and, if not combusted for energy, would be 

alternately disposed of in some manner—most likely through flaring. The 

utilization of this same fuel in a gas turbine to generate electricity would result in 

the same CO2 emissions as alternate combustion but instead provides the 

benefit of utilizing this thermal capacity produce energy. Further, this generation 

would displace the need for other thermal electric generation resulting in a net 

reduction in CO2 emissions.31 

We note that process gases are commonly co-fired with natural gas. 

Installations in which there is not a sufficient supply of process gas, or, where the 

process gas alone does not have sufficient energy density. Alternately, a 

process gas may be fired in supplemental duct burners to enhance steam 

production. EPA could allow for the exemption of process gas during co-firing 

and provide for compliance demonstration through fuel sampling. Compliance of 

CO2 emissions during co-firing should be based solely on the natural gas usage 

and could be readily demonstrated through natural gas fuel consumption. As 

noted, such an approach would promote beneficial use of an otherwise waste 

fuel, consistent with historic EPA’s policies on waste fuels. 

29 77 Fed. Reg. at 22,437 (Proposed Rule 40 C.F.R. § 60.5535(c)). 30 77 Fed. Reg. at 22,439 (Proposed Rule § 60.5580). 31 Fuels specifically created from a process for the purpose of generating electricity, such as in 

the case of IGCC, would be included. 

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XI. EPA Should Provide for Compliance Calculated as an Average of All 

New Electric Generating Units at a Single Plant. 

GE recommends the emission limitation be applied as an average of all 

electric generating units at a single installation. The average emission limit 

across units would provide additional compliance flexibility. A unit average will 

also simplify the determination for combined cycle installations in which multiple 

gas turbines with their associated heat recovery boilers supply steam to a single 

steam turbine. For these installations, the total site electrical output would be the 

combined output from each gas turbine and the steam turbine. The limit must 

apply to the average of all gas turbine stacks to simplify the allocation of the 

steam turbine output in determining a per unit emission compliance value. 

XII. CHP Facilities Where Useful Thermal Output Accounts for 20 Percent 

of the Total Useful Output Should Be Excluded from This Rule. 

The proposed exemption of CHP units would recognize the environmental 

benefits of CHP. CHP units are environmentally beneficial and this exemption 

would encourage new units without adversely affecting CO2 emissions. CHP 

plants operate in a similar manner to the NGCC units. The thermal energy from 

CHP plants can be diverted to either energy production (kWh) or to thermal loads 

(heating and cooling). The regulatory challenge of quantifying the equivalence of 

the thermal energy used in terms of kWh to determine compliance with the 

proposed NSPS would be immense and impractical. Because of that complexity, 

CHP and cogeneration facilities should be exempt. 

XIII. The Pollution Control Project Exclusion Should Not Be Eliminated. 

EPA solicits comment on eliminating the pollution control project exclusion 

under the NSPS, 77 Fed. Reg. at 22,421, in light of a D.C. Circuit decision under 

the New Source Review/PSD programs, New York v. EPA, 413 F.3d 3, 40 (D.C. 

Cir. 2005). EPA should not eliminate this exclusion for NSPS purposes. As the 

Supreme Court has noted, the purposes of the NSPS and NSR/PSD programs 

are different from one another, Environmental Defense v. Duke Energy Corp., 

549 U.S. 561, 576-81 (2007), and the term modification can be defined differently 

in these programs. The exclusion ensures that changes that reduce emissions 

and provide significant environmental benefits are not discouraged because of a 

minor collateral increase in another pollutant. 

The New York case did not indicate that the Court there even considered 

the NSPS program and its purposes and no one challenged the exclusion in the 

Part 60 General Provisions or in numerous NSPS rules. Such challenges 

needed to be brought within 60 days from promulgation or from the date that new 

grounds arose. No one brought such a challenge and industry has relied on this 

exclusion for many years. Because this provision exclusion remains sound both 

from a policy and from a legal perspective. It should not be changed. 

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XIV. The Proposed Rule should be Revised to Include Language 

Clarifying that the Final Standard Included in this Rule for NGCC 

Does Not Apply to PSD Permits for Simple Cycle Units. 

NSPS standards are generally considered the “floor” for PSD permits. 

EPA should include language in the rule to ensure that the regional permitting 

authorities are not interpreting the standard as a limit for simple cycle turbines. 

The comments regarding simple cycle turbines have created ambiguity in the 

marketplace, leading to uncertainty about what standards will apply for simple 

cycle. EPA needs to state clearly that simple cycle turbines are excluded from 

this rule. 

XV. EPA Should Include Explicit Regulatory Language in Part 52 PSD 

Regulations to Clarify that Regulation of CO2 Under Section 111 

Triggers the Tailoring Rule GHG Emission Thresholds. 

The proposed rule regulates GHG for the first time under CAA § 111. 

Under EPA’s current interpretation of the CAA, this action triggers the 

applicability of PSD to GHG emissions and potentially cancels the increased 

GHG applicability thresholds enacted under the Tailoring Rule. PSD regulations 

define the term “major stationary source” as a “stationary source of air pollutants 

which emits, or has the potential to emit, 100 [or 250] tons per year or more of 

any regulated NSR pollutant.”32 The regulatory definition of NSR pollutant 

contains four triggers: 1) any pollutant or precursor with a NAAQS; 2) any 

pollutant subject to a standard promulgated under § 111; 3) any Class I or II 

substance under Title VI; and 4) any pollutant subject to regulation.

33 Only the 

fourth trigger incorporates the Tailoring Rule “subject to regulation” language 

raising the GHG threshold to 100,000/75,000 tpy of GHG. 

EPA believes that a statement included in the preamble to the Tailoring 

Rule extends the increased GHG thresholds to the § 111 trigger. This statement 

explains that the Tailoring Rule thresholds apply to all “major stationary 

source[s]” not just the fourth prong of the NSR pollutant definition.34 While EPA 

proposes to revise the NSPS regulations to confirm this interpretation, these 

regulations were not included in the proposed GHG NSPS standard.35 EPA 

advises states with approved GHG SIPs to take the position that their current SIP 

incorporates EPA’s Tailoring Rule interpretation. Just in case, EPA expects to 

proceed with a separate rulemaking to narrow approval of SIPs to exclude GHGs 

below the 100,000/75,000 tpy threshold.36 

32 40 C.F.R. 51.166(b)(1)(i)(a). 33 40 C.F.R. 51.666(b)(49). 34 77 Fed. Reg. at 22,429 (Citing Prevention of Significant Deterioration and Title V Greenhouse 

Gas Tailoring Rule; Final Rule, 75 Fed. Reg. 31,514, 31582 (Jun. 3, 2010)). 35 Id. at 22,429.

36 Id. 

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To remove any legal uncertainty regarding the application of the Tailoring 

Rule, EPA should include regulatory language in the Part 52 PSD regulations 

that the Tailoring Rule thresholds apply to the regulation of CO2 triggered by 

CAA § 111. 

CONCLUSION 

GE appreciates the opportunity to provide these comments and seeks to 

work with the Agency to achieve a final rule that promotes efficient electric 

generation using advanced technologies that meet the full range of the country’s 

electric generation needs. Please contact Larry Boggs at larry.boggs@ge.com 

or 202.637.4126 with any questions regarding these comments. 

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