From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> 

Sent: Thursday, July 30, 2015 3:38 PM 

To: Vasu, Amy; Culligan, Kevin; Harvey, Reid 

Cc: Frey, Nathan J.; Grossman, Andrea 

Subject: RE: Summary of Interagency Comments under EO 12866 and EO 13563 on the GHG 

Mitigation TSD BB2 Chapter 

Attached please find a summary of interagency comments under EO 12866 and 13563 on the 

GHG Mitigation TSD BB2 chapter. 

 

Thank you and please let me know if you have any questions. 

Aaron L. Szabo 

Policy Analyst 

Office of Management and Budget 

202-395-3621 

Aaron_L_Szabo@omb.eop.gov 

<< Summary of Interagency Comments Under_EO12866_EO13563_GHG Mitigation 

TSD....docx >> 
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Chapter 3: CO2 Reduction Potential from Generation Shifts Among Existing 

Units 

Overview 

This chapter explores the dynamics of power sector dispatch and the cost-effectiveness of 

lowering the carbon dioxide (CO2) emissions intensity of the power sector by substituting 

generation from the most carbon-intensive existing EGUs and increasing utilization, to the extent 

possible, of less carbon-intensive existing fossil fuel-fired EGUs. More specifically, the 

examination focuses on opportunities to improve emissions intensity by increasing the utilization 

of existing natural gas combined cycle units. The TSD provides background on existing power 

plants, power system operation, and the economics of electricity production and delivery in the 

context of cost-effective CO2 emission reduction opportunities. 

Introduction 

Electric system dispatch is typically defined as “the operation of generation facilities to 

produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits 

of generation and transmission facilities.”1

 Electricity demand varies across geography and time 

in response to numerous conditions, such that electricity generators are constantly responding to 

changes to meet demand in the most reliable and cost-effective manner possible. 

The nation’s EGUs are connected by transmission grids that extend over large regions. 

Through these interconnections, EGU balancing authorities treat the product (i.e., electricity) of 

EGUs as fungible, calling for electricity generation supply to meet demand usually by deploying 

the least expensive power source first, subject to the constraints of reliable system operation.2

 

EGU operators and balancing authorities must take into account several constraints in 

dispatch, including transmission and other operating constraints as well as emission control 

programs and other environmental requirements. Such programs and requirements can change 

the relative cost of generating electricity among plants and/or limit the number of hours that a 

plant can run. For many years, EGU operators throughout the country have considered the 

                                                            

1

 Energy Policy Act of 2005 

2

 A balancing authority is the responsible entity that integrates resource plans ahead of time, maintains the balance 

between supply, demand, and generation within a balancing authority area, and supports interconnection frequency 

in real-time. http://www.nerc.com/files/glossary_of_terms.pdf 

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emissions implications for pollutants such as SO2 and NOx when scheduling unit dispatch, in 

response to costs and regulatory requirements. For example, EGU operators in 10 states 

participating in the Regional Greenhouse Gas Initiative have several years of experience with 

factoring CO2 emissions limits directly into bids for economic dispatch. The electric system’s 

carbon intensity can be lowered by shifting generation among existing EGUs, particularly by 

shifting generation from coal-fired units to natural gas combined cycle (NGCC) units. 

Power Sector Background 

Electric Dispatch 

The operation of electricity generation accords to the principle of security-constrained 

economic dispatch, which is “the operation of generation facilities to produce energy at the 

lowest cost to reliably serve consumers, recognizing any operational limits of generation and 

transmission facilities.”3

 The cost of operating electric generators varies based on a number of 

factors, such as fuel used and generator efficiency. In many regions of the country, Regional 

Transmission Organizations (RTOs) and Independent System Operators (ISOs) help coordinate 

economic dispatch over large areas to help keep the cost of meeting electricity demand as low as 

possible, subject to operational constraints. 

The decision by balancing authorities to call upon, or dispatch, any particular generating 

unit is generally driven by the relative operating cost, or marginal cost, of generating electricity 

to meet the last increment of electricity demand. These costs change over time depending upon a 

variety of factors like fuel prices, weather conditions, and overall demand levels. Since the fixed 

cost of power plants is a sunk cost, plant operators usually bid into electricity markets such that 

their variable costs are covered. For fossil fuel-fired electric generating units, variable costs are 

dominated by the cost of the fuel, although coal-fired units often also have considerable variable 

costs associated with running pollution controls.4

 Other generating technologies, like 

renewables, hydroelectric, and nuclear, have little or no variable costs and are generally 

dispatched to the extent possible. Under economic distpatch, the units with the lowest variable 

                                                            

3

 Federal Energy Regulatory Commission, 2005. Economic Dispatch: Concepts, Practices, and Issues 

4

 In addition to fuel costs, variable costs also include costs associated with operation and maintenance, and costs of 

operating a pollution control and/or the price of allowances to emit certain pollutants. 

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costs will be called upon first, then other units (with higher variable costs) will be called upon 

sequentially, such that total system demand is met. The merit order in which units are dispatched 

to meet demand, at any particular point in time, is commonly called a dispatch or supply

“curve.”5 

Balancing Authorities 

In states with cost-of-service regulation of vertically-integrated utilities who own 

generation, transmission, and distribution infrastructure, the utilities themselves are often also the 

balancing authorities who determine unit dispatch. Such utilities are presumed to dispatch their 

units in a cost-minimizing fashion (seeking the lowest cost), and they can arrange to buy and sell 

power with other balancing authorities. 

In states that have restructured regulation to allow for competition between generators, 

RTOs and ISOs are generally responsible for moving electricity across larger areas in the most 

efficient (least-cost) manner possible.6

 RTOs and ISOs coordinate, control, and monitor the 

operation of the electric power system to ensure cost-effective and reliable delivery of power, 

and they are independent from market participants. ISOs grew out of the Federal Energy 

Regulatory Commission (FERC) requirements for existing power pools to satisfy the 

requirement of providing non-discriminatory access to transmission. Subsequently, FERC 

encouraged the voluntary formation of RTOs to administer the transmission grid on a regional 

basis throughout North America (including Canada). 

RTOs and ISOs administer wholesale power markets, which match the generation of 

electricity with the purchase of electricity (and ancillary services) prior to delivery to end-users. 

Companies that provide retail electricity (e.g., utilities and energy service companies) procure 

power through these wholesale electricity markets. 

State Public Utility Commissions (PUCs)7

Each state has a governing body that is tasked with regulating retail electricity rates and 

electric services to protect the public interest, ensure efficient and reliable delivery of electricity, 

                                                            

5

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

6

 http://www.ferc.gov/industries/electric/indus-act/rto.asp 7

 These entities are sometimes called Utilities Commissions, Utility Regulatory Commissions, or Public Service 

Commissions.

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and plan appropriately for the short and long term energy needs of the state and consumers. 

Depending on market structure, PUCs also allocate costs among customers, design price 

structures and set price levels, set service quality standards, approve capital expenditure by 

utilities, and arbitrate disputes among relevant parties and stakeholders. In restructured markets, 

the PUC’s authority is generally applicable to the transmission and distribution system, since the 

revenues from generation (and sometimes capacity) are earned through markets governed by 

RTOs and ISOs. In cost-of-service states, the PUC also has oversight of the generation and 

capacity planning components. 

Wholesale Power Markets 

RTOs and ISOs operate spot markets for wholesale power supply and demand for their 

designated area, including both day-ahead and real-time markets (using hourly or shorter time 

periods). These markets are based on bids for supply and demand and operate according to rules 

established by FERC. The RTOs and ISOs use these markets for balancing power supply and 

load in their area and typically serve as the balancing authority for the same area. 

For areas not administered by RTOs and ISOs, dispatch is scheduled on both a day-ahead 

and an hourly basis, but it is typically driven by the power supply costs and schedules of 

traditional utilities. This dispatch will depend to a certain degree on spot markets for power, 

since utilities will dispatch purchased power from other suppliers when that power can be 

obtained at a cost savings. There is an active wholesale market for this power in the spot market, 

from individual sales and from exchanges. These markets typically sell power on a day-ahead 

basis rather than on an hourly basis, and they can also sell power for longer periods of time, such 

as weekly or monthly. However, the actual dispatch and balancing of power is conducted by the 

utility based on its own scheduling, and purchasing protocols and varies considerably from one 

utility to the next. 

Reliability 

As a balancing authority, the ISO/RTO or utility will balance demand, generation, and 

imports/exports in real time while ensuring that the next hour’s demand, or load, is met. As this 

happens, the electric power system is constantly monitored and load is dispatched to ensure 

reliability limits are met, voltage levels are appropriate, system frequency is maintained and 

appropriate corrective action is taken when needed. 

Deleted: generation and dispatch component is 

Commented [A1]: What does this mean?

Deleted: maintaining system frequency and

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As reliability coordinators, balancing authorities are responsible for the reliable operation 

of the bulk power system. The bulk power system refers to a large interconnected electrical 

system made up of generation and transmission facilities and their control systems. To ensure 

reliability, system operators continuously analyze real-time and forecasted load and transmission 

conditions to ensure that scheduled generation dispatch can meet load without adverse impacts. 

If the scheduled dispatch is not feasible within the limits of the transmission system, it must be 

adjusted by the system operator. The North American Electric Reliability Corporation (NERC) 

develops and enforces the procedures to ensure reliability, in accordance with Federal laws and 

regulations, and with FERC oversight.8

 

Generation Shifting: Technical Potential 

In 2012, nationwide average CO2 emission rates9 across the following technology types 

on a net generation basis were: 

 Coal Steam: 2,217 lbs/MWh 

 Oil/Gas (O/G) Steam: 1,435 lbs/MWh 

 NGCC: 905 lbs/MWh 

Coal- and oil/gas-fired boilers are considerably higher-emitting sources than NGCCs, on 

average. Therefore, shifting generation from the average existing fossil fuel-fired boiler to an 

average existing NGCC will result in notable CO2 emission reductions. 

The lower emission rate of NGCC conveys the potential of generation shifting to reduce 

GHG emissions. However, the actual potential to realize emission reductions through this 

technology depends on the availability and capacity factors of the existing NGCC fleet. In order 

to shift generation from existing fossil fuel-fired boilers to existing NGCC, there needs to be 

some existing unused generation potential in the current NGCC fleet that could replace 

generation from more CO2-intensive generating resources. 

                                                            

8

 http://www.nerc.com/ 

9

 Emission rates in this document are shown on a net generation basis and reflect Hawaii and Alaska sources, as well 

as units that commenced construction in 2012. See “2012 unit-level data using the eGrid methodology” file 

provided in the docket 

Deleted: electric

Deleted: electric

Commented [A2]: Right?
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Given their cost structure, for purposes of economic dispatch, most NGCCs have 

historically operated as base load or intermediate load10 due to their high efficiency and 

flexibility of operation, with national average annual capacity factors in the range of 40-50%.11,12 

However, NGCCs are designed for, and are demonstrably capable of, reliable and efficient 

operation at much higher annual capacity factors, as shown in observed historical data for 

particular units and their design and engineering specifications. 

The capability of NGCCs to operate is indicated, in part, by data on the average 

availability factor of NGCCs. 13 The term “availability” is a common engineering term used in 

the power sector that reflects the percentage of period hours that a plant is available to produce 

electricity (a period being 1 year, or 8,784 hours in 2012 since that year included a leap day). 

The unavailable period is generally attributable to scheduled maintenance, unplanned 

maintenance, and unplanned outages. For modeling purposes, the EPA assumes that NGCC has 

an availability of 87%.14 Other reports suggest that NGCC availability factors may reach as high 

as 92%.15,16 Many modern NGCCs have demonstrated availability factors of over 95%. 

According to one NGCC manufacturer, these highly efficient units already represent over 15 

percent of total installed capacity nationwide, including all electric generating sources (as of 

2010).17 These high-efficiency and high-availability NGCC units were first introduced around 

1995 and have consistently reported availability factors of 90 to 92 percent to NERC.18 These 

availability factors are substantially above the 2012 NGCC generation level, indicating that there 

is a significant potential for increasing generation from unutilized existing NGCC capacity. 

                                                            

10 Unlike baseload power, intermediate load is cycled to follow the changing demand for electricity, but it is not

cycled as often as peaking supply which operates on much shorter timescales. 11 EIA, Today In Energy, January 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data) 12 EIA, Electric Power Annual 2009, http://www.eia.gov/electricity/annual/archive/03482009.pdf (Table 5-2 for 

2009 and earlier data) 

13 NERC, 2008-2012 Generating Unit Statistical Brochure – All Units Reporting, 

http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx

14 See Chapter 3, Table 3-18 at http://www.epa.gov/powersectormodeling/BaseCasev513.html 

15 http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html 

16 Power Engineering, Negotiating Availability Guarantees for Gas Turbine Plants, 03/01/2001, http://www.powereng.com/articles/print/volume-105/issue-3/features/negotiating-availability-guarantees-for-gas-turbine-plants.html

17 http://site.ge-energy.com/corporate/network/downloads/7FA_Evolution.pdf 

18 GE Power Systems submitted to U.S. Department of Energy, 2000. Utility Advanced Turbine Systems 

Technology Readiness Testing Phase 3 Restructured. DOE Cooperative Agreement No. DE-FC21-95MC31176—

30. 

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To evaluate potential opportunities for shifting generation to unused NGCC capacity, the 

EPA reviewed recent operating data across all NGCCs to determine NGCC capacity factors in 

2012. For GHG abatement purposes, generation shifting would require one net MWh of 

generation from a lower-emitting technology operating in place of one net MWh of generation 

from a higher-emitting technology. Therefore, the EPA calculated capacity factors as the ratio of 

a unit’s reported net generation to its potential net generation, the latter of which is determined 

by the unit’s net generating capacity. Net generating capacity reflects a reduction from nameplate 

capacity due to on-site electricity use (e.g., station service or auxiliaries) and local temperature 

conditions. The EPA used the net summer capacity reported for units in the EIA Form 860 

because it controls for local conditions and is thus a consistent metric for evaluating dependable 

capacity nationwide. Potential net generation was calculated as the net summer generation 

capacity of a unit multiplied by the number of hours in a year. Therefore, the equation for 

calculating capacity factors is: 

Reported generation in 2012

ሺNet summer capacityሻ x (hours in 2012)

This calculation of capacity factor provides an indication of how much net generation a 

unit is providing as a percent of its total net generating capacity. The capacity factor refers to the 

actual utilization of that source on an annual basis, while that source’s availability refers to its 

potential maximum utilization level. The EPA surveyed 2012 data for 439 NGCC plants and 

observed that the NGCC fleet had an average capacity factor of 46% in 2012.19 Since the fleetwide capacity factor in 2012 was less than the technical generation potential available for the 

technology, the historical data suggests that there is a significant potential for shifting generation 

from higher CO2 emitting resources to lower CO2 emitting NGCC generation. 

Availability for NGCC fleet ......................................... 87% to 92% 

2012 Capacity Factor for NGCC fleet ...................................... 46% 

                                                            

19 EIA 860 and 923. 
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To quantify the GHG reduction potential from generation shifting, the EPA considered 

alternative capacity factor levels at which the NGCC fleet could be dispatched. Although the 

availability for NGCC units is assumed to be 87% to 92%, the EPA did not assume that the 

NGCC fleet could collectively operate at this level on an annual basis. To determine a reasonable 

average capacity factor for the NGCC fleet as part of BSER, the EPA considered historical data 

and modeling projections describing NGCC characteristics and operating behavior. 

As seen in Table 3-1, the existing NGCC fleet is relatively young. More than 80% of the 

capacity has come online in the last 15 years.20 Of this capacity, almost all are highly efficient 

NGCCs that are able to achieve high availability factors. 

Table 3-1: Existing NGCC Capacity, by Age21

Online Year Capacity 

(Name Plate Capacity – MW) 

Percentage of 

Total Existing NGCC 

Fleet 

Pre 1950 103 0% 

1950-1959 1,769 0.7% 

1960-1969 3,087 1.3% 

1970-1979 6,909 2.8% 

1980-1989 7,658 3.1% 

1990-1999 28,467 11.7% 

2000-2009 174,947 71.7% 

2010+ 21,068 8.6% 

Total 244,008 100% 

Of 439 NGCC plants generating in 2012, the EPA observed that 67 plants (more than 

15% of NGCC plants) had a capacity factor of 75% or greater (see Figures 3-1 and 3-2).22 

                                                            

20 See the National Electricity Energy Data Systems (NEEDS) file at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html 

21 See “Operable” worksheet in “GeneratorY2012” Workbook in 2012 Zip file at 

http://www.eia.gov/electricity/data/eia860/ 

22 See “2012 unit-level data using the eGrid methodology” file provided in the docket 
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Figure 3-1: NGCC Plant Distribution by Capacity Factors (2012) 

Source: EIA forms 860, 923 (2012), Combined Cycle Steam Part (CA) and Combined Cycle 

Combustion Turbine Part (CT) prime mover categories 

 

Table 3-2: Plant Distribution of Existing NGCCs (2012) 

Capacity Factor 

(net summer) 

# of NGCC 

plants 

% of NGCC 

Plants 

Less than 5% 32 7.3% 

5%-9% 23 5.2% 

10%-14% 17 3.9% 

15%-19% 23 5.2% 

20%-24% 22 5.0% 

25%-29% 13 3.0% 

30%-34% 21 4.8% 

35%-39% 23 5.2% 

40%-44% 26 5.9% 

45%-49% 25 5.7% 

50%-54% 29 6.6% 

55%-59% 30 6.8% 

60%-64% 27 6.2% 

65%-69% 38 8.7% 

0

5

10

15

20

25

30

35

40

Number of NGCC Plants

2012 Capacity Factor
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70%-74% 23 5.2% 

75%-79% 30 6.8% 

80-84% 19 4.3% 

85-89% 7 1.6% 

Greater than 90% 11 2.5% 

In 2012, more than 15% of NGCC plants operated at an annual capacity factor of 75% or 

higher on a net summer basis. This subset of NGCCs was largely dispatched to provide base load 

power. While only 15% of plants operated at 75% or higher capacity factor on an annual basis, 

the fleet of NGCC units was relied upon heavily during certain periods of time, in response to 

higher demand. On a seasonal basis, a significant number of units achieved capacity factors 

greater than 50%, and even up to 80%. During periods where demand levels are typically lower, 

some NGCCs were idled or operated at lower capacity factors. Nonetheless, a notable number of 

existing NGCCs have demonstrated the ability to achieve a 75% or higher capacity factor for 

extended periods of time. These units achieved high capacity factors without adverse effects on 

the electric system. 

Hourly data reported to EPA23, particularly from the peak summer months of July and 

August, also show that most individual NGCC units can operate at high capacity factors. 

Capacity factors from the hourly unit level data reported to EPA are based on heat input and 

input capacity; these calculations correspond closely to the capacity factor calculations described 

above (that are based on data reported to EIA representing longer periods of time) and enable 

consideration of capacity factors at the unit and hourly level. Using EIA and EPA data from 

2012 for the same facilities, capacity factor averages from EIA nameplate values and EPA unit 

level data from 2012 data are both 46%, while net summer capacity factors from EIA are 52%.24 

On average, then, net capacity factors are approximately 5% or more above nameplate capacity 

factors. Analysis of these hourly data demonstrates several important points about the feasibility 

of running NGCC units at capacity factors above 70% nameplate – or 75% net summer – levels. 

To examine historical potential capacity factors for NGCC units, EPA calculated nameplate 

capacity factors for daily peak operation from 7 AM to 7 PM during the months of July and 

August, a sustained period that demonstrates both the ability of individual units to operate at high 

                                                            

23 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 24 The EPA Air Markets data is unit level data from 411 facilities; EIA data surveys are from 439 facilities.  
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capacity factors and of the power grid to support regional operation of the NGCC fleet at much 

higher levels than current averages. This analysis shows the following key points: 

 Most individual units are capable of high levels of operation: 88% of NGCC 

units operated at a nameplate capacity factor of 70% or above for at least one day 

in July and August of 2012; 67% operated at 80% or above for at least one day. 

 The interconnected power grids can support region-wide NGCC operation at 

much higher than average capacity factors. Each NERC region operated at a 

nameplate capacity 70% or above for at least one day, as shown below: 

o ERCOT 75% 

o WECC 74% 

o Eastern Interconnection Regions 

 RFC 75% 

 MRO 76% 

 SERC 73% 

 FRCC 75% 

 SPP 71% 

 NPCC 70% 

These observations demonstrate the technical ability to operate existing NGCC capacity 

at or above a 70% nameplate capacity factor, and therefore at least at a 75% net summer capacity 

factor or higher. 

Historical Trend 

Over the last several years, advances in the production of natural gas have helped reduce 

natural gas prices and improved the competitive position of gas-fired units relative to coal-fired 

units. As a result, operators have shifted significant quantities of generation from coal units to 

NGCCs, absent any federal CO2 requirements. 2012 net generation from NGCC units grew to 

966 TWh, up from 783 TWh in 2011 (23% growth in one year).25 

An analysis of historical generation across the fleet of coal and NGCC units for 2011 and 

2012 provides some implicit measures of the cost dynamics between the two technologies. For 

                                                            

25 EIA Form 860, 923 (2011)

Commented [A3]: I would also note that this demonstrates that

the NG transmission system can handle this level of NGCC

generation.
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example, one is able to look at the change in the prices of coal and gas to gauge the relative costs 

of generating for each technology. While there are wide-ranging costs at the unit level, an 

aggregated assessment of the relative economics is informative and can provide a metric for 

assessing the implications of this generation pattern as it relates to emissions of CO2. 

The potential for shifting generation from CO2 intensive sources to less CO2 intensive 

sources is evidenced in historical data. EIA form 860 and 923 data demonstrate an increase in 

NGCC generation and fuel use between 2011 and 2012 of more than 20% (even though the 

NGCC fleet capacity rose by just 3%). As NGCC generation rose by approximately 183 TWh, 

coal generation fell by approximately 217 TWh. The significant shift from coal to gas generation 

over just a one year period demonstrates the ability for a quick shift in generation patterns in 

response to market or economic drivers. 

The increase in NGCC utilization was in large part driven by a decrease in natural gas 

prices (see Table 3-3). Electric power sector delivered natural gas prices averaged $4.89/Mcf in 

2011 and $3.54/Mcf in 2012.26 This price decline of $1.35/TCF created an additional incentive 

for decreasing coal generation and increasing NGCC generation relative to 2011 electricity 

production economics. This historical data also shows a sharp increase in the NGCC fleet’s net 

summer capacity factor from approximately 40% on average in 2011 to approximately 46% on 

average in 2012. 

The historical trend of shifting generation to NGCC is expected to continue, as dry 

natural gas production is expected to grow as much as 23% by 2022 relative to its 2012 level.27

Table 3-3: 2011 and 2012 Gas and Coal Generation28

Year 

NGCC Net 

Summer 

Capacity 

(GW) 

NGCC Net 

Generation 

(TWh) 

NGCC 

Capacity 

Factor 

Electric 

Power 

Sector 

Natural Gas 

Price 

($/TCF) 

Coal Net 

Generation 

(TWh) 

2011 204 783 40% $4.89 1,718 

2012 211 966 46% $3.54 1,501 

                                                            

26 EIA Natural Gas Prices, http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm 27 AEO 2015 

28 EIA form 860 and EIA form 923 (NGCC), and EIA Monthly Energy Review, Table 7.2b (coal) 
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Table 3-4. Electric Power Sector Electricity Net Generation from Natural Gas, 1990-2012 

Year 

Net Generation: 

Natural Gas 

(million KWh) 

Percent Increase 

from Previous 

Year 

1990 309,486 

1991 317,773 3% 

1992 334,274 5% 

1993 342,222 2% 

1994 385,689 13% 

1995 419,179 9% 

1996 378,757 -10% 

1997 399,596 6% 

1998 449,293 12% 

1999 472,996 5% 

2000 517,978 10% 

2001 554,940 7% 

2002 607,683 10% 

2003 567,303 -7% 

2004 627,172 11% 

2005 683,829 9% 

2006 734,417 7% 

2007 814,752 11% 

2008 802,372 -2% 

2009 841,006 5% 

2010 901,389 7% 

2011 926,290 3% 

2012 1,132,791 22% 

Source: EIA Monthly Energy Review, Table 7.2b (multiple years) 

Phase-In 

The application of an increase in NGCC operation equivalent to a 75% net summer 

utilization to the baseline data from 2012 would yield an increase of less than 11% in NGCC 

generation, from 966 TWh to 1,070 TWh. To allow time for potential infrastructure 

improvements to facilitate increased utilization of existing NGCC plants, the EPA is finalizing a 

gradual phase over the interim period, consistent with the historical data presented above. The 

Commented [A4]: Please check. This seems much too low to go

from a 46% CF to a 75% CF.
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phase-in schedule is based on two parameters. The first parameter defines an amount of 

generation shift to existing NGCC capacity that is feasible by 2022. This parameter is 

conservatively defined as a percent increase from 2012 to 2022 that is equal to the largest single 

largest annual increase in power sector gas-fired generation since 1990. It is reasonable to 

assume that the same increase in NGCC utilization that occurred in one year could be 

implemented again by 2022. 

The increase in NGCC utilization over the remaining years of the interim period is 

limited by the average annual growth in gas-fired generation in the power sector between 1990 

and 2012, or approximately 5 percent per year. Since this is the average annual increase in gas 

utilization that has occurred over recent history, it is reasonable to assume that this increase 

could occur throughout the interim period, up to the full technical potential of 75% utilization on 

a net summer basis. 

In the performance rate calculation methodology, these two parameters constrain the 

annual rate at which building block 2 shifts generation from fossil steam units to NGCC units. 

As discussed in the preamble, the interim performance rate is an average of annual rates 

calculated over the 2022-2029 period. The two parameters above limit the extent to which 

NGCC generation is assumed to increase and replace fossil steam generation in each year of the 

interim period. From historical data, we can observe that the single largest annual increase in 

power sector gas-fired generation since 1990 occurred between 2011 and 2012 and is equal to 22 

percent. Therefore, in the first year, NGCC generation is limited to a maximum of a 22 percent 

increase from 2012 levels in each region. In each subsequent year, regional NGCC generation is 

limited to a maximum of a 5 percent increase from the previous year. This phase-in continues in 

the performance rate-setting methodology until the BSER level of shifting from fossil steam 

generation to NGCC generation is completed. Under this approach, building block 2 is 

completely phased into the performance rates of all regions by the end of the interim period. 

Table 3-5 summarizes the quantity of NGCC generation that represents building block 2 

potential as incorporated in the emission performance rate calculation in each region and year. 

Table 3-5. BSER Maximum NGCC Generation by Region and Year (TWh). 

NGCC Generation (TWh) 
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Region 

Maximum 

Potential 

at 75% 

2012 

(adjusted) 

BSER Maximum 

2022 2023 2024 2025 2026 2027 2028 2029 2030 

Limit -- -- 22% 5% 5% 5% 5% 5% 5% 5% 5% 

Eastern 

Interconn

ection 988 735 896 941 988 988 988 988 988 988 988 

Western 

Interconn

ection 306 198 242 254 267 280 294 306 306 306 306 

Texas 

Interconn

ection 204 137 167 176 185 194 203 204 204 204 204 

Natural Gas Supply 

The EPA expects that the gradual increase in generation from existing NGCC as defined 

above to be feasible and consistent with domestic natural gas supplies in each year of the 2022-

2029 phase-in. Increases in the natural gas resource base have led to fundamental changes in the 

outlook for natural gas. There is general agreement that recoverable natural gas resources will be 

substantially higher for the foreseeable future than previously anticipated, exerting downward 

pressure on natural gas prices.29

According to EIA, natural gas proved reserves have doubled between 2000 and 2012.30 

Domestic dry gas production has increased by 25% over that same timeframe (from 19.2 TCF to 

24.0 TCF). EIA’s Annual Energy Outlook for 2015 projects that production will further increase 

to 29.5 TCF by 2022, due to increased supplies and favorable market conditions. For 

comparison, building block 2 assumes NGCC generation growth of 340 TWh from 2012 to reach 

the level assumed for 2022, and that NGCC generation growth would result in increased gas 

consumption of less than 2 TCF for the electricity sector, which is less than EIA’s projected 

increase in natural gas production of 5.5 TCF from 2012 to 2022.31 

The National Petroleum Council (NPC), a privately funded advisory committee 

established by the Secretary of Energy, recently updated a major resource study and concluded 

                                                            

29 National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant 

Natural Gas and Oil Resources. http://www.npc.org/reports/rd.html (see Figure 1.2 on p. 47). 

30 http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=3&pid=3&aid=6 

31 Assuming 1,028 Btu/cubic foot and 7,615 Btu/KWh 
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that “the potential supply of North American natural gas is far bigger than was thought even a 

few years ago,” after large increases in shale resource estimates had already been realized.32 

Figure 3-2: U.S. Natural Gas Technically Recoverable Resources (from NPC, 2011)33

Natural Gas Deliverability 

To examine the potential for increases in pipeline deliverability, the EPA analyzed the 

pipeline flow data from the Energy Information Administration. These data provide pipeline 

capacity for inflows and outflows by region (see Figure 3-4). However, we cannot measure 

natural gas deliverability solely by considering a region’s inflow capacity, since that region may 

need to allow some of that inflowing natural gas to become outflow to other regions (effectively 

passing that natural gas through the region to consumers in other regions). Consequently, net 

capacity – the difference between inflow capacity and outflow capacity -- is a better metric for a 

                                                            

32 National Petroleum Council, 2012 (http://www.npc.org/PD_update-80112.pdf) 

33 http://www.npc.org/reports/rd.html 
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region’s ability to increase deliverability of natural gas supply, because natural gas using such 

pipeline net capacity must be consumed within the region (as there would be no more outflow 

capacity for it to leave the region). The regions used by EIA for measuring regional natural gas 

deliverability are shown in Figure 3-4. Our assessment focuses on areas that would experience 

increases in natural gas consumption in line with building block 2’s quantified potential for 

increased utilization of NGCC; in other words, these areas have most of the unutilized NGCC 

capacity. These are the Northeast, Southeast, Midwest and Western regions in Figure 3-4. The 

net pipeline capacity for these regions from 2005 to 2011 is shown in Table 3-6 below. 

Table 3-6. Natural Gas Pipeline Net Capacity by Region, 2005 - 2011 by Gas Consuming 

Area34

Region 2005 2006 2007 2008 2009 2010 2011

Capacity in MMCF/day 

Midwest 17,102 17,232 17,452 17,302 18,714 18,564 18,414 

Northeast 11,199 11,219 11,384 11,929 12,079 12,229 12,379 

Southeast 12,921 12,901 12,736 15,741 18,241 20,797 20,797 

Western 11,882 11,882 12,496 12,496 12,496 12,641 14,407 

All Areas 53,104 53,234 54,068 57,468 61,530 64,231 65,997 

Percent Change from 2005 

Midwest 0.0% 0.8% 2.0% 1.2% 9.4% 8.5% 7.7%

Northeast 0.0% 0.2% 1.7% 6.5% 7.9% 9.2% 10.5%

Southeast 0.0% -0.2% -1.4% 21.8% 41.2% 61.0% 61.0%

Western 0.0% 0.0% 5.2% 5.2% 5.2% 6.4% 21.3%

All Areas 0.0% 0.2% 1.8% 8.2% 15.9% 21.0% 24.3%

As a conservative assumption, the increase from the period 2005 to 2011 can be used as 

an estimator of the potential to increase pipeline capacity between 2016 and 2030 in the IPM 

projections for the BB2 BSER scenario where existing natural gas units were required to operate 

at the BSER capacity factor. Increased use of natural gas in existing units can be largely met with 

                                                            

34 Source: Energy Information Administration, http://www.eia.gov/naturalgas/data.cfm

Deleted: 5

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expansions to existing pipeline facilities and corridors, so that the types of capacity expansion 

required will be less expensive and take less time than new pipelines. Over 2005-2011, the total 

gas deliverability in gas consuming areas increased by 24%. In the BB2 BSER scenario, power 

sector natural gas consumption increased 36% over the base case, and 35% over estimated 2016 

consumption. However, pipeline deliverability increases apply to all sector consumptions, and 

the total consumption in the BSER scenario were projected to increase by 13% over the base 

case and 18% over 2016 consumption. Since this historical increase in pipeline capacity over the 

2005 to 2011 period is 24.3%, the historical data indicate that pipeline capacity can expand 

sufficiently to support the potential increased utilization of natural gas power plants quantified 

for building block 2 in the BSER modeling. 

Figure 3-3. Energy Information Administration Natural Gas Pipeline Regions

Source: Energy Information Administration. 

Deleted: will be adequate
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Recent pipeline construction continued to demonstrate the pipeline network’s ability to 

accommodate increasing demand for natural gas. According to information released in April, 

2014 by the EIA,35 118 pipeline projects were completed and placed into service from 2010 to 

2014, totaling 4,699 miles of pipe, and 44,107 MMcf per day of additional pipeline capacity. 

For projects expected to be in service from April, 2014 through 2016, EIA reports 47 projects, 

with planned capacity additions of 20,505 MMcf per day and 1,567 miles of pipe. These 

projects cover all major gas consuming areas of the US, and include both new pipeline 

construction, such as the Spectra Energy’s NEXUS Gas Transmission project in the Upper 

Midwest and pipeline expansions such as the Tennessee Gas Pipeline Project in Connecticut. 

The ability of the pipeline system to accommodate the increased utilization of NGCC 

quantified for building block 2 is reinforced by a recent DOE study of pipeline system 

expansion.36 This study examined two cases of pipeline expansion through 2030, one with a 

25% increase in overall natural gas demand in 2030 and one with a 46% increase compared to a 

reference case projection. In a key finding, the study concluded that, in both scenarios, 

compared to historical pipeline infrastructure expansion, “Intermediate interstate natural gas 

pipeline infrastructure needs in [the assessed scenarios] are projected to be modest relative to the 

Reference Case”.37 The levels of increased natural gas demand assessed in that DOE study are 

substantially above the 15% increase in natural gas demand projected in the EPA’s power sector 

modeling of a scenario that would realize the building block 2 NGCC utilization level (described 

below). 

Cost-Effectiveness of Shifting Generation to NGCC 

To evaluate the cost-effectiveness and technical capability of increasing utilization of 

existing NGCC as quantified for building block 2, EPA employed the Integrated Planning Model 

(IPM), a multi-regional, dynamic, deterministic linear programming model of the U.S. electric 

power sector that the EPA has used for over two decades to evaluate the economic and emission 

impacts of prospective environmental policies. IPM provides a wide array of projections related 

                                                            

35 See www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xls. 36 U.S. Department of Energy, Natural Gas Infrastructure Implications of Increased Demand from the Electric Power

Sector, February 2015. 37 Ibid. Page vi.
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to the electric power sector and its related markets (including least cost capacity expansion and 

electricity dispatch projections) while meeting fuel supply, transmission, dispatch, and reliability 

constraints. 

Natural gas supply, demand, transportation, storage, and related costs are modeled 

directly in IPM through the incorporation of a natural gas module. The module includes a detail 

rich representation of the natural gas pipeline network inclusive of discount curves that represent 

the marginal value of gas transmission as a function of the pipeline’s load factor. IPM’s natural 

gas module has the capability to expand pipeline capacity on an economic basis. 

At the unit level, IPM contains a detailed representation of new and existing resource 

options, inclusive of key operational limitations. For example, turn down constraints are 

designed to account for the cycling capabilities of EGUs to ensure that the model properly 

reflects the distinct operating characteristics of peaking, cycling, and base load units. EPA 

believes IPM represents a powerful tool to evaluate the technical feasibility of requiring 

increasing levels of re-dispatch from higher to lower-emitting EGUs. 

The EPA used IPM to model a series of scenarios representing replacement of fossil 

steam generation in each interconnection with increases of average NGCC net capacity factors in 

the same interconnection of up to 70, 75, and 80 percent. For example, in the 70 percent net 

capacity factor scenario, total fossil fuel-fired generation at existing sources across each 

interconnection is held constant with the level projected in the base case, while the model 

increases existing NGCC utilization in each interconnection either to a 70 percent capacity factor 

on average, or to a lower utilization level if such a level would deliver the same amount of fossil 

fuel-fired generation projected from existing sources in that interconnection in the base case.38 

 

 The costs and economic impacts of these scenarios were evaluated by comparing the total 

costs and emissions from each scenario to the costs and emissions from the base case. For the 

scenarios reflecting a 70, 75, and 80 percent NGCC utilization rate, comparison to the base case 

                                                            

38 The existing source fossil fuel‐fired generation described here includes generation from existing NGCC, coal

steam, IGCC and oil/gas steam boilers greater than 25 MW.

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indicates that the average cost of CO2 reductions was $15, $24, and $33 per short ton of CO2, 

respectively, over the 2022-2030 period. 

Table 3-7: IPM Results 

Existing NGCC 

Average 

Capacity 

Factor 

Average Cost ($ 

per short ton, 

2022-2030) 

Base Case N/A 

70% $15 

75% $24 

80% $33 

Natural Gas Price Impacts 

The extent of generation shifting estimated in this building block can be achieved without 

causing significant economic impacts, even without the gradual phase-in of this building block 

that was not represented in this analysis. For example, in the 75% scenario, delivered natural gas 

price projections increase by approximately 7 percent in the 2022-2030 period, which is well 

within the range of historical natural gas price volatility. For example, the year-to-year 

percentage difference in Henry Hub prices reported by the Energy Information Administration 

averaged 18.5% over the period from 1981 to 2012.39 Projected wholesale electricity price 

increases over the same period were about 4 percent in the 75% case, which is similarly well 

within the range of historic electric price variability. For example, the average year-to-year price 

change for all of the ISOs and RTOs in the East was about 20 percent over the period from 2000 

to 2013.40 

Table 3-8: National Average Delivered Natural Gas Price, 

Power Sector (Average 2022-2030) 

Existing NGCC 

Average Capacity 

Factor 

Price 

($/mmBtu) 

% Change 

from Base 

Case 

                                                            

39 http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm 40 ISO Real-Time data for all hours, from Ventyx Velocity Suite data across Eastern ISOs (PJM, NYISO,ISO-NE 

and Midcontinent ISO). 
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Base Case $5.45 N/A 

70% $5.70 5% 

75% $5.85 7% 

80% $5.99 10% 
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