### 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 >>

### Summary	of	Interagency	Working	Co mments	on	Draft	Language	under EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

3 - 1 

### Chapter 3: CO 2 

### Reduction Potential from Gene ration Shifts Among Existing Units

Overview

This chapter explores the dynamics of power sector dispatch and the cost-effectiveness of lowering the carbon dioxide (CO 2 ) 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 CO 2 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 transmissi on 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 Deleted: s

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3 - 2 emissions implications for pollutants such as SO 2 and NO x 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 CO 2 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 e lectricity 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 electric ity 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 operati o n and maintenance, and costs of operating a pollution control and/or the price of allowances to emit certain pollutants. Deleted: E

Deleted: conforms

Deleted:

Deleted: least-cost

Deleted: r

Deleted: In order to maintain least-cost dispatch, the

Deleted: g

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3 - 3 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

. Deleted: economic

Deleted: marginal

Deleted: electricity transmission systems

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3 - 4 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

Deleted: In addition

Deleted: transmission

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3 - 5 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 di spatch 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 CO 2 emission rates 9 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 CO 2 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 CO 2 -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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3 - 6 Given their cost structure, for purposes of economic dispatch, most NGCCs have historically operated as base load or intermediate load 10 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/archi ve/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. Deleted: For

Deleted: been

Deleted: to serve

Deleted: demand

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3 - 7 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 ሺ Net summer capacity ሻ 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 CO 2 emitting resources to lower CO 2 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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3 - 8 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 Age 21

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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3 - 9 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 40NumberofNGCCPlants

2012 Capacity Factor

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3 - 10 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 capa city 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 EPA 23 , 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 point s 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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3 - 11 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 CO 2 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 co st 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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3 - 12 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 CO 2. The potential for shifting generation from CO 2 intensive sources to less CO 2 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 Generation 28

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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3 - 13 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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3 - 14 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 Genera tion by Region and Year (TWh).

NGCC Generation (TWh)

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3 - 15 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, recent ly 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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3 - 16 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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3 - 17 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 Area 34 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

Deleted: in

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3 - 18 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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3 - 19 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 Te nnessee 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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3 - 20 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. Deleted:

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3 - 21 indicates that the average cost of CO 2 reductions was $15, $24, and $33 per short ton of CO 2 , 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 wit hout 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 Vent y x Velocity Suite data across Eastern ISOs (PJM, NYISO,ISO-NE and Midcontinent ISO).

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3 - 22 Base Case $5.45 N/A 70% $5.70 5% 75% $5.85 7% 80% $5.99 10%

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A - 1