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1 GHG Abatement Measures Technical Support Document Chapter 3: CO 2 Reduction Potential from Re -Dispatch of Existing Units

Table of Contents Overview ...................................................................................................................... ................... 2
Introduction .................................................................................................................. ................... 2 Power Sector Background ....................................................................................................... ........ 3
Historical Context ............................................................................................................ ............... 6
Technical Considerations ...................................................................................................... ........ 12 Analysis of Cost-Effectiveness ................................................................................................ ..... 17DRAFT DELIBERATIVE

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2 Overview This chapter explores the dynamics of power s ector dispatch and the cost-effectiveness of lowering the carbon dioxide (CO 2 ) emissions intensity of the power sector by reducing
utilization of the most carbon- intensive existing EGUs and incr easing utilization, to the extent possible, of less carbon-intensive existing fossi l fuel-fired EGUs. The TSD provides background on existing power plants, power system operatio n, 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 ge neration 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 generato rs are constantly responding to changes in demand and “re-dispatching” to meet demand in the most reliable and cost-effective manner possible.

The nation’s EGUs are connected by transmi ssion grids that extend over large regions. Through these interconnections, EGU balancing author ities treat the product (i.e., electricity) of EGUs as fungible, calling for el ectricity generation supply to m eet demand usually by deploying the least expensive power source first. 2

EGU operators and balancing authorities must take into account se veral constraints in dispatch, including transmission constraints as well as emissi on control programs and other environmental requirements. Such programs and re quirements 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 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 operato rs in 10 states partic ipating 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

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.pdfDRAFT DELIBERATIVE

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3 through re-dispatch among existing EGUs, particul arly by shifting generation from coal-fired units to natural gas combined cycle (NGCC) units.

Power Sector Background Electric Dispatch Electricity generation conforms to the principle of least-cost economic dispatch, which is “the operation of generation faci lities to produce energy at the lo west cost to reliably serve consumers, recognizing any operational limits of generation and tr ansmission facilities.” 3 The cost of operating electric generato rs varies based on a number of f actors, such as fuel used and generator efficiency. Regional Transmission Or ganizations (RTOs) a nd Independent System Operators (ISOs) help coordinate economic dispatch over larger ar eas to help keep the cost of meeting electricity demand as low as possi ble, subject to opera tional constraints.

The decision by balancing authorities to call upon, or dispatch, any particular generating unit is driven by the relative operating cost, or marg inal cost, of generating electricity to meet the
last increment of electric demand. These cost s 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 bid into electricity ma rkets 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 technol ogies, like renewables, hydroelectric, and nuclear, have lit tle or no variable costs and ar e generally dispatched to the extent possible. In order to maintain least-cost dispatch, the units with the lowest variable costs will be called upon first, then other units (wit h higher variable costs) will be called upon sequentially, such that total system demand is met. The economic orde r in which units are dispatched to meet demand, at any particular point in time, is commonly called a dispatch
“curve.” 5

3 Federal Energy Regulatory Commission, 2005. Economic Dispatch: Concepts, Practices, and Issues 4 In addition to fuel costs, variable costs also include costs associated operating and maintenance, and costs of operating a pollution control and/or emission allowance charges. 5 http://www.eia.gov/todayinenergy/detail.cfm?id=7590DRAFT DELIBERATIVE

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4 Balancing Authorities In states with cost-of-service regulation of vertically-integra ted utilities who own generation, transmission, and distribution infrastruc ture, the utilit ies themselves often form the balancing authorities who determin e unit dispatch. Such utilities ar e presumed to dispatch their units in a cost-minimizing fashion (seeking the lo west marginal cost), and they can arrange to buy and sell power with othe r balancing authorities.

In states that have restruct ured regulation to allow for co mpetition between generators, RTOs and ISOs are generally responsible for movi ng electricity across larger areas in the most efficient and least-cost manner possible. 6 They coordinate, contro l, and monitor electricity transmission systems 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 el ectricity (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 wholesal e 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, en sure efficient and reliable delivery of electricity, and plan appropriately for the short and long te rm energy needs of the state and consumers. Depending on market structure, PUCs also al locate costs among customers, design price structures and set price levels, set service qua lity standards, approve capital expenditure by utilities, and arbitrate disputes among relevant pa rties and stakeholders. In restructured markets, the PUC’s authority is generally applicable to the transmission and distribution system, since the

6 http://www.ferc.gov/industrie s/electric/indus-act/rto.asp 7 These entities are sometimes called Utilities Commissions , Utility Regulatory Commissions, or Public Service Commissions

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5 generation and dispatch component is governed by RTOs and ISOs. In cost-of-service states, the PUC also has oversight of the genera tion and capacity planning components

. Spot and Day-Ahead Markets RTOs and ISOs operate spot markets for w holesale power supply and demand for their designated area, including both day ahead and real -time (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 balanci ng authority for the same area.

For areas not administered by RTOs and ISOs , dispatch is scheduled both day ahead and hourly, but is typically driven by the power supply costs and sche dules 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 typica lly sell power day-ahead but not hourly, and also sell power for longer periods, 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.

As a balancing authority, the RTO or u tility will balance demand, generation, and imports/exports in real time while maintaining system frequency and ensuring that the next hour’s demand, or load, is met. In addition, the tr ansmission system is constantly monitored to ensure reliability limits are met, voltage levels are appropriate, and appropriate corrective action
is taken when needed.

Reliability As reliability coordinators, balancing authorities are responsible for the reliable operation of the bulk electric system. The bulk electric system re fers to a large interconne cted electrical system made up of generation and transmi ssion 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 th e limits of the transmission system, it must be adjusted by the system operator. The North Amer ican Electric Reliability Corporation (NERC)DRAFT DELIBERATIVE

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6 develops and enforces the procedures to ensure reliability, in accordance with Federal laws and regulations, and with FERC oversight. 8

Historical Context In 2012, average CO 2 emission rates 9 across all the following te chnology categories on a net generation basis were:

 Coal Steam - 2,354 lbs/MWh

 Oil/Gas (O/G) Steam - 1,624 lbs/MWh

 NGCC – 926 lbs/MWh

Coal- and oil/gas-fired boilers are consid erably higher-emitting sources than NGCCs, on average. Therefore, the replacement, or re -dispatch, of each megawatt-hour (MWh) from the average fossil fuel-fired boiler with each MW h from an average NGCC will result in notable
CO 2 emission reductions.

The lower emission rate of NGCC conveys th e potential of re-dispatch to reduce GHG emissions. However, the actual potential to r ealize emission reductions through this technology depends on the availability and capacity factor s of the existing NGCC fleet. In order to redispatch from existing fossil fuel-fired boilers to existing NGCC, there needs to be some existing unused generation potential in the current NGCC fl eet that could displace generation from more
CO 2 intensive generating resources. The term “ava ilability” is a common engineering term used in the power sector, which 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 sin ce that year included a leap day). The unavailable period is generally attr ibuted to scheduled maintenance, unplanned maintenance, and unplanned outages. The EPA assu mes that NGCC has an availability of 87%. 10 Other reports suggest that NGCC availab ility factors may reach as high as 92%. 11

If the existing NGCC fleet was already operating at a level of 87% to 92%, there would not be any additional generation potential in the existing generating system for re-dispatch. To

8 http://www.nerc.com/ 9 Emission rates in this document are shown on a net generation basis and reflect Hawaii and Alaska sources. See “2012 eGrid Data” file provided in the docket 10 See Chapter 3, Table 3-18 at http://www.epa.gov/powersectormodeling/BaseCasev513.html 11 http://www.power-eng.com/a rticles/print/volume-115/issue-2/featur es/higher-availab ility-of-gas-turbinecombined-cycle.htmlDRAFT DELIBERATIVE

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7 evaluate re-dispatch opportunitie s to unused NGCC generation poten tial in the system, the EPA reviewed recent NGCC fleet operating data to de termine capacity factors. Redispatch for GHG abatement purposes would require one net MWh of a lower emitting technology displacing one net MWh of generation from higher emitting technology. Therefore, when the EPA was assessing capacity factor it used the net generation of a give n NGCC unit as the numerator. The EPA was interested in the relationship of a unit’s total net generation relative to its net generating capacity (i.e., capacity factor). Net generating capacity is a fu nction of weather/temperature conditions at the site, which varies throughout the year. While some units may model actual weather adjusted capacity by the hour/minute, this data is not reported for the fleet. Therefore, the EPA used the reported nameplate capacity re ported for units. The net generation was divided into the nameplate generation capacity of a un it multiplied by the number of hours in a year. This calculation of capacity factor provides an indi cation of how much net generation a unit is providing as a percent of its total generating capacity. Whereas availability refers to the maximum amount of generation that could be expect ed from a given source, the capacity factor
refers to the actual utilization of that source on an annual basis. The EPA surveyed 2012 data for
over 1800 NGCC units and observed that the NGCC fl eet had an average cap acity factor in the 44% to 46% range for 2012. 12 Since the fleet-wide capacity factor in 2012 was less than the availability assumed for the technology, the histor ical data suggests that there is a significant potential for re-dispatch from higher CO 2 emitting resources to lower emitting NGCC generation.

Availability for NGCC fleet......... .......................87% to 92% (84% to 89%) 13 2012 Capacity Factor for NGCC fleet.....................44% -46%

To quantify the GHG reduction potential fr om re-dispatch, the EPA considered alternative capacity factor le vels at which the NGCC fleet c ould be dispatched. Although the availability for NGCC units is assumed to be in the mid to high 80s, the EPA did not assume that
each state’s NGCC fleet could collec tively operate at this level on an annual basis. To determine reasonable average capacity factor ceilings for a state’s NGCC fleet as part of BSER, the EPA

12 See “2012 eGrid Data” file provided in the docket for 44% figure. See EIA 860 and 923 for 46% value. 13 Because the 2012 capacity factor us ed in this exercise focuses on net generation as a percent of name plate capacity, the availability is converted from a gross generati on/name plate value to a net generation/name plate value using a .97net/gross conversion resulting in a range is 84% to 89%.DRAFT DELIBERATIVE

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8 considered historical data and modeling proj ections describing NGC C 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. 14 Of this capacity, almost all are a highly efficient
class of NGCCs that are able to achieve high availa bility factors.

Table 3-1: Existing NGCC Capacity, by Age 15

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 1,812 NGCC units operating in 2012, the EPA observed that 179 units (10% of NGCC units) had a net generation value that was gr eater than or equal to its nameplate capacity x 8784 hours * 70%. That is, a capacity factor that was 70% or greater (see Figures 3-1 and 3- 2). 16

14 See the National Electricity Ener gy Data Systems (NEEDS) file at http://www.epa.gov/powersectormodeling/BaseCasev513.html 15 See “Operable” worksheet in “Generator Y2012” Workbook in 2012 Zip file at http://www.eia.gov/electricity/data/eia860/ 16 See “2012 eGrid Data” file provided in the docketDRAFT DELIBERATIVE

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9 Figure 3-1: Cumulative NGCC Capacity Factor vs. Percentage of Units

Figure 3-2: Frequency of NGCC Capacity Factors

In 2012, roughly 10% of NGCC units operated at an annual capacity factor of 70% or higher. This subset of NGCCs was largely disp atched to provide base load power. While only 10% of units operated at 70% or higher capacity factor on an annual ba sis, the fleet of NGCC units was relied upon heavily during certain period s of time, in response to higher demand. On a seasonal basis, a significant number of units ach ieved capacity factors gr eater than 50%, and 0% 20% 40% 60% 80% 100%0%4%8%12%16%20%24%28%32%36%40%44%48%52%56%60%65%69%73%77%81%85%89%93%97%CapacityFactor

% of Units 

## Cumulative Capacity Factor

0 20 40 60 80 100 120 140 160 180 200#ofUnits 

## Unit Distribution by Capacity FactorDRAFT DELIBERATIVE

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10 even up to 80%. Using data reported to the EPA, 17 and looking more closely at data during the summer and winter peak electric ity demand timeframes nationwide, more than 10% of NGCC were operated at a capacity factor greater than 70%. 18 In fact, 19% of NGCCs achieved 70% capacity factor during the wint er of 2011/2012 and 20% hit that level or higher during the

summer. 19 During periods where demand levels are t ypically lower, some NGCCs were idled or operated at lower capacity factors. Nonethele ss, a notable number of existing NGCCs have demonstrated the ability to achieve a 70% capac ity factor for extended periods of time. These units achieved high capacity factors without adve rse effects on the electric system. While many units demonstrated an ability to deliver net generation that was more than 70% of their nameplate capacity, the EPA assumed that 70% was a reasonable fleet-wide ceiling for each

state. Over the last several years, advances in th e production of natural gas have helped reduce natural gas prices and improved the competitive pos ition 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 981 TWh, up from 796 TWh in 2011 (22% growth in one year). The extent of this capability varies by region, based on factors such as the mix of EGU types and the amount of available NGCC capacity.

An analysis of historical di spatch across the generating fleet of coal and NGCC units for 2011 and 2012 provides some implicit measures of the cost dynamics between the two technologies. For example, one is able to look at the change in the prices of coal and gas to gauge the relative costs of generating, or di spatch, for each technology. While there are wideranging costs at the unit level, an aggregated a ssessment of the relative economics is informative and can provide a metric for assessing the implica tions of dispatch as it relates to emissions of
CO 2.
The potential for redispatch 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

17 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 18 Summer defined as June, July and Au gust. Winter defined as December, Ja nuary, and February. Estimates are for units for which data was provided to EPA. 19 Air Markets Program Data ( http://ampd.epa.gov/ampd/ ). Winter includes December of 2011, January and February of 2012. Summer includes June, July, and August.DRAFT DELIBERATIVE

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11 capacity rose by just 3%). As NGCC generation rose by approximately 185 TWh, coal generation fell by approximately 216 TWh. The signifi cant redispatch from coal to gas over just a one year period demonstrates the ability for th e quick re-dispatch in response to market or
economic drivers.

The increase in the NGCC utilization was in la rge part driven by the decrease in natural gas prices to historic lows (s ee Table 3-2). Henry Hub natural gas prices averaged $4.00/mmBtu in 2011 and $2.76/mmBtu in 2012. This $1.24/mmBtu creates an additional incentive for redispatch from coal generation to NGCC relative to 2011 dispatch economics. The fuel advantage is similar to the incen tive that a $15/metric ton of CO 2 price signal would create. 20
This historical data also show s a sharp increase in the NGCC fl eet’s capacity factor from the high 30s to the mid 40s. During that same pe riod, net coal generation dropped by an amount similar to the increase observed in NGCC net ge neration. Furthermore, natural gas supply is expected to grow more than 20% by 2020 relative to its 2012 levels , creating more fuel resources to foster the potential con tinued and increasing redispatch to NGCC generating technology. 21

Table 3-2: 2011 and 2012 Gas and Coal Generation 22

Year NGCC
Name Plate

Capacity

(GW) NGCC Heat Input for Electricity

(TBtu) NGCC Net
Generation (TWh) NGCC Capacity

Factor HH Natural
Gas Price ($/mmBtu Coal Net
Generation (TWh) 2011 235 5,912 796 39% $4.00 1,719 2012 242 7,224 981 46% $2.76 1,503

The demonstrated ability of the NGCC units to consistently operate at levels greater than 70% of their nameplate capacity (e.g., this was the utilization level of the ~ 90 th percentile unit), the historic evidence supporting quick and significant redispatch to NGCC, and the costeffectiveness of high NGCC utilization demonstrated later in this TSD all supported the notion of a NGCC fleet capacity factor of 70% as a reas onable ceiling in the EPA’s BSER approach.

20 Assumes 11,000 Btu/KWh heat rate and 2354 lb/MWh emision rate for coal, 8000 Btu/KWh and 926 lbs/MWh for NGCC (based of “2012 eGrid file”) 21 http://www.eia.gov/oiaf/aeo/tablebrowser/#rel ease=AEO2014ER&subject=0-AEO2014ER&table=13- AEO2014ER®ion=0-0&cases=ref2014er-d102413a 22 EIA form 860 and EIA form 923DRAFT DELIBERATIVE

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12 Technical Considerations Emission reductions through re-dispatch are larg ely determined by the ability to change the utilization of existing generating units, relative to current utilization le vels. Other influences include physical limitations of the electric transm ission system and considerations for reliability, timing, and cost.

NGCC Availability For purposes of economic dispatc h, most NGCCs have historical ly been operated to serve
base load or intermediate demand due to their hi gh efficiency and flexib ility of operation, with national average annual capacity f actors in the range of 40-50%. 23,24 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 at capacity factors of 70% and greater is indicated, in part, by statistics on the average availability factor of NGCCs. 25 Annual availability is the ratio of annual hours that an EGU is operating or consid ered able to operate (not in a forced or maintenance outage) to the hours in a year. The average availability factor for NGCCs in the U.S. generally exceeds 85%, and can exceed 90% for selected groups, as reported to NERC. 26,27 Advanced NGCCs being built today have availab ility 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 gene rating sources (as of 2010). 28

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 (compared to 95 percent or greater availabi lities reported by curre nt vintage F class and H class turbines

23 EIA, Today In Energy, January 15, 2014, http://www.eia.gov/todayine nergy/detail.cfm?id=14611 (for recent data) 24 EIA, Electric Power Annual 2009, http://www.eia.gov/electric ity/annual/archive/03482009.pdf (Table 5-2 for 2009 and earlier data) 25 NERC, 2008-2012 Generating Unit Statis tical Brochure – All Units Reporting, http://www.nerc.com/pa/RAPA/ gads/Pages/Reports.aspx 26 Power Engineering, Negotiating Availability Gu arantees for Gas Turbine Plants, 03/01/2001, http://www.powereng.com/articles/print/volume-105/issue-3/features/negotia ting-availability-guarantees-for-gas-turbine-plants.html 27 Power Engineering, Higher Availability of Gas Turbine Combined Cycle 02/01/2011, http://www.powereng.com/articles/print/volume-115/issue-2/features/hig her-availability-of-gas-turbine-combined-cycle.html 28 http://site.ge-energy.com/corporate/n etwork/downloads/7FA_Evolution.pdfDRAFT DELIBERATIVE

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13 from General Electric Power Systems). 29 Data reported to NERC fr om NGCC units greater than 50 MW in 1994 through 1998 shows similar availabi lity factors (generally exceeding 89 percent).

Natural Gas Pipeline and Electricity Transmission The EPA believes that the natural gas pipeline and electricity transm ission networks can support aggregate operation of the NGCC fleet at up to a 70% capacity factor on average, either as they currently exist or with modifications th at can be reasonably expected in the time frame for compliance with this rule. Existing NGCCs are already connected to both the power and natural gas networks and, while constraints to spec ific unit operations can occur in either or both networks during peak pipeline flow or electricity use, the rule allows for emission rate averaging across multiple units and across time for complia nce. As a consequence of this averaging flexibility, constraints that occur at peak tim es are unlikely to be a barrier to achieving compliance with the rule, because these peak times are only a small percentage of the year and will constrain only a limited percentage of the state-wide NGCC fleet. The ability for the current fleet to ramp up significantly to meet changes in demand can be seen from the increased use of natural gas that occurred in 2012 in response to hi storically low natural gas prices. Power plant use of natural gas use in 2012 increased by 20% over 2011 30 and resulted in a national average capacity factor for NGCC of 49% on av erage, and higher in some states. 31

During the peak hours of the day (which vary by region and season), NGCC capacity factors are typically well a bove average capacity factors. 32 The pattern of capacity utilization by hour for 2005 to 2010 is shown in Figure 3-3. In this figure, capacity factors in 2010 are approximately 50% from the Hour 11 to Hour 21. 33 The persistence of th is hourly pattern across years shows the pattern to be stable. Since the av erage capacity factor for combined cycle units
in 2010 from the same information source was 39% 34 , this indicates that the current system can support levels of approximately 11% above the aver age capacity factor. Th ese peak hours are the

29 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. 30 Energy Information Administration, U.S. Natural Gas Consumption by End Use, http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm. 31 Source: Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2014 32 Energy Information Administration, Today in Energy, July 9, 2011. Average utilization of the nation’s natural gas combined-cycle power plant fleet is rising. http://www.eia.gov/todayine nergy/detail.cfm?id=1730# 33 In this figure, hour 11 is the hour ending at 11 AM, and similarly for other hours. 34 Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2014DRAFT DELIBERATIVE

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14 period when there are most likely to be constrai nts on the pipeline or electricity transmission networks; during other hours of the day, continue d NGCC operation at equa l, or higher levels, are technically feasible but may be limited by economic considerations (e.g., whether NGCCs can offer least-cost electricity compared to other sources at those times). As a result, the current system is already able to suppor t national average capacity factors in the mid to high 50’s for NGCC for peak. It is reasonable to expect that average capacity factors could be extended to higher levels at all hours without experiencing technical feasibility barriers from either pipeline supplies or electricity transmission.

Figure 3-3. Average Utilization of Natura l Gas Combined Cycle Power Plant Fleet

Although there can be site-specific constraint s on utilization at some NGCC facilities, several factors support the ability of the power and natural gas pipeline systems to respond effectively with increases in infrastructure when needed to alleviate these barriers. For example, in recent years, the power transmission syst em has responded with increased transmission infrastructure when needed to allow the retirement of uneconomic coal plants. 35 This rule

35 See http://www.pjm.com/~/media/about-pjm/newsroom/2013-releases/20131211-pjm-board-authorizes-4.6- billion-in-chnages-to-regional-electric-grid.ashx for an example of short term transmission upgrades performed to facilitate environmental compliance. For tec hnical description of these upgrades, see: http://www.pjm.com/~/m edia/committees-groups/commi ttees/teac/20131211/20131211- december-2013-pjm-boardapproval-of-rtep-whitepaper.ashx

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15 provides for flexible implementation that will permit efficient scheduling of infrastructure upgrades as needed. Upgrades to pipeline and tran smission infrastructure potentially needed to meet additional use of existing facilities will gene rally be less extensive than upgrades of that infrastructure potentially needed for siting of new capacity. In addition, this proposed rule is expected to result in significantly higher leve ls of end-use energy efficiency, which will reduce the load on the electricity transmission and na tural gas pipeline infrastructure, while also providing other system wide benefits, such as decreased need for new generating units and reduced peak demands.

In addition, natural gas pipeline capacity is regularly added in response to increased gas demand and supply, such as the addition of la rge amounts of new NGCC capacity in 2001 to 2003, or the delivery to market of un conventional gas supplies since 2008. 36 These pipeline capacity increases have added significant deliverab ility to the natural gas pipeline network to meet the potential demands from increased us e of existing NGCCs. Over a longer time period, much more significant pipeline e xpansion is possible. In previ ous studies, when the pipeline system was expected to face very large demands for natural gas us e by electric utilities about 10 years ago, increases of up to 30% in total deliverability out of the pipeline system were judged to be possible by the pipeline industry. 37 There have also been no table capacity expansions over the past five years, in response to increased natu ral gas supply estimates and advances in drilling techniques. 38

To examine the potential for increases in pi peline deliverability, the EPA analyzed the pipeline flow data from the Energy Informa tion Administration. These data provide pipeline capacity for inflows and outflows by state. However, since the natural gas pipeline system is a network for flows into, across, and out of states and broader area, the leve l of gas supply that can be firmly delivered to a particular region de pends on the amount of natural gas the will be required to be delivered out of the region to othe r regions. Consequently, it is important to focus on the net capacity – the diffe rence between inflow capacity and outflow capacity -- in the relevant areas. The regions used by EIA for m easuring regional natural gas deliverability are

36 Energy Information Administration, Today in Ener gy, Natural Gas Pipeline Additions in 2011. Additions averaged around 20Bcf per day from 2008 to 2011. 37 Pipeline and Storage Infrastructure Requirements for a 30 Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas groups confident of 30-tcf market, Oil and Gas Journal, 1999. 38 http://www.eia.gov/naturalgas/data.cfm#pipelinesDRAFT DELIBERATIVE

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16 shown in Figure 3-4. Of these regions, the key regi ons for the analysis of the potential impact of the proposed rule are those natural gas consuming areas where there could be increases in natural gas consumption as a result of re-dispatch to comply with the proposed rule. 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 3-3 below.

Table 3-3. Natural Gas Pipeline Net Capacity by Region, 2005 - 2011 by Gas Consuming Area 39
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 fr om the period 2005 to 2010 can be used as an estimator of the potential increase in pipelin e capacity to accommodate compliance with the rule between 2015 and 2020. This is an extremely conservative assumption, since compliance is measured over a longer period and is not limited to re-dispatch approaches. Moreover, pipeline requirements for increased use of natural gas in ex isting facilities can be e xpected to be largely on existing pipeline facilities and corridors, so that th e types of capacity e xpansion required will be less expensive and take less time than new pipelines. Over 2005-2010, the total gas deliverability in gas consuming areas increased by 21%. Since the power sector currently uses

39 Source: Energy Information Administration, http://www.eia.gov/naturalgas/data.cfmDRAFT DELIBERATIVE

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17 approximately 30% of the total national natural gas consumption, and gas usage in other sectors is expected to be essentially flat through 2020, this historical increase indicates that pipeline capacity will be adequate to support any complian ce changes in re-dispatc h of natural gas power plants.

Figure 3-4. Energy Information Administra tion Natural Gas Pipeline Regions

Source: Energy Information Administration.

Analysis of Cost-Effectiveness The EPA has conducted extensive analysis to quantify the opportunity to reduce CO 2 emissions through re-dispatch. As pa rt of this effort, the EPA conduc ted an initial set of analyses utilizing the Integrated Pla nning Model (IPM) to provide a framework for understanding the broader economic and emissions implications of shifting generation from coal-fired steam EGUs
to NGCC units within defined areas. 40 In the most restrictive scenarios, re-dispatch was

40 IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It provides forecasts of least cost cap acity expansion, electricity dispatch , and emission control strategies whileDRAFT DELIBERATIVE

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18 simulated only between EGUs located in the same state. These scenarios were designed to consider, even under a restrictive interpretation of the degree of re -dispatch that might constitute a component of BSER under CAA section 111(d), 41 to what extent existing NGCC units could increase their dispatch cost-eff ectively taking into account the impact of that behavior on prices of natural gas and electricity. To evaluate how EGU operators and balancing authorities could respond to a state’s goal by incentivizing re-dispa tch from more carbon-intensive to less carbonintensive EGUs, the EPA introduced two addi tional elements to the IPM framework:

1. The application of a CO 2 charge to the variable cost of dispatch for all existing coal steam boilers, IGCC units, and oil/gas steam boilers greater than 25 MW and with a CO 2 emissions rate greater than 1,100 lbs/MWh. 42

2. Generation constraints that maintain the sum of state-level generation in the Base Case 43 from existing NGCC of any size, plus existing coal steam, IGCC and oil/gas steam boilers greater than 25 MW and with a CO 2 emissions rate >1,100 lbs/MWh.

These elements test the economic and technical potential for re-dispa tch by: (1) increasing dispatch costs for affected coal steam, IGCC, and O/G steam EGUs within each state, and (2) requiring that any reduction in output from those s ources be offset in its entirety by an increase in output from that state’s existing NGCC capac ity. Utilizing IPM to conduct this analysis ensures an integrated, least-cost , technically feasible solution subject to power sector system reliability constraints, fuel market impacts, natural gas transmission and distribution networks, electric power transmission constraints, and unit-specific characteris tics (e.g., operating and maintenance costs, heat rate, turndown/cycling behavior).

meeting energy demand and environmental, transmission, di spatch, and reliability constraints. Full documentation of the IPM model can be found at http://www.epa.gov/powersectormodeling 41 In practice, unit dispatch does not respect state boundaries because l east-cost supply must be balanced with demand in real time over grid interconnects which span mu ltiple states (with the exception of the Electric Reliability Council of Texas interconnect). The design of this modelin g scenario assumes artificial constraints on re-dispatch to force such behavior to respect state boundaries, given the context of this rulemaking’s quantification of individual state goals. These state boundary constr aints necessarily forgo cost-effective opportunities to re-d ispatch units in different states; as a result, costs and pr ices in this analysis are overstated. 42 The addition of CO 2 costs represents a simple analytic ap proach to estimating the cost-effective CO 2 reductions under this building block and acts as a proxy for some existing state policies that shift dispatch. In actual plan implementation, states would be free to select any policy approach that has the net ef fect of reducing the carbon intensity of generation and/or reducing overall emissions from affected sources. 43 http://epa.gov/powersectormodeling/BaseCasev513.htmlDRAFT DELIBERATIVE

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19 Cost and Availability of Econom ic Re-Dispatch Opportunities In executing this analysis, the EPA conducte d a number of scenarios to quantify the relationship between the amount and cost of re-dispatch. Figure 3- 5 below presents the projected national average capacity factor for NGCCs in 2020 (the first year of the assumed re-dispatch incentive) and the associat ed average $/tonne of CO 2 reduced by comparing emissions and costs against the EPA’s Base Case (the difference in total system cost divided by the difference in power sector emissions).

Figure 3-5: NGCC National Capaci ty Factor, 2020 Initial Analyses

The EPA believes average $/tonne – which is distinct from the $/tonne CO 2 cost imposed in these analytic scenarios on affected coal st eam, IGCC, and O/G steam EGUs – to be the most relevant metric in evaluating cost-effectiveness. System cost changes necessarily encompass all elements of cost across power, transmission, a nd fuel markets and therefore provide the most comprehensive perspective regarding cost-effectiveness. 58%

62% 65% 68% 71% 74% 75%

0% 10% 20% 30% 40% 50% 60% 70% 80%

‐ 10 20 30 40 50 60AverageCapacityFactor

Average $/tonne 

### Projected Capacity Factor for Existing NGCCs (2020)DRAFT DELIBERATIVE

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20 Table 3-4: Power Sector Emission Reductions Due to Re-Dispatch

CO 2 Cost Level Imposed National Average
NGCC Capacity Factor Average Cost ($/tonne) 2020 Power Sector CO 2 Emissions (MMT / % Change from 2020) Base Case 52% N/A 2,161 $10/tonne 58% $17 2,038 / -6% $15/tonne 62% $18 1,997 / -8% $20/tonne 65% $21 1,961 / -9% $25/tonne 68% $27 1,928 / -11% $30/tonne 71% $34 1,901 / -12% $40/tonne 74% $44 1,866 / -14% $50/tonne 75% $50 1,852 / -14%

Although the EPA views this estimated range of average $/tonne costs as reasonable, we expect the costs of implementing this requirement in a compliance setting will be considerably
lower for several reasons:

 Analytic construct used to simulate re-dispatch incentive: As described earlier in this chapter, the EPA’s init ial analyses utilized CO 2 charges on the variable cost of dispatch for existing coal steam, IGCC, and O/G st eam with emission rates greater than 1,100 lbs/MWh and a capacity greater than 25 MW, as an analytic cons truct to induce redispatch behavior in the model to existing NGCC facilities. The CO 2 charge was applied uniformly to all states in order to quantify the ultimate amount of in-state re-dispatch opportunities available as that ch arge is increased acr oss scenarios. In th e initial analyses,
low levels of CO 2 charges produce cost-effective re-d ispatch opportunities relative to the Base Case in almost all states. However, as the CO 2 costs are increased to higher levels, economic re-dispatch, opportunitie s within some states may ev entually plateau – a point clearly illustrated in the d eclining slope of the best-fit line in Figure 3-5. A uniform application of the same rising CO 2 charge in all states pr oduces an outcome for many
states where the additional CO 2 costs imposed on affected coal steam, IGCC, and O/GDRAFT DELIBERATIVE

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21 steam are not able to produce incremental econo mic re-dispatch at units within that state; therefore, the additional costs imposed by th ese higher CO2 charges overstate the actual $/tonne necessary to induce achieva ble re-dispatch in each state.

 Potential for multi-state compliance: The EPA also analyzed scenarios where shifting of generation among EGUs was not limited by stat e boundaries. In one set of analyses, redispatch was allowed to occur across the multi-state regions defined by NERC assessment areas (subject to othe r real-world constraints specif ied in the model, including transmission limits). In these scenarios with greater re-dispatch flexibility, the system was able to achieve 8% greater CO 2 emission reductions at an identical CO 2 charge, demonstrating that the main analysis’s im position of artificial re-dispatch boundaries on
state borders overstates the cost-eff ectiveness of re-dispatch potential.

To evaluate how EGU owners and grid operato rs could respond to a state plan’s possible requirements, signals, or incentives to re-dis patch from more carbon-in tensive to less carbonintensive EGUs, the EPA also analyzed an additi onal series of scenarios in which the fleet of NGCC units nationwide was required, on average, to achieve a specified a nnual utilization rate. Specifically, the scenarios required average NGCC unit utilization rates of 65, 70, and 75 percent. For each scenario, dispatch decisions are allowed such that electricity demand is met at the lowest total cost, subject to all other spec ified operating and reliability constraints for the scenario, including the aforementioned state-by-stat e generation levels from the base case. This constraint effectively requires states that decrease coal genera tion to offset, in equal amounts, NGCC generation. Collectively, states must achie ve the required capacity factor for NGCCs.

The costs and economic impacts of the vari ous scenarios were evaluated by comparing
the total costs and emissions from each scenario to the costs and emissions from a business-asusual scenario. For the scenario reflecting a 70 percent NGCC utilization rate and a constraint prohibiting interstate re-dispa tch opportunities, comparison to the business-as-usual case indicates that the average cost of the CO 2 reductions achieved ranged from [$xx] to [$xx] per
metric ton of CO 2 .

These scenarios include constraints such that there will be no cost-effective re-dispatch opportunities among EGUs in different states, contra ry to the reality that interstate flows of electricity routinely change in response to economic conditions. As a result, this case assumes noDRAFT DELIBERATIVE

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22 use of interstate electricity trading as a co st reduction mechanism, and thus overstates the impacts of re-dispatch.

In the 70 percent NGCC unit util ization rate scenario with restrictions on interstate redispatch, natural gas prices were projected to increase by a range of from [x] percent to [x] percent, which is within the ra nge of historic natural gas pric e variability. Projected wholesale electricity price increases ranged fr om [x] to [x] percent, which si milarly is within the range of historic electric price variability.

The EPA also analyzed dispatch-only scen arios where shifting of generation among EGUs was not limited by state bound aries. In one set of analyses , re-dispatch was simulated to occur across the multi-state regions overseen by independent system operators (ISOs) and other regional transmission organizati ons (RTOs), while in another set of analyses, national redispatch was simulated (subject to other c onstraints specified in the model, including transmission limits). In these scenarios with grea ter re-dispatch flexibility, the cost of achieving the quantity of CO 2 reductions corresponding to a nationwid e average NGCC unit utilization of 70% was notably lower.