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Long-Term Electricity Report for Maryland (LTER) List of Modeling Input Assumptions

November 30, 2010 Introduction This report presents the principal assumptions that will be used to produce the Long-term Electricity Report (LTER) for the State of Maryland.1 Each section of this report describes the following types of assumptions in detail: transmission topology; loads; generation unit cost and operational characteristics for both fossil-fueled and renewable generation; and environmental policies and renewable energy portfolio standards. In addition, the Appendix contains more detailed information about the fuel and generation cost assumptions. Ventyx, an engineering firm with extensive experience modeling electricity markets, has been selected to perform the electricity modeling for the Long-term Electricity Report (LTER) and will work closely with PPRP and Exeter Associates, Inc. to perform the quantitative modeling needed to complete the LTER. Exeter staff, along with PPRP and Ventyx, have designed various modeling scenarios and the Ventyx model will produce the outputs listed in Table 1 below. Table 1: Ventyx Model Outputs

Production: Generation (MW and MWh) Fuel Cost ($) Fuel Consumption by fuel type (MMBtu) Variable O & M ($) Fixed O & M ($) Emission Cost ($) Emission Rates (lbs/MMBtu) Emissions (tons) Capacity Factors Prices: Market Energy ($/MWh) Monthly On-Peak, Off-Peak, All Hours Capacity Prices $/kW-Month Regional REC Prices ($/MWh) Planning: Reserve Margin (%) Generic Capacity Built (MW) Resource Mix (%) Plant Retirements Plant Retrofits

1

The Long-Term Electricity Report for the state of Maryland is being written pursuant to Executive Order 01.01.2010.16, signed by Governor Martin O'Malley on July 23, 2020. http://www.governor.maryland.gov/pressreleases/100723.asp

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Ventyx will produce the outputs in Table 1 with two models. The first model is called the Integrated Pre-Processor ("IPP") and it forecasts:

· · · · · · · ·

capacity additions; capacity retirements; capacity retrofits; electric capacity prices; fuel prices; emissions prices; REC prices; and generator dispatch data (i.e., the MWh that each generator produces).

Ventyx inputs the IPP outcomes into PROMOD (a production costing model), which in turn produces more detailed plant dispatch and hence price projections. The Ventyx models (IPP and PROMOD) require four categories of inputs, described in Table 2 below, to produce the outputs listed in Table 1.

Table 2: Ventyx Inputs -Transmission topology -Loads -Generation unit cost and operational characteristics for fossil fuel-fired and renewable generation, and related -Environmental policies and the renewable energy portfolio standard

Each of the inputs categories in Table 2 is discussed in turn below. Please note that the assumptions contained in this White Paper are preliminary and subject to change as the Advisory Committee submits comments, as public input is obtained, and as more current data become available. Transmission Topology The IPP and PROMOD models separate the relevant geographic area surrounding PJM into market centers or "bubbles" shown in Figure 1 below. The transfer capability between bubbles is particularly important because transmission constraints are the main cause of price differentials across PJM. The transmission topology will change if new backbone transmission projects, such as MAPP and PATH, are constructed in the region. Most of Maryland's energy users (i.e., those within the Pepco and BGE zones) fall within the PJM-SW bubble; Allegheny customers fall within the PJM-APS bubble; and Delmarva customers fall within the PJM-Mid-East bubble. It is important to note that the prices in all of the PJM bubbles are relevant when determining the price of electricity in the State of Maryland because PJM operates as a centralized market.

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Figure 1: Ventyx Rendition of PJM and Surrounding Areas

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Table 3 describes the geographic areas associated with the market are bubbles in Figure 1.

Table 3: Market Topology Market Area Name Cincinnati Dakotas FirstEnergy ATSI MISO - Gateway MISO - Indiana MISO - Iowa MISO - Manitoba MISO - Michigan MISO - Minnesota MISO - North Dakota MISO - WI-UPMI PJM - AEP PJM - APS PJM - COMED PJM - South PJM MidAtlantic - E PJM MidAtlantic East PA PJM MidAtlantic SW PJM MidAtlantic West PA Saskatchewan SPP - Central SPP - KSMO SPP - Louisiana SPP - Nebraska Abbreviation CIN Dakotas FE-ATSI MISO-Gat MISO-IN MISO-IA Manitoba MISO-MI MISO-MN MISO-ND WI-UPMI PJM-AEP PJM-APS PJM-CE PJM-S PJM-MidE PJM-EPA PJM-SW PJM-WPA SK-CAN SPP-C SPP-KSMO SPP-LA SPP-NE Market Area Description Duke Energy Ohio and Kentucky North and South Dakotas First Energy - ATSI S Illinois E Missouri (Gateway) Cinergy + Other Indiana Utilities Iowa Manitoba Michigan Electric Coordinated Systems Minnesota MISO North Dakotas Wisconsin-Upper Michigan American Electric Power Allegheny Power System Commonwealth Edison/Northern Illinois Dominion Virginia Power Company PJM MidAtlantic - East of East Interface PJM MidAtlantic - East Pennsylvania PJM MidAtlantic - Southwest PJM MidAtlantic - West Pennsylvania Saskatchewan Power Southwest Power Pool - Central Region Southwest Power Pool - North Louisiana (Non-Entergy) Nebraska Geographic Location OH, KY ND, SD, IA OH, PA IL, MO OH, IN IA MB (Canada) MI MN, WI, ND ND MI, WI VA, OH, IN, KY WV, MD, PA IL VA NJ, PA, DE, MD PA MD, DC PA SK (Canada) LA, MO, OK, TX KS, MO LA NE

MAPP and PATH Lines The assumptions related to the Mid-Atlantic Power Pathway (MAPP) and the Potomac Appalachian Transmission Highline (PATH), being relied upon are: PATH: In-service date: Transfer capability: MAPP: In-service date: Transfer capability: Southwest to East Southwest to South These assumptions were developed by Ventyx.

2016 2,011 MW

2016 2,001 MW 2,500 MW 1,250 MW

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Loads Load forecasts for the LTER are a required input into the Ventyx models. PPRP will adjust PJM's December 2010 Peak Load and Energy Forecast downward to reflect the impacts of energy efficiency and peak load reduction programs in the State of Maryland, such as EmPOWER Maryland and also programs in other PJM states.2 The energy and demand reductions associated with EmPOWER Maryland are presented in Tables 4 and 5, respectively. The energy savings figures in both Tables 4 and 5 will be updated after the Maryland Public Service Commission releases an updated report about utility EmPOWER Maryland savings. Please see the EmPOWER Maryland White Paper for more details.

Table 4: MD PSC EmPOWER Maryland 2015 Energy Reduction Projections Based on Log Growth

Utility Allegheny BGE Delmarva Pepco SMECO Total Projected Energy Reduction (MWh) 35,398 1,993,449 74,376 348,073 365,350 2,751,238

Notes: Energy reductions will be updated after the release of Maryland PSC data expected in late-December 2010.

Table 5: MD PSC EmPOWER Maryland 2015 Demand Reduction Projections Based on Log Growth

Utility Projected Demand Reduction (MW) NA 1,401 135 493 141 2,170

Allegheny BGE Delmarva Pepco SMECO Total

Notes: Demand reductions will be updated after the release of Maryland PSC data expected in late-December 2010. Allegheny does not have a demand response program.

2

See the attached White Paper on EmPOWER Maryland, November 30, 2010.

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PPRP will also adjust the PJM load forecast to account for the impact Plug-in Hybrid Electric Vehicles ("PHEVs") and Battery Electric Vehicles ("BEVs"). These are referred to collectively as Plug-in Electric Vehicles ("PEVs") and treated as electrically equivalent with respect to energy use.3 The estimated load impacts of PEVs are based on the following assumptions, as explained in the "Plug-In Electric Vehicles" White Paper.

· Market penetration assumptions: based on Pacific Northwest National

Laboratory's market penetration analysis

· PEV energy consumption assumptions: achieves 4 to 5 miles/kWh; 10 year life. · PEV driving assumptions: average use is 30 miles/day; required charge per day

is 7 kWh.

· PEV charging assumptions: Level 2 home chargers; utility managed charging

technology spreads loads evenly over charging hours; 90 percent of PEVs charged during off-peak hours, 10 percent during on-peak hours. Table 6 lists the assumed weekday peak and off-peak load impacts of increased numbers of PEVs for the PJM region as a whole and separately for the State of Maryland.

Table 6: Total Weekday Hourly Demand from PEVs in Maryland and PJM (MW)

Maryland 2020 PJM Maryland 2030 PJM Total On-Peak Total Off-Peak Total On-Peak Total Off-Peak Total On-Peak Total Off-Peak Total On-Peak Total Off-Peak 3.5 63 33 589 23.6 424 222 4,003

Consistent with State planning requirements, PPRP has developed an alternative load forecast adjustment that considers the impact of climate change by incorporating the results of the Maryland Commission on Climate Change's "Global Warming and the Free State: Comprehensive Assessment of Climate Change Impacts in Maryland" report, published in July 2008. This report provides temperature forecasts through 2100. Based on the Maryland Commission on Climate Change's report, Exeter staff

3

See the attached White Paper on PEVs for a detailed discussion of the PEV assumptions, November 30, 2010.

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projects an additional warming of 2.3 degrees Fahrenheit by 2030 compared to the long-term trend; annual climate change will be linearly interpolated between 2010 and 2030. PJM has agreed to produce alternative load growth projections based on alternative weather-related assumptions. To accomplish this, PJM will adjust the "normal" temperatures that it uses to produce the forecast to reflect the warming trends predicted by the Maryland Commission on Climate Change. Alternative scenarios based on high and low load forecasts are contemplated for the LTER (see list of scenarios). While PJM produces forecasts of peak demand and energy both higher and lower than its base case set of forecasts, those alternative forecasts are based on extreme weather conditions rather than on alternative economic assumptions (e.g., higher-than-expected or lower-than-expected growth in Gross Metropolitan Product). To capture the range of impacts on prices, emissions, fuel use, and other factors due to higher or lower growth in peak demand and energy consumption in PJM as a whole and within those zones that contain Maryland, alternative load growth scenarios have been developed. The high growth scenarios assume load growth in energy and peak demand of 0.5 percent per year higher than projected by PJM's base case. Similarly, the low load growth case relies on growth rate projections 0.5 percent per year lower than contained in the PJM base case. These modifications provide loads in the terminal year of the analysis period (2030) approximately 10 percent lower and higher than the PJM base case. Annual growth changes significantly below 0.5 percent do not result in a substantial enough change in projected load to generate meaningful results. Changes to load in excess of 0.5 percent per year result in unreasonably high and low forecast. PJM's forecasted peak demand will also be adjusted for demand response. PJM includes a demand response adjustment for the first three years of the forecast, and holds constant the Year 3 demand response level for each remaining year of the forecast period. PPRP anticipates that the Year 4 through Year 20 demand response adjustment will be modified by assumption, but those assumptions have not yet been fully quantified. PJM states other than Maryland also have implemented energy conservation and efficiency programs. While the PJM load forecast makes no adjustment for these programs, we anticipate reducing the PJM forecast to account for the various state programs currently operating. This adjustment, to date, has not been fully quantified.

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Generation unit operational and cost characteristics Fossil Fuel Generation Generation unit operational and cost characteristics are critical assumptions because they determine how much it will cost to generate electricity. The operational characteristic assumptions include fuel costs and fixed and variable operation and maintenance ("O&M") expenses. Fuel prices are among the most important assumptions in the LTER because they will determine which power plants operate, what the price of electricity in each market bubble will be (this price depends on the marginal unit in each bubble), and what types of new power plants (e.g., natural gas, nuclear, etc.) will get built as demand grows and existing plants retire. Figures 2 through 4 plot the key fuel price forecasts of the Ventyx models, which are preliminary pending feedback from the LTER Advisory Committee. The Appendix provides fuel price forecasts for natural gas, coal, fuel oil, and nuclear fuel in tabular format. Figure 2 plots the base, high, and low gas price for the Henry Hub, which is the most liquid natural gas hub in the U.S.4 The Henry Hub fuel price is adjusted upward to reflect the costs necessary to transport gas from the Henry Hub to the geographic region where each generator is located. This methodology, which relies on Henry Hub basis point differentials, is standard in the industry.

4

Henry Hub is the most important and liquid trading hub for natural gas and the most commonly used benchmark for natural gas futures contracts. Virtually every natural gas forecast produced in the industry, including the Ventyx and Energy Information Administration's Annual Energy Outlook, is based in part on Henry Hub prices. The Henry Hub is physically located in Louisiana.

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Figure 2: Natural Gas Forecast of the Henry Hub Price

$14.00

$12.00

$10.00

2010 $/MMBtu

$8.00

$6.00

$4.00

Base

$2.00

Low

High

$0.00

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

The base case gas price forecast shown in Figure 2 (and numerically presented in Table A1 in the Appendix) is generally consistent with the Energy Information Administration's 2010 Annual Energy Outlook (AEO) reference case. The high and low gas price cases, however, differ markedly from the 2010 AEO high and low gas price projections, which we judge to be too similar to the reference case to adequately capture the range of uncertainty associated with future gas prices. The forecasted gas prices shown in Figure 2 for the high case exceed the 2010 AEO high case and the Figure 2 low case projections are below the 2010 AEO low case. The 2010 AEO projections are shown in Figure A1 in the Appendix for reference. For the LTER, it is anticipated that scenarios will be run using the base case gas prices and, for the LTER high gas price scenarios, the high case. It is not anticipated that the low case prices will be relied upon for LTER scenario development. Figure 3 plots coal prices by PJM area for various regions in PJM. These projections are based on highly detailed information about individual generating units, and these data can be used to produce burner tip prices at each coal-fired power plant based on the specific type of coal (e.g., Central Appalachia or Illinois Basin) that each generator purchases.

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Figure 3: Coal Price Forecast by PJM Area

$3.50

$3.00

$2.50

2010 $/MMBtu

$2.00

$1.50

$1.00

PJM AEP PJM MAEast

PJM APS PJM MA EPA

PJM COMED PJM MA SW

PJM South PJM MA W PA

$0.50

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Fuel oil projections are presented in Figure 4 below. The fuel prices are coupled with

generator-specific heat rate data to determine the marginal cost of each generation unit located within the market bubbles shown in Figure 1. Figure 4: Fuel Oil Forecast

$25.00

$20.00

2010 $/MMBtu

$15.00

$10.00

$5.00

No. 6 0.3% S No. 2 (Distillate)

No. 6 0.7% S Diesel

No. 6 1% S Kerosene/Jet Fuel

No. 6 2% S

$0.00

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

The Ventyx model also "builds" new generation when it is economic to do so based on market conditions and the cost of constructing new facilities. Table A5 in the Appendix contains detailed information on the capital, variable, and O&M costs associated with new generation technologies. Given that capital investment decisions are required, financial parameters are needed to guide the investment decisions. These parameters are described in Table 7 below.

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Table 7: Capital Cost Assumptions for New Generation Debt Equity Debt/Equity Ratio 50% 50% Cost rate 7% 12% Effective Tax Rate Inflation Rate 40.20% 2.5%

Renewable Generation

On-shore Wind --The principal source for the development of the modeling assumptions for on-shore wind power is the U.S. Department of Energy's 2009 Wind Technologies Market Report.5 This report provides regional break-outs of wind power data, although the degree of granularity is coarser than we would prefer, i.e., regional wind power data for the mid-Atlantic area are aggregated with other wind power data for the East. Nonetheless, this document appears to be the best available source of information needed to develop a comprehensive set for modeling assumptions related to on-shore wind power characteristics and costs. Capital Costs: The capital costs of wind projects have increased in recent years. The capacity-weighted average installed cost for wind projects built in 2009 was $2,120 per kW, an increase of $170 per kW (9 percent) from 2008 and an increase of $820 per kW (63 percent) from the average cost of wind projects constructed from 2001 through 2004. For wind projects installed in the Eastern United States between 2007 and 2009, DOE's report finds the capacityweighted capital cost to be $2,137 per kW in 2009 dollars based on information for 19 wind projects totaling 1,539 MW (an average of about 80 MW per project). Based on a small sample, it appears that the capital costs of wind projects in the midAtlantic are higher than elsewhere in the East. Table 8 contains statistics about recent wind projects in the mid-Atlantic. In Maryland, Constellation's 70-MW Criterion wind project will reportedly be built for $140 million, or $2,000 per kW,6 while U.S. WindForce's Dans Mountain wind project was projected to cost $142 million for the 69.6 MW project, or $2,040 per kW.7 In West Virginia, the estimated cost of U.S. WindForce's planned 55 MW Pinnacle wind project is $131 million, or $2,381 per kW.8 In Pennsylvania AES' 101-MW Armenia Mountain project was constructed for $250 million, or $2,475 per kW.9 Also in Pennsylvania, the 62.5 MW Highland

5

Ryan Wiser and Mark Bolinger. 2009 Wind Technologies Market Report. U.S. Department of Energy, August 2010. http://eetd.lbl.gov/EA/EMP/reports/lbnl-3716e.pdf. 6 Constellation Energy. "Constellation Energy Signs Agreement to Acquire Western Maryland Wind Project," November 30, 2009. http://ir.constellation.com/releasedetail.cfm?ReleaseID=426909. 7 Kevin Spradlin. "PSC Grants Wind Farm Exemption," Cumberland TimesNews, March 11, 2009. http://times news.com/archive/x1540446566. 8 U.S. WindForce. "Pinnacle Project Facts." http://web.uswindforce.com/index.php?option=com_content&task=view&id=45&Itemid=19. 9 Cheryl R. Clarke. "Senator Tours $250 Million Wind Project Atop Armenia Mountain," SunGazette, September 8, 2010. http://www.sungazette.com/page/content.detail/id/553341/Senatortours250millionwindprojectatop ArmeniaMountain.html?nav=5014.

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Wind project came on-line in 2009 and was constructed for $143 million, or $2,288 per kW.10 A simple averaging of these five projects results in an average capital cost of $2,250 per kW.11 Table 8: Sample On-Shore Wind Project Capital Costs Estimated Capital Cost (millions)

$140 $142 $131 $250 $143

Company

Constellation Energy U.S. WindForce U.S. WindForce AES EverPower Wind Holdings, Inc.

Project Name

Criterion Dans Mountain Pinnacle Armenia Mountain Highland Wind

State

MD MD WV PA PA

Project Size (MW)

70 69.6 55 101 62.5

Operational Status

Online in late 2010 Delayed Proposed Online in 2010 Online in 2009

Market information from various recent industry reports suggests that while wind turbine costs have increased up until recently, wind turbine costs have declined between 20 and 25 percent in 2010 compared to 2009 due to lower commodity costs, stiffer competition with other fuels (e.g., natural gas) and a tightening of overall market conditions for wind power in general. We can expect, however, that as economic recovery becomes more robust, there will be upward pressure on the 2010 prices and the 2010 price declines that have characterized the market will diminish. Based on the foregoing, we assume a capital cost of $2,200 per kW in 2010, and an 18 percent decline in 2011 to a capital cost level of $1800 per kW for 2011. We also assume that the 2011 capital cost level will remain constant in real dollar terms through the terminal year of the LTER study period (2030). The Ventyx integrated models include an annual O&M cost of $29.55 per kW (in 2010 dollars), which is supported by O&M costs reported in Federal Energy Regulatory Commission ("FERC") Form No. 1s for various regulated utilities. Consequently, we are comfortable in adopting the Ventyx assumption for annual O&M costs for on-shore wind projects, which is held constant (in real terms) over the study period.

10

Harry Zimbler. "Highland Wind Farm Receives a $42 Million Federal Grant," Pennsylvania Business Central, http://www.pabusinesscentral.com/2009/09/highlandwindfarmreceivesa42millionfederalgrant/. 11 This analysis only looked at planned or operating wind projects from 2007 through 2009, to the extent data was available.

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Capacity Factor: DOE reports that the capacity-weighted average capacity factor for Eastern on-shore wind projects in 2009 was 28 percent, although there is a substantial range around that average, with a low of 17 percent to a high of about 31 percent. Table 9 contains annual production data for wind projects operating in New Jersey, Pennsylvania, and West Virginia and calculated capacity factors for 2006 through 2008. The average capacity factor varies by year, ranging from 21 percent in 2007 to about 25 percent in 2006, with capacity factors being higher in New Jersey (for one project) and West Virginia as compared to Pennsylvania. Because the two soon-to-be-operating wind projects in Western Maryland are nearby on-line wind projects in West Virginia that have higher capacity factors, PPRP adopted a capacity factor assumption of 30 percent for new Maryland on-shore wind projects.

Table 9: Average Annual Capacity Factor of Wind Projects in New Jersey, Pennsylvania and West State 2006 2007 2008 New Jersey Pennsylvania West Virginia Pennsylvania and West Virginia New Jersey, Pennsylvania, and West Virginia 24.3% 24.1% 30.1% 31.1% 19.5% 29.0% 31.7% 22.1% 29.2%

25.0%

20.5%

22.7%

24.9%

21.4%

23.4%

Off-shore Wind12 -- To date, no off-shore wind projects have been constructed in the United States, although there are about 20 proposed off-shore wind projects representing over 2,000 MW of capacity. Most of these proposed off-shore wind projects are located in the Northeast, although some have been proposed for the Great Lakes, the Gulf of Mexico and the Pacific Coast. A few have progressed to the point of having power purchase agreements; these are presented in Table 10 below.

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Unless otherwise indicated, the information in this section comes from Walter Musial and Bonnie Ram. Large-Scale Offshore Wind Power in the United States: Executive Summary, National Renewable Energy Laboratory, September 2010. http://www.nrel.gov/docs/fy10osti/49229.pdf.

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Table 10: Comparison of Offshore Wind Power Purchase Agreements

Jurisdicti on DE Seller Bluewater Wind Buyer Delmarva Power Price Unbundled pricing in 2007 dollars, with annual adjustment of 2.5%: Energy: $98.93/MWh; Capacity: $70.23/kW-per year; RECs: $15.32 per REC, times the percent credit Delmarva receives toward meeting RPS requirements. Up to $235.70/MWh, depending on total facility cost; annual escalation of 3.5% begins in 2013. Term 25 years Contract Capacity Up to 200 MW Project Size 200 MW to 600 MW Deadline for Commercial Operation December 1, 2016 (L/Ds payable after this date); May 1, 2018 (PPA may be terminated). December 31, 2012 (can be extended by Deepwater until December 31, 2017). December 31, 2015 (can be extended by Cape Wind until December 31, 2017). 5 ½ years following contract date.

RI

Deepwater Wind

National Grid

20 years

Up to 30 MW

Up to 30 MW

MA

Cape Wind

National Grid

$187/MWh in 2013, escalating annually by 3.5% thereafter.

15 years

50% of project capacity (468 MW)

468 MW

Ontario

Qualifying Owners of Ontario projects

Ontario Power Authority (Feed-in Tariff)

C$190/MWh in 2010, subject to escalation based on CPI.

20 years

>10 kW

N/A

Source: Mary Ann Christopher and Tom Mullooly, "Early Offshore Wind PPAs Have Influential Supporters," North American Windpower, p. 58-64.

Because of the relative newness of the off-shore wind industry and the lack of planned or operating off-shore wind projects with available data, the cost and performance estimates should be viewed as exhibiting greater uncertainty than the on-shore estimates. NREL estimates the installed capital cost for off-shore wind projects at $4,260 per kW, but there is a wide range among individual projects, from $2,000 per kW and $6,390 per kW among planned and operating off-shore wind projects in Europe and in the United States. Adding to the uncertainty, all planned and operating off-shore wind projects around the world are operating in shallow water (up to 30 meters in depth), but that will change over time as projects move further off-shore. Future cost reductions in off-shore wind capital costs from technological improvements and economies of scale may be partially or fully offset by higher costs of moving further off-shore and developing in deeper ocean waters, although the small number of projects in operation or under development makes it difficult to estimate or quantify this in any meaningful detail.

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Table 11: Estimation Methodologies for Future Offshore Wind Project Costs (2008 US$)

Metric for Calculation of Future Offshore Arithmetic Mean Capacity-Weighted Wind Project Cost (US$/kW) Average (US$/kW) Installed 2009 projects 4,252 3,964 Proposed 2010 projects 3,965 3,905 Proposed U.S. projects 2010-2015 4,191 3,921 Proposed European projects 2010-2015 4,411 4,431 Proposed projects 2010-2015 4,327 4,259 Source: Walter Musial and Bonnie Ram. Large-Scale Offshore Wind Power in the United States: Executive Summary, National Renewable Energy Laboratory, September 2010. http://www.nrel.gov/docs/fy10osti/49229.pdf.

Based on interviews with off-shore wind power developers, NREL expects future capital costs of off-shore wind projects to stabilize or rise slightly from current levels. Therefore, PPRP adopted the average capital cost estimate of $4,260 per kW for off-shore wind. Capacity Factor: Capacity factors of off-shore wind projects are estimated to range between 35 percent and 50 percent. In making resource estimates of potential off-shore wind capacity in the United States, NREL relied upon an assumed capacity factor of 37 percent. For purposes of the LTER, we rely on an assumed capacity factor of 40 percent, which is held constant over the 20-year study period. The three-percentage point increase to the NRELassumed value of 37 percent was adopted to recognize the potential for future wind turbine efficiency gains over the study period and also to account for the high degree of uncertainty surrounding estimated capacity factors.. O&M Costs: O&M costs are higher for off-shore wind projects relative to on-shore wind projects because it is more complex and costly to perform work at sea than on land. The NREL report estimates that off-shore O&M costs are two to three times higher than those of on-shore wind turbines. Based on the NREL analysis, we propose to rely on an on-shore O&M cost multiple of 2.5, which results in an off-shore annual O&M cost estimate of $73.88 per kW. Solar Photovoltaic ­ The development of forecast assumptions for future PV projects are based largely on discussions and interviews with industry experts. Capital Costs: The capital costs of PV projects have been decreasing rapidly in recent years. Recent consultations with industry experts suggest that the capital costs for groundmounted, utility-scale PV projects are approximately $5,000 per kW and can be expected to decline to $4,000 per kW over the next ten years. Based on the assimilation of that information, we have assumed that utility-scale PV projects will have an associated capital cost of $5,000 per kW in 2010 and declining linearly to $4,000 per kW by 2020, remaining constant in real terms thereafter. Capacity Factor: Recent discussions with industry experts suggest that the capacity factor for ground-mounted PV systems in the mid-Atlantic will be about 13 percent; a single-axis tracking system would increase the capacity factor to 17 percent. Because there may be a mix

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of ground-mounted and single-axis tracking PV systems developed, a capacity factor of 15 percent has been adopted for the LTER. O&M Costs: The Ventyx integrated models employ an annual O&M estimate of $12.55 per kW. The information that we have obtained through discussion with industry experts is roughly in line with the Ventyx figure, and we anticipate adopting the $12.55-per-kW Ventyx estimate of solar PV annual O&M costs.

Calvert Cliffs Nuclear Unit No. 3

For those scenarios that include Calvert Cliffs Unit No. 3, the following assumptions regarding that unit are: In-service date: Capital Cost: Capacity: 2019 $10.0 billion 1,600 MW

Environmental Policies and the Renewable Energy Portfolio Standard National Carbon Legislation

The assumptions regarding national carbon legislation were developed by Ventyx and include the following principal parameters: Initial year: Type of program: Offsets allowed: Price of allowances: 2015 Cap and Trade (similar to Waxman/Markey and Kerry/Lieberman 2 billion tons $16/ton (in $2010) of CO2 in 2015, increasing by $1/year through 2023, then increasing an average by approximately $4.50/year through 2030, for a maximum allowance of $54/ton ($2010) of CO2 in 2030.

Renewable Energy Portfolio Standard

Maryland's Renewable Energy Portfolio Standard (RPS) has undergone modification several times since its enactment in 2004. These modifications have included: (1) reducing the scope of the geographical area for eligible renewables, (2) establishing a separate requirement for solar photovoltaic energy, and (3) changing the annual solar requirements and solar alternative compliance payments. A full discussion of the Maryland RPS is contained in the Renewable Energy Portfolio Standard White Paper is Support LTER Assumptions (November 30, 2010). As explained in the White Paper, the relevant RPS assumptions are: Tier 1 Solar Energy Resources in Maryland currently generate approximately 8 GWh of electricity per year. Solar electricity output is expected to increase to 720 GWh by 2022.

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Development of several large utility-scale solar projects will produce sufficient electricity to meet the Tier 1 Solar RPS in the short term (2011 ­ 2018). However, while a significant amount of new solar capacity is installed, only 50 percent of the 2022 Tier 1 Solar requirement is likely to be met. Thus the input assumption is that there is sufficient solar capacity to meet the Maryland RPS up through 2018. Tier 1 Non-Solar Energy Resources in PJM currently generate approximately 20,100 GWh of electricity per year which is more than enough to supply the regional 2010 Tier 1 Non Solar renewable energy requirements established in Maryland and those of the PJM state's with similar renewable energy portfolio standards. Development of Tier 1 Non Solar renewable resources are assumed to keep pace with demand so that the region's RPS requirements are met throughout the study period (2010-2030). Tier 2 Energy Resources in PJM currently generate approximately 18,000 GWh of electricity per year, which is more than enough to supply the regional Tier 2 renewable energy requirements established in Maryland and those of the PJM state's with similar renewable energy portfolio standards. Very little new Tier 2 generation is required to meet the regional requirements throughout the study period. The high renewable energy scenario is based the assumption that all existing state RPS requirements (i.e., for all states having an RPS) are achieved (including solar requirements), with the addition of a federal renewable energy requirement. In those instances where the federal requirement is less than the state requirement, it is assumed that the state requirement remains in effect and continues to be met. The Federal RPS is set at 7 percent in 2015, increasing 1 percent per year to 12 percent by 2020 and staying at 12 percent for utilities serving greater than 4,000 GWh of annual energy (accounts for about 80 percent of retail sales).

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APPENDIX

Table A1 Henry Hub Price Average and Maximum Monthly Prices (2010 $/MMBtu) Low Base High Average Max Average Max Average Max Year

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 $3.56 $3.84 $3.94 $4.16 $4.43 $4.59 $4.74 $4.75 $4.76 $4.75 $4.74 $4.73 $4.67 $4.66 $4.70 $4.67 $4.61 $4.58 $4.60 $4.63 $3.97 $4.12 $4.36 $4.61 $4.93 $5.09 $5.21 $5.24 $5.16 $5.12 $5.15 $5.10 $5.00 $5.04 $5.01 $4.97 $4.93 $4.87 $4.86 $4.90 $4.46 $4.89 $5.09 $5.46 $5.90 $6.22 $6.53 $6.75 $6.98 $7.09 $7.13 $7.16 $7.12 $7.16 $7.36 $7.46 $7.52 $7.61 $7.80 $8.01 $4.98 $5.24 $5.63 $6.05 $6.57 $6.90 $7.18 $7.44 $7.57 $7.64 $7.75 $7.72 $7.63 $7.75 $7.86 $7.94 $8.03 $8.09 $8.23 $8.48 $5.50 $6.09 $6.41 $6.93 $7.57 $8.05 $8.53 $8.90 $9.28 $9.52 $9.66 $9.78 $9.82 $9.95 $10.32 $10.55 $10.72 $10.95 $11.30 $11.70 $6.15 $6.53 $7.09 $7.69 $8.42 $8.93 $9.37 $9.81 $10.07 $10.26 $10.49 $10.55 $10.52 $10.77 $11.02 $11.23 $11.45 $11.63 $11.93 $12.39

18

Table A2 Average Delivered Coal Price Forecast (2010 $/MMBtu)

Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 PJM AEP $2.32 $2.32 $2.34 $2.36 $2.36 $2.38 $2.38 $2.37 $2.38 $2.37 $2.39 $2.39 $2.40 $2.39 $2.40 $2.40 $2.41 $2.40 $2.38 $2.40 PJM APS $2.32 $2.33 $2.35 $2.35 $2.32 $2.32 $2.30 $2.30 $2.30 $2.31 $2.32 $2.32 $2.32 $2.32 $2.33 $2.33 $2.34 $2.35 $2.34 $2.35 PJM COMED $1.58 $1.60 $1.66 $1.65 $1.71 $1.74 $1.78 $1.79 $1.83 $1.82 $1.84 $1.84 $1.88 $1.86 $1.86 $1.85 $1.85 $1.84 $1.80 $1.78 PJM South $2.85 $2.85 $2.86 $2.91 $2.91 $2.96 $2.95 $2.94 $2.95 $2.97 $2.97 $2.98 $2.99 $2.99 $3.00 $3.01 $3.02 $3.03 $3.02 $3.03 PJM MA-East $3.00 $3.02 $3.07 $3.12 $3.13 $3.15 $3.12 $3.11 $3.11 $3.12 $3.13 $3.14 $3.16 $3.16 $3.17 $3.18 $3.19 $3.19 $3.17 $3.18 PJM MA E-PA $2.77 $2.75 $2.79 $2.76 $2.77 $2.76 $2.75 $2.73 $2.75 $2.75 $2.77 $2.76 $2.77 $2.77 $2.77 $2.76 $2.77 $2.78 $2.77 $2.78 PJM MA SW $2.89 $2.89 $2.90 $2.90 $2.88 $2.86 $2.86 $2.84 $2.85 $2.86 $2.87 $2.86 $2.88 $2.87 $2.89 $2.88 $2.90 $2.90 $2.88 $2.90 PJM MA W PA $2.42 $2.43 $2.61 $2.63 $2.61 $2.60 $2.58 $2.57 $2.56 $2.57 $2.58 $2.57 $2.58 $2.58 $2.58 $2.58 $2.60 $2.60 $2.58 $2.59

Note MA denotes MidAtlantic

Table A3 Average Annual Fuel Oil Price (2010 $/MMBtu) Average of No. 6 ­ 0.3% S $10.06 $10.22 $10.33 $10.65 $10.86 $11.05 $11.18 $11.28 Average of No. 6 ­ 0.7% S $10.03 $10.18 $10.30 $10.61 $10.82 $11.00 $11.14 $11.23 Average of No. 6 ­ 1% S $10.00 $10.15 $10.27 $10.58 $10.79 $10.97 $11.10 $11.20 Average of No. 6 ­ 2% S $9.71 $9.85 $9.97 $10.27 $10.48 $10.65 $10.78 $10.88 Average of No. 2 (Distillate) $15.69 $15.94 $16.13 $16.64 $16.98 $17.27 $17.49 $17.64 Average of Kerosene/ Jet Fuel $17.45 $17.72 $17.93 $18.49 $18.87 $19.19 $19.42 $19.59

Year 2011 2012 2013 2014 2015 2016 2017 2018 2030

19

Table A4 Nuclear Fuel Prices

Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2010 $/MMbtu $0.75 $0.78 $0.79 $0.78 $0.78 $0.80 $0.81 $0.80 $0.79 $0.77 $0.74 $0.73 $0.71 $0.70 $0.68 $0.66 $0.65 $0.65 $0.65 $0.66

20

Table A5 Cost and Operational Assumptions of New Generation Over the Forecast Period

Forced Outage Rate % 6.0% 3.6% 3.6% 5.5% 6.0% 3.8% Maintenance Outage Rate (MOR) % 6.5% 4.1% 4.1% 4.1% 6.5% 6.1% Overnight Construction Cost 2010 $/kW $2,660 $660 $1,020 $970 $3,360 $5,870

Unit Type

Summer Capacity MW 800 160 90 450 600 1,000

Capacity Factor

Pulverized Coal Steam Turbine Combustion Gas Turbine Aeroderivative Gas Turbine Combined Cycle Integrated Coal Gasification Combined Cycle Nuclear Pulverized Coal Steam Turbine with Carbon Capture and Sequestration Combined Cycle with Carbon Capture and Sequestration Integrated Coal Gasification CC w\ Carbon Capture and Sequestration Geothermal Steam Turbine Landfill Gas Biomass Photovoltaic Wind Turbine - On Shore (2010) Wind Turbine - On-Shore (20112030) Wind Turbine - Off-Shore

PC GT AD CC IG NU PCCCS CCCCS IGCCS GE LG BM PV WT

Full Load Heat Rate HHV, Btu/kWh 8,600 10,500 9,000 6,800 8,300 10,400

Fixed O&M 2010 $/kW-yr $26.95 $12.60 $10.95 $13.00 $47.30 $70.55

Variable O&M 2010 $/MWh $4.00 $3.75 $3.30 $2.15 $4.65 $0.55

540 310 410 10 10 10 10 10

11,200 8,900 10,800 10,000 10,000 10,000 -

$32.15 $22.10 $56.40 $169.85 $119.72 $70.23 $12.55 $29.55 $29.55 $73.88

$6.15 $3.15 $7.10 $0.00 $0.01 $7.21 $0.00 $0.00 $0.00 $0.00

7.0% 6.5% 7.0% 20.0% 30.0% 30.0% 0.0% 0.0%

7.5% 5.0% 7.5% 0.0% 0.0% 0.0% 0.0% 0.0%

$5,089 $2,134 $5,649 $1,900 $2,550 $3,300 $5,000* $2,200 $1,800 $4,260

15% 28% 28% 37%

*Declines linearly to $4,000/kW in 2030.

21

Table A6 CO2 Emission Prices (2010 $/ton) National RGGI Carbon Policy Year 2011 2 0 2012 2 0 2013 2 0 2014 2 0 2015 2 16 2016 2 17 2017 2 18 2018 2 19 2019 2 20 2020 2 21 2021 2 22 2022 2 23 2023 2 24 2024 2 26 2025 2 30 2026 2 35 2027 2 38 2028 2 42 2029 2 46 2030 2 54

22

Figure A1- 2010 EIA Annual Energy Outlook Forecast for Henry Hub Natural Gas

$10.00 $9.00 $8.00 $7.00

2010 $ MMBtu

$6.00 $5.00 $4.00 $3.00

Reference

$2.00 $1.00 $0.00

High

Low

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

23

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