Ten-Year Plan (2011-2020) of Electric Companies in Maryland

PUBLIC SERVICE COMMISSION

OF MARYLAND

TEN-YEAR PLAN

(2011 – 2020)

OF ELECTRIC

COMPANIES

IN MARYLAND

Prepared for the

Maryland Department of Natural Resources

In compliance with Section 7-201

of the Maryland Public Utilities Article

February 2012

State of Maryland

Public Service Commission

Douglas R. M. Nazarian, Chairman

Harold D. Williams, Commissioner

Lawrence Brenner, Commissioner

Kelly Speakes-Backman, Commissioner

W. Kevin Hughes, Commissioner

David J. Collins Gregory V. Carmean H. Robert Erwin

Executive Secretary Executive Director General Counsel

6 St. Paul Street

Baltimore, MD 21202

Tel: (410) 767-8000

www.psc.state.md.us

This report was drafted by the Commission’s Energy Analysis and Planning Division (Crissy Godfrey,

Director), in cooperation with the Engineering Division (Jerry Hughes, Chief Engineer). Electric

companies under the Commission’s jurisdiction provided most of the data in the Appendix.

TABLE OF CONTENTS

I. INTRODUCTION ...............................................................................................................................1

II. MARYLAND UTILITY AND PJM ZONAL LOAD FORECASTS...............................................3

A. Introduction...................................................................................................................................... 3

B. PJM Zonal Forecast.......................................................................................................................... 4

C. Maryland Company Forecasts.......................................................................................................... 5

III. REGIONAL GENERATION AND SUPPLY ADEQUACY IN MARYLAND..............................7

A. Introduction...................................................................................................................................... 7

B. Maryland Generation Profile: Age and Fuel Characteristics........................................................... 9

C. Potential Generation Additions in Maryland.................................................................................. 13

D. CPCN Exemptions for Generation................................................................................................. 15

IV. TRANSMISSION INFRASTRUCTURE: PJM, MARYLAND, AND NATIONAL...................19

A. Introduction.................................................................................................................................... 19

B. Eastern Interconnection Planning Collaborative............................................................................ 19

C. The Regional Transmission Expansion Planning Protocol ............................................................ 20

D. Transmission Congestion in Maryland........................................................................................... 22

E. High Voltage Transmission Lines in PJM ..................................................................................... 24

V. DEMAND RESPONSE AND CONSERVATION AND ENERGY EFFICIENCY....................26

A. Statutory Requirements.................................................................................................................. 26

B. Demand Response Initiatives......................................................................................................... 28

C. Energy Efficiency and Conservation Programs ............................................................................. 34

D. Advanced Metering Infrastructure / Smart Grid ............................................................................ 37

E. Mid-Atlantic Distributed Resources Initiative ............................................................................... 42

VI. ENERGY, THE ENVIRONMENT, AND RENEWABLES...........................................................42

A. The Regional Greenhouse Gas Initiative........................................................................................ 42

B. The Renewable Energy Portfolio Standard Program ..................................................................... 44

C. Solar Power Requirements in Maryland ........................................................................................ 49

VII. ELECTRIC DISTRIBUTION RELIABILITY IN MARYLAND.................................................51

A. Electric Distribution Reliability Reporting, Operation and Maintenance ...................................... 51

B. Distribution Reliability Issues........................................................................................................ 53

C. Managing Distribution Outages ..................................................................................................... 58

D. Distribution Planning Process........................................................................................................ 60

VIII. MARYLAND ELECTRICITY MARKETS....................................................................................63

A. Status of Retail Electric Choice in Maryland................................................................................. 63

B. Standard Offer Service................................................................................................................... 65

IX. REGIONAL ENERGY ISSUES AND EVENTS ............................................................................66

A. Overview of PJM, OPSI, and Reliability First............................................................................... 66

B. PJM Summer Peak Events of 2010 and 2011 ................................................................................ 68

C. PJM’s Reliability Pricing Model.................................................................................................... 69

D. Region-Wide Demand Response in PJM Markets......................................................................... 71

X. PROCEEDINGS BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION.....72

APPENDIX

Table A-1: Utilities Providing Retail Electric Service in Maryland................................. 74

Table A-2: Number of Customers by Customer Class as of December 31, 2010............ 75

Table A-3: Typical Monthly Electric Bills in Maryland (Winter 2010)........................... 76

Table A-4(a): System Wide Peak Demand Forecast as of December 31, 2010 (MW) (Net

of DSM Programs).................................................................................................... 77

Table A-4(b): Maryland Peak Demand Forecast as of December 31, 2010 (MW) (Net of

DSM Programs)........................................................................................................ 78

Table A-4(c): System Wide Peak Demand Forecast as of December 31, 2010 (MW)

(Gross of DSM Programs) ........................................................................................ 79

Table A-4(d): Maryland Peak Demand Forecast as of December 31, 2010 (MW) (Gross

of DSM Programs).................................................................................................... 80

Table A-5(a): System Wide Energy Sales Forecast (GWh) (Net of DSM Programs)...... 81

Table A-5(b): Maryland Energy Sales Forecast (GWh) (Net of DSM Programs) ........... 82

Table A-6: Maryland Licensed Electric/Natural Gas Suppliers and Brokers as of

December 1, 2011..................................................................................................... 83

Table A-7: Transmission Enhancements by Service Area ............................................... 89

Table A-8: Renewable Projects Providing Capacity and Energy to Maryland Customers

as of December 31, 2010 .......................................................................................... 94

Table A-9: Power Plants in the PJM Process for New Electric Generating Stations in

Maryland as of December 31, 2010.......................................................................... 95

LIST OF MAPS, FIGURES, TABLES, AND CHARTS

Map I.1: Maryland Utilities and their Service Territories in Maryland............................. 2

Figure II.A.1: PJM Maryland Forecast Zones................................................................... 3

Table II.B.1: Summer Peak Load (MW) Growth Rates .................................................... 4

Table II.B.2: Winter Peak Load (MW) Growth Rates....................................................... 5

Table II.C.1: Comparison of Maryland Peak Demand Forecasts....................................... 6

Table II.C.2: Comparison of Maryland Energy Sales Forecast.......................................... 6

Table III.A.1: State Electricity Imports (Year 2009) (GWh)............................................. 8

Table III.B.1: Maryland Generating Capacity Profile (Year 2010)................................... 9

Table III.B.2: Maryland Electric Power Generation Profile (Year 2009) ....................... 11

Table III.B.3: Generation by Owner, County, and Capacity (Year 2010)....................... 12

Table III.C.1: PJM Transmission Queue Active New Generating Capacity................... 15

Table III.D.1: Construction Approvals for CPCN Exempt Generation........................... 17

Table III.D.2: Number and Capacity in MW of CPCN Exempt Generating Units by

Energy Resource....................................................................................................... 18

Table V.B.1: Utilities’ Incentives to DLC Program Participants .................................... 29

Table V.B.2: Utilities’ Direct Load Program Installations; Program-to-Date as of

December 31, 2010................................................................................................... 30

Table V.B.3: Direct Load Control Program Bids into PJM BRA (MW) ........................ 30

Table V.B.4: Peak Load Reduction Forecast (MW)........................................................ 34

Table VI.A.1: Annual State CO

Allowance Budgets (2009 – 2014).............................. 43

Table VI.B.1: Eligible Tier 1 and Tier 2 Renewable Resources ..................................... 45

Table VI.B.2: Annual RPS Percentage Requirements by Tier........................................ 46

Table VI.B.3: RPS Alternative Compliance Fee Schedule ($/MWh) ............................. 47

Table VI.B.4: RPS Supplier Annual Report Results as of December 31, 2010.............. 48

Chart VI.B.5: Maryland RPS Eligible Capacity by State................................................ 49

Table VIII.A.1: Residential Customers Enrolled in Retail Supply.................................. 64

Table VIII.A.2: Electric Choice Enrollment in Maryland as of September 30, 2011 ..... 65

Table IX.B.1: Summer 2010 and 2011 Coincident Peaks and Zone LMP...................... 69

Table IX.C.1: RPM “Net Load” Price and Cost.............................................................. 71

iii

LIST OF ACRONYMS AND DEFINITIONS USED

ACP Alternative Compliance Penalty

AMI Advanced Metering Infrastructure

ARR Auction Revenue Right

ARRA American Recovery and Reinvestment Act of 2009

BGE Baltimore Gas and Electric Company

BRA Base Residual Auction

C&I Commercial and Industrial

CAIDI Customer Average Interruption Duration Index

CETL Capacity Emergency Transfer Limit

CETO Capacity Emergency Transfer Objective

CIS Customer Information System

Carbon Dioxide

CPCN Certificate of Public Convenience and Necessity

CSP Curtailment Service Provider

DLC Direct Load Control

DOE United States Department of Energy

DPL Delmarva Power & Light Company

DR Demand Response or Demand Resource

DSM Demand-Side Management

DY Delivery Year

EDC Electric Distribution Company

EE&C Energy Efficiency and Conservation

EFORd Equivalent Demand Forced Outage Rate

EIA Energy Information Administration

EIPC Eastern Interconnection Planning Collaborative

EISA Energy Independence and Security Act of 2007

EISPC Eastern Interconnection State Planning Council

ELRP Economic Load Response Program

EMAAC Eastern Mid-Atlantic Area Council

EMS Energy Management System

EM&V Evaluation, Measurement, and Verification

EPA United States Environmental Protection Agency

ETR Estimated Time of Restoration

FERC Federal Energy Regulatory Commission

FTR Financial Transmission Right

GATS Generation Attributes Tracking System

GIS Geographic Information System

GW/GWh Gigawatt/Gigawatt-hours

HVAC Heating, Ventilation, and Air Conditioning

HVCS High Volume Call Service

HVDC High Voltage Direct Current

IOU Investor-Owned Utility

IRM Installed Reserve Margin

ISAC Independent State Agency Committee

ISO Independent System Operator

IVR Interactive Voice Response

kV Kilovolt

kW/kWh Kilowatt/Kilowatt-hours

LDA Load Deliverability Area

LMP Locational Marginal Price

LSE Load Serving Entity

MAAC Mid-Atlantic Area Council

MADRI Mid-Atlantic Distributed Resources Initiative

MAPP Mid-Atlantic Power Pathway

MDE Maryland Department of the Environment

MDS Mobile Dispatch System

MEA Maryland Energy Administration

MW/MWh Megawatt/Megawatt-hours

NERC North American Electric Reliability Council

O&M Operation and Maintenance

OATT Open Access Transmission Tariff (PJM)

OMS Outage Management System

OPC Office of People’s Counsel (Maryland)

OPSI Organization of PJM States, Inc.

PATH Potomac-Appalachian Transmission Highline

PE The Potomac Edison Company

Pepco Potomac Electric Power Company

PJM PJM Interconnection, LLC (Pennsylvania-Jersey-

Maryland)

PJM-EIS PJM – Environmental Information Services, Inc

PSC/ MD PSC Maryland Public Service Commission

PTR Peak-Time Rebate

PUA Public Utilities Article, Annotated Code of Maryland

REC Renewable Energy Credit

RFP Request for Proposal

RGGI Regional Greenhouse Gas Initiative

RPM Reliability Pricing Model (PJM)

RPS Renewable Energy Portfolio Standard

RTEP Regional Transmission Expansion Plan

RTO Regional Transmission Organization

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SCADA Supervisory Control and Data Acquisition

SEIF Maryland Strategic Energy Investment Fund

SGIG Smart Grid Investment Grant

SMECO Southern Maryland Electric Cooperative, Inc.

SOS Standard Offer Service

SWMAAC Southwest Mid-Atlantic Area Council

TEAC Transmission Expansion Advisory Committee (PJM)

TrAIL Trans-Allegheny Interstate Line

WMS Work Management System

I. INTRODUCTION

Section 7-201 of the Public Utilities Article, Annotated Code of Maryland

(“PUA”), requires the Maryland Public Service Commission (“Commission” or “PSC” or

“MD PSC”) to forward a Ten-Year Plan of Electric Companies in Maryland (“Ten-Year

Plan”) to the Secretary of Natural Resources on an annual basis. This report constitutes

that effort for the 2011 – 2020 timeframe and, with exceptions as noted in the text, the

referenced data and information is as it existed as of December 31, 2010. It is a

compilation of information on long-range plans of Maryland electric utilities. This report

also includes summaries of events that have affected or may affect the electric utility

industry in Maryland in the near future.

A principal focus of the Commission is the reliability of Maryland’s electricity

supply, delivered at reasonable rates. Achieving reliability is a complex undertaking

which requires consideration of factors affecting both supply and demand. To address

these elements the Commission is taking action on several fronts: challenging wholesale

power policies at the Federal Energy Regulatory Commission (“FERC”); working with

the wholesale independent market monitor to effectuate positive market results;

evaluating the need for procuring new generation in the State; directing new utility

investment in demand response programs to reduce peak electricity demand; evaluating

conservation and energy efficiency programs to meet EmPower Maryland peak and

overall energy reductions;

and encouraging better use of emergency generation within

the State to promote adequate, economical, and efficient delivery of electricity services.

Section II of this plan addresses the peak demand load forecast for Maryland and

establishes the baseline load requirements for the next ten years. Section III provides

information on generation, including certificates of public convenience and necessity

(“CPCNs”), and forecasts the availability of generation to meet load requirements.

Section IV reviews transmission issues impacting Maryland, including the Department of

Energy’s National Interest Electric Transmission Corridors. Section V addresses the

options of energy efficiency, conservation, and demand response as part of Maryland’s

supply resources, and discusses the effort required to meet EmPower Maryland goals.

Proposals to deploy advanced metering infrastructure also are discussed in this section.

Because environmental issues continue to play an increasingly important role in energy

decisions, Section VI discusses Maryland’s involvement in the Regional Greenhouse Gas

Initiative and other issues involving the impact of renewable generation growth. Section

VII provides information on distribution reliability, the manner in which utilities have

managed outages, and how utilities plan to meet load requirements.

Beginning with Section VIII, we broaden our perspective and review Maryland’s

Electricity Market in general terms and its relation to Commission efforts that are

currently underway or anticipated. Section IX discusses PJM Interconnection, LLC

See EmPower Maryland Energy Efficiency Act of 2008, codified within MD. CODE ANN., PUB.

UTIL. § 7-211 (2011) (“EmPower Maryland”).

(“PJM”)

and the impact that market rule changes have had both regionally and in

Maryland. Section X reviews national issues and the impact generated by FERC rulings

and U.S. Department of Energy actions. Also included in the Ten-Year Plan is an

Appendix that contains a compilation of data provided by Maryland’s utilities

summarizing, among other things, demand and anticipated sales over the next 15 years.

Maryland is geographically divided into thirteen electric utility service territories.

Four of the largest are investor-owned utilities (“IOUs”), four are electric cooperatives

(two of which serve only small areas of Maryland), and five are electric municipal

operations.

Table A-1 in the Appendix lists the utilities providing retail electric service

in Maryland and Map I.1 below provides a geographic picture of the utilities’ service

territories.

Map I.1: Maryland Utilities and their Service Territories in Maryland

Source: Cumulative Environmental Impact Report 15, MD. DEP’T OF NATURAL RES., Figure 2-12,

http://esm.versar.com/pprp/ceir15/Report_2_3.htm (last updated Feb. 25, 2010).

PJM is a regional transmission organization that coordinates the movement of wholesale

electricity in all or parts of 13 states and the District of Columbia.

The St. Michaels Utilities Commission service territory was transferred to Choptank Electric

Cooperative, Inc. in October 2006.

The Potomac Edison Company no longer uses its “doing business name” of “Allegheny Power”

and any references within the Ten-Year Plan to Allegheny Power should be read as referencing

Potomac Edison.

II. MARYLAND UTILITY AND PJM ZONAL LOAD FORECASTS

A. Introduction

The foundation of an analysis for meeting Maryland’s electricity needs starts with

a forecast of the anticipated demand over a relevant planning horizon. The Commission

routinely evaluates forecasts from individual utilities, as well as the PJM forecast, which

provides separate estimates for the transmission zones shown in Figure II.A.1.

Figure II.A.1: PJM Maryland Forecast Zones

Source: PJM Load Forecast Report, PJM PLANNING (Jan. 2011),

http://www.pjm.com/planning/resource-adequacy-planning/~/media/documents/reports/2011-pjm-

load-report.ashx.

PJM sub-regions, known as zones, generally correspond with the IOU service

territories. The PJM zones include adjacent municipal and rural electric cooperatives. The

four IOUs operating in Maryland are Baltimore Gas and Electric Company (“BGE”),

Potomac Electric Power Company (“Pepco”), Delmarva Power & Light Company

(“DPL” or “Delmarva”), and The Potomac Edison Company (“PE”). PJM zones for

three of the four IOUs traverse state bounds and extend into other jurisdictions. Pepco,

DPL, and PE company data are a subset of the PJM zonal data, since PJM’s zonal

forecasts are not limited to Maryland. The BGE zone, alone, resides solely within the

State of Maryland.

PJM operates the wholesale power market that includes the entire mid-Atlantic

region and dispatches power plants to serve load on an economic bid basis, subject to

transmission capacity availability. PJM’s load forecasts drive the need for generation,

which impacts electric consumer prices at the retail level. The Commission closely

monitors the development of PJM regional forecasts.

While forecasts can rely on similar economic data, projections of peak demand

and energy usage can vary based upon the underlying assumptions used to generate the

forecasts. In general, the expected growth in peak demand and electricity usage is due

primarily to expected increases in population and economic activity, which have a direct

impact on electricity consumption levels. Key forecast variables include economic and

non-economic variables. Economic variables used in forecast models can include gross

domestic product, employment, energy prices, and population. Non-economic variables

can include weather normalized variables, monthly seasonal variables, ownership of

appliances, and building codes.

B. PJM Zonal Forecast

PJM’s 2011 Load Forecast Report includes long-term forecasts of peak loads and

net energy for the entire wholesale market region and each PJM sub-region (i.e., zone) –

including the four sub-regions in which Maryland resides.

The 2011 Load Forecast

Report concludes that the PJM region will, in aggregate, experience higher peak usage in

the summer throughout the forecast period ending 2026.

Tables II.B.1 and II.B.2

present comparisons in expected growth for the four PJM zones containing Maryland.

The 2011 Load Forecast is compared to the 2009 and 2010 Load Forecasts on a very

broad macro level for the four PJM regions roughly corresponding with the four IOU

service territories that serve Maryland. When compared, the 2011 Load Forecast shows

significant reductions in both Summer and Winter peak demand growth rates from the

previous year’s Load Forecast. The PJM zones containing BGE, DPL, and Pepco

experience their peak demands during the summer while the PJM region containing PE

experiences peak demands in the winter.

Table II.B.1: Summer Peak Load (MW) Growth Rates

PJM Zone

2009-2019* 2010-2020** 2011-2021***

PE 1.5% 1.4% 1.0%

BGE 1.8% 1.8% 1.3%

DPL 2.1% 1.4% 1.1%

Pepco 1.2% 1.2% 1.0%

PJM Load Analysis Subcommittee, PJM, available at: http://www.pjm.com/committees-and-

groups/subcommittees/las.aspx.

PJM Load Forecast Report, PJM, 37 (January 2011), available at:

http://www.pjm.com/committees-and-groups/subcommittees/~/media/documents/reports/2011-

pjm-load-report.ashx. The PJM RTO summer peak is forecasted to be 182,904 MW in 2026, a 15-

year increase of 28,521 MW. Id.

For Maryland, the four PJM regions contain all four of the State’s investor-owned utilities, the five

municipal systems, and Maryland’s four rural electric cooperatives. Id.

Id.

Table II.B.2: Winter Peak Load (MW) Growth Rates

PJM Zone 2009-2019* 2010-2020** 2011-2021***

PE 1.3% 1.3% 1.0%

BGE 1.0% 1.1% 0.8%

DPL 1.5% 1.0% 0.8%

Pepco 1.1% 1.2% 1.0%

Sources: * PJM Load Forecast Report, January 2009, Tables B-1 and B-2.

** PJM Load Forecast Report, January 2010, Tables B-1 and B-2.

***PJM Load Forecast Report, January 2011, Tablets B-1 and B-2.

C. Maryland Company Forecasts

Maryland’s electric utilities annually submit responses to Commission data

requests that include forecasts of peak and annual energy demand. The forecast

information provided by each company is summarized in the Appendices as Tables A-

4(a) – (d) and Tables A-5(a) – (b). Data requests for the current Ten-Year Plan include

responses that expand beyond a ten-year period – from 2011 through 2025. The prior

year’s submissions began and terminated one year earlier, that is, from 2010 through

2024. A comparison of the electric utility submissions for the first and last years of the

forecast period is provided to indicate, on an aggregate basis, current expectations for

peak usage in the State for electricity. The utility forecasts reflect: short-term

recessionary impacts, the utilities’ current expectations with regard to nascent demand-

side management (“DSM”) and energy efficiency programs, and the expected reductions

in energy usage attributable to these programs. Precision and certainty diminish the

longer the time period over which a forecast is generated. Comparisons are first

presented for the State in aggregate for four common future years: 2011, 2016, 2021, and

2024.

Additional analysis pertaining to 2011 and the period 2011 through 2021 also are

explored.

Table II.C.1 compares Maryland peak demand forecasts on an aggregate basis and

includes utility-provided estimates of currently-approved DSM and energy efficiency

measures. Actual peak demand in 2011 net of DSM programs compared to the 2010

forecasted peak demand net of DSM programs indicates that peak demand increased by

1.1%. Peak demand forecasts for this Ten-Year Plan period compared to the 2010 – 2019

Ten-Year Plan forecasted peak demand indicate that peak demands are estimated to

increase by 0.7% in 2016, 0.7% in 2021, and 0.8% in 2024.

Additional data for the 2011 to 2025 period can be located in Tables A-4 and A-5 of this Ten-Year

Plan Appendix. Corresponding data considering the 2010 to 2024 time period can be located in

last year’s Ten-Year Plan Appendix Tables A-5 and A-6.

Increases are a comparison strictly to last year’s submissions and not considered on a per capita

basis in keeping with the goals of EmPower Maryland.

Table II.C.1: Comparison of Maryland Peak Demand Forecasts

(Net of DSM Programs; MW)

2010 - 2019 2011 - 2020

Ten-Year Plan Ten-Year Plan

2011

13,638 13,786 148 1.1

2016

13,812 13,914 102 0.7

2021

14,801 14,900 99 0.7

2024

15,381 15,511 130 0.8

Year Change %

Sources: Ten-Year Plan (2010-2019) of Electric Companies in Maryland, MD PSC,

6 (Aug. 2011), available at: http://webapp.psc.state.md.us/Intranet/Reports/2010-

2019%20Ten%20Year%20Plan.pdf. See Appendix Table A-4(b).

Table II.C.2 compares utility forecasted energy sales within the State of

Maryland. When compared to utility estimates provided last year, the electric utility

forecasts, in aggregate, project additional increases in overall annual electricity sales in

the State. During the timeframe examined, increases in energy usage trend upward

between 0.6% and 1.4% when compared to last year’s electric utility submissions.

Table II.C.2: Comparison of Maryland Energy Sales Forecast

(Net of DSM Programs; GWh)

2010 - 2019 2011 - 2020

Ten-Year Plan

(GWh)

Ten-Year Plan

(GWh)

2011

63,651 64,012 361 0.6

2016

66,954 66,887 -67 -0.1

2021

71,111 72,056 945 1.3

2024

73,848 74,865 1,017 1.4

Year Change %

Sources: Ten-Year Plan (2010-2019) of Electric Companies in Maryland, MD PSC,

6 (Aug. 2011), available at: http://webapp.psc.state.md.us/Intranet/Reports/2010-

2019%20Ten%20Year%20Plan.pdf. See Appendix Table A-5(b).

As reflected in Table II.C.1 and Table II.C.2, utility projections of peak demand

and of annual energy sales are currently moving in similar directions: peak demand is

increasing and annual energy sales are increasing when compared to utility estimates

provided last year. Historically, peak demand and annual energy sales have moved in

tandem.

Numerous changes have occurred or have been proposed to PJM demand

response (“DR”) programs recently. These changes include implementing a more

accurate method of measuring and verifying the quantity of demand reductions provided

Although the comparison of 2016 forecasted energy sales between the 2010 – 2019 TYP and the

2011 – 2020 TYP indicates a 0.1% reduction, utility data for the 2011 – 2020 TYP reflects an

increase in forecasted State energy sales in the aggregate when compared to the 2010 – 2019 TYP

forecast. See Appendix Table A-5(b).

and proposals to significantly expand both the time period and the seasons during which

DR participants must reduce load. The uncertainty associated with such changes leads to

less aggressive projections of future DR participation and DSM impacts.

III. REGIONAL GENERATION AND SUPPLY ADEQUACY IN MARYLAND

A. Introduction

The Commission recognizes that in order to maintain electric system reliability

and an adequate supply of electricity for customers in the future, access to adequate

electric capacity must be available to meet customer demand.

A critical requirement for reliable electric service is an appropriate level of

generation and transmission capacity to meet Maryland consumers’ energy needs. While

reliability needs may be partially met through local demand side management programs

and the import of electricity using high-voltage transmission lines, local generation must

be maintained and is essential to keeping the lights on and the power grid operating

effectively and economically. All load serving entities in the PJM region are required to

ensure they have sufficient capacity contracts to provide reliable electric service during

periods of peak demand. As of 2010, Maryland’s net summer generating capacity was

approximately 12,516 MW.

Maryland’s peak demand forecast for 2011 with utility

demand-side management and energy conservation measures is approximately 13,786

MW.

According to PJM’s established margin for necessary reserves, an additional

2,137 MW

is required and would result in a cumulative estimated reliability

requirement of 15,923 MW. Therefore, 3,407 MWs of estimated capacity in the

transmission system serves to meet Maryland’s requirements during periods of peak

usage in the system.

All major utility systems in the eastern half of the United States and Canada are

interconnected and operate synchronously as part of the Eastern Interconnection. PJM

operates, but does not own, the transmission systems in: (1) Maryland; (2) all or part of

12 other states; and (3) the District of Columbia. With FERC approval, PJM undertakes

this task in order to coordinate the movement of wholesale electricity and provide access

to the transmission grid for utility and non-utility users alike. Within the PJM region,

power plants are dispatched to meet load requirements without regard to operating

company boundaries. Generally, adjacent utility service territories import or export

See Tables III.B.1 and III.B.3.

See Appendix Table A-4(b).

The example uses an installed reserve margin (“IRM”) of 1.155 for 2010/2011, which is

applicable for planning reserves on a regional basis for the entire pool of PJM resources. IRM

establishes a level of installed capacity resources that will provide acceptable reliability levels for

the PJM region – and not on an individual state basis – considering demand forecasts, available

unforced capacity from existing generation, and the probability that a generating unit will not be

available (i.e., Equivalent Demand Forced Outage Rate (“EFORd”)). See PJM, Resource

Adequacy Planning, 2009 PJM Reserve Requirements Study, Table I - 1: Historical RRS

Parameters, 3, available at:

http://www.pjm.com/planning/resource-adequacy-

planning/~/media/documents/reports/2009-pjm-reserve-requirement-study.ashx

wholesale electricity as needed to reduce the total amount of installed capacity required

by balancing retail load and generation capacity over a regional, diversified system.

Within eastern PJM, the District of Columbia, Maryland, Delaware, New Jersey,

and Virginia continue to be net importers of electricity. Maryland imported about 40

percent of its electricity in 2009.

On a percentage basis, Maryland was the fifth largest

electric energy importer in the United States – surpassed by the District of Columbia,

Delaware, and Virginia in the immediate PJM area.

Much of the East Coast is

dependent on generation exported from states to the west of the region – many with low-

cost, largely depreciated, coal-fired generation assets. Prominent states within the PJM

region currently exporting more electricity in aggregate than consumed within each state

are Illinois, Indiana, Pennsylvania, and West Virginia.

Table III.A.1: State Electricity Imports (Year 2009) (GWh)

State Retail Sales

Losses & Direct

Use

Generation Net Imports

Percent Retail

Sales Imported

DC 12,199 785 35 (12,984) 106%

Delaware 11,258 1,298 4,842 (7,714) 69%

Idaho 22,754 2,635 13,100 (12,333) 54%

Virginia 108,462 8,338 70,082 (46,719) 43%

Maryland 62,589 5,924 43,775 (24,738) 40%

California 259,584 31,858 204,776 (84,137) 32%

New Jersey 75,780 5,630 68,811 (19,598) 26%

Massachusetts 54,359 3,216 38,967 (14,036) 26%

Tennessee 94,650 7,137 79,717 (22,070) 23%

Wisconsin 66,286 5,825 59,959 (12,153) 18%

Minnesota 64,004 6,891 52,492 (10,611) 17%

North Carolina 127,658 11,672 118,407 (20,922) 16%

Louisiana 78,670 24,670 90,994 (12,346) 16%

Ohio 146,300 11,550 136,090 (21,755) 15%

Georgia 130,766 15,814 128,698 (17,881) 14%

Florida 224,750 21,646 217,952 (28,444) 13%

Colorado 51,036 4,345 50,566 (4,815) 9%

Mississippi 46,049 5,563 48,701 (2,911) 6%

New York 140,034 3,026 133,151 (7,606) 5%

Alaska 6,270 770 6,702 (337) 5%

Kentucky 88,809 5,397 90,630 (3,576) 4%

Hawaii 10,126 1,166 11,011 (282) 3%

Michigan 98,121 10,076 101,203 (1,357) 1%

Texas 345,296 54,439 397,168 (2,456) 1%

Source: State Electricity Profiles 2009, U.S. ENERGY INFORMATION ADMINISTRATION, Table 10, (April 15,

2011) available at: http://www.eia.gov/cneaf/electricity/st_profiles/sep2009.pdf.

State Electricity Profiles 2009, U.S. ENERGY INFORMATION ADMINISTRATION, Table 10, (April 15,

2011) available at: http://www.eia.gov/cneaf/electricity/st_profiles/sep2009.pdf.

Id.

B. Maryland Generation Profile: Age and Fuel Characteristics

Most electric generating capacity in Maryland is provided by coal-fired power

plants, which contribute approximately 39 percent of the summer peak capacity available

in-State. The vast majority of the State’s coal-fired generation capacity, approximately

70 percent, is provided by power plants thirty-one or more years old. Approximately 41

percent of all capacity in Maryland burns oil or gas as a fuel source, and the majority of

these facilities are aging. Overall, approximately 67 percent of Maryland generating

capacity has been in operation for over 30 years. As indicated in Table III.B.1, only

about 16 percent of the State’s summer generating capacity has been constructed in the

past 20 years, and only about 7 percent has been constructed in the last 10 years.

Table III.B.1: Maryland Generating Capacity Profile (Year 2010)

Primar

Fuel

Type

Summer

(MW)

Pct. Of

Total

1-10

Years

11-20

Years

21-30

Years

31+

Years

Coal 4886 39.04% 0.0% 16.7% 13.0% 70.3%

Oil & Gas 5126 40.96% 14.2% 21.0% 13.3% 51.5%

Nuclear 1705 13.62% 0.0% 0.0% 0.0% 100.0%

Hydroelectric 590 4.71% 0.0% 0.0% 0.0% 100.0%

Other &

Renewables

209 1.67% 43.9% 25.9% 30.2% 0.0%

TOTAL 12516 100.00% 6.5% 15.6% 11.0% 66.9%

Capacity Age of Plants, by % of Fuel Type

Source: Report EIA-860: “GenY10” Excel, U.S. ENERGY INFORMATION ADMINISTRATION, (Nov. 30, 2011),

available at: http://www.eia.gov/cneaf/electricity/page/eia860.html.

In the past few years several older generating units in the eastern PJM region have

requested deactivation. These older generating units are located in Delaware,

Pennsylvania, New Jersey, Virginia, and the District of Columbia. These older

generation units typically have operated only a limited number of hours each year

recently and generate electricity at relatively high marginal costs. However, the units

also may be helpful in ensuring reliable electric service in the region. PJM undertakes an

analysis to determine the parameters under which units may deactivate or continue to

operate.

The following paragraphs summarize the pending deactivations of generating

facilities in the PJM region; several official owner requests for retirement date back to

2007.

In 2007, owners of power plants requested deactivation of units at locations in

D.C.: two Buzzard Point plants with a combined capacity of 240 MW; and two Benning

site power plants, 550 MW. The reliability issues have been identified for all units and

Manual M-14D: Generator Operational Requirements, Revision: 17, PJM (effective date Jan. 1,

2010), available at: http://www.pjm.com/~/media/documents/manuals/m14d.ashx.

are expected to be resolved to meet the requested deactivation dates.

All the units are

scheduled for deactivation on May 31, 2012.

In 2009, owners of power plants requested deactivation of units at three locations

in New Jersey and Pennsylvania: two Cromby units (Pennsylvania) with a combined

capacity of 345 MW; two Eddystone units (Pennsylvania), 588 MW; and two units at the

Kearny (New Jersey) site, 250 MW. On May 31, 2011, one Cromby unit and one

Eddystone unit were deactivated

; the remaining four units have requested deactivation

dates between May of 2011 and June of 2012. Reliability impacts were identified with

the Eddystone unit and with the Cromby unit. The requested deactivation date for the

Eddystone unit has been delayed from May 31, 2011 to May 31, 2012, and the requested

deactivation date for the Cromby unit has been delayed from May 31, 2011 to December

31, 2011. Additionally, a reliability analysis remains underway for both Kearny units.

In 2010, owners of power plants requested deactivation of five units that remain

pending: one Kearney unit with a capacity of 21 MW; a Cromby Diesel unit, 2.7 MW;

the Ingenco Petersburg plant, 2.9 MW; an Indian River unit, 169.7 MW; and one Sporn

unit, 440 MW. The reliability analysis remains underway for the Kearney unit, with a

projected deactivation timeline reaching into May of 2015. The reliability analyses were

completed for the other four units, and all issues are expected to be resolved to meet the

requested deactivation dates.

Depending on the unit, deactivation is projected between

May of 2011 and December of 2013.

In 2011, owners of power plants requested deactivation of nineteen units: two

State Line units with a combined capacity of 515 MW; one Vineland unit, 23 MW; one

Viking Energy unit, 16 MW; five Potomac River units, 482 MW; four Chesapeake units,

576 MW; one Yorktown unit, 159 MW; one Bergen unit, 21 MW; one Burlington unit,

21 MW; one National Park unit, 21 MW; one Mercer unit, 115 MW; and one Sewaren

unit, 111 MW. The reliability analyses remain underway for the majority of the units,

although results are available for both State Line units, the Vineland unit, the Viking

Energy unit, and all five Potomac River units. The reliability issues identified in the

completed analyses are expected to be resolved to meet the requested deactivation

dates.

Depending on the unit, deactivation is projected between 2012 and 2015.

Several requests for deactivation were filed in the opening months of 2012. One

noteworthy request is an application submitted on January 26, 2012 by FirstEnergy

Pending Deactivation Requests, PJM PLANNING (Feb. 6, 2012), available at:

http://www.pjm.com/planning/generation-retirements/~/media/planning/gen-retire/pending-

deactivation-requests.ashx.

PJM Generator Deactivations, PJM PLANNING (Jan. 10, 2012), available at:

http://www.pjm.com/planning/generation-retirements/~/media/planning/gen-retire/generator-

deactivations.ashx.

Pending Deactivation Requests, PJM PLANNING (Feb. 6, 2012), available at:

http://www.pjm.com/planning/generation-retirements/~/media/planning/gen-retire/pending-

deactivation-requests.ashx.

Id.

(formerly Allegheny Power) that references two units located in this State; R. Paul Smith

3 has been in service for 64 years and represents a 28 MW capacity, while R. Paul Smith

4 has been in service for 43 years and represents a capacity of 87 MW. The reliability

analysis is underway, and PJM has listed a projected deactivation date of September 1,

2012 for both R. Paul Smith units.

The Maryland generating profile differs considerably from its capacity profile.

Coal and nuclear facilities generate over 88 percent

of all electricity produced in

Maryland, even though they represent little more than half of in-State capacity.

contrast, oil and gas facilities, which tend to operate as mid-merit or peaking units that

come on-line only when needed, generate less than 6 percent of the electricity produced

by in-State resources, while representing approximately 41 percent of in-State capacity.

Table III.B.2 summarizes Maryland’s in-State fuel-mix in MWh by generating sources

for 2009. In 2009, Maryland plants produced 43,774,832 MWh of electricity.

Table III.B.2: Maryland Electric Power Generation Profile (Year 2009)

Source MWh

(%)

Coal 24,162,345 55.2

Oil & Gas 2,366,927 5.4

Nuclear 14,550,119 33.2

Hydroelectric 1,888,769 4.3

Other & Renewables 806,671 1.9

Total 43,774,832 100.0

Source: Maryland Electricity Profile, U.S. ENERGY INFORMATION

ADMINISTRATION, Table 5, (April 15, 2011), available at:

http://www.eia.gov/cneaf/electricity/st_profiles/maryland.html.

The total summer capacity of Maryland generators is approximately 12,516

MW,

of which approximately 80 percent of the in-State generation capacity is owned

by two companies or their subsidiaries: Constellation Energy Group and GenOn Energy,

Inc. (“GenOn”). Constellation Energy Group owns about 43 percent of this capacity, and

GenOn owns about 37 percent.

Nearly two-thirds (65 percent) of the State’s power

plant capacity resides in one of four counties: Prince George’s, 21 percent; Anne

Arundel, 18 percent; Calvert, 14 percent; and Charles, 12 percent. Table III.B.3 lists

Maryland generating units by owner, county, and capacity.

Id.

See Table III.B.2. In 2009 coal facilities generated 55.2% of Maryland’s electricity and nuclear

facilities generated 33.2%, for a total representative of 88.4% of Maryland’s electric power

generation profile in 2009. Id.

See Table III.B.1. Coal facilities represented 39.04% of the in-State capacity in 2010 while

nuclear facilities represented 13.62% of the capacity in 2010. Therefore, coal and nuclear

facilities combined for 52.66% of Maryland’s generating capacity profile in 2010. Id.

Id.

See Table III.B.3.

Id.

Table III.B.3: Generation by Owner, County, and Capacity (Year 2010)

Operator/Owner Plant Name County

Name Plate Summer

Pct. Summer

A & N Electric Smith Island

Somerset 1.7 1.6 0.01%

AES Warrior Run AES Warrior Run

Allegany 229 180 1.44%

Allegheny Energy R Paul Smith

Washington 109.5 115 0.92%

American Sugar Domino Sugar

Baltimore City 17.5 17.5 0.14%

Town of Berlin Berlin

Worcester 9 9 0.07%

BP Piney & Deep Creek LLC Deep Creek

Garrett 20 18 0.14%

Calpine Mid-Atlantic Generation LLC Crisfield Somerset 11.6 10.4 0.08%

Constellation Calvert Cliffs Calvert 1828.7 1705

Constellation Brandon Shores Anne Arundel 1370 1273

Constellation C P Crane Baltimore 415.8 399

Constellation Gould Street Baltimore City 103.5 97

Constellation Herbert A Wagner Anne Arundel 1058.5 975.9

Constellation Notch Cliff Baltimore 144 116.7

Constellation Perryman Harford 404.4 353.6

Constellation Philadelphia Baltimore City 82.8 60.9

Constellation Riverside Baltimore 257.2 228

Constellation Westport Baltimore City 121.5 115.8

Constellation Solar Maryland, LLC McCormick & Co. Inc. at Belcamp Hartford 1.4 1.4 0.01%

Covanta Montgomery, Inc. Montgomery County Resource Recovery Montgomery 67.8 54 0.43%

Criterion Power Partners LLC Criterion Wind Project Garrett 70 70 0.56%

Eastern Landfill Gas LLC Eastern Landfill Gas LLC Baltimore 3 3 0.02%

Easton Utilities Comm Easton Talbot 33.6 31.9

Easton Utilities Comm Easton 2 Talbot 38.8 37

Energy Recovery Operations, Inc Harford Waste to Energy Facility Harford 1.2 1.1 0.01%

Exelon Power Conowingo Harford 506.8 572 4.57%

GenOn Chalk Point LLC Chalk Point LLC Prince Georges 2,647 2,347

GenOn Mid-Atlantic LLC Morgantown Generating Plant Charles 1,548 1,477

GenOn Mid-Atlantic LLC Dickerson Montgomery 930 844

Industrial Power Generating Company LLC Wicomico Wicomico 5.4 5.4 0.04%

Maryland Environmental Service Eastern Correctional Institute Somerset 5.8 4.6 0.04%

NAEA Rock Springs LLC NAEA Rock Springs LLC Cecil 772.6 652 5.21%

NewPage Corporation Luke Mill Allegany 65 60 0.48%

NRG Vienna Operations Inc Vienna Operations Dorchester 183 170 1.36%

Panda-Brandywine LP Panda Brandywine LP Prince Georges 288.8 230 1.84%

Power Choice/Pepco Energy Serv NIH Cogeneration Facility Montgomery 22 21.2 0.17%

Prince George's County Brown Station Road Plant I Prince Georges 6.7 5.6 0.04%

RG Steel LLC RG Steel Sparrows Point, LLC Baltimore 120 152.3 1.22%

SCE Engineers Montgomery County Oaks LFGE Plant Montgomery 2.4 2.3 0.02%

Solo Cup Co Solo Cup Co Baltimore 11.2 11.2 0.09%

Trigen Inner Harbor East, LLC Inner Harbor East Heating Baltimore City 2.1 2.1

Trigen-Cinergy Solutions College Park UMCP CHP Plant Prince Georges 27.4 20.8

Wheelabrator Environmental Systems Wheelabrator Baltimore Refuse Baltimore City 64.5 61.3 0.49%

Worcester County Renewable Energy LLC Worcester County Renewable Energy Worcester 2 2 0.02%

13,611.20 12,515.60 100.00%

0.18%

0.55%

Capacity Statistics (MW)

42.55%

37.30%

Source: Report EIA-860: “GenY10” Excel, U.S. ENERGY INFORMATION ADMINISTRATION, (Nov. 30,

2011), available at: http://38.96.246.204/cneaf/electricity/page/eia860.html.

C. Potential Generation Additions in Maryland

Siting for central station generation in Maryland continues to be an important

concern. There are reliability, environmental, and competitive issues that must be

resolved when finding an appropriate location for a new generator. Generation is largely

deregulated and currently the responsibility of independent power producers. Generation

companies have proposed various projects, but they are typically either expansions of

existing sites or conjoined locations with other industrial or government facilities.

Without the financial assurances that were typically available through utility ownership,

it has become increasingly difficult for generation companies to secure potential new

sites, long-term sales contracts, and the funding necessary to build new generation.

Other sources of generation have benefited from the Commission’s small

generation interconnection rules. Distributed generation from solar facilities and

combined heat and power installations are examples of small scale generation. Co-

locating smaller generation facilities with other industrial process facilities provides an

alternative to increasing central station generation capacity.

However, regardless of the growth in distributed generation, there will still be a

need for central power stations that can be acceptably developed. Areas in or near the

State that may be considered for new generation include projects in the Atlantic Ocean,

the Nanticoke River area around Vienna on the Lower Eastern Shore, the Calvert Cliffs

area in Southern Maryland, various brownfield sites in the Central Maryland area, and

wind power sites in the mountains of Western Maryland. Upgrades and additions to

existing sites (i.e., brownfield deployment) offer advantages over new, undeveloped

greenfield sites with respect to licensing, transmission facilities, and environmental

concerns.

Although no significant generation has been constructed in Maryland within the

past few years, the Commission has granted both CPCNs and approvals for construction

for those who quality for CPCN exemptions for new generation. Furthermore, no units

have been retired recently. The Commission currently has before it several applications

for construction of new generation and transmission. When and if constructed, these

projects will make available additional electricity for use in Maryland and the PJM

region, and should ease congestion substantially.

In 2009, the Commission initiated a new proceeding (Case No. 9214) to consider

proposals for new electric generation facilities in Maryland. On September 29, 2011, the

Commission issued a Notice of Approval of Request for Proposals for New Generation to

be issued by Maryland Electric Distribution Companies. Attached to that notice was a

Request for Proposals inviting interested persons to submit proposals to the Commission

to construct new generation facilities that would produce and sell electricity to

Maryland’s regulated electric distribution companies. Proposals were due to the

Commission January 20, 2012. Additionally, the Commission set for comment whether

new generation is needed to meet the long-term anticipated demand in Maryland for

standard offer service and other electric supply and if so, the quantity of generation

needed. A hearing on the comments was held January 31, 2012.

The status of Commission proceedings covering proposed new electric generator

facilities in Maryland (projects ineligible for CPCN exemptions as discussed in Section

III.D.) that were active cases in late 2009 through 2011, is as follows :

CN9206: A CPCN application from Constellation Power Source Generation Inc.

authorizing the modification of the C.P. Crane generating station for the use of

sub-bituminous coal in Baltimore County. Testimony filed January 13, 2010. In-

service June 9, 2010.

CN9218: A CPCN application from UniStar, LLC authorizing the modification of

the Calvert Cliffs Unit 3 nuclear project for ancillary equipment that will increase

air emissions. In-service April 26, 2010.

CN9199: A CPCN Application from Energy Answers International, Inc. to

construct a 120 MW Generating Facility in Baltimore using processed waste for

fuel. On December 29, 2011, Energy Answers filed a motion to toll its

construction deadline contained in the CPCN.

CN9229: A CPCN Application from Mirant for STAR, a processor for flyash at

the Morgantown Power Plant in Charles County. In-service November 4, 2010.

In addition to the aforementioned CPCN applications, Maryland is experiencing

an uptick in the amount of solar generation capacity both planned and already available to

the State. Section VI.C. details the Commission’s efforts to spur small-scale solar

generator interconnection throughout Maryland. On the utility-scale, plans for new solar

generation also began taking shape in 2011; Case Number 9272 was opened for the

CPCN application of Maryland Solar LLC to construct a 20 MW solar photo-voltaic

generating facility in Hagerstown, Maryland. The Commission granted approval on

October 8, 2011 for construction of the Hagerstown facility in Order No. 84369. Other

notable examples of planned new solar generation include the October 26, 2011

Commission approval for SMECO Solar LLC to construct a Type IV solar generator in

Hughesville.

Additionally, on December 14, 2011, the Commission granted approval to

Constellation Solar Holding, LLC to construct a solar photovoltaic generation project

located at Mount St. Mary’s University comprising two solar arrays with capacities of

1.25 MW and 250 kW, respectively.

The number of projects for which a transmission interconnection request (capacity

or energy) has been filed with PJM provides an indication of potential generation

capacity additions in Maryland. Table III.C.1 lists the new generation projects located in

Maryland for which a transmission interconnection request has been made to PJM and

that are categorized as under study, under construction, providing partial service, or

The Commission granted approval of SMECO Solar LLC’s application for an exemption of the

CPCN requirement. Letter Order, Maillog No. 134380.

The Commission granted approval of Constellation Solar Holding, LLC’s application for an

exemption of the CPCN requirement. Letter Order, Maillog No. 135780.

currently suspended. The Table demonstrates the diversity of projects being pursued

throughout the State. The vast majority (about 89%) of proposed new generation

capacity would be located within the Southern Maryland Electric Cooperative, Inc.

(“SMECO”) and Pepco service territories, and would use primarily natural gas or nuclear

fuel. Additional generation capacity, especially from renewable sources, has been

proposed for the DPL and PE service territories.

Table III.C.1: PJM Transmission Queue Active New Generating Capacity

BGE

290

DPL

478

259

PEPCO

SMECO

TOTAL

205

Service

Territory

3,060 - 11,474 2010-2017

- 1,640 1,640 2017

8,520 - 8,548 2012-2017

- - 259 2009-2013

- - 478 2009-2017

259 - 549 2012-2015

Other &

Renewable Total

In-service

DatesNuclearNatural Gas

Plant Capacity (MW) By Fuel

Source

: See Appendix Table A-9.

D. CPCN Exemptions for Generation

Pursuant to Public Utilities Article § 7-207.1, certain power generating stations

are exempt from the requirement to obtain a CPCN, subject to Commission approval,

prior to commencing construction of the generating station. These approvals are

available to generating stations that are designed to provide on-site generated electricity

and that meet the following qualifications:

1. The capacity of the generating station does not exceed 70 MW; and

2. The electricity that may be exported for sale from the generating station to

the electric system is sold only on the wholesale market pursuant to an

interconnection, operation, and maintenance agreement with the local

electric company.

PUA § 1-101(s) defines “On-site generated electricity” as electricity that: (1) is not transmitted or

distributed over an electric company’s transmission or distribution system; or (2) is generated at a

facility owned or operated by an electric customer or operated by a designee of the owner who,

with the other tenants of the facility, consumes at least 80% of the power generated by the facility

each year.

The Statute also provides for an exemption from the CPCN process for a generating station that

does not exceed 25 MW if electricity that may be exported for sale from the generating station to

the electric system is sold only on the wholesale market pursuant to an interconnection, operation,

and maintenance agreement with the local electric company, and at least 10% of the electricity

generated at the generating station each year must be consumed on-site. MD. C

ODE ANN., PUB.

UTIL. § 7-207.1 (2011).

For wind-powered generating stations with a capacity up to 70 MW, there are two

additional qualifications that must be met in order to be granted approval without

obtaining a CPCN. The first is that the generating station must be land-based; therefore,

any off-shore facility within State waters will be required to obtain a CPCN. The second

qualification is that the Commission must provide an opportunity for public comment at a

public hearing.

The Commission’s PUA § 7-207.1- approved application requires the applicant to

select one of four specific types of generating stations: Type I, Type II, Type III, or Type

IV. With the exception of Type I, all generators are required to obtain an

Interconnection, Operation, and Maintenance Agreement (“Interconnection Agreement”)

with the local Electric Distribution Company (“EDC”). Type I generators must obtain a

letter from the local EDC that states an Interconnection Agreement is not necessary.

A Type I generator is not synchronized with the local electric company’s

transmission and distribution system and will not export electricity to the electric

system.

An emergency or back-up generator is the most common Type I generator. A

Type II generator is synchronized with the electric system; however, it will not export

electricity to the electric system. Generators used for peak-load shaving or generators

participating in a demand response program are the most common form of Type II

generators. Type III generators are synchronized with the electric system and export

electricity for sale on the wholesale market. A Type IV generator is a generator that is

synchronized with the electric system, but utilizes the disconnect feature of an inverter to

prevent export of power in the event of a power failure on the utility’s grid.

In order to obtain approval to construct a generator under PUA § 7-207.1, an

applicant must submit a completed application. In addition, the generator will need a

wholesale sales agreement with PJM if the generator is selling electricity on the

wholesale market. It is important to note that the approval does not exempt an applicant

from complying with other regulations or from obtaining all other necessary State and

local permits, such as those required by the Air and Radiation Management

Administration at the Maryland Department of the Environment (“MDE”).

Table III.D.1 provides an overview of the number and capacity of generators that

have applied for PUA § 7-207.1 approvals on an annual basis. The number of

applications has generally been increasing over time, and these generators have a

cumulative generation capacity of over 1,300 MW.

PUA § 1-101(h) defines “Electric company,” with certain exclusions, as a person who physically

transmits or distributes electricity in the State to a retail electric customer.

Table III.D.1: Construction Approvals for CPCN Exempt Generation

Period Approved Applications No. of Units Total (MW)

Calendar Year 2001 4 7 35.4

Calendar Year 2002 9 26 68.3

Calendar Year 2003 21 29 43.4

Calendar Year 2004 36 58 77.1

Calendar Year 2005 36 70 94.4

Calendar Year 2006 31 55 91.4

Calendar Year 2007 40 62 67.3

Calendar Year 2008 72 130 212.1

Calendar Year 2009 102 153 269.2

Calendar Year 2010 101 152 167.2

Calendar Year 2011 78 138 188.6

Total 530 880 1314.4

Pending 10 16 16.0

Total (Including Pending) 540 896 1330.4

Source: PSC database.

Note

: 2011 data is current as of October 31, 2011. Each application may contain multiple generation units.

Table III.D.2 reflects that fossil fuel generators were 92.6% of the 896 generator

units reported. These fossil fuel generators provided 1070.0 MW (80.4%) of the total

1330.4 MW of generating capacity reported. Oil remained the dominant fuel source for

new generators. Oil-fired generators were 930.1 MW (69.9%) of the total generation

reported. Wind-powered units provided 189.6 MW (14.3%) of total CPCN exempt

capacity. Solar-powered units provided 44.7 MW (3.4%) of total CPCN exempt

capacity.

Table III.D.2: Number and Capacity in MW of CPCN Exempt

Generating Units by Energy Resource

Energy Resource

Total

Approved

Percent of

Total

Approved

GENERATOR UNITS

Oil

790 88.2%

Natural Gas

38 4.2%

Fossil

Propane

2 0.2%

Fossil Total 830 92.6%

Biomass

1 0.1%

Digester Gas

3 0.3%

Landfill Gas

3 0.3%

Solar

56 6.3%

Renewable

Wind

3 0.3%

Renewable Total 66 7.4%

Grand Total 896 100.0%

CAPACITY (MW)

Oil

930.1 69.9%

Natural Gas

139.8 10.5%

Fossil

Propane

0.2 0.0%

Fossil Total 1070.0 80.4%

Biomass

19.8 1.5%

Digester Gas

3.2 0.2%

Landfill Gas

3.1 0.2%

Solar

44.7 3.4%

Renewable

Wind

189.6 14.3%

Renewable Total 260.3 19.6%

Grand Total 1330.4 100.0%

Source: PSC database.

Note: Data is current as of November 1, 2011.

IV. TRANSMISSION INFRASTRUCTURE: PJM, MARYLAND, AND

NATIONAL

A. Introduction

Transmission facilities in PJM and Maryland have continued to play a key role in

energy supply. With Maryland’s dependence on energy imports, it is necessary that

adequate transmission facilities be available to reliably provide electricity supplies.

While all network systems can experience congestion at times, portions of the Mid-

Atlantic States -- including central Maryland and the Delmarva Peninsula -- have

continued to experience significantly higher levels of congestion than the rest of PJM.

This, in turn, has led to higher energy and capacity costs in portions of Maryland and the

surrounding states since local, but more expensive, generation resources had to be

deployed to meet load. Adequate capacity and reliable supplies of electricity are

continually monitored, managed, and, when necessary, supplemented with additional

infrastructure.

B. Eastern Interconnection Planning Collaborative

During 2011, the Eastern Interconnection Planning Collaborative (“EIPC”)

completed the first phase of its work identifying a broad range of alternative futures to be

analyzed by a production cost model. Eight futures were modeled under varying

assumptions. The futures modeled were:

1. Business as Usual – This Future continues today’s policies.

2. National Carbon Policy/National Implementation – This Future envisions a

national Carbon Emission Mitigation policy to be fulfilled by constructing

no/low carbon – emitting energy generation facilities in the most productive

generation resource areas and building transmission to connect those

generation facilities to customers in the Eastern Interconnection.

3. National Carbon Policy/Regional Implementation – This Future concentrates

on fulfilling a national Carbon Emission Mitigation Policy by constructing

generation and transmission within each region to serve the customers within

that region.

4. High Energy Efficiency/Demand Response/Distributed Generation/Smart

Grid – This Future focuses on developing local programs to avoid the need for

large generation and transmission construction.

5. National RPS/National Implementation – Imposes a 30% Renewable Portfolio

Standard which may be fulfilled by importing renewable from the areas of the

Eastern Interconnection with the highest renewable energy resource potential.

6. National RPS/Regional Implementation – The RPS is assumed to be fulfilled

using renewable energy resource potential within each region of the Eastern

Interconnection.

7. Nuclear Resurgence – This Future looks at incenting the construction of

nuclear technologies as an option on other generation technologies.

8. National Carbon Policy/National Implementation with high

Efficiency/Demand Response – This Future combines Future Nos. 2 and 4.

The results from these modeling runs, which include what type of generation is

built, where it will be located, how much is needed, and at what cost, can be found at

www.eipconline.com. Next, EIPC identified three future scenarios for which a complete

transmission build-out will be designed. This exercise will provide an estimate of the

transmission costs associated with each scenario. The results of the transmission build-

out should be available in early 2012.

C. The Regional Transmission Expansion Planning Protocol

Planning the enhancement and expansion of transmission capability on a regional

basis is one of the primary functions of the wholesale market operator, PJM. PJM

implements this function pursuant to the Regional Transmission Expansion Planning

Protocol set forth in Schedule 6 of the PJM Operating Agreement.

PJM annually develops the Regional Transmission Expansion Plan (“RTEP”) to

meet system enhancement requirements for new backbone transmission lines and

interconnection requests for new generation. To establish a starting point for

development, PJM performs a “baseline” analysis of system adequacy and security. The

baseline is used for conducting feasibility studies on behalf of all proposed generation

and transmission projects. Subsequent System Impact Studies for those potentially viable

projects provide recommendations that become part of the RTEP Report.

PJM’s RTEP looks at a 15-year projection of the grid to predict reliability

problems. The system is planned for the probability of loss of load to be one day in ten

years. Single contingency analysis allows for the grid to function with the loss of any

one line. In some cases, double contingency analysis is used. PJM’s 15-year planning

horizon process has predicted that the congestion on the eastern and western interfaces

may cause both load deliverability and generator deliverability issues in central

Maryland.

Deliverability issues can be a result of significant load growth and the

retirement of existing generation.

Ideally, these problems can be solved with a

combination of new generation, transmission projects, and demand response.

The RTEP process applies reliability criteria over a 15-year horizon to identify

transmission constraints and reliability concerns. PJM uses CETO/CETL

analysis to

determine the import capabilities of the transmission system to supply the peak load

requirements for sub-regions within PJM. There are currently 23 sub-regions or load

The central Maryland region of the Mid-Atlantic area generally includes northern Virginia and the

Baltimore/Washington region.

Generation slated for retirement includes Benning Road, Buzzard Point, Potomac River, and Gude

Landfill in Washington, DC; and Indian River on the Eastern Shore.

Capacity Emergency Transfer Objective/ Capacity Emergency Transfer Limit.

deliverability areas (“LDAs”) in PJM. The Transmission Expansion Advisory

Committee (“TEAC”) is the primary forum for stakeholders to discuss the RTEP results.

The Commission is an active participant in the RTEP and regularly attends the TEAC

meetings.

1. Baseline Reliability Assessment

PJM establishes a baseline from which the need and responsibility for

transmission system enhancements can be determined. PJM performs a comprehensive

load flow analysis of the ability of the grid to meet reliability standards, taking into

account forecasted loads, imports and exports to neighboring systems, existing generation

and transmission assets, and anticipated new generation and generation retirements. The

baseline reliability assessment identifies areas where the planned system is not in

compliance with standards required by the North American Electric Reliability

Corporation (“NERC”)

and the regional reliability councils. The baseline assessment

develops and recommends enhancement plans to achieve compliance.

2. Inter-regional Planning

PJM is engaged in planning processes that address issues of mutual concern to

PJM and neighboring transmission grid systems: the Midwest Independent System

Operator (“ISO”); ISO New England; the New York ISO; the Tennessee Valley

Authority; and the North Carolina Planning Collaborative (added in 2009). The Inter-

regional Planning Stakeholder Advisory Committee facilitates stakeholder review and

input into the Coordinated System Plan. Coordinated regional transmission expansion

planning across seams is expected to reduce congestion on an inter-Regional

Transmission Organization (“RTO”) basis, and enhance the physical and economic

efficiencies of congestion management. Inter-regional ties are a benefit for reliability,

especially when load centers peak at different times (referred to as “load diversity”).

This kind of forum has been important for addressing problems such as loop flows

around Lake Erie.

3. Obligation to Build RTEP Projects

PJM’s Transmission Owners’ Agreement obligates transmission owners to

proceed with building transmission projects that are needed to maintain reliability

Since 1968, NERC has been committed to ensuring the reliability of the bulk power system in

North America.

To achieve that goal, NERC develops and enforces reliability standards; assesses

adequacy annually via a 10-year forecast and winter and summer forecasts; monitors the bulk

power system; audits owners, operators, and users for preparedness; and educates, trains, and

certifies industry personnel. NERC is a self-regulatory organization, subject to oversight by

FERC. As of June 18, 2007, FERC granted NERC the legal authority to enforce reliability

standards with all U.S users, owners, and operators of the bulk power system, and made

compliance with those standards mandatory and enforceable. NERC's status as a self-regulatory

organization means that it is a non-government organization which has statutory responsibility to

regulate bulk power system users, owners, and operators through the adoption and enforcement of

standards for fair, ethical, and efficient practices.

standards as approved by the PJM Board of Directors. Transmission owners can

voluntarily build these projects, or PJM can file with FERC to request FERC to order the

project to be built. In Maryland, CPCNs are required for transmission lines above 69,000

volts or modifications to existing facilities.

4. PJM’s Authority

FERC approved PJM as an Independent System Operator in 1997. Since that

time, PJM has administered its RTEP as described in Schedule 6 of the Operating

Agreement. PJM has subsequently received authority from FERC for procedures and

rules for transmission expansions needed to enable the interconnection of new and

expanded generation and merchant transmission facilities. PJM has amended the RTEP

to include the development of transmission projects to support competition in wholesale

electric markets, allowing it to justify projects for economic reasons as well as reliability.

PJM received final FERC approval as an RTO in 2002. As an RTO, PJM is the

administrator of the Open Access Transmission Tariff (“OATT”) as approved by FERC.

The OATT is the basis for PJM to collect charges to recover the costs of projects owned,

constructed, or financed by the transmission owners. Transmission owners file rate

schedules with FERC to recover transmission investments made pursuant to the RTEPs

approved by the PJM Board. The OATT enables generation to be sold anywhere in the

system.

D. Transmission Congestion in Maryland

1. PJM’s Definition of Congestion

PJM’s Locational Marginal Pricing (“LMP”) system takes account of congestion

in determining electricity prices. It reflects the value of the energy at the specific location

and time it is delivered. Theoretically, if the lowest-priced electricity could

simultaneously be distributed across the entire 13 states and the District of Columbia

(thereby encompassing the entire PJM wholesale market), prices would be the same

across the entire PJM grid. However, the capital investments that would be required for

such an expansive transmission system would be cost prohibitive. Therefore, more

expensive but advantageously located power plants that generate electricity are required

to meet the demand. As a result, LMPs are higher in the congested areas and lower at the

source of cheaper power. Congestion costs vary significantly during the course of a day,

seasonally, and from year to year. Persistent patterns of high LMPs can indicate future

reliability problems and the need for new generation, new transmission, and/or demand

response.

2. Location of Congestion

In 2010, the PE South interface continued to be the largest contributor to

congestion costs for the third consecutive year. This one constraint’s costs were nearly

double the sum of all remaining constraint costs. The PE South interface continues to be

the primary west-to-east transfer constraint.

3. Costs of Congestion

Congestion reflects the underlying characteristics of the power system, including

the nature and capability of transmission facilities and the cost and geographical

distribution of generation facilities. Total PJM congestion costs increased by $709.1

million (or 99%) from $719 million in calendar year 2009 to $1,428 billion in calendar

year 2010. Maryland utilities shared in these increased congestion costs.

Zone

2010 Total Annual

Zonal Congestion

Costs ($ million)

2009 Total Annual

Zonal Congestion

Costs ($ million)

Allegheny Power (Potomac Edison) 282.7 95.3

Baltimore Gas and Electric 91.6 33.5

Delmarva Power 47.2 31.1

Potomac Electric Power 98 58.4

Wholesale prices for electricity are determined in PJM’s Reliability Pricing

Model (“RPM”) Base Residual Auctions (“BRAs”). Blocks of capacity are sold

regionally for future delivery. The data below summarizes the annual capacity price for

Maryland in 2014/2015 compared to the 2013/2014 delivery year.

Zone

2014/2015

$/MW-Day

2013/2014

$/MW-Day

Western Maryland (PE) 125.94 27.73

Central Maryland (BGE) 136.50 226.15

Central Maryland (PEPCO) 136.50 247.14

Delmarva (DPL) 136.50 245.00

Delmarva South 136.50 245.00

Transmission expansion for the bulk electric system can act to reduce the

differences from zone to zone and support reliability requirements and economic

concerns.

Data for 2010. The zones for Allegheny (Potomac Edison), DPL, and Pepco include territory

outside of Maryland (Delaware, District of Columbia, Pennsylvania, New Jersey, West Virginia,

Virginia). Monitoring Analytics, LLC, 2010 State of the Market Report for PJM, Table 7-13

(March 10, 2011), available at:

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2010.shtml.

Id. at Table 7-19.

Data for 2009. The zones for Allegheny (Potomac Edison), DPL, and Pepco include territory

outside of Maryland (Delaware, District of Columbia, Pennsylvania, New Jersey, West Virginia,

Virginia). Monitoring Analytics, LLC, 2009 State of the Market Report for PJM, Table 7-17

(March 11, 2010), available at: http://monitoringanalytics.com/reports/PJM

_State_of_the_Market/2009.shtml.

2014-2015 RPM Pricing Points, PJM (May 13, 2011), available at:

http://www.pjm.com/markets-and-operations/rpm/rpm-auction-user-info.aspx#Item08.

Financial Transmission Rights (“FTRs”) and Auction Revenue Rights (“ARRs”)

give transmission service customers and PJM members an offset against congestion costs

in the Day-Ahead Energy Market. An FTR provides the holder with revenues, or

charges, equal to the difference in congestion prices in the Day-Ahead Energy market

across the specific FTR transmission path. An ARR provides the holder with revenues,

or charges, based on the price differences across the specific ARR transmission path that

results from the annual FTR auction. In PJM, FTRs have been available to network

service and long-term, firm, point-to-point transmission service customers as a hedge

against congestion costs since the inception of locational marginal pricing on April 1,

1998. FTRs became available to all transmission service customers and other PJM

members with the introduction of the annual FTR auction effective June 1, 2003.

In the 2009 to 2010 planning period, all ARRs and FTRs hedged more than 96.2%

of the congestion costs within PJM. During the first seven months of the 2010 to 2011

planning period, total ARR and FTR revenues hedged 78.7% of the congestion costs

within PJM.

43, 44

For the planning period 2009 to 2010, Potomac Edison and BGE were

hedged at greater than 100%, DPL at 55.2%, and Pepco at 19.7%.

Congestion of the electricity transmission grid continues to affect the

Baltimore/Washington area and to warrant attention. During the summer of 2010 overall

congestion rose by 99%, yet was still lower than congestion costs of 2005. This has

resulted primarily from reduced demand and the absence of significant generation or

transmission outages. The PJM metered peaks increased for 2010, but 2008 and 2009

were lower than the peaks in 2007 and 2006. This was due to the relatively mild weather,

the slowing economy, and increased diversity (non-coincident regional peaks).

For the 2014/2015 capacity auction, PJM announced an increase from the prior

2013/2014 auction in cleared Demand Resources of 4836.5 MW (or 52.1%).

E. High Voltage Transmission Lines in PJM

PJM’s 2010 Regional Transmission Expansion Plan was not published until

February 2011. However, the PJM Board approved over 400 individual bulk electric

system upgrades in 2010. Determined via PJM’s RTEP process, the upgrades are

required to support reliable electricity flows and ensure the power supply system meets

national standards through 2024. The PJM Board has approved more then $19.022

billion of bulk electric system upgrades since the inception of the RTEP process in 1997,

ensuring that PJM is compliant with NERC reliability criteria.

The ARR and FTR revenue adequacy results are aggregate results and all those paying congestion

charges were not necessarily hedged. Aggregate numbers do not reveal the underlying distribution

of FTR holders, their revenues, or those paying congestion premiums. The FTR markets can be

risky and have resulted in defaults for some participants. Financial entities own about 77% of all

Monthly Balance of Planning Period FTRs.

PJM Financial Transmission and Revenue Rights: 2010 State of the Market Report for PJM

(March 10, 2011), available at:

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2009/2009-som-pjm-

volume2-sec8.pdf.

The deep recession experienced by the country, which began in 2008, continues to

have a substantial impact on PJM’s RTEP. Load growth is a fundamental driver of

resource adequacy and transmission expansion plans. The slow economic recovery has

caused PJM to dramatically adjust its backbone transmission line project plans. In

particular, the 2011 load forecast issued in January 2011 forecasts significantly lower

load growth in the near term than in previous forecasts. Projects of interest to Maryland

which have been affected include:

• Potomac-Appalachian Transmission Highline (“PATH”) is a 765-kV transmission

line that would extend 300 miles from the Amos Substation (Charleston, WV) to

the Kemptown Substation in Frederick County, Maryland. This project was

docketed as Case No. 9233. Although included in the 2010 RTEP as a baseline

transmission project, in an RTEP update for events since December 2010, PJM

stated, “Preliminary 2011 PJM RTEP process analysis suggests that the need for

the PATH line has moved several years into the future beyond 2015. This has led

the PJM Board to direct owners to suspend efforts on the PATH line pending a

more complete analysis in the 2011 RTEP.” PJM 2010 RTEP 2/28/2010, p. 1.

• Mid-Atlantic Power Pathway (“MAPP”) is a 500-kV line that would connect the

Possum Point Substation in Virginia and the generation plants in southern

Maryland to Vienna and then to Indian River on the Delmarva Peninsula. The

portion under the Chesapeake Bay will be a submarine high-voltage direct current

line (“HVDC”). This project is docketed as Case No. 9179 at the MD PSC. On

Friday August 19, 2011 PHI announced that the new transmission line will be

delayed, suggesting that the new in-service date could be between 2019 and 2021.

• Trans-Allegheny Interstate Line (“TrAIL”), 502 Junction to Loudon. Construction

was completed on TrAIL in 2011, and its in-service date was June 2011. This

500 kV transmission line runs from near the border of Pennsylvania and West

Virginia to northern Virginia.

• Susquehanna to Roseland is a 500-kV line, approximately 130 miles from

northern Pennsylvania to northern New Jersey. Although its in-service date

technically remains 2012, permitting difficulties will delay this project.

The PJM RTEP requires that cost responsibility for transmission enhancements be

established. The cost of transmission facilities in PJM that operate at a voltage of 500 kV

and above are currently socialized across all PJM load. The backbone projects listed

above have secured incentive rate adders from FERC.

To make this determination,

For the MAPP project, FERC granted Pepco a 12.8% return on equity (including incentives), and

no rehearing was sought; as well, FERC granted BGE a 12.8% return on equity (including

incentives), and denied rehearing. The TrAIL project settled for a 12.7% return on equity

(including incentives). FERC granted PATH a 14.3% return on equity (including incentives);

however, rehearing remains pending.

FERC requires the applicant to satisfy its nexus test (non-routine project with advanced

technology) and address the rebuttable presumption standard (a project required by PJM).

Transmission projects not highlighted above but identified by the transmission

owners are listed in Table A-7 of the Ten-Year Plan for Maryland. For instance, the

Southern Maryland Electric Cooperative is continuing with plans for its 230 kV loop in

Southern Maryland.

V. DEMAND RESPONSE AND CONSERVATION AND ENERGY

EFFICIENCY

The Commission recognizes the potential of demand-side management ("DSM")

as a powerful tool to bolster energy efficiency and conservation efforts in our State.

Furthermore, DSM supports system reliability, energy security, energy and capacity price

mitigation (i.e., reducing overall energy costs), and enhanced energy market

competitiveness, and limits environmental impacts. The Commission encourages energy

service providers to offer DSM programs to customers where appropriate. Distribution

companies have been tasked with providing cost-effective DSM programs, particularly

for mass market residential and small commercial customers. As part of EmPower

Maryland,

the Commission has required the utilities to implement aggressive and cost-

effective demand management and energy conservation programs.

A. Statutory Requirements

Recognizing energy efficiency as one of the least expensive ways to meet

growing electricity demands in the State, the EmPower Maryland Energy Efficiency Act

(“Act”) was enacted on April 24, 2008. By statute, each utility

is required to develop

and implement cost-effective programs and services that encourage and promote the

efficient use and conservation of energy by consumers and utilities alike. EmPower

Maryland also establishes long-term reduction goals for electric consumption and

demand, based on a per capita and 2007 energy consumption baseline. The Act

specifically states at § 7-211(g)(1) and (2):

(1) To the extent that the Commission determines that cost-

effective energy efficiency and conservation programs and

services are available, for each affected class, require each electric

company to procure or provide for its electricity customers cost-

effective energy efficiency and conservation measures programs

and services with projected and verifiable energy electricity

savings that are designed to achieve the following a targeted

reduction of at least 5% by the end of 2011 and 10% by the end of

2015 of per capita electricity consumed in the electric company’s

service territory during 2007; and

See MD. CODE ANN., PUB. UTIL. § 7-211 (2011).

The term “Utilities” used in this Section refer to: BGE; DPL; Pepco; PE; and SMECO.

(2) require each electric company to implement a cost-effective

demand response program in the electric company’s service

territory that is designed to achieve a targeted reduction of at least

5% by the end of 2011, 10% by the end of 2013, and 15% by the

end of 2015, in per capita peak demand of electricity consumed in

the electric company’s service territory during 2007.

The Act also states at § 7-211(i)(1):

(1) In determining whether a program or service encourages and

promotes the efficient use and conservation of energy, the

Commission shall consider the: (i) cost–effectiveness; (ii) impact

on rates of each ratepayer class; (iii) impact on jobs; and (iv)

impact on the environment.

Prior to July 1 of each program planning phase (2008, 2011, 2014), the Act

requires each utility to consult with the Maryland Energy Administration (“MEA”),

Maryland Public Service Commission Staff (“Staff”), and other stakeholders regarding

the design and adequacy of the programs proposed by the utility. The 2011 planning

phase began in the summer of 2010 with requests for stakeholder input and progressed

through various stages of discussion and refinement. All plans were required to be

submitted by September 1, 2011 and hearings regarding the EmPower process took place

between October 12, 2011 and October 21, 2011. On December 22, 2011 the

Commission approved, with some modifications, the utilities' proposed plans in

Commission Order No. 84569.

The Commission’s December 22 Order provided increased guidance and

framework for the 2012-2014 program cycle. This included standardization of incentive

structures, the transition of Limited Income Energy Efficiency programs to the Maryland

Department of Housing and Community Development, the creation of various

workgroups to enhance and expand program offerings, and necessary updates to budgets

and surcharges associated with the EmPower Maryland program.

Commission Order No. 84569 also changes the reporting process for the 2012-

2014 cycle. Previously, utility reporting was done on a quarterly basis with an annual

summary report filed in January of the following year. The new requirements set forth a

semi-annual, formal filing process with required metric submissions filed informally with

Staff each quarter. The PSC, in consultation with MEA, will continue to provide an

annual report to the General Assembly regarding the status of the programs, a

recommendation for the appropriate funding level to adequately fund the programs and

services, and the per capita electricity consumption and peak demand for the previous

year.

B. Demand Response Initiatives

Demand Response is defined as changes in electric usage by end-use customers

from their normal consumption patterns either in response to changes in the price of

electricity over time or to incentive payments designed to induce lower electricity use at

times of high wholesale market prices and when system reliability is jeopardized. The

increase in electricity prices and changes in technology have spurred interest in finding

cost-effective means of reducing electricity consumption. Additionally, the price of

electricity in the wholesale markets serving the central and eastern portions of Maryland

is determined, in part, by the relative scarcity of generation and transmission capacities

serving those areas.

Demand Response initiatives comprise utility-run direct load control programs,

inclusive of their legacy demand response programs – the precursor of these Direct Load

Control (“DLC”) programs. These programs, although approved separately by the

Commission and, in many cases prior to the EmPower Maryland Energy Efficiency and

Conservation (“EE&C”) plans, are a critical component in meeting the EmPower

Maryland goals and as such are considered part of the EmPower Maryland umbrella

package.

1. DLC Programs

In 2008, the Commission approved the DLC programs of BGE, DPL, Pepco, and

SMECO.

These utilities filed revised DLC programs as part of the planning process for

the 2012-2014 program cycle. Pepco and DPL proposed to expand their respective DLC

programs to include Small Commercial as well as Residential, while BGE and SMECO

proposed other enhancements to their programs. However, Potomac Edison did not

propose a DLC program due to the non-economical projections associated with their

DLC program offerings; this decision was consistent with Potomac Edison's 2009-2011

planning proposals.

Each DLC program includes these common components: (1) all DLC programs

are voluntary; (2) upon receiving a customer request, the utility installs either a

programmable thermostat or a direct load control switch for a central air conditioning

system or an electric heat pump on a customer’s premise; (3) the utilities provide one-

time installation incentive and bill credits to the participants in the summer peak months;

and (4) with the exception of SMECO, customers can choose one of three cycling

choices, 50, 75, or 100 percent.

SMECO uses an initial 2 degree offset followed by 30

percent cycling for the thermostats, and a 50 percent cycling option followed by 30

The Commission approved BGE’s PeakRewards Program on November 30, 2007; Pepco and

DPL’s Energy Wise Programs on April 18, 2008; and SMECO’s CoolSentry Program on April 15,

2008. The utilities’ filings were documented in Case Number 9111. Potomac Edison/Allegheny

Power also filed its direct load control program, but it was not found to be cost-effective at the

time.

The cycling choices of 50%, 75%, and 100% represent the air conditioner compressor working

cycle reduced by 50%, 75%, and 100% under PJM- or utility- invoked emergency events during

summer peak season.

percent cycling for the switches during specified time periods. Utilities will invoke the

cycling process when PJM calls for an emergency event or a utility-determined event

during summer peak season.

The DLC incentives vary among utilities. The one-time installation incentive is

credited to the customer’s bill after installation is complete and an annual bill credit is

awarded for each participation year. Table V.B.1 summarizes the utilities’ incentives to

the program participants.

Table V.B.1 Utilities’ Incentives to DLC Program Participants

50% Cycling 75% Cycling 100% Cycling

Utility

Installation

Incentive

Annual

Bill

Credit

Installation

Incentive

Annual Bill

Credit

Installation

Incentive

Annual

Bill

Credit

Bill

Credit

Month

BGE $50 $50 $75 $75 $100 $100 Jun. –

Sept.

DPL $40 $40 $60 $60 $80 $80 Jun.–

Oct.

Pepco $40 $40 $60 $60 $80 $80 Jun.–

Oct.

Installation incentive Annual Bill Credit

Thermostat Digital Switch Thermostat Digital Switch

Bill

Credit

Month

SMECO *** None $50 $50 Jun.–

Oct.

*** A participant in SMECO’s CoolSentry program can keep the installed thermostat for free after 12 months of

the installation; otherwise, the thermostat will be removed if the participant terminates the participation less than

12 months.

Source: Utilities’ EmPower Maryland Energy Efficiency Program Websites.

Table V.B.2 summarizes the progress in installing these devices for each utility

DLC program as of December 31, 2010--since each program’s inception. Installed

devices (programmable thermostats and digital switches) number 403,024 units.

Table V.B.2 Utilities’ Direct Load Program Installations;

Program-to-Date as of December 31, 2010

Utility

Installed

During 2010

Installed

PTD as of

12/31/2010

BGE 158,838 326,310

DPL 11,554 13,807

Pepco 36,057 39,987

SMECO 9,599 22,920

Total 216,048 403,024

Source: For BGE, PE and SMECO, Utilities 2010 Quarter 4 Report of EmPower

Maryland Program. For DPL and Pepco, Utilities refiling of 2010 made on August 26, 2011.

The DLC program resulted in 803 MW being bid for Delivery Year (“DY”) 2013-

2014 in the May 2010 PJM RPM auction, a 16 percent decrease from the 2009 bid of 952

MW for DY 2012-2013. To date, these programs have accounted for 3,050 MW of the

total capacity bid into PJM’s capacity market. Table V.B.3 summarizes the capacity bid

into PJM’s capacity market from the DLC program by utility and delivery year.

Table V.B.3: Direct Load Control Program Bids into PJM BRA (MW)

Utility DY 2013-

2014

DY 2012-

2013

2011-

2012

DY 2010-

2011

2009-

2010

Total

BGE

615 740 512.6 415.4 217.0 2,500

DPL 32.1 38.8 24.7 N/A** N/A 95

Pepco 124.1 148.7 99.2 N/A N/A 372

SMECO 31.9 25.0 25.0 N/A N/A 82

Total 803 952.5 661.5 415.4 217 3049.5

Source: Various data requests in Case Nos. 9111, 9154, 9155, 9156, and 9157.

Notes: *BGE’s bid includes both its current DLC and its legacy demand response program.

**N/A means data are not available because there was no program launched for these utilities.

a. Update on the DLC four programs

i. BGE

BGE launched its DLC program, PeakRewards, in June 2008. Popular to date,

PeakRewards installed a total of 158,838 air conditioning cycling devices from January 1,

2010 through December 2010. Approximately 30,000 more devices have been installed

through the third quarter of 2011. As of the end of the third quarter of 2011, a total of

356,000 devices (thermostats or switches) have been installed. BGE also has its legacy

demand response programs, which include air conditioner and water heater switches

installed in the customer premises, and is in the process of transferring these customers to

the PeakRewards program, if the customer decides to continue to participate. BGE plans

to phase out the legacy programs in 2011. Therefore, BGE’s bid currently includes both

the PeakRewards and legacy demand response programs.

Since the inception of PeakRewards, BGE has bid into PJM’s BRA for six

consecutive delivery years (see Table V.B.3). The total bid is approximately 2,500 MW,

although this total does not reflect the 2014-2015 bid year.

ii. Pepco

Pepco launched its Energy Wise program (similar in program design to

PeakRewards) in January 2009.

Pepco had installed 39,987 devices as of December

2010. The program made significant progress in 2010, with 36,057 devices installed in

the year 2010 alone. A further 30,790 devices were installed through the third quarter of

2011. The Company has installed 70,777 devices since the program inception.

Pepco has bid into the last four of PJM’s RPM BRAs, with a total bid of 372 MW

for all but the 2014-2015 bid year.

The Company bid 124 MW for DY 2013/2014 and

149 MW for DY 2012/2013 into PJM’s BRA.

iii. DPL

Concurrently with Pepco, DPL launched its Energy Wise program in January

2009. The Company had installed 13,807 devices by the end of December 2010.

Through the third quarter of 2011 the Company had installed an additional 7,115 devices.

Since the inception of the program DPL has installed 20,922 devices.

DPL has bid into the last four of PJM’s RPM BRA, with a total bid of 96 MW,

excluding the 2014-2015 bid year.

The Company bid 32.1 MW for DY 2013/2014,

38.8 MW for DY 2012/2013, and 24.7 MW for DY 2011/2012 into the PJM BRA.

iv. SMECO

SMECO launched its CoolSentry Program in November 2008. A customer may

elect to have installed either a thermostat or a digital switch on his/her air conditioner or

electric heat pump. SMECO offers a $50 annual bill credit to each participant, but if a

participant chooses to install a thermostat, the participant can also keep the thermostat for

free after 12 months of participation. No installation incentive is offered to a participant

This bid year is not included as bids have not been made public at this time.

Pepco and DPL entered into a contract with Comverge on January 20, 2009, and started the testing

phase with their own employee volunteers.

This bid year is not included as it has not been made public at this time.

to choose a digital switch. SMECO has installed 30,811 devices since program inception,

including 11,347 through the third quarter of 2011.

SMECO bid a total of 81.9 MW into PJM’s RPM BRA over the last four years,

31.9 MW for DY 2013/2014, and 25 MW for each DY 2011/2012 and 2012/2013.

v. Suspension of White Rodgers Programmable Thermostat

Installation

In 2010, the Commission suspended the installation of the thermostats used by

Pepco, DPL, and SMECO due to a potential safety hazard with the devices. The

Commission issued Order No. 83588 on September 23, 2010 directing Pepco, DPL, and

SMECO

(“the Companies”) to cease the installation of the affected thermostats

immediately and appear before the Commission at a hearing on September 24, 2010. On

September 24, 2010, the Commission issued Order No. 83592 reinforcing the decision to

cease thermostat installation in Order No. 83588 and directed the Companies to notify the

Commission when the Consumer Protection Safety Commission (“CPSC”) issued a

decision on corrective actions for the safety issue with the thermostats.

On January 14, 2011 the Companies issued a press release providing further detail

about the Canadian CPSC ruling and a subsequent recall by White-Rodgers. On February

1, 2011 the Companies filed a motion to lift the stay, imposed by the Maryland PSC,

citing the steps outlined by White-Rodgers to rectify the problem as well as future

changes to the program to prevent this type of issue from remaining problematic. On

March 7, 2011 the Commission issued Order No. 83899, which lifted the stay on the

installation of White-Rodgers thermostats in the manner proposed by the Companies in

the February 1 filing.

b. July 22, 2011 DLC Activation Event

July 22, 2011 was the first time PJM had declared an emergency event since the

Utilities’ current DLC programs were approved by the Commission in 2008. BGE was

the only utility in Maryland to have an emergency event declared by PJM. This was

primarily due to the overheating of a transformer at one of BGE’s substations (forcing

BGE to take that transformer out of service) and extremely high temperatures. Because

of this emergency event, BGE initiated its DLC program at all three cycling levels for the

first time (50%, 75%, and 100%), so this was the first time that customers who signed up

for the 75% and 100% cycling options had their thermostat or switch cycling at the 75%

or 100% level.

The combination of the extreme high temperatures, cycling participants

for the first time at their selected cycling level, and the length of the event (7.75 hours)

The 2014-2015 bid year is not included as it has not been made public at this time.

SMECO also was installing the same White Rodgers programmable thermostats in its CoolSentry

program.

For non-PJM Emergency events, BGE cycles all participants at a 50 percent level.

This total of 7.75 hours was the average time the DLC program was activated, and consisted of

two events. The first event was the PJM-declared emergency which lasted for 6 hours and 34

minutes. For the second event, the Company switched all participants to cycle at the 50 percent

led to very high levels of calls to both the BGE call center and the DLC call center, which

led to longer than average wait times and customer dissatisfaction.

Pepco, DPL, and SMECO activated their DLC programs for economic reasons

and did not experience any above-average duration times or number of calls at their call

centers. Pepco, DPL, and SMECO also reported no problems with overloads on their

communication systems.

The major problems of the day were due to shortcomings in participant education

and communication. The following is a list of education and communication problems

and the proposed corrections to avoid these issues in future activations events:

1. Participants forgot what level of cycling they were signed up for - BGE

(and all the Utilities) need to remind the participants of their cycling level

prior to the summer season, when these devices are most likely to be

activated. Additionally, BGE should describe situations when a participant

might want to lower their cycling level, such as medical conditions or homes

with elderly people and small children.

2. Participants were unaware of the PJM emergency event – BGE should

attempt to contact participants the evening prior to an event (PJM Emergency

or BGE initiated), similar to the commitment BGE has made for customer

contact for Smart Energy Pricing. That way a participant will be aware of the

event beyond the message on the thermostat and light on the switch.

3. Participants had never been cycled at more than 50% prior to July 22 –

BGE may want to consider cycling participants at their selected cycling level

during BGE declared events. Since BGE declared events generally do not last

longer than four hours, a 100% participant, for example, may have a better

idea of the interior temperature change to expect for a potential PJM declared

emergency event.

4. Long time spent on hold while contacting call center – BGE has

committed, in its report, to increase call center staff during a PJM declared

emergency.

5. Paging signals to DLC devices unable to transmit due to system

overloading – BGE has indicated that it is already working with its signal

vendor to configure the system to enable the prioritization of system-wide

device commands.

BGE has been working on improving the education and communication issues

identified during the July 22 DLC activation event in order to provide more transparency

and be more responsive to program participants during future PJM declared emergency

events.

level in order to scale down from the emergency event. The second event lasted for 1 hour and 11

minutes.

2. Peak Load Reduction Forecast

Table V.B.4 demonstrates the impact of demand side management programs on

the utilities’ peak load forecast. The table presents the 10-year growth rate for gross of

demand side management programs and the impact, or net of, those programs during the

period of 2011 through 2020. Overall, the peak load forecast for the utilities listed in

Table V.B.4 is estimated to result in an 18 percent increase in demand by 2020 without

DSM programs. However, net of DSM programs, the overall forecast is expected to result

in a 13 percent increase in demand over the 10-year period. Therefore, holding all other

factors constant, it is forecasted that the DSM programs will reduce the peak demand

growth rate 5 percent by 2020.

Table V.B.4: Peak Load Reduction Forecast (MW)

Gross of DSM Net of DSM (MW)

2011

(MW)

2020

(MW)

10 Year

Growth

Rate

2011

(MW)

2020

(MW)

10 Year

Growth

Rate

10 Year

Growth

Rate

Variance

BGE

7,374 8,789 19% 6,699 7,589

13% 6%

DPL

1,249 1,447 16% 1,118 1,255

12% 4%

1,441 1,712 19% 1,412 1,680

19% 0%

Pepco

3,712 4,230 14% 3,322 3,591

8% 6%

SMECO

871 1,080 24% 838 1,031

23% 1%

Total

14,647 17,258 18% 13,389 15,146

13% 5%

Source: Table A-4(a) Peak Summer Demand Forecast Breakdown 2010 in Company data responses to the

Commission's 2011 data request for the Ten-Year Plan.

The major contributors to the peak load reduction are: (1) the current direct load

control program (BGE, DPL, Pepco, and SMECO); (2) legacy load reduction program

(BGE and SMECO); (3) BGE’s Smart Grid Initiative,

and (4) energy efficiency and

conservation programs (BGE, DPL, Pepco, and PE).

C. Energy Efficiency and Conservation Programs

On December 31, 2008, the Commission preliminarily approved the utilities’

EmPower Maryland EE&C portfolios, contingent upon varying Commission-prescribed

alterations to their programs, budgets, and projected savings. Although BGE’s programs

were approved in whole, the Commission directed the other utilities to file their revised

portfolios, along with information confirming their final estimated costs and budgets

through completed request for proposals or finalized contracts by March 31, 2009.

Comments by the interveners, as well as a response by the utility, were filed in each

proceeding. As with the original series of proceedings, the Commission conducted

Pepco did not include demand reductions from its Commission-approved AMI initiative.

The contribution information is obtained through Staff communication with the utilities. SMECO

does not include energy-efficient demand reduction as part of its forecast.

hearings for each utility’s proposal. The remaining four utilities’ - PE, DPL, Pepco and

SMECO - programs were approved in August 2009.

1. EmPower Maryland Policy

The Commission contracted an Independent Evaluator in April 2010 to conduct

quality control and due diligence of the Utilities’ EM&V programs and contracted

evaluator.

In an effort to build a credible and reliable EM&V infrastructure,

stakeholders and their various evaluators collectively established the Strategic Evaluation

Plan in September 2010 which provided guidance on a variety of issues, but also laid out

expectations for the Utilities and their evaluator. A baseline study, conducted by KEMA,

was completed in 2010 and released in 2011 for use by the utilities and evaluators. 2011

also saw the release of the first round of cost-effectiveness testing. This was a joint effort

by the Utilities, stakeholders, Itron, and Navigant Consulting to gather and analyze

savings reported under the EmPower Maryland programs and provide an evaluation of

the costs and benefits realized by each Utility. Overall, cost-effectiveness testing

returned positive results; however, some programs struggled due to their transformative

nature. It was determined that these programs may need additional time and attention in

order to achieve minimum cost-effectiveness standards.

The five EmPower Maryland Utilities, MEA, the Office of the Peoples Counsel

(“OPC”) and Staff (hereafter referred to as the “Planning Group”) began preparations for

the 2012-2014 EmPower Plan filings in the summer of 2010. On September 2, 2010

Staff filed the “Invitation to Stakeholders to Propose New or Revised Programs,

Measures or Products” on behalf of the Planning Group (“Invitation”). The Invitation

clarified that all cost-effective programs would be considered; however the Utilities

would determine what they include in these filings and the utilities have the right to

modify, adapt, incorporate and/or implement as they deem appropriate any ideas

presented on this process and during the stakeholder sessions. The Invitation included a

template intended examine all elements for the implementation of a proposed program or

product. Proposals were submitted on October 4, 2010 to Staff and MEA.

Over thirty proposals were submitted. The majority came from organizations or

firms that had little or no prior association with demand side stakeholder or work group

activities in Maryland. The Planning Group scored proposals largely on the

completeness of information provided. Eight organizations or firms were rejected prior

to the presentation of proposals in most cases because proposals lacked cost or savings

estimates.

Four Work Group meetings starting November 1, 2010, open to all stakeholders,

were noticed to Staff’s contact list and in a planning framework filed with the

Commission. The Planning Group met a number of times during the winter to discuss the

merits of the proposals and whether they were likely to be included in some form in the

draft Plans. Planning and workgroup meetings continued into 2011 with a culmination in

July 2011. As required under the statute each utility and any parties wishing to take part

The Utilities also have their own EM&V evaluator, as does the OPC and the MEA.

in the hearing process were required to file proposals by September 1, 2011. The

subsequent EmPower Maryland hearing process lasted eight days and included

presentations from the five Utilities, DHCD, Technical Staff, OPC, and MEA, as well as

trade organizations and contractors.

2. EmPower Maryland EE&C Programs

On December 31, 2008, by Order Nos. 82383, 82384, 82385, 82386, and 82387,

the Commission partially approved the Energy Efficiency, Conservation, and Demand

Response Programs pursuant to the EmPower Maryland Energy Efficiency Act of 2008.

With the exception of BGE’s portfolio, which was approved as a whole, DPL, Pepco,

Potomac Edison and SMECO were all requested to make alterations to some program

designs as well as revise the total estimated cost and savings with the finalized RFPs.

The Commission approved these revised plans in Order Nos. 82825 on August 6, 2009,

and 82835, 82836 and 82837 on August 13, 2009. The approved programs are designed

for residential customers,

as well as small and large commercial businesses.

Generally, most programs are designed to provide a rebate to consumers to encourage the

purchase of energy-efficient products, equipment, or services.

a. BGE

As of the end of the third quarter of 2011 BGE has spent 89 percent of its

forecasted 2009-2011 EE&C budget ($149,207,339). The Commission approved BGE’s

2011 Residential EE&C EmPower Maryland Surcharge at $0.000730 per kWh effective

January, 2011. The Company’s EmPower Maryland EE&C Programs have achieved 26

percent of its 2011 energy savings goal (2,052,948 MWh) and 5 percent of the 2011 peak

reduction goal (513 MW) through the third quarter of 2011.

b. Pepco

As of the end of the third quarter of 2011 Pepco has spent 41 percent of the 2009-

2011 EE&C budget ($49.8 million). Pepco continued to use the 2010 combined

residential surcharge ($0.00187) as no other surcharge was filed for 2011. The Company

has filed a surcharge for 2012 that will encompass the 2010 and 2011 true ups. The

Company has achieved 18 percent of its EE&C 2011 energy savings goal (685,378

MWh) and 8 percent of its demand reduction goal (230 MW).

The Commission subsequently approved certain program revisions for BGE in Order No. 82674.

Residential programs include Lighting and Appliances; Home Performance with Energy Star,

Quick Home Energy Check-up, and Comprehensive Home Audits; Energy Star for New Homes;

Limited Income Energy Efficiency Program; Heating, Ventilation, and Air Conditioning

(“HVAC”) and Domestic Hot Water Heaters. Program availability varies slightly across service

territories.

Non-residential programs include the C&I Prescriptive; C&I Custom; Commissioning; C&I

HVAC. Program availability varies slightly across service territories.

All data in the following sections will be current as of the third quarter of 2011 unless otherwise

noted. All data is reported at the Wholesale Level.

These percentages do not reflect savings from Demand Response programs as these are not part of

the EE&C portfolio but are part of the DLC programs.

c. DPL

DPL has spent 29 percent of its three-year forecasted budget ($19.6 million).

Pepco continued to use its 2010 combined residential surcharge ($0.001822) during 2011.

The Company has filed a surcharge for 2012 that will combined the 2010 and 2011 true

ups. Energy savings from EE&C programs through the third quarter will amount to 12

percent of the 2011 goal (205,846 MWh) and will account for 4 percent of the 2011

demand reduction goal (73 MW).

d. SMECO

Program spending for Residential and C&I EE&C programs through the third

quarter accounts for 63 percent of its 2009-2011 forecast ($14.3 million). The

Commission approved a residential EE&C surcharge of $0.00145 effective February,

2011. Program-to-date results through the third quarter of 2011 account for 34 percent of

the 2011 goal (94,229 MWh) and 40 percent of the 2011 demand reduction goal (29

MW).

e. PE

Program spending, through the third quarter of 2011, for EE&C programs

accounts for 9 percent of the 2009-2011 forecasted budget. The Commission approved a

residential EE&C surcharge of $0.00010 effective for June, 2011. This was a follow up

surcharge in response to the approval of the merger with First Energy. Program-to-date

results through the third quarter of 2011 account for 30 percent of the 2011 energy

savings goal (122,664 MWh) and 15 percent of the 2011 demand reduction goal (49.4

MW).

D. Advanced Metering Infrastructure / Smart Grid

1. Background

“Smart grid” technology is generally defined as a two-way communication system

and associated equipment and software, including equipment installed on an electric

customer’s premise that uses the electric company’s distribution network to provide real-

time monitoring, diagnostic, and control information and services that can improve the

efficiency and reliability of the distribution and use of electricity. Advanced Metering

Infrastructure (“AMI”) is a component of smart grid and refers to the installation of

meters on a customer’s premises capable of being addressed by the utility. Soon the

technology will enable customers to see and respond to market-based pricing as well as

be more self-aware of their energy usage, assisting in grid reliability and reducing

environmental impacts. Reliability and power quality benefits can also accrue when AMI

is employed to reduce blackout probabilities and forced outage rates while restoring

power in shorter time periods. On September 28, 2007, the Commission issued Order

No. 81637, which established the following minimum technical standards for AMI. BGE,

Pepco and DPL subsequently filed, for Commission approval, plans seeking to establish

an AMI program.

2. Approved AMI Initiatives

a. BGE

On August 13, 2010, the Commission issued Order No. 83531 in Case No.

9208,

which authorized BGE to deploy its AMI Initiative. Some highlights of the

approved AMI Initiative are:

• Install over 2 million electric meters and gas modules;

• Deployment cost of $440 million in capital cost and $57 million in operational

costs;

• Total cost over the life of the program of $641 million capital cost and $194

million in operational costs offset by $136 million

in federal grants from the

Department of Energy;

• Total benefits over the life of the project are estimated at $2.7 billion; and

• 80 percent of all meters to be installed by 2014.

Order No. 83531 directs BGE to do the following:

1) Establish a regulatory asset for the AMI Initiative. Once the Company has

delivered a cost-effective AMI system, it may seek cost recovery in its base

rates, including incremental costs and net depreciation and amortization costs

relating to the meters;

2) Allow cost recovery for the replacement of legacy meters by smart meters to

be considered in a future depreciation proceeding;

3) Submit for Commission approval, an updated customer education plan;

4) Develop “a comprehensive set of installation, performance, benefits and

budgetary metrics that will allow the Commission to assess the progress and

performance of the Initiative;

and

5) Notify the Commission of whether it will proceed with the initiative. BGE

confirmed its intent to proceed with the initiative in a letter sent to the

Commission on August 16, 2010.

Since authorization, BGE, in conjunction with PHI, Staff and other stakeholders,

established a Smart Grid Collaborative Work Group per Commission direction. The

Work Group offers a venue to discuss issues such as the consumer education plan and the

In the Matter of Baltimore Gas and Electric Company for Authorization to Deploy a Smart Grid

Initiative and to Establish a Surcharge Mechanism for the Recovery of Cost.

BGE was awarded $200 million in American Recovery and Reinvestment Act funding. Of this,

$136 million funds AMI deployment and $64 million for Peak Rewards and Customer Care &

Billing.

Order No. 83531at 48.

comprehensive set of performance metrics. The Company provided an update on

deployment efforts at a status conference on December 15, 2010. The Company proposed

that deployment take place from 2011-2014, with installation of smart meters beginning

in October 2011.

b. Pepco

On September 2, 2010, the Commission issued Order No. 83571 in Case No.

9207,

authorizing Pepco to deploy its AMI Initiative contingent upon the Company

submitting an amended business case and a comprehensive consumer education plan.

Some highlights of the approved Smart Grid Initiative are:

• Install 570,000 electric meters;

• Deployment cost of $69.4 million in capital cost;

• Total cost over the life of the program of $127 million in capital cost and

$1.038 million in annual incremental operational costs;

• Total benefits over the life of the project are estimated at $311.6 million; and

• Pepco awarded $104.8 million in Smart Grid Investment Grant funds.

Order No. 83571 directs and allows Pepco to do the following:

1) Submit an amended business case and associated benefits-to-costs analysis

that demonstrates the cost-effectiveness of the AMI proposal;

2) Submit a plan detailing how it intends to fund its proposed Critical Peak

Rebate dynamic pricing structure, including the manner in which it intends to

monetize peak demand and energy use reductions attributable to AMI;

3) Develop “a detailed and comprehensive customer education and

communications plan,” along with a corresponding customer education and

communications budget;

4) Develop a comprehensive set of metrics of the Company’s AMI proposal,

including: (a) installation and performance of the technology; (b) incremental

costs incurred; (c) incremental benefits realized; (d) effectiveness of customer

education and communications efforts to include customer satisfaction and

participation levels; and (e) customer privacy and cyber security;

5) Establish a regulatory asset for the incremental costs associated with the AMI

deployment, including start-up costs, which the Company may seek to

recover in a base rate proceeding;

6) Seek cost recovery for the replacement of legacy meters by smart meters to

be considered in a future depreciation proceeding.

The Order also prohibits the Company from implementing a Critical Peak

Pricing rate structure. A dynamic rate schedule will go in effect once AMI has

been installed. Further, the Commission ordered Commission Staff as well as

Pepco to convene an AMI working group, which is to include representatives

In the Matter of Potomac Electric Power Company and Delmarva Power and Light Company

Request for the Deployment of Advanced Meter Infrastructure.

Id. at 4.

from Pepco, BGE, and the Office of People’s Counsel to submit a proposal for

“uniformity of critical peak period seasons, times, frequency, and duration,

and other aspects of dynamic pricing implementation.”

Pepco filed with the Commission its Customer Education Plan on October 15,

2010 and an amended business case on December 13, 2010, in accordance with Order

No. 83571. Pepco provided cost-benefit analyses under three different post-deployment

scenarios, all of which yielded cost-effectiveness scenarios greater than 1.0. The filing

also included depreciation timetables for advanced metering infrastructure and estimated

costs for regulatory assets. The consumer education plan and amended business case’s

final budget—as well as the performance metrics required to be reported— will be

subject to the review of the Smart Grid Collaborative Work Group and to the approval of

the Commission. In its amended business case filed December 13, 2010, Pepco proposed

a time period of 15 months for AMI installation, and the starting month is projected to be

June 2011, with completion in August 2012.

c. DPL

In Order No. 83571, the Commission deferred the decision on DPL’s request to

proceed with deployment of its AMI Initiative. DPL’s request to establish a regulatory

asset for the incremental costs associated with its proposed AMI deployment was

deferred as well.

Order No. 83571:

1) Deferred DPL’s request to proceed with deployment of its AMI Initiative, and

directed the Company to submit an amended business case and associated

cost-benefit analysis demonstrating the cost-effectiveness of the proposal;

2) Required the Company to submit a plan detailing how it intends to fund its

proposed Critical Peak Rebate dynamic pricing structure, including the

manner in which it intends to monetize peak demand and energy use

reductions attributable to AMI;

3) Denied DPL’s request to establish a regulatory asset for the incremental costs

associated with AMI deployment, pending submission of a revised business

case of AMI system deployment that is agreeable to the Commission; and

4) Prohibited the Company from implementing a Critical Peak Pricing rate

structure.

DPL filed a revised business case for its AMI Initiative on December 14, 2010,

which includes forecast scenarios for all of the adjustments specified by Order No.

83571. The Commission reheard the case on August 17, 2011. At this time no order has

been issued by the Commission on this issue but one is expected in 2012.

Id. at 51.

3. AMI Pilots

a. SMECO

SMECO proposed a two-phase AMI Pilot Program to test the operational benefits

of AMI deployment, such as savings from eliminating meter readings and improved

outage restoration. Phase I of the pilot, approved by the Commission in December of

2009, includes the installation of 1,000 meters in one section of the service territory and

went into effect in 2010. The Cooperative will attempt to quantify the level of operational

benefits attainable through deployment of AMI, and the Cooperative will report the

results of Phase I to the Commission prior to implementing Phase II, which will be a

10,000 meter deployment across the entire service territory. At the time of this report,

SMECO had not yet submitted the report on Phase I of the project. SMECO notified

Commission Staff that Phase I will commence in mid-March 2011.

4. AMI Workgroups

a. BGE and Pepco

Following the Commission’s direction that workgroups be established to bring

stakeholders together with the utilities for the development of metrics, educational

programs, and security standards a number of initiatives were undertaken in 2010 and

2011. In a letter dated February 18, 2011 Pepco received approval from the Commission

to implement its “Proposed Phase 1” customer education plan. In a letter dated July 18,

2011 BGE received approval from the Commission to implement its “Smart Grid

Customer Education and Communication Plan.” In a letter dated August 18, 2011 the

Commission granted approval for the Phase 1 Metrics for both BGE and Pepco. The

workgroup continues to develop plans for cyber security, Phase II metrics, and Phase II

customer education and communication. It is expected that consensus filings and specific

plans will be filed for approval on each of these issues in 2012.

E. Mid-Atlantic Distributed Resources Initiative

The Mid-Atlantic Distributed Resources Initiative (“MADRI”) was established in

2004, and currently consists of seven PJM State Commissions, DOE and PJM.

Its goal

is “to develop regional policies and market-enabling activities to support distributed

generation and demand response in the Mid-Atlantic region.” Facilitation support is

provided by the Regulatory Assistance Project funded by DOE. There has been much

participation by a large number of stakeholders, including utilities, Commission Staff,

FERC, service providers, and consumers. During 2011, MADRI focused on time of use,

peak period and related pricing approaches that may be used following the

implementation of Smart Grid infrastructure.

VI. ENERGY, THE ENVIRONMENT, AND RENEWABLES

A. The Regional Greenhouse Gas Initiative

The Regional Greenhouse Gas Initiative (“RGGI”) is the first mandatory cap-and-

trade program in the United States for carbon dioxide (“CO

”). Under RGGI, ten

Northeastern and Mid-Atlantic states have jointly designed a cap-and-trade program that

limits permitted carbon dioxide emissions from fossil fuel power plants, and then

incrementally lowers that level or “cap” 10% by 2018. The first compliance period

spanned January 1, 2009 – December 31, 2011. Nine member states will continue

participation in the RGGI program for the second compliance period of January 1, 2012 –

December 31, 2014; New Jersey has formally withdrawn from the RGGI program,

effective January 1, 2012.

RGGI, Inc. is a nonprofit Delaware corporation formed to provide technical and

scientific advisory services to participating states in the development and implementation

of the carbon dioxide budget trading programs. The RGGI, Inc. offices are located in

New York City in space co-located with the New York Public Service Commission. The

RGGI Board of Directors is composed of two representatives from each member state,

with equal representation from the states’ environmental and energy regulatory agencies.

Agency Heads (two from each state), who also serve as RGGI Board members, constitute

a steering committee that provides direction to the Staff Working Group and allows

coordination of in-process projects for Board review.

Under RGGI, the participating states have agreed to use an auction of allowances

as the means to distribute CO

emissions allowances to electric power plants regulated

under coordinated state CO

cap-and-trade programs. All fossil fuel electric power plants

25 megawatts or greater must obtain allowances and adhere to RGGI guidelines. The

effective date for RGGI was January 1, 2009. From 2009 through 2014, the cap

stabilizes emissions at 2009 levels of approximately 188 million tons annually. These

initial base annual emissions budgets for the 2009-2014 periods are summarized in Table

VI.A.1.

The Commissions are Delaware, D.C., Illinois, Maryland, New Jersey, Ohio and Pennsylvania.

Table VI.A.1: Annual State CO

Allowance Budgets (2009 – 2014)

State

Carbon Dioxide Allowances

(in Short Tons)

Connecticut 10,695,036

Delaware 7,559,787

Maine 5,948,902

Maryland 37,503,983

Massachusetts 26,660,204

New Hampshire 8,620,460

New York 64,310,805

New Jersey 22,892,730

Rhode Island 2,659,239

Vermont 1,225,830

Total* 188,076,976

Source: Memorandum of Understanding, REGIONAL GREENHOUSE GAS INITIATIVE

(Dec. 20, 2005), available at http://www.rggi.org/design/history/mou.

*Note

: Following the withdrawal of New Jersey (effective Jan. 1, 2012), the total

annual regional cap will be adjusted to 165,184,246 allowances.

Beginning in 2015, the cap is reduced by 2.5% each year until 2018. This phased

approach, with initially modest emissions reductions, is intended to provide market

signals and regulatory certainty so that electricity generators may begin planning for, and

investing in, lower-carbon alternatives throughout the region while avoiding volatile

wholesale electricity price impacts and attendant retail electricity rate impacts. The

RGGI Memorandum of Understanding apportions carbon dioxide allowances

among

signatory states through a process that was based on historical emissions and negotiation

among the signatory states. Together, the emissions budgets of each signatory state

comprise the regional emissions budget, or RGGI “cap.”

In 2011, RGGI held four successful auctions for carbon dioxide allowances. As a

result of the fourteen auctions comprising the first compliance period, Maryland’s

Strategic Energy Investment Fund has received a cumulative total of $180,315,817

through December 2011; the Fund received almost $33 million in 2011 alone.

During 2011, auction clearing prices did not recover from the downward trend

that started in mid-2009. All allowances sold in 2011 auctions were purchased at the

auction floor price.

In 2011, the auction floor price was $1.89; the floor price will

increase to $1.93 in 2012 auctions.

An allowance is a limited permission to emit one ton of carbon dioxide.

See MD Proceeds by Auction, REGIONAL GREENHOUSE GAS INITIATIVE, available at

http://www.rggi.org/docs/MD_Proceeds_by_Auction.pdf (last updated Dec. 12, 2011).

See Auction Results, REGIONAL GREENHOUSE GAS INITIATIVE, available at

http://www.rggi.org/market/co2_auctions/results (last updated Dec. 12, 2011).

B. The Renewable Energy Portfolio Standard Program

The Renewable Energy Portfolio Standard (“RPS”) Program imposes an annual

requirement upon Maryland load serving entities (“LSEs”) to derive a percentage of

electricity sales from the renewable sources specified in the corresponding RPS Statute.

LSEs, which include both electricity suppliers and the utilities that provide Standard

Offer Service (“SOS”),

file compliance reports with the Commission verifying that the

renewable requirement for each entity is satisfied. The RPS obligation applies to anyone

who has completed an electricity sale at retail to customers in the State of Maryland.

Additional information regarding the status of the Maryland RPS is available in the

annual Renewable Energy Portfolio Standard Report submitted to the General

Assembly.

On an annual basis each supplier must present renewable energy credits (“RECs”)

equal to the percentage specified by the RPS Statute,

or pay the alternative compliance

fees equal to any shortfalls.

A REC is equal to one MWh of electricity generated using

specified renewable sources.

As such, a REC is a tradable commodity equal to one

MWh of electricity generated or obtained from a renewable energy generation resource.

Generators and suppliers are allowed to trade RECs using a system known as the

Generation Attributes Tracking System (“GATS”). GATS is a system designed and

operated by PJM Environmental Information Services, Inc. (“PJM-EIS”) that tracks the

ownership and trading of the generation attributes.

A REC has a three-year life during

which it may be transferred, sold, or redeemed.

Suppliers that do not meet the annual RPS requirement are required to pay

Alternative Compliance Payments (“ACPs”) or fees equal to any shortfalls.

Compliance fees are deposited into the Maryland Strategic Energy Investment Fund

(“SEIF” or “Energy Fund”) as dedicated funds to provide for loans and grants that can

MD. CODE ANN., PUB. UTIL. § 7-701(j) (2011).

Standard Offer Service (“SOS”) is electricity supply purchased from an electric company by the

company’s retail customers that cannot or choose not to transact with a competitive supplier

operating in the retail market. See M

D. CODE ANN., PUB. UTIL. §§ 7-501(n) and 7-510(c) (2011).

See Commission Reports, MARYLAND PUBLIC SERVICE COMMISSION, available at

http://webapp.psc.state.md.us/Intranet/psc/Reports_new.cfm (last visited Dec. 2011), for a listing

of available RPS Reports submitted in previous years.

MD. CODE ANN., PUB. UTIL. § 7-703(b) (2011).

Using the Tier 2 RPS requirement as an example, assume a hypothetical LSE operating in the

State had 100,000 MWh in retail electricity sales for 2008. In 2008, the Tier 2 requirement was

2.5%. Thus, the LSE would have to verify the purchase of 2,500 Tier 2 RECs in satisfaction of

the Tier 2 RPS obligation, or pay compliance fees for deficits. Similar requirements apply to Tier

1 and Tier 1 solar, the additional RPS tiers provided for in Maryland’s RPS Statute.

MD. CODE ANN., PUB. UTIL. § 7-701(i) (2011).

An attribute is “a characteristic of a generator, such as location, vintage, emissions output, fuel,

state RPS program eligibility, etc.” PJM Environmental Information Services, Generation

Attribute Tracking System Operating Rules, at 3 (September 30, 2010).

MD. CODE ANN., PUB. UTIL. § 7-709(d) (2011).

MD. CODE ANN., PUB. UTIL. § 7-705(b) (2011).

indirectly spur the creation of new renewable energy sources in the State.

The

Commission is responsible for creating and administering the RPS Program;

responsibility for developing renewable energy resources through loans and grants has

been vested with the Maryland Energy Administration.

Eligible fuel sources for Tier 1 RECs and Tier 2 RECs are listed in Table VI.B.1.

In order to verify that each LSE has met its RPS obligation, the Commission requires that

all licensed electricity suppliers and electric companies file a Supplier Annual Report no

later than April 1

of each year.

The April 1

deadline provides time for LSEs to

calculate electricity sales based on settlement data for the compliance year that ends on

December 31

. The April 1

deadline also allows LSEs time to purchase any RECs

needed to fulfill their respective RPS obligations.

Table VI.B.1: Eligible Tier 1 and Tier 2 Renewable Sources,

for Compliance Year 2010

Tier 1 Renewable Sources Tier 2 Renewable Sources

• Solar (set-aside with separate standard)

• Wind

• Qualifying Biomass

• Methane (landfill or wastewater treatment

plant)

• Geothermal

• Ocean Energy (waves, tides, currents, and

thermal differences)

• Fuel Cells (which produce electricity

from biomass or methane under Tier 1)

• Hydroelectric Power Plant (less than 30

MW capacity)

• Poultry Litter-to-Energy

• Hydroelectric Power (other

than pump storage

generation) at or above 30

• Waste-to-Energy

Source: MD. CODE ANN., PUB. UTIL. § 7-705(b) (2011).

Note: Tier 1 RECs may be used to satisfy Tier 2 obligations; Tier 2 RECs, however, may not be used to

satisfy Tier 1 obligations.

Chapters 127 and 128 of the Laws of 2008 repealed the Maryland Renewable Energy Fund and

redirected compliance fees paid into that fund into the Maryland Strategic Energy Investment

Fund. 2008 Md. Laws 846.

MD. CODE ANN., PUB. UTIL. § 7-703(a)(1)(i) (2011).

These reports have been filed pursuant to MD. CODE ANN., PUB. UTIL. § 7-705(a) (2011).

Effective October 1, 2011, new legislation reclassified “waste-to-energy” as a Tier 1 renewable

source. 2011 Md. Laws 3045. However, “waste-to-energy” was classified as a Tier 2 renewable

source during the 2010 compliance year as reported in this section.

LSEs are required to purchase specified minimum percentages of their electricity

resources via RECs from Maryland-certified Tier 1 and Tier 2 renewable resources. As

presented in Table VI.B.2, Tier 1 and the Tier 1 solar set-aside

requirements gradually

increase until they peak in 2022 at 18% and 2%, respectively, and are subsequently

maintained at those levels. Maryland’s Tier 2 requirement remains constant at 2.5%

through 2018, after which it sunsets.

Table VI.B.2: Annual RPS Percentage Requirements by Tier

Compliance

Year Tier 1

Tier 1

Solar Tier 2

2010 3.00% 0.025% 2.50%

2011 4.95% 0.050% 2.50%

2012 6.40% 0.100% 2.50%

2013 8.00% 0.200% 2.50%

2014 10.00% 0.300% 2.50%

2015 10.10% 0.400% 2.50%

2016 12.20% 0.500% 2.50%

2017 12.55% 0.550% 2.50%

2018 14.90% 0.900% 2.50%

2019 16.20% 1.200%

2020 16.50% 1.500%

2021 16.85% 1.850%

2022 18.00% 2.000%

Source: MD. CODE ANN., PUB. UTIL. § 7-703(b) (2011).

Note:

Schedule reflects increased percentage requirements effective January 1, 2011 for the Tier 1 Solar

category.

Electricity suppliers not meeting the RPS requirement for any or all tiers of

resources pay an ACP on each MW of shortfall.

Table VI.B.3 presents the ACP

schedule separated by tiers for each year of the RPS from 2010 to 2023 and beyond.

Compliance fees, as previously mentioned, are deposited into the SEIF and dedicated to

supporting the development of new Tier 1 renewable resources in Maryland.

"Tier 1 solar set-aside" refers to the set-aside (or carve-out) of Tier 1 for energy derived from

qualified solar energy facilities. The Tier 1 solar set-aside requirement applies to retail electricity

sales in the State by LSEs and is a sub-set of the Tier 1 standard.

MD. CODE ANN., PUB. UTIL. § 7-705(b) (2011).

Table VI.B.3: RPS Alternative Compliance Fee Schedule ($/MWh)

Compliance

Year

Tier 1

(non-solar)

Tier 1

Solar

Tier 2

IPL*

Tier 1

2010 $20 $400 $15 $5

2011 $40 $400 $15 $4

2012 $40 $400 $15 $4

2013 $40 $400 $15 $3

2014 $40 $400 $15 $3

2015 $40 $350 $15 $2.50

2016 $40 $350 $15 $2.50

2017 $40 $200 $15 $2

2018 $40 $200 $15 $2

2019 $40 $150 $2

2020 $40 $150 $2

2021 $40 $100 $2

2022 $40 $100 $2

2023 + $40 $50 $2

Source: MD. CODE ANN., PUB. UTIL. § 7-705(b) (2011).

*Note: A supplier sale from Industrial Process Load (“IPL”) is required to meet the entire Tier 1

obligation for electricity sales, including solar. However, the ACP for an IPL Tier 1 non-solar

shortfall and a Tier 1 solar shortfall is the same. For IPL, there is no compliance fee for Tier 2

shortfalls.

Calendar year 2010 marked the fifth compliance year for the Maryland RPS, and

the third year for LSEs to comply with the solar Tier 1 set-aside. GATS and the RPS

compliance reports submitted to the Commission by LSEs provide information regarding

the RECs retired and the underlying renewable energy facilities (e.g., type and location)

utilized by electricity suppliers to comport with Maryland RPS obligations.

RPS

compliance reports were filed by 58 electricity suppliers, including 33 competitive

suppliers, 14 brokers or wholesale electricity suppliers with zero retail electricity sales,

and 11 electric companies, of which four are investor-owned utilities. In compliance year

2010, there were approximately 65.6 million MWh of total retail electricity sales in

Maryland; 64.1 million MWh of electricity sales were subject to RPS compliance, and

1.5 million MWh were exempt.

According to § 7-709, a REC can be diminished or extinguished before the expiration of three

years by: the electricity supplier that received the credit; a nonaffiliated entity of the electricity

supplier that purchased or received the transferred credit; or demonstrated noncompliance by the

generating facility with the requirements of § 7-704(f). In the PJM region, the regional term of art

is “retirement,” and describes the process of removing a REC from circulation by the REC owner,

i.e., the owner “diminishes or extinguishes the REC.” PJM Environmental Information Services,

Generation Attribute Tracking System (GATS) Operating Rules, at 54 – 56 (September 30, 2010).

According to Article § 7-703(a)(2), exceptions for the RPS requirement may include: industrial

process load which exceeds 300,000,000 kWh to a single customer in a year; regions where

residential customer rates are subject to a freeze or cap (under Article § 7-505); or electric

cooperatives under a purchase agreement that existed prior to October 1, 2004, until the expiration

of the agreement.

For the 2010 compliance year, electricity suppliers retired 3,569,569 RECs, a

quantity greater than the overall RPS obligation for the year by almost 30,000 RECs.

According to the compliance reports filed with the Commission, the cost of RECs retired

totaled $7,630,526 for the 2010 compliance year. For each of the five compliance years,

Table VI.B.4 displays: the breakdown of RECs submitted for each tier in MWh; the

number of RECs retired in the year by tier in MWh; and the cumulative tiered shortfalls,

in terms of the ACP amount required in dollars per MWh.

Table VI.B.4: RPS Supplier Annual Report Results as of December 31, 2010

RPS Compliance Year

Tier 1

(non-solar) Tier 1 Solar Tier 2 Total

RPS Obligation (MWh)

520,073 - 1,300,201 1,820,274

Retired RECs (MWh)

552,874 - 1,322,069 1,874,943

2006

ACP Required ($/MWh)

$13,293

$24,917

$38,209

RPS Obligation (MWh)

553,612 - 1,384,029 1,937,641

Retired RECs (MWh)

553,374 - 1,382,874 1,936,248

2007

ACP Required ($/MWh)

$12,623

$23,751

$36,374

RPS Obligation (MWh)

1,183,439 2,934 1,479,305 2,665,678

Retired RECs (MWh)

1,184,174 227 1,500,414 2,684,815

2008

ACP Required ($/MWh)

$9,020

$1,218,739

$8,175

$1,235,934

RPS Obligation (MWh)

1,228,521 6,125 1,535,655 2,770,301

2009

Retired RECs (MWh)

1,280,946 3,260 1,509,270 2,793,475

ACP Required ($/MWh)

$395 $1,147,600 $270 $1,148,265

RPS Obligation (MWh)

1,922,070 15,985 1,601,723 3,539,778

2010

Retired RECs (MWh)

1,931,367 15,451 1,622,751 3,569,569*

ACP Required ($/MWh)

$20 $217,600 $0 $217,620

Sources: Annual Utility RPS Filings with the Commission in years 2007, 2008, 2009, 2010, and 2011.

Commission Reports, M

ARYLAND PUBLIC SERVICE COMMISSION, available at

http://webapp.psc.state.md.us/Intranet/psc/Reports_new.cfm (last visited Dec. 2011).

*Note

: Some electricity suppliers retired more RECs than required by individual RPS obligations.

In 2010 there was a shortfall of 544 MWh in RECs for the Tier 1 Solar

requirement of 15,985 MWh—significantly lower than the 2009 Tier 1 Solar REC

shortfall of 2,865 MWh. Therefore, the reliance by electricity suppliers on ACPs to

fulfill the Tier 1 Solar requirement decreased dramatically between 2009 and 2010.

However, the shortfalls associated with the RPS solar obligation still contributed over

99% of the total ACPs due for the 2010 compliance year. The degree to which solar

technologies are available to provide renewable output plays a role in the Tier 1 Solar

compliance option selected.

The RPS obligation is the total obligation for electricity sales in MWh, which is equal to the

number of RECs required for compliance. The number of retired RECs is the actual number of

RECs retired for RPS compliance in each corresponding compliance year. The ACP required is

calculated by multiplying the difference between the RPS obligation and the actual retired RECs

(i.e., the shortfalls) by the applicable ACP. All ACPs are denominated in U.S. dollars.

Chart VI.B.5 presents the geographical location and the total generating capacity

(5,615 MW) for all Maryland RPS-certified facilities, regardless of tier.

RPS

requirements also exist in the surrounding states, which generally support out-of-state and

regional market participation. Of the renewable facilities that are eligible to participate

and potentially provide renewable energy to Maryland, 68 percent are located in the Mid-

Atlantic states.

The locations of the remaining eligible resources span seven states and

in total contribute the remaining 32 percent of the State’s eligible capacity.

Chart VI.B.5: Maryland RPS Eligible Capacity by State

461.7

180.1

44.6

0.6

0.0

122.5

300.0

738.6

1,325.7

1,187.0

438.6

109.6

705.9

200

400

600

800

1,000

1,200

1,400

PA MD IL DE VA WV IN NY NJ OH WI DC NC

State

Capacity (MWs)

Source: PJM-EIS, Generation Attribute Tracking System, Database query, August 2011.

C. Solar Power Requirements in Maryland

In 2008, the Commission laid the foundation for an active solar market in

Maryland. Regulations were enacted which established a small generator interconnection

standard supported by an expedited process for the interconnection of solar facilities.

Additionally, regulations were adopted that established a mechanism for creating solar

renewable energy credits (“SRECs”) and a corresponding tracking site. To further

streamline the process, an on-line Solar Renewable Energy Facility application form was

introduced to the Commission’s website. Also, in 2009 the Commission approved

The information in this figure comes from PJM GATS, and does not include Commission

authorized renewable energy facilities that have not established a REC account with PJM GATS.

Facilities are classified as “MD Certified” if they have applied to the Commission and received an

approval number that is recorded in GATS.

For this discussion, the Mid-Atlantic states are classified as Pennsylvania, Maryland, Delaware,

Virginia, New Jersey, and the District of Columbia (“D.C”). The combined capacity of these Mid-

Atlantic state facilities is 3,803.5 MW, or approximately 68% of the total generating capacity of

Maryland RPS-certified facilities.

The other six states referenced in the text are: Illinois, West Virginia, Indiana, New York, Ohio,

Wisconsin, and North Carolina. The combined capacity of these facilities is 1,811.5 MW, or

approximately 32% of the total generating capacity of Maryland RPS-certified facilities.

modifications to the solar regulations to reduce the filing requirements for small solar

facilities.

For compliance year 2010, an LSE subject to Maryland RPS compliance

was

obligated to purchase a minimum of 0.025% of its electricity resources from eligible solar

sources.

The solar RPS obligation increases incrementally each year until reaching the

required 2.000% by 2022.

If an LSE fails to offset the applicable percentage of retail

electricity sales with electricity derived from solar resources or from the purchase of

SRECs, then the LSE is responsible for making an alternative compliance payment as set

forth in the RPS statute.

100

An electricity supplier seeking to satisfy its solar RPS obligation may choose to

accumulate credits from a renewable on-site generator for purposes of RPS

compliance.

101

The rated capacity of the renewable on-site generator governs the

minimum contract terms by which the LSE and solar electricity generator must generally

abide.

The Maryland Solar RPS grants customers the rights to the SRECs each system

earns, and requires contract terms to be a minimum of 15 years when the renewable

energy credits are purchased by an electricity supplier directly from the solar electricity

generator. For facilities that are greater than 10 kW in rated capacity, the stipulation

associated with an LSE purchasing SRECs directly from a renewable on-site generator to

meet the solar component of the Maryland RPS is that the contract terms for the SRECs

must be for no less than 15 years.

102

An LSE that purchases SRECs directly from a solar renewable on-site facility that

is less than 10 kW in rated capacity must do so through a contract that provides for an up-

front lump sum payment for at least 15-years’ worth of SRECs at a price that is

determined by the Commission. The up-front purchase of SRECs is intended to aid in

financing the construction of this type of solar installation. The current proposed level of

payment for the SRECs is the net present value of the 15-years’ worth of RECs using

80% of the compliance fee schedule,

with a discount rate that is equal to the Federal

Secondary Credit Interest Rate.

103

Beginning January 1, 2012, electricity generated from a Tier 1 solar renewable

source must be connected with the electric distribution grid serving Maryland in order for

the generation to be eligible to create Maryland SRECs after that date. Until January 1,

2012, SRECS from non-Maryland Tier 1 solar renewable energy facilities located in PJM

are eligible for the Maryland RPS only to the extent that there is a shortage of SRECs

derived from facilities interconnected with the Maryland grid. All Maryland-based Tier 1

See supra Section VI.B. (discussing entities subject to the RPS obligation).

MD. CODE ANN., PUB. UTIL. § 7-703(b) (2011).

See supra Table VI.B.2.

100

MD. CODE ANN., PUB. UTIL. § 7-705(b) (2011). See supra Table VI.B.3.

101

MD. CODE ANN., PUB. UTIL. § 7-709(a) (2011).

102

MD. CODE ANN., PUB. UTIL. § 7-709 (2011).

103

See COMAR 20.61.

solar renewable energy facilities must be certified by the Commission as a Maryland

renewable energy facility, prior to the facility being eligible to create Maryland-eligible

SRECs. As of August 2011, GATS had registrations for 1,585 solar facilities in

Maryland with a total capacity of 25.83 MW.

The decisions made in surrounding states regarding RPS requirements, ACP

levels, and the availability of state grants or subsidized loans may potentially impact the

Maryland RPS program. The prices that Maryland LSEs will need to offer to obtain

RECs in the spot market and under longer term arrangements may reflect the decisions of

surrounding states.

VII. ELECTRIC DISTRIBUTION RELIABILITY IN MARYLAND

The Commission supervises and regulates public service companies to promote

the economical and efficient delivery of utility services in the State. Economical and

efficient delivery of electricity depends on a well-planned, maintained, and operated

distribution system.

A. Electric Distribution Reliability Reporting, Operation and

Maintenance

Electric utilities serving 40,000 or more Maryland customers are required to file

an Annual Reliability Report with the Commission. For each utility, the reports contain

measurements of reliability for the preceding calendar year of the System Average

Interruption Duration Index (“SAIDI”), the System Average Interruption Frequency

Index (“SAIFI”) and the Customer Average Interruption Duration Index (“CAIDI”).

104

Each investor-owned utility also reports the reliability measurements for a group of the

least reliable electric feeders in its system for the year, together with the remedial actions

it has taken to improve the reliability of those feeders. The same feeders are not

permitted to appear on a utility's least reliable list in any two successive years under a

COMAR provision designed to gradually increase over time the reliability of all feeders

in the least performing range. The large electric cooperatives report the operating district

with the least reliability for the year, together with the remedial actions taken to improve

reliability within those districts.

Routine inspection and maintenance of existing distribution system equipment

must be performed periodically to help maintain a baseline level of reliability. All

electric companies serving Maryland have developed written operation and maintenance

(“O&M”) procedures pursuant to COMAR 20.50.02.04. The O&M procedures must list

the specific inspection and maintenance tasks to be performed and the frequency with

which the tasks are to be performed. The six largest electric utilities operating in

Maryland are required to maintain their written O&M procedures with the Commission

and to file annual updates of any changes that are made to those procedures. While the

procedures vary somewhat from utility to utility, there are many common practices, since

104

CAIDI is calculated by dividing SAIDI by SAIFI.

the procedures should be based on utility experience and accepted good practice within

the industry.

With respect to substations, periodic attention is typically given to power

transformers, various electrical relays and circuit breakers used primarily for equipment

protection, and devices used for controlling voltage such as capacitors and voltage

regulators.

For distribution feeder lines, inspection and maintenance attention is typically

focused on the electrical conductors in general, capacitors and other voltage regulators,

automatic re-closers, electronic monitoring/control devices, vegetation management, and

support poles for overhead equipment. Utilities have ongoing, proactive programs for

replacement of aged underground electrical conductors, in addition to such activity in

reaction to service interruptions. Some utilities inject conditioners into existing

underground cable to increase its life expectancy.

The electric distribution system is a large-scale array of electric power circuits

and, increasingly, electronic sensing and control circuits. Excessive heat, whether

generated internally or by a hot day, is one of the greatest threats to the proper operation

of electric and electronic circuits. Electric utilities use infrared imaging technology in

performing periodic inspections to identify substation equipment that is operating at a

temperature higher than the normal range for proper operation. Some utilities include

distribution feeder equipment in such inspections. The value in this procedure is that

abnormally hot spots in electric conductors or equipment can often be detected and

corrected long before they fail due to overheating.

Each utility is required by COMAR to keep sufficient records to demonstrate

compliance with its O&M procedures. The Commission’s Engineering Division

conducts yearly inspection visits to the electric utilities to examine these records, in a

continuing effort to assure basic distribution system reliability.

In recent years, electric distribution utilities have made efforts to raise the

baseline level of service reliability by increasing the automation of distribution feeders,

with the potential to reduce both frequency and duration of sustained electric service

interruptions. For example, some feeders can be connected with other feeders by

switches that are normally off (open), but can be closed so that one of the feeders may

temporarily supply part or all of a feeder experiencing an outage. Currently, many of

these switches are manually operated, and require a utility crew to operate the switches to

restore power. If the operation of such a switch is automated, either with local electronic

intelligence or through remote operation from the distribution system control or

operations center, service outage time to customers can be reduced.

Although electric service interruptions cannot be totally avoided, new utility

operating methods that could serve to improve reliability include more aggressive

attempts to reduce the threat of large privately- and publicly- owned trees or large

branches falling on overhead power lines. Utilities work to gain tree owner cooperation

to allow the removal of large trees near the lines or large branches overhanging the lines,

which would help reduce the frequency of service outages, particularly during storms.

Other efforts involve limiting the number of customers exposed to any given outage that

does occur.

As members of Mutual Assistance Groups, the utilities share restoration crew

manpower and other resources when outages increase beyond levels thought to be

manageable using the utility's normal resources. Such assistance serves to reduce outage

duration, one common measure of reliability. In addition to crew sharing, the groups

hold conference calls for storm preparation for storm damage assessment, and to discuss

overall restoration resource availability.

The four large investor-owned electric utilities operating in Maryland are

members of the Mid-Atlantic Mutual Assistance group and the Southeastern Electrical

Exchange. Another similar group, Maryland Utilities, includes municipal and

cooperative electric utilities. These groups and others will continue to be important

alliances in the years to come, as effective distribution outage management and storm

restoration requires not only a community-wide effort, but sometimes also a regional or

national effort.

B. Distribution Reliability Issues

1. Rulemaking No. 43

The Commission instituted Rulemaking No. 43 to adopt service quality and

reliability standards. During the pendency of the Rulemaking, the Legislature enacted

Chapter 167 of the 2011 Laws of Maryland also requiring the institution of service

quality and reliability standards. The Commission convened a working group in this

Rulemaking to make recommendation, which recommendations were presented to the

Commission on October 27, 2011. The Commission considered the working group’s

recommendations and other comments submitted thereon and adopted a set of

comprehensive service quality and reliability standards.

The standards include several major categories. The Commission adopted, for

publication in the Maryland Register for notice and comment,

105

system-wide SAIDI and

SAIFI reliability metrics for each of the four investor-owned utilities and the two largest

electric cooperatives. The SAIDI and SAIFI metrics are for calendar years 2012-2015,

after which the Commission will institute company proceedings to determine future

SAIDI and SAIFI reliability metrics. To ensure that groups or pockets of customers do

not experience poor reliability, the Commission adopted standards to monitor utility

feeders and protective devices that activate multiple times. These two reliability

standards require the utilities to improve the performance of the poorest three percent of

the utility’s feeders and protective devices that operate five or more times.

105

The term “adopted” in this subsection means “adopted for notice and comment.” These standards

have not been finally adopted as of December 31, 2011.

Additionally, the Commission adopted standards governing a utility’s effort to

restore service interruptions. The service interruption standards call for electric service to

be restored within certain time periods during normal conditions and when major outage

events occur. Major outage events are weather-related or other events that cause an

interruption in electric service to 100,000 or 10 percent of a utility’s customers,

whichever is less.

106

To ensure adequate utility response to downed electric wires, the

Commission also adopted standards to direct utility response to hazardous downed wire

events.

The reliability and service quality standards also establish customer

communication metrics related to how long it takes a utility representative to answer a

customer’s calls, how many calls are abandoned and how much telephone line capacity is

maintained for customer inquires. These standards establish the minimum level of

expected service quality. Finally, the Commission adopted comprehensive vegetation

management and periodic equipment maintenance standards. These two categories

establish minimum practices for utilities when maintaining and operating their electric

facilities.

The electric utilities are required to submit annual performance reports to the

Commission summarizing electric service quality and reliability results. By July 1

each year, the Commission shall determine whether each company met its service quality

and reliability standards. The first review will be concluded by July 1, 2013 after

considering utility performance during 2012.

107

If a utility fails to meet one or more of

its standards, the utility must file a corrective action plan if it fails a standard. The

Commission will under take appropriate corrective action against a utility that fails to

meet a standard, including imposition of appropriate civil penalty.

Electric utilities will need to develop implementation plans or supplement existing

plans to ensure their level of performance meets or exceeds the new service quality and

reliability standards discussed above.

2. In the Matter of an Investigation into the Reliability and Quality of the

Electric Distribution Service of Potomac Electric Power Company – Case

No. 9240

As reported in the 2010 Annual Report, on August 12, 2010, the Commission

initiated the docketed Case No. 9240 for the purpose of investigating the reliability of

Pepco’s electric distribution system and the quality of electric distribution service that

Pepco is providing to its customers. The initiation of the investigation was based on the

unusually large number of complaints from Pepco’s customers and their elected officials

alleging frequent and lengthy service outages during and after storm events as well as

during “blue sky” conditions. Further, customers expressed frustration with the failure of

106

The interruption must last for 24 or more hours.

107

The standards adopted by the Commission are anticipated to become effective on July 1, 2012.

Thus, the first performance review will cover the portion of 2012 during which the standards are

effective.

Pepco’s communications system during storm events, which resulted in the customers

being unable to obtain estimated times of restoration or report outages. The Commission,

in addition to holding a legislative-style hearing in August 2010 for the purpose of

questioning the Company’s senior executive responsible for system reliability, storm

restoration, and customer communications:

•

held two evening hearings for public comment to permit members

of the public and elected officials to provide their views on

Pepco’s service quality and reliability;

•

issued extensive data requests to the Company to produce

documents and information;

• required Pepco to hire an independent consultant to evaluate

Pepco’s distribution system and communication system

(“Consultant”), and directed the Consultant to submit a report

of the its findings and recommendations to the Commission;

and

• held four days of evidentiary hearings at which the Consultant

presented its findings and all parties, as well as the

Commission, were able to cross-examine the consultant, the

Company’s witnesses and the other parties’ witnesses on their

pre-filed testimony.

Prior to the hearings in August 2010, the Company submitted its Reliability

Enhancement Plan for Montgomery County, Maryland (“REP”). According to the

Company, the REP was designed to significantly increase the reliability of its distribution

system in Maryland over a five-year period and included the following six-point

reliability programs: enhanced vegetation management; priority feeders; load growth;

distribution automation; URD cable replacement; and selective undergrounding. The

Company committed to making adjustments to plan as necessary, as the plan was

implemented.

In May 2010, Montgomery County filed its Pepco Work Group Final Report,

which contained a series of findings and recommendations by a 12-member Work Group

assembled by Montgomery County tasked with investigating the causes of Pepco’s

frequent electricity outages in the County. The filing of this Work Group Report resulted

in a contentious discovery dispute between Pepco and the County. After holding a

hearing on the discovery dispute, the Commission issued a subpoena compelling

Montgomery County to present a witness or panel of witnesses at the evidentiary hearing

to sponsor and answer questions related to the Work Group Report. Montgomery County

also responded to the discovery requests.

In addition to the Company’s witnesses’ pre-filed testimony and the Work Group

Report, pre-filed testimony was submitted by Technical Staff of the Commission,

Maryland Office of People’s Counsel, Maryland Energy Administration, and the City of

Gaithersburg. The City of Gaithersburg did not sponsor a witness and its testimony was

not admitted into the administrative record. The Apartment and Office Building

Association of Metropolitan Washington intervened in the matter, but did not file

testimony. The Office of People’s Counsel of the District of Columbia petitioned to

intervene, but was ultimately granted status as an interested person rather than a party.

On December 21, 2011, the Commission issued Order No. 84564 in which it

concluded that, as alleged by its customers, Pepco had failed to provide an acceptable of

reliable service during 2010 as well as several of the preceding few years. Similar to the

findings of the Consultant, the Commission found that a direct cause of Pepco’s low level

of reliability was its poor and ineffective maintenance of the vegetation surrounding its

sub-transmission and distribution system. Specifically, the Commission pointed to the

evidence in the record that Pepco failed to adequately fund its vegetation management,

failed to meet its own annual tree trimming goals, and failed to adopt a more aggressive

tree trimming practice similar to the practices adopted by other Maryland electric

companies after 2001. Moreover, the Commission cited the decline of Pepco’s SAIFI

figures (adjusted for major outages) during each year from 2004 to 2010 as proof of the

steadily deteriorating level of reliability which coincided with Pepco’s poor vegetation

management practices. These documented failures and deteriorating level of reliability as

measured by SAIDI and SAIFI were evidence of the Company’s neglectful conduct and

poor engineering practices sufficient to constitute a violation of its obligations to provide

reliable service to its customers. Further, the Commission found that Pepco failed to

conduct periodic inspections of its sub-transmission and distribution lines or to direct

after-storm inspections or patrols as required by the National Electrical Safety Code

(“NESC”) and COMAR 20.50.02.02. Although the Commission held that NESC Rule

214 does not require any precise intervals between inspections, it does require that the

Company inspect at intervals experience shows is necessary. The lack of any procedure

establishing an interval for periodic inspections reflected that the Company was not

complying with the NESC rules or COMAR. Accordingly, based on Pepco’s failure to

provide its customers reliable service and its violation of the regulations requiring it to

periodically inspection its sub-transmission and distribution line, the Commission

assessed Pepco a civil penalty of $1 million.

Many of the parties in the matter requested that the Commission, in addition to

fining the company, reduce Pepco’s authorized return on equity, restrict its payment of

dividends to PHI, direct Pepco to waive its monthly customer charge, or modify or

revoke Pepco’s authority to exercise its franchise. The Commission declined to adopt

any of these additional penalties, but it agreed with the Maryland Energy Administration,

Office of People’s Counsel and Montgomery County that it is

inequitable for Pepco to have caused significant reliability problems

and escalating EIVM costs as a result of years of poorly executed and

underfunded vegetation management programs and for the Company’s

ratepayers to be burdened with full repayment for the EIVM programs

that are now required as a direct result of the company’s

imprudence.

108

Order No. 84564 at 59.

Specifically, the Commission found that Pepco acted imprudently by: failing to

execute adequate vegetation management; by neglecting to conduct periodic inspection or

after-storm patrols; by engaging in uncertain and at times contradictory tree trimming

practices between 1999 and 2010; and by refusing to transition to a four-year tree

trimming cycle, consistent with other Maryland utilities and the recommendations of the

tree Trimming Working Group.

109

Because the Commission found that it was highly

probably this imprudence increased the cost to ratepayers of the Company’s vegetation

management programs beyond what they should have been if Pepco had acted prudently,

the Commission determined that, in a future rate case, it will disallow recovery of any

incremental amounts expended for Pepco’s vegetation management programs that is

demonstrated to have been caused by Pepco’s imprudence.

Additionally, the Commission designed a series of reporting requirements to

ensure that Pepco is implementing its REP in a manner that is significantly increasing

reliability. Also, in light of the Commission’s finding that Pepco’s ineffective

communications system contributed to significantly to customer dissatisfaction, the

Commission directed quarterly reports on Pepco’s effort to reform its communications

issues. The Commission did not modify Pepco’s REP, as requested by certain of the

parties, but encouraged Pepco to consider that comments or suggestions of these parties

as it conducts its annual review of the REP to determine further updates that will improve

reliability. Finally, the Commission warned Pepco that, in the event the periodic reports

filed by the Company did not reflect improvement of service reliability, the Commission

may consider a larger civil penalty or other additional penalties as justified by the

circumstances.

3. Electric Service Interruptions Due to Hurricane Irene

According to the United States Department of Energy (“DOE”), Hurricane Irene

made landfall near Cape Lookout, North Carolina as a Category 1 hurricane at 8:00 a.m.

EDT on August 27, 2011. In September 2011, the Commission initiated Case No. 9279

to investigate the electric service interruptions due to Hurricane Irene. Maryland’s four

investor-owned utilities,

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along with SMECO and Choptank Electric Cooperative filed

major storm reports, pursuant to Commission Order No. 84306 and in compliance with

COMAR 20.50.07.07 in an effort to detail the utility’s response and preparation efforts

regarding Hurricane Irene.

According to data provided by utilities, customers began losing power at 7:50

a.m. EDT on August 27, 2011. Power was not restored to more than 99.9% all affected

customers until 11:30 p.m. EDT on September 4, 2011.

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The utilities dispatched

approximately 11,882 employees to restore power as a result of Hurricane Irene, with

109

Id.

110

BGE, Pepco, Delmarva, Potomac Edison

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BGE restored power to 756,016 of the 756,395 affected customers at the declared end of the storm

at 11:30 p.m. EDT on Sept. 4. See Baltimore Gas and Electric Company Major Storm Report –

Hurricane Irene August 27 through September 4, 2011 p 34 for detailed explanation.

nearly half of the employees coming from outside the utility. Out of all of the impacted

utilities, BGE experienced the highest peak of customer outages with 476,664; followed

by Pepco, 194,516; SMECO, 104,328; Delmarva, 63,597; Choptank, 11,990

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; and

Potomac Edison, peaking with 8,554 customer outages.

On October 31, 2011 the Commission issued Order No. 84445 in the matter of the

electric service interruptions due to Hurricane Irene in the State of Maryland beginning

August 27, 2011. As a result of this Order, the four IOUs as well as Choptank and

SMECO were directed to undertake three specific categories of actions: (1) submit

implementation plans in regard to the “lessons learned” issues identified in the respective

post-Irene Major Storm Report; (2) participate in a work group tasked with developing

standards to provide customers reasonable and reliable estimated time of restoration

(“ETR”) information; and (3) file with the Commission the protocols used in determining

restoration priority.

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C. Managing Distribution Outages

An important tool developed in recent years for managing electric distribution

system outages is the computerized Outage Management System (“OMS”). When an

outage occurs, a fully developed OMS accepts information inputs from several sources,

including customers and systems internal to the utility, and uses that information to help

develop output information as to the location and type of equipment that needs attention

in order to end the outage. This output information can then be used to generate work

orders for repairs or dispatch repair crews by way of a Mobile Dispatch System (“MDS”)

using two-way radio communication. After repairs are made or other actions taken to

end the outage, related outage information is entered as additional input into the OMS.

The OMS then can identify what customers were affected by the outage, usually what

caused the outage, and when it started and ended.

1. Typical Information Inputs to the OMS

• Customer Information System (“CIS”):

When a customer calls in an

outage, the customer interacts with elements within the utility that

have access to the CIS, such as a Customer Service Representative, an

automated Interactive Voice Response (“IVR”) unit, or a High Volume

Call Service (“HVCS”). The CIS contains the customer's address, can

identify the distribution system transformer that serves the customer,

and passes this information on to the OMS. The OMS then can be

used, with assistance from the next two listed inputs, to identify the

location of the customer, both in terms of electrical position in the

system diagram and geographic position.

112

See Choptank Electric Cooperative Major Storm Report – Hurricane Irene Sept. 21 at 1. The

utility explains that it believes the maximum number of peak outages is 11,990 members but the

utility’s outage management software (OMS), which malfunctioned, reported 8,862 outages. The

OMS was used to calculate the Storm Timeline and the data in Figure 1.

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See Commission Order No. 84445, pg. 1-2.

The traditional CIS function will be transformed as some utilities

begin to implement elements of Advanced Metering Infrastructure.

Advanced electric service meters and associated two-way communications

systems between the customer and utility provide an information channel

with the potential for use by both parties to make important decisions

related to the efficient supply and use of electricity. AMI also promises

faster detection of and more accurate utility response to electric service

outages, and may largely replace the role of outage detection provided by

customer calls within the traditional CIS.

• Energy Management System (“EMS”): The EMS includes an electronic

diagram of the electric system showing how elements are connected

electrically. The EMS also uses remote monitoring devices such as those

of the Supervisory Control and Data Acquisition (“SCADA”) system, so

that information related to the operational condition of important, major

pieces of electric system equipment can be passed on to the OMS.

• Geographic Information System (“GIS”): The GIS includes a map of key

landmarks such as streets, and it shows the location of important elements

of the electric system relative to those landmarks. This relationship is

clearly important in the effort to get repair crews to the heart of the matter.

In addition to providing information to the OMS, both the EMS electric

system diagram and the GIS map can be displayed on computer monitors

and are used by dispatchers to direct the efforts of repair crews.

• Mobile Dispatch System and Work Management System (“WMS”): After

an outage is cleared, a work order is closed out within the WMS, and in

some cases the repair crew can directly close the outage with, and enter

related information directly into, the OMS using the MDS. The WMS or

MDS information usually includes the time of restoration and the cause of

the outage. After this information input is made, the OMS then contains

an archive of important information about the entire history of the outage.

2. Typical Information Outputs from the OMS

• Information about the type of equipment involved in the outage and its

location is passed to the WMS or MDS so that crews can be effectively

dispatched to clear the outage.

• Prior to the clearing of an outage, an Estimated Time of Restoration

(“ETR”) and other information can be fed back to the CIS, so customers

calling in who are affected by a particular ongoing outage may be kept

informed.

• Information concerning outages can be extracted from the OMS in near

real-time to feed Internet websites containing outage reports or outage

maps.

• The OMS can be queried for outage information to be used to generate

reports concerned with reliability statistics for the entire distribution

system or any part thereof.

The four large investor-owned electric utilities operating in Maryland and the

large electric cooperatives, Choptank and SMECO, have implemented OMS, each with

functionality developed generally to the extent described above.

Improvements and efforts to increase the functionality of the OMS elements are

ongoing. As with most computer and software-based systems, the OMS evolves with

each new software upgrade, and as utilities learn how to best utilize the systems.

Furthermore, the OMS is expected to evolve in the next few years as a result of the

Commission’s Order No. 84445 in the matter of the electric service interruptions due to

Hurricane Irene in the State of Maryland beginning August 27, 2011. The Order directs

the four investor-owned electric utilities and SMECO to participate in a work group

tasked with developing standards to provide customers reasonable and reliable ETR

information; ETR information is a typical information output from an OMS system.

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Additionally, Pepco’s system tasked with providing customers and emergency

management personnel timely outage-related information remains under review in Case

No. 9240.

D. Distribution Planning Process

The role of an electric distribution system planner begins with identification of

customer needs, both for the near term and the longer term. Once identified, those needs

are translated into a flexible plan involving the engineering and operations functions

necessary to meet those needs. Short term planning typically focuses on system

expansion to keep pace with electric load growth and maintenance or improvements

related to reliability or safety of the system, with a forecast horizon of a few years.

Longer term planning, with a forecast horizon of 10 to 20 years, may include

expectations of new technologies and altered business climate, in addition to

considerations of expanded load growth, reliability, and safety of the system.

A sampling of the largest electric distribution system projects and programs,

ongoing, planned, or in development by Maryland's large electric companies, follows.

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See Commission Order No. 84445, pg. 1-2.

1. PE

• In 2012, PE expects to complete construction of two substations, to serve the

town of Keedysville and surrounding area, and to serve the area of Lappans

Crossroads.

• PE plans to complete a major upgrade of facilities at its Urbana substation in 2012

to provide additional capacity to serve the town of Urbana and the surrounding

area.

• PE plans to complete construction in 2013 of a substation to serve the town of

Walkersville and the surrounding area.

• In 2014, PE plans to upgrade three substations. The substations supply an area

west of Frederick, an area south of Frederick, and the Taneytown area.

• PE plans to complete the construction of a new substation to serve an area around

Deep Creek Lake by 2014.

• PE expects to complete a capacity upgrade of a substation serving an area south of

Mt. Airy in 2017.

• PE plans to construct a new substation to serve the area southwest of Frederick in

2019.

2. BGE

• BGE plans to construct three additional new substations by the end of 2012. The

substations are to serve the Fallston area of Harford County, the Laurel area of

Howard County, and the Sykesville area of Carroll County.

• BGE expects to finish the rebuilding of a substation serving northern Baltimore

City/Baltimore County in 2012. The utility also expects to complete work to

transfer load between feeders and substations to benefit the Westport area of

Baltimore City in 2012. The work will retire aging facilities and increase

reliability of the network distribution system in the area.

• In 2013, BGE plans to build a new substation to serve load growth in the Konterra

Town Center and to relieve other existing substations in the Laurel area. Plans for

2013 also include completing a capacity upgrade in a substation serving Prince

George's County.

• BGE plans to complete the construction of two new substations and the rebuilding

of two others in 2014. The rebuilding efforts will retire aging facilities and

increase electric capacity. These efforts will benefit the Cockeysville and Towson

areas of Baltimore County, and the Carroll/Calverton area of Baltimore City.

• Between 2015 and 2016, BGE intends to build five new substations and rebuild

two others. The work would provide additional electric capacity to three areas in

Harford County, three areas in Baltimore City, and the Hampstead area of Carroll

County.

3. Choptank

• Choptank expects load growth to occur along the U.S. Route 301 corridor in

Kent and Queen Anne Counties, Chestertown, Cambridge, Easton, the west

side of Salisbury, and the east side of Berlin.

• Construction of a new substation to serve the Cambridge area is planned for

completion by the end of 2012. Currently, most of Choptank's electrical load

in Dorchester County is supplied by one substation, which constitutes a single

point of connection to the transmission grid. The addition of the new

substation would create a backup delivery point in addition to providing

increased capacity.

4. DPL

• DPL plans to complete the construction of a substation to serve southern

Talbot County in 2012.

• To serve southwestern Kent County, DPL plans to construct a substation and

extend two feeders in 2013. The utility also intends to complete construction

of a new substation that year to serve growing electrical load in Harford

County.

• DPL expects to complete the construction of a substation and the extension of

three feeders in 2014 to serve Cecil County.

• During 2017, DPL intends to complete construction of a new substation to

serve the Queenstown area of Queen Anne's County, and the rebuilding of a

substation to serve the Salisbury area.

5. Pepco

• During 2012, Pepco plans to build two new feeders and to extend two others to

serve the Lanham area of Prince George's County. Plans for the year also

include extending and increasing the capacity of an existing feeder to serve the

Greenbelt Station Project.

• By the close of 2012, Pepco plans to complete construction of a new feeder

and the extension of another to meet the electricity needs of the National

Harbor Development and the Gaylord National Hotel and Conference Center.

• Pepco’s plans for 2013 include a capacity upgrade of a substation serving the

Colesville, Rossmoor, and Fairland areas of Montgomery County.

• Pepco plans to complete the construction of a substation in 2014 to supply the

Westphalia Town Center and the Melwood and Forestville areas of Prince

George's County.

• To accommodate the projected demand for electricity in the Hunting Hill,

Shady Grove, and Fernwood Road areas of Montgomery County, Pepco plans

to complete the construction of two substations by mid-2015. By the close of

that year, the utility intends to extend three feeders to serve the Woodmount

area of Montgomery County.

• Pepco plans to complete the construction of a new substation in 2017 to

accommodate load growth in the Beltsville area of Prince George's County.

6. SMECO

• During 2013, SMECO plans to purchase an additional mobile substation to be

used to provide backup power during outage contingency situations in areas

where providing backup power through distribution feeder switching is difficult

or impossible.

VIII. MARYLAND ELECTRICITY MARKETS

The Electric Customer Choice and Competition Act of 1999 (“Electric Choice

Act”) established the legal framework for the restructuring and revised regulation of the

electric industry in Maryland. The Electric Choice Act altered the Commission’s role

relative to electricity generation and provided that retail electric choice would be

available to all customers. Beginning on July 1, 2000, all retail electric customers of

IOUs in the State were given the opportunity to choose their electricity supplier. Since

July 1, 2003, customers of Maryland’s electric cooperatives have had the right to choose

suppliers under a separate schedule adopted by the Commission. Customers of

Maryland’s municipal electric utilities will be allowed to choose suppliers on a timetable

established in part by the municipal utilities.

A. Status of Retail Electric Choice in Maryland

Customers shopping for electricity in Maryland may choose to buy electricity

from a competitive supplier or to take standard offer service from their local electric

company. This framework was established by the Electric Choice Act of 1999. This Act

deregulated the pricing of electric generation and opened retail markets to competitive

suppliers. Opening retail markets for competition has attracted competitive suppliers to

Maryland. As of December 1, 2011, Maryland has 65 licensed electricity suppliers and

146 licensed electricity brokers.

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As of December 1, 2011, the following numbers of

companies had registered on the Commission’s website as actively soliciting new

customers in any Maryland service territory: 32 serving residential load, 65 serving

industrial load, 70 serving commercial load, and 18 serving other types of load (such as

government).

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See Table A-6.

An examination of the number of customers using a competitive supplier indicates

that the transition from utility-supplied generation service to electric competition in

Maryland shows that a smaller percentage of residential customers have switched to retail

suppliers than non-residential customers. As of September 30, 2011, 19.2% of residential

customers, 29.3% of small commercial customers, 56.3% of mid-sized commercial and

industrial customers and 91.7% of large commercial and industrial customers were served

by retail electricity suppliers. In terms of total electricity supply, almost half of IOU load

(47.3%) was served by retail electricity suppliers as of September 30, 2011.

In 2011, residential switching continued to increase as the number of Residential

Choice customers increased by 42% statewide. The increase in switching may be due to

the availability of savings over the Standard Offer Service rates. Certain residential

electricity offers have been observed to be on the order of 10% below the cost of

Standard Offer Service, saving an average customer about $150 per year. The

implementation of utility purchase of retail supplier receivables in 2010 for those

suppliers that use utility billing probably also played a significant role in the increase in

the number of residential customers served by retail electricity suppliers.

The following table illustrates the increase in residential customer switching during 2011:

Table VIII.A.1: Residential Customers Enrolled in Retail Supply

2010 2011

Annual %

Increase

BGE

179,801 250,856 40%

DPL

12,759 17,481 37%

11,763 16,101 37%

Pepco

64,335 98,310 53%

Md. Total 268,658 382,748 42%

Source: Electric Choice Enrollment Monthly Reports.

Note:

2011 data is as of September 30, 2011.

Between December 2005 and September 2011, the total number of customers

statewide served by electricity suppliers increased from 39,527 to 553,438 customers.

During the same time, the number of customers served by electricity suppliers in BGE’s

service territory increased from 3,347 to 339,932.

Table VIII.A.2: Electric Choice Enrollment in Maryland as of September 30, 2011

Number of Customers Served by Competitive Electricity Suppliers

Utilities Residential Small C&I Mid C&I Large C&I All C&I Total

BGE

250,856 28,822 15,037 679 44,538 339,932

DPL

17,481 6,828 2,841 70 9,739 36,959

16,101 6,760 3,211 113 10,084 36,269

Pepco

98,310 11,283 9,196 505 20,984 140,278

Total 382,748 53,693 30,285 1,367 85,345 553,438

Percentage of Peak Load Obligation Served by Competitive Electricity Suppliers

Utilities Residential Small C&I Mid C&I Large C&I All C&I Total

BGE

23.9% 34.5% 71.0% 95.5% 78.5% 48.7%

DPL

11.8% 38.2% 69.9% 91.8% 70.2% 37.4%

8.1% 34.2% 64.0% 62.4% 61.1% 34.2%

Pepco

21.9% 42.4% 72.1% 94.5% 80.1% 52.7%

Total 20.9% 36.4% 70.5% 91.1% 76.5% 47.3%

Source: Electric Choice Enrollment Monthly Report, Month Ending September 2011.

Notes: Small commercial and industrial (“C&I”) customers are commercial or industrial customers with demands

less than or equal to 25 kW. These customers are eligible for “Type I” fixed-price utility SOS if they do not switch

to a supplier. Mid-sized C&I customers are commercial or industrial customers with demands greater than 25kW,

the level for small C&I service (Type I SOS) but less than 600 kW. These customers are eligible for “Type II” fixed

price utility SOS if they do not switch to a supplier. See Case Nos. 9037 and 9056 for more information on the Type

II customer class. Large C&I customers are commercial or industrial customers with demands equal to or greater

than 600 kW. These customers are no longer eligible for “Type III” SOS and receive hourly-priced service (based

on PJM hourly LMP) if they do not switch to a supplier.

B. Standard Offer Service

Standard Offer Service (“SOS”) is electricity supply service sold by electric

utility companies to any customer who does not choose a competitive supplier. The

statute requires that SOS should be “designed to obtain the best price for residential and

small commercial customers in light of prevailing market conditions at the time of the

procurement and the need to protect these customers against excessive price

increases.”

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Except for Potomac Edison,

117

the investor owned electric companies provide

SOS by purchasing wholesale power contracts with two-year terms twice a year, for

116

MD. CODE ANN., PUB. UTIL. § 7-510(c)(4)(ii) (2011).

117

PE procures its residential and small commercial SOS full service requirement through the sealed

bid process similar to the other IOUs, but they procure a portion of the SOS load four times a year

and the length of the contract varies.

residential and small commercial service of two-year terms, through sealed bid

procurements. These procurements take place in the Spring and Fall for service starting

the following Fall and Summer; each procurement covers roughly 25% of the total SOS

load. Consequently, the SOS price for residential and small commercial customers at any

one time reflects an average of market conditions on those four bid days.

SOS for mid-sized non-residential customers is not intended to stabilize prices

over an extended period of time. Mid-sized non-residential SOS is procured through

sealed bids for three-month contracts procured four times a year. The price of the service

at any one time reflects market conditions on the most recent bid day.

SOS for SMECO is procured by the cooperative through an actively managed

portfolio approach. Choptank provides SOS through procurement of full-requirements

wholesale service through the Old Dominion Electric Cooperative.

IX. REGIONAL ENERGY ISSUES AND EVENTS

A. Overview of PJM, OPSI, and Reliability First

The flow of electricity and the electricity markets are undeniably regional

concepts. Maryland is not an energy island—the transmission lines located within

Maryland do not terminate at our borders, but rather are connected to the transmission

lines in adjoining states.

The entire State of Maryland resides within PJM, the RTO that coordinates the

movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky,

Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee,

Virginia, West Virginia, and the District of Columbia. The FERC is responsible for

approving tariff changes proposed by PJM, which wholesale market entities operating in

Maryland must abide by as a member of PJM.

The Organization of PJM States, Inc. (“OPSI”) is

an organization of statutory

regulatory agencies in the 13 states and the District of Columbia that form PJM. The

Commission is a member of OPSI.

In addition, Maryland falls within the boundaries of Reliability First, one of eight

regional entities approved by North America Electric Reliability Council (“NERC”) as of

January 1, 2006 to develop and enforce regional reliability standards.

1. PJM Interconnection, LLC

PJM, as an RTO, keeps the electricity supply and demand in balance by providing

power producers price signals to generate sufficient power to match supply with demand

and by adjusting import and export transactions. In managing the grid, the company

dispatches about 180,400 MW of generating capacity over 61,200 miles of transmission

lines.

118

PJM exercises a broader reliability role than that of a local electric utility. PJM

system operators conduct dispatch operations and monitor the status of the grid over a

wide area, using an enormous amount of telemetered data from nearly 74,000 points on

the grid.

119

This gives PJM a big-picture view of regional conditions and reliability

issues, including those in neighboring systems.

PJM also manages a sophisticated regional planning process for generation and

transmission expansion to ensure the continued reliability of the electric system. PJM is

responsible for maintaining the integrity of the regional power grid and for managing

changes and additions to the grid to accommodate new generating plants, substations and

transmission lines.

PJM’s members (totaling more than 750) include: power generators, transmission

owners, electricity distributors (including Maryland utilities), power marketers and large

consumers.

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The Commission is not a member of PJM (meaning it is unable to cast a

vote); however, it does monitor and actively participates in stakeholder and committee

processes at PJM.

2. Organization of PJM States, Inc.

OPSI was established in 2005. OPSI, among other things, coordinates activities

such as data collection, issue analyses, and policy formulation related to PJM, its

operations, its market monitor, and related FERC matters.

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OPSI provides a means for

the PJM states to act in concert with one another when it is deemed to be in their common

interest. Actions of OPSI, however, do not bind individual commissions or the states

they represent.

Each state commission has a member on the OPSI Board of Directors. Chairman

Nazarian of the Commission served as OPSI President during 2009. Commissioner

Brenner currently serves as the Commission’s member on the OPSI Board of Directors.

During 2011, OPSI was particularly active in facilitating the development of the

Independent State Agency Committee (“ISAC”). The purpose of ISAC is to provide PJM

with modeling input for potential transmission planning studies. However, no ISAC

118

PJM’s Role as an RTO, PJM (June 1, 2011), http://www.pjm.com/~/media/about-

pjm/newsroom/fact-sheets/pjms-role-as-an-rto-fact-sheet.ashx.

119

Company Overview, PJM, http://www.pjm.com/about-pjm/who-we-are/company-overview.aspx

(last visited December 1, 2011).

120

Company Overview, PJM, http://www.pjm.com/about-pjm/who-we-are/company-overview.aspx

(last visited December 1, 2011).

121

Organization of PJM States, Inc., available at: http://www.opsi.us.

member will be bound by the results of any PJM transmission planning study.

Furthermore, the participation of any state in ISAC proceedings will not be considered an

assessment of the merits of any particular transmission expansion project. As an OPSI

Board member, the Commission will serve as the lead agency on ISAC for the State. The

Commission continues to be a very active participant in OPSI.

3. Reliability First Corporation

ReliabilityFirst is a not-for-profit company which began operations on January 1,

2006. ReliabilityFirst's mission is to preserve and enhance electric service reliability and

security for the interconnected electric systems within the ReliabilityFirst geographic

area. The Boundaries of ReliabilityFirst are defined by the service territories of Load

Serving Entities and include all of New Jersey, Delaware, Pennsylvania, Maryland,

District of Columbia, West Virginia, Ohio, Indiana, Lower Michigan and portions of

Upper Michigan, Wisconsin, Illinois, Kentucky, Tennessee and Virginia.

ReliabilityFirst's primary responsibilities include developing reliability standards and

monitoring compliance to those reliability standards for all owners, operators and users of

the bulk electric system and providing seasonal and long-term assessments of bulk

electric system reliability within its Region. The Commission monitors ReliabilityFirst

activities and comments if necessary.

B. PJM Summer Peak Events of 2010 and 2011

Peak load is maximum load usage during a specified period of time. Table IX.B.1

provides the coincident peaks as measured by PJM to illustrate the maximum amount of

MW usage in PJM at a particular time during a 12-month period. PJM is a summer

peaking region, meaning that it has historically experienced its peak loads during hot

summer days when air-conditioning usage increases to meet cooling demand. PJM

measures energy usage over an hour; accordingly, the data in the table below means the

peak occurred sometime in the 59 minutes preceding the hour listed. The table also shows

the average LMP for each Maryland utility zone and for all of PJM at the peak hours.

Table IX.B.1: Summer 2010 and 2011 Coincident Peaks and Zone LMP

Summer 2010 Coincident Peaks Zone LMP During the Peak

Day Date Hour MW PE BGE DPL PEPCO PJM

Tuesday 7/6/2010 17:00 136,950 $146.60 $331.01 $332.23 $250.24 $194.70

Wednesday 7/7/2010 17:00 137,788 $139.44 $183.75 $196.80 178.59 $135.93

Friday 7/23/2010 17:00 134,917 $164.76 $271.36 $213.22 $231.33 $169.13

Tuesday 8/10/2010 17:00 132,570 $145.08 $152.42 $137.34 $141.86 $137.93

Wednesday 8/11/2010 17:00 131,949 $129.64 $126.25 $122.75 $153.04 $114.67

Summer 2011 Coincident Peaks Zone LMP During the Peak

Day Date Hour MW PE BGE DPL PEPCO PJM

Wednesday 6/8/2011 17:00 144,394 $267.88 $422.85 $352.54 $417.40 $279.82

Tuesday 7/19/2011 17:00 145,253 $96.18 $101.78 $104.43 $99.20 $99.25

Wednesday 7/20/2011 17:00 150,121 $179.70 $195.48 $207.51 $186.14 $187.70

Friday 7/21/2011 17:00 158,121 $165.32 $199.17 $196.36 $162.03 $162.36

Thursday 7/22/2011 15:00 152,921 $182.94 $361.51 $407.29 $209.20 $229.54

Source: Daily Real-Time LMP Files, PJM MARKETS & OPERATIONS, http://www.pjm.com/markets-and-

operations/energy/real-time/lmp.aspx (last visited Nov. 30, 2011).

The 2011 summer peak events in PJM were higher than the summer peak events

that occurred in 2010. Table IX.B.1 above shows the summer 2011 and 2010 coincident

peaks in PJM and the average real-time LMP by zones located in Maryland during that

time period. The summer 2011 peak was 158,121 MW and occurred on July 21, 2011

during the hour ending 5:00 PM Eastern Daylight Time.

122

The summer 2010 peak was

137,788 MW and occurred on July 7, 2010 during the hour ending 5:00 PM Eastern

Daylight Time.

123

C. PJM’s Reliability Pricing Model

As a means of ensuring reliability of the electric system in the RTO, PJM

annually conducts a long-term planning process that compares the potential available

generation located within the RTO and the import capability of the RTO against the

estimated demand of customers within the RTO and establishes the amount of generation

and transmission required to maintain the reliability of the electric grid within PJM. The

amount of capacity procured in PJM’s Reliability Pricing Model (“RPM”) is roughly

based upon a forecast of the peak load projected by PJM for a particular year, plus a

reserve margin. RPM works in conjunction with PJM’s RTEP to ensure reliability in the

PJM region for future years.

122

Summer 2011 Coincident Peaks, PJM PLANNING, http://www.pjm.com/planning/resource-

adequacy-planning/~/media/planning/res-adeq/load-forecast/pjm-5cps-and-w-n-zonal-peaks.ashx

(last updated Nov. 21, 2011).

123

Summer 2010 Coincident Peaks, PJM PLANNING, http://www.pjm.com/planning/resource-

adequacy-planning/~/media/planning/res-adeq/load-forecast/summer-2010-peaks-and-5cps.ashx

(last updated Nov. 11, 2010).

Using this information, PJM evaluates offers from generators and other resources

three years in advance to be available for a one year delivery period running from June

through May (up to three years for new generation) through the Base Residual Auction

(“BRA”).

124

Once PJM completes its RTEP and conducts the RPM BRA, PJM is in a

position to evaluate the reliability of its system. PJM must operate the transmission

system to meet reliability criteria established by the FERC and administered by the

NERC.

PJM held the BRA for the 2014/2015 delivery period in May 2011. PJM

calculated the RTO reliability requirement to be 148,323.1 MW, which includes a 15.3%

reserve margin. However, as a result of the administratively determined downward

sloping demand curve - the Variable Resource Requirement - more resources than needed

cleared the market. In 2011, 149,974.7 MW cleared the BRA, which essentially

increased the reserve margin to 20.6%. This means 1,651.6 MW in excess of the

reliability requirement were procured in the BRA. Approximately 10,511.6 MW of

excess capacity was offered into the 2014/2015 BRA (i.e., this capacity did not clear);

accordingly, for the 2014/2015 delivery year, approximately 12,163.2 MW of capacity in

excess of the RTO reliability requirement was offered into the BRA.

125

The “Net Load” capacity prices for the IOUs in Maryland for each of the eight

completed BRAs are presented in Table IX.C.1. The estimated total capacity cost to

Maryland of each BRA is also presented. The Net Load capacity price reflects the BRA

clearing price and credits from any transmission capacity transfer rights. Maryland has

experienced significant volatility in Net Load prices from the past eight BRAs. The Net

Load cost to Maryland from the first BRA for the 2007/2008 delivery year was

approximately $693 million. By the 2009/2010 BRA, capacity cost had increased to

approximately $1.131 billion before declining to $580 million for 2011/2012 and then

again increasing to approximately $1.1 billion for 2013/2014. The 2014/2015 BRA

experienced another decline in capacity cost, totaling over $700 million. The observed

historical pattern of results suggests that future BRA results could vary significantly from

year to year and must be closely monitored.

124

Reliability Pricing Model, PJM MARKETS & OPERATIONS, available at:

http://www.pjm.org/markets-and-operations/rpm.aspx.

125

2014/2015 Base Residual Auction Report, PJM MARKETS & OPERATIONS, available at:

http://www.pjm.com/markets-and-operations/rpm/~/media/markets-ops/rpm/rpm-auction-

info/20110513-2014-15-base-residual-auction-report.ashx.

126

Table IX.C.1: RPM “Net Load” Price and Cost

Potomac

Edison

BGE DPL Pepco TOTAL

Delivery

Year

($/MW-

day)

($/MW-

day)

($/MW-

day)

Maryland

($/MW-day) ($)

693,678,286

2007/2008 40.69 139.67 177.00 139.67

2008/2009 113.22 183.03 145.24 183.03 901,994,343

2009/2010 193.80 224.93 193.71 224.78 1,130,545,999

2010/2011 174.29 174.29 178.27 174.29 920,141,784

2011/2012 110.04 110.04 110.04 110.04 579,821,643

2012/2013 16.46 129.63 162.99 129.63 636,535,392

1,100,652,116

2013/2014 27.73 223.85 240.41 236.93

2014/2015 125.94 135.25 142.99 135.25 711,062,492

Source: RPM Auction User Information, PJM MARKETS & OPERATIONS, available at:

http://www.pjm.com/markets-and-operations/rpm/rpm-auction-user-info.aspx#Item01.

D. Region-Wide Demand Response in PJM Markets

Demand Response continues to be actively promoted within the wholesale

electricity markets. PJM provides the opportunity for DR to be bid into the Energy,

Capacity, Synchronized Reserve, Day-Ahead Scheduling Reserve, and Regulation

markets. 15,545 MW of demand resources were offered into the 2014/2015 BRA, which

represents an increase of 20% over the amount offered into the 2013/2014 BRA.

127

that amount, 14,118 MW cleared, which is 4,836.5 MW greater than that which cleared

in the 2013/2014 BRA.

128

PJM has two basic energy and capacity market demand response programs: the

Economic Load Response Program and the Emergency Load Program. The goal of these

programs is to provide economic incentives for end-use customers to curtail their

electricity usage in the circumstances of either peak periods or unexpected outages.

126

The “Net Load” price for each company is the RPM auction price adjusted for any capacity

transfer credits and load variations from forecast. The total Maryland cost assumes a constant

demand for the periods shown based on the summer peak load contribution for each company’s

transmission zone. The PE zone includes PE, the municipal electric companies of Hagerstown,

Thurmont, Williamsport, and Somerset Rural Electric Cooperative electric loads. The DPL zone

includes DPL Maryland, Choptank, the municipal electric companies of Easton, Berlin, and A&N

Electric Cooperative loads. The Pepco zone includes Pepco Maryland and SMECO loads.

127

2014/2015 RPM Base Residual Auction Results, PJM MARKETS & OPERATIONS (Nov. 18, 2010),

http://pjm.com/markets-and-operations/rpm/~/media/markets-ops/rpm/rpm-auction-

info/20110513-2014-15-base-residual-auction-report.ashx. The newly integrated American

Transmission Systems, Inc. (“ATSI”) transmission zone accounted for 1,384 MW of the total

increase, while the other transmission zones accounted for the remaining 1,720 MW. Id. at 2.

128

Id.

1. Economic Load Response Program

The PJM Economic Load Response Program (“ELRP”) is a PJM-managed

accounting mechanism that provides for payment of the real savings that result from load

reductions to the load reducing customer. This is a voluntary program that allows

customers the opportunity to reduce their load and receive payments in either the energy

market or the ancillary services market, which includes reserve and regulation. Payments

in the energy market generally are based upon the difference between retail rates and day

ahead or real-time LMP. Customers who elect to have their load reductions dispatched

by PJM are guaranteed to receive a payment equal to their offer into the market.

Payments in the ancillary services markets generally are based upon the market clearing

price.

2. Emergency Load Program

The PJM Emergency Load Program is designed to provide a method by which end-

use customers may be compensated by PJM for reducing load during an emergency event.

The Emergency-Capacity Only program provides RPM payments for reducing capacity and

reduction is mandatory. The Emergency-Full program provides both RPM payments and

energy payments for reducing capacity, and reduction is mandatory. The Emergency-Energy

Only program provides energy payments to end-use customers for voluntarily reducing load

during an emergency event. The energy payment is the zonal LMP, but customers who elect

to have their load reductions dispatched by PJM are guaranteed to receive a payment equal to

their offer into the market, including shutdown costs. The 2014/2015 BRA is the first under

which two additional demand resource products were offered: Annual DR which is available

throughout the year, and Extended Summer DR, which is available for an extended summer

period. These new products have fewer limitations than the current DR product.

X. PROCEEDINGS BEFORE THE FEDERAL ENERGY REGULATORY

COMMISSION

The Commission is actively engaged in wholesale energy market policy

development at PJM. While the Commission is not a formal stakeholder in the

stakeholder process, the Commission does actively engage on issues and voice its

concerns regularly, both independently and as part of OPSI. The Commission

participates in the policy development process because decisions made at PJM directly

affect the price of electricity and related services to Maryland customers.

PJM holds more than 300 stakeholder meetings each year for more than two

dozen committees, subcommittees, task forces, and working groups. The Commission

assigns one or more Commission Advisors to represent the Commission at the major

policy-setting groups. These groups include the Members Committee, the Markets &

Reliability Committee, the Markets Implementation Committee, the Planning Committee,

and the Regional Planning Process Task Force. Other Commission Staff cover technical

and engineering-related meetings, such as the Transmission Expansion Advisory

Committee, Resource Adequacy Analysis Subcommittee, Demand Response

Subcommittee, and the Load Analysis Subcommittee.

Some of the issues in which the Commission is regularly engaged include load

forecasting, demand response, price responsive demand, the capacity market, shortage

pricing, governance, transmission planning and reliability planning criteria. While many of

these issues are ultimately litigated at FERC, where the Office of General Counsel represents

the Commission, being involved in PJM’s stakeholder process gives the Commission early

input into the important issues as they emerge.

APPENDIX

The Appendix contains a compilation of data provided by Maryland’s electric

companies, including the number of customers, sales by customer class, and typical

utility bills, as well as forecasted peak demand and electricity sales over the next fifteen

years, by utility. It also includes a list of licensed electricity and natural gas suppliers and

brokers in Maryland, renewable energy projects, planned transmission enhancements, and

potential new power plants in Maryland.

Table A-1: Utilities Providing Retail Electric Service in Maryland

Utility Service Territory

A&N Electric Cooperative Smith Island in Somerset County

Baltimore Gas & Electric Company Anne Arundel County, Baltimore City, Baltimore

County and portions of the following counties:

Calvert, Carroll, Howard, Harford, Montgomery, and

Prince George's.

Town of Berlin Town of Berlin.

Choptank Electric Cooperative Portions of the Eastern Shore.

Delmarva Power & Light Company Major portions of ten counties primarily on the

Eastern Shore.

Easton Utilities Commission City of Easton.

Hagerstown Municipal Electric Light

Plant

City of Hagerstown.

Potomac Edison Company Parts of Western Maryland.

Potomac Electric Power Company Major portions of Montgomery and Prince George's

Counties.

Somerset Rural Electric Cooperative Northwestern corner of Garrett County.

Southern Maryland Electric Cooperative Charles and St. Mary's Counties; portions of Calvert

and Prince George's Counties.

Thurmont Municipal Light Company Town of Thurmont

Town of Williamsport Town of Williamsport

Source: Table 1 in Company data responses to the Commission’s 2011 data request for the Ten-Year Plan.

Table A-2: Number of Customers by Customer Class as of December 31, 2010

Utility/Co. Residential Commercial Industrial Other

Sales for

Resale

Total Residential Commercial Industrial Other

Sales for

Resale

Total

A&N N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Berlin 1,968 293 112 18 0 2,391 1,968 293 112 18 0 2,391

BGE

1,114,712 118,575 5,536 0 0 1,238,823 1,114,712 118,575 5,536 0 0 1,238,823

Choptank 47,179 4,787 22 255 0 52,243 47,179 4,787 22 255 0 52,243

DPL 287,398 58,688 451 648 0 347,185 94,414 25,577 241 274 0 120,506

Easton

96,779 23,388 0 0 0 120,167 96,779 23,388 0 0 0 120,167

Hagerstown 14,798 2,471 123 0 0 17,392 14,798 2,471 123 0 0 17,392

334,650 42,838 4,841 665 3 382,997 220,576 27,186 2,861 345 3 250,971

PEPCO 713,148 73,782 0 1,368 0 788,298 483,906 47,349 0 1,336 0 532,591

SMECO 136,191 13,641 6 314 0 150,152 136,191 13,641 6 314 0 150,152

Somerset

12,212 1,157 6 0 0 13,375 754 37 3 0 0 794

Thurmont 2,441 332 10 43 0 2,826 2,441 332 10 43 0 2,826

Williamsport

857 72 32 44 0 1,005 857 72 32 44 0 1,005

Total 2,762,333 340,024 11,139 3,355 0 3,116,854 2,214,575 263,708 8,946 2,629 3 2,489,861

System Wide Maryland

Source

: Company data responses to Table A-2 in the Commission's 2011 data request for the Ten-Year Plan.

Note: A&N did not provide the requested information.

Table A-3: Typical Monthly Electric Bills in Maryland (Winter 2010)

Utility/Co. Residential Commercial Industrial Other Residential Commercial Industrial Other Residential Commercial Industrial Other

A&N N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Berlin 1,661 1,227 8,969 1,663 249.44 238.28 1503.62 395.73 0.1502 0.1942 0.1676 0.2380

BGE

1,251 11,886 47,477 N/A 182.71 559.00 961.39 N/A 0.1461 0.0470 0.0202 N/A

Choptank 1,406 3,506 308,531 272 184.72 443.72 29175.09 71.07 0.1314 0.1266 0.0946 0.2622

DPL

1,327 5,547 130,086 3,868 181.05 290.35 2102.04 854.09 0.1365 0.0523 0.0162 0.2208

Easton 1,527 6,243 N/A N/A 155.56 670.72 N/A N/A 0.1019 0.1074 N/A N/A

Hagerstown 1,110 2,720 71,329 N/A 111.35 284.09 6576.78 N/A 0.1003 0.1045 0.0922 N/A

1,540 7,687 51,412 N/A 157.36 922.68 4842.91 N/A 0.1022 0.1200 0.0942 N/A

PEPCO 1,227 15,030 3,298,402 82,154 165.23 675.11 49027.70 3249.22 0.1347 0.0449 0.0149 0.0396

SMECO 750 12,500 200,000 N/A 108.11 1533.73 21324.05 N/A 0.1442 0.1227 0.1066 N/A

Somerset

N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Thurmont 1,896 4,606 252,541 1,608 197.70 451.74 22478.08 180.27 0.1043 0.0981 0.0890 0.1121

Williamsport 974 1,872 16,512 1,641 95.23 189.34 1657.44 154.06 0.0977 0.1011 0.1004 0.0939

Total

14,669 72,824 4,385,259 91,205 1788.46 6258.76 139649.10 4904.45 1.3494 1.1189 0.7959 0.9666

Typical Bill ($) Revenue ($/kWh)Energy Use (kWh)

Source: Table A-3 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Note:

For those utilities that have retail competition available, bills and revenues reflect SOS, distribution service and any non-bypassable charges.

Note: Winter is defined as Dec. 1 through Feb. 29--as defined by PJM.

Note: A&N did not provide the requested information.

Table A-4(a): System Wide Peak Demand Forecast as of December 31, 2010 (MW) (Net of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport

Total

2011

4 6,699 232

3,979

68 68

2,691

6,593 838 20 5

21,196

2012

4 6,710 236

3,892

69 63

2,712

6,538 836 20 5

21,084

2013

4 6,880 248

3,871

71 63

2,728

6,535 851 20 5

21,274

2014

4 6,840 257

3,878

72 63

2,750

6,562 867 20 5

21,317

2015

4 6,802 266

3,887

73 64

2,773

6,586 882 20 5

21,361

2016

4 6,728 276

3,920

74 64

2,809

6,623 897 20 5

21,420

2017

5 6,822 287

3,960

75 64

2,844

6,682 913 20 5

21,676

2018

5 6,917 297

4,007

77 65

2,883

6,743 928 20 5

21,945

2019

5 7,014 307

4,059

78 65

2,925

6,825 943 20 5

22,245

2020

5 7,112 318

4,120

79 65

2,969

6,901 958 20 5

22,552

2021

5 7,213 329

4,167

80 66

3,012

6,957 973 20 5

22,827

2022

5 7,314 341

4,217

82 66

3,061

7,018 987 20 5

23,115

2023

6 7,407 354

4,267

83 66

3,113

7,077 1,002 20 5

23,398

2024

6 7,497 367

4,318

84 67

3,168

7,144 1,017 20 5

23,692

2025

6 7,586 381

4,367

85 67

3,217

7,207 1,031 20 5

23,971

Chan

e (MW)

(2011-2025)

2 887 149 388 17 (1) 526 614 193 - - 2,775

Percent

Change

47.50% 13.24% 64.42% 9.75% 25.38% -1.91% 19.54% 9.31% 23.05% 0.00% 0.00% 13.09%

Annual

Growth Rate

2.82% 0.89% 3.62% 0.67% 1.63% -0.14% 1.28% 0.64% 1.49% 0.00% 0.00% 0.88%

Source: Table A-4 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-4(b): Maryland Peak Demand Forecast as of December 31, 2010 (MW) (Net of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport

Total

2011 4 6,699 232 1,118 68 68

1,412

3,322 838 20 5

13,786

2012 4 6,710 236 1,117 69 63

1,415

3,237 836 20 5

13,711

2013 4 6,880 248 1,117 71 63

1,414

3,246 851 20 5

13,918

2014 4 6,840 257 1,116 72 63

1,420

3,256 867 20 5

13,919

2015 4 6,802 266 1,111 73 64

1,426

3,261 882 20 5

13,913

2016 4 6,728 276 1,121 74 64

1,445

3,281 897 20 5

13,914

2017 5 6,822 287 1,133 75 64

1,463

3,312 913 20 5

14,098

2018 5 6,917 297 1,147 77 65

1,483

3,344 928 20 5

14,287

2019 5 7,014 307 1,163 78 65

1,506

3,388 943 20 5

14,493

2020 5 7,112 318 1,181 79 65

1,531

3,428 958 20 5

14,702

2021 5 7,213 329 1,195 80 66

1,556

3,458 973 20 5

14,900

2022 5 7,314 341 1,210 82 66

1,585

3,490 987 20 5

15,105

2023 6 7,407 354 1,225 83 66

1,617

3,522 1,002 20 5

15,305

2024 6 7,497 367 1,241 84 67

1,651

3,557 1,017 20 5

15,511

2025 6 7,586 381 1,255 85 67

1,680

3,591 1,031 20 5

15,707

Chan

e (MW)

(2011-2025)

2 887 149 138 17 (1) 267 268 193 - - 1,921

Percent

Change

47.50% 13.24% 64.42% 12.33% 25.38% -1.91% 18.91% 8.08% 23.05% 0.00% 0.00% 13.93%

Annual

Growth Rate

2.82% 0.89% 3.62% 0.83% 1.63% -0.14% 1.24% 0.56% 1.49% 0.00% 0.00% 0.94%

Source: Table A-4 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-4(c): System Wide Peak Demand Forecast as of December 31, 2010 (MW) (Gross of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport Total

2011 11 7,374 242 4,148 68 68

2,720

6,986 871 20 5

22,512

2012 11 7,471 246 4,173 69 63

2,757

7,095 878 20 5

22,787

2013 11 7,596 258 4,226 71 63

2,787

7,192 897 20 5

23,124

2014 11 7,717 267 4,278 72 63

2,825

7,271 915 20 5

23,443

2015 11 7,833 276 4,328 73 64

2,864

7,339 931 20 5

23,742

2016 11 7,931 286 4,361 74 64

2,903

7,376 946 20 5

23,977

2017 11 8,025 297 4,401 75 64

2,935

7,435 962 20 5

24,229

2018 12 8,120 307 4,448 77 65

2,971

7,496 977 20 5

24,496

2019 12 8,217 317 4,500 78 65

3,010

7,578 992 20 5

24,792

2020 12 8,315 328 4,561 79 65

3,049

7,654 1,007 20 5

25,094

2021 12 8,416 339 4,608 80 66

3,085

7,710 1,022 20 5

25,362

2022 12 8,507 351 4,658 82 66

3,124

7,771 1,036 20 5

25,631

2023 12 8,610 364 4,708 83 66

3,164

7,830 1,051 20 5

25,913

2024 13 8,700 377 4,759 84 67

3,210

7,897 1,066 20 5

26,196

2025 13 8,789 391 4,808 85 67

3,249

7,960 1,080 20 5

26,467

Chan

e (MW)

(2011-2025)

2 1,415 149 660 17 (1) 530 974 209 - - 3,955

Percent

Change

17.59% 19.19% 61.72% 15.91% 25.38% -1.91% 19.48% 13.94% 23.96% 0.00% 0.00% 17.57%

Annual

Growth Rate

1.16% 1.26% 3.49% 1.06% 1.63% -0.14% 1.28% 0.94% 1.55% 0.00% 0.00% 1.16%

Source: Table A-4 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-4(d): Maryland Peak Demand Forecast as of December 31, 2010 (MW) (Gross of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport Total

2011 11 7,374 242 1,249 68 68

1,441

3,713 871 20 5

15,061

2012 11 7,471 246 1,256 69 63

1,459

3,770 878 20 5

15,248

2013 11 7,596 258 1,272 71 63

1,474

3,822 897 20 5

15,487

2014 11 7,717 267 1,288 72 63

1,495

3,864 915 20 5

15,716

2015 11 7,833 276 1,303 73 64

1,517

3,900 931 20 5

15,932

2016 11 7,931 286 1,313 74 64

1,538

3,920 946 20 5

16,107

2017 11 8,025 297 1,325 75 64

1,554

3,951 962 20 5

16,288

2018 12 8,120 307 1,339 77 65

1,572

3,984 977 20 5

16,475

2019 12 8,217 317 1,355 78 65

1,591

4,027 992 20 5

16,677

2020 12 8,315 328 1,373 79 65

1,611

4,068 1,007 20 5

16,881

2021 12 8,416 339 1,387 80 66

1,628

4,097 1,022 20 5

17,072

2022 12 8,507 351 1,402 82 66

1,648

4,130 1,036 20 5

17,258

2023 12 8,610 364 1,417 83 66

1,669

4,161 1,051 20 5

17,457

2024 13 8,700 377 1,433 84 67

1,693

4,197 1,066 20 5

17,652

2025 13 8,789 391 1,447 85 67

1,712

4,230 1,080 20 5

17,839

Change (MW)

(2011-2025)

2 1,415 149 199 17 (1) 271 518 209 - - 2,779

Percent

Change

17.59% 19.19% 61.72% 15.91% 25.38% -1.91% 18.82% 13.94% 23.96% 0.00% 0.00% 18.45%

Annual

Growth Rate

1.16% 1.26% 3.49% 1.06% 1.63% -0.14% 1.24% 0.94% 1.55% 0.00% 0.00% 1.22%

Source: Table A-4 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-5(a): System Wide Energy Sales Forecast (GWh) (Net of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport Total

2011

31,991

953 12,579

275 337 14,135 26,574 3,534 85 20

90,525

2012

31,963

975 12,696

278 307 14,358 26,840 3,567 85 20 91,130

2013

32,002

995 12,777

281 310 14,503 27,070 3,631 85 20

91,714

2014

32,461

1,008 12,864

283 313 14,697 27,284 3,693 85 20

92,750

2015

32,938

1,029 13,007

286 316 14,885 27,590 3,755 85 20 93,952

2016

33,382

1,047 13,181

289 319 15,100 27,954 3,818 85 20

95,238

2017

43 33,931 1,066 13,365

291 323 15,321 28,272 3,877 85 20 96,593

2018

43 34,488 1,087 13,573

294 326 15,550 28,636 3,937 85 20

98,039

2019

44 35,054 1,106 13,835

297 336 15,787 29,057 3,992 85 20

99,613

2020

45 35,628 1,126 14,126

299 329 16,012 29,547 4,045 85 20 101,262

2021

36,212

1,146 14,371

302 332 16,256 29,979 4,098 85 20

102,848

2022

36,805

1,168 14,892

305 336 16,510 29,432 4,147 85 20 103,746

2023

37,408

1,191 15,130

307 339 16,775 29,779 4,200 85 20

105,281

2024

38,020

1,215 15,356

310 342 17,047 30,147 4,250 85 20

106,840

2025

38,642

1,241 15,633

313 346 17,315 30,570 4,299 85 20 108,512

Change (GWh)

(2011-2025)

7 6,651 288 3,054 37 9 3,180 3,996 765 - - 17,987

Percent

Change

18.39% 20.79% 30.22% 24.27% 13.55% 2.77% 22.49% 15.04% 21.64% 0.00% 0.00% 19.87%

Annual Growth

Rate

1.21% 1.36% 1.90% 1.56% 0.91% 0.20% 1.46% 1.01% 1.41% 0.00% 0.00% 1.30%

Source: Table A-5 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-5(b): Maryland Energy Sales Forecast (GWh) (Net of DSM Programs)

Year Berlin BGE Choptank DPL Easton Hagerstown PE Pepco SMECO Thurmont Williamsport

Total

2011

31,991

953 4,279

275 337 7,392 15,105 3,534 85 20

64,012

2012

31,963

975 4,311

278 307 7,497 15,065 3,567 85 20

64,109

2013

32,002

995 4,348

281 310 7,542 15,186 3,631 85 20

64,440

2014

32,461

1,008 4,379

283 313 7,632 15,255 3,693 85 20

65,170

2015

32,938

1,029 4,433

286 316 7,722 15,407 3,755 85 20

66,032

2016

33,382

1,047 4,478

289 319 7,835 15,571 3,818 85 20

66,887

2017

43 33,931 1,066 4,515

291 323 7,956 15,732 3,877 85 20

67,839

2018

43 34,488 1,087 4,557

294 326 8,080 15,915 3,937 85 20

68,831

2019

44 35,054 1,106 4,606

297 336 8,208 16,112 3,992 85 20

69,860

2020

45 35,628 1,126 4,675

299 329 8,329 16,358 4,045 85 20

70,938

2021

36,212

1,146 4,734

302 332 8,464 16,616 4,098 85 20

72,056

2022

36,805

1,168 4,808

305 336 8,609 16,315 4,147 85 20

72,643

2023

37,408

1,191 4,867

307 339 8,763 16,540 4,200 85 20

73,768

2024

38,020

1,215 4,920

310 342 8,922 16,733 4,250 85 20

74,865

2025

38,642

1,241 4,993

313 346 9,076 16,978 4,299 85 20

76,041

Chan

e (GWh)

(2011-2025)

7 6,651 288 714 37 9 1,684 1,873 765 - - 12,029

Percent

Change

18.39% 20.79% 30.22% 16.69% 13.55% 2.77% 22.78% 12.40% 21.64% 0.00% 0.00% 18.79%

Annual

Growth Rate

1.21% 1.36% 1.90% 1.11% 0.91% 0.20% 1.48% 0.84% 1.41% 0.00% 0.00% 1.24%

Source: Table A-5 in Company data responses to the Commission's 2011 data request for the Ten-Year Plan.

Table A-6: Maryland Licensed Electric/Natural Gas Suppliers and Brokers

as of December 1, 2011

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No.

5Linx Enterprises, Inc.

IR-2167 IR-2166

A Better Choice Energy Services

IR-1697 IR-1698

Acclaim Energy, Ltd.

IR-1726 IR-1728

Advantage IQ, Inc.

IR-2240 IR-2242

Affiliated Power Purchasers International, LLC

IR-279 IR-2127

Affinity Energy Management, LLC

IR-2016 IR-2104

Allegheny Energy Supply

IR-229 IR-229

Alphabuyer, Inc.

IR-2214 IR-2217

Ambit Northeast, LLC

IR-1992 IR-1993

Ameresco, Inc.

IR-2145 IR-2144

Amerex Brokers, LLC

IR-1513 IR-1512

America Approved Commercial, LLC

IR-2174

America Approved Energy Services Direct, LLC

IR-1841

American Power Partners LLC

IR-2142

American PowerNet Management, L.P.

IR-604

AOBA Alliance, Inc.

IR-267 IR-375

AP Gas & Electric (MD), LLC d/b/a APG&E

IR-2231

API Ink, LLC

IR-1399

ARS International, Inc.

IR-1181

Avalon Energy Services, LLC

IR-1693 IR-1743

Better Cost Control, LLC d/b/a Ardor Power

IR-2082

BGE Home Products and Services, Inc. also d/b/a

BGE Commercial Building Systems

IR-311

BGE Home Products and Services, Inc. also d/b/a

BGE Commercial Building Systems d/b/a

Constellation Electric

IR-228

BidURenergy, Inc.

IR-1847 IR-1846

BlueStar Energy Services

IR-757

Bmark Energy, Inc.

IR-2018

Bollinger Energy Corporation

IR-265 IR-322

BP Energy Company

IR-676

BTU Energy, LLC

IR-864

C & D Commercial Brokerage, Inc. t/a Capital

Energy Solutions

IR-1823

Castlebridge Energy Group

IR-1735

Castlebridge Energy Group, LLC

IR-2331

CCES, LLC

IR-2161

Champion Energy Services, LLC

IR-2196

Chesapeake Energy Services, Inc.

IR-1638

Choice! Energy Services

IR-682

Clean Currents, LLC

IR-980 IR-1782

Clearview Electric, Inc.

IR-2009

Coastal Energy Company, LLC

IR-1900

Co-eXprise, Inc.

IR-879 IR-879

Coleman Hines, Inc.

IR-1389

Colonial Energy, Inc.

IR-606

Commerce Energy, Inc.

IR-639 IR-737

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No.

Commercial and Industrial Energy Solutions, LLC

IR-2062

Commercial Utility Consultants, Inc.

IR-2361

Compass Energy Services

IR-652

Competitive Energy Services-Maryland, LLC

IR-895 IR-895

ConocoPhillips Company

IR-1359

ConocoPhillips, Inc.

IR-378

Consolidated Edison Solutions, Inc.

IR-603

Constellation Energy Projects and Services

Group, Inc.

IR-239

Constellation NewEnergy, Inc.

IR-500 IR-522

Constellation NewEnergy-Gas Division, LLC

IR-655

Consumer Energy Solutions, Inc.

IR-1210

Coral Energy Gas Sales, Inc.

IR-360

CQI Associates, LLC

IR-575 IR-1753

Creativ Energy Options

IR-1528

Current Choice, Inc.

IR-2153

Cybermark Systems, Inc. d/b/a Proenergy

Consultants

IR-1785

Cypress Natural Gas, L.L.C.

IR-674

DD&J LLC

IR-1560

Delta Energy, LLC

IR-645

Direct Energy Business f/k/a Strategic Energy

IR-437

Direct Energy Services, LLC

IR-719 IR-791

Dominion Retail, Inc. t/a Dominion Energy

Solutions

IR-252 IR-345

Downing Place, LLC

IR-2011

DTE Energy Trading, Inc.

IR-686

E Source Companies, LLC

IR-2017 IR-2021

Early Bird Power

IR-1798

Eastern Shore of Maryland Educational

Consortium Energy Trust dba ESMEC Energy

Trust

IR-342

EDF Trading North America, LLC

IR-2019

EGP Energy Solutions, LLC d/b/a Atlantic

Energy Resources

IR-1363 IR-1430

Eisenbach Consulting, LLC

IR-1950 IR-1951

Electric Advisors, Inc.

IR-1183 IR-1523

Ellicott City Investments, LLC d/b/a Allied Power

Services

IR-1890 IR-1891

Emex, LLC

IR-2065

Eneractive Solutions, LLC

IR-1939

Energy Acceptance, Corp.

IR-2074

Energy Advisory Service, LLC

IR-1486 IR-1485

Energy Edge Consulting, LLC

IR-2022

Energy Enablement, LLC

IR-2385

Energy Management Resources of Missouri, Inc.

IR-2067 IR-2073

Energy Options, LLC

IR-568

Energy Plus Holdings, LLC

IR-1805

Energy Plus Natural Gas, LP

IR-2216

Energy Professionals, LLC

IR-1791

Energy Services Management, LLC d/b/a

Maryland Energy Consortium

IR-236 IR-312

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No.

Energy Services Providers, Inc. d/b/a Maryland

Gas and Electric

IR-2110

Energy Shopper, LLC

IR-2048

Energy Trust, LLC

IR-1682 IR-1681

Etheredge Partners, LLC

IR-2054

Field Personnel Services d/b/a Vanguard

Engineering Services

IR-1789

FirstEnergy Solutions Corp

IR-225

Gateway Energy Services Corporation

IR-340 IR-334

GDF Suez Energy Resources

IR-605

GDF Suez Retail Energy Solutions, LLC

IR-2404

Genesis Energy International, LLC

IR-1986

Glacial Energy of Maryland, Inc.

IR-888

Glacial Natural Gas, Inc.

IR-1855

Global Energy Market Services, LLC

IR-2170

Global Montello Group Corp.

IR-2225

Goldstar Energy Group, Inc.

IR-1370 IR-1381

Good Energy, LP

IR-1592

Green Power Management Solutions, LLC

IR-1835 IR-1834

Hess Corporation

IR-219 IR-323

Horizon Power & Light, LLC

IR-704

Houston Energy Services Company, L.L.C

IR-403

Hudson Energy Services, LLC

IR-1114 IR-1120

I.C. Thomasson Associates, Inc.

IR-1445 IR-1446

IDT Energy, Inc.

IR-1747 IR-1745

Integrity Energy, LTD

IR-1985

Integrys Energy Services

IR-951

IntelliGEN Resources LP

IR-2113

Interstate Gas Supply, Inc. d/b/a IGS Energy

IR-2182

Interstate Gas Supply, Inc. d/b/a IGS Energy d/b/a

Columbia Retail Energy

IR-1836

Invado International, LLC

IR-2026 IR-2025

Liberty Power Corp, LLC

IR-607

Liberty Power Delaware, LLC

IR-962

Liberty Power Holdings, LLC

IR-957

Liberty Power, MD, LLC

IR-793

Linde Energy Services

IR-753

Long Distance Consultants, L.L.C.

IR-1455

MABLock Consulting d/b/a The Lock Group

IR-1683

Maglor Marketing Group

IR-2088 IR-2089

Major Energy Electric Services, LLC

IR-2098

Major Energy Services, LLC

IR-1749

Marathon Oil Company

IR-364

Market Direct LLC d/b/a mdenergy

IR-614

Maryland Energy Advisors, LLC

IR-1954

Maryland Energy Trust, LLC

IR-1994

MCENERGY, INC.

IR-2354

Metromedia Energy, Inc.

IR-355

Metromedia Power, Inc.

IR-867

Mid Atlantic Renewables, LLC

IR-856

MidAmerican Energy Company

IR-798

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No.

Mid-Atlantic Aggregation Group Independent

Consortium, L.L.C. d/b/a MAAGIC

IR-234 IR-234

Mid-Atlantic Cooperative Solutions, Inc. d/b/a

Aero Energy

IR-2030

Mitchell Energy Management Services, Inc.

IR-1371

Mondre Energy, Inc.

IR-2334

MRDB Holdings, LP d/b/a LPB Energy

Consulting

IR-930 IR-1000

Mxenergy Electric Inc.

IR-1853

Mxenergy, Inc.

IR-327

Nania Energy, Inc.

IR-1857

National Power Source, LLC

IR-2084

National Utility Service, Inc.

IR-1400 IR-1401

Natures Current, LLC

IR-1352

Netpique, LLC

IR-2432

NextEra Energy Services, LLC

IR-966

Noble Americas Energy Solutions, LLC

IR-464 IR-464

North American Power and Gas LLC

IR-1983

North Shore Energy Consulting, LLC

IR-2160

Northeast Energy Partners

IR-1649

NOVEC Energy Solutions, Inc.

IR-338

NRGing, LLC d/b/a NetGain Energy Advisors

IR-2038 IR-2037

Oasis Power, LLC d/b/a Oasis Energy

IR-1848 IR-1929

On-Demand Energy, Inc.

IR-1442

Open Market Energy, LLC

IR-1981 IR-2013

Palmco Energy MD, LLC

IR-1803

Palmco Power MD, LLC

IR-1804

Patch Energy Services, LLC

IR-1943

Patriot Energy Group, Inc.

IR-2187

Peninsula Energy Services Company, Inc.

IR-2003

Pepco Energy Services, Inc.

IR-222

Pepco Energy Services, Inc. also d.b.a. Conectiv

Energy Services

IR-316

Planet Energy (Maryland) Corp.

IR-2133 IR-2121

Platinum Advertising II, LLC

IR-1673 IR-1668

Positive Energy Electricity Supply, LLC

IR-2164

Power Brokers, LLC

IR-2066

Power Brokers, LP

IR-1610

Power Management

IR-1670 IR-1669

PPL EnergyPlus, LLC

IR-230 IR-335

Premier Energy Group

IR-942 IR-943

Premier Power Solutions, LLC

IR-894 IR-894

Prospect Resources, Inc.

IR-2042 IR-2041

Public Power & Utility of Maryland, LLC

IR-1781

QVINTA Energy Services

IR-557 IR-530

Reflective Energy Solutions, LLC

IR-2352 IR-2253

Reliable Power Alternatives Corp.

IR-1719

Reliant Energy Northeast, LLC d/b/a Reliant

Energy

IR-2058

ResCom Energy, LLC

IR-2120

Resource Energy Systems, LLC

IR-2115

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No.

Richards Energy Group, Inc.

IR-818

RMI Consulting, Inc.

IR-1685

Satori Enterprises, Inc.

IR-1499

Secure Energy Soltions, LLC

IR-2117

Select Energy Partners, LLC

IR-1864

Senergy Corporate Ventures, LLC

IR-2325 IR-2326

Shell Energy North America

IR-1357 IR-1358

Silver Star Associates Corporation

IR-2194

Simply Competitive Energy, LLC

IR-2304

Smart Choice Energy Services

IR-1611 IR-1612

Smart One Energy, LLC

IR-2355

SmartEnergy.com, Inc.

IR-270

SourceOne, Inc. (DE)

IR-2111 IR-2172

South Jersey Energy Company

IR-740

South River Consulting

IR-863

SouthStar Energy Services, LLC d/b/a Maryland

Energy

IR-2106

Spark Energy Gas, LP

IR-613

Spark Energy, LP

IR-979

Sprague Energy Corp.

IR-339

Stand Energy Corporation

IR-632

Starion Energy PA, Inc.

IR-2094

Statoil Natural Gas LLC

IR-561

Stream Energy Maryland, LLC

IR-2072

Summit Energy Services

IR-1396

Suncom Energy Inc.

IR-2051

Sustainable Star LLC

IR-2306

Taylor Consulting and Contracting, LLC

IR-1790 IR-1960

Technology Resource Solutions, Inc.

IR-2105

Technology Resources Solutions, Inc.

IR-1802

TES Energy Services, LP

IR-2169

Texas Energy Options, Inc.

IR-1542

Texas Retail Energy, LLC

IR-2272

TFS Energy Solutions, LLC

IR-918

TFS Energy Solutions, LLC d/b/a Tradition

Energy

IR-982

The Energy Link, LLC

IR-2068 IR-2069

The Eric Ryan Corporation

IR-1438 IR-1437

The Legacy Energy Group

IR-1692 IR-1691

The Loyalton Group, Inc.

IR-1766 IR-1765

Tiger Natural Gas

IR-351

Tybec Energy Management Specialist, Inc.

IR-2299

Tybec Energy Management Specialists, Inc.

IR-2163

U.S. Gas & Electric d/b/a Maryland Gas &

Electric

IR-1744

U.S. Harvest Postal Protection Services

Corp.d/b/a United States Ethane Gas Corp.

IR-1824

U.S. Harvest Postal Protection Services

Corporation d/b/a U.S. Harvest Energy &

Technologies Corp.

IR-1774

U.S. Sun Energy, Inc.

IR-1952

Company

Electricity

Supplier

License No.

Electricity

Broker

License No.

Natural Gas

Supplier

License No.

Natural Gas

Broker

License No

UEC Energy, LLC

IR-1972

UGI Energy Services, Inc.

IR-237 IR-319

Unified Energy Services, LLC

IR-1751

Usource, LLC

IR-1160

UtiliTech, Inc.

IR-915 IR-915

Utility Savings Solutions

IR-2322

Veterans Energy Supply Company, LLP

IR-2397

Virginia Power Energy Marketing, Inc. d/b/a

Dominion Sales and Marketing, Inc.

IR-689

Viridian Energy PA, LLC

IR-1840

Volunteer Energy Services, Inc.

IR-2012 IR-2004

Washington Gas Energy Services, Inc.

IR-227 IR-324

World Energy Solutions, Inc.

IR-619 IR-953

IR-2165

Xencom Green Energy, LLC

Source: PSC database and Table A-6 in Company data responses to the Commission's 2011 data request for the

Ten-Year Plan.

The Table below lists the electricity and natural gas suppliers by license type. The license

type indicates what services a supplier may offer in Maryland. The Table below only

indicates the license type and does not imply that all suppliers are offering services.

Electric Supplier

Electric Broker

Gas Supplier

Gas Broker

Total Suppliers (Incl. Brokers)*

* Certain suppliers have both natural gas and electric

licenses.

146

244

Table A-7: Transmission Enhancements by Service Area

Transmission

Owner

Voltage

(kV)

Length

(miles)

No. of

Circuits

Start

Date

Comp.

Date

In-Service

Date Purpose County Terminal County Terminal

BGE 115 0.4 2 2007 2013 2013 BTR Harford Perryman Harford Harford

BGE 115 3 2 2008 2014 2014 DA Baltimore

City

Westport Baltimore

City

Wilkens

BGE 500 1 2 2009 2019 2019 BTR Calvert MAPP

Project

Calvert MAPP Project

BGE 230 8.6 1 2011 2014 2014 BTR Harford Conastone Harford Graceton

BGE 115 3.3 1 2010 2014 2014 BTR Baltimore

County

Deer Park Baltimore

County

Northwest

BGE 115 1 2 2009 2014 2014 BTR Baltimore

City

Orchard St Baltimore

City

Front St

BGE 115 0.6 2 2012 2014 2014 DA Baltimore

City

Coldspring Baltimore

City

Melvale

BGE 230 13.7 1 2009 2014 2014 BTR Harford Graceton Harford Bagley

BGE 115 5.2 2 2012 2015 2015 DA Baltimore

City

Erdman Baltimore

City

Argon

BGE 115 5 1 2012 2015 2015 BTR Baltimore

City

Melvale Baltimore

City

Argon

BGE 230 6.1 2 2007 2015 2015 BTR Harford Raphael Rd Harford Bagley

BGE 230 4 2 2010 2015 2015 BTR Baltimore

County

Northwest Baltimore

County

Emory Grove

BGE 230 11.7 2 2007 2019 2019 BTR Harford Raphael Rd Harford Perryman

DPL 138 24 1 2014 2015 2015 BTR Queen

Annes

Wye Mills Queen

Annes

Church

Start location End Location

Transmission

Owner

Voltage

(kV)

Length

(miles)

No. of

Circuits

Start

Date

Comp.

Date

In-Service

Date Purpose County Terminal County Terminal

DPL 69 11.7 1 2014 2016 2016 STR Queen

Annes

Wye Mills Queen

Annes

Stevensville

DPL 69 4.42 1 2015 2017 2017 STR Wicomico Sharptown Dorchester Vienna

DPL 69 2.61 1 2011 2012 2012 BTR Worcester Ocean Bay Worcester Maridel

DPL 69 18.41 1 2011 2012 2012 BTR Dorchester Todd Talbot Trappe

DPL 138 12.33 1 2011 2012 2012 BTR Worcester Bishop Sussex Indian River

DPL 139 12.33 1 2013 2014 2014 BTR New Castle Townsend Queen

Annes

Church

DPL 230 28.28 1 2016 2017 2017 BTR Caroline Steele Dorchester Vienna

DPL 230 18.7 1 2016 2018 2018 BTR Somerset Loretto Dorchester Vienna

DPL 230 9.51 1 2016 2019 2019 BTR Wicomico Piney Grove Somerset Loretto

DPL 69 5.99 1 2016 2020 2020 DA Queen

Annes

Grasonville Queen

Annes

Queenstown

DPL 69 5.99 1 2016 2021 2021 DA Queen

Annes

Wye Mills Queen

Annes

Queenstown

DPL 69 12 1 2013 2014 2014 DA Kent Lynch Kent McCleans

DPL 69 12 1 2013 2014 2014 DA Kent Chestertown Kent McCleans

DPL 69 6.52 1 2012 2013 2013 DA Kent Massey Queen

Annes

Church

DPL 69 2.25 1 2015 2016 2016 DA Talbot Trappe Talbot Lakeside

DPL 69 2.25 1 2015 2016 2016 DA Talbot Talbot Talbot Lakeside

DPL 138 3.96 1 2011 2011 2011 BTR Accomack Wattsville Accomack Oak Hall

DPL 138 5.22 1 2014 2015 2015 BTR Cecil Cecil New Castle Glasgow

DPL 138 N/A N/A 2012 2013 2013 BTR Worcester 138th Street Worcester SVC site @ 138th

Street Sub.

DPL 69 19.13 1 2014 2016 2016 BTR Accomack Wattsville Worcester Kenney

DPL 69 15.04 1 2015 2014 2014 BTR Somerset Cristfield Somerset Kings Creek

Start location End Location

Transmission

Owner

Voltage

(kV)

Length

(miles)

No. of

Circuits

Start

Date

Comp.

Date

In-Service

Date Purpose County Terminal County Terminal

DPL 69 8.74 1 2016 2014 2014 BTR Worcester Ocean City Worcester Worcester

DPL 69 15.04 1 2017 2014 2014 BTR Somerset Cristfield Somerset Kings Creek

DPL 69 8.74 1 2018 2014 2014 BTR Worcester Ocean City Worcester Worcester

PE 138 16.7 1 2011 2012 2012 BTR Preston,

Albright Garrett Mt. Zion

PE 230 3.2 1 Canc. -- -- BTR Frederick Doubs Frederick Eastalco (Section

205)

PE 230 3.7 1 Canc. -- -- BTR Frederick Doubs Frederick Eastalco (Section

206)

PE 138 3.2 1 2011 2012 2012 BTR Garrett Mt. Zion Mineral,

Beryl

PE 230 9.8 1 2011 2012 2012 BTR Washington Ringgold Frederick Catoctin

PE 230 10.7 1 2011 2012 2012 BTR Frederick Walkersville Frederick Catoctin

PE 230 12.7 1 2010 2013 2013 BTR Frederick Catoctin Carroll Carroll

PE 230 5.4 1 2010 2013 2013 BTR Frederick Monocacy Frederick Walkersville

PE 138 6.1 1 2012 2013 2013 BTR Mineral,

Beryl Allegany Black Oak

PE 230 6.7 1 2012 2013 2013 BTR Frederick Doubs Frederick Lime Kiln (Section

207)

PE 230 6.7 1 2012 2013 2013 BTR Frederick Doubs Frederick Lime Kiln (Section

231)

PE 138 4.8 1 2012 2013 2013 BTR Berkeley,

Marlowe Washington Halfway

PE 138 0.1 2 2014 2015 2014 DA Garrett Altamont

(new)

Garrett Albright – Mt. Zion

Start location End Location

Transmission

Owner

Voltage

(kV)

Length

(miles)

No. of

Circuits

Start

Date

Comp.

Date

In-Service

Date Purpose County Terminal County Terminal

PE 138 4 1 2014 2015 2014 BTR Washington Ringgold Franklin,

East Waynesboro

PE 765 19.6 1 2012 2015 SUSP BTR Hardy, WV Welton

Spring (new)

Frederick Kemptown (new)

PE 230 24.9 1 2016 2017 2017 BTR Doubs Frederick Frederick Monocacy

PE 138 0.1 2 2016 2017 2017 DA Washington McDade

(new)

Washington Halfway –

Paramount No. 1

PE 230 2.1 2 2018 2019 2019 DA Frederick Urbana1 Frederick Lime Kiln -

Montgomery

PE 230 0.1 2 2019 2020 2019 DA Frederick Jefferson No.

1 (new)

Frederick Doubs - Monocacy

PE 230 0.1 2 2019 2019 2019 DA Frederick South

Frederick

No. 1 (new)

Frederick Monocacy – Lime

Kiln

PE 138 0.1 2 2019 2020 2020 DA Washington Fairplay

(new)

Washington Marlowe -

Boonsboro

PE 230 0.6 2 2019 2020 2020 DA Frederick Ridgeville 1 Frederick Mt. Airy -

Damascus

Pepco 230 10.7 2 2009 2011 2011 BTR Dickerson Existing Quince

Orchard

Existing

Pepco 230 7.5 1 2010 2011 2011 BTR Dickerson Existing Pleasant

View

Existing

Pepco 230 Unknow

2 2011 2012 2012 BTR Quince

Orchard

Existing Bells Mill

Rd.

Existing

Pepco 230 5.34 2 2012 2012 2012 BTR Benning Existing Ritchie Existing

Pepco 230 6.42 4 2013 2012 2012 BTR Burches Hill Existing Palmers

Corner

Existing

Start location End Location

Transmission

Owner

Voltage

(kV)

Length

(miles)

No. of

Circuits

Start

Date

Comp.

Date

In-Service

Date Purpose County Terminal County Terminal

Pepco 230 5.01 4 2011 2013 2013 BTR Oak Grove Existing Ritchie Existing

Pepco 230 10.98 1 2012 2014 2014 BTR Ritchie Existing Buzzard

Point

Existing

Pepco 230 10.83 1 2012 2014 2014 BTR Ritchie Existing Buzzard

Point

Existing

Pepco 500 33 1 2010 2017 2017 BTR Possum

Point

Existing Burches

Hill

Existing

Pepco 500 19 1 2010 2017 2017 BTR Burches Hill Existing Chalk Point Existing

Pepco 500 20 1 2010 2017 2017 BTR Chalk Point Existing Calvert

Cliffs

Existing

SMECO 230 20 2 2012 2013 2013 Capacity Calvert Holland Clif

Sw. St.

Calvert Sollers Wharf Sw.

St.

SMECO 230 10 2 2014 2015 2015

eliabilit

Calvert Sollers

Wharf Sw.

St.

St. Mary's Hewitt Rd. Sw. St.

Start location End Location

Purpose Codes:

BTR ¾ Baseline Transmission Reliability

C ¾ Capacity

DA ¾ Distribution Adequacy

STR ¾ Supplemental Transmission

Reliability

R ¾ Reliability

Source: Company data responses to Question 7 in the Commission's 2011 data request for the Ten-Year Plan.

Table A-8: Renewable Projects Providing Capacity and Energy to Maryland Customers as of December 31, 2010

Utility

Service

Area

Operator/Owner Plant Name County Energy Source

Name

Plate

Summer

PE BP Piney & Deep Creek LLC Deep Creek Garrett 20 18 Water

BGE Constellation Solar Maryland, LLC McCormick & Co. Inc. at Belcamp Hartford 1.4 1.4 Solar

Pepco Covanta Montgomery, Inc. Montgomery County Resource Recover

Montgomery 67.8 54 Municipal Solid Waste

PE Criterion Power Partners LLC Criterion Wind Project Garrett 70 70 Wind

BGE Eastern Landfill Gas LLC Eastern Landfill Gas LLC Baltimore 3 3 Landfill Gas

BGE Energy Recovery Operations, Inc Harford Waste to Energy Facility Harford 1.2 1.1 Municipal Solid Waste

BGE Exelon Power Conowingo Harford 506.8 572 Water

DPL Industrial Power Generating Company L

Wicomico Wicomico 5.4 5.4 Landfill Gas

DPL Maryland Environmental Service Eastern Correctional Institute Somerset 3.8 2.6 Wood/Wood Waste Solids

Pepco Prince George's County Brown Station Road Plant II Prince Georges 6.7 5.6 Landfill Gas

Pepco SCE Engineers Montgomery County Oaks LFGE Plant Montgomery 2.4 2.3 Landfill Gas

BGE Wheelabrator Environmental Systems Wheelabrator Baltimore Refuse Baltimore City 64.5 61.3 Municipal Solid Waste

Choptank Worcester County Renewable Energy L

Worcester County Renewable Energy Worcester 2 2 Landfill Gas

TOTAL 755 798.7

Capacity

Statistics (MW)

Source: Report EIA-860: "GenY10" Excel, U.S. ENERGY INFORMATION ADMINISTRATION, (Nov. 30, 2011), available at:

http://38.96.246.204/cneaf/electricity/page/eia860.html.

Table A-9: Power Plants in the PJM Process for New Electric Generating Stations

in Maryland as of December 31, 2010

Electric

Company

Service

Territory

PJM

Queue # Project Name

Status of

Application

(12/31/10)

Plant

Capacity

(MW) Fuel Type

Projected

In-Service

Date

BGE S32 Perryman Suspended 256 natural gas 2014 Q2

BGE V1-033 Pumphrey 115kV Under Construction 132 other 2015 Q1

BGE V3-037 Naval Academy Junction 13kV Under Construction 3 natural gas 2013 Q2

BGE V4-038 Friendship Manor 34.5kV Under Construction 1 methane 2013 Q1

BGE W1-033 Pumphrey 115kV Under Construction 157

iomass 2015 Q1

BGE W4-030 Jessup Under Construction 0 solar 2012 Q1

DPL T144 Pocomoke Under Study 20

iomass 2010 Q1

DPL U3-003 Mt. Olive 69kV Under Construction 2 methane 2012 Q2

DPL U3-004 Cecil Under Study 2 methane 2009 Q3

DPL V2-028 Vienna Under Study 6 solar 2010 Q4

DPL W1-070 Laurel 69kV Under Study 20 solar 2011 Q2

DPL W3-071 Worcester 25kV Under Study 13 solar 2012 Q2

DPL W3-160 Worcester 25kV Under Study 10 solar 2011 Q1

DPL W4-017 Kings Creek-Crisfield 69kV Under Study 100 wind 2013 Q4

DPL X1-032 Costen 25kV Under Construction 4 solar 2012 Q2

DPL X1-096 Loretto-Kings Creek 138kV Under Study 150 wind 2014 Q4

DPL X2-045 Kenney-Mt. Olive 69kV Under Study 20 solar 2013 Q2

DPL X2-084 East New Market 69kV Under Study 20 solar 2012 Q4

DPL X3-008 Todd 69kV Under Study 20 solar 2017 Q2

DPL X3-009 New Market 69kV Under Study 20 solar 2017 Q2

DPL X3-015 West Cambridge-Vienna 69kV Under Study 20 solar 2012 Q4

DPL X3-066 Church Hill 69kV Under Study 7 solar 2012 Q3

DPL X3-067 Church Hill 12kV Under Study 2 solar 2012 Q3

DPL X3-073 Massey 69kV Under Study 10 solar 2013 Q1

DPL X3-074 Chestertown 69kV Under Study 12 solar 2013 Q1

DPL X4-017 Fruitland 69kV Under Study 20 solar 2017 Q2

PE S14 Dans Mountain Under Study 70 wind 2009 Q4

PE T16 Gorman-Snowy Creek 69kV Under Study 30 wind 2011 Q4

PE U2-030 Four Mile Ridge Wind 138kV Under Study 60 wind 2010 Q4

PE U4-007 Jennings Randolph Dam Under Study 14 hydro 2013 Q3

PE W1-116 Emmitsburg 34kV Under Construction 14 solar 2012 Q2

PE W3-070 Metropolitan Court 34.5kV Under Study 52

iomass 2013 Q4

PE W4-102 Lappans 34.5kV Under Study 17 solar 2012 Q4

PE X2-038 Halfway 12.5kV Under Study 2 methane 2012 Q3

PEPCO S17 Talbert 230kV Suspended 225 natural gas 2017 Q4

PEPCO T133 Chalk Point-Bowie 230kV Suspended 225 natural gas 2016 Q4

PEPCO T134 Chalk Point-Bowie 230kV Suspended 325 natural gas 2017 Q4

PEPCO V3-017 Morgantown-Oak Grove Under Study 725 natural gas 2012 Q2

PEPCO W3-105 Dickerson 230kV Under Construction 18 oil 2011 Q4

PEPCO W4-010 White Oak Under Study 53 natural gas 2014 Q1

PEPCO W4-020 Mt. Zion 13.8kV Under Study 10 solar 2011 Q3

PEPCO W4-044 Kelson Ridge 230kV Under Study 1450 natural gas 2014 Q2

PEPCO X2-030 Morgantown-Oak Grove 230kV Under Study 830 natural gas 2016 Q1

PEPCO X3-087 Burches Hill-Brandywine 230kV Under Study 914 natural gas 2016 Q2

Electric

Company

Service

Territory

PJM

Queue # Project Name

Status of

Application

(12/31/10)

Plant

Capacity

(MW)

Fuel Type

Projected

In-Service

Date

PEPCO X3-088 Dickerson 230kV Under Study 440 natural gas 2016 Q4

PEPCO X3-102 Burches Hill-Possum Point 500kV Under Study 971 natural gas 2016 Q2

PEPCO X4-006 Kelson Ridge 230kV Under Study 785 natural gas 2015 Q2

PEPCO X4-007 Kelson Ridge 230kV Under Study 785 natural gas 2015 Q2

PEPCO X4-026 Aquasco 230kV Under Study 792 natural gas 2015 Q2

SMECO V2-042 Calvert Cliffs 500kV Under Study 1640 nuclear 2017 Q2

Total (MW): 11,474

Source: Generation Queues: Active, PJM, http://www.pjm.com/planning/generation-

interconnection/generation-queue-active.aspx (last visited December 18, 2011).