10-K 1 d226617d10k.htm FORM 10-K FORM 10-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

 

Commission

File Number

  

Exact Name of Registrant as Specified in its Charter,
State or Other Jurisdiction of Incorporation,

Address of Principal Executive Offices, Zip Code

and Telephone Number (Including Area Code)

   I.R.S. Employer
Identification Number
001-31403   

PEPCO HOLDINGS, INC.

(Pepco Holdings or PHI), a Delaware corporation

701 Ninth Street, N.W.

Washington, D.C. 20068

Telephone: (202)872-2000

   52-2297449
001-01072   

POTOMAC ELECTRIC POWER COMPANY

(Pepco), a District of Columbia and Virginia corporation

701 Ninth Street, N.W.

Washington, D.C. 20068

Telephone: (202)872-2000

   53-0127880
001-01405   

DELMARVA POWER & LIGHT COMPANY

(DPL), a Delaware and Virginia corporation

500 North Wakefield Drive, 2nd Floor

Newark, DE 19702

Telephone: (202)872-2000

   51-0084283
001-03559   

ATLANTIC CITY ELECTRIC COMPANY

(ACE), a New Jersey corporation

500 North Wakefield Drive, 2nd Floor

Newark, DE 19702

Telephone: (202)872-2000

   21-0398280


Securities registered pursuant to Section 12(b) of the Act:

 

Registrant

  

Title of Each Class

  

Name of Each Exchange

on Which Registered

Pepco Holdings

   Common Stock, $.01 par value    New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

 

Registrant

  

Title of Each Class

    

Pepco

   Common Stock, $.01 par value   

DPL

   Common Stock, $2.25 par value   

ACE

   Common Stock, $3.00 par value   

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

Pepco Holdings

      Yes  x    No   ¨     Pepco       Yes  ¨    No   x

DPL

      Yes  ¨    No   x     ACE       Yes  ¨    No   x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 

Pepco Holdings

      Yes  ¨    No   x     Pepco       Yes  ¨    No   x

DPL

      Yes  ¨    No   x     ACE       Yes  ¨    No   x

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

 

Pepco Holdings

      Yes  x    No   ¨     Pepco       Yes  x    No   ¨

DPL

      Yes  x    No   ¨     ACE       Yes  x    No   ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Pepco Holdings

      Yes  x    No   ¨     Pepco       Yes  x    No   ¨

DPL

      Yes  x    No   ¨     ACE       Yes  x    No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco Holdings only).  x


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

    

Large

Accelerated

Filer

   Accelerated
Filer
   Non-
Accelerated
Filer
   Smaller
Reporting
Company

Pepco Holdings

   x    ¨    ¨    ¨

Pepco

   ¨    ¨    x    ¨

DPL

   ¨    ¨    x    ¨

ACE

   ¨    ¨    x    ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Pepco Holdings

      Yes  ¨    No   x     Pepco       Yes  ¨    No   x

DPL

      Yes  ¨    No   x     ACE       Yes  ¨    No   x

Pepco, DPL, and ACE meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K.

 

Registrant

  

Aggregate Market Value of Voting and
Non-Voting Common Equity Held by
Non-Affiliates of the Registrant at

June 30, 2011

   Number of Shares of Common
Stock of the Registrant
Outstanding at February 15, 2012

Pepco Holdings

  

$4,432,800,000 (a)

   227,609,131

($.01 par value)

Pepco

   None (b)    100

($.01 par value)

DPL

   None (c)    1,000

($2.25 par value)

ACE

   None (c)    8,546,017

($3.00 par value)

 

(a) Solely for purposes of calculating this aggregate market value, PHI has defined its affiliates to include (i) those persons who were, as of June 30, 2011, its executive officers, directors and beneficial owners of more than 10% of its common stock, and (ii) such other persons who were, as of June 30, 2011, controlled by, or under common control with, the persons described in clause (i) above.
(b) All voting and non-voting common equity is owned by Pepco Holdings.
(c) All voting and non-voting common equity is owned by Conectiv, LLC, a wholly owned subsidiary of Pepco Holdings.

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY PEPCO HOLDINGS, PEPCO, DPL AND ACE. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.


 

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Pepco Holdings, Inc. definitive proxy statement for the 2012 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission within 120 days after December 31, 2011 are incorporated by reference into Part III of this report.

 

 

 


 

TABLE OF CONTENTS

 

 
                 Page  

Glossary of Terms

           i   

Forward-Looking Statements

           1   

PART I

        

Item 1.

     -       Business      3   

Item 1A.

     -       Risk Factors      23   

Item 1B.

     -       Unresolved Staff Comments      37   

Item 2.

     -       Properties      38   

Item 3.

     -       Legal Proceedings      39   

Item 4.

     -       Mine Safety Disclosures      39   

PART II

        

Item 5.

     -      

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     40   

Item 6.

     -       Selected Financial Data      43   

Item 7.

     -       Management’s Discussion and Analysis of Financial Condition and Results of Operations      44   

Item 7A.

     -       Quantitative and Qualitative Disclosures About Market Risk      125   

Item 8.

     -       Financial Statements and Supplementary Data      128   

Item 9.

     -       Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      321   

Item 9A.

     -       Controls and Procedures      321   

Item 9B.

     -       Other Information      322   

PART III

        

Item 10.

     -       Directors, Executive Officers and Corporate Governance      323   

Item 11.

     -       Executive Compensation      323   

Item 12.

     -      

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     323   

Item 13.

     -       Certain Relationships and Related Transactions, and Director Independence      323   

Item 14.

     -       Principal Accounting Fees and Services      324   

PART IV

        

Item 15.

     -       Exhibits and Financial Statement Schedules      324   

Schedule I

     -       Condensed Financial Information of Parent Company      326   

Schedule II

     -       Valuation and Qualifying Accounts      331   

Signatures

           349   

Exhibit 12

     -       Statements Re: Computation of Ratios   

Exhibit 21

     -       Subsidiaries of the Registrant   

Exhibit 23

     -       Consents of Independent Registered Public Accounting Firm   

Exhibits 31.1-31.8

     -       Rule 13a-14a/15d-14(a) Certifications   

Exhibits 32.1-32.4

     -       Section 1350 Certifications   


GLOSSARY OF TERMS

The following is a glossary of terms, abbreviations and acronyms that are used in the Reporting Companies’ SEC reports. The terms, abbreviations and acronyms used have the meanings set forth below, unless the context requires otherwise.

 

Term   

Definition

ACE    Atlantic City Electric Company
ACE Funding    Atlantic City Electric Transition Funding LLC
ADITC    Accumulated deferred investment tax credits
AFUDC    Allowance for funds used during construction
AOCL    Accumulated other comprehensive loss
AMI    Advanced metering infrastructure
ASC    Accounting Standards Codification
BART    Best Available Retrofit Technology
BGS    Basic Generation Service
BGS-CIEP    BGS-Commercial and Industrial Energy Price
BGS-FP    BGS-Fixed Price
Bondable Transition Property    Principal and interest payments on the transition bonds and related taxes, expenses and fees
BSA    Bill Stabilization Adjustment
Budget Support Act    The Fiscal Year 2012 Budge Support Act of 2011, approved by the Council of the District of Columbia on June 14, 2011
CAIR    Clean Air Interstate Rule issued by EPA
Calpine    Calpine Corporation, the purchaser of Conectiv Energy’s wholesale power generation business
CERCLA    Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv    Conectiv, LLC (formerly Conectiv), a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy    Conectiv Energy Holding Company and its subsidiaries
CSAPR    Cross-State Air Pollution Rule
DCPSC    District of Columbia Public Service Commission
DDOE    District of Columbia Department of the Environment
Default Electricity Supply    The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as SOS or BGS
DPL    Delmarva Power & Light Company
DEDA    Delaware Economic Development Authority
DOE    U.S. Department of Energy
DPSC    Delaware Public Service Commission
DRP    Shareholder Dividend Reinvestment Plan
Dynamic Pricing    A pricing mechanism that rewards SOS customers for lowering their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher
EBITDA    Earnings before interest, taxes, depreciation, and amortization
EDC    Electricity Distribution Company
EDIT    Excess Deferred Income Taxes
EmPower Maryland    A DSM program for Pepco and DPL
EPA    U.S. Environmental Protection Agency
Exchange Act    Securities Exchange Act of 1934, as amended
FASB    Financial Accounting Standards Board
FERC    Federal Energy Regulatory Commission
FHACA    Flood Hazard Area Control Act
FPA    Federal Power Act
GAAP    Accounting principles generally accepted in the United States of America

 

i


 

Term   

Definition

GCR    Gas Cost Rate
GWh    Gigawatt hour
HPS    Hourly Priced Service
IFRS    International Financial Reporting Standards
IIP    ACE’s Infrastructure Investment Program
IRS    Internal Revenue Service
ISDA    International Swaps and Derivatives Association
ISRA    Industrial Site Recovery Act
Line Losses    Estimates of electricity and gas expected to be lost in the process of its transmission and distribution to customers
LTIP    The Pepco Holdings, Inc. Long-Term Incentive Plan
MAPP    Mid-Atlantic Power Pathway
Market Transition Charge Tax    Revenue ACE receives, and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
Mcf    Thousand Cubic Feet
MDC    MDC Industries, Inc.
Medicare Act    Medicare Prescription Drug Improvement and Modernization Act of 2003
Medicare Part D    A prescription drug benefit under the Medicare Act
MFVRD    Modified fixed variable rate design
Mirant    Mirant Corporation
MMBtu    One Million British Thermal Units
MPSC    Maryland Public Service Commission
MSCG    Morgan Stanley Capital Group, Inc.
MWh    Megawatt hours
NAV    Net Asset Value
NERC    North American Electric Reliability Corporation
NYMEX    New York Mercantile Exchange
NJBPU    New Jersey Board of Public Utilities
NJDEP    New Jersey Department of Environmental Protection
NOx    Nitrogen oxide
NPCC    Northeast Power Coordinating Council
NPDES    National Pollutant Discharge Elimination System
NPL    National Priorities List
NUGs    Non-utility generators
OPEB    Other postretirement benefit
PARS    Performance accelerated restricted stock
PCBs    Polychlorinated biphenyls
PCI    Potomac Capital Investment Corporation and its subsidiaries
Pepco    Potomac Electric Power Company
Pepco Energy Services    Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI    Pepco Holdings, Inc.
PJM    PJM Interconnection, LLC
PJM RTO    PJM regional transmission organization
Power Delivery    The operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas
PPA    Power purchase agreement
PRP    Potentially responsible party

 

ii


 

Term   

Definition

PUHCA 2005    Public Utility Holding Company Act of 2005
RECs    Renewable energy credits
Regulated T&D Electric Revenue    Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Reporting Company    Each of PHI, Pepco, DPL and ACE
Revenue Decoupling Adjustment    An adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer
RFC    ReliabilityFirst Corporation
RFP    Request for proposals
RI/FS    Remedial investigation and feasibility study
RIM    Reliability investment recovery mechanism
ROE    Return on equity
RPM    Reliability Pricing Model
RPS    Renewable Energy Portfolio Standards
SEC    Securities and Exchange Commission
SO2    Sulfur dioxide
SOCA    Standard Offer Capacity Agreement
SOS    Standard Offer Service (the supply of electricity by Pepco in the District of Columbia, by Pepco and DPL in Maryland and by DPL in Delaware to retail customers who have not elected to purchase electricity from a competitive supplier)
SPCC    Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
T&D    Transmission and distribution
Transition Bonds    Transition Bonds issued by ACE Funding
VADEQ    Virginia Department of Environmental Quality
VaR    Value at Risk
VRDBs    Variable Rate Demand Bonds
WACC    Weighted average cost of capital

 

iii


FORWARD-LOOKING STATEMENTS

Some of the statements contained in this Annual Report on Form 10-K with respect to Pepco Holdings, Inc. (PHI or Pepco Holdings), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), including each of their respective subsidiaries, are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended, and are subject to the safe harbor created thereby and by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more Reporting Companies or their subsidiaries. In some cases, you can identify forward-looking statements by terminology such as “may,” “might,” “will,” “should,” “could,” “expects,” “intends,” “assumes,” “seeks to,” “plans,” “anticipates,” “believes,” “projects,” “estimates,” “predicts,” “potential,” “future,” “goal,” “objective,” or “continue” or the negative of such terms or other variations thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause one or more Reporting Company’s or their subsidiaries’ actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Therefore, forward-looking statements are not guarantees or assurances of future performance, and actual results could differ materially from those indicated by the forward-looking statements.

The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond each Reporting Company’s or their subsidiaries’ control and may cause actual results to differ materially from those contained in forward-looking statements:

 

   

Changes in governmental policies and regulatory actions affecting the energy industry, including allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of transmission and distribution facilities and the recovery of purchased power expenses;

 

   

The outcome of pending and future rate cases, including the possible disallowance of costs and expenses;

 

   

The expenditures necessary to comply with regulatory requirements, including regulatory orders, and to implement reliability enhancement, emergency response and customer service improvement programs;

 

   

Possible fines, penalties or other sanctions assessed by regulatory authorities against PHI’s regulated utilities;

 

   

Weather conditions affecting usage and emergency restoration costs;

 

   

Population growth rates and changes in demographic patterns;

 

   

Changes in customer energy demand due to conservation measures and the use of more energy-efficient products;

 

   

General economic conditions, including the impact of an economic downturn or recession on energy usage;

 

   

Changes in and compliance with environmental and safety laws and policies;

 

1


   

Changes in tax rates or policies;

 

   

Changes in rates of inflation;

 

   

Changes in accounting standards or practices;

 

   

Unanticipated changes in operating expenses and capital expenditures;

 

   

Rules and regulations imposed by, and decisions of, federal and/or state regulatory commissions, PJM Interconnection, LLC (PJM), the North American Electric Reliability Corporation (NERC) and other applicable electric reliability organizations;

 

   

Legal and administrative proceedings (whether civil or criminal) and settlements that affect a Reporting Company’s or their subsidiaries’ business and profitability;

 

   

Pace of entry into new markets;

 

   

Interest rate fluctuations and the impact of credit and capital market conditions on the ability to obtain funding on favorable terms; and

 

   

Effects of geopolitical events, including the threat of domestic terrorism or cyber attacks.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in Part I, Item 1A. “Risk Factors” in this Annual Report on Form 10-K, and investors should refer to such risk factors in evaluating the forward-looking statements contained in this Form 10-K.

Any forward-looking statements speak only as to the date of this Form 10-K for each Reporting Company and none of the Reporting Companies undertakes an obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for a Reporting Company to predict all such factors, nor can the impact of any such factor be assessed on such Reporting Company’s or its subsidiaries’ business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries) or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. The foregoing factors should not be construed as exhaustive.

 

2


Part I

 

Item 1. BUSINESS

Overview

Pepco Holdings, a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and, to a lesser extent, the distribution and supply of natural gas:

 

   

Potomac Electric Power Company, which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,

 

   

Delmarva Power & Light Company, which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and

 

   

Atlantic City Electric Company, which was incorporated in New Jersey in 1924.

Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI also provides energy efficiency and renewable energy services primarily to government and institutional customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business and preparing for the retirement of its two oil-fired generating facilities.

In addition, through Potomac Capital Investment Corporation (PCI), PHI holds several cross-border energy lease investments as described below under the heading “Other Business Operations.”

The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries:

 

LOGO

 

3


PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services, to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methods set forth in the service agreement.

Pepco Holdings’ management has identified its operating segments at December 31, 2011 as (i) Power Delivery, consisting of the operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas, (ii) Pepco Energy Services and (iii) Other Non-Regulated, consisting primarily of the operations of PCI. For financial information relating to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.

Discontinued Operations

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, are being accounted for as a discontinued operation. For further information on the former Conectiv Energy segment and the disposition of its assets, operations and obligations, see Note (20), “Discontinued Operations,” to the consolidated financial statements of PHI.

Investor Information

Each Reporting Company maintains an Internet web site, at the Internet address listed below:

 

Reporting Company

 

Internet Address

PHI   http://www.pepcoholdings.com
Pepco   http://www.pepco.com
DPL   http://www.delmarva.com
ACE   http://www.atlanticcityelectric.com

Each of PHI, Pepco, DPL and ACE files reports with the Securities and Exchange Commission (SEC) under the Exchange Act. Copies of the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each Reporting Company are made available free of charge on PHI’s Internet Web site as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. Copies of these reports may be found at http://www.pepcoholdings.com/investors. The information contained on the web sites listed above is not a part of this Form 10-K, and any web site references are not intended to be made through active hyperlinks.

Business Strategy

PHI’s business strategy is to become a top-performing, regulated power delivery company focused on:

 

   

investing in transmission and distribution infrastructure to improve reliability of electric service;

 

   

building a smarter grid to automate certain functions on the electric system, restore power more efficiently and provide customers detailed energy information to help them control their energy costs;

 

   

investing in advanced technologies, new processes and personnel to enhance the customer experience during power restoration, including delivering enhanced customer communications;

 

   

pursuing a regulatory strategy that results in earning reasonable rates of return and timely cost recovery of PHI’s investments;

 

4


   

growing PHI’s energy services business by providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions; and

 

   

demonstrating PHI’s core values of safety, diversity and environmental stewardship through PHI’s business approaches and tangible business practices and outcomes.

To further its business strategy, PHI may examine transactions involving its existing businesses, including entering into joint ventures, disposing of businesses or making acquisitions. PHI also may refine components of its business strategy as it deems necessary or appropriate in response to business factors and conditions, including regulatory requirements.

Description of Business

Power Delivery

PHI’s primary business is Power Delivery. Power Delivery in 2011, 2010 and 2009, produced 79%, 73%, and 67%, respectively, of PHI’s consolidated operating revenues and 78%, 81%, and 78%, respectively, of PHI’s consolidated operating income.

Each utility comprising Power Delivery is regulated in the jurisdictions that encompass its electricity distribution service territory and is regulated by FERC for its electricity transmission facilities. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, Power Delivery distributes electricity to more than 1.8 million customers in the mid-Atlantic region and delivers natural gas to approximately 124,000 customers in Delaware. None of PHI’s three utilities owns any electric generation facilities.

Distribution and Default Supply of Electricity

Pepco, DPL and ACE each owns and operates a network of wires, substations and other equipment that are classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities carry electricity from the transmission facilities to the end-use customers located in the utility’s service territory.

Each utility is responsible for the distribution of electricity in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive retail supplier. The regulatory term for this default supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Form 10-K, these supply services are referred to generally as Default Electricity Supply.

Transmission of Electricity and Relationship with PJM

The transmission facilities owned by Pepco, DPL and ACE are interconnected with the transmission facilities of contiguous utilities and are part of an interstate power transmission grid over which electricity is transmitted throughout the mid-Atlantic portion of the United States and parts of the Midwest. Pepco, DPL and ACE each is a member of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by the Federal Energy Regulatory Commission (FERC) to coordinate the movement of wholesale electricity within a region consisting of 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.

 

5


PJM, the FERC-approved independent grid operator, manages the transmission grid and the wholesale electricity market in the PJM RTO region. Any entity that wishes to have wholesale electricity delivered at any point within the PJM RTO region must obtain transmission services from PJM. In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the region make their transmission facilities available to the PJM RTO, and PJM directs and controls the operation of these transmission facilities. For transmission services, transmission owners are paid rates proposed by the transmission owner and approved by FERC. PJM provides billing and settlement services, collects transmission service revenue from transmission service customers and distributes the revenue to the transmission owners. PJM also directs the regional transmission planning process within the PJM RTO region. The PJM Board of Managers reviews and approves each PJM regional transmission expansion plan, including whether to include new construction of transmission facilities proposed by PJM RTO members in the plan and, if so, the target in-service date for those facilities.

Seasonality

The operating results of Power Delivery historically have been directly related to the volume of electricity delivered to its customers, producing higher revenues and net income during periods when customers consumed higher amounts of electricity (usually during periods of extreme temperatures) and lower revenues and net income during periods when customers consumed lower amounts of electricity (usually during periods of mild temperatures). This has been due in part to the long standing practice by which the applicable public service commissions set distribution rates based on a fixed charge per kilowatt-hour of electricity used by the customer. Because most of the costs associated with the distribution of electricity do not vary with the volume of electricity delivered, this pricing mechanism also contributed to seasonal variations in net income. As a result of the implementation of a BSA for retail customers of Pepco and DPL in Maryland in June 2007 and for customers of Pepco in the District of Columbia in November 2009, distribution revenues have been decoupled from the amount of electricity delivered. Under the BSA, utility customers pay an approved distribution charge for their electric service which does not vary by electricity usage. This change has had the effect of aligning annual distribution revenues more closely with annual distribution costs. In addition, the change has had the effect of eliminating changes in customer electricity usage, whether due to weather conditions or for any other reason, as a factor having an impact on annual distribution revenue and net income in those jurisdictions. The BSA also eliminates what otherwise might be a disincentive for the utility to aggressively develop and promote efficiency programs. Distribution revenues are not decoupled for the distribution of electricity and natural gas by DPL in Delaware or for the distribution of electricity by ACE in New Jersey, and thus are subject to variability due to changes in customer consumption.

In contrast to electricity distribution costs, the cost of the electricity supplied, which is the largest component of a customer’s bill, does vary directly in relation to the volume of electricity used by a customer. Accordingly, whether or not a BSA is in effect for the jurisdiction, the revenues of Pepco, DPL and ACE from the supply of electricity and natural gas vary based on consumption and on this basis are seasonal. Because the revenues received by each of the utility subsidiaries for the default supply of electricity and natural gas closely approximate the supply costs, the impact on net income is immaterial, and therefore is not seasonal.

Regulated Utility Subsidiaries

The following is a more detailed description of the business of each of PHI’s three regulated utility subsidiaries:

 

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Pepco

Pepco is engaged in the transmission, distribution and default supply of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2011, Pepco distributed electricity to 788,000 customers (of which 257,000 were located in the District of Columbia and 531,000 were located in Maryland), as compared to 787,000 customers as of December 31, 2010 (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland). As of December 31, 2009, Pepco distributed electricity to 778,000 customers (of which 252,000 were located in the District of Columbia and 526,000 were located in Maryland).

In 2011, Pepco distributed a total of 26,895,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2010, Pepco distributed a total of 27,665,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were distributed to residential customers, 49% to commercial customers, and 21% to United States and District of Columbia government customers. In 2009, Pepco distributed a total of 26,549,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 29% of the total megawatt hours were distributed to residential customers, 50% to commercial customers, and 21% to United States and District of Columbia government customers.

Pepco has been providing SOS in Maryland since July 2004. Pursuant to orders issued by the Maryland Public Service Commission (MPSC), Pepco is obligated to provide SOS (i) to residential and small commercial customers until further action of the Maryland General Assembly and (ii) to medium-sized commercial customers through November 2012. Pepco purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the MPSC. Pepco also is obligated to provide Standard Offer Service, known as Hourly Priced Service (HPS), for large Maryland customers. Power to supply HPS customers is acquired in next-day and other short-term PJM RTO markets. Pepco is entitled to recover from its SOS customers the cost of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the District of Columbia Public Service Commission (DCPSC), Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers indefinitely. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the DCPSC. Pepco is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of District of Columbia SOS customers in each customer class and the amount of electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its District of Columbia service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

 

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For the year ended December 31, 2011, 43% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 46% and 49% in 2010 and 2009, respectively, and 27% of its District of Columbia distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 29% and 31% in 2010 and 2009, respectively.

DPL

DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of Maryland. In northern Delaware, DPL also supplies and delivers natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from another supplier.

Distribution and Supply of Electricity

DPL’s electricity distribution service territory consists of the state of Delaware, and Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset, Talbot, Wicomico and Worcester counties in Maryland. This territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of December 31, 2011, DPL delivered electricity to 501,000 customers (of which 301,000 were located in Delaware and 200,000 were located in Maryland), as compared to 500,000 customers as of December 31, 2010 (of which 301,000 were located in Delaware and 199,000 were located in Maryland). As of December 31, 2009, DPL delivered electricity to 498,000 customers (of which 299,000 were located in Delaware and 199,000 were located in Maryland).

In 2011, DPL distributed a total of 12,688,000 megawatt hours of electricity to its customers, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 41% of the total megawatt hours were distributed to residential customers, 42% to commercial customers and 17% to industrial customers. In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within Maryland. Of this amount, 42% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 17% to industrial customers. In 2009, DPL distributed a total of 12,494,000 megawatt hours of electricity, of which 67% was distributed within its Delaware territory and 33% within Maryland. Of this amount, 39% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 20% to industrial customers.

DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the Delaware Public Service Commission (DPSC), DPL is obligated to provide SOS to residential, small commercial and industrial customers through May 2014, and to medium, large and general service commercial customers through May 2012. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the DPSC. DPL also has an obligation to provide SOS, known as HPS, for the largest Delaware customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL’s rates for supplying SOS and HPS reflect the associated capacity, energy (including satisfaction of renewable energy requirements), transmission and ancillary services costs and an amount referred to as a Reasonable Allowance for Retail Margin. Components of the Reasonable Allowance for Retail Margin include a fixed annual margin of approximately $2.75 million, plus estimated incremental expenses, a cash working capital allowance, and recovery, with a return over five years ending 2011, of the capitalized costs of the billing system used for billing HPS customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

 

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DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers until further action of the Maryland General Assembly, and to medium-sized commercial customers through May 2014. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the MPSC. DPL also is obligated to provide HPS for large Maryland customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow DPL to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.

For the year ended December 31, 2011, 51% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 53% and 51% in 2010 and 2009, respectively, and 58% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers in 2011, as compared to 63% in 2010 and 2009.

Supply and Distribution of Natural Gas

DPL provides regulated natural gas supply and distribution service to customers in a service territory consisting of a major portion of New Castle County in Delaware. This service territory covers approximately 275 square miles and has a population of approximately 500,000. Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to deliver natural gas to customers that choose to purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. DPL purchases natural gas supplies for resale to its retail service customers from marketers and producers through a combination of long-term agreements and next-day distribution arrangements. For the year ended December 31, 2011, DPL supplied 64% of the natural gas that it delivered, compared to 65% in 2010 and 68% in 2009.

As of December 31, 2011, DPL delivered natural gas to 124,000 customers as compared to 123,000 customers as of December 31, 2010 and 2009. In 2011, DPL delivered 19,000,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 40% were sales to residential customers, 23% to commercial customers, 1% to industrial customers and 36% to customers receiving a transportation-only service. In 2010, DPL delivered 19,000,000 Mcf of natural gas, of which 41% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 35% were sales to customers receiving a transportation-only service. In 2009, DPL delivered 19,000,000 Mcf of natural gas, of which 42% were sales to residential customers, 25% were sales to commercial customers, 1% were sales to industrial customers and 32% were sales to customers receiving a transportation-only service.

ACE

ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million. As of December 31, 2011, ACE distributed electricity to 547,000 customers in its service territory, as compared to 548,000 and 547,000 customers as of December 31, 2010 and 2009, respectively.

 

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In 2011, ACE distributed a total of 9,683,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers and 9% to industrial customers. In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 44% to commercial customers, and 10% to industrial customers. In 2009, ACE distributed a total of 9,659,000 megawatt hours of electricity to its customers, of which 45% was distributed to residential customers, 45% to commercial customers, and 10% to industrial customers.

Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey’s electric distribution companies, including ACE, jointly obtain the electricity to meet their BGS obligations from competitive suppliers selected through auctions authorized by the New Jersey Board of Public Utilities (NJBPU) for the supply of New Jersey’s total BGS requirements. Each winning bidder is required to supply its committed portion of the BGS customer load with full requirements service, consisting of power supply and transmission service.

ACE provides two types of BGS:

 

  BGS-Fixed Price (BGS-FP), which is supplied to smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and the two prior years. As of December 31, 2011, ACE’s BGS-FP peak load was approximately 1,500 megawatts, which represents approximately 98% of ACE’s total BGS load.

 

  BGS-Commercial and Industrial Energy Price (BGS-CIEP), which is supplied to large customers at hourly PJM RTO real-time market prices for a term of 12 months. As of December 31, 2011, ACE’s peak BGS-CIEP load was approximately 20 megawatts, which represents approximately 2% of ACE’s BGS load.

ACE is paid tariff supply rates established by the NJBPU that compensate it for the cost of obtaining the BGS supply. These rates are set such that ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory regardless of whether the customer receives BGS or purchases electricity from another supplier.

For the year ended December 31, 2011, 56% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 65% and 73% in 2010 and 2009, respectively.

ACE has contracts with three unaffiliated non-utility generators (NUGs) under which ACE is obligated to purchase capacity and the entire generation output of the facilities. One of the contracts expires in 2016 and the other two expire in 2024. In 2011, ACE purchased 1.9 million megawatt hours of power from the NUGs. ACE sells this electricity into the wholesale market administered by PJM.

In 2001, ACE established Atlantic City Electric Transitional Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond charges collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding.

 

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Other Power Delivery Initiatives and Activities

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, PHI announced comprehensive reliability enhancement plans for Pepco in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives such as enhanced vegetation management, the identification and upgrading of under-performing feeder lines, the addition of new facilities to support load, the installation of distribution automation systems on both the overhead and underground network system, the rejuvenation and replacement of underground residential cables, improvements to substation supply lines and selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability and enhance customer satisfaction. During 2011, Pepco continued to execute on its plans to improve reliability which it believes have contributed to its progress in reducing both the frequency and duration of power outages. During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities. Since initiating the reliability enhancement plans, Pepco trimmed trees along nearly 3,500 miles of power lines, completed 48 expansion projects to meet growth in customer demand for electricity, upgraded more than 340 miles of aging underground lines, and added 125 automated switches that will reroute power more effectively during outages. PHI has extended its reliability enhancement efforts to DPL and ACE.

In 2011 PHI initiated an accelerated emergency restoration improvement program prior to the start of the 2011 summer storm season. As part of this program, Pepco:

 

   

more than doubled the number of telephone trunk lines to its Washington, D.C. regional call center;

 

   

developed mobile applications to report and track outages;

 

   

improved outage information on its Web site to enhance communications with its customers;

 

   

implemented regional storm centers for more efficient crew dispatch;

 

   

implemented better methodologies for estimating times for restoration of power;

 

   

employed technology, including smart meters, to obtain real-time information from the field on power outages and to assist restoration planning efforts by providing data needed to conduct real-time damage assessments;

 

   

augmented training of its emergency response personnel; and

 

   

installed a backup crisis call center.

These and other emergency restoration improvements implemented as a part of this program were tested during Hurricane Irene in August 2011. Although nearly 500,000 customers across all three utilities were without power at the peak of the storm, nearly 98% of outages were restored within a little more than two days.

PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Expenditures.”

Blueprint for the Future

Each of PHI’s utility subsidiaries is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability and address government energy reduction goals. The initiative includes the implementation of various programs to help customers better manage their energy use, reduce the total cost of energy and provide other benefits. These programs also enhance the ability of PHI’s utilities to better manage and operate their electrical and natural gas distribution systems.

 

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One of the primary initiatives of Blueprint for the Future is the installation of smart meters (also known as Advanced Metering Infrastructure (AMI)) for electric and natural gas customers, which are subject to the approval of applicable state regulators. These smart meters allow the utilities, among other capabilities, to remotely read meters, significantly reduce the number of customer bills that are based on usage estimates, improve outage management and detection, and provide customers with more detailed information about their energy consumption. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. Meter installation is substantially complete for DPL electric customers in Delaware, with meter activation expected to be completed in the first quarter of 2012. Meter installation is progressing for Pepco customers in both the District of Columbia and Maryland, with installation expected to be complete in the second and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of a regulatory asset to defer AMI costs between rate cases, as well as the accrual of a return on the deferred costs. Thus, these costs will be recovered through base rates in the future.

Approval of AMI is still pending for electric customers in DPL’s Maryland service territory, and has been deferred for ACE in New Jersey.

On December 20, 2011, the Delaware Public Service Commission approved DPL’s request to implement dynamic pricing for its Delaware customers. Dynamic pricing will reward SOS customers for lowering their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher. Implementation for residential customers will be phased in commencing in 2012 through 2013. Implementation of dynamic pricing for commercial and industrial SOS customers in Delaware will be phased in commencing in 2013 through 2014.

Dynamic pricing has been approved in concept for Pepco customers in Maryland, with phase-in for residential customers beginning in 2012. Pepco has dynamic pricing proposals pending in the District of Columbia jurisdiction with the proposed phase-in for residential customers anticipated to begin in 2012. Dynamic pricing has been approved in concept pending AMI deployment authorization for DPL’s Maryland customers and has been deferred for ACE’s customers in New Jersey.

For a discussion of the capital expenditures associated with Blueprint for the Future, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Requirements – Blueprint for the Future.”

MAPP Project

In October 2007, the PJM Board of Managers approved PHI’s proposal to construct a new 230-mile, 500-kilovolt interstate transmission line referred to as the Mid-Atlantic Power Pathway (MAPP), as part of PJM’s regional transmission expansion plan to address the reliability objectives of the PJM RTO system. Since that time, there have been various modifications to the proposal that have redefined the length and route of the MAPP project. PJM has approved the use of advanced direct current technology for segments of the project, including the portion of the line that will traverse under the Chesapeake Bay. The direct current portion of the line will be 640 kilovolts and the remainder of the line will be 500 kilovolts. As currently approved by the PJM Board of Managers, MAPP is approximately 152 miles in length originating at the Possum Point substation in Virginia and ending at the Indian River substation in Delaware. The cost of the MAPP project for Pepco and DPL is currently estimated to be $1.2 billion.

 

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In connection with the MAPP project, FERC has authorized for each of Pepco and DPL a 150 basis point adder to its return on equity, resulting in a FERC-approved rate of return on the MAPP project of 12.8%, along with full recovery of construction work-in-progress and prudently incurred abandoned plant costs.

On August 18, 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period, after taking into account changes in demand response, generation retirements and additions, and a revised load forecast for the PJM region that is lower than the load that was forecasted in prior PJM studies. A more recent load forecast continues to support this trend. PJM has retained the MAPP project in its 2011 Regional Transmission Expansion Plan. In light of the delayed in-service date for MAPP, substantially all of the anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on current projections.

The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process. Until PJM’s evaluation is concluded, PJM has directed PHI to limit further development efforts with respect to the MAPP project and to proceed with only those development efforts reasonably necessary to allow the MAPP project to be quickly restarted if and when deemed necessary. Based on PJM’s direction, PHI intends to continue to complete the right-of-way acquisition for the proposed route, and some environmental and other preparatory activities.

For a discussion of the capital expenditures associated with the MAPP Project, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity – Capital Requirements – MAPP Project.”

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

 

   

providing energy efficiency services principally to federal, state and local government customers, and designing, constructing, and operating combined heat and power and central energy plants.

 

   

providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. area.

Most of Pepco Energy Services’ contracts with federal, state and local governments, as well as independent agencies such as housing and water authorities, contain provisions authorizing the governmental authority or independent agency to terminate the contract at any time. Those provisions contain explicit mechanisms that, if exercised, would require the other party to pay Pepco Energy Services for work performed through the date of termination and for additional costs incurred as a result of the termination.

From time to time, PHI is required to guarantee the obligations of Pepco Energy Services under certain of its construction contracts. At December 31, 2011, PHI’s guarantees of Pepco Energy Services’ projects totaled $65 million.

Pepco Energy Services has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it would wind-down the retail energy supply business. Pepco Energy Services is implementing this wind-down by not entering into any new supply contracts, while continuing to perform under its existing supply contracts through their expiration dates. As of December 31, 2011, Pepco Energy Services’ estimated retail electricity backlog was approximately 3.9 million megawatts for distribution through 2014, a decrease of approximately 5.8 million megawatts and 16.2 million megawatts when compared to December 31, 2010 and 2009, respectively. For additional information on the Pepco Energy Services wind-down, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Pepco Energy Services.”

Pepco Energy Services’ retail natural gas sales volumes and revenues are seasonally dependent. Colder weather from November through March of each year generally translates into increased sales volumes, which, when coupled with higher natural gas prices during these months, allows Pepco Energy Services to recognize generally higher revenues as compared to other months of the year. Retail electricity sales volumes are also seasonally dependent, with sales in the summer and winter months being generally higher than other months of the year, which, when coupled with higher electricity prices during these periods, allows Pepco Energy Services to recognize generally higher revenues as compared to other periods during the year. However, as Pepco Energy Services is in the process of winding down its retail energy supply business, this effect of seasonality will likely decrease as such wind-down is completed. The energy services business is not seasonal.

Pepco Energy Services owns and operates two oil-fired generating facilities. The facilities are located in Washington, D.C. and have a combined generating capacity of approximately 790 megawatts. Pepco Energy Services sells the output of these facilities into the wholesale market administered by PJM. In February 2007, Pepco Energy Services provided notice to PJM of its intention to deactivate these facilities by the end of May 2012. PJM has informed Pepco

 

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Energy Services that these facilities will not be needed for reliability after May 2012; therefore decommissioning plans are currently underway and on schedule. It is not expected that deactivation of these facilities will have a material impact on PHI’s financial condition, results of operations or cash flows.

Pepco Energy Services also owns three landfill gas-fired electricity facilities that have a total generating capacity rating of ten megawatts, the output of which is sold into the wholesale market administered by PJM. Pepco Energy Services also owns a solar photovoltaic facility that has a generating capacity rating of two megawatts, the output of which is sold to its host facility.

Pepco Energy Services’ continuing lines of business will not be significantly affected by the wind-down of the retail energy supply business.

PJM Capacity Markets

Historically, Pepco Energy Services has earned revenue from the sale of capacity associated with its generating facilities. PJM is responsible for ensuring that within its transmission control area there is sufficient generating capacity available to meet the load requirements plus a reserve margin and locates and prices electricity capacity by holding annual auctions covering capacity to be supplied over consecutive 12-month periods. Pepco Energy Services has been exposed to deficiency charges payable to PJM when their generation units failed to meet certain reliability levels.

Since Pepco Energy Services intends to deactivate its two oil-fired generating facilities by May 2012, Pepco Energy Services has not included the facilities’ capacity in any auctions for periods after May 2012.

Competition

Pepco Energy Services’ energy services business is highly competitive. Pepco Energy Services competes with other energy services companies primarily with respect to contracts with federal, state and local governments and independent agencies. Many of these energy services companies are subsidiaries of larger construction or utility holding companies (as is the case with Pepco Energy Services). Among the factors as to which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. The energy services business is impacted by new entrants into the market, energy prices, and general economic conditions.

Other Business Operations

Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early termination of the leases were negotiated at the request of the lessees and were completed in June 2011. As of December 31, 2011, PHI’s equity investment in its cross-border energy leases was approximately $1.3 billion. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities,” and Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

 

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Regulation

The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the distribution and transmission of electricity and, in the case of DPL, the distribution and transportation of natural gas, are subject to regulation by governmental agencies in the jurisdictions in which the subsidiaries provide utility service as follows:

 

   

Pepco’s electricity distribution operations are regulated in Maryland by the MPSC and in the District of Columbia by the DCPSC.

 

   

DPL’s electricity distribution operations are regulated in Maryland by the MPSC and in Delaware by the DPSC.

 

   

DPL’s natural gas distribution and intrastate transportation operations in Delaware are regulated by the DPSC.

 

   

ACE’s electricity distribution operations are regulated by the NJBPU.

 

   

Each utility subsidiary’s transmission facilities are regulated by FERC.

 

   

DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.

 

   

Each utility subsidiary’s and Pepco Energy Services’ bulk power system is subject to reliability standards established by NERC.

Rates and tariffs are established by these regulatory commissions. PHI’s utility subsidiaries have filed rate cases which are pending in each of its jurisdictions as further described in Note (7), “Regulatory Matters – Regulatory Proceedings – Rate Proceedings,” to the consolidated financial statements of PHI.

The rates and tariffs established by these regulatory commissions are intended to balance the interests of the utilities’ customers and those of its investors by reflecting costs incurred during the period in which the rates are in effect, and giving each utility the opportunity to generate revenues sufficient to recover its costs, including a reasonable rate of return on investor supplied capital during such period. In establishing a utility’s rates, an important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to minimize the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and operating expenses is outpacing revenue growth.

Higher operating and construction costs, including labor, material, depreciation, taxes and financing costs, as well as costs associated with enhanced distribution system reliability and environmental compliance, are expected at each of PHI’s utility subsidiaries for several years into the future. At the same time, low usage growth and customer growth is expected to limit the growth in revenues. This mismatch between high expense growth and low revenue growth exacerbates regulatory lag for each of PHI’s utility subsidiaries, making it more difficult for each utility to earn equity returns that are allowed by regulators without higher rates or other regulatory relief. See “Risk Factors – The failure of PHI to obtain timely recognition of costs in its rates may have a negative effect on PHI’s results of operations and financial condition.”

Pepco, DPL and ACE anticipate that they will continue to face regulatory lag. In their most recent rate cases, Pepco (in the District of Columbia and Maryland) and DPL (in Delaware and Maryland) each has proposed mechanisms that would track reliability and other expenses and permit the utility between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. In New Jersey, the NJBPU has approved certain rate recovery mechanisms

 

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in connection with ACE’s Infrastructure Investment Program (IIP), which ACE has proposed to extend and expand. There can be no assurance that these proposals or any other attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, if necessary to address the problem of regulatory lag, the utilities plan to file rate cases at least annually in an effort to align more closely their revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, Pepco, DPL and ACE, as applicable, would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

Maryland Reliability Investigation

In August 2010, following major storm events that occurred in July and August 2010, an investigation was initiated in Maryland into the reliability of Pepco’s distribution system and the quality of distribution service Pepco provided to its customers. As a result of that investigation, the MPSC imposed sanctions on Pepco in December 2011, including a fine of $1 million, which Pepco has paid. In accordance with the order, Pepco has filed a detailed work plan for the next five years, which provided a comprehensive description of Pepco’s reliability enhancement plan, its emergency response improvement project, and other communication and service restoration improvements. Pepco is also required to file quarterly updates and a year-end status report with the MPSC providing, among other things, detailed information about its reliability and emergency response improvement objectives, progress and spending (and explanations for any inability to meet such objectives), together with an analysis of trends concerning the measured duration and frequency of customer interruptions. In the required reports, Pepco will be required to demonstrate that its reliability enhancement plan costs were prudently spent and produced a significant improvement in reliability, and if it is unable to do so, the MPSC may deny Pepco reimbursement for future reliability enhancement investments or impose additional fines. In addition to the sanctions, the MPSC stated its intent to review the recovery of reliability costs in Pepco’s pending rate case and to disallow incremental costs it determines to be the result of imprudent management. Pepco believes its reliability costs have been prudently incurred. Furthermore, Pepco expects its reliability enhancement plan to enable Pepco to meet the MPSC’s requirements. For more information about the MPSC’s ruling in this proceeding, see Note (7), “Regulatory Matters – Regulatory Proceedings,” to the consolidated financial statements of PHI.

District of Columbia and Maryland Reliability and Customer Service Rulemakings

In December 2011, the MPSC approved proposed rules establishing reliability and customer service regulations, compliance with which is anticipated to be mandated as early as the second quarter of 2012. In addition, in July 2011, the DCPSC adopted regulations that establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020 and thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. Pepco and DPL each expect to incur significant operation and maintenance spending and capital investments to comply with these requirements. Pepco believes that the DCPSC’s standards are achievable in the short term, but continues to believe that the standards may not be realistically achievable at an acceptable cost over the longer term. The reliability standards permit Pepco to petition the DCPSC to reevaluate these standards for the period from 2016 to 2020 to address feasibility and cost issues.

Maryland New Generation RFP Issuance Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland’s regulated electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In September 2011, the MPSC issued a notice in which it stated that it had not made a final determination at this time whether new generation in Maryland is needed, but directed each of the four Maryland EDCs, including Pepco and DPL, to issue a request for proposal (RFP) for new generation resources by October 7, 2011. On that date, Pepco and DPL issued the RFP and sought additional information from the MPSC on

 

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several aspects of the process established in the notice, including whether the MPSC will consider a utility-owned generation option. Hearings were held on January 31, 2012, to obtain further input on whether the EDCs should be ordered to proceed with the RFP. Pepco and DPL have filed a request for rehearing of the notice. The MPSC has stated its intent to select generators and execute long-term contracts between the generators and selected EDCs in April 2012. PHI opposes the requirement to enter into such long-term contracts, which would be viewed as debt by the credit rating agencies and would have an adverse effect on PHI’s, Pepco’s and DPL’s credit metrics.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generators to receive payments from, or make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM. Each of the other EDCs in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each company’s annual proportion of the total New Jersey load attributable to all EDCs. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received by ACE and the other EDCs.

ACE and the other EDCs entered the SOCAs under protest based on concerns about the potential cost to distribution customers and the negative credit rating agency implications and have filed lawsuits challenging the constitutionality of the New Jersey law. For more information about the New Jersey law and associated regulatory and legal proceedings, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements,” to the consolidated financial statements of PHI.

Delaware Renewable Energy Portfolio Standards

DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. In July 2011, the Governor of the State of Delaware signed legislation that expands DPL’s RPS obligations beginning in 2012. Before this legislation, DPL was required to obtain RECs for energy delivered only to SOS customers in Delaware; the legislation expands that requirement to energy delivered to all of DPL’s distribution customers in Delaware. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.

The legislation also establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. The legislation requires that the DPSC adopt a tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a qualified fuel cell provider that deploys Delaware-manufactured fuel cells as part of a 30-megawatt generation facility. The legislation also provides for a reduction in DPL’s REC and solar REC requirements based upon the actual energy output of the 30-megawatt generation facility. In October 2011, the DPSC approved the tariff submitted by DPL in response to the legislation. For more information on the tariff, see Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – DPL Renewable Energy Transactions,” to the consolidated financial statements of PHI.

 

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NERC Reliability Standards

NERC has established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. There are eight NERC regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cyber security requirements on the bulk power systems of Pepco, DPL, ACE and Pepco Energy Services. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Each of PHI’s utility subsidiaries and Pepco Energy Services are subject to routine audits and monitoring for compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets designated as “critical assets” (including cyber security assets) subject to NERC’s cyber security standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.

Employees

At December 31, 2011, PHI had the following number of employees:

 

             In Collective Bargaining Agreements  
      Non-union      International
Brotherhood
of Electrical
Workers
     International
Union of
Operating
Engineers
     Other      Total  

Pepco

     354         1,094         —           —           1,448   

DPL

     228         688         —           —           916   

ACE

     174         384         —           —           558   

Pepco Energy Services

     273         199         56         27         555   

PHI Service Company and Other

     1,261         366         —           —           1,627   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total PHI Employees

     2,290         2,731         56         27         5,104   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions. All five collective bargaining agreements will expire within the next four years, including one agreement that will expire on June 1, 2012. Collective bargaining agreements are generally renegotiated every three to five years.

Environmental Matters

PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, greenhouse gas emissions, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI’s subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. PHI’s subsidiaries may also be responsible for ongoing environmental remediation costs associated with facilities or operations that have been sold to third parties as further described in Note (17), “Commitments and Contingencies – Environmental Matters – Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.

 

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PHI’s subsidiaries’ currently projected capital expenditures for the replacement of existing or installation of new environmental control facilities that are necessary for compliance with environmental laws, rules or agency orders are approximately $6 million in 2012 and $3 million in each of 2013, 2014 and 2015. This projection could change depending on the outcome of the matters addressed below or as a result of the imposition of additional environmental requirements or new or different interpretations of existing environmental laws, rules and agency orders. In view of the sale of the Conectiv Energy wholesale power generation business in 2010, PHI is no longer subject to environmental regulations prospectively applicable to electricity generating facilities, except insofar as such regulations affect the operation of the two generating facilities located in the District of Columbia owned by Pepco Energy Services. Moreover, PHI anticipates that these regulations will cease to apply to PHI electricity generating facilities altogether after May 2012, assuming the two generating facilities are deactivated by Pepco Energy Services as planned.

Air Quality Regulation

The generating facilities owned by Pepco Energy Services are subject to federal, state and local laws and regulations, including the Federal Clean Air Act, which limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements.

Sulfur Dioxide and Nitrogen Oxide Emissions

The acid rain provisions of the Clean Air Act regulate total Sulfur dioxide (SO2) emissions from affected generating units and allocate “allowances” to each affected unit that permit the unit to emit a specified amount of SO2. The generating facilities of Pepco Energy Services that require allowances use allocated allowances or allowances acquired, as necessary, in the open market to satisfy the applicable regulatory requirements.

In 2005, the U.S. Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (CAIR), which imposes further reductions of SO2 and limits nitrogen oxide (NOx) emissions from electric generating units in 28 eastern states and the District of Columbia. CAIR uses an allowance system to cap state-wide emissions (and emissions within the District of Columbia) of SO2 (using acid rain allowances) and NOx allowances, as described below, in two stages. NOx reductions were required beginning in 2009 and SO2 reductions were required beginning in 2010. States and the District of Columbia may implement CAIR by adopting EPA’s trading program or through adopting regulations that at a minimum achieve the level of reductions that would otherwise be achieved through implementation of EPA’s trading program. Pepco Energy Services Buzzard Point generating units and its landfill gas generating units produce fewer megawatts than CAIR’s applicability threshold and therefore are not subject to CAIR.

Each state covered by CAIR and the District of Columbia may determine independently which emission sources to control and which control measures to adopt. CAIR includes model rules for multi-state cap and trade programs for power plants that states may choose to adopt to meet the required emissions reductions. In the District of Columbia, the Pepco Energy Services’ Benning Road units are permitted to satisfy the CAIR requirements through the use of allocated allowances or allowances acquired in the open market, through the installation of pollution control devices or through fuel modifications. The Benning Road units use NOx annual, NOx ozone season and SO2 allowances allocated or acquired, as necessary, in the open market to comply with CAIR.

In July 2011, EPA adopted new regulations to replace CAIR, which address transport of air pollution across state boundaries. The Cross-State Air Pollution Rule (CSAPR) imposes stricter limits on SO2 and NOx (annual and ozone season) than CAIR; however, the District of Columbia was in the group of jurisdictions excluded from the SO2, NOx, and seasonal NOx under CSAPR. As a result, CSAPR’s Cap and Trade program, which was originally planned to go into effect on January 1, 2012, is not applicable to Pepco Energy Services.

On December 30, 2011, the District of Columbia Circuit Court of Appeals ruled to stay the CSAPR, and ordered EPA to continue enforcing CAIR. Consequently, Pepco Energy Services must continue to meet its CAIR obligations until after the court resolves petitions for review of CSAPR.

 

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Federal Regional Haze Rule

The federal Regional Haze Rule was adopted by EPA to address a type of visibility impairment known as regional haze created by the emission of specified pollutants by certain types of large stationary sources. The regulation requires installation of best available retrofit technology (BART) to boilers that (i) emit 250 tons or more per year of a visibility-impairing air pollutant, (ii) were placed in service between 1962 and 1977, and (iii) may reasonably be anticipated to cause or contribute to visibility impairment in any federally protected park or wilderness area. Pepco Energy Services’ Benning Road generating units are subject to this regulation for particulate matter less than ten microns in diameter and for SO2 and NOx to the extent not addressed by CAIR. Under Pepco Energy Services’ current operating permit issued by the DDOE, the Benning Road generating units will not be required to implement any remedial actions if the facilities are shut down on or before December 17, 2012, which is Pepco Energy Services’ current plan.

Pepco Energy Services’ other generating units, including those at Buzzard Point, are not subject to the Regional Haze Rule.

Hazardous Air Pollutant Emissions

In December 2011, EPA finalized a rule to reduce the emission of toxic air pollutants from generating facilities. The Mercury and Air Toxics Standards will reduce emissions of heavy metals, including mercury, arsenic, chromium and nickel, as well as emissions of acid gases, including hydrochloric and hydrofluoric acid. Because existing generating sources generally have up to four years from the Standards’ effective date to comply with the Mercury and Air Toxics Standards, this rule is not expected to impact the Benning Road or Buzzard Point generating facilities, which are expected to be retired by May 2012.

Greenhouse Gas Emissions Reporting

In October 2009, EPA adopted regulations requiring sources that emit designated greenhouse gases– specifically, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers) – in excess of specified thresholds to file annual reports with EPA disclosing the amount of such emissions. Under these regulations:

 

   

Pepco Energy Services reports CO2, methane and nitrous oxide for its Benning Road units. No changes or restrictions on operations will occur as a result of this rule.

 

   

DPL currently reports with respect to its gas distribution operations CO2 emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributes to its customers. Beginning in September 2012, DPL will be required to report fugitive CO2 and methane emissions for its gas distribution operations for the previous calendar year (hence, the 2012 report will contain data from calendar year 2011). DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.

 

   

ACE, DPL and Pepco will be required to start reporting sulfur hexafluoride emissions from electrical equipment beginning in September 2012, for the previous calendar year.

 

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Water Quality Regulation

Clean Water Act

Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act, establish the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, the Clean Water Act requires that any person wishing to discharge pollutants from a point source (generally a confined, discrete conveyance such as a pipe) obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program. The Benning Road facility has a NPDES permit authorizing pollutant discharges, which is subject to periodic renewal.

Pepco and a subsidiary of Pepco Energy Services discharge water from the Benning Road electric generating plant and service center located in the District of Columbia under a NPDES permit issued by EPA in July 2009. The permit imposes compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load standards for polychlorinated biphenyls (PCBs), oil and grease, metals and other substances. As required by the permit, Pepco has initiated studies to identify the source of the regulated substances to determine appropriate best management practices for minimizing the presence of the substances in storm water. The initial study reports are scheduled for completion in March 2012 and will be submitted to EPA as required. The capital expenditures, if any, that may be needed to implement best management practices to satisfy these new permit conditions will not be known until the results of the studies are reviewed by EPA.

New Jersey Flood Hazard Area Control Act

In November 2007, the New Jersey Department of Environmental Protection adopted amendments to the agency’s regulations under the Flood Hazard Area Control Act the (FHACA) to minimize damage to life and property from flooding caused by development in flood plains. The amended regulations impose a new regulatory program to mitigate flooding and related environmental impacts from a broad range of construction and development activities, including electric utility transmission and distribution construction, which were previously unregulated under the FHACA. These regulations impose restrictions on construction of new electric transmission and distribution facilities and increase the time and personnel resources required to obtain permits and conduct maintenance activities. While ACE continues to evaluate the financial impact related to compliance with the amended regulations, based on current information, PHI and ACE do not believe these regulations will have a material adverse effect on their respective financial conditions or results of operations.

EPA Oil Pollution Prevention Regulations

Facilities that, because of their location, store or use oil and could reasonably be expected to discharge oil into water bodies or adjacent shorelines in quantities that may be harmful to the environment are subject to EPA’s oil pollution prevention regulations. These regulations require entities to prepare and implement Spill Prevention, Control, and Countermeasure Plans (SPCC) and specify site-specific measures to prevent and respond to an oil discharge. The SPCC regulations generally require the use of containment and/or diversionary structures to prevent the discharge of oil in the event of a leak or release of oil at the facility. As an alternative to the containment/diversionary structure requirement, owners of certain oil-filled operational equipment, such as electric system transformers, may comply with EPA’s regulations by implementing an inspection and monitoring program, developing an oil spill contingency plan, and providing a written commitment of resources to control and remove any discharge of oil. ACE, DPL and Pepco are complying with the SPCC regulations by employing containment/diversionary structures and by means of inspection and monitoring measures, in each case where such measures have been determined to be appropriate. Total costs in 2011 to Pepco, DPL and ACE were approximately $5 million, $1 million and $2 million, respectively, as of December 31, 2011 and each utility expects to incur ongoing costs to comply with the SPCC regulations. In addition to the costs to comply with EPA’s oil pollution prevention regulations, PHI companies project expenditures of approximately $11 million over four years to replace certain oil-filled breakers with gas-filled breakers to eliminate the possibility of an oil release from such equipment. Compliance costs for Pepco Energy Services have not been material, and PHI does not expect that they will become material in the foreseeable future.

 

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Hazardous Substance Regulation

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) of 1980 authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Pepco, DPL and ACE each has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. See (i) Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Capital Requirements – Environmental Remediation Obligations,” and (ii) Note (17), “Commitments and Contingencies – Environmental Matters,” to the consolidated financial statements of PHI.

Executive Officers of PHI

The names of the executive officers of PHI, their ages and the positions they held as of February 23, 2012, are set forth in the following table. The business experience of each executive officer during the past five years is set forth adjacent to his or her name under the heading “Office and Length of Service” in the following table and in the applicable footnote.

 

Name

   Age     

Office and
Length of Service

Joseph M. Rigby

     55       Chairman of the Board 5/09 - Present, President 3/08 - Present, and Chief Executive Officer 3/09 - Present (1)

David M. Velazquez

     52      

Executive Vice President

3/09 - Present (2)

Kirk J. Emge

     62      

Senior Vice President and General Counsel

3/08 - Present (3)

Anthony J. Kamerick

     64      

Senior Vice President and Chief Financial Officer

6/09 - Present (4)

Beverly L. Perry

     64      

Senior Vice President

10/02 - Present

Ronald K. Clark

     56      

Vice President and Controller

8/05 - Present

Ernest L. Jenkins

     57      

Vice President

5/05 – Present

Laura L. Monica

     55      

Vice President

8/11 – Present (5)

Hallie M. Reese

     48      

Vice President, PHI Service Company

5/05 - Present

John U. Huffman

     52       President 6/06 - Present, and Chief Executive Officer, Pepco Energy Services, Inc. 3/09 - Present (6)

 

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(1) Mr. Rigby was Chief Operating Officer of PHI from September 2007 until February 28, 2009 and Executive Vice President of PHI from September 2007 until March 2008, Senior Vice President of PHI from August 2002 until September 2007 and Chief Financial Officer of PHI from May 2004 until September 2007. Mr. Rigby was President and Chief Executive Officer of ACE, DPL and Pepco from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009.
(2) Mr. Velazquez served as President of Conectiv Energy Holding Company, an affiliate of PHI, from June 2006 to February 28, 2009, Chief Executive Officer of Conectiv Energy Holding Company from January 2007 to February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006. He served as a Vice President of PHI from February 2005 to June 2006 and as Chief Risk Officer of PHI from August 2005 to June 2006.
(3) Mr. Emge was Vice President, Legal Services of PHI from August 2002 until March 2008. Mr. Emge has served as General Counsel of ACE, DPL and Pepco since August 2002 and as Senior Vice President of Pepco and DPL since March 1, 2009.
(4) Mr. Kamerick was Senior Vice President and Chief Regulatory Officer of PHI from March 2009 until June 2009. Mr. Kamerick was Vice President and Treasurer of PHI from August 2002 until February 28, 2009.
(5) From October 2006 to October 2010, Ms. Monica was Senior Vice President, Corporate Communications at American Water Works Company (NYSE: AWK), and from September 1991 to October 2006, Ms. Monica was President of High Point Communications, a strategic communications firm. Ms. Monica rejoined High Point Communications as President from October 2010 to August 2011.
(6) Mr. Huffman has been employed by Pepco Energy Services since June 2003. He was Chief Operating Officer from April 2006 to February 28, 2009, Senior Vice President from February 2005 to March 2006 and Vice President from June 2003 to February 2005.

Each PHI executive officer is elected annually and serves until his or her respective successor has been elected and qualified or his or her earlier resignation or removal.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

Item 1A. RISK FACTORS

The businesses of each Reporting Company are subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of any one or more of the Reporting Companies, including, depending on the circumstances, its financial condition, results of operations and cash flow. Unless otherwise noted, each risk factor set forth below applies to each Reporting Company.

 

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PHI utility subsidiaries are subject to comprehensive regulation which may significantly affect their operations. PHI’s utility subsidiaries may be subject to fines, penalties and other sanctions for the inability to meet these requirements.

The regulated utilities that comprise Power Delivery are subject to extensive regulation by various federal, state and local regulatory agencies. Each of Pepco, DPL and ACE is regulated by the state agencies for each service territory in which it operates, with respect to, among other things, the manner in which utility service is provided to customers, as well as rates it can charge customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). NERC has also established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. Further, FERC regulates the electricity transmission facilities of Pepco, DPL and ACE.

Approval of these regulators is required in connection with changes in rates and other aspects of the utilities’ operations. These regulatory authorities, and NERC with respect to electric reliability, are empowered to impose financial penalties, fines and other sanctions against the utilities for non-compliance with certain rules and regulations. In this regard, in December 2011, the MPSC sanctioned Pepco related to its reliability in connection with major storm events that occurred in July and August 2010. These sanctions included imposing a fine on Pepco and requiring Pepco to file a work plan detailing, among other things, its reliability improvement objectives and progress in meeting those objectives, while raising the possibility of additional fines or cost disallowances for failing to meet those objectives. The MPSC also stated that it would consider in Pepco’s pending Maryland retail base rate case the potential disallowance of costs which may be determined to have been imprudently incurred.

NERC’s eight regional oversight entities, including RFC, of which Pepco, DPL, ACE and Pepco Energy Services are members, and NPCC, of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services are subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” From time to time, Pepco, DPL and ACE have entered into settlement agreements with RFC resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RFC or NPCC requirements will not occur in the future. The imposition of additional sanctions and civil fines by these enforcement entities could have a material adverse effect on a Reporting Company’s results of operations, cash flow and financial condition.

PHI’s utility subsidiaries, as well as Pepco Energy Services, are also required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. Although PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws, PHI is unable to predict the impact that future regulatory activities may have on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require any one or more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

PHI’s profitability is largely dependent on its ability to recover costs of providing utility services to its customers and to earn an adequate return on its capital investments. The failure of PHI to obtain timely recognition of costs in its rates may have a negative effect on PHI’s results of operations and financial condition.

The public service commissions which regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide the utility the opportunity to obtain revenues sufficient to recover its prudently incurred costs, together with a reasonable return on investor supplied capital. These regulatory authorities also determine how Pepco, ACE and DPL recover from their customers purchased power and natural gas

 

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and other operating costs, including transmission and other costs. The utilities cannot change their rates without approval by the applicable regulatory authority. There can be no assurance that the regulatory authorities will consider all costs to have been prudently incurred, nor can there be any assurance that the regulatory process by which rates are determined will always result in rates that achieve full and timely recovery of costs or a just and reasonable rate of return on investments. In addition, if the costs incurred by any of the utilities in operating its business exceed the amounts on which its approved rates are based, the financial results of that utility, and correspondingly PHI, may be adversely affected.

PHI’s utility subsidiaries are also exposed to “regulatory lag,” which refers to a shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. All of PHI’s utilities are currently experiencing significant regulatory lag because their investment in the rate base and their operating expenses are outpacing revenue growth. PHI anticipates that this trend will continue for the foreseeable future. The failure to timely recognize costs in rates could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

In their most recent rate cases, Pepco (in the District of Columbia and Maryland), DPL (in Maryland and Delaware) and ACE (in New Jersey) have proposed mechanisms that would track reliability and other expenses and permit each utility to make adjustments in its approved rates to account for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. In New Jersey, the NJBPU has previously approved a similar mechanism, and ACE currently has an update and expansion of that previously approved mechanism pending before the NJPBU. There can be no assurance that these proposals or any attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms will fully ameliorate the effects of regulatory lag. If necessary to address in whole or in part the problem of regulatory lag, each utility can file base rate cases annually (or even more frequently) to seek to align its revenue and related cash flow levels allowed by the applicable public service commissions with operation and maintenance spending and capital investments. The inability of PHI’s utility subsidiaries to obtain relief from the impact of regulatory lag through base rate cases or otherwise may have an adverse effect on the business, results of operations, cash flow and financial condition of PHI and each utility subsidiary.

The operating results of Power Delivery and the retail energy supply business of Pepco Energy Services fluctuate on a seasonal basis and can be adversely affected by changes in weather.

The Power Delivery business historically has been seasonal and, as a result, weather has had a material impact on its operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer in the winter and cooler in the summer. In addition, severe weather conditions can produce storms that cause extensive damage to the transmission and distribution systems, as well as related facilities, that can require the utilities to incur additional operation and maintenance expense, as well as capital expenditures. These additional costs can be significant and the rates charged to customers may not always be timely or adequately adjusted to reflect these higher costs.

In the District of Columbia and Maryland, Pepco and DPL are subject to a bill stabilization adjustment mechanism applicable to retail customers, which decouples distribution revenue for a given reporting period from the amount of power delivered during the period. The bill stabilization mechanism has the effect in those jurisdictions of reducing the impact of changes in the use of electricity by retail customers due to weather conditions or for other reasons on reported distribution revenue and income. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.

 

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The retail energy supply business of Pepco Energy Services generally produces higher gross margins when temperatures are colder than normal in winter or warmer than normal in summer, and less gross margin when weather conditions are milder than normal. The energy services business of Pepco Energy Services, which includes providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power energy plants for customers, is not seasonal.

Facilities may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.

Operation of the Pepco, DPL and ACE transmission and distribution facilities involves many risks, including the breakdown or failure of equipment, accidents, labor disputes, theft of copper wire or pipe, scams, failure of software or hardware, and performance below expected levels. Older facilities and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Thefts of copper wire or pipe, which seek to capitalize on the current high market price of copper, increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance.

PHI’s Blueprint for the Future program includes the replacement of customers’ existing electric and gas meters with an AMI system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.

Energy companies are subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions.

Utility companies, including PHI’s utility subsidiaries, have a large consumer customer base and as a result have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures, public service commissions and other regulatory authorities and government officials, less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing PHI’s operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

 

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Unfavorable regulatory developments and compliance with new or enhanced regulatory requirements will subject PHI’s utility subsidiaries to higher operating costs.

PHI’s utility subsidiaries are subject to and will continue to be subject to changing regulatory requirements, including those related to reliability and customer service, in the various jurisdictions in which they operate. For example, in December 2011, the MPSC approved proposed rules establishing reliability and customer service regulations, compliance with which is anticipated to be mandated as early as the second quarter of 2012. In addition, in July 2011, the DCPSC adopted regulations that establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020 and thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. Pepco believes that the DCPSC’s standards are achievable in the short term, but continues to believe that the standards may not be realistically achievable at an acceptable cost over the longer term. The reliability standards permit Pepco to petition the DCPSC to reevaluate these standards for the period from 2016 to 2020 to address feasibility and cost issues.

Each of Pepco and DPL expect that it will have to incur significant operating and maintenance and capital expenses to comply with these requirements. Furthermore, each of Pepco and DPL would be subject to civil penalties or other sanctions if it does not meet the required performance or reliability standards. Other jurisdictions in which PHI’s utility subsidiaries have operations have reliability and customer service quality standards, the violation of which could also result in the imposition of penalties, fines and other sanctions. Compliance, and any failure to comply, with current, proposed or future regulatory requirements may have a material adverse effect on PHI and each utility subsidiary’s business, results of operations, cash flow and financial condition.

The transmission facilities of Power Delivery are interconnected with the facilities of other transmission facility owners. Failures of neighboring transmission systems could have a negative impact on Power Delivery’s operations.

The electricity transmission facilities of Pepco, DPL and ACE are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid. Pepco, DPL and ACE are members of the PJM RTO, a regional transmission organization that operates the portion of the interstate transmission grid that includes the PHI transmission facilities. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions originating at other utilities will not cause interruptions in the Pepco, DPL or ACE service territories. Thus, due to the interconnected nature of the grid, an outage in a neighboring utility could trigger a system outage in either Pepco, DPL or ACE. If Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on its and PHI’s business, results of operations, cash flow and financial condition.

Changes in technology and conservation measures may adversely affect Power Delivery.

Increased conservation and end-user generation made possible through advances in technology could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect PHI and one or more of its utility subsidiaries. Alternative technologies to produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity. As these new technologies are developed and

become available, the quantity and pattern of electricity usage by customers could decline, which could have a negative impact on the business, results of operations, cash flow and financial condition of PHI or its utility subsidiaries.

 

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The cost of compliance with environmental laws is significant and implementation of new and existing environmental laws may increase operating costs.

The operations of PHI’s subsidiaries are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, spill prevention, waste management, natural resource protection, site remediation and health and safety. These laws and regulations may require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation, complete environmental studies and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to achieve compliance.

In addition, PHI’s subsidiaries are required to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if there is a failure to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.

Failure to retain and attract key skilled and properly motivated professional and technical employees could have an adverse effect on operations.

PHI and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated systems and technology. One of the challenges they face in implementing their business strategy is to attract, motivate and retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. Over the course of the next three years, PHI estimates that approximately one-third of this skilled workforce will reach retirement age. Competition for skilled employees in some areas is high and the inability to attract and retain these employees, especially as existing skilled workers retire in the near future, could adversely affect the business, operations and financial condition of PHI or the affected company.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2011, 55% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. All five collective bargaining agreements will expire within the next four years, including one agreement that expires on June 1, 2012. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations. Though PHI believes that a protracted work stoppage is unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of PHI and the affected utility.

The energy services business of Pepco Energy Services is highly competitive. (PHI only)

Unlike PHI’s regulated business, Pepco Energy Services’ business is highly competitive and is not assured a rate of return on capital investments through a predetermined rate structure. This competition generally has the effect of limiting margins and requiring a continual focus on controlling costs. The energy services business is impacted by new entrants into the market, energy prices, and general economic conditions. These factors may negatively impact Pepco Energy Services’ ability to market its services to new customers, or renew existing contracts, as well as the prices Pepco Energy Services may charge.

 

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Among the factors on which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts. In connection with many of its energy efficiency installation projects, Pepco Energy Services guarantees a minimum level of annual energy cost savings over a period typically ranging up to 15 years. Currently, Pepco Energy Services does not insure against this risk, and accordingly could suffer financial losses if a project does not achieve the guaranteed level of performance.

Under its energy savings performance contracts, Pepco Energy Services is responsible for maintaining, repairing and replacing energy equipment, which obligations may require Pepco Energy Services to incur significant costs many years after an installation of a project is completed. (PHI only)

Pepco Energy Services owns energy equipment and is also responsible for operating and maintaining additional energy equipment that it does not own. In addition, it is generally Pepco Energy Services’ responsibility to repair or replace this energy equipment in the event of a failure. These equipment maintenance, repair and replacement obligations could adversely affect PHI’s results of operations, cash flow and financial condition.

The inability of Pepco Energy Services to perform its obligations in connection with its energy services construction projects may have a material adverse effect on PHI. (PHI only)

Projects undertaken by Pepco Energy Services include design, construction, startup and testing activities related to combined heat and power and other energy facilities, pursuant to guaranteed maximum price or fixed-price contracts. Pepco Energy Services will generally secure commitments from subcontractors and vendors to perform within contract pricing commitments, equipment-performance standards, jobsite safety requirements, and other key parameters. Ultimately, however, Pepco Energy Services will bear responsibility in the event of unexcused failures by these subcontractors and vendors, as well as other third parties, to perform in accordance with the terms of these contracts or otherwise pursuant to the expectations of the parties. If such events occur, Pepco Energy Services could experience reputational harm and claims for money damages and other relief, which could, depending upon the cause and severity of the failure of performance, adversely affect PHI’s business, results of operations, cash flow and financial condition.

Pepco Energy Services relies on generation, transmission, storage and distribution assets that it does not own or control to deliver electricity and natural gas to its customers and to obtain the fuel required to operate its generating facilities. (PHI only)

Pepco Energy Services is dependent on electric generating and transmission facilities, natural gas pipelines and natural gas storage facilities owned and operated by others to fulfill the remaining contractual obligations of its retail energy supply business. A disruption in the operation of these facilities or the inefficient operation of these facilities would have an adverse effect on Pepco Energy Services.

The operation of Pepco Energy Services’ generating facilities depends on fuel supplied by others. If the fuel supply to these generating facilities was to be disrupted and storage or other sources of supply were not available, the ability of Pepco Energy Services to operate its plants would be adversely affected.

If PHI is not successful in mitigating the risks inherent in its business, its operations could be adversely affected.

PHI and its subsidiaries are faced with a number of different types of risk. PHI confronts legislative, regulatory policy, compliance and other risks, including:

 

   

risks related to recovery of capital and operating costs;

 

   

resource planning and other long-term planning risks, including resource acquisition risks;

 

   

financial risks, including credit, interest rate and capital market risks; and

 

   

macroeconomic risks, including risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries, as well as with respect to Pepco Energy Services’ business.

PHI management seeks to mitigate the risks inherent in the implementation of PHI’s business strategy through its established risk mitigation process, which includes adherence to PHI’s business policies and other compliance policies, operation of formal risk management structures and groups, and overall business management. PHI management is responsible for identifying, assessing and managing risks, and developing risk-management strategies, while the Board of Directors and its Audit Committee oversee the assessment, management and mitigation of risk. However, there can be no assurance these risk mitigation efforts will adequately address all such risks.

 

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PHI and its subsidiaries are exposed to contractual and credit risks associated with certain of their operations.

PHI and its subsidiaries are subject to a number of contractual and credit risks associated with certain of their operations. For example, Pepco Energy Services has entered into commercial transactions for the purchase and sale of electricity and natural gas, as well as derivative and other transactions to manage the risk of commodity price fluctuations. Under these arrangements, Pepco Energy Services is exposed to the risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by Pepco Energy Services when the counterparty is required to do so. In addition, PHI’s PCI subsidiary has entered into several cross-border energy lease investments located outside the United States. Under these leases, PCI is exposed to the risk that the counterparty may fail to make lease payments on time or at all.

Many of these contracts provide for PHI or a subsidiary to receive collateral or other types of performance assurance from the counterparty, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. In the event of a bankruptcy of a counterparty to any contract to which PHI or any of its subsidiaries is a party, bankruptcy law, in some circumstances, could require the surrender of collateral held or payments received. In the case of PCI, the fact that the counterparties are located outside the United States could make it more difficult for PCI to seek redress or obtain a judgment or compensation against a foreign counterparty for any breach of the lease agreement by that counterparty.

The retail energy supply business of Pepco Energy Services can give rise to significant collateral requirements. (PHI only)

In conducting its retail energy supply business, Pepco Energy Services has entered into electricity or natural gas supply agreements and wholesale purchase contracts for electricity and natural gas that typically impose collateral requirements on each party. The collateral requirements are designed to protect the other party against the risk of nonperformance between the date the contract was entered into and the date of payment for the energy. When energy market prices decrease relative to the supplier contract prices, Pepco Energy Services’ collateral obligations increase. While Pepco Energy Services is no longer entering into new energy supply contracts, it has continuing supply obligations based on existing contracts and corresponding wholesale purchase contracts that extend through 2014. Particularly in periods of energy market price volatility, the collateral obligations associated with these wholesale purchase contracts can be substantial, although they can be expected to diminish as the retail energy supply business is wound down. These collateral demands could negatively affect PHI’s liquidity by requiring PHI to draw on its capacity under its primary credit facility or other financing sources.

 

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Business operations could be adversely affected by terrorism and cyber attacks.

The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause electrical disruptions or disruptions of fuel supplies and markets, including natural gas. Utility industry operations require the continued deployment and utilization of sophisticated information technology systems and network infrastructure. While PHI has implemented protective measures designed to mitigate its vulnerability to physical and cyber threats and attacks, such protective measures, and technology systems generally, are vulnerable to disability or failure due to cyber attack, acts of war or terrorism, and other causes. As a result, there can be no assurance that such protective measures will be completely effective in protecting PHI’s infrastructure or assets from a physical or cyber attack or the effects thereof. If any of Pepco’s, DPL’s or ACE’s infrastructure facilities, including their transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of PHI’s and its subsidiaries’ facilities, or the integrity or security of their computer networks and systems (and any programs or data stored thereon or therein), could adversely affect PHI’s and its subsidiaries’ ability to manage these facilities, networks, systems, programs and data efficiently or effectively, which in turn could have a material adverse effect on PHI’s or its subsidiaries’ results of operations and financial condition. Corresponding instability in the financial markets as a result of threats or acts of terrorism or threatened or actual cyber attacks also could adversely affect the ability of PHI or its subsidiaries to raise needed capital.

Mark-to-market accounting treatment for instruments Pepco Energy Services uses to hedge the cost of supply used to satisfy retail customer load obligations could cause earnings volatility. (PHI only)

Pepco Energy Services purchases energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of natural gas and electricity for delivery to customers. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked to market through current earnings. Any change in the fair value of the transactions used to hedge price risk that receive mark-to-market accounting treatment will be reflected in PHI’s current earnings without any offsetting change in the fair value of its retail load obligations until the settlement date of these contracts in future periods. As a result, PHI’s earnings could be more volatile due to the mark-to-market accounting treatment associated with these commodity contracts. As of December 31, 2011, the commodity contracts that Pepco Energy Services currently accounts for on an accrual basis (because they are designated as normal purchases or normal sales) are, on a fair value basis, in a significant net loss position. If PHI could no longer sustain the normal purchase and normal sale designation for these contracts, it would be required to recognize these net losses in earnings, which could result in greater earnings volatility.

New accounting standards or changes to existing accounting standards could materially impact how a Reporting Company reports its results of operations, cash flow and financial condition.

Each Reporting Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The SEC, the Financial Accounting Standards Board (FASB) or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require the Reporting Companies to change their accounting policies. These changes are beyond the control of the Reporting Companies, can be difficult to predict and could materially impact how they report their results of operations, cash flow and financial condition. Each Reporting Company could be required to apply a new or revised standard retroactively, which could adversely affect its results of operations, cash flow and financial condition.

 

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Each Reporting Company’s financial statements, including their reported earnings, could be significantly impacted by convergence of GAAP with International Financial Reporting Standards (IFRS).

The FASB is expected to make broad changes to GAAP as part of an overall initiative to converge GAAP with IFRS. These changes could have significant impacts on the financial statements of each Reporting Company. Also, the SEC is considering incorporating IFRS into the financial reporting system for U.S. public companies. A transition to IFRS could significantly impact each Reporting Company’s financial results, since these standards differ from GAAP in many ways. One of the major differences is the lack of special accounting treatment for regulated activities under IFRS, which could result in greater earnings volatility for each Reporting Company.

Undetected errors in internal controls and information reporting could result in the disallowance of cost recovery and noncompliant disclosure.

Each Reporting Company’s internal controls, accounting policies and practices and internal information systems are designed to enable the Reporting Company to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, laws and regulations, taxation requirements and federal securities laws and regulations applicable to it. Such compliance permits each Reporting Company to, among other things, disclose and report financial and other information in connection with the recovery of its costs and with the reporting requirements for each Reporting Company under federal securities, tax and other laws and regulations.

Each Reporting Company has implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and relevant SEC rules, as well as other applicable regulations. Such internal controls and policies have been and continue to be closely monitored by each Reporting Company’s management and PHI’s Board of Directors to ensure continued compliance with these laws, rules and regulations. Management is also responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. While PHI believes these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees or temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to undetected errors that could result in the disallowance of cost recovery and noncompliant disclosure and reporting. The consequences of these events could have a negative impact on the results of operations and financial condition of the affected Reporting Company. The inability of management to certify as to the effectiveness of these controls due to the identification of one or more material weaknesses in these controls could also increase financing costs or could also adversely affect the ability of a Reporting Company to access the capital markets.

Insurance coverage may not be sufficient to cover all casualty or property losses that the companies might incur.

PHI and its subsidiaries, including Pepco, DPL and ACE, currently have insurance coverage for their facilities and operations in amounts and with deductibles that they consider appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at all. In addition, some risks, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire cost of replacement or repair.

 

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The Internal Revenue Service (IRS) challenge to cross-border energy sale and lease-back transactions entered into by a PHI subsidiary could result in loss of prior and future tax benefits. (PHI only)

PCI maintains a portfolio of seven cross-border energy lease investments, which as of December 31, 2011, had an equity value of approximately $1.3 billion and from which PHI currently derives approximately $51 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. PHI’s cross-border energy lease investments, each of which is with a tax-indifferent party, have been under examination by the IRS as part of the normal PHI federal income tax audits. In the final IRS revenue agent’s report in connection with the audits of PHI’s federal income tax returns from 2001 to 2005, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income. PHI disagrees with the IRS’ proposed adjustments and filed tax protests.

Effective November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. PHI’s claim for refund for the disallowed deductions was denied by the IRS and PHI has filed suit against the IRS in the U.S. Court of Federal Claims to recover payments made. The case with respect to the 2003 to 2005 returns is currently pending with the IRS Office of Appeals.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these leases and recharacterizing these leases as loans, PHI estimates that, as of December 31, 2011, it would be obligated to pay approximately $643 million in additional federal and state taxes and $121 million of interest, of which $74 million has been satisfied by the payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional tax would not be due immediately. Rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income due to the recharacterization of the leases as loans, PHI would be required under Financial Accounting Standards Board guidance on leases (Accounting Standards Codification (ASC) 840) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a non-cash charge to earnings that could be material.

For further discussion of this matter, see Note (17), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

PHI and its subsidiaries are dependent on obtaining access to capital markets and bank financing to satisfy their capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on their respective businesses.

PHI, Pepco, DPL and ACE each have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. These companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of PHI and its subsidiaries also require access to short-term money markets and bank financing

 

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as sources of liquidity that are not met by cash flow from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent PHI or any of its subsidiaries from accessing one or more financial markets. Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:

 

   

a recession or an economic slowdown;

 

   

the bankruptcy of one or more energy companies or financial institutions;

 

   

a significant change in energy prices;

 

   

a terrorist or cyber attack or threatened attacks;

 

   

the outbreak of a pandemic or other similar event; or

 

   

a significant electricity or natural gas transmission disruption.

Any reductions in or other actions with respect to the credit ratings of PHI or any of its subsidiaries could increase its financing costs and the cost of maintaining certain contractual relationships.

Nationally recognized rating agencies currently rate PHI, Pepco, DPL and ACE, and debt securities issued by Pepco, DPL and ACE. Ratings are not recommendations to buy or sell securities. PHI or its subsidiaries may, in the future, incur new indebtedness with interest rates that may be affected by changes in or other actions associated with these credit ratings. Each of the rating agencies reviews its ratings periodically, and previous ratings may not be maintained in the future. Rating agencies may also place PHI, Pepco, DPL or ACE under review for potential downgrade in certain circumstances or if any of them seek to take certain actions. A downgrade of these debt ratings or other negative action, such as a review for a potential downgrade, could affect the market price of existing indebtedness and the ability to raise additional debt without incurring increases in the cost of capital. In addition, a downgrade of these ratings, or other negative action, could make it more difficult to raise capital to refinance any maturing debt obligations, to support business growth and to maintain or improve the current financial strength of PHI’s business and operations.

The collateral requirements of Pepco Energy Services’ retail energy supply business also are determined in part by the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s or the utility’s operating results or prospects would increase funding costs. Any increases in collateral requirements could make such contractual obligations more expensive and make financing more difficult to obtain.

The agreements that govern PHI’s primary credit facility contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, the consolidated indebtedness of each borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict the affected Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, a further write-down of PHI’s cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the restrictions on its ability to operate its business in its sole discretion could harm PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

 

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PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its regulated and competitive operating subsidiaries, access to capital markets and other sources of liquidity. PHI’s unsecured obligations are effectively subordinated to the liabilities of its subsidiaries. (PHI only)

PHI is a holding company that conducts its operations entirely through its regulated and competitive subsidiaries, and all of PHI’s consolidated operating assets are held by its subsidiaries. Accordingly, PHI’s cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of its subsidiaries, each Reporting Company’s access to capital markets and all sources of cash flow and liquidity that may be available to PHI. PHI’s subsidiaries are separate legal entities and have no obligation to pay any amounts due on any debt or equity securities issued by PHI or to make any funds available for such payment. The ability of PHI’s subsidiaries to pay dividends and make other payments to PHI may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements made by PHI and its subsidiaries, including under the terms of indebtedness, and PHI’s financial objective of maintaining a common equity ratio at its utility subsidiaries of between 48% and 50%. Because the claims of the creditors of PHI’s subsidiaries are superior to PHI’s entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries, including trade creditors. In addition, claims of creditors, including trade creditors, of PHI’s subsidiaries will generally have priority with respect to the assets and earnings of such subsidiaries over the claims of PHI’s creditors.

Further delays in the current in-service date for the MAPP project or the suspension or cancellation of this project could hinder PHI’s future revenue growth. (PHI, Pepco and DPL)

In 2007, PJM directed PHI and its utility subsidiaries to construct MAPP to address future potential violations of national and regional standards for reliable operation of the region’s transmission system. On August 18, 2011, PJM notified PHI that it has delayed the scheduled in-service date for MAPP from June 1, 2015 to the 2019 to 2021 time period, after taking into account changes in the demand response, generation retirements and additions, and a revised load forecast for the PJM region that was lower than forecasted in prior PJM studies. A more recent load forecast continues to support this load forecast trend. PJM is currently evaluating the exact in-service date as part of its 2012 Regional Transmission Expansion Plan review process. In the interim, the delay of the in-service date will defer a substantial portion of the transmission revenue that PHI expects to earn from the MAPP project, which is anticipated to generate higher rates of return on equity than most of PHI’s other existing transmission assets. Depending on the conclusions reached in its 2012 evaluation, PJM may further delay the required in-service date for the MAPP project or suspend or cancel the project altogether. Although PHI intends to substitute alternative transmission projects for MAPP based on the delay in the MAPP in service date, PHI may not be able to achieve an equal or higher rate of return on these alternative projects as has been approved under the MAPP project.

PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant non-cash charge to earnings.

PHI had a goodwill balance at December 31, 2011, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv in 2002. An impairment charge must be recorded under GAAP to the extent that the implied fair value of goodwill is less than the carrying value of goodwill, as shown on the consolidated balance sheet. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include a decline in PHI’s stock price causing market capitalization to fall below book value, an adverse change in business conditions or an adverse regulatory action. If PHI were to determine that its goodwill is impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition and results of operations, but would not have an impact on cash flow.

 

35


The funding of future defined benefit pension plan and post-retirement benefit plan obligations is based on assumptions regarding the valuation of future benefit obligations and the performance of plan assets. If market performance decreases plan assets or changes in assumptions regarding the valuation of benefit obligations increase plan liabilities, any of the Reporting Companies may be required to make significant cash contributions to fund these plans.

PHI holds assets in trust to meet its obligations under PHI’s defined benefit pension plan and its postretirement benefit plan. The amounts that PHI is required to contribute (including the amounts for which Pepco, DPL and ACE are responsible) to fund the trusts are determined based on assumptions made as to the valuation of future benefit obligations, and the investment performance of the plan assets. Accordingly, the performance of the capital markets will affect the value of plan assets. A decline in the market value of plan assets may increase the plan funding requirements to meet the future benefit obligations. In addition, changes in interest rates affect the valuation of the liabilities of the plans. As interest rates decrease, the liabilities increase, potentially requiring additional funding. Demographic changes, such as a change in the expected timing of retirements or changes in life expectancy assumptions, also may increase the funding requirements of the plans. A need for significant additional funding of the plans could have a material adverse effect on the cash flows of any of the Reporting Companies. Future increases in pension plan and other postretirement benefit plan costs, to the extent they are not recoverable in the base rates of PHI’s utility subsidiaries, could have a material adverse effect on the results of operations, cash flow and financial condition of any of the Reporting Companies.

Provisions of the Delaware General Corporation Law and in PHI’s constituent documents may discourage an acquisition of PHI. (PHI only)

PHI is governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibit a public Delaware corporation from engaging in a business combination with an interested stockholder (as defined in Section 203) for a period commencing three years from the date in which the person became an interested stockholder, unless:

 

   

the board of directors approved the transaction which resulted in the stockholder becoming an interested stockholder;

 

   

upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation (excluding shares owned by officers, directors, or certain employee stock purchase plans); or

 

   

at or subsequent to the time the transaction is approved by the board of directors, there is an affirmative vote of at least 66 2/3% of the outstanding voting stock not owned by the interested stockholder approving the transaction.

Section 203 could prohibit or delay mergers or other takeover attempts against PHI, and accordingly, may discourage or prevent attempts to acquire PHI through a tender offer, proxy contest or otherwise.

In addition, PHI’s restated certificate of incorporation and amended and restated bylaws contain provisions that may discourage, delay or prevent a third party from acquiring PHI, even if doing so would be beneficial to its stockholders. Under PHI’s restated certificate of incorporation, only its board of directors may call special meetings of stockholders. Further, stockholder actions may only be taken at a duly called annual or special meeting of stockholders and not by written consent. Moreover, directors of PHI may be removed by stockholders only for cause and only by the effective vote of at least a majority of the outstanding shares of capital stock of PHI entitled to vote generally in the election of directors (voting together as a single class) at a meeting of stockholders called for that purpose. In addition, under PHI’s amended and restated bylaws, stockholders must comply with advance notice requirements for

 

36


nominating candidates for election to PHI’s board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings, and this provision may be amended or repealed by stockholders only upon the affirmative vote of the holders of two-thirds of the outstanding shares of PHI capital stock entitled to vote generally in the election of directors, voting together as a single class.

Issuances of additional series of PHI preferred stock could adversely affect holders of PHI’s common stock. (PHI only)

PHI’s board of directors is authorized to issue shares of PHI preferred stock in series without any action on the part of PHI stockholders. PHI’s board of directors also has the power, without stockholder approval, to set the terms of any such series of preferred stock, including with respect to dividend rights, redemption rights and sinking fund provisions, conversion rights, voting rights, and other preferential rights, limitations and restrictions. If PHI issues preferred stock in the future that has a preference over PHI’s common stock with respect to the payment of dividends or upon its liquidation, dissolution or winding up, or if preferred stock is issued with voting rights that dilute the voting power of the common stock, the rights of holders of PHI’s common stock or the market price of such common stock could be adversely affected. Furthermore, issuances of preferred stock can be used to discourage, delay or prevent a third party from acquiring PHI where the acquisition might be perceived as being beneficial to stockholders.

Because Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI, PHI can exercise substantial control over their dividend policies and businesses and operations. (Pepco, DPL and ACE only)

All of the members of each of Pepco’s, DPL’s and ACE’s board of directors, as well as many of their respective executive officers, are officers of PHI. Among other decisions, each of Pepco’s, DPL’s and ACE’s board is responsible for decisions regarding payment of dividends, financing and capital raising activities and acquisition and disposition of assets. Within the limitations of applicable law, and subject to the financial covenants under each company’s respective outstanding debt instruments, each of Pepco’s, DPL’s and ACE’s board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on its capital structure, which is based in part on earnings and cash flow, and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.

 

Item 1B. UNRESOLVED STAFF COMMENTS

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

 

37


Item 2. PROPERTIES

Generating Facilities

The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2011.

 

Electric Generating Facilities

   Location    Owner    Generating
Capacity
(kilowatts)
 

Oil Fired Units

        

Benning Road (a)

   Washington, DC    Pepco Energy Services      550,000   
        

 

 

 

Combustion Turbines/Combined Cycle Units

        

Buzzard Point (a)

   Washington, DC    Pepco Energy Services      240,000   
        

 

 

 

Landfill Gas-Fired Units

        

Fauquier Landfill Project

   Fauquier County, VA    Pepco Energy Services      2,000   

Eastern Landfill Project

   Baltimore County, MD    Pepco Energy Services      3,000   

Bethlehem Landfill Project

   Northampton, PA    Pepco Energy Services      5,000   
        

 

 

 
           10,000   
        

 

 

 

Solar Photovoltaic

        

Atlantic City Convention Center

   Atlantic City, NJ    Pepco Energy Services      2,000   
        

 

 

 

Total Electric Generating Capacity

     802,000   
        

 

 

 

(a)     PHI intends to deactivate these facilities by the end of May 2012.

       

The preceding table sets forth the net summer electric generating capacity of each electric generating facility owned. Although the generating capacity may be higher during the winter months, the facilities are used to meet summer peak loads that are generally higher than winter peak loads. Accordingly, the summer generating capacity more accurately reflects the operational capability of the facilities.

Transmission and Distribution Systems

On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2011, consisted of approximately 3,900 transmission circuit miles of overhead lines, 460 transmission circuit miles of underground cables, 18,400 distribution circuit miles of overhead lines, and 16,200 distribution circuit miles of underground cables, primarily in their respective service territories. DPL and ACE own and operate distribution system control centers in New Castle, Delaware and Mays Landing, New Jersey, respectively. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.

DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 3 million gallons and an emergency sendout capability of 25,000 Mcf per day. DPL owns 10 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 204,075 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,912 pipeline miles of natural gas distribution mains, and 1,309 natural gas pipeline miles of service lines. In addition, DPL has a 10% undivided interest in approximately 7 miles of natural gas transmission mains, which are used by DPL for its natural gas operations and by the 90% owner for distribution of natural gas to its electric generating facilities.

 

38


Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE is subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (11), “Debt” to the consolidated financial statements of PHI.

 

Item 3. LEGAL PROCEEDINGS

Pepco Holdings

Other than litigation incidental to PHI and its subsidiaries’ business, PHI is not a party to, and PHI and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (17), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

Pepco

Other than litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the financial statements of Pepco.

DPL

Other than litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the financial statements of DPL.

ACE

Other than litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies,” to the consolidated financial statements of ACE.

 

Item 4. MINE SAFETY DISCLOSURES

Not applicable

 

39


Part II

 

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.

 

     Dividends      Price Range
 

Period

   Per Share      High      Low  

2011:

        

First Quarter

   $ .27      $ 19.14       $ 17.83   

Second Quarter

     .27        20.36         18.10   

Third Quarter

     .27        20.04         16.57   

Fourth Quarter

     .27        20.64         17.77   
  

 

 

       
   $ 1.08        
  

 

 

       

2010:

        

First Quarter

   $ .27      $ 17.57       $ 15.74   

Second Quarter

     .27        17.78         15.13   

Third Quarter

     .27        18.92         15.40   

Fourth Quarter

     .27        19.80         18.01   
  

 

 

       
   $ 1.08        
  

 

 

       

At February 15, 2012, there were 52,667 registered holders of record of Pepco Holdings common stock.

Dividends

On January 26, 2012, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 30, 2012, to shareholders of record on March 12, 2012.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Capital Requirements — Dividends,” and Note (14), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock — Dividend Restrictions,” for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.

PHI Subsidiaries

One of PHI’s financial objectives is to maintain an equity ratio of 48%-50% in each of its operating utilities. Each quarter, PHI may contribute equity into its utility subsidiaries or the utility subsidiaries may make a dividend payment to PHI in order to maintain an equity ratio of 48%-50% in each of the utility subsidiaries.

 

40


Pepco

All of Pepco’s common stock is held by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI during each quarter in the last two years. Dividends received by PHI in 2011 and 2010 were used to support the payment of its common stock dividend.

 

Period

   Aggregate
Dividends
 

2011:

  

First Quarter

   $ —     

Second Quarter

     —     

Third Quarter

     —     

Fourth Quarter

     25,000,000   
  

 

 

 
   $ 25,000,000   
  

 

 

 

2010:

  

First Quarter

   $ 25,000,000   

Second Quarter

     25,000,000   

Third Quarter

     45,000,000   

Fourth Quarter

     20,000,000   
  

 

 

 
   $ 115,000,000   
  

 

 

 

DPL

All of DPL’s common stock is held by Conectiv, LLC (Conectiv). The table below presents the aggregate amount of common stock dividends paid by DPL to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2011 and 2010 were passed through to PHI to support the payment of its common stock dividend.

 

Period

   Aggregate
Dividends
 

2011:

  

First Quarter

   $ —     

Second Quarter

     —     

Third Quarter

     50,000,000   

Fourth Quarter

     10,000,000   
  

 

 

 
   $ 60,000,000   
  

 

 

 

2010:

  

First Quarter

   $ —     

Second Quarter

     23,000,000   

Third Quarter

     —     

Fourth Quarter

     —     
  

 

 

 
   $ 23,000,000   
  

 

 

 

 

41


ACE

All of ACE’s common stock is held by Conectiv. The table below presents the aggregate amount of common stock dividends paid by ACE to Conectiv during each quarter in the last two years. Dividends received by Conectiv in 2010 were used to pay down short-term debt owed to PHI.

 

Period

   Aggregate
Dividends
 

2011:

  

First Quarter

   $ —     

Second Quarter

     —     

Third Quarter

     —     

Fourth Quarter

     —     
  

 

 

 
   $ —     
  

 

 

 

2010:

  

First Quarter

   $ —     

Second Quarter

     —     

Third Quarter

     —     

Fourth Quarter

     35,000,000   
  

 

 

 
   $ 35,000,000   
  

 

 

 

Recent Sales of Unregistered Equity Securities

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Pepco Holdings

None.

Pepco

None.

DPL

None.

ACE

None.

 

42


Item 6. SELECTED FINANCIAL DATA

The following table sets forth selected historical consolidated data for PHI as of and for the years ended December 31, 2011, 2010, 2009, 2008, and 2007, derived from PHI’s audited financial statements.

PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS

 

     2011   2010     2009     2008     2007  
     (in millions, except per share data)   

Consolidated Operating Results

                       

Total Operating Revenue

   $ 5,920       $ 7,039       $ 7,402        $ 8,059        (h   $ 7,613     

Total Operating Expenses

     5,283     (a)     6,415       (c     6,754        (f     7,510          6,953        (j

Operating Income

     637         624         648          549          660     

Other Expenses

     228         474       (d     321          276          255     

Preferred Stock Dividend Requirements of Subsidiaries

     —            —            —             —             —        

Income from Continuing Operations Before Income Tax Expense

     409         150         327          273          405     

Income Tax Expense Related to Continuing Operations

     149     (b)     11       (e     104        (g     90        (h )(i)      141        (k

Net Income from Continuing Operations

     260         139         223          183          264     

(Loss) Income from Discontinued Operations, net of Income Taxes

     (3 )       (107 )       12          117          70     

Net Income

     257         32         235          300          334     

Earnings Available for Common Stock

     257         32         235          300          334     

Common Stock Information

                       

Basic Earnings Per Share of Common Stock from Continuing Operations

   $ 1.15       $ 0.62       $ 1.01        $ 0.90        $ 1.36     

Basic (Loss) Earnings Per Share of Common Stock from Discontinued Operations

     (0.01 )       (0.48 )       0.05          0.57          0.36     

Basic Earnings Per Share of Common Stock

     1.14         0.14         1.06          1.47          1.72     

Diluted Earnings Per Share of Common Stock from Continuing Operations

     1.15         0.62         1.01          0.90          1.36     

Diluted (Loss) Earnings Per Share of Common Stock from Discontinued Operations

     (0.01 )       (0.48 )       0.05          0.57          0.36     

Diluted Earnings Per Share of Common Stock

     1.14         0.14         1.06          1.47          1.72     

Cash Dividends Per Share of Common Stock

     1.08         1.08         1.08          1.08          1.04     

Year-End Stock Price

     20.30         18.25         16.85          17.76          29.33     

Net Book Value Per Common Share

     19.05         18.79         19.15          19.14          20.04     

Weighted Average Shares Outstanding

     226         224         221          204          194     

Other Information

                       

Investment in Property, Plant and Equipment

   $ 12,855       $ 12,120       $ 11,431        $ 10,860        $ 10,392     

Net Investment in Property, Plant and Equipment

     8,220         7,673         7,241          6,874          6,552     

Total Assets

     14,910         14,480         15,779          16,133          15,111     

Capitalization

                       

Short-term Debt

   $ 732       $ 534       $ 530        $ 465        $ 289     

Long-term Debt

     3,794         3,629         4,470          4,859          4,175     

Current Portion of Long-Term Debt and Project Funding

     112         75         536          85          332     

Transition Bonds issued by ACE Funding

     295         332         368          401          434     

Capital Lease Obligations due within one year

     8         8         7          6          6     

Capital Lease Obligations

     78         86         92          99          105     

Long-Term Project Funding

     13         15         17          19          21     

Non-controlling Interest

     —            6         6          6          6     

Common Shareholders’ Equity

     4,336         4,230         4,256          4,190          4,018     
  

 

 

     

 

 

     

 

 

      

 

 

      

 

 

    

Total Capitalization

   $ 9,368       $ 8,915       $ 10,282        $ 10,130        $ 9,386     
  

 

 

     

 

 

     

 

 

      

 

 

      

 

 

    

 

(a) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of certain cross-border energy leases held in trust.
(b) Includes tax benefits of $14 million primarily associated with an interest benefit related to federal tax liabilities and a $22 million reversal of previously recognized tax benefits associated with the early termination of cross-border energy leases held in trust.
(c) Includes $30 million ($18 million after-tax) related to a restructuring charge and an $11 million ($6 million after-tax) charge related to the effects of Pepco divestiture-related claims.
(d) Includes a loss on extinguishment of debt of $189 million ($113 million after-tax).
(e) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions, $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt.
(f) Includes $40 million ($24 million after-tax) gain related to the effects of Pepco divestiture-related claims.
(g) Includes a $13 million state income tax benefit (after Federal tax) related to a change in the state income tax reporting for the disposition of certain assets in prior years and a benefit of $6 million related to additional analysis of current and deferred tax balances completed in 2009.
(h) Includes a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in Income Taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligation.
(i) Includes $18 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with the reversal of previously accrued interest payable resulting from the tentative settlement with the IRS on the mixed service cost issue and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries) and a benefit of $8 million (including a $3 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.
(j) Includes $33 million ($20 million after-tax) from settlement of Mirant bankruptcy claims.
(k) Includes $20 million ($18 million net of fees) benefit related to Maryland income tax settlement.

 

43


INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.

 

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information required by this item is contained herein, as follows:

 

Registrants

   Page No.

Pepco Holdings

   45

Pepco

   95

DPL

   105

ACE

   116

 

44


PEPCO HOLDINGS

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pepco Holdings, Inc.

General Overview

PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, PHI provides energy efficiency services primarily to government and institutional customers and is in the process of winding down its competitive electricity and natural gas retail supply business. Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, owns a portfolio of seven cross-border energy lease investments.

The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to the Power Delivery, Pepco Energy Services and Other Non-Regulated segments:

 

     December 31,  
     2011     2010     2009  

Percentage of Consolidated Operating Revenue

      

Power Delivery

     79     73     67

Pepco Energy Services

     21     27     32

Other Non-Regulated

             1

Percentage of Consolidated Operating Income

      

Power Delivery

     78     81     78

Pepco Energy Services

     5     11     14

Other Non-Regulated

     17     8     8

Percentage of Power Delivery Operating Revenue

      

Power Delivery Electric

     95     95     95

Power Delivery Gas

     5     5     5

Power Delivery

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas. Power Delivery represents a single operating segment for financial reporting purposes.

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that encompass its service territory. Each company is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission in each jurisdiction. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is SOS in Delaware, the District of Columbia and Maryland, and BGS in New Jersey. In this report, these supply service obligations are referred to generally as Default Electricity Supply.

Pepco, DPL and ACE are also responsible for the transmission of wholesale electricity into and across their service territories. The rates each company is permitted to charge for the wholesale transmission of electricity are regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

 

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The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions, energy prices and the impact of energy efficiency measures on customer usage of electricity.

In ACE and DPL’s Delaware service territories, results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and for customers of Pepco in the District of Columbia, revenue is not affected by season changes because a BSA was implemented for retail customers that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. With respect to customers subject to a BSA, changes in usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

The following are developments in some of the key initiatives of Power Delivery in 2011:

Reliability Enhancement and Emergency Restoration Improvement Plans

In 2010, PHI announced that Pepco had adopted and begun to implement comprehensive reliability enhancement plans in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

 

   

enhanced vegetation management;

 

   

the identification and upgrading of under-performing feeder lines;

 

   

the addition of new facilities to support load;

 

   

the installation of distribution automation systems on both the overhead and underground network system;

 

   

the rejuvenation and replacement of underground residential cables;

 

   

improvements to substation supply lines; and

 

   

selective undergrounding of portions of existing above ground primary feeder lines, where appropriate to improve reliability.

During 2011, Pepco invested $120 million in capital expenditures on these reliability enhancement activities.

In 2011, prior to the start of the summer storm season, PHI initiated a program to improve Pepco’s emergency restoration efforts that included, among other initiatives, an expansion and enhancement of customer service capabilities.

PHI has extended its reliability enhancement efforts to DPL and ACE. PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures in the section titled “Capital Resources and Liquidity — Capital Expenditures.”

 

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Blueprint for the Future

Each of PHI’s three utilities is participating in a PHI initiative referred to as “Blueprint for the Future.” The installation of smart meters (also known as AMI), a key initiative of Blueprint for the Future, is almost complete for DPL electric customers in Delaware, with meter activation expected to be completed in the first quarter of 2012. Meter installation is still underway for Pepco customers in both the District of Columbia and Maryland, with installation of residential meters expected to be complete in the first and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of a return on the deferred costs. Thus, these costs will be recovered through base rates in the future. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors.

Approval of AMI is still pending for electric customers in DPL’s Maryland jurisdiction, and has been deferred in New Jersey.

In 2011, the DPSC approved DPL’s request to implement dynamic pricing for its Delaware customers. Implementation for customers will be phased in between 2012 and 2014. Dynamic pricing has been approved in concept, with phase-in for residential customers beginning in 2012 for Pepco customers in Maryland. Customers in Pepco’s District of Columbia jurisdiction have proposals pending with proposed phase-in for residential customers anticipated to begin in 2012. Dynamic pricing has been approved in concept pending AMI deployment authorization for DPL’s Maryland customers and has been deferred for ACE’s customers in New Jersey.

Regulatory Lag

An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and their operating expenses are outpacing revenue growth. PHI is continuing to seek cost recovery and tracking mechanisms from applicable public service commissions to reduce the effects of regulatory lag.

Pepco Energy Services

Pepco Energy Services is engaged in the following businesses:

 

   

providing energy efficiency services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants.

 

   

providing high voltage electric construction and maintenance services to customers throughout the United States and low voltage electric construction and maintenance services and streetlight construction and asset management services to utilities, municipalities and other customers in the Washington, D.C. area.

 

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Pepco Energy Services also has been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the U.S., as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind-down the retail energy supply component of the Pepco Energy Services business. The decision was made after considering, among other factors, the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments.

To effectuate the wind-down, Pepco Energy Services will continue to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but will not be entering into any new retail energy supply contracts. Operating revenues related to the retail energy supply business for the years ended December 31, 2011, 2010 and 2009 were $0.9 billion, $1.6 billion and $2.3 billion, respectively, and operating income for the same periods was $11 million, $59 million and $88 million, respectively.

PHI expects the operating results of the retail energy supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to be profitable in 2012, based on its existing retail contracts and its corresponding portfolio of wholesale hedges, with immaterial losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.

In connection with the operation of the retail energy supply business, as of December 31, 2011 and 2010, Pepco Energy Services had collateral pledged to counterparties primarily for the instruments it uses to hedge commodity price risk of approximately $113 million and $230 million, respectively. The collateral pledged as of December 31, 2011, included $1 million in the form of letters of credit and $112 million posted in cash. Pepco Energy Services estimates that at current market prices, with the wind-down of the retail energy supply business, an aggregate of 80% of the collateral will no longer need to be pledged by December 31, 2012, and substantially all collateral will no longer need to be pledged by June 1, 2014.

As a result of the decision to wind-down the retail energy supply business, Pepco Energy Services in the fourth quarter of 2009 recorded (i) a $4 million pre-tax impairment charge reflecting the write off of all goodwill allocated to the business and (ii) a pre-tax charge of less than $1 million related to employee severance.

Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail energy supply business.

Other Non-Regulated

Through its subsidiary PCI, PHI maintains a portfolio of cross-border energy lease investments with a book value at December 31, 2011 of approximately $1.3 billion. This activity constitutes a third operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (17), “Commitments and Contingencies—PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

Discontinued Operations

On April 20, 2010, the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine for $1.64 billion. The disposition of all of Conectiv Energy’s remaining assets and businesses not

 

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included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been substantially completed. The operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s consolidated financial statements for each of the years ended December 31, 2011, 2010 and 2009, and the business is no longer being treated as a separate segment for financial reporting purposes. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

Earnings Overview

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

PHI’s net income from continuing operations for the year ended December 31, 2011 was $260 million, or $1.15 per share, compared to $139 million, or $0.62 per share, for the year ended December 31, 2010.

Net income from continuing operations for the year ended December 31, 2010, included the charges set forth below in the business segments noted which are presented net of federal and state income taxes (assuming a composite tax rate of approximately 40%) and are in millions of dollars:

 

Debt extinguishment costs including treasury lock hedge (Corporate and Other)

   $  113   

Restructuring charge (All segments)

   $ 18   

Effects of Pepco divestiture-related claims (Power Delivery)

   $ 6   

Excluding these items, net income from continuing operations would have been $276 million, or $1.24 per share, for the year ended December 31, 2010. PHI discloses net income from continuing operations and related per share data excluding these items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with GAAP.

PHI’s net loss from discontinued operations for the year ended December 31, 2011 was $3 million, or $0.01 per share, compared to a net loss of $107 million, or $0.48 per share, for the year ended December 31, 2010.

PHI’s net income (loss) for the years ended December 31, 2011 and 2010, by operating segment, is set forth in the table below (in millions of dollars):

 

     2011     2010     Change  

Power Delivery

   $ 210     $ 206     $ 4  

Pepco Energy Services

     24       36       (12

Other Non-Regulated

     35       25       10  

Corporate and Other

     (9     (128     119  
  

 

 

   

 

 

   

 

 

 

Net Income from Continuing Operations

     260       139       121  

Discontinued Operations

     (3     (107     104  
  

 

 

   

 

 

   

 

 

 

Total PHI Net Income

   $ 257     $ 32     $ 225  
  

 

 

   

 

 

   

 

 

 

 

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PEPCO HOLDINGS

 

Discussion of Operating Segment Net Income Variances:

Power Delivery’s $4 million increase in earnings was primarily due to the following:

 

   

$23 million increase from higher distribution revenue primarily due to Regulated T&D Electric and Regulated Gas distribution rate increases.

 

   

$18 million increase associated with higher Default Electricity Supply margins, primarily resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing SOS in the District of Columbia, and adjustments to Pepco and DPL operating and maintenance expenses for providing SOS.

 

   

$17 million increase from higher transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011, related to increases in transmission plant investment.

 

   

$17 million increase due to a restructuring charge related to severance, pension and health and welfare benefits for employee terminations, associated with the reorganization of PHI in 2010.

 

   

$6 million increase due to an order by the DCPSC in 2010 associated with the effects of Pepco divestiture-related claims.

 

   

$56 million decrease due to higher operating and maintenance expenses primarily from increased system preventative maintenance and reliability activities.

 

   

$10 million decrease in distribution revenues due to lower usage, including the effect of milder weather.

 

   

$8 million decrease due to higher depreciation expense.

Pepco Energy Services’ $12 million decrease in earnings was primarily due to mark-to-market losses of $18 million in 2011 on derivative contracts, lower earnings as a result of the ongoing wind-down of the retail energy supply business and lower capacity revenues from the generating facilities, partially offset by higher operating income from the energy services business.

Other Non-Regulated’s $10 million increase in earnings was primarily due to favorable income tax adjustments and the gain on the early termination of certain cross-border energy leases, partially offset by lower financial investment portfolio activity (as further discussed in Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (12), “Income Taxes,” to the consolidated financial statements of PHI.

Corporate and Other’s $119 million decrease in loss was primarily due to the unfavorable impact of debt extinguishment costs in 2010 and lower interest expense in 2011 as a result of the reduction in outstanding debt due to the retirement of debt with the Conectiv Energy sale proceeds, partially offset by favorable income tax adjustments in 2010 from the release of certain deferred tax valuation allowances related to state net operating losses.

The $104 million decrease in the net loss from discontinued operations was primarily due to the 2010 write-down associated with the sale of the wholesale power generation business to Calpine and unrealized losses on derivative instruments no longer qualifying for cash flow hedge accounting, partially offset by gains in the 2010 period from sales of load service supply contracts.

 

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Consolidated Results of Operations

The following results of operations discussion compares the year ended December 31, 2011, to the year ended December 31, 2010. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

A detail of the components of PHI’s consolidated operating revenue is as follows:

 

     2011     2010     Change  

Power Delivery

   $ 4,650     $ 5,114     $ (464 )

Pepco Energy Services

     1,238       1,883       (645 )

Other Non-Regulated

     48       54       (6 )

Corporate and Other

     (16 )     (12 )     (4 )
  

 

 

   

 

 

   

 

 

 

Total Operating Revenue

   $ 5,920     $ 7,039     $ (1,119
  

 

 

   

 

 

   

 

 

 

Power Delivery Business

The following table categorizes Power Delivery’s operating revenue by type of revenue.

 

     2011      2010      Change  

Regulated T&D Electric Revenue

   $ 1,891      $ 1,858      $ 33  

Default Electricity Supply Revenue

     2,462        2,951        (489 )

Other Electric Revenue

     67        68        (1 )
  

 

 

    

 

 

    

 

 

 

Total Electric Operating Revenue

     4,420        4,877        (457 )
  

 

 

    

 

 

    

 

 

 

Regulated Gas Revenue

     183        191        (8 )

Other Gas Revenue

     47        46        1  
  

 

 

    

 

 

    

 

 

 

Total Gas Operating Revenue

     230        237        (7 )
  

 

 

    

 

 

    

 

 

 

Total Power Delivery Operating Revenue

   $ 4,650      $ 5,114      $ (464 )
  

 

 

    

 

 

    

 

 

 

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. Depending on the jurisdiction, Default Electricity Supply is also known as SOS or BGS. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

 

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Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

 

     2011      2010      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 683      $ 683      $ —     

Commercial and industrial

     884        883        1  

Transmission and other

     324        292        32  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 1,891      $ 1,858      $ 33  
  

 

 

    

 

 

    

 

 

 

 

     2011      2010      Change  

Regulated T&D Electric Sales (Gigawatt hours(GWh))

        

Residential

     17,728         18,398         (670

Commercial and industrial

     31,282         32,045         (763 )

Transmission and other

     256         260         (4 )
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     49,266        50,703        (1,437 )
  

 

 

    

 

 

    

 

 

 

 

     2011      2010      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     1,636        1,635        1  

Commercial and industrial

     198        198        —     

Transmission and other

     2        2        —     
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     1,836        1,835        1  
  

 

 

    

 

 

    

 

 

 

The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base.

 

   

Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

 

   

Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $33 million primarily due to:

 

   

An increase of $32 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Maryland effective July 2011, and in Delaware effective February 2011; and ACE in New Jersey effective June 2010).

 

   

An increase of $32 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.

 

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PEPCO HOLDINGS

 

 

   

An increase of $11 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

 

   

An increase of $7 million primarily due to Pepco customer growth in 2011, primarily in the residential class.

 

   

An increase of $2 million due to the implementation of the EmPower Maryland (a demand side management program) surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $30 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).

 

   

A decrease of $11 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

 

   

A decrease of $10 million due to lower non-weather related average customer usage.

Default Electricity Supply

 

     2011      2010      Change  

Default Electricity Supply Revenue

        

Residential

   $  1,668       $ 2,022       $ (354 )

Commercial and industrial

     642        733        (91 )

Other

     152        196        (44 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 2,462       $ 2,951       $ (489
  

 

 

    

 

 

    

 

 

 

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.

 

     2011      2010      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     15,545        17,385        (1,840 )

Commercial and industrial

     6,168        7,034        (866 )

Other

     73        93        (20 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     21,786        24,512         (2,726 )
  

 

 

    

 

 

    

 

 

 

 

     2011      2010      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     1,432        1,525        (93 )

Commercial and industrial

     137        148        (11 )

Other

     —           1        (1 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     1,569        1,674        (105 )
  

 

 

    

 

 

    

 

 

 

 

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PEPCO HOLDINGS

 

Default Electricity Supply Revenue decreased by $489 million primarily due to:

 

   

A decrease of $200 million due to lower sales, primarily as a result of customer migration to competitive suppliers.

 

   

A net decrease of $153 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.

 

   

A decrease of $94 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

 

   

A decrease of $40 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.

 

   

A decrease of $3 million due to a decrease in revenue from Transmission Enhancement Credits.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for providers of Default Electricity Supply was shortened from a monthly to a weekly period, effective in June 2009.

Total Default Electricity Supply Revenue for the 2011 period includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million decrease in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2011 as compared to the corresponding period in 2010. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

 

     2011      2010      Change  

Regulated Gas Revenue

        

Residential

   $ 113      $ 118      $ (5 )

Commercial and industrial

     61        65        (4 )

Transportation and other

     9        8        1  
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Revenue

   $ 183      $ 191      $ (8 )
  

 

 

    

 

 

    

 

 

 

 

     2011      2010      Change  

Regulated Gas Sales (billion cubic feet)

        

Residential

     7        8        (1 )

Commercial and industrial

     5        5        —     

Transportation and other

     7        6        1  
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Sales

     19        19        —     
  

 

 

    

 

 

    

 

 

 

 

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PEPCO HOLDINGS

 

 

     2011      2010      Change  

Regulated Gas Customers (in thousands)

        

Residential

     115        114        1   

Commercial and industrial

     9        9        —    

Transportation and other

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Customers

     124        123        1  
  

 

 

    

 

 

    

 

 

 

DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth.

 

   

Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.

 

   

Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue decreased by $8 million primarily due to:

 

   

A decrease of $17 million due to lower non-weather related average customer usage.

The decrease was partially offset by:

 

   

An increase of $6 million due to higher sales primarily as a result of colder weather during the winter of 2011 as compared to the winter of 2010.

 

   

An increase of $2 million due to a distribution rate increase effective February 2011.

 

   

An increase of $2 million due to customer growth in 2011.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $645 million primarily due to:

 

   

A decrease of $672 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail energy supply business.

 

   

A decrease of $33 million due to lower generation and capacity revenues at the generating facilities.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $61 million due to increased energy services activities.

 

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Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

 

     2011     2010     Change  

Power Delivery

   $ 2,490     $ 3,086     $ (596 )

Pepco Energy Services

     1,106       1,691       (585 )

Corporate and Other

     (2 )     (6 )     4  
  

 

 

   

 

 

   

 

 

 

Total

   $ 3,594     $ 4,771     $ (1,177 )
  

 

 

   

 

 

   

 

 

 

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $596 million primarily due to:

 

   

A decrease of $300 million due to lower average electricity costs under Default Electricity Supply contracts.

 

   

A decrease of $221 million primarily due to customer migration to competitive suppliers.

 

   

A decrease of $83 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.

 

   

A decrease of $16 million in the cost of gas purchases for on-system sales as a result of lower average gas prices, lower volumes purchased and lower withdrawals from storage.

 

   

A decrease of $11 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $18 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.

 

   

An increase of $18 million in deferred natural gas expense as a result of a higher rate of recovery of natural gas supply costs.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $585 million primarily due to:

 

   

A decrease of $621 million due to lower volumes of electricity and gas purchased to serve decreased retail supply sales volume as a result of the ongoing wind-down of the retail energy supply business.

 

   

A decrease of $10 million due to lower fuel usage associated with the generating facilities.

 

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The aggregate amount of these decreases was partially offset by:

 

   

An increase of $46 million due to increased energy services activities.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

 

     2011     2010     Change  

Power Delivery

   $ 884     $ 809     $ 75  

Pepco Energy Services

     81       95       (14 )

Other Non-Regulated

     6       4       2  

Corporate and Other

     (57 )     (24 )     (33 )
  

 

 

   

 

 

   

 

 

 

Total

   $ 914     $ 884     $ 30  
  

 

 

   

 

 

   

 

 

 

Other Operation and Maintenance expense for Power Delivery increased by $75 million primarily due to:

 

   

An increase of $38 million associated with higher tree trimming and preventative maintenance costs.

 

   

An increase of $13 million primarily due to higher 2011 DCPSC rate case costs and reliability audit expenses and due to 2010 Pepco adjustments for the deferral of (i) February 2010 severe winter storm costs of $5 million and (ii) distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, allowing for the recovery of the costs.

 

   

An increase of $9 million in employee-related costs, primarily benefit expenses.

 

   

An increase of $8 million primarily due to Pepco’s emergency restoration improvement project and reliability improvement costs.

 

   

An increase of $8 million in customer support service and system support costs.

 

   

An increase of $6 million in communication costs.

 

   

An increase of $5 million in corporate cost allocations, primarily due to higher contractor and outside legal counsel fees.

 

   

An increase of $5 million related to New Jersey Societal Benefit Program costs that are deferred and recoverable.

 

   

An increase of $4 million in emergency restoration costs. The increase is primarily related to significant incremental costs incurred for repair work following Hurricane Irene in August 2011. Costs incurred for repair work were $28 million, of which $22 million was deferred as regulatory assets to reflect the probable recovery of these storm costs in certain jurisdictions, and the remaining $6 million was charged to other operation and maintenance expense. Approximately $4 million of these total incremental storm costs have been estimated for the cost of restoration services provided by outside contractors. Since the invoices for such services had not been received at December 31, 2011, actual invoices may vary from these estimates. PHI’s utility subsidiaries currently plan to seek recovery of the incremental Hurricane Irene costs in each of their various jurisdictions in pending or planned distribution rate case filings.

 

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PEPCO HOLDINGS

 

 

   

An increase of $3 million in costs related to customer requested and mutual assistance work (primarily offset in other Electric T&D Revenue).

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $17 million resulting from adjustments recorded by PHI in 2011 associated with the accounting for DPL and Pepco Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital, uncollectible accounts, late fees and administrative costs.

 

   

A decrease of $15 million in environmental remediation costs.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $33 million to $426 million in 2011 from $393 million in 2010 primarily due to:

 

   

An increase of $16 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

 

   

An increase of $14 million due to utility plant additions.

 

   

An increase of $4 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

 

   

An increase of $1 million in amortization of software upgrades to Pepco’s Energy Management System.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $3 million primarily due to the higher 2010 recognition of asset retirement obligations associated with Pepco Energy Services generating facilities scheduled for deactivation in May 2012.

Other Taxes

Other Taxes increased by $17 million to $451 million in 2011 from $434 million in 2010. The increase was primarily due to:

 

   

An increase of $16 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

 

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An increase of $5 million due to an adjustment in the third quarter of 2010 to correct certain errors related to other taxes.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $5 million in the Energy Assistance Trust Fund surcharge primarily due to rate decreases effective October 2010 (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Gain on Early Termination of Finance Leases Held in Trust

PHI’s operating expenses include a $39 million pre-tax gain for the year ended December 31, 2011 associated with the early termination of several lease investments included in its cross-border energy lease portfolio. For a further discussion of this transaction, see Note (8), “Leasing Activities,” to the consolidated financial statements of PHI.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over- or under-recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over- or under-recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $45 million, to an expense reduction of $63 million in 2011 as compared to an expense reduction of $108 million in 2010, primarily due to higher Default Electricity Supply Revenue rates and lower electricity supply costs.

Effects of Pepco Divestiture-Related Claims

The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010.

Other Income (Expenses)

Other Expenses (which are net of Other Income) decreased by $246 million primarily due to the loss on extinguishment of debt that was recorded in 2010 and lower interest expense in 2011 resulting from the reduction in outstanding long term debt in 2010 with the proceeds from the Conectiv Energy sale.

 

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PEPCO HOLDINGS

 

Loss on Extinguishment of Debt

In 2010, PHI purchased or redeemed senior notes in the aggregate principal amount of $1,194 million. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $189 million in 2010, $174 million of which was attributable to the retirement of the debt and $15 million of which related to the acceleration of losses on treasury rate lock transactions associated with the retired debt. For a further discussion of these transactions, see Note (11), “Debt,” to the consolidated financial statements of PHI.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2011 and 2010 were 36.4% and 7.3%, respectively. The increase in the effective tax rate was primarily due to the recognition of certain tax benefits in 2010 that did not recur in 2011 and PHI’s early termination of its interest in certain cross-border energy leases in 2011.

In 2010, certain PHI subsidiaries were restructured which subjected PHI to state income taxes in new jurisdictions and resulted in current state tax benefits that were recorded in 2010 and did not recur in 2011. Specifically, on April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing a valuation allowance on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred tax benefits.

In addition, in November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010.

In 2011, a $17 million (after-tax) income tax benefit was recorded in the first quarter when PHI reached a settlement with the IRS related to the calculation of interest due as a result of the November 2010 audit settlement. This benefit was more than offset during the second quarter of 2011, when PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated term. As a result of the early terminations, PHI reversed $22 million of previously recognized federal tax benefits associated with those leases that will not be realized.

Discontinued Operations

For the year ended December 31, 2011, the $3 million loss from discontinued operations, net of income taxes, consists of an after-tax loss from operations of $1 million and after-tax net loss of $2 million from dispositions of assets and businesses.

 

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PEPCO HOLDINGS

 

The following results of operations discussion is for the year ended December 31, 2010, compared to the year ended December 31, 2009. All amounts in the tables (except sales and customers) are in millions of dollars.

Continuing Operations

Operating Revenue

A detail of the components of PHI’s consolidated operating revenue is as follows:

 

     2010     2009     Change  

Power Delivery

   $ 5,114     $ 4,980     $ 134  

Pepco Energy Services

     1,883       2,383       (500

Other Non-Regulated

     54       51       3  

Corporate and Other

     (12 )     (12 )     —     
  

 

 

   

 

 

   

 

 

 

Total Operating Revenue

   $ 7,039     $ 7,402     $ (363
  

 

 

   

 

 

   

 

 

 

Power Delivery Business

The following table categorizes Power Delivery’s operating revenue by type of revenue.

 

     2010      2009      Change  

Regulated T&D Electric Revenue

   $ 1,858      $ 1,653      $ 205  

Default Electricity Supply Revenue

     2,951        2,990        (39 )

Other Electric Revenue

     68        69        (1 )
  

 

 

    

 

 

    

 

 

 

Total Electric Operating Revenue

     4,877        4,712        165  
  

 

 

    

 

 

    

 

 

 

Regulated Gas Revenue

     191        228        (37 )

Other Gas Revenue

     46        40        6  
  

 

 

    

 

 

    

 

 

 

Total Gas Operating Revenue

     237        268        (31 )
  

 

 

    

 

 

    

 

 

 

Total Power Delivery Operating Revenue

   $ 5,114      $ 4,980      $ 134  
  

 

 

    

 

 

    

 

 

 

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. Depending on the jurisdiction, Default Electricity Supply is also known as SOS or BGS. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

 

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Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Regulated T&D Electric

 

     2010      2009      Change  

Regulated T&D Electric Revenue

        

Residential

   $ 683      $ 596      $ 87  

Commercial and industrial

     883        804        79  

Transmission and other

     292        253        39  
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Revenue

   $ 1,858      $ 1,653      $ 205  
  

 

 

    

 

 

    

 

 

 

 

     2010      2009      Change  

Regulated T&D Electric Sales (GWh)

        

Residential

     18,398         16,871         1,527   

Commercial and industrial

     32,045         31,570         475  

Transmission and other

     260         261         (1 )
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Sales

     50,703        48,702        2,001  
  

 

 

    

 

 

    

 

 

 

 

     2010      2009      Change  

Regulated T&D Electric Customers (in thousands)

        

Residential

     1,635        1,623        12  

Commercial and industrial

     198        198        —     

Transmission and other

     2        2        —     
  

 

 

    

 

 

    

 

 

 

Total Regulated T&D Electric Customers

     1,835        1,823        12  
  

 

 

    

 

 

    

 

 

 

The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base.

 

   

Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.

 

   

Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.

Regulated T&D Electric Revenue increased by $205 million primarily due to:

 

   

An increase of $61 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

 

   

An increase of $46 million due to distribution rate increases (Pepco in the District of Columbia effective November 2009 and March 2010; DPL in Maryland effective December 2009; DPL in Delaware effective April 2010; and ACE in New Jersey effective June 2010).

 

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PEPCO HOLDINGS

 

 

   

An increase of $37 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 related to an increase in transmission plant investment.

 

   

An increase of $26 million due to higher revenue in the District of Columbia, Delaware and New Jersey service territories, primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009. Distribution revenue in Maryland was decoupled from consumption in 2010 and 2009, and therefore, the weather in this jurisdiction does not affect the period-to-period comparison. The BSA was not implemented in the District of Columbia until November 2009, and therefore, the period-to-period comparison is affected by weather.

 

   

An increase of $15 million due to the implementation of the EmPower Maryland surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).

 

   

An increase of $9 million due to higher non-weather related average customer usage.

 

   

An increase of $8 million due to Pepco customer growth of 1% in 2010, primarily in the residential class.

Default Electricity Supply

 

     2010      2009      Change  

Default Electricity Supply Revenue

        

Residential

   $ 2,022       $ 1,915       $ 107  

Commercial and industrial

     733        915        (182 )

Other

     196        160        36  
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Revenue

   $ 2,951       $ 2,990       $ (39 )
  

 

 

    

 

 

    

 

 

 

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from Transmission Enhancement Credits.

 

     2010      2009      Change  

Default Electricity Supply Sales (GWh)

        

Residential

     17,385        16,274        1,111  

Commercial and industrial

     7,034        8,470        (1,436 )

Other

     93        101        (8 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Sales

     24,512         24,845         (333 )
  

 

 

    

 

 

    

 

 

 

 

     2010      2009      Change  

Default Electricity Supply Customers (in thousands)

        

Residential

     1,525        1,572        (47 )

Commercial and industrial

     148        159        (11 )

Other

     1        2        (1 )
  

 

 

    

 

 

    

 

 

 

Total Default Electricity Supply Customers

     1,674        1,733        (59 )
  

 

 

    

 

 

    

 

 

 

Default Electricity Supply Revenue decreased by $39 million primarily due to:

 

   

A decrease of $200 million due to lower sales, primarily as a result of commercial customer migration to competitive suppliers.

 

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PEPCO HOLDINGS

 

 

   

A decrease of $59 million as a result of lower Default Electricity Supply rates.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $144 million due to higher sales primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009.

 

   

An increase of $40 million due to higher non-weather related average customer usage.

 

   

An increase of $29 million in wholesale energy and capacity revenues primarily due to higher market prices for the sale of electricity and capacity purchased from NUGs.

 

   

An increase of $8 million due to an increase in revenue from transmission enhancement credits.

Total Default Electricity Supply Revenue for the 2010 period includes an increase of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million increase in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2010 as compared to the corresponding period in 2009. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.

Regulated Gas

 

     2010      2009      Change  

Regulated Gas Revenue

        

Residential

   $ 118      $ 139      $ (21 )

Commercial and industrial

     65        81        (16 )

Transportation and other

     8        8        —     
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Revenue

   $ 191      $ 228      $ (37 )
  

 

 

    

 

 

    

 

 

 
     2010      2009      Change  

Regulated Gas Sales (billion cubic feet)

        

Residential

     8        8        —     

Commercial and industrial

     5        5        —     

Transportation and other

     6        6        —     
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Sales

     19        19        —     
  

 

 

    

 

 

    

 

 

 
     2010      2009      Change  

Regulated Gas Customers (in thousands)

        

Residential

     114        113        1  

Commercial and industrial

     9        10        (1 )

Transportation and other

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total Regulated Gas Customers

     123        123        —     
  

 

 

    

 

 

    

 

 

 

DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth.

 

   

Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.

 

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PEPCO HOLDINGS

 

 

   

Industrial activity in the region includes chemical and pharmaceutical.

Regulated Gas Revenue decreased by $37 million primarily due to:

 

   

A decrease of $22 million due to Gas Cost Rate (GCR) decreases effective March 2009 and November 2009.

 

   

A decrease of $14 million due to lower sales as a result of milder weather during the winter months of 2010 as compared to 2009.

Other Gas Revenue

Other Gas Revenue increased by $6 million primarily due to higher revenue from off-system sales resulting from:

 

   

An increase of $4 million due to higher demand from electric generators and natural gas marketers.

 

   

An increase of $2 million due to higher market prices.

Pepco Energy Services

Pepco Energy Services’ operating revenue decreased $500 million primarily due to:

 

   

A decrease of $651 million due to lower retail electricity sales volume due to the ongoing wind-down of the retail energy supply business.

The decrease is partially offset by:

 

   

An increase of $100 million due to higher electricity generation output as the result of completed transmission construction projects and warmer than normal weather, and lower RPM charges associated with the generating facilities.

 

   

An increase of $38 million due to increased energy services activities.

 

   

An increase of $13 million due to a higher retail natural gas supply load as the result of 2009 customer acquisitions, partially offset by lower retail natural gas prices.

Operating Expenses

Fuel and Purchased Energy and Other Services Cost of Sales

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

 

     2010     2009     Change  

Power Delivery

   $ 3,086     $ 3,243     $ (157 )

Pepco Energy Services

     1,691       2,179       (488 )

Corporate and Other

     (6 )     (7 )     1  
  

 

 

   

 

 

   

 

 

 

Total

   $ 4,771     $ 5,415     $ (644 )
  

 

 

   

 

 

   

 

 

 

 

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PEPCO HOLDINGS

 

Power Delivery Business

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $157 million primarily due to:

 

   

A decrease of $197 million primarily due to commercial customer migration to competitive suppliers.

 

   

A decrease of $59 million in deferred electricity expense primarily due to lower Default Electricity Supply Revenue rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.

 

   

A decrease of $17 million in deferred natural gas expense as a result of a lower rate of recovery of natural gas supply costs.

 

   

A decrease of $14 million due to lower average electricity costs under Default Electricity Supply contracts.

 

   

A decrease of $12 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.

The aggregate amount of these decreases was partially offset by:

 

   

An increase of $143 million due to higher electricity sales primarily as a result of warmer weather during the spring and summer months of 2010 as compared to 2009.

Pepco Energy Services

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $488 million primarily due to:

 

   

A decrease of $571 million due to lower volumes of electricity purchased to serve decreased retail customer load as a result of the ongoing wind-down of the retail energy supply business.

The decrease is partially offset by:

 

   

An increase of $42 million due to increased energy services activities.

 

   

An increase of $27 million due to higher fuel usage associated with the generating facilities.

 

   

An increase of $15 million due to a higher retail natural gas supply load as the result of 2009 customer acquisitions, partially offset by lower wholesale natural gas prices.

Other Operation and Maintenance

A detail of PHI’s Other Operation and Maintenance expense is as follows:

 

     2010     2009     Change  

Power Delivery

   $ 809     $ 752     $ 57  

Pepco Energy Services

     95       90       5  

Other Non-Regulated

     4       2       2  

Corporate and Other

     (24 )     (25 )     1  
  

 

 

   

 

 

   

 

 

 

Total

   $ 884     $ 819     $ 65  
  

 

 

   

 

 

   

 

 

 

 

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PEPCO HOLDINGS

 

Other Operation and Maintenance expense for Power Delivery increased by $57 million; however, excluding an increase of $11 million primarily related to bad debt and administrative expenses that are deferred and recoverable in Default Electricity Supply Revenue, Other Operation and Maintenance expense increased by $46 million. The $46 million increase was primarily due to:

 

   

An increase of $33 million in emergency restoration costs primarily due to severe storms in February, July and August 2010.

 

   

An increase of $17 million in estimated environmental remediation costs.

 

   

An increase of $14 million primarily due to higher tree trimming and preventative maintenance costs.

 

   

An increase of $5 million primarily due to system support and customer support service costs.

The aggregate amount of these increases was partially offset by:

 

   

A decrease of $17 million in employee-related costs, primarily due to lower pension and other postretirement benefit (OPEB) expenses.

 

   

A decrease of $9 million primarily due to Pepco deferral of (i) February 2010 severe winter storm costs, and (ii) distribution rate case costs, which in each case originally had been charged to Other Operation and Maintenance expense. These deferrals were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, respectively, authorizing the establishment of regulatory assets for the recovery of these costs.

Other Operation and Maintenance expense for Pepco Energy Services increased $5 million, primarily due to increases of $8 million in power plant operating costs and $3 million due to the repair cost of a distribution system pipe leak; partially offset by a decrease of $5 million in bad debt expense.

Restructuring Charge

As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.

Depreciation and Amortization

Depreciation and Amortization expense increased by $44 million to $393 million in 2010 from $349 million in 2009 primarily due to:

 

   

An increase of $12 million in amortization of regulatory assets primarily due to the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

 

   

An increase of $10 million due to utility plant additions.

 

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An increase of $8 million due to higher amortization by ACE of stranded costs, primarily the result of higher revenue due to increases in sales (partially offset in Default Electricity Supply Revenue).

 

   

An increase of $4 million primarily due to the recognition of asset retirement obligations associated with Pepco Energy Services generating facilities scheduled for deactivation in May 2012.

 

   

An increase of $2 million in the amortization of demand-side management program deferred expenses.

Other Taxes

Other Taxes increased by $66 million to $434 million in 2010 from $368 million in 2009. The increase was primarily due to increased pass-throughs experienced by Power Delivery (which are substantially offset by a corresponding increase in Regulated T&D Electric Revenue) primarily resulting from utility tax rate increases imposed by Montgomery County, Maryland.

Deferred Electric Service Costs

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over- or under-recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over- or under-recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $53 million, to an expense reduction of $108 million in 2010 as compared to an expense reduction of $161 million in 2009, primarily due to an increase in deferred electricity expense as a result of lower electricity supply costs and higher Default Electricity Supply Revenue rates.

Effects of Pepco Divestiture-Related Claims

District of Columbia Divestiture Case

The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco was required to distribute to customers by approximately $11 million. PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010.

Settlement of Mirant Bankruptcy Claims

In March 2009, the DCPSC approved an allocation between Pepco and its District of Columbia customers of the District of Columbia portion of the Mirant bankruptcy settlement proceeds remaining after the transfer of the power purchase agreement between Pepco and Panda-Brandywine, L.P. As a result, Pepco recorded a pre-tax gain of $14 million in the first quarter of 2009 reflecting the District of Columbia proceeds retained by Pepco. In July 2009, the MPSC approved an allocation between Pepco and its Maryland customers of the Maryland portion of the Mirant bankruptcy settlement proceeds. As a result, Pepco recorded a pre-tax gain of $26 million in the third quarter of 2009 reflecting the Maryland proceeds retained by Pepco.

 

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Other Income (Expenses)

Other Expenses (which are net of Other Income) increased by $153 million primarily due to a $189 million loss on extinguishment of debt that was recorded in 2010 as further discussed below, partially offset by lower interest expense of $34 million.

Loss on Extinguishment of Debt

In 2010, PHI purchased or redeemed senior notes in the aggregate principal amount of $1,194 million. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $189 million in 2010, $174 million of which was attributable to the retirement of the debt and $15 million of which related to the acceleration of losses on treasury rate lock transactions associated with debt that was retired. For a further discussion of these transactions, see Note (11), “Debt,” to the consolidated financial statements of PHI.

Income Tax Expense

PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2010 and 2009 were 7.3% and 31.8%, respectively. The reduction in the effective tax rate is primarily due to two factors. The first is the recording of current state tax benefits resulting from the restructuring of certain PHI subsidiaries which subjected PHI to state income taxes in new jurisdictions. On April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing a valuation allowance on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred tax benefits.

The second factor is the reversal of accrued interest on uncertain and effectively settled tax positions resulting from final settlement with the IRS of certain open tax years. In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate has resulted in the reversal of $15 million of previously accrued estimated interest due to the IRS. This reversal has been recorded as an income tax benefit in 2010, and PHI recorded an additional tax benefit of $17 million (after-tax) in the second quarter of 2011 when the IRS finalized its calculation of the amount of interest due.

Discontinued Operations

For the year ended December 31, 2010, the $107 million loss from discontinued operations, net of income taxes, consists of after-tax income from operations of $6 million and after-tax net losses of $113 million from dispositions of assets and businesses.

Capital Resources and Liquidity

This section discusses PHI’s working capital, cash flow activity, capital requirements and other uses and sources of capital.

 

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Working Capital

At December 31, 2011, PHI’s current assets on a consolidated basis totaled $1.4 billion and its current liabilities totaled $1.9 billion, resulting in a working capital deficit of $422 million. PHI expects the working capital deficit at December 31, 2011 to be funded during 2012 in part through cash flow from operations. Additional working capital will be provided by anticipated reductions in collateral requirements due to the ongoing wind-down of the Pepco Energy Services retail energy supply business. At December 31, 2010, PHI’s current assets on a consolidated basis totaled $1.8 billion and its current liabilities totaled $1.8 billion. The decrease in working capital from December 31, 2010 to December 31, 2011 was primarily due to a decrease in prepayments of income taxes and an increase in short-term debt. Prepayments of income taxes have decreased in 2011 because certain net operating losses that were classified as current assets in 2010 were reclassified as long-term assets in 2011. Short-term debt increased to temporarily support higher spending by the utilities on infrastructure investments and reliability initiatives until permanent financing is obtained.

At December 31, 2011, PHI’s cash and current cash equivalents totaled $109 million, of which $87 million was invested in money market funds, and the balance was held as cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled $11 million. At December 31, 2010, PHI’s cash and current cash equivalents totaled $21 million, of which $1 million was reflected on the balance sheet in Conectiv Energy assets held for sale, and its current restricted cash equivalents totaled $11 million.

A detail of PHI’s short-term debt balance and its current maturities of long-term debt and project funding balance follows:

 

    

As of December 31, 2011

(millions of dollars)

        

Type

   PHI
Parent
     Pepco      DPL      ACE      ACE
Funding
     Pepco
Energy
Services
     PHI
Consolidated
 

Variable Rate Demand Bonds

   $ —         $ —         $ 105      $ 23      $ —         $ 18      $ 146  

Commercial Paper

     465        74        47        —           —           —           586  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Short-Term Debt

   $ 465      $ 74      $ 152      $ 23      $ —         $ 18      $ 732  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current Maturities of Long-Term Debt and Project Funding

   $ —         $ —         $ 66      $ —         $ 37      $ 9      $ 112  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

    

As of December 31, 2010

(millions of dollars)

        

Type

   PHI
Parent
     Pepco      DPL      ACE      ACE
Funding
     Pepco
Energy
Services
     PHI
Consolidated
 

Variable Rate Demand Bonds

   $ —         $ —         $ 105      $ 23      $ —         $ 18      $ 146  

Commercial Paper

     230        —           —           158        —           —           388  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Short-Term Debt

   $ 230      $ —         $ 105      $ 181      $ —         $ 18      $ 534  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Current Maturities of Long-Term Debt and Project Funding

   $ —         $ —         $ 35      $ —         $ 35      $ 5      $ 75  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Credit Facility

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016.

 

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The aggregate borrowing limit under the facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The initial credit sublimit for PHI is $750 million and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all financial covenants under this facility as of December 31, 2011.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of December 31, 2011, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively. In January 2012, the Board of Directors approved an increase in PHI’s maximum to $1.25 billion.

PHI, Pepco and DPL had $465 million, $74 million and $47 million, respectively, of commercial paper outstanding at December 31, 2011. ACE had no commercial paper outstanding at December 31, 2011. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2011 was 0.64%, 0.35%, 0.34% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2011 was eleven, two, two and six days, respectively.

 

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Cash and Credit Facility Available as of December 31, 2011

 

     Consolidated
PHI
     PHI Parent      Utility
Subsidiaries
 
     (millions of dollars)  

Credit Facility (Total Capacity)

   $ 1,500      $ 750      $ 750  

Less: Letters of Credit issued

     7        2        5  

Commercial Paper outstanding

     586        465        121  
  

 

 

    

 

 

    

 

 

 

Remaining Credit Facility Available

     907        283        624  

Cash Invested in Money Market Funds (a)

     87        —           87  
  

 

 

    

 

 

    

 

 

 

Total Cash and Credit Facility Available

   $ 994      $ 283      $ 711  
  

 

 

    

 

 

    

 

 

 

 

(a) Cash and cash equivalents reported on the balance sheet of $109 million includes $22 million of cash and uncollected funds.

Collateral Requirements of Pepco Energy Services

In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) assumed by novation, the electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts, and (ii) supplied electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any obligation to post collateral based on changes in electricity prices. The upfront fees incurred by Pepco Energy Services in 2009 in the amount of $25 million was amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of the novation. For the years ended December 31, 2011, 2010 and 2009, approximately $1 million $8 million and $16 million, respectively, of the fees have been amortized and reflected in interest expense.

In relation to the wind-down of its retail energy supply business, Pepco Energy Services in the ordinary course of business has entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.

Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit. As of December 31, 2011, Pepco Energy Services posted net cash collateral of $112 million and letters of credit of $1 million. At December 31, 2010, Pepco Energy Services posted net cash collateral of $117 million and letters of credit of $113 million.

At December 31, 2011 and 2010, the amount of cash, plus borrowing capacity under the primary credit facility available to meet the future liquidity needs of Pepco Energy Services totaled $283 million and $728 million, respectively.

Pension and Other Postretirement Benefit Plans

Based on the results of the 2011 actuarial valuation, PHI’s net periodic pension and OPEB costs were approximately $94 million in 2011 versus $116 million in 2010. The current estimate of benefit cost for 2012 is $103 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 30% of net periodic pension and OPEB costs are capitalized. PHI estimates that its net periodic pension and OPEB expense will be approximately $72 million in 2012, as compared to $66 million in 2011 and $81 million in 2010.

 

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Pension benefits are provided under the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006.

During 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions totaling $110 million to the PHI Retirement Plan, in the amounts of $40 million, $40 million and $30 million, respectively. In 2010, PHI Service Company made discretionary tax-deductible contributions totaling $100 million to the PHI Retirement Plan.

Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2011, 2010 and 2009. On January 31, 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which is expected to bring the PHI Retirement Plan assets to at least the funding target level for 2012 under the Pension Protection Act. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.

Effective July 1, 2011, PHI approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan were effective on or after July 1, 2011 and affect the retirement benefits payable to approximately 750 of PHI’s employees. All full-time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.

In the third quarter of 2011, PHI also approved a new, non-qualified Supplemental Executive Retirement Plan (SERP) which replaced PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.

In the fourth quarter of 2011, PHI approved an increase in the medical benefit limits for certain employees in its postretirement health care benefit plan to align the limits with those provided to other employees. The amendment affects approximately 1,400 employees, of which 400 are retirees and 1,000 are active union employees. The effective date of the plan modification was January 1, 2012.

The additional liabilities and expenses for the benefit plan modifications described above did not have a material impact on PHI’s overall consolidated financial condition, results of operations, or cash flows.

 

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Cash Flow Activity

PHI’s cash flows during 2011, 2010 and 2009 are summarized below:

 

     Cash Source (Use)  
     2011     2010     2009  
     (millions of dollars)  

Operating Activities

   $ 686     $ 813     $ 606  

Investing Activities

     (747     718       (860

Financing Activities

     149       (1,556 )     (84
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ 88     $ (25   $ (338
  

 

 

   

 

 

   

 

 

 

Operating Activities

Cash flows from operating activities during 2011, 2010 and 2009 are summarized below:

 

     Cash Source (Use)  
     2011     2010     2009  
     (millions of dollars)  

Net Income from continuing operations

   $ 260     $ 139     $ 223  

Non-cash adjustments to net income

     351       352       262  

Pension contributions

     (110 )     (100     (300

Changes in cash collateral related to derivative activities

     9       13       24  

Changes in other assets and liabilities

     134       161       294  

Changes in Conectiv Energy net assets held for sale

     42       248       103  
  

 

 

   

 

 

   

 

 

 

Net cash from operating activities

   $ 686     $ 813     $ 606  
  

 

 

   

 

 

   

 

 

 

Net cash from operating activities was $127 million lower for the year ended December 31, 2011, compared to the same period in 2010. The decrease was due primarily to a $206 million reduction in Conectiv Energy net assets held for sale as well as $10 million increase in pension contributions compared to 2010. A significant portion of the decline in Conectiv Energy assets held for sale was associated with the transfer of derivative instruments to a third party as further described in Note (20), “Discontinued Operations,” to the consolidated financial statements of PHI. Partially offsetting this decrease in operating cash flows was a $121 million increase in cash flows from continuing operations.

Net cash from operating activities was $207 million higher for the year ended December 31, 2010, compared to the same period in 2009. Portions of the increase are attributable to a 2010 decrease in pension plan contributions of $200 million compared to 2009 and a decrease in regulatory liabilities during 2010 that was the result of a lower rate of recovery by ACE of costs associated with energy and capacity purchased under the NUG contracts. Changes in cash from Conectiv Energy assets held for sale reflect a net decrease in Conectiv Energy assets and liabilities included in discontinued operations, including a decrease in collateral requirements as a result of the liquidation of derivative instruments.

 

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Investing Activities

Cash flows used by investing activities during 2011, 2010 and 2009 are summarized below:

 

     Cash (Use) Source  
     2011     2010     2009  
     (millions of dollars)  

Investment in property, plant and equipment

   $ (941 )   $ (802 )   $ (664 )