10-K 1 a11-1286_110k.htm 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.

1-9052	DPL INC.	31-1163136
	(An Ohio Corporation)
	1065 Woodman Drive
	Dayton, Ohio 45432
	937-224-6000

1-2385	THE DAYTON POWER AND LIGHT COMPANY	31-0258470
	(An Ohio Corporation)
	1065 Woodman Drive
	Dayton, Ohio 45432
	937-224-6000

Each of the following classes or series of securities registered pursuant to Section 12 (b) of the Act is registered on the New York Stock Exchange:

Registrant		Description

DPL Inc.		Common Stock, $0.01 par value and Preferred Share Purchase Rights

The Dayton Power and Light Company		None

Securities registered pursuant to Section 12(g) of the Act: None

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

DPL Inc.	Yes x	No o
The Dayton Power and Light Company	Yes o	No x

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

DPL Inc.	Yes o	No x
The Dayton Power and Light Company	Yes o	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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

DPL Inc.	Yes x	No o
The Dayton Power and Light Company	Yes x	No o

Indicate by check mark whether each 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).

DPL Inc.	Yes x	No o
The Dayton Power and Light Company	Yes o	No o

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 each 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.

DPL Inc.	x
The Dayton Power and Light Company	x

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

	Large			Smaller
	Accelerated	Accelerated	Non-Accelerated	reporting
	filer	filer	filer	company
DPL Inc.	x	o	o	o
The Dayton Power and Light Company	o	o	x	o

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

DPL Inc.	Yes o	No x
The Dayton Power and Light Company	Yes o	No x

The aggregate market value of DPL Inc.’s common stock held by non-affiliates of DPL Inc. as of June 30, 2010 was approximately $2.8 billion based on a closing sale price of $23.90 on that date as reported on the New York Stock Exchange. All of the common stock of The Dayton Power and Light Company is owned by DPL Inc. As of February 15, 2011, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, $0.01 par value and Preferred Share Purchase Rights	116,931,350

The Dayton Power and Light Company	Common Stock, $0.01 par value	41,172,173

This combined Form 10-K is separately filed by DPL Inc. and The Dayton Power and Light Company. 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 a registrant other than itself.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of DPL’s definitive proxy statement for its 2011 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K.

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DPL Inc. and The Dayton Power and Light Company

Index to Annual Report on Form 10-K

Fiscal Year Ended December 31, 2010

		Page No.

Glossary of Terms		3

	Part I
Item 1	Business	5
Item 1A	Risk Factors	22
Item 1B	Unresolved Staff Comments	32
Item 2	Properties	32
Item 3	Legal Proceedings	32
Item 4	Removed and Reserved	33

	Part II
Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	33
Item 6	Selected Financial Data	36
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	73
Item 8	Financial Statements and Supplementary Data	73
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	152
Item 9A	Controls and Procedures	152
Item 9B	Other Information	152

	Part III
Item 10	Directors and Executive Officers of the Registrant	153
Item 11	Executive Compensation	153
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	153
Item 13	Certain Relationships and Related Transactions	153
Item 14	Principal Accountant Fees and Services	154

	Part IV
Item 15	Exhibits and Financial Statement Schedules	155

	Other
	Signatures	165
	Schedule II Valuation and Qualifying Accounts	167
	Subsidiaries of DPL Inc. and The Dayton Power and Light Company
	Consent of Independent Registered Public Accounting Firm

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GLOSSARY OF TERMS

The following select abbreviations or acronyms are used in this Form 10-K:

Abbreviation or Acronym		Definition

AMI		Advanced Metering Infrastructure

AOCI		Accumulated Other Comprehensive Income

ARO		Asset Retirement Obligation

ASU		Accounting Standards Update

BTU		British Thermal Units

CFTC		Commodity Futures Trading Commission

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CSP		Columbus Southern Power, a subsidiary of AEP

CO2		Carbon Dioxide

CCEM		Customer Conservation and Energy Management

CRES		Competitive Retail Electric Service

DPL		DPL Inc., the parent company

DPLE		DPL Energy, LLC, a wholly owned subsidiary of DPL which engages in the operation of peaking generation facilities

DPLER		DPL Energy Resources, Inc., a wholly owned subsidiary of DPL which sells retail electric energy and other energy services

DP&L		The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio

Duke Energy		Duke Energy Ohio, Inc., formerly The Cincinnati Gas & Electric Company (CG&E)

EIR		Environmental Investment Rider

EPS		Earnings Per Share

ESP Stipulation		A Stipulation and Recommendation filed by DP&L with the PUCO on February 24, 2009 regarding DP&L’s ESP filing pursuant to SB 221. The Stipulation was signed by the Staff of the PUCO, the Office of the Ohio Consumers’ Counsel and various intervening parties. The PUCO approved the Stipulation on June 24, 2009.

ESOP		Employee Stock Ownership Plan

ESP		Electric Security Plans, filed with the PUCO, pursuant to Ohio law

FASB		Financial Accounting Standards Board

FASC		FASB Accounting Standards Codification

FERC		Federal Energy Regulatory Commission

FGD		Flue Gas Desulfurization

FTRs		Financial Transmission Rights

GAAP		Generally Accepted Accounting Principles in the United States

GHG		Greenhouse Gas

kWh		Kilowatt hours

LOC		Letter of Credit

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Abbreviation or Acronym		Definition

MRO		Market Rate Option

MTM		Mark to Market

MVIC		Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries

MWh		Megawatt hours

NERC		North American Electric Reliability Corporation

NOV		Notice of Violation

NOx		Nitrogen Oxide

NYMEX		New York Mercantile Exchange

OAQDA		Ohio Air Quality Development Authority

OCC		Ohio Consumers’ Counsel

ODT		Ohio Department of Taxation

Ohio EPA		Ohio Environmental Protection Agency

OTC		Over-The-Counter

OVEC		Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest

PJM		PJM Interconnection, LLC, a regional transmission organization

PRP		Potentially Responsible Party

PUCO		Public Utilities Commission of Ohio

RSU		Restricted Stock Units

RTO		Regional Transmission Organization

RPM		Reliability Pricing Model

SB 221		Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an ESP or MRO to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.

SCR		Selective Catalytic Reduction

SEC		Securities and Exchange Commission

SECA		Seams Elimination Charge Adjustment

SFAS		Statement of Financial Accounting Standards

SO2		Sulfur Dioxide

SSO		Standard Service Offer which represents the regulated rates, authorized by the PUCO, charged to retail customers within DP&L’s service territory.

TCRR		Transmission Cost Recovery Rider

USEPA		U.S. Environmental Protection Agency

USF		Universal Service Fund

VRDN		Variable Rate Demand Note

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PART I

Item 1 — Business

This report includes the combined filing of DPL and DP&L. DP&L is the principal subsidiary of DPL providing approximately 93% of DPL’s total consolidated gross margin and approximately 91% of DPL’s total consolidated asset base. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

WEBSITE ACCESS TO REPORTS

We file current, annual and quarterly reports and other information required by the Securities Exchange Act of 1934, as amended, with the SEC. You may read and copy any document we file at the SEC’s public reference room located at 100 F Street N.E., Washington, D.C. 20549, USA. Please call the SEC at (800) SEC-0330 for further information on the public reference rooms. Our SEC filings are also available to the public from the SEC’s website at http://www.sec.gov.

Our public internet site is http://www.dplinc.com. We make available, free of charge, through our internet site, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and Forms 3, 4 and 5 filed on behalf of our directors and executive officers and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

In addition, our public internet site includes other items related to corporate governance matters, including, among other things, our governance guidelines, charters of various committees of the Board of Directors and our code of business conduct and ethics applicable to all employees, officers and directors. You may obtain copies of these documents, free of charge, by sending a request, in writing, to DPL Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.

Forward-looking Statements: Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Please see page 37 for more information about forward-looking statements contained in this report.

ORGANIZATION

DPL is a regional energy company organized in 1985 under the laws of Ohio. Our executive offices are located at 1065 Woodman Drive, Dayton, Ohio 45432 — telephone (937) 224-6000.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic, manufacturing and defense. DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market. DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of its retail customers.

During 2010, DPL, for the first time, met the GAAP requirements for separate segment reporting. DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 17 of Notes to Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.

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DPLER sells competitive retail electric service, under contract, primarily to commercial and industrial customers. DPLER has approximately 9,000 customers currently located throughout Ohio. All of DPLER’s electric energy was purchased from DP&L to meet these sales obligations. During 2010, we implemented a new wholesale agreement between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on the market prices for wholesale power. In 2009 and prior periods, DPLER’s purchases from DP&L were transacted at prices that approximated DPLER’s sales prices to its end-use retail customers. The operations of DPLER are not subject to rate regulation by federal or state regulators.

DPL’s other significant subsidiaries (all of which are wholly-owned) include: DPLE, which engages in the operation of peaking generating facilities and sells power in wholesale markets and MVIC, which is our captive insurance company that provides insurance to us and our subsidiaries.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed 1,494 persons as of January 31, 2011, of which 1,321 were full-time employees and 173 were part-time employees. At that date, 1,298 of these full-time employees and substantially all of the part-time employees were employed by DP&L. Approximately 54% of the employees are under a collective bargaining agreement.

SIGNIFICANT DEVELOPMENTS

Borrowing Activities

On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. The facility contains one financial covenant: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This facility also contains a $50 million letter of credit sublimit.

On December 1, 2010, DP&L renewed two $50 million LOC agreements with JPMorgan Chase Bank, N.A. These agreements are for three years, expiring December 9, 2013. The irrevocable LOC’s continue to back the payment of principal and interest relating to the $100 million State of Ohio Collateralized Air Quality Development Revenue Refunding Bonds, 2008 Series A and B which are due in November 2040.

Stock Repurchase Plan

On October 27, 2010, the DPL Board of Directors approved a new stock repurchase plan to acquire up to $200 million of DPL common stock. Under this plan, DPL may repurchase its common stock from time to time in the open market, through private transactions or otherwise, on such terms and conditions as the company deems appropriate. The company expects to subject the purchases to restrictions relating to volume, price and timing in an effort to minimize the impact of the purchases upon the market for its common stock. DPL intends to fund purchases from cash on hand, available borrowings, cash flow from operations and proceeds from potential debt or other capital market transactions. The plan will run through December 31, 2013, but may be modified or terminated at any time without prior notice. Through December 31, 2010, DPL repurchased approximately 2.04 million shares of common stock under this stock repurchase plan at an average price per share of $25.75.

Construction of Yankee Solar Facility

On April 23, 2010, DP&L’s Yankee solar station, a certified Ohio Renewable Energy Resource Generating Facility, was placed into service. The Yankee facility is comprised of 9,120 solar panels constructed over approximately 7 acres of land located in the Dayton, Ohio area. The facility is expected to generate approximately 1,390 MWh of electric energy per year which is sufficient to power the equivalent of approximately 150 homes a year.

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Customer Switching

During 2010, there were 4 additional unaffiliated marketers that registered as CRES providers in DP&L’s service territory. We have experienced increased competition to provide transmission and generation services to our retail customers. DPLER, a CRES provider that is also a subsidiary of DPL, accounted for approximately 97% of the total retail energy supplied by CRES providers within DP&L’s service territory in 2010. During 2010, 847 customers with an energy usage of 145 million kWh were supplied by other CRES providers within DP&L’s service territory, compared to 44 customers that had an energy usage of 16 million kWh during 2009. For the year ended December 31, 2010, the reduction in DPL’s and DP&L’s gross margin as a result of customers switching to DPLER and other CRES providers is estimated to be approximately $17 million and $53 million, respectively.

Increase in Dividends on DPL’s Common Stock

ELECTRIC OPERATIONS AND FUEL SUPPLY

	2010 Summer Generating Capacity
(Amounts in MWs)	Coal Fired	Peaking Units	Total

DPL	2,830	988	3,818

DP&L	2,830	431	3,261

DPL’s present summer generating capacity, including peaking units, is approximately 3,818 MW. Of this capacity, approximately 2,830 MW, or 74%, is derived from coal-fired steam generating stations and the balance of approximately 988 MW, or 26%, consists of solar, combustion turbine and diesel peaking units.

DP&L’s present summer generating capacity, including peaking units, is approximately 3,261 MW. Of this capacity, approximately 2,830 MW, or 87%, is derived from coal-fired steam generating stations and the balance of approximately 431 MW, or 13%, consists of solar, combustion turbine and diesel peaking units.

Our all-time net peak load was 3,270 MW, occurring August 8, 2007.

Approximately 87% of the existing steam generating capacity is provided by certain generating units owned as tenants in common with Duke Energy and CSP. As tenants in common, each company owns a specified share of each of these units, is entitled to its share of capacity and energy output, and has a capital and operating cost responsibility proportionate to its ownership share. DP&L’s remaining steam generating capacity (approximately 365 MW) is derived from a generating station owned solely by DP&L. Additionally, DP&L, Duke Energy and CSP own, as tenants in common, 884 circuit miles of 345,000-volt transmission lines. DP&L has several interconnections with other companies for the purchase, sale and interchange of electricity.

In 2010, we generated 98.9% of our electric output from coal-fired units and 1.1% from solar, oil and natural gas-fired units.

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The following table sets forth DP&L’s and DPLE’s generating stations and, where indicated, those stations which DP&L owns as tenants in common.

				Approximate Summer
				MW Rating
Station	Ownership*	Operating Company	Location	DPL Portion	Total
Coal Units
Hutchings	W	DP&L	Miamisburg, OH	365	365
Killen	C	DP&L	Wrightsville, OH	402	600
Stuart	C	DP&L	Aberdeen, OH	808	2,308
Conesville-Unit 4	C	CSP	Conesville, OH	129	780
Beckjord-Unit 6	C	Duke Energy	New Richmond, OH	207	414
Miami Fort-Units 7 & 8	C	Duke Energy	North Bend, OH	368	1,020
East Bend-Unit 2	C	Duke Energy	Rabbit Hash, KY	186	600
Zimmer	C	Duke Energy	Moscow, OH	365	1,300

Solar, Combustion Turbines or Diesel
Hutchings	W	DP&L	Miamisburg, OH	25	25
Yankee Street	W	DP&L	Centerville, OH	101	101
Yankee Solar	W	DP&L	Centerville, OH	1	1
Monument	W	DP&L	Dayton, OH	12	12
Tait Diesels	W	DP&L	Dayton, OH	10	10
Sidney	W	DP&L	Sidney, OH	12	12
Tait Units 1-3	W	DP&L	Moraine, OH	256	256
Killen	C	DP&L	Wrightsville, OH	12	18
Stuart	C	DP&L	Aberdeen, OH	3	10
Montpelier Units 1-4	W	DPLE	Poneto, IN	236	236
Tait Units 4-7	W	DPLE	Moraine, OH	320	320
Total approximate summer generating capacity				3,818	8,388

*W = Wholly-Owned

C = Commonly-Owned

In addition to the above, DP&L also owns a 4.9% equity ownership interest in OVEC, an electric generating company. OVEC has two plants in Cheshire, Ohio and Madison, Indiana with a combined generation capacity of approximately 2,265 MW. DP&L’s share of this generation capacity is approximately 111 MW.

We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2011 under contract. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. Due to the installation of emission controls equipment at certain jointly owned units and barring any changes in the regulatory environment in which we operate, we expect to have a balanced SO2 and NOx position for 2011.

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The gross average cost of fuel consumed per kWh was as follows:

	Average Cost of Fuel
	Consumed (¢/kWh)
	2010	2009	2008

DPL	2.42	2.39	2.28

DP&L	2.37	2.36	2.22

SEASONALITY

The power generation and delivery business is seasonal and weather patterns have a material effect on operating performance. In the region we serve, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could have an adverse effect on our results of operations, financial condition and cash flows.

RATE REGULATION AND GOVERNMENT LEGISLATION

DP&L’s sales to SSO retail customers are subject to rate regulation by the PUCO. DP&L’s transmission rates and wholesale electric rates to municipal corporations, rural electric co-operatives and other distributors of electric energy are subject to regulation by the FERC under the Federal Power Act.

Ohio law establishes the process for determining SSO retail rates charged by public utilities. Regulation of retail rates encompasses the timing of applications, the effective date of rate increases, the recoverable cost basis upon which the rates are set and other related matters. Ohio law also established the Office of the OCC, which has the authority to represent residential consumers in state and federal judicial and administrative rate proceedings.

Ohio legislation extends the jurisdiction of the PUCO to the records and accounts of certain public utility holding company systems, including DPL. The legislation extends the PUCO’s supervisory powers to a holding company system’s general condition and capitalization, among other matters, to the extent that such matters relate to the costs associated with the provision of public utility service. Based on existing PUCO and FERC authorization, regulatory assets and liabilities are recorded on the balance sheets. See Note 3 of Notes to Consolidated Financial Statements.

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COMPETITION AND REGULATION

Ohio Matters

Ohio Retail Rates

The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

On May 1, 2008, substitute SB 221, an Ohio electric energy bill, was signed by the Governor and went into effect July 31, 2008. This law required that all Ohio distribution utilities file either an ESP or MRO. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade, or replace its electric distribution system, including cost recovery mechanisms. Both the MRO and ESP option involve a “significantly excessive earnings test” based on the earnings of comparable companies with similar business and financial risks. The PUCO issued three sets of rules related to implementation of the law. These rules address topics such as the information that must be included in an ESP as well as a MRO, the significantly excessive earnings test requirements, corporate separation revisions, rules relating to the recovery of transmission related costs, electric service and safety standards dealing with the statewide line extension policy, and rules relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.

In compliance with SB 221, DP&L filed its ESP at the PUCO on October 10, 2008. This plan contained three parts: 1) a standard offer plan; 2) a CCEM plan; and 3) an alternative energy plan. After discussions with Commission Staff, the Ohio Consumers’ Counsel and other interested parties, an ESP Stipulation was agreed to and filed on February 24, 2009. The ESP Stipulation, among other things, extended the Company’s rate plan through 2012, provided for recovery of the Ohio retail customers’ portion of fuel and purchased power costs beginning January 2010, provided for recovery of certain SB 221 compliance costs, and required DP&L to re-file its Smart Grid and advanced metering infrastructure (AMI) business cases, which were part of the CCEM plan, by September 1, 2009. On June 24, 2009, the PUCO issued an order granting approval of the ESP Stipulation as filed and authorized DP&L to implement rates associated with alternative energy and energy efficiency compliance costs, which DP&L implemented beginning on July 1, 2009.

Consistent with the ESP Stipulation, DP&L re-filed its Smart Grid and AMI business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a three-year plan to deploy AMI; and a ten-year plan for distribution and substation automation, core telecommunications, supporting software and in-home technologies. In August 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding for the Smart Grid Investment Grant Program, seeking $145.1 million of matching funds but was notified in October 2009, that we would not receive funding under the ARRA. On October 19, 2010, DP&L elected to withdraw the re-filed case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future.

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. In December 2009, DP&L made several filings relating to its renewable energy and energy efficiency compliance plans. DP&L was able to obtain Renewable Energy Credits sufficient to meet its non-solar renewable energy targets, but obtained only 36% of the 2009 Ohio-based solar resources. DP&L requested a waiver of any unmet 2009 Ohio solar requirements on grounds of force majeure because there were insufficient solar renewable energy credits available from Ohio resources. In March 2010, the PUCO ruled that DP&L’s 2009 Ohio solar target would be reduced to the amount that it had procured, but that any unmet requirement must be added to the 2010 target. DP&L has been able to acquire sufficient renewable resources in 2010 to meet its 2010 requirements plus that portion of the 2009 Ohio solar requirement that was added by the PUCO order.

On April 15, 2010, DP&L made its first annual required filing related to compliance with renewable and advanced energy targets contained in SB 221. Pursuant to PUCO rules, each April 15, DP&L and DPLER who are electric services companies pursuant to Ohio Revised Code, are required to provide a status report on whether or not they met the renewable benchmarks of the previous year, as well as a ten-year plan outlining their plans to meet future annual renewable targets. In addition, on April 15 of each year, each utility that owns an electric generating facility in Ohio must report to the PUCO regarding its greenhouse gas emissions, and plans to reduce those emissions (environmental control plan) as well as a long-term forecast report which includes a plan to provide sufficient resources to meet customer load obligations (resource plan). DP&L’s long-term forecast filing was set for hearing. A settlement was reached in early 2011 under which the need for solar facilities was established. This settlement was filed with the PUCO for their approval.

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In two separate filings, DP&L requested the PUCO’s consent that DP&L had met the 2009 requirements for energy efficiency and for demand reduction based on DP&L’s interpretation of how those requirements should be applied. These filings also requested that if the PUCO disagreed with DP&L’s interpretation, the PUCO grant alternative relief and find that DP&L was unable to meet the targets due to reasons beyond its reasonable control, i.e., uncertainty throughout 2009 caused by delays in finalizing the rules and the lack of timely PUCO action on several of DP&L’s special contracts relating to demand response efforts which remain pending before the PUCO. Since this is a new process, it is unclear if a final order will be issued in these proceedings.

In addition, the rules that became effective December 10, 2009 required that on January 1, 2010, DP&L file an extensive energy efficiency portfolio plan, outlining how DP&L plans to comply with the energy efficiency and demand reduction benchmarks. DP&L filed a separate request for a finding that it had already complied with this requirement in the form of DP&L’s portfolio plan that had been filed in 2008 as part of its CCEM plan, which had been approved by the PUCO and is being implemented. On May 19, 2010 the Commission approved in part and denied in part DP&L’s request that the Commission find that it met the 2009 energy efficiency portfolio requirements and directed DP&L to file a measurement and verification plan as well as a market potential study within 60 days of the date of the order. We made this filing on July 15, 2010. Although this case was set for hearing settlement talks are on-going.

We are unable to predict how the PUCO will respond to many of the filings discussed above, but believe that the outcome will not be material to our financial condition. However, as the energy efficiency and alternative energy targets get increasingly larger over time, the costs of complying with SB 221 and the PUCO’s implementing rules could have a material impact on our financial condition.

The ESP Stipulation also provided for the establishment of a fuel and purchased power recovery rider beginning January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year. DP&L is currently undergoing an audit of its fuel rider which is conducted by an independent third party in accordance with the PUCO standards. As a result there is some uncertainty as to the costs that will be approved for recovery. DP&L anticipates that some of this uncertainty will be resolved during the summer of 2011 after completion of the fuel audit. Based on the results of the audit, DP&L may record a favorable or unfavorable adjustment to earnings. It is too early to determine if any such adjustment would be material to our results of operations, financial condition and cash flows.

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. SB 221 included a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. DP&L’s TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs. Both the TCRR and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers’ load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES providers decreases DP&L’s SSO retail customers’ load and sales volumes. Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. RPM capacity costs and revenues are discussed further under “Regional Transmission Organizational Risks” in Item 1A — Risk Factors. DP&L’s annual true-up of these two riders was approved by the PUCO by an order dated April 28, 2010. On October 15, 2010 DP&L made an interim adjustment to both the TCRR and the RPM riders that had no material change to the rate recovery amounts.

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On September 9, 2009, the PUCO issued an order establishing a significantly excessive earnings test (SEET) proceeding pursuant to provisions contained in SB 221. A question and answer session was held before the Commission on April 1, 2010 to allow the Commission to gain a better understanding of the issues. The PUCO issued an order on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. The other three Ohio utilities were required to make their SEET determinations in 2010 based on 2009 results. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material impact on operations.

On August 28, 2009, DP&L filed its application to establish reliability targets consistent with the most recent PUCO Electric Service and Safety Standards (ESSS). The PUCO issued a procedural schedule and held a technical conference in November 2009. Comments and reply comments were filed. On March 29, 2010 DP&L entered into a settlement establishing the new reliability targets. This settlement was approved on July 29, 2010. According to the ESSS rules, DP&L will be subject to financial penalties if the established targets are not met for two consecutive years.

While the overall financial impact of SB 221 will not be known for some time, implementation of the bill and compliance with its requirements could have a material impact on our financial condition.

Ohio Competitive Considerations and Proceedings

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Overall power market prices, as well as government aggregation initiatives within DP&L’s service territory, have led or may lead to the entrance of additional competitors in our service territory. During the year ended December 31, 2010, there were four additional unaffiliated marketers that registered as CRES providers in DP&L’s service territory, bringing the total number of CRES providers in DP&L’s service territory to eleven. DPLER, an affiliated company and one of the eleven registered CRES providers, has been marketing transmission and generation services to DP&L customers. During 2010, DPLER accounted for approximately 4,417 million kWh of the total 4,562 million kWh supplied by CRES providers within DP&L’s service territory. Also during 2010, 847 customers with an annual energy usage of 145 million kWh were supplied by other CRES providers within DP&L’s service territory, compared to 44 customers that had an annual energy usage of 16 million kWh during 2009. The volume supplied by DPLER represents approximately 31% of DP&L’s total distribution sales volume during 2010. The reduction to gross margin in 2010 as a result of customers switching to DPLER and other CRES providers was approximately $17 million and $53 million, for DPL and DP&L, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the impact this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, none of these communities have aggregated their generation load.

In 2010, DPLER began providing CRES services to business customers in Ohio who are not in DP&L’s service territory. The incremental costs and revenues have not had a material impact on our results of operations, financial condition or cash flows.

Federal Matters

Like other electric utilities and energy marketers, DP&L and DPLE may sell or purchase electric products on the wholesale market. DP&L and DPLE compete with other generators, power marketers, privately and municipally-owned electric utilities and rural electric cooperatives when selling electricity. The ability of DP&L and DPLE to sell this electricity will depend not only on the performance of our generating units, but also on how DP&L’s and DPLE’s price, terms and conditions compare to those of other suppliers.

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As part of Ohio’s electric deregulation law, all of the state’s investor-owned utilities are required to join a RTO. In October 2004, DP&L successfully integrated its 1,000 miles of high-voltage transmission into the PJM RTO. The role of the RTO is to administer a competitive wholesale market for electricity and ensure reliability of the transmission grid. PJM ensures the reliability of the high-voltage electric power system serving 51 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM coordinates and directs the operation of the region’s transmission grid, administers the world’s largest competitive wholesale electricity market and plans regional transmission expansion improvements to maintain grid reliability and relieve congestion.

As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC Orders issued in 2007 and thereafter regarding the allocation of costs of large transmission facilities within PJM, would result in additional costs being allocated to DP&L that, over time and depending on final costs and how quickly the facilities are constructed, could become material. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit which was consolidated with other appeals taken by other interested parties of the same FERC Orders and the consolidated cases were assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. Rehearings were filed by other interested litigants and denied by the Court, which then remanded the matter to the FERC for further proceedings. On January 21, 2010, the FERC issued a procedural order on remand establishing a paper hearing process under which PJM will make an informational filing in late February. Subsequently PJM and other parties, including DP&L, filed initial comments, testimony, and recommendations and reply comments. FERC did not establish a deadline for its issuance of a substantive order and the matter is still pending. DP&L cannot predict the timing or the likely outcome of the proceeding. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that DP&L is not one of these beneficiaries, any new credits or additional costs resulting from the ultimate outcome of this proceeding will be reflected in DP&L’s TCRR rider which already includes these costs.

NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, including Critical Infrastructure Protection (CIP) reliability standards, across eight reliability regions. In June 2009, Reliability First Corporation (RFC), with responsibilities assigned to it by NERC over the reliability region that includes DP&L, commenced a routine audit of DP&L’s operations. The audit, which was for the period June 18, 2007 to June 25, 2009, evaluated DP&L’s compliance with 42 requirements in 18 NERC-reliability standards. DP&L is currently subject to a compliance audit at a minimum of once every three years as provided by the NERC Rules of Procedure. This audit was concluded in June 2009 and its findings revealed that DP&L had some Possible Alleged Violations (PAVs) associated with five NERC reliability requirements of various Standards. In response to the report, DP&L filed mitigation plans with RFC/NERC to address the PAVs. These mitigation plans were accepted by RFC/NERC. In July 2010, DP&L negotiated a settlement with NERC wherein DP&L agreed to pay an immaterial amount in exchange for a resolution of all issues and obligations relating to the aforementioned PAVs. The settlement was approved on January 21, 2011 by the FERC.

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ENVIRONMENTAL CONSIDERATIONS

DPL’s and DP&L’s facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. The environmental issues that may impact us include:

· The Federal CAA and state laws and regulations (including State Implementation Plans) which require compliance, obtaining permits and reporting as to air emissions.

· Litigation with federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants require additional permitting or pollution control technology, or whether emissions from coal-fired generating plants cause or contribute to global climate changes.

· Rules and future rules issued by the USEPA and Ohio EPA that require substantial reductions in SO2, particulates, mercury and NOx emissions. DP&L has installed emission control technology and is taking other measures to comply with required and anticipated reductions.

· Rules issued by the USEPA and Ohio EPA that require reporting and future rules that may require reductions of GHGs.

· Rules and future rules issued by the USEPA associated with the Federal Clean Water Act (FCWA), which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits.

· Solid and hazardous waste laws and regulations, which govern the management and disposal of certain waste. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion by-products. The EPA has previously determined that fly ash and other coal combustion by-products are not hazardous waste subject to the Resource Conservation and Recovery Act (RCRA), but the EPA is reconsidering that determination. A change in determination could significantly increase the costs of disposing of such by-products.

As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for loss contingencies related to environmental matters when a loss is probable of occurring and can be reasonably estimated in accordance with the provisions of GAAP. Accordingly, we have estimated accruals for loss contingencies of approximately $4.0 million for environmental matters. We also have a number of unrecognized loss contingencies related to environmental matters that are disclosed in the paragraphs below. We evaluate the potential liability related to environmental matters quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial condition or cash flows.

In July 2010, the USEPA proposed new rules to limit the interstate transport of emissions of NOx and SO2 that would, if finalized, have a significant industry-wide impact on the operation of coal-fired generation units. We also have several other pending environmental matters associated with our coal-fired generation units and these pending matters, along with the new rules proposed by the USEPA, could result in significant capital and operations and maintenance expenditures for our coal-fired generation plants, and could result in the early retirement of our generation units that do not have SCR and FGD equipment installed. Currently, our coal-fired generation units at Hutchings and Beckjord do not have this emission-control equipment installed and their early retirement could occur as early as 2015. DP&L owns 100% of the Hutchings plant and has a 50% interest in Beckjord Unit 6. In addition to environmental matters, the operation of our coal-fired generation plants could be impacted by a multitude of other factors, including forecasted power, capacity and commodity prices, competition and the levels of customer switching, current and forecasted customer demand, cost of capital, and regulatory and legislative developments, any of which could pose a potential triggering event for an impairment of our investments in the Hutchings and Beckjord units.

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Regulation Matters Related to Air Quality

Clean Air Act Compliance

In 1990, the federal government amended the CAA to further regulate air pollution. Under the law, the USEPA sets limits on how much of a pollutant can be in the air anywhere in the United States. The CAA allows individual states to have stronger pollution controls, but states are not allowed to have weaker pollution controls than those set for the whole country. The CAA has a material effect on our operations and such effects are detailed below with respect to certain programs under the CAA.

On October 27, 2003, the USEPA published final rules regarding the equipment replacement provision (ERP) of the routine maintenance, repair and replacement (RMRR) exclusion of the CAA. Activities at power plants that fall within the scope of the RMRR exclusion do not trigger new source review (NSR) requirements, including the imposition of stricter emission limits. On December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. On June 6, 2005, the USEPA issued its final response on the reconsideration of the ERP exclusion. The USEPA clarified its position, but did not change any aspect of the 2003 final rules. This decision was appealed and the D.C. Circuit vacated the final rules on March 17, 2006. The scope of the RMRR exclusion remains uncertain due to this action by the D.C. Circuit, as well as multiple litigations not directly involving us where courts are defining the scope of the exception with respect to the specific facts and circumstances of the particular power plants and activities before the courts. While we believe that we have not engaged in any activities with respect to our existing power plants that would trigger the NSR requirements, if NSR requirements were imposed on any of DP&L’s existing power plants, the results could have a material adverse impact to us.

The USEPA issued a proposed rule on October 20, 2005 concerning the test for measuring whether modifications to electric generating units should trigger application of NSR standards under the CAA. A supplemental rule was also proposed on May 8, 2007 to include additional options for determining if there is an emissions increase when an existing electric generating unit makes a physical or operational change. The rule was challenged by environmental organizations and has not been finalized. While we cannot predict the outcome of this rulemaking, any finalized rules could materially affect our operations.

Interstate Air Quality Rule

On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap SO2 and NOx emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and ozone pollution in other downwind states in the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, now renamed the Clean Air Interstate Rule (CAIR). The final rules were signed on March 10, 2005 and were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. On August 24, 2005, the USEPA proposed additional revisions to the CAIR. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision to vacate the USEPA’s CAIR and its associated Federal Implementation Plan and remanded to the USEPA with instructions to issue new regulations that conformed with the procedural and substantive requirements of the CAA. The Court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program established by the March 10, 2005 rules, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. The USEPA and a group representing utilities filed a request on September 24, 2008 for a rehearing before the entire Court. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 11, 2008 decision.

On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) which may replace CAIR in 2012. We have reviewed this proposal and submitted comments to the USEPA on September 30, 2010. We are unable to determine the overall financial impact that these rules could have on our operations in the future.

In 2007, the Ohio EPA revised their State Implementation Plan (SIP) to incorporate a CAIR program consistent with the IAQR. The Ohio EPA had received partial approval from the USEPA and had been awaiting full program approval from the USEPA when the U.S. Court of Appeals issued its July 11, 2008 decision. As a result of the December 23, 2008 order, the Ohio EPA proposed revised rules on May 11, 2009, which were finalized on July 15, 2009. On September 25, 2009, the USEPA issued a full SIP approval for the Ohio CAIR program. We do not expect that full SIP approval of the Ohio CAIR program will have a significant impact on operations.

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Mercury and Other Hazardous Air Pollutants

On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA “de-listed” mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005 and was published on May 18, 2005. On March 29, 2005, nine states sued the USEPA, opposing the cap-and-trade regulatory approach taken by the USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to “de-listing” a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for “listed” hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. The USEPA is expected to propose Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units during the quarter ending March 31, 2011 and finalize them during the quarter ending December 31, 2011. Upon publication in the federal register following finalization, affected electric generating units (EGUs) will have three years to come into compliance with the new requirements. DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial condition or results of operations; however, a MACT standard could have a material adverse effect on our operations. We cannot predict the final costs we may incur to comply with proposed new regulations to control mercury or other hazardous air pollutants.

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities. This regulation may affect five auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The proposed regulations contain emissions limitations, operating limitations and other requirements. The compliance schedule will be three years from the date when these rules, if finalized, become effective. We currently cannot determine whether or not these rules will be finalized nor can we predict the effect of compliance costs, if any, on DP&L’s operations. Such costs, however, are not expected to be material.

On May 3, 2010, the USEPA finalized the “National Emissions Standards for Hazardous Air Pollutants” (NESHAP) for compression ignition (CI) reciprocating internal combustion engines (RICE). The units affected at DP&L are 18 diesel electric generating engines and eight emergency “black start” engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs on DP&L’s operations are not expected to be material.

National Ambient Air Quality Standards

On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. On March 4, 2005, DP&L and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered the USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, the USEPA denied the petitions for reconsideration. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting DP&L’s generation plants, however, on October 8, 2009 the USEPA issued new designations based on 2008 monitoring data that showed all areas in attainment to the standard with the exception of several counties in northeastern Ohio. The USEPA is expected to propose revisions to the PM 2.5 standard during the first quarter of 2011 as part of its routine five-year rule review cycle. We cannot predict the impact the revisions to the PM 2.5 standard will have on DP&L’s financial condition or results of operations.

On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In the final rule, the USEPA made the determination that CAIR achieves greater progress than BART and may be used by states as a BART substitute. Numerous units owned and operated by us will be impacted by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.

On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. A more stringent ambient ozone standard may lead to stricter NOx emission standards in the future. DP&L cannot determine the effect of this potential change, if any, on its operations.

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Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. DP&L cannot determine the effect of this potential change, if any, on its operations.

Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO2 replacing the current 24-hour standard and annual standard with a one hour standard. DP&L cannot determine the effect of this potential change, if any, on its operations.

Climate Change

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under USEPA’s view, this is the final action that renders carbon dioxide and other GHGs “regulated air pollutants” under the CAA. As a result of this action, it is expected that in 2011 various permitting programs will apply to other combustion sources, such as coal-fired power plants. We cannot predict the effect of this change, if any, on DP&L’s operations.

Legislation proposed in 2009 to target a reduction in the emission of GHGs from large sources was not enacted. Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Proposed GHG legislation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation, we cannot predict the final outcome or the financial impact that this legislation will have on DP&L.

On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. The first report is due in March 2011 for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Plants

In 2004, eight states and the City of New York filed a lawsuit in Federal District Court for the Southern District of New York against American Electric Power Company, Inc. (AEP), one of AEP’s subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. A similar lawsuit was filed against these companies in the same court by Open Space Institute, Inc., Open Space Conservancy, Inc. and The Audubon Society of New Hampshire. The lawsuits allege that the companies’ emissions of CO2 contribute to global warming and constitute a public or private nuisance. The lawsuits seek injunctive relief in the form of specific emission reduction commitments. In 2005, the Federal District Court dismissed the lawsuits, holding that the lawsuits raised political questions that should not be decided by the courts. The plaintiffs appealed. Finding that the plaintiffs have standing to sue and can assert federal common law nuisance claims, the United States Court of Appeals for the Second Circuit on September 21, 2009 vacated the dismissal of the Federal District Court and remanded the lawsuits back to the Federal District Court for further proceedings. In response to a petition by the company defendants, the U.S. Supreme Court on December 6, 2010 granted a hearing on the matter. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could be affected by the outcome of these lawsuits. The outcomes of these lawsuits could also encourage these or other plaintiffs to file similar lawsuits against other electric power companies, including DP&L. We are unable to predict the impact that these lawsuits might have on DP&L.

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On September 21, 2004, the Sierra Club filed a lawsuit against DP&L and the other owners of the J.M. Stuart generating station in the U.S. District Court for the Southern District of Ohio for alleged violations of the CAA and the station’s operating permit. On August 7, 2008, a consent decree was filed in the U.S. District Court in full settlement of these CAA claims. Under the terms of the consent decree, DP&L and the other owners of the J.M. Stuart generating station agreed to: (i) certain emission targets related to NOx, SO2 and particulate matter; (ii) make energy efficiency and renewable energy commitments that are conditioned on receiving PUCO approval for the recovery of costs; (iii) forfeit 5,500 SO2 allowances; and (iv) provide funding to a third party non-profit organization to establish a solar water heater rebate program. DP&L and the other owners of the station also entered into an attorneys’ fee agreement to pay a portion of the Sierra Club’s attorney and expert witness fees. The parties to the lawsuit filed a joint motion on October 22, 2008, seeking an order by the U.S. District Court approving the consent decree with funding for the third party non-profit organization set at $300,000. On October 23, 2008, the U.S. District Court approved the consent decree. On October 21, 2009, the Sierra Club filed with the U.S. District Court a motion for enforcement of the consent decree based on the Sierra Club’s interpretation of the consent decree that would require certain NOx emissions that DP&L has been excluding from its computations to be included for purposes of complying with the emission targets and reporting requirements of the consent decree. DP&L believed that it was properly computing and reporting NOx emissions under the consent decree, but participated in settlement discussions with the Sierra Club. A proposed settlement was agreed to by both parties, approved by the court and then filed into the official record on July 13, 2010. The settlement amends the Consent Decree and sets forth a more detailed and clearer methodology to compute NOx emissions during start-up and shut-down periods. There were no cash payments under the terms of this settlement. The revision is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.

Notices of Violation Involving Co-Owned Plants

In November 1999, the USEPA filed civil complaints and NOVs against operators and owners of certain generation facilities for alleged violations of the CAA. Generation units operated by Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. Numerous northeast states have filed complaints or have indicated that they will be joining the USEPA’s action against Duke Energy and CSP. Although DP&L was not identified in the NOVs, civil complaints or state actions, the results of such proceedings could materially affect DP&L’s co-owned plants.

In June 2000, the USEPA issued a NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy, and CSP) for alleged violations of the CAA. The NOV contained allegations consistent with NOVs and complaints that the USEPA had recently brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter or the financial impact this matter will have on DP&L.

In December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOVs alleged deficiencies in the continuous monitoring of opacity. We submitted a compliance plan to the Ohio EPA on December 19, 2007. To date, no further actions have been taken by the Ohio EPA.

On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received a NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters or the financial impact that these matters will have on DP&L.

Other Issues Involving Co-Owned Plants

In 2006, DP&L detected a malfunction with its emission monitoring system at the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) and ultimately determined its SO2 and NOx emissions data were under reported. DP&L has petitioned the USEPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter of 2006. DP&L has sufficient allowances in its general account to cover the understatement. Management does not believe the ultimate resolution of this matter will have a material impact on results of operations, financial condition or cash flows.

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Notices of Violation Involving Wholly-Owned Plants

In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the O.H. Hutchings Station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. DP&L has provided data to those agencies regarding its maintenance expenses and operating results. On December 15, 2008, DP&L received a request from the USEPA for additional documentation with respect to those issues and other CAA issues including issues relating to capital expenses and any changes in capacity or output of the units at the O.H. Hutchings Station. During 2009, DP&L continued to submit various other operational and performance data to the USEPA in compliance with its request. DP&L is currently unable to determine the timing, costs or method by which the issues may be resolved and continues to work with the USEPA on this issue.

On November 18, 2009, the USEPA issued a NOV to DP&L for alleged NSR violations of the CAA at the O.H. Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the two projects described in the NOV were modifications subject to NSR. DP&L is unable to determine the timing, costs or method by which these issues may be resolved and continues to work with the USEPA on this issue.

Regulation Matters Related to Water Quality

Clean Water Act — Regulation of Water Intake

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules to the Federal Court of Appeals for the Second Circuit in New York and the Court issued an opinion on January 25, 2007 remanding several aspects of the rule to the USEPA for reconsideration. Several parties petitioned the U.S. Supreme Court for review of the lower court decision. On April 14, 2008, the Supreme Court elected to review the lower court decision on the issue of whether the USEPA can compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Briefs were submitted to the Court in the summer of 2008 and oral arguments were held in December 2008. In April 2009, the U.S. Supreme Court ruled that the USEPA did have the authority to compare costs with benefits in determining best technology available. The USEPA is developing proposed regulations and anticipates proposing requirements by March 2011 with final rules in place by mid-2012. We are unable to predict the impact this will have on our operations.

Clean Water Act — Regulation of Water Discharge

On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station that continued our authority to discharge water from the station into the Ohio River. During the three-year term of the Permit, we conducted a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers. In December 2006, we submitted an application for the renewal of the Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA agreed to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which USEPA has agreed to conduct. If a public hearing is held, it is anticipated that it would be scheduled in the first half of 2011. We are attempting to resolve this issue with both the USEPA and Ohio EPA. The timing for issuance of a final permit is uncertain. DP&L is unable to predict the impact this will have on its operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. Subsequent to the information collection effort, it is anticipated that the USEPA will release a proposed rule by mid-2012 with a final regulation in place by early 2014. DP&L is unable to predict the impact this rulemaking will have on its operations.

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Regulation Matters Related to Land Use and Solid Waste Disposal

Regulation of Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with the USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. However, on August 25, 2009, the USEPA issued an Administrative Order requiring that access to DP&L’s service center building site, which is across the street from the landfill site, be given to the USEPA and the existing PRP group to help determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. DP&L has granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. DP&L believes the chemicals used at its service center building site were appropriately disposed of and have not contributed to the contamination at the South Dayton Dump landfill site. On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. DP&L filed a motion to dismiss the complaint and intends to vigorously defend against any claim that it has any financial responsibility to remediate conditions at the landfill site. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. While DP&L is unable to predict the outcome of these matters, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking (ANPRM) announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCB). While this reassessment is in the early stages and the USEPA is seeking information from potentially affected parties on how it should proceed, the outcome may have a material effect on DP&L. At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. DP&L has ash ponds at the Killen, O.H. Hutchings and J.M. Stuart Stations which it operates, and also at generating stations operated by others but in which DP&L has an ownership interest.

During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station. In October 2009, the USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, the USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds. In May 2010, DP&L responded to the USEPA final inspection report with our plans to address the recommendations.

Similarly, in August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. The draft report relating to the inspection was received in November 2010 and DP&L provided comments on the draft report in December 2010. DP&L is unable to predict the outcome this inspection will have on its operations.

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In addition, as a result of the TVA ash pond spill, there has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion products including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. DP&L is unable to predict the financial impact of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse impact on operations.

Other Legal Matters

In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two jointly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim, under which DPL received $3.4 million (net of associated expenses).

In connection with DP&L and other utilities joining PJM, in 2006 the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. DP&L, along with other transmission owners in PJM and the Midwest Independent System Operator (MISO) made a compliance filing at FERC on August 19, 2010 that fully demonstrated all payment obligations to and from all parties within PJM and the MISO. The FERC has made no ruling regarding the compliance filing and some parties have requested rehearing by FERC of its May 21, 2010 order. It is expected that any order on the compliance filing and any order regarding the rehearing request will be appealed for Court review. Prior to this final order being issued, DP&L entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. Further, in October 2010, DP&L entered into another settlement agreement to settle a portion of SECA amounts still owed to DP&L. With respect to unsettled claims, DP&L management believes it has deferred as a regulatory liability the appropriate amounts that are subject to refund (see SECA net revenue subject to refund within Note 3 of Notes to Consolidated Financial Statements) and therefore the results of this proceeding are not expected to have a material adverse effect on DP&L’s results of operations.

Capital Expenditures for Environmental Matters

Test operations of the FGD equipment on our jointly-owned Conesville Unit 4 were completed in November 2009. The equipment is currently in service.

DPL’s construction additions were approximately $151 million, $145 million and $228 million in 2010, 2009 and 2008, respectively, and are expected to approximate $310 million in 2011. Planned construction additions for 2011 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system.

DP&L’s construction additions were $148 million, $144 million and $225 million in 2010, 2009 and 2008, respectively, and are expected to approximate $300 million in 2011. Planned construction additions for 2011 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution system.

All environmental additions made during the past three years pertain to DP&L and approximated $12 million, $21 million and $90 million in 2010, 2009 and 2008, respectively.

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ELECTRIC SALES AND REVENUES

The following table sets forth DPL’s, DP&L’s and DPLER’s electric sales and revenues for the years ended December 31, 2010, 2009 and 2008, respectively.

	DPL						DP&L (a)						DPLER (b)
	2010		2009		2008		2010		2009		2008		2010		2009		2008
Electric sales (millions of kWh)
Residential	5,522		5,120		5,533		5,522		5,120		5,533		1		—		—
Commercial	3,842		3,678		3,959		3,741		3,678		3,959		1,194		68		421
Industrial	3,605		3,353		3,986		3,582		3,353		3,986		2,476		983		2,322
Other retail	1,437		1,386		1,454		1,432		1,386		1,454		875		413		469
Total retail	14,406		13,537		14,932		14,277		13,537		14,932		4,546		1,464		3,212

Wholesale	2,831		3,130		2,240		2,806		3,053		2,173		—		—		—

Total	17,237		16,667		17,172		17,083		16,590		17,105		4,546		1,464		3,212

Operating revenues ($ in thousands)
Residential	$	687,932	$	560,223	$	544,561	$	687,891	$	560,223	$	544,561	$	41	$	—	$	—
Commercial	384,385		332,808		332,010		304,078		329,006		308,934		80,307		3,802		23,076
Industrial	260,763		228,458		240,041		118,517		186,293		133,832		142,246		42,165		106,209
Other retail	113,550		98,781		97,592		64,240		82,749		78,905		52,811		18,871		21,338
Other miscellaneous revenues	9,814		8,766		9,042		10,723		8,966		9,046		57		—		64
Total retail	1,456,444		1,229,036		1,223,246		1,185,449		1,167,237		1,075,278		275,462		64,838		150,687

Wholesale	142,312		122,519		149,874		365,798		181,871		293,500		—		—		—

RTO revenues	272,832		225,677		217,357		239,274		201,254		204,074		1,503		615		31

Other revenues	11,534		11,689		11,080		—		—		—		27		95		88

Total	$	1,883,122	$	1,588,921	$	1,601,557	$	1,790,521	$	1,550,362	$	1,572,852	$	276,992	$	65,548	$	150,806

Electric customers at end of period
Residential	455,572		456,144		456,770		455,572		456,144		456,770		33		—		—
Commercial	50,764		50,141		50,190		50,155		50,141		50,190		7,205		223		432
Industrial	1,800		1,773		1,797		1,769		1,773		1,797		564		44		184
Other	6,742		6,577		6,517		6,739		6,577		6,517		1,200		123		126

Total	514,878		514,635		515,274		514,235		514,635		515,274		9,002		390		742

(a) DP&L sold 4,417 million kWh, 1,464 million kWh and 3,212 million kWh of power to DPLER (a subsidiary of DPL) during the years ended December 31, 2010, 2009 and 2008, respectively, which are not included in DP&L wholesale sales volumes in the chart above. These kWh sales also relate to DP&L retail customers within the DP&L service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on DP&L’s Financial Statements and retail revenues on DPL’s Consolidated Financial Statements.

(b) This chart includes all sales of DPLER, both within and outside of the DP&L service territory.

Item 1A — Risk Factors

This annual report and other documents that we file with the SEC and other regulatory agencies, as well as other written or oral statements we may make from time to time, contain information based on management’s beliefs and include forward-looking statements (within the meaning of the Private Securities Litigation Reform Act of 1995) that involve a number of known and unknown risks, uncertainties and assumptions. These forward-looking statements are not guarantees of future performance and there are a number of factors including, but not limited to, those listed below, which could cause actual outcomes and results to differ materially from the results contemplated by such forward-looking statements. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. These forward-looking statements are generally identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will” and similar expressions.

Future operating results are subject to fluctuations based on a variety of factors, including but not limited to: unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages; changes in wholesale power sales prices; unusual maintenance or repairs; changes in fuel and purchased power costs, emissions allowance costs, or availability constraints; environmental compliance; and electric transmission system constraints.

The following is a listing of specific risk factors that DPL and DP&L consider to be the most significant to your decision to invest in our securities. If any of these events occur or are continuing, our business, results of operations, financial condition and cash flows could be materially affected.

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Our customers have recently begun to select alternative electric generation service providers, as permitted by Ohio legislation.

Customers can elect to buy transmission and generation service from a PUCO-certified CRES provider offering services to customers in DP&L’s service territory. DPLER, a wholly-owned subsidiary of DPL, is one of the PUCO-certified CRES providers and accounted for approximately 97% of the total retail energy supplied by CRES providers within DP&L’s service territory in 2010. Unaffiliated CRES providers also have been certified to provide energy in DP&L’s service territory and during 2010, approximately 800 DP&L customers switched their generation service to these providers. Customer switching from DP&L to DPLER reduces DPL’s revenues since the generation rates charged by DPLER are less than the rates charged by DP&L. Increased competition by unaffiliated CRES providers in our service territory for retail generation service could result in the loss of existing customers and reduced revenues and increased costs to retain or attract customers. Decreased revenues and increased costs due to continued customer switching and customer loss could have a material adverse effect on our results of operations, financial condition and cash flows. The following are a few of the factors that could result in increased switching by customers to PUCO-certified CRES providers in the future:

· Low wholesale price levels may lead to existing CRES providers becoming more active in our service territory, and additional CRES providers entering our territory.

· We could also experience customer switching through “governmental aggregation,” where a municipality may contract with a CRES provider to provide generation service to the customers located within the municipal boundaries.

We are subject to extensive laws and local, state and federal regulation, as well as related litigation, that could affect our operations and costs.

We are subject to extensive laws and regulation by federal, state and local authorities, such as the PUCO, the CFTC, the USEPA, the Ohio EPA, the FERC, the SEC, the Department of Labor and the Internal Revenue Service, among others. Regulations affect almost every aspect of our business, including in the areas of the environment, health and safety, cost recovery and rate making, securities, corporate governance, public disclosure and reporting and taxation. New laws and regulations, and new interpretations of existing laws and regulations, are ongoing and we generally cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. Complying with this regulatory environment requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business. Additional detail about the effect of this regulatory environment on our operations is included in the risk factors set forth below. In the normal course of business, we are also subject to various lawsuits, actions, proceedings, claims and other matters asserted under this regulatory environment or otherwise, which require us to expend significant funds to address, the outcomes of which are uncertain and the adverse resolutions of which could have a material adverse effect on our results of operations, financial condition and cash flows.

The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO. On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, required all Ohio distribution utilities to file either an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks. The PUCO approved DP&L’s filed ESP on June 24, 2009. DP&L’s ESP provides, among other things, that DP&L’s existing rate plan structure will continue through 2012; that DP&L may seek recovery for adjustments to its existing rate plan structure for costs associated with storm damage, regulatory and tax changes, new climate change or carbon regulations, fuel and purchased power and certain other costs; and that SB 221’s significantly excessive earnings test will apply in 2013 based upon DP&L’s 2012 earnings. DP&L’s ESP and certain filings made by us in connection with this plan are further discussed under “Ohio Retail Rates” in Item 1 — COMPETITION AND REGULATION. In addition, as the local distribution utility, DP&L has an obligation to serve customers within its certified territory and under the terms of its ESP Stipulation, it is the provider of last resort (POLR) for standard offer service. DP&L’s current rate structure provides for a nonbypassable charge to compensate DP&L for this POLR obligation. The PUCO may decrease or discontinue this POLR rate charge at some time in the future.

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While rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable or that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return. Certain of our cost recovery riders are also by-passable by some of our customers who switched to a CRES provider. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Therefore, DP&L could be subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return and POLR service; changes in DP&L’s rate structure and its ability to recover amounts for environmental compliance, POLR obligations, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates; and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

Our increased costs due to advanced energy and energy efficiency requirements may not be fully recoverable in the future.

SB 221 contains targets relating to advanced energy, renewable energy, peak demand reduction and energy efficiency standards. The standards require that, by the year 2025 and each year thereafter, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including solar energy. Annual renewable energy standards began in 2009 with increases in required percentages each year through 2024. The advanced energy standard must be met by 2025 and each year thereafter. Annual targets for energy efficiency began in 2009 and require increasing energy reductions each year compared to a baseline energy usage, up to 22.3% by 2025. Peak demand reduction targets began in 2009 with increases in required percentages each year, up to 7.75% by 2018. The advanced energy and renewable energy standards have increased our power supply costs and are expected to continue to increase (and could materially increase) these costs. Pursuant to DP&L’s approved ESP, DP&L is entitled to recover costs associated with its alternative energy plans, as well as its energy efficiency and demand response programs. DP&L began recovering these costs in 2009. If in the future we are unable to timely or fully recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these standards, monetary penalties could apply. These penalties are not permitted to be recovered from customers and significant penalties could have a material adverse effect on our results of operations, financial condition and cash flows. The demand reduction and energy efficiency standards by design result in reduced energy and demand that could adversely affect our results of operations, financial condition and cash flows.

The availability and cost of fuel has experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from fuel availability and price volatility.

We purchase coal, natural gas and other fuel from a number of suppliers. The coal market in particular has experienced significant price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic issues like government-imposed direct costs and permitting issues that affect mining costs and supply availability, the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. Our approach is to hedge the fuel costs for our anticipated electric sales. However, we may not be able to hedge the entire exposure of our operations from fuel price volatility. As of the date of this report, DPL has substantially all of the total expected coal volume needed to meet its retail and firm wholesale sales requirements for 2011 under contract. Historically, some of our suppliers and buyers of fuel have not performed on their contracts and have failed to deliver or accept fuel as specified under their contracts. To the extent our suppliers and buyers do not meet their contractual commitments and, as a result of such failure or otherwise, we cannot secure adequate fuel or sell excess fuel in a timely or cost-effective manner or we are not hedged against price volatility, we could have a material adverse impact on our results of operations, financial condition and cash flows. In addition, DP&L is a co-owner of certain generation facilities where it is a non-operating owner. DP&L does not procure or have control over the fuel for these facilities, but is responsible for its proportionate share of the cost of fuel procured at these facilities. Co-owner operated facilities do not always have realized fuel costs that are equal to our co-owners’ projections, and we are responsible for our proportionate share of any increase in actual fuel costs. Pursuant to its ESP for SSO retail customers, DP&L implemented a fuel and purchased power recovery mechanism beginning on January 1, 2010, which subjects our recovery of fuel and purchased power costs to tracking and adjustment on a seasonal quarterly basis. If in the future we are unable to timely or fully recover our fuel costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our use of derivative and nonderivative contracts may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.

We transact coal, power and other commodities to hedge our positions in these commodities. These trades are impacted by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations, financial condition and cash flows. As part of our risk management, we use a variety of non-derivative and derivative instruments, such as swaps, futures and forwards, to manage our market risks. We also use interest rate derivative instruments to hedge against interest rate fluctuations related to our debt. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform, which could result in a material adverse effect on our results of operations, financial condition and cash flows.

The Dodd-Frank Act contains significant requirements related to derivatives that, among other things, could reduce the cost effectiveness of entering into derivative transactions.

In July 2010, The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the CFTC to establish rules to implement the Dodd-Frank Act’s requirements and exceptions. Requirements to post collateral could reduce the cost effectiveness of entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental liabilities.

Our operations and facilities (both wholly-owned and co-owned with others) are subject to numerous and extensive federal, state and local environmental laws and regulations relating to air quality (such as reductions in NOx, SO2 and particulate emissions), water quality, wastewater discharge, solid waste and hazardous waste. We could also become subject to additional environmental laws and regulations in the future (such as reductions in mercury and other hazardous air pollutants, SO3 (sulfur trioxide), regulation of ash generated from coal-based generating stations and reductions in greenhouse gas emissions as discussed in more detail in the next risk factor). With respect to our largest generation station, the J.M. Stuart Station, we are also subject to continuing compliance requirements related to NOx, SO2 and particulate matter emissions under DP&L’s consent decree with the Sierra Club. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources. These expenditures have been significant in the past and we expect that they could also be significant in the future. Complying with these numerous requirements could at some point become prohibitively expensive and result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Environmental laws and regulations also generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If we are not able to timely obtain, maintain or comply with all licenses, permits, inspections and approvals required to operate our business, then our operations could be prevented, delayed or subject to additional costs. Failure to comply with environmental laws, regulations and other requirements may result in the imposition of fines and penalties and the imposition of stricter environmental standards and controls and other injunctive measures affecting operating assets. In addition, any alleged violation of these laws, regulations and other requirements may require us to expend significant resources to defend against any such alleged violations. We own a non-controlling interest in several generating stations operated by our co-owners. As a non-controlling owner in these generating stations, we are responsible for our pro rata share of expenditures for complying with environmental laws, regulations and other requirements, but have limited control over the compliance measures taken by our co-owners. DP&L has an EIR in place as part of its existing rate plan structure, the last increase of which occurred in 2010 and remains at that level through 2012. In addition, DP&L’s ESP permits it to seek recovery for costs associated with new climate change or carbon regulations. While we expect to recover certain environmental costs and expenditures from customers, if in the future we are unable to fully recover our costs in a timely manner or the SSO retail riders are by-passable or additional customer switching occurs, we could have a material adverse impact to our results of operations, financial condition and cash flows. In addition, if we were found not to be in compliance with these environmental laws, regulations or requirements, any penalties that would apply would likely not be recoverable from customers and could have a material adverse effect on our results of operations, financial condition and cash flows.

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If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of Greenhouse Gasses on generation facilities, we could be required to make large additional capital investments.

There is an on-going concern nationally and internationally among regulators, investors and others concerning global climate change and the contribution of emissions of GHGs, including most significantly CO2. This concern has led to increased interest in legislation and action at the federal and state levels and litigation, including a declaration by the USEPA that GHGs pose a danger to the public health that the USEPA believes allows it to directly regulate greenhouse emissions. There have been various GHG legislative proposals introduced in Congress and there is growing consensus that some form of legislation of GHG emissions will be approved at the federal level that could result in substantial additional costs in the form of taxes or emission allowances. Approximately 99% of the energy we produce is generated by coal. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of CO2 and other GHGs on generation facilities, we could be required to make large additional capital investments. Legislation and regulations could also impair the value of our generation stations or make some of these stations uneconomical to maintain or operate and could raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing generation stations. Although DP&L is permitted under its current ESP to seek recovery of costs associated with new climate change or carbon regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows.

Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.

DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. During 2010 and 2009, DP&L realized net gains from these sales. Sales of coal are impacted by a range of factors, including price volatility among the different coal basins and qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate.

DP&L may sell its excess emission allowances, including NOx and SO2 emission allowances, from time to time. Sales of any excess emission allowances are impacted by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory available for sale and changes to the regulatory environment, including the status of the USEPA’s CAIR. These factors could cause the amount and price of excess emission allowances we sell to fluctuate, which could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period. There has been overall reduced trading activity in the annual NOx and SO2 emission allowance trading markets in recent years. This impact on the emission allowance trading market was due, in large part, to a court order calling into question the USEPA’s CAIR annual NOx and SO2 emission allowance trading programs and requiring the USEPA to issue new regulations to address the court order. The adoption of new regulations that could regulate emissions or establish or modify emission allowance trading programs, like the USEPA’s proposed Clean Air Transport Rule to replace CAIR, could impact the emission allowance trading markets and have a material effect on DP&L’s emission allowance sales.

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The operation and performance of our facilities are subject to various events and risks that could negatively impact our business.

The operation and performance of our generation, transmission and distribution facilities and equipment is subject to various events and risks, such as the potential breakdown or failure of equipment, processes or facilities, fuel supply or transportation disruptions, the loss of cost-effective disposal options for solid waste generated by our facilities (such as coal ash and gypsum), accidents, injuries, labor disputes or work stoppages by employees, operator error, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, performance below expected or required levels, weather-related and other natural disruptions, vandalism, events occurring on the systems of third parties that interconnect to and affect our system and the increased maintenance requirements, costs and risks associated with our aging generation units. Our results of operations, financial condition and cash flows could have a material adverse impact due to the occurrence or continuation of these events.

Diminished availability or performance of our transmission and distribution facilities could result in reduced customer satisfaction and regulatory inquiries and fines, which could have a material adverse effect on our results of operations, financial condition and cash flows. Operation of our owned and co-owned generating stations below expected capacity levels, or unplanned outages at these stations, could cause reduced energy output and efficiency levels and likely result in lost revenues and increased expenses that could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, since over 50% of our base-load generation is derived from co-owned generation stations operated by our co-owners, poor operational performance by our co-owners, misalignment of co-owners’ interests or lack of control over costs (such as fuel costs) incurred at these stations could have an adverse effect on us. We have constructed and placed into service FGD facilities at most of our base-load generating stations. If there is significant operational failure of the FGD equipment at the generating stations, we may not be able to meet emission requirements at some of our generating stations or, at other stations, it may require us to burn more expensive cleaner coal or utilize emission allowances. These events could result in a substantial increase in our operating costs. Depending on the degree, nature, extent, or willfulness of any failure to comply with environmental requirements, including those imposed by the Consent Decree, such non-compliance could result in the imposition of penalties or the shutting down of the affected generating stations, which could have a material adverse effect on our results of operations, financial condition and cash flows.

Asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. Although we believe that any asbestos at our facilities is contained and suitable, we have been named as a defendant in asbestos litigation, which at this time is not material to us. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

As an owner and operator of a bulk power transmission system, DP&L is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. In addition, DP&L is subject to Ohio reliability standards and targets. Compliance with reliability standards subjects us to higher operating costs or increased capital expenditures. While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the PUCO will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

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Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.

Weather conditions significantly affect the demand for electric power. In our Ohio service territory, demand for electricity is generally greater in the summer months associated with cooling and in the winter months associated with heating as compared to other times of the year. Unusually mild summers and winters could therefore have an adverse effect on our results of operations, financial condition and cash flows. In addition, severe or unusual weather, such as hurricanes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While DP&L is permitted to seek recovery of storm damage costs under its ESP, if DP&L is unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Our membership in a regional transmission organization presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.

On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM, a regional transmission organization. The price at which we can sell our generation capacity and energy is now dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM’s business rules. While we can continue to make bilateral transactions to sell our generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. To the extent we sell electricity into the power markets on a contractual basis, we are not guaranteed any rate of return on our capital investments through mandated rates. The PJM RPM base residual auction for the 2013/2014 and 2012/2013 periods cleared at a per megawatt price of $28/day and $16/day, respectively, for our RTO area. Prior to these auctions, the per megawatt prices for the 2011/2012 and 2010/2011 periods were $110/day and $174/day, respectively. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources. Auction prices could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows. We cannot predict the outcome of future auctions, but if the auction prices are sustained at low levels, our results of operations, financial condition and cash flows could have a material adverse impact.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenues and have a material adverse effect on our results of operations, financial condition and cash flows. We may be required to expand our transmission system according to decisions made by PJM rather than our internal planning process. While PJM transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place at FERC may cause transmission rates to change from time to time. In addition, PJM has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us. We also incur fees and costs to participate in PJM.

SB 221 includes a provision that allows electric utilities to seek and obtain deferral and recovery of RTO related charges. Therefore, most if not all of the above costs are currently being recovered through our SSO retail rates. If in the future, however, we are unable to defer or recover all of these cost in a timely manner, or the SSO retail riders are by-passable or additional customer switching occurs, our results of operations, financial condition and cash flows could have a material adverse impact.

As members of PJM, DP&L and DPLE are also subject to certain additional risks including those associated with the allocation among PJM members of losses caused by unreimbursed defaults of other participants in PJM markets and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and DPLE. These amounts could be significant and have a material adverse effect on our results of operations, financial condition and cash flows.

Costs associated with new transmission projects could have a material adverse effect on our results of operations, financial condition and cash flows.

Annually, PJM performs a review of the capital additions required to provide reliable electric transmission services throughout its territory. PJM traditionally allocated the costs of constructing these facilities to those entities that benefited directly from the additions. FERC orders issued in 2007 and thereafter modified the traditional method of allocating costs associated with new high voltage planned transmission facilities. FERC ordered that the cost of new high-voltage facilities be socialized across the PJM region. Various parties, including DP&L, challenged this allocation method and in 2009, the U.S. Court of Appeals, Seventh Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method and remanded the case to the FERC for further proceedings. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. The overall impact of FERC’s allocation methodology cannot be definitively assessed because not all new planned construction is likely to happen. The additional costs charged to DP&L for new large transmission approved projects were immaterial in 2010 and are not expected to be material in 2011. Over time, as more new transmission projects are constructed and if the allocation method is not changed, the annual costs could become material. Although we continue to maintain that the costs of these projects should be borne by the direct beneficiaries of the projects and that DP&L is not one of these beneficiaries, DP&L can, and currently is recovering these allocated costs from its SSO retail customers through the TCRR rider.

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Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows.

From time to time we rely on access to the credit and capital markets to fund certain of our operational and capital costs. These capital and credit markets have experienced extreme volatility and disruption and the ability of corporations to obtain funds through the issuance of debt or equity has been negatively impacted. Disruptions in the credit and capital markets make it harder and more expensive to obtain funding for our business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability. DP&L has variable rate debt that bears interest based on a prevailing rate that is reset weekly based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also currently maintain both cash on deposit and investments in cash equivalents that could be adversely affected by interest rate fluctuations. In addition, select debt of DPL and DP&L is currently rated investment grade by various rating agencies. If the rating agencies were to rate DPL and DP&L below investment grade, we would likely be required to pay a higher interest rate under certain existing and future financings and our potential pool of investors and funding sources would likely decrease. Our credit ratings also govern the collateral provisions of certain of our contracts, and a below investment grade credit rating by one of the rating agencies could require us to post cash collateral under these contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.

Poor investment performance of our benefit plan assets and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. The Pension Protection Act, enacted in August 2006, requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans at times have increased and may increase in the future. In addition, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the discounted liabilities increase, potentially increasing benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postretirement benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows.

Our businesses depend on counterparties performing in accordance with their agreements. If they fail to perform, we could incur substantial expense, which could adversely affect our liquidity, cash flows and results of operations.

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components (such as limestone for our FGD equipment), for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. These events could cause our results of operations, financial condition and cash flows to have a material adverse impact.

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Our stock price may fluctuate on account of a number of factors, many of which are beyond our control.

The market price of DPL’s common stock has fluctuated over a relatively wide range. Over the past three years, the market price of our common stock has fluctuated with a low of $19.16 and a high of $30.18. Our common stock in recent years has experienced significant price and volume variations that have often been unrelated to our operating performance. Over the previous year, the global markets have increasingly been characterized by substantially increased volatility in companies in a number of industries and in the broader markets. The market price of our common stock may continue to significantly fluctuate in the future and may be affected adversely by factors such as actual or anticipated change in our operating results, acquisition activity, changes in financial estimates by securities analysts, general market conditions, rumors and other factors, which factors may increase price volatility and be exacerbated by continued disruption in the global markets at large.

Our consolidated results of operations may be negatively affected by overall market, economic and other conditions that are beyond our control.

Economic pressures, as well as changing market conditions and other factors related to physical energy and financial trading activities, which include price, credit, liquidity, volatility, capacity, transmission and interest rates, can have a significant effect on our operations and the operations of our retail, industrial and commercial customers and our suppliers. The direction and relative strength of the economy has been increasingly uncertain due to softness in the real estate and mortgage markets, volatility in fuel and other energy costs, difficulties in the financial services sector and credit markets, high unemployment and other factors. Many of these factors have disproportionately impacted our Ohio service territory.

Our results of operations, financial condition and cash flows may be negatively affected by sustained downturns or a sluggish economy. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. During economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. In addition, our customers’ ability to pay us could also be impaired, which could result in an increase in receivables and write-offs of uncollectible accounts. Our suppliers could also be affected by the economic downturn resulting in supply delays or unavailability. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows.

The exercise of warrants would increase the number of common shares outstanding and increase our common share dividend costs, thus affecting any existing guidance on earnings per share and adversely affecting our financial condition and cash flows.

DPL’s warrant holders can exercise their warrants to purchase shares of DPL common stock at their discretion until March 12, 2012. As of the date of this report, the number of outstanding warrants is 1.7 million. As a result, DPL could be required to issue up to 1.7 million common shares in exchange for the receipt of the exercise price of $21.00 per share or pursuant to a cashless exercise process. The exercise of warrants would increase the number of common shares outstanding and increase our common share dividend payments.

Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing.

Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP in the United States of America, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the “Act”). Our internal controls and policies have been and continue to be closely monitored by management and our Board of Directors to ensure continued compliance with Section 404 of the Act. While we believe these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.

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New accounting standards or changes to existing accounting standards could materially impact how we report our results of operations, financial condition and cash flows.

Our Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our results of operations, financial condition and cash flows. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial condition. In addition, in preparing our Consolidated Financial Statements, management is required to make estimates and assumptions. Actual results could differ significantly from those estimates.

The SEC has issued a roadmap for the transition by U.S. public companies to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board that could result in significant changes to our accounting and reporting, such as in the treatment of regulatory assets and liabilities and property. Under the SEC’s proposed roadmap, we could be required to prepare financial statements in accordance with IFRS in 2015. The SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS. We are currently assessing the impact that this potential change would have on our Consolidated Financial Statements and we will continue to monitor the development of the potential implementation of IFRS.

If we are unable to maintain a qualified and properly motivated workforce, our results of operations, financial condition and cash flows could have a material adverse effect.

One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations, financial condition and cash flows could have a material adverse impact. In addition, we have employee compensation plans that reward the performance of our employees. While we seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing, and although we have policies and procedures in place to mitigate excessive risk-taking by employees; excessive risk-taking by our employees to achieve performance targets could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements and other employee workforce factors that could affect our businesses.

Over half of our employees are represented by a collective bargaining agreement that is in effect until October 31, 2011. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the bargaining agreement or at the expiration of the collective bargaining agreement before a new agreement is negotiated. Work stoppages by, or poor relations or ineffective negotiations with, our employees could have a material adverse effect on our results of operations, financial condition and cash flows.

Potential security breaches and terrorism could adversely affect our business.

Man-made problems, such as human error, computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In the course of our business, we also store and use certain of our customers’, employees’ and others’ personal information and other confidential and sensitive information. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover them in a timely way, we could be unable to fulfill critical business functions and sensitive and confidential information and other data could be compromised, which could result in negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief. These events could have a material adverse effect on our results of operations, financial condition and cash flows. Our third party service providers that provide critical business functions or have access to sensitive and confidential information and other data may also be vulnerable to security breaches and other man-made problems that could have an adverse effect on us. In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our business. Any such disruption could result in a material decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse effect on our results of operations, financial condition and cash flows. The continued threat of terrorism and heightened security and military action in response to this threat, or any future acts of terrorism, may cause further disruptions to the economies of the United States and other countries and create further uncertainties or otherwise materially harm our results of operations, financial condition and cash flows.

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DPL is a holding company and parent of DP&L and other subsidiaries. DPL’s cash flow is dependent on the operating cash flows of DP&L and its other subsidiaries and their ability to pay cash to DPL.

DPL is a holding company and its investments in its subsidiaries are its primary assets. A significant portion of DPL’s business is conducted by its DP&L subsidiary. As such, DPL’s cash flow is dependent on the operating cash flows of DP&L and its ability to pay cash to DPL. DP&L’s governing documents contain certain limitations on the ability to declare and pay dividends to DPL while preferred stock is outstanding. Certain of DP&L’s debt agreements also contain limits with respect to the ability of DP&L to loan or advance funds to DPL. In addition, DP&L is regulated by the PUCO that possesses broad oversight powers to ensure that the needs of utility customers are being met. While we are not currently aware of any plans to do so, the PUCO could attempt to impose restrictions on the ability of DP&L to pay cash to DPL pursuant to these broad powers. While we do not expect any foregoing restrictions to significantly affect DP&L’s ability to pay funds to DPL in the future, a significant limitation on DP&L’s ability to pay dividends or loan or advance funds to DPL would have a material adverse impact on DPL’s results of operations, financial condition and cash flows.

Item 1B — Unresolved Staff Comments

None

Item 2 — Properties

Information relating to our properties is contained in Item 1 — ELECTRIC OPERATIONS AND FUEL SUPPLY and Note 4 of Notes to Consolidated Financial Statements.

Substantially all property and plants of DP&L are subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated as of October 1, 1935 with the Bank of New York, as Trustee (Mortgage).

Item 3 - Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below) and to comply with applicable laws and regulations will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2010, cannot be reasonably determined.

As we have previously disclosed, on or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by a memorandum that had been sent on March 10, 2004, by DPL’s and DP&L’s Corporate Controller at the time to the Chairman of the Audit Committee of our Board of Directors expressing the Corporate Controller’s “concerns, perspectives and viewpoints” regarding financial reporting and governance issues within DPL and DP&L. On May 7, 2010, DPL received confirmation from the SEC’s Division of Enforcement that it had completed its investigation as to DPL and did not intend to recommend any action at this time.

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The following additional information is incorporated by reference into this Item: (i) information about the legal and other proceedings contained in Item 1 — COMPETITION AND REGULATION of Part 1 of this Annual Report on Form 10-K under the subheading “Ohio Retail Rates” and (ii) information about the legal proceedings contained in Item 8 — Note 16 of Notes to Consolidated Financial Statements of Part II of this Annual Report on Form 10-K under the subheadings “Litigation Involving Co-Owned Plants”, “Notices of Violation Involving Co-Owned Plants” and “Notices of Violation Involving Wholly-Owned Plants” of the section entitled Litigation, Notices of Violation and Other Matters Related to Air Quality and under the subheading “Regulation of Waste Disposal” under the sections entitled Regulation Matters Related to “Land Use and Solid Waste Disposal.”

Item 4 — Removed and Reserved

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of February 15, 2011, there were 19,792 holders of record of DPL common equity, excluding individual participants in security position listings. The following table presents the high and low per share sales prices for DPL common stock as reported by the New York Stock Exchange for each quarter of 2010 and 2009:

	2010				2009
	High		Low		High		Low
First Quarter	$	28.47	$	26.51	$	23.28	$	19.27
Second Quarter	$	28.18	$	23.80	$	23.46	$	21.18
Third Quarter	$	26.65	$	23.95	$	26.53	$	22.79
Fourth Quarter	$	27.51	$	25.33	$	28.68	$	25.16

DP&L’s common stock is held solely by DPL and, as a result, is not listed for trading on any stock exchange.

As long as DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its Common Stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2010, DP&L’s retained earnings of $616.9 million were all available for DP&L common stock dividends payable to DPL.

DPL paid regular quarterly cash dividends of $0.3025 and $0.2850 per share on our common stock during 2010 and 2009, respectively. The annualized dividend rate was $1.21 per share in 2010 and $1.14 per share in 2009.

On December 8, 2010, DPL’s Board of Directors authorized a quarterly dividend rate increase of approximately 10%, increasing the quarterly dividend per DPL common share from $0.3025 to $0.3325, effective with the next dividend declaration. If this dividend rate were maintained, the annualized dividend would increase from $1.21 per share to $1.33 per share. Additional information concerning dividends paid on DPL common stock is set forth under Selected Quarterly Information in Item 8 — Financial Statements and Supplementary Data.

Information regarding DPL’s equity compensation plans as of December 31, 2010 is disclosed in Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, which incorporates such information by reference from DPL’s proxy statement for the 2011 Annual Meeting of Shareholders.

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The following table details the repurchase by DPL of its common shares during the fourth quarter of 2010:

				Number of	Approximate dollar
				shares purchased	value of shares
	Number of	Average		as part of the	that could still be
	shares	price paid		Stock Repurchase	purchased under
Month (1)	purchased (2)	per share (3)		Program (4)	the program (4)

October	—	$	—	—	$	200,000,000
November	1,094,995	$	25.94	1,094,995	$	171,595,830
December	945,335	$	25.60	941,841	$	147,484,700
	2,040,330			2,036,836

(1) Based on a calendar month.

(2) Comprises shares purchased as part of DPL’s 2010 repurchase program and shares surrendered to DPL by employees to satisfy individual tax withholding obligations upon vesting of equity awards that are settled in DPL common stock. Shares totaling 3,494 were surrendered during the fourth quarter of 2010 to satisfy these individual tax withholding obligations.

(3) Average price paid per share reflects the individual trade price of repurchases under DPL’s current repurchase program as well as the closing price of DPL common stock on the vesting dates of the equity awards.

(4) On October 27, 2010, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. During the fourth quarter of 2010, DPL repurchased approximately 2.04 million shares of its common stock at an average price per share of $25.75. This Stock Repurchase Program will run through December 31, 2013 but may be modified or terminated at any time without notice.

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The graph below matches DPL’s cumulative 5-year total shareholder return on common stock with the cumulative total returns of the Dow Jones US Industrial Average index, the S&P Utilities index and the S&P Electric Utilities index. The graph tracks the performance of a $1,000 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 2005 to December 31, 2010.

	12/05		12/06		12/07		12/08		12/09		12/10

DPL Inc.	$	1,000.00	$	1,108.68	$	1,226.29	$	987.60	$	1,252.18	$	1,220.96
Dow Jones US Industrial Average	$	1,000.00	$	1,190.47	$	1,296.24	$	882.34	$	1,082.48	$	1,234.72
S&P Electric Utilities	$	1,000.00	$	1,232.11	$	1,516.95	$	1,125.05	$	1,163.05	$	1,202.99
S&P Utilities	$	1,000.00	$	1,209.90	$	1,444.37	$	1,025.78	$	1,147.94	$	1,210.62

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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Item 6 - Selected Financial Data

	For the years ended December 31,
($ in millions except per share amounts or as indicated)	2010			2009			2008			2007			2006

DPL

Basic earnings per share of common stock:
Continuing operations (a)	$	2.51		$	2.03		$	2.22		$	1.97		$	1.12
Discontinued operations (b) (c)	$	—		$	—		$	—		$	0.09		$	0.12
Total basic earnings per common share	$	2.51		$	2.03		$	2.22		$	2.06		$	1.24

Diluted earnings per share of common stock:
Continuing operations (a)	$	2.50		$	2.01		$	2.12		$	1.80		$	1.03
Discontinued operations (b) (c)	$	—		$	—		$	—		$	0.08		$	0.12
Total dilutive earnings per common share	$	2.50		$	2.01		$	2.12		$	1.88		$	1.15

Dividends declared per share	$	1.21		$	1.14		$	1.10		$	1.04		$	1.00
Dividend payout ratio	48.2		%	56.2		%	49.5		%	50.5		%	80.7		%

Total electric sales (millions of kWh)	17,237			16,667			17,172			18,598			18,418

Results of operations:
Revenues	$	1,883.1		$	1,588.9		$	1,601.6		$	1,515.7		$	1,393.5
Earnings from continuing operations, net of tax (a)	$	290.3		$	229.1		$	244.5		$	211.8		$	125.6
Earnings from discontinued operations, net of tax	$	—		$	—		$	—		$	10.0		$	14.0
Cumulative effect of accounting change, net of tax	$	—		$	—		$	—		$	—		$	—
Net income	$	290.3		$	229.1		$	244.5		$	221.8		$	139.6

Financial position items at December 31:
Total assets	$	3,813.3		$	3,641.7		$	3,637.0		$	3,566.6		$	3,612.2
Long-term debt (d)	$	1,026.6		$	1,223.5		$	1,376.1		$	1,541.5		$	1,551.8
Total construction additions	$	151.4		$	145.3		$	227.8		$	346.7		$	351.6
Redeemable preferred stock of subsidiary	$	22.9		$	22.9		$	22.9		$	22.9		$	22.9

Senior unsecured debt ratings at December 31:
Fitch Ratings	A-			A-			BBB+			BBB+			BBB
Moody’s Investors Service	Baa1			Baa1			Baa2			Baa2			Baa3
Standard & Poor’s Corporation	BBB+			BBB+			BBB-			BBB-			BB

Number of shareholders - common stock	19,877			20,888			21,628			22,771			24,434

DP&L

Total electric sales (millions of kWh)	17,083			16,590			17,105			18,598			18,418

Results of operations:
Revenues	$	1,790.5		$	1,550.4		$	1,572.9		$	1,507.4		$	1,385.2
Earnings on common stock (a)	$	276.8		$	258.0		$	284.9		$	270.7		$	241.6

Financial position items at December 31:
Total assets	$	3,475.4		$	3,457.4		$	3,397.7		$	3,276.7		$	3,090.3
Long-term debt (d)	$	884.0		$	783.7		$	884.0		$	874.6		$	785.2
Redeemable preferred stock	$	22.9		$	22.9		$	22.9		$	22.9		$	22.9

Senior secured debt ratings at December 31:
Fitch Ratings	AA-			AA-			A+			A+			A
Moody’s Investors Service	Aa3			Aa3			A2			A2			A3
Standard & Poor’s Corporation	A			A			A-			BBB+			BBB

Number of shareholders - preferred stock	234			242			256			281			290

(a)		In the fourth quarter of 2006, DPL entered into agreements to sell two of its peaking facilities resulting in a $44.2 million ($71 million pre-tax) impairment charge. The sale was finalized in April 2007. During 2006, DPL recorded a $37.3 million ($61.2 million pre-tax) charge for early redemption of debt. DP&L recorded a $2.5 million ($4.1 million pre-tax) charge for early redemption of debt in 2006. In May 2007, DPL settled the litigation with former executives resulting in a $19.7 million ($31 million pre-tax) gain. In April 2007, DPL also recouped legal costs associated with the litigation with the former executives from one of its insurers resulting in a $9.2 million ($14.5 million pre-tax) gain. In 2008, DPL sold coal and excess emission allowances to various counterparties, realizing net gains of $58.2 million ($83.4 million pre-tax) and $24.3 million ($34.8 million pre-tax), respectively. Also, in June 2008, DPL entered into a $42 million tax settlement with ODT resulting in a recorded income tax benefit of $8.5 million.
(b)		On February 13, 2005, DPL’s subsidiaries, MVE, Inc. (MVE) and MVIC, entered into an agreement to sell their respective interest in forty-six private equity funds. MVE and MVIC completed the sale of forty-three funds and a portion of another during 2005. The ownership interests to the remaining two funds and a portion of the third fund were transferred in 2006 and 2007, at which time DPL recognized previously deferred gains. $7.9 million ($4.9 million after tax) and $18.9 million ($12.1 million after tax) of these previously deferred gains were recognized in 2007 and 2006, respectively.
(c)		On May 21, 2007 DPL settled litigation with three former executives, the three former executives relinquished all of their rights to certain deferred compensation, restricted stock units, MVE incentives, stock options and reimbursement of legal fees. The reversal of accruals related to the performance of the financial asset portfolio was recorded in discontinued operations. A portion of the $25 million settlement expense was allocated to discontinued operations. These transactions resulted in a net gain of $8.1 million, net of associated expenses ($5.1 million after tax), on the settlement of litigation being recorded in discontinued operations in 2007.
(d)		Excludes current maturities of long-term debt.

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Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

Certain statements contained in this discussion are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including management’s expectations, strategic objectives, business prospects, anticipated economic performance and financial condition and other similar matters constitute forward-looking statements. Forward-looking statements are based on management’s beliefs, assumptions and expectations of future economic performance, taking into account the information currently available to management. These statements are not statements of historical fact and are typically identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will” and similar expressions. Such forward-looking statements are subject to risks and uncertainties, and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to: abnormal or severe weather and catastrophic weather-related damage; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, natural gas and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; performance of our suppliers; increased competition and deregulation in the electric utility industry; increased competition in the retail generation market; changes in interest rates; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels, rate structures or tax laws; changes in federal or state environmental laws and regulations to which DPL and its subsidiaries are subject; the development and operation of RTOs, including PJM to which DPL’s operating subsidiary (DP&L) has given control of its transmission functions; changes in our purchasing processes, pricing, delays, contractor and supplier performance and availability; significant delays associated with large construction projects; growth in our service territory and changes in demand and demographic patterns; changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; financial market conditions; the outcomes of litigation and regulatory investigations, proceedings or inquiries; general economic conditions; and the risks and other factors discussed in this report and other DPL and DP&L filings with the SEC.

Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based.

The following discussion should be read in conjunction with the accompanying Consolidated Financial Statements and related footnotes included in Item 8 — Financial Statements and Supplementary Data.

BUSINESS OVERVIEW

DPL is a regional electric energy and utility company. During 2010, DPL, for the first time, met the GAAP requirements for separate segment reporting. DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 17 of Notes to Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.

DP&L is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL’s and DP&L’s strategy is to match energy supply with load or customer demand, maximizing profits while effectively managing exposure to movements in energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost while maintaining the highest level of customer service and reliability.

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We operate and manage generation assets and are exposed to a number of risks. These risks include, but are not limited to, electricity wholesale price risk, PJM capacity price risk, regulatory risk, environmental risk, fuel supply and price risk, customer switching risk and the risk associated with power plant performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to coal source, cost structure and operating characteristics. We are focused on the operating efficiency of these power plants and maintaining their availability.

We operate and manage transmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.

Additional information relating to our risks is contained in Item 1A — Risk Factors.

We have identified certain issues that we believe may have a significant impact on our results of operations and financial condition in the future. The following issues mentioned below are not meant to be exhaustive but to provide insight on matters that are likely to have an effect on our results of operations and financial condition in the future:

REGULATORY ENVIRONMENT

· Carbon Emissions — Climate Change Legislation

There is an on-going concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly, CO2. This concern has led to interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions. In 2007, a U.S. Supreme Court decision upheld that the USEPA has the authority to regulate CO2 emissions from motor vehicles under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the CAA, which was finalized and published on December 15, 2009. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. In December 2009, USEPA finalized this endangerment finding with a regulatory effective date of January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision. This endangerment finding, if not changed, is expected to lead to the regulation of CO2 and other GHGs from electric generating units and other stationary sources of these emissions. Increased pressure for CO2 emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Legislation proposed in 2009 to target a reduction in the emission of GHGs from large sources was not enacted. Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. If legislation or regulations are passed at the federal or state levels that impose mandatory reductions of CO2 and other GHGs on generation facilities, the cost to DPL and DP&L of such reductions could be material.

· SB 221 Requirements

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. The standards require that, by the year 2025, 25% of the total number of kWh of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal and biomass. At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy. The renewable energy portfolio, energy efficiency and demand reduction standards began in 2009 with increased percentage requirements each year thereafter. The annual targets for energy efficiency and peak demand reductions began in 2009 with annual increases. Energy efficiency programs are to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage. If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.

SB 221 also contains provisions for determining whether an electric utility has significantly excessive earnings. On September 9, 2009, the PUCO issued an order establishing a significantly excessive earnings test (SEET) proceeding. After receiving comments from interested parties including DP&L, the PUCO issued an order on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material impact on operations. DP&L faces regulatory uncertainty from its next ESP or MRO filing which is scheduled to be filed in the first quarter of 2012 to be effective January 1, 2013. The filing may result in changes to the current rate structure and riders.

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· NOx and SO2 Emissions — CAIR

The USEPA issued CAIR on March 10, 2005 to regulate certain upwind states with respect to fine particulate matter and ozone. CAIR created interstate trading programs for annual NOx emission allowances and made modifications to an existing trading program for SO2 that were to take effect in 2010. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit issued a decision that vacated the USEPA CAIR and its associated Federal Implementation Plan. This decision remanded these issues back to the USEPA. The court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. On December 23, 2008, the court reversed part of its decision that vacated CAIR. Thus, CAIR currently remains in effect, but the USEPA remains subject to the court’s order to revise the program. On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) which will effectively replace CAIR. We have reviewed this proposal and submitted comments to the USEPA on September 30, 2010. At this time, we are unable to determine the overall financial impact that these rules could have on our operations in the future.

· Dodd-Frank Financial Reform Bill

In July 2010, the President signed The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) into law. The Dodd-Frank Act contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the CFTC to establish rules to implement the Act’s requirements and exceptions. Requirements to post collateral could reduce the cost-effectiveness of us entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits. The occurrence of any of these events could have an adverse effect on our results of operations, financial condition and cash flows.

COMPETITION AND PJM PRICING

· RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2013/2014 period cleared at a per megawatt price of $28/day for our RTO area. The per megawatt prices for the periods 2012/2013, 2011/2012 and 2010/2011 were $16/day, $110/day and $174/day, respectively, based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for demand response and energy efficiency resources in the RPM capacity auctions. The SSO retail costs and revenues are included in the RPM rider therefore increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but based on actual results attained in 2010, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would result in an annual impact to net income of approximately $4.4 million and $3.1 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

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· Ohio Competitive Considerations and Proceedings

Overall power market prices, as well as government aggregation initiatives within DP&L’s service territory, have led or may lead to the entrance of additional competitors in our service territory. During the year ended December 31, 2010, there were four additional unaffiliated marketers that registered as CRES providers in DP&L’s service territory, bringing the total number of CRES providers in DP&L’s service territory to eleven. DPLER, an affiliated company and one of the eleven registered CRES providers, has been marketing transmission and generation services to DP&L customers. During 2010, DPLER accounted for approximately 4,417 million kWh of the total 4,562 million kWh supplied by CRES providers within DP&L’s service territory. During 2010, 847 customers with an annual energy usage of 145 million kWh were supplied by other CRES providers within DP&L’s service territory, compared to 44 customers that had an annual energy usage of 16 million kWh during 2009. The volume supplied by DPLER represents approximately 31% of DP&L’s total distribution sales volume during 2010. The reduction to gross margin in 2010 as a result of customers switching to DPLER and other CRES providers was approximately $17 million and $53 million, for DPL and DP&L, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the impact this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

FUEL AND RELATED COSTS

· Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2011, we have hedged substantially all our coal requirements to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.

Effective January 2010, the SSO retail customers’ portion of fuel price changes, including coal requirements and purchased power costs, was reflected in the implementation of the fuel and purchased power recovery rider, subject to PUCO review. DP&L is currently undergoing an audit of its fuel and purchased power recovery rider and as a result there is some uncertainty as to the costs that will be approved for recovery. Independent third parties conduct the fuel audit in accordance with the PUCO standards. DP&L anticipates that some of this uncertainty will be resolved during the summer of 2011 after completion of the fuel audit. Based on the results of the audit, DP&L may record a favorable or unfavorable adjustment to earnings. It is too early to determine if any such adjustment would be material to our results of operations, financial condition and cash flows.

· Sales of Coal and Excess Emission Allowances

During the year ended December 31, 2010, DP&L sold coal and excess emission allowances to various counterparties realizing total net gains of $4.1 million and $0.8 million, respectively, compared to total net gains of $56.3 million and $5.0 million, respectively, realized over the same period in 2009. For 2010, these gains are recorded as a component of DP&L’s fuel costs and are reflected in operating income. Coal sales are impacted by a range of factors but can be largely attributed to the following: price volatility among the different coal basins or the quality of coal based on market conditions (coal optimization), variation in power demand, and the market price of power compared to the cost to produce power. Sales of excess emission allowances are impacted, among other factors, by: general economic conditions; fluctuations in market demand and pricing; availability of excess inventory available for sale; and changes to the regulatory environment in which we operate. The combined impact of these factors on our ability to sell coal and emission allowances in 2011 and beyond is not fully known at this time and could materially impact the amount of gains that will be recognized in the future. Effective January 2010, as part of the operation of the fuel and purchased power recovery rider, the SSO retail customers’ share of the emission gains and a portion of the SSO retail customers’ share of the coal gains were used to reduce the overall rate charged to customers.

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FINANCIAL OVERVIEW

The following financial overview relates to DPL, which includes its principal subsidiary DP&L. The results of operations for both DPL and DP&L are separately discussed in more detail following this financial overview.

For the year ended December 31, 2010, Net income for DPL was $290.3 million, or $2.50 per share, compared to Net income of $229.1 million, or $2.01 per share, for the same period in 2009. All EPS amounts are on a diluted share basis. The increase in net income compared to the prior year was primarily due to the following:

· an increase in retail rates primarily as a result of an increase in the EIR, TCRR and RPM riders combined with the implementation of the fuel and energy efficiency riders,

· an increase in sales volumes due to favorable weather and improved economic conditions,

· a decrease in the volume of fuel consumed due to decreased generation by our power plants,

· a net reduction in interest costs primarily as a result of certain redemptions of outstanding debt, and

· an increase in wholesale market prices.

Partially offsetting these items were:

· an increase in purchased power prices,

· a decrease in retail revenue due to pricing associated with competitively supplied customers,

· an increase in RTO capacity and other charges, net of RTO revenues, which includes the net impact of the deferral and recovery of costs under the TCRR and RPM riders,

· an overall decline in generating plant performance which resulted in a decrease in wholesale sales volume,

· a decrease in gains recognized from the sales of coal and excess emission allowances, and

· an increase in long-term disability and other operation and maintenance expenses.

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RESULTS OF OPERATIONS — DPL Inc.

DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. DP&L provides approximately 93% of DPL’s total consolidated gross margin. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.

Income Statement Highlights — DPL

	For the years ended December 31,
$ in millions	2010			2009			2008

Revenues:
Retail	$	1,456.5		$	1,229.0		$	1,223.3
Wholesale	142.3			122.5			149.9
RTO revenues	86.6			89.4			110.4
RTO capacity revenues	186.2			136.3			106.9
Other revenues	11.5			11.7			11.1
Total revenues	$	1,883.1		$	1,588.9		$	1,601.6

Cost of revenues:
Fuel costs	$	388.8		$	391.7		$	361.2
Gains from sale of coal	(4.1		)	(56.3		)	(83.4		)
Gains from sale of emission allowances	(0.8		)	(5.0		)	(34.8		)
Net fuel	383.9			330.4			243.0

Purchased power	82.1			46.9			148.7
RTO charges	113.4			100.9			127.8
RTO capacity charges	191.9			112.4			100.9
Net purchased power	387.4			260.2			377.4

Total cost of revenues	$	771.3		$	590.6		$	620.4

Gross margins (a)	$	1,111.8		$	998.3		$	981.2

Gross margin as a percentage of revenues	59.0		%	62.8		%	61.3		%

Operating income	$	504.4		$	428.2		$	435.5

Earnings per share of common stock:
Basic EPS from operations	$	2.51		$	2.03		$	2.22
Diluted EPS from operations	2.50			2.01			2.12

(a) For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

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Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, our retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Cooling degree days typically have a more significant impact than heating degree days since some residential customers do not use electricity to heat their homes.

	For the years ended December 31,
Number of days	2010	2009	2008

Heating degree days (a)	5,636	5,561	5,811
Cooling degree days (a)	1,245	734	853

(a) Heating and cooling degree days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the difference of the average actual daily temperature below 65 degrees Fahrenheit. If the average temperature on March 20th was 40 degrees Fahrenheit, the heating degrees for that day would be the 25 degree difference between 65 degrees and 40 degrees. In a similar manner, cooling degrees in a day are the difference of the average actual daily temperature in excess of 65 degrees Fahrenheit.

Since we plan to utilize our internal generating capacity to supply our retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa. The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting our wholesale sales volume each hour of the year include: wholesale market prices; our retail demand; retail demand elsewhere throughout the entire wholesale market area; our plants’ and other utility plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. Our plan is to make wholesale sales when market prices allow for the economic operation of our generation facilities not being utilized to meet our retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

The following table provides a summary of changes in revenues from prior periods:

$ in millions	2010 vs. 2009			2009 vs. 2008

Retail
Rate	$	148.0		$	119.6
Volume	78.4			(113.5		)
Other	1.1			(0.4		)
Total retail change	$	227.5		$	5.7

Wholesale
Rate	$	31.5		$	(87.0	)
Volume	(11.7		)	59.6
Total wholesale change	$	19.8		$	(27.4	)

RTO capacity and other
RTO capacity and other revenues	$	46.9		$	9.0

Total revenues change	$	294.2		$	(12.7	)

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For the year ended December 31, 2010, Revenues increased $294.2 million, or 19%, to $1,883.1 million from $1,588.9 million in the same period of the prior year. This increase was primarily the result of higher average retail and wholesale rates, higher retail sales volume, and increased RTO capacity and other revenues, partially offset by lower wholesale sales volume. The revenue components for the year ended December 31, 2010 are further discussed below:

· Retail revenues increased $227.5 million resulting primarily from an 11% increase in average retail rates due largely to the implementation of the fuel and energy efficiency riders, an increase in the TCRR and RPM riders, combined with the incremental effect of the recovery of costs under the EIR. This increase in the average retail rates was partially offset by the effect of lower rates due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume had a 6% increase compared to those in the prior year period largely due to more favorable weather and improved economic conditions. The favorable weather conditions resulted in a 70% increase in the number of cooling degree days to 1,245 days from 734 days in 2009. The above resulted in a favorable $148.0 million retail price variance and a favorable $78.4 million retail sales volume variance.

· Wholesale revenues increased $19.8 million primarily as a result of a 28% increase in wholesale average prices, partially offset by a 10% decrease in wholesale sales volume which was largely a result of lower generation by our power plants and increased retail sales volume. This resulted in a favorable $31.5 million wholesale price variance partially offset by an unfavorable wholesale sales volume variance of $11.7 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $46.9 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $49.9 million increase in revenues realized from the PJM capacity auction, partially offset by a $3.0 million decrease in transmission, congestion and other revenues.

For the year ended December 31, 2009, Revenues decreased $12.7 million, or 1%, to $1,588.9 million from $1,601.6 million in the prior year. This decrease was primarily the result of lower retail sales volume as well as decreased wholesale average prices, partially offset by higher average retail rates, increased wholesale sales volume and an increase in RTO capacity and other revenues. The revenue components for the year ended December 31, 2009 are further discussed below:

· Retail revenues increased $5.7 million resulting primarily from an 11% increase in average retail rates due largely to the incremental effect of the recovery of costs under the EIR combined with the implementation of the TCRR, RPM, Energy Efficiency and Alternative Energy riders, partially offset by a 9% decrease in sales volume driven largely by the effects of the economic recession and milder weather conditions. The milder weather conditions saw heating and cooling degree days decrease by 4% and 14% to 5,561 days and 734 days, respectively. As a result, retail revenues had a favorable $119.6 million price variance and an unfavorable $113.5 million sales volume variance.

· Wholesale revenues decreased $27.4 million primarily as a result of a 42% decrease in wholesale average prices partially offset by a 40% increase in sales volume, resulting in an unfavorable $87.0 million wholesale price variance and a favorable $59.6 million sales volume variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves as well as capacity payments under the RPM construct, increased $9.0 million compared to the same period in the prior year. This increase was primarily the result of additional revenue of $29.4 million that was realized from the PJM capacity auction, partially offset by a decrease in PJM transmission and congestion revenues of $21.0 million.

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DPL — Cost of Revenues

For the year ended December 31, 2010:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $53.5 million, or 16%, compared to 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the year ended December 31, 2010, DP&L realized $4.1 million and $0.8 million in gains from the sale of coal and excess emission allowances, respectively, compared to $56.3 million and $5.0 million, respectively, realized during the same period in 2009. The effect of these lower gains was partially offset by the impact of a 2% decrease in the volume of generation by our plants.

· Net purchased power increased $127.2 million, or 49%, compared to the same period in 2009 due largely to an increase of $92.0 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $37.7 million increase related to higher average market prices for purchased power, partially offset by a $2.5 million decrease associated with lower purchased power volumes. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

For the year ended December 31, 2009:

· Net fuel costs, which include coal gas, oil and emission allowances costs, increased $87.4 million, or 36%, compared to 2008, primarily due to the impact of lower gains realized from the sales of coal and excess emission allowances combined with a 7% increase in the usage of fuel due mainly to the improved performance of our generating facilities. In 2009, DP&L realized $56.3 million and $5.0 million in gains from the sales of coal and excess emission allowances, respectively, compared to $83.4 million and $34.8 million, respectively, during 2008. Also contributing to the increase in fuel costs was a 2% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from higher market prices of coal combined with outages at lower-cost units.

· Net purchased power decreased $117.2 million compared to 2008. The net decrease in purchased power was due in part to lower volumes of purchased power and lower average market rates of $72.3 million and $29.5 million, respectively. The improved performance of our generating facilities, as mentioned in the preceding paragraph, resulted in increased generation output and a reduced demand for higher-cost purchased power. Also contributing to the decrease in purchased power were lower costs relating to other RTO charges as well as the net deferral during 2009 of costs relating to DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. These decreases were partially offset by increased RTO capacity charges. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

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DPL - Operation and Maintenance

$ in millions	2010 vs. 2009
Energy efficiency programs (1)	$	11.1
Health insurance / long-term disability	8.9
Low-income payment program (1)	5.2
Pension	4.0
Generating facilities operating and maintenance expenses	3.8
Insurance settlement, net	(3.4		)
Other, net	4.5
Total operation and maintenance expense	$	34.1

(1) There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.

During the year ended December 31, 2010, Operation and maintenance expense increased $34.1 million, or 11%, compared to the same period in 2009. This variance was primarily the result of:

· higher expenses relating to energy efficiency programs that were put in place for our customers during 2009 and 2010,

· increased health insurance and disability costs primarily due to a number of employees going on long-term disability,

· increased assistance for low-income retail customers which is funded by the USF revenue rate rider,

· increased pension costs due largely to a decline in the values of pension plan assets during 2008 and increased benefit costs, and

· increased expenses for generating facilities largely due to unplanned outages at jointly-owned production units.

These increases were partially offset by:

· an insurance settlement that reimbursed us for legal costs associated with our litigation against certain former executives.

$ in millions	2009 vs. 2008
Pension	$	6.2
Low-income payment program (1)	6.1
Energy efficiency programs (1)	5.9
Deferred compensation	4.1
ESOP	3.3
Health insurance	3.2
Deferred 2004/2005 storm costs and PJM administrative fees	(4.0		)
Generating facilities operating and maintenance expenses	(1.4		)
Other, net	0.6
Total operation and maintenance expense	$	24.0

(1) There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.

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During the year ended December 31, 2009, Operation and maintenance expense increased $24.0 million, or 8%, compared to 2008. This variance was primarily the result of:

· higher pension costs due largely to a decline in the values of pension plan assets from 2008 and increased benefit costs,

· increases in assistance for low-income retail customers which is funded by the USF revenue rate rider,

· expenses related to new energy efficiency programs put in place for our customers during 2009,

· increased deferred compensation costs,

· increases in employee benefit expense funded by the ESOP, and

· increased health insurance costs that were partially related to higher disability costs.

These increases were partially offset by:

· lower amortization of regulatory assets related to the 2004/2005 deferred storm costs and PJM administrative fees in 2009 as these deferred costs were fully recovered through rates during 2008 and in the first quarter of 2009, respectively, and

· decreases in expenses for generating facilities largely due to unplanned outages in 2008 at lower-cost production units resulting in higher costs in that year. These decreases were partially offset by increased maintenance expenses associated with unplanned outages at jointly-owned production units during 2009.

DPL — Depreciation and Amortization

During the year ended December 31, 2010, Depreciation and amortization expense decreased $6.1 million, or 4%, as compared to 2009. The decrease primarily reflects the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by approximately $4.8 million during the year ended December 31, 2010.

During the year ended December 31, 2009, Depreciation and amortization expense increased $7.8 million, or 6%, as compared to 2008 primarily as a result of higher asset balances at the generating stations. These higher balances were due largely to the completion of the FGD projects during 2008.

DPL — General Taxes

During the year ended December 31, 2010, General taxes increased $9.3 million, or 8%, as compared to 2009. These increases were primarily the result of higher property tax accruals in 2010 compared to 2009, increased state excise taxes due to increased revenue and an adjustment to future credits against state gross receipt taxes.

During the year ended December 31, 2009, General taxes decreased $7.4 million, or 6%, as compared to 2008 primarily due to lower property tax accruals in 2009 compared to 2008 and lower kWh excise taxes resulting from lower retail sales volumes.

DPL — Investment Income (Loss)

During the year ended December 31, 2010, Investment income (loss) increased $2.4 million as compared to 2009 primarily as a result of the $1.4 million expense incurred in 2009 related to the early redemption of debt (see subsequent paragraph below). In addition, DPL had higher cash and short-term investment balances in 2010 compared to 2009 which resulted in higher investment income.

During the year ended December 31, 2009, Investment income (loss) decreased $4.2 million, or 117%, as compared to 2008 primarily as a result of lower cash and short-term investment balances combined with overall lower market yields on investments in 2009. In addition, we also recorded a $1.4 million expense during 2009 related to a loss incurred upon the early redemption of a debt obligation.

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DPL — Interest Expense

During the year ended December 31, 2010, Interest expense decreased $12.4 million, or 15%, as compared to 2009 primarily due to the early redemption in December 2009 of $52.4 million of the $195 million 8.125% Note to DPL Capital Trust II and the redemption of DPL’s $175 million 8.00% Senior Notes in March 2009. A premium of $3.7 million was incurred as an expense in 2009 upon the early debt redemption of $52.4 million referred to above.

During the year ended December 31, 2009, Interest expense decreased $7.7 million, or 8%, compared to 2008 primarily due to:

· a $12.8 million reduction in Interest expense due to the redemption of DPL’s $175 million 8.00% Senior Notes and the $100 million 6.25% Senior Notes in March 2009 and May 2008, respectively,

· a $1.6 million write-off in 2008 of unamortized debt issuance costs relating to DP&L’s $90 million variable rate pollution control bonds following their repurchase from the bondholders in April 2008, and

· $2.0 million of deferred interest carrying costs on regulatory assets primarily associated with the 2008 incremental storm costs and the riders for RPM and TCRR.

The above decreases were partially offset by $6.4 million of lower capitalized interest in 2009 compared to 2008, due largely to the completion of the FGD projects at our DP&L and partner-operated generating stations, as well as a $3.7 million premium paid upon the early redemption of $52.4 million of DPL’s Note to DPL Capital Trust II.

DPL — Income Tax Expense

During the year ended December 31, 2010, Income tax expense increased $30.5 million, or 27%, as compared to 2009 primarily due to increases in pre-tax income.

During the year ended December 31, 2009, Income tax expense increased $9.6 million, or 9%, as compared to 2008, due to estimate to actual adjustments of 2008 taxes related to the Internal Revenue Code Section 199 deduction, adjustments to deferred tax liabilities and a 2008 settlement relating to the Ohio Franchise Tax. These increases were partially offset by a decrease in pre-tax book earnings, estimate to actual adjustments of 2008 state tax liabilities, adjustments to our current tax receivables and the phase-out of the Ohio Franchise Tax.

RESULTS OF OPERATIONS BY SEGMENT — DPL Inc.

Utility Segment

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

Competitive Retail Segment

The Competitive Retail segment is comprised of DPLER’s competitive retail electric service business which sells retail electric energy under contract primarily to commercial and industrial customers who have selected DPLER as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately 9,000 customers currently located throughout Ohio. Due to increased competition in Ohio, during 2010 we increased the number of employees and resources assigned to manage DPLER and increased its marketing to customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. During 2010, we implemented a new wholesale agreement between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on the market prices for wholesale power. In periods prior to 2010, DPLER’s purchases from DP&L were transacted at prices that approximated DPLER’s sales prices to its end-use retail customers. The Competitive Retail segment has no transmission or generation assets. The operations of DPLER are not subject to rate regulation by federal or state regulators.

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Other

Included within Other are other businesses that do not meet the GAAP requirements for separate disclosure as reportable segments as well as certain corporate costs which include interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin. In the discussions which follow, we have not provided extensive discussions of the results of operations related to 2009 and 2008 for the Competitive Retail segment because we believe that financial information is not comparable to the 2010 financial information. We have, however, included brief descriptions of the Competitive Retail segment’s financial results for 2009 and 2008 for informational purposes as required by GAAP following the Income Statement Highlights table below.

See Note 17 of Notes to Consolidated Financial Statements for further discussion of DPL’s reportable segments.

The following table presents DPL’s gross margin by business segment:

	For the years ended December 31,									Increase (Decrease)
$ in millions	2010			2009			2008			2010 vs 2009			2009 vs 2008

Utility	$	1,035.1		$	967.6		$	961.6		$	67.5		$	6.0
Competitive Retail	38.5			0.7			0.2			37.8			0.5
Other	42.7			33.7			23.1			9.0			10.6
Adjustments and Eliminations	(4.5		)	(3.7		)	(3.7		)	(0.8		)	—
Total consolidated	$	1,111.8		$	998.3		$	981.2		$	113.5		$	17.1

The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects and for all periods presented, to those of DP&L which are included in this Form 10-K. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions below.

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Income Statement Highlights — Competitive Retail Segment

	For the years ended December 31,									Increase (Decrease)
$ in millions	2010			2009			2008			2010 vs 2009			2009 vs 2008

Revenues:
Retail	$	275.5		$	64.8		$	150.7		$	210.7		$	(85.9	)
RTO and other	1.5			0.7			0.1			0.8			0.6
	277.0			65.5			150.8			211.5			(85.3		)

Cost of revenues:
Purchased power	238.5			64.8			150.6			173.7			(85.8		)

Gross margins (a)	38.5			0.7			0.2			37.8			0.5

Operation and maintenance expense	7.8			2.7			0.9			5.1			1.8
Other expenses (income), net	1.4			1.5			(3.2		)	(0.1		)	4.7
Total expenses, net	9.2			4.2			(2.3		)	5.0			6.5

Earnings (Loss) from continuing operations before income tax	$	29.3		$	(3.5	)	$	2.5		$	32.8		$	(6.0	)
Income tax expense (benefit)	10.5			(0.8		)	0.6			11.3			(1.4		)
Net income (Loss)	$	18.8		$	(2.7	)	$	1.9		$	21.5		$	(4.6	)

Gross margin as a percentage of revenues	13.9		%	1.1		%	0.1		%

Competitive Retail Segment — Revenue

For the year ended December 31, 2010, the segment’s retail revenues increased $210.7 million, or 325%, as compared to 2009. The increase was primarily driven by increased levels of competition in the competitive retail electric service business in the state of Ohio which in turn has resulted in a significant number of DP&L’s retail customers switching their retail electric service to DPLER. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 4,546 million kWh of power to 9,002 customers during 2010 compared to 1,464 million kWh to 390 customers during 2009.

For the year ended December 31, 2009, the segment’s retail revenues decreased $85.9 million, or 57%, as compared to 2008. This decrease primarily reflected customers switching their retail electric service from DPLER back to DP&L due to the expiration of a significant number of customers’ service contracts at the end of 2008. As a result, the Competitive Retail segment sold approximately 1,464 million kWh of power to 390 customers during 2009 compared to 3,212 million kWh to 742 customers during 2008.

Competitive Retail Segment — Purchased Power

During the year ended December 31, 2010, the Competitive Retail segment purchased power increased $173.7 million, or 268%, as compared to 2009 primarily due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L. During 2010, we implemented a new wholesale agreement between DP&L and DPLER. Under this agreement, intercompany sales from DP&L to DPLER were based on the market prices for wholesale power. In periods prior to 2010, DPLER’s purchases from DP&L were transacted at prices that approximated DPLER’s sales prices to its end-use retail customers. This increase was partially offset by lower average prices paid for purchased power in 2010.

During the year ended December 31, 2009, purchased power decreased $85.8 million, or 57%, as compared to 2008. This decrease was primarily associated with lower 2009 retail volumes due to the expiration of some customers’ service contracts in 2008 as discussed under Competitive Retail Segment — Revenue above.

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Competitive Retail Segment — Operation and Maintenance

DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2010 as compared to 2009 and 2008 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

RESULTS OF OPERATIONS — The Dayton Power and Light Company (DP&L)

Income Statement Highlights — DP&L

	For the years ended December 31,
$ in millions	2010			2009			2008

Revenues:
Retail	$	1,185.4		$	1,167.2		$	1,075.3
Wholesale	365.8			181.9			293.5
RTO revenues	81.7			86.1			108.3
RTO capacity revenues	157.6			115.2			95.8
Total revenues	$	1,790.5		$	1,550.4		$	1,572.9

Cost of revenues:
Fuel costs	$	376.8		$	384.9		$	349.6
Gains from sale of coal	(4.1		)	(56.3		)	(83.4		)
Gains from sale of emission allowances	(0.8		)	(5.0		)	(34.8		)
Net fuel	371.9			323.6			231.4

Purchased power	82.0			46.9			152.4
RTO charges	109.7			99.9			126.6
RTO capacity charges	191.8			112.4			100.9
Net purchased power	383.5			259.2			379.9

Total cost of revenues	$	755.4		$	582.8		$	611.3

Gross margins (a)	$	1,035.1		$	967.6		$	961.6

Gross margin as a percentage of revenues	57.8		%	62.4		%	61.1		%

Operating income	$	450.2		$	421.9		$	436.6

(a) For purposes of discussing operating results, we present and discuss gross margins. This format is useful to investors because it allows analysis and comparability of operating trends and includes the same information that is used by management to make decisions regarding our financial performance.

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DP&L — Revenues

The following table provides a summary of changes in DP&L’s Revenues from prior periods:

$ in millions	2010 vs. 2009			2009 vs. 2008

Retail
Rate	$	(46.9	)	$	191.7
Volume	63.4			(99.7		)
Other	1.7			(0.1		)
Total retail change	$	18.2		$	91.9

Wholesale
Rate	$	75.0		$	(230.5	)
Volume	108.9			118.9
Total wholesale change	$	183.9		$	(111.6	)

RTO capacity and other
RTO capacity and other revenues	$	38.0		$	(2.8	)

Total revenues change	$	240.1		$	(22.5	)

For the year ended December 31, 2010, Revenues increased $240.1 million, or 15%, to $1,790.5 million from $1,550.4 million in the prior year. This increase was primarily the result of higher retail and wholesale sales volumes, higher average wholesale prices as well as increased RTO capacity and other revenues, partially offset by lower average retail rates. The revenue components for the year ended December 31, 2010 are further discussed below:

· Retail revenues increased $18.2 million primarily as a result of a 6% increase in retail sales volumes compared to those in the prior year period largely due to more favorable weather and improved economic conditions. The favorable weather conditions resulted in a 70% increase in the number of cooling degree days to 1,245 days from 734 days in 2009. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 4% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in a favorable $63.4 million retail sales volume variance and an unfavorable $46.9 million retail price variance.

· Wholesale revenues increased $183.9 million primarily as a result of a 26% increase in average wholesale prices combined with a 60% increase in wholesale sales volume due in large part to the effect of customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in a favorable $108.9 million wholesale sales volume variance and a favorable wholesale price variance of $75.0 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $38.0 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $42.4 million increase in revenues realized from the PJM capacity auction partially offset by a decrease of $4.4 million in transmission and congestion revenues.

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For the year ended December 31, 2009, Revenues decreased $22.5 million, or 1%, to $1,550.4 million from $1,572.9 million in the prior year. This decrease was primarily the result of lower wholesale average prices and lower retail sales volume, partially offset by higher average retail rates and increased wholesale sales volume. The revenue components for the year ended December 31, 2009 are further discussed below:

· Retail revenues increased $91.9 million resulting primarily from a 20% increase in average retail rates due largely to the incremental effect of the EIR and the implementation of the TCRR, RPM, energy efficiency and alternative energy riders, partially offset by a 9% decrease in retail sales volume driven largely by the effects of the economic recession and milder weather conditions. The milder weather conditions saw heating and cooling degree days decrease by 4% and 14% to 5,561 days and 734 days, respectively. As a result, retail revenues had a favorable $191.7 million price variance and an unfavorable $99.7 million sales volume variance.

· Wholesale revenues decreased $111.6 million primarily as a result of a 56% decrease in wholesale average prices, partially offset by a 41% increase in sales volume, resulting in an unfavorable $230.5 million wholesale price variance and a favorable $118.9 million sales volume variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, as well as capacity payments under the RPM construct, decreased $2.8 million compared to the prior year. This decrease primarily resulted from $22.2 million of lower transmission and congestion revenues, partially offset by additional revenue of $19.4 million that was realized from the PJM capacity auction.

DP&L — Cost of Revenues

For the year ended December 31, 2010:

· Net fuel costs, which include coal, gas, oil, and emission allowance costs, increased $48.3 million, or 15%, compared to 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the year ended December 31, 2010, DP&L realized $4.1 million and $0.8 million in gains from the sale of coal and excess emission allowances, respectively, compared to $56.3 million and $5.0 million, respectively, during 2009. The effect of these lower gains was partially offset by the impact of a 3% decrease in the volume of generation by our plants.

· Net purchased power increased $124.3 million, or 48%, compared to 2009, due largely to an increase of $89.2 million in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This increase included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $37.6 million increase related to higher average market prices for purchased power, partially offset by a $2.5 million decrease associated with lower purchased power volumes. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

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For the year ended December 31, 2009:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $92.2 million, or 40%, compared to 2008, primarily due to the impact of lower gains realized from the sales of coal and excess emission allowances combined with a 7% increase in the usage of fuel due mainly to the improved performance of our generating facilities. In 2009, DP&L realized $56.3 million and $5.0 million in gains from the sales of coal and excess emission allowances, respectively, compared to $83.4 million and $34.8 million, respectively, during 2008. Also contributing to the increase in fuel costs was a 3% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from higher market prices of coal combined with outages at lower-cost units.

· Net purchased power decreased $120.7 million compared to 2008. The net decrease in purchased power was due in part to lower volumes of purchased power and lower average market rates of $74.8 million and $30.8 million, respectively. The improved performance of our generating facilities, as mentioned in the preceding paragraph, resulted in increased generation output and a reduced demand for higher-cost purchased power. Also contributing to the decrease in purchased power were lower costs relating to other RTO charges as well as the net deferral during 2009 of costs relating to DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. This deferral is discussed in greater detail in Note 3 of Notes to Consolidated Financial Statements. These decreases were partially offset by increased RTO capacity charges. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

DP&L — Operation and Maintenance

$ in millions	2010 vs. 2009
Energy efficiency programs (1)	$	11.1
Health insurance / long-term disability	8.9
Low-income payment program (1)	5.1
Pension	4.0
Generating facilities operating and maintenance expenses	3.6
Other, net	4.0
Total operation and maintenance expense	$	36.7

(1) There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.

During the year ended December 31, 2010, Operation and maintenance expense increased $36.7 million, or 13%, compared to 2009. This variance was primarily the result of:

· higher expenses relating to energy efficiency programs that were put in place for our customers during 2009 and 2010,

· increased health insurance and disability costs primarily due to a number of employees going on long-term disability,

· increased assistance for low-income retail customers which is funded by the USF revenue rate rider,

· increased pension costs due largely to a decline in the values of pension plan assets during 2008 and increased benefit costs, and

· increased expenses for generating facilities largely due to unplanned outages at jointly-owned production units.

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$ in millions	2009 vs. 2008
Pension	$	6.1
Low-income payment program (1)	6.1
Energy efficiency programs (1)	5.9
ESOP	3.3
Health insurance	3.2
Deferred 2004/2005 storm costs and PJM administrative fees	(4.0		)
Generating facilities operating and maintenance expenses	(1.4		)
Other, net	1.2
Total operation and maintenance expense	$	20.4

(1) There is a corresponding increase in Revenues associated with these programs resulting in no impact to Net income.

During the year ended December 31, 2009, Operation and maintenance expense increased $20.4 million, or 7%, compared to 2008. This variance was primarily the result of:

· higher pension costs due largely to a decline in the values of pension plan assets from 2008 and increased benefit costs,

· increases in assistance for low-income retail customers which is funded by the USF revenue rate rider,

· expenses related to new energy efficiency programs put in place for our customers during 2009,

· increases in employee benefit expense funded by the ESOP, and

· increased health insurance costs that were partially related to higher disability costs.

These increases are partially offset by:

DP&L — Depreciation and Amortization

During the year ended December 31, 2010, Depreciation and amortization expense decreased $4.8 million as compared to 2009. The decrease primarily reflected the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by $3.4 million during the year ended December 31, 2010.

During the year ended December 31, 2009, Depreciation and amortization expense increased $7.7 million, or 6%, as compared to 2008 primarily as a result of higher asset balances at the generating stations. These higher balances were due largely to the completion of the FGD projects during 2008.

DP&L — General Taxes

During the year ended December 31, 2010, General taxes increased $7.3 million to $124.1 million compared to 2009. These increases were primarily the result of higher property tax accruals in 2010 compared to 2009, increased state excise taxes due to increased revenue and an adjustment to future credits against state gross receipt taxes.

During the year ended December 31, 2009, General taxes decreased $7.4 million, or 6%, compared to 2008 primarily due to lower property tax accruals in 2009 compared to 2008 and lower kWh excise taxes resulting from lower retail sales volumes.

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DP&L — Investment Income

Investment income realized during 2010 did not fluctuate significantly from that realized during 2009.

During the year ended December 31, 2009, Investment income decreased $4.2 million, or 60%, as compared to 2008 primarily as a result of lower gains realized from the sale of DPL common stock from DP&L’s Master Trust Plan used for deferred compensation distributions as well as lower cash and short-term investment balances combined with overall lower market yields on investments in 2009.

DP&L — Interest Expense

Interest expense recorded during 2010 did not fluctuate significantly from that recorded in 2009.

During the year ended December 31, 2009, Interest expense increased $2.0 million, or 5%, as compared to 2008 primarily as a result of $6.4 million of lower capitalized interest due largely to the completion of the FGD projects at our own and partner-operated generating stations. This increase was partially offset by:

· $2.0 million of deferred interest carrying costs on regulatory assets primarily associated with the 2008 incremental storm costs and the riders for RPM and TCRR. These Regulatory assets are further discussed in Note 3 of Notes to Consolidated Financial Statements.

DP&L — Income Tax Expense

During the year ended December 31, 2010, Income tax expense increased $10.7 million compared to 2009 primarily due to increases in pre-tax income.

During 2009, Income tax expense increased $4.3 million, or 4%, compared to 2008, due to estimate to actual adjustments of 2008 income taxes related to the Internal Revenue Code Section 199 deduction, adjustments to deferred tax liabilities and a 2008 settlement relating to the Ohio Franchise Tax. These increases were partially offset by a decrease in pre-tax book earnings, estimate to actual adjustments of 2008 state tax liabilities, adjustments to our current tax receivables and the phase-out of the Ohio Franchise Tax.

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FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

DPL’s financial condition, liquidity and capital requirements include the consolidated results of its principal subsidiary DP&L. All material intercompany accounts and transactions have been eliminated in consolidation. The following table provides a summary of the cash flows for DPL and DP&L:

DPL

	For the years ended December 31,
$ in millions	2010			2009			2008

Net cash provided by operating activities	$	464.2		$	524.7		$	361.2
Net cash used for investing activities	(220.6		)	(164.7		)	(252.9		)
Net cash used for financing activities	(194.5		)	(347.6		)	(180.7		)

Net change	$	49.1		$	12.4		$	(72.4	)
Cash and cash equivalents at beginning of period	74.9			62.5			134.9
Cash and cash equivalents at end of period	$	124.0		$	74.9		$	62.5

DP&L

	For the years ended December 31,
$ in millions	2010			2009			2008

Net cash provided by operating activities	$	446.4		$	513.7		$	392.7
Net cash used for investing activities	(148.6		)	(166.0		)	(240.1		)
Net cash used for financing activities	(300.9		)	(311.4		)	(145.0		)

Net change	$	(3.1	)	$	36.3		$	7.6
Cash and cash equivalents at beginning of period	57.1			20.8			13.2
Cash and cash equivalents at end of period	$	54.0		$	57.1		$	20.8

The significant items that have impacted the cash flows for DPL and DP&L are discussed in greater detail below:

Net Cash Provided by Operating Activities

The revenue from our energy business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes. Management believes that the diversified retail customer mix of residential, commercial and industrial classes coupled with rate relief approved by the PUCO provides us with a reasonably predictable gross cash flow from operations.

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DPL — Net Cash provided by Operating Activities

DPL’s Net cash provided by operating activities for the years ended December 31, 2010, 2009 and 2008 can be summarized as follows:

$ in millions	2010			2009			2008

Earnings from continuing operations	$	290.3		$	229.1		$	244.5
Depreciation and amortization	139.4			145.5			137.7
Deferred income taxes	59.9			201.6			43.1
Income tax settlement	—			—			(42.0		)
Contribution to pension plan	(40.0		)	—			—
Deferred regulatory costs, net	16.0			(24.6		)	(12.9		)
Other	(1.4		)	(26.9		)	(9.2		)
Net cash provided by operating activities	$	464.2		$	524.7		$	361.2

For the year ended December 31, 2010, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

· The $59.9 million increase to Deferred income taxes primarily results from changes related to pension contributions, depreciation expense and repair expense.

· DP&L contributed $40.0 million to the defined benefit pension plan in 2010.

· $16.0 million of cash collected to pay for fuel, purchased power and other fuel related costs and transmission, capacity and other PJM-related costs incurred during 2010, in excess of cash expenditures. These costs reduced the Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Consolidated Financial Statements) and are expected to reduce the amount to be collected from customers in future periods.

· Other represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances.

For the year ended December 31, 2009, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

· The $201.6 million increase to Deferred income taxes primarily results from the recognition of certain tax benefits for 2008 and 2009 relating to a change in the tax accounting method for deductions pertaining to repairs, depreciation and mixed service costs. Primarily due to the recognition of these benefits during 2009, DPL received a net cash refund of state and federal income taxes totaling $94.6 million and, in addition, was able to offset $69.0 million of these benefits against income tax liabilities accrued in 2009.

· $24.6 million of cash used primarily to pay for transmission, capacity and other PJM-related costs incurred during 2009, net of recoveries. These costs were recorded as a Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Consolidated Financial Statements) and are expected to be collected from customers during future years.

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For the year ended December 31, 2008, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

· Deferred income taxes increased by $43.1 million as a result of the acceleration of the deduction of newly installed FGD and SCR equipment for tax purposes, which had the effect of reducing current period income tax payments and increasing cash on hand.

· The $42 million cash payment made in 2008 to the ODT following a tax settlement agreement.

· $13.1 million of cash used to restore damage of a non-capital nature caused by the hurricane-force winds of September 2008 and other major 2008 storms. These costs were recorded as a Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Consolidated Financial Statements) and are expected to be collected from customers during future years.

DP&L — Net Cash provided by Operating Activities

DP&L’s Net cash provided by operating activities for the years ended December 31, 2010, 2009 and 2008 can be summarized as follows:

$ in millions	2010			2009			2008

Net income	$	277.7		$	258.9		$	285.8
Depreciation and amortization	130.7			135.5			127.8
Deferred income taxes	54.3			200.1			40.9
Income tax settlement	—			—			(42.0		)
Contribution to pension plan	(40.0		)	—			—
Deferred regulatory costs, net	16.0			(24.6		)	(12.9		)
Other	7.7			(56.2		)	(6.9		)
Net cash provided by operating activities	$	446.4		$	513.7		$	392.7

For the years ended December 31, 2010, 2009 and 2008, the significant components of DP&L’s Net cash provided by operating activities are similar to those discussed under DPL’s Net cash provided by operating activities above.

DPL and DP&L — Net Cash used for Investing Activities

DPL and DP&L’s Net cash used for investing activities for the years ended December 31, 2010, 2009 and 2008 can be summarized as follows:

$ in millions	2010			2009			2008
DP&L
Environmental and renewable energy capital expenditures	$	(11.9	)	$	(21.2	)	$	(90.2	)
Capital upgrades due to 2008 storms	—			—			(18.6		)
Other plant-related asset acquisitions	(138.1		)	(146.2		)	(133.2		)
Other	1.4			1.4			1.9
DP&L’s net cash used for investing activities	$	(148.6	)	$	(166.0	)	$	(240.1	)

Proceeds from sale of short-term investments	17.1			25.7			34.2
Purchases of short-term investments	(86.4		)	(20.7		)	(39.1		)
Other	(2.7		)	(3.7		)	(7.9		)
DPL’s net cash used for investing activities	$	(220.6	)	$	(164.7	)	$	(252.9	)

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For the year ended December 31, 2010, DP&L continued to see reductions in its environmental capital expenditures due to the completion of FGD and SCR projects including the FGD and SCR equipment completed and placed into service at Conesville during the fourth quarter of 2009. Approximately $4.2 million of the environmental capital expenditures incurred during 2010 relate to the construction of a solar energy facility at Yankee station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment. Additionally, DPL purchased $54.2 million of VRDN securities, net of redemptions from various institutional securities brokers as well as $15.1 million of investment-grade fixed income corporate bonds. The VRDN securities are backed by irrevocable letters of credit. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.

For the year ended December 31, 2009, DP&L continued to see reductions in its environmental-related capital expenditures due to the completion of FGD and SCR projects. The expenditures in 2009 relate to the construction of FGD and SCR equipment at the Conesville generation station which was substantially completed and placed into service during the fourth quarter of 2009. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment.

For the year ended December 31, 2008, DP&L saw reduced cash outflows associated with environmental-related expenditures compared to 2007 due to projects relating to the installation of FGD and SCR equipment that had either been completed or were nearing completion. In addition, DP&L was forced to replace a portion of its distribution lines and equipment following the damage caused by the hurricane-force winds of September 2008 and other 2008 storms.

DPL — Net Cash used for Financing Activities

DPL’s Net cash used for financing activities for the years ended December 31, 2010, 2009 and 2008 can be summarized as follows:

$ in millions	2010			2009			2008

Dividends paid on common stock	$	(139.7	)	$	(128.8	)	$	(120.5	)
Repurchase of DPL common stock	(56.4		)	(64.4		)	—
Retirement of long-term debt	—			(227.4		)	(100.0		)
Repurchase of warrants	—			(25.2		)	—
Proceeds from exercise of warrants	—			77.7			—
Cash withdrawn from restricted funds	—			14.5			32.5
Proceeds from exercise of stock options	1.4			9.0			2.2
Other	0.2			(3.0		)	5.1
Net cash used for financing activities	$	(194.5	)	$	(347.6	)	$	(180.7	)

For the year ended December 31, 2010, DPL paid common stock dividends of $139.7 million. In addition, under the stock repurchase programs approved by the Board of Directors in October 2009 and October 2010 (see Note 12 of Notes to Consolidated Financial Statements), DPL repurchased approximately 2.18 million DPL common shares for $56.4 million.

For the year ended December 31, 2009, DPL redeemed long-term debt totaling $227.4 million and paid common stock dividends of $128.8 million. Under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 12 of Notes to Consolidated Financial Statements), DPL repurchased approximately 2.4 million DPL common shares for $64.4 million. In addition, DPL repurchased 8.6 million warrants for $25.2 million. DPL’s cash inflows during the period include $77.7 million received from the cash exercise of 3.7 million warrants and the withdrawal of the remaining balance of restricted funds of $14.5 million which was used primarily to fund the construction of FGD equipment at the Conesville generation station. DPL also received $9.0 million from option holders who exercised stock options due, in part, to the increase in our average stock price compared to 2008.

For the year ended December 31, 2008, DPL paid common stock dividends of $120.5 million, retired $100 million of long-term debt and withdrew $32.5 million from restricted funds held in trust to pay for environmental-related capital expenditures.

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DP&L — Net Cash used for Financing Activities

DP&L’s Net cash used for financing activities for the years ended December 31, 2010, 2009 and 2008 can be summarized as follows:

$ in millions	2010			2009			2008

Dividends paid on common stock to parent	$	(300.0	)	$	(325.0	)	$	(155.0	)
Net loan (paid to) / received from parent	—			—			(20.0		)
Cash withdrawn from restricted funds	—			14.5			32.5
Other	(0.9		)	(0.9		)	(2.5		)
Net cash used for financing activities	$	(300.9	)	$	(311.4	)	$	(145.0	)

For the year ended December 31, 2010, DP&L’s Net cash used for financing activities primarily relates to $300 million in dividends.

For the year ended December 31, 2009, DP&L paid $325 million in dividends to DPL and withdrew the remaining balance of $14.5 million from restricted funds to pay for the Conesville FGD and SCR projects.

For the year ended December 31, 2008, DP&L paid $155 million in dividends to DPL, withdrew $32.5 million from restricted funds held in trust and repaid the net $20 million short-term loan from DPL.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated obligations. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities, taxes, interest and dividend payments. For 2011 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

At the filing date of this annual report on Form 10-K, DP&L has access to $420 million of short-term financing under two revolving credit facilities. The first facility for $220 million expires in November 2011 and has three participating banks; the lead bank has a total commitment of 36% while the other two have commitments of 32% each. The second facility, established in April 2010, is for $200 million and expires in April 2013. A total of five banks participate in this facility, with no bank having more than 35% of the total commitment.

					Amounts
					available at
$ in millions	Type	Maturity	Commitment		December 31, 2010

DP&L	Revolving	November 2011	$	220.0	$	220.0

DP&L	Revolving	April 2013	200.0		200.0
			$	420.0	$	420.0

Each revolving credit facility has a $50 million LOC sublimit. As of December 31, 2010 and through the date of filing this annual report on Form 10-K, there were no outstanding LOCs on either facility.

DPL’s $297.4 million 6.875% senior notes due September 2011 have been reflected as a current liability. Management will continue to monitor and evaluate market conditions over the next several months and make a determination to either seek to refinance the senior notes or explore alternative financing arrangements.

Cash and cash equivalents for DPL and DP&L amounted to $124.0 million and $54.0 million, respectively, at December 31, 2010. At that date, DPL also had short-term investments amounting to $69.3 million.

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On January 26, 2011, DPL signed an agreement with a third party to acquire $122.1 million of outstanding DPL Capital Trust II 8.125% trust preferred securities. The sale to DPL is contingent upon the third party’s ability to acquire the trust preferred securities.

In the event the third party is successful in acquiring the trust preferred securities, it has agreed to sell the trust preferred securities to DPL for a price of $134.3 million, plus any interest accrued through the date of closing. The closing is expected to occur on or before February 25, 2011. If this transaction closes, DPL expects to record a net loss on the reacquisition of the securities in the amount of approximately $15.3 million ($10.2 million net of tax) in the first quarter of 2011. Interest savings from the redemption of these securities are expected to be approximately $8.4 million ($5.6 million net of tax) for the remainder of 2011. DPL expects to finance this transaction using a combination of cash on hand and proceeds from the intended sale of some of its short-term investments.

In the event the third party is not able to acquire these securities, DPL will have no obligation to purchase these securities and will continue to carry these trust preferred securities as a long-term obligation on its Consolidated Balance Sheets.

Capital Requirements

CONSTRUCTION ADDITIONS

	Actual						Projected
$ in millions	2010		2009		2008		2011		2012		2013

DPL	$	151	$	145	$	228	$	310	$	260	$	200

DP&L	$	148	$	144	$	225	$	300	$	255	$	195

Planned construction additions for 2011 relate primarily to new investments in and upgrades to DP&L’s power plant equipment, and transmission and distribution system. Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors.

DPL, through its subsidiary DP&L, is projecting to spend an estimated $770 million in capital projects for the period 2011 through 2013. Approximately $20 million of this projected amount is to enable DP&L to meet the recently revised reliability standards of NERC. DP&L is subject to the mandatory reliability standards of NERC, and Reliability First Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. NERC has recently changed the definition of the Bulk Electric System (BES) to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. DP&L’s 138 kV facilities were previously not subject to these reliability standards. Accordingly, DP&L anticipates spending approximately $100 million within the next 5 years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Debt Covenants

As mentioned above, DP&L has access to $420 million of short-term financing under its two revolving credit facilities. The following financial covenant is contained in each revolving credit facility: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. As of December 31, 2010, this covenant was met with a ratio of 0.40 to 1.00. The above ratio is calculated as the sum of DP&L’s current and long-term portion of debt, including its guaranty obligations, divided by the total of DP&L’s shareholders’ equity and total debt including guaranty obligations.

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Credit Ratings

The following table outlines the debt credit ratings and outlook of each company, along with the effective dates of each rating and outlook for DPL and DP&L.

	DPL (a)	DP&L (b)	Outlook	Effective

Fitch Ratings	A-	AA-	Stable	October 2010
Moody’s Investors Service	Baa1	Aa3	Stable	June 2010
Standard & Poor’s Corp.	BBB+	A	Stable	April 2010

(a) Credit rating relates to DPL’s Senior Unsecured debt.

(b) Credit rating relates to DP&L’s Senior Secured debt.

Off-Balance Sheet Arrangements

DPL — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE and DPLER on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s and DPLER’s intended commercial purposes. During the year ended December 31, 2010, DPL did not incur any losses related to the guarantees of DPLE’s and DPLER’s obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s and DPLER’s obligations.

At December 31, 2010, DPL had $57.8 million of guarantees to third parties for future financial or performance assurance under such agreements, on behalf of DPLE and DPLER. The guarantee arrangements entered into by DPL with these third parties cover all present and future obligations of DPLE and DPLER to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $1.7 million at December 31, 2010 and $0.6 million at December 31, 2009.

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of December 31, 2010, DP&L could be responsible for the repayment of 4.9%, or $62.3 million, of a $1,272.2 million debt obligation that matures in 2026. This would only happen if this electric generation company defaulted on its debt payments. As of December 31, 2010, we have no knowledge of such a default.

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Commercial Commitments and Contractual Obligations

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2010, these include:

			Payment Year
$ in millions	Total		2011		2012-2013		2014-2015		Thereafter
DPL

Long-term debt	$	1,324.4	$	297.4	$	470.0	$	—	$	557.0
Interest payments	677.9		64.7		96.1		53.9		463.2
Pension and postretirement payments	258.5		23.8		51.0		52.0		131.7
Capital leases	0.2		0.1		0.1		—		—
Operating leases	0.9		0.4		0.3		0.2		—
Coal contracts (a)	1,409.0		415.2		501.3		177.6		314.9
Limestone contracts (a)	42.9		5.6		11.7		12.4		13.2
Purchase orders and other contractual obligations	141.5		71.1		56.0		11.7		2.7
Total contractual obligations	$	3,855.3	$	878.3	$	1,186.5	$	307.8	$	1,482.7

DP&L

Long-term debt	$	884.4	$	—	$	470.0	$	—	$	414.4
Interest payments	424.8		39.5		72.9		30.7		281.7
Pension and postretirement payments	258.5		23.8		51.0		52.0		131.7
Capital leases	0.2		0.1		0.1		—		—
Operating leases	0.9		0.4		0.3		0.2		—
Coal contracts (a)	1,409.0		415.2		501.3		177.6		314.9
Limestone contracts (a)	42.9		5.6		11.7		12.4		13.2
Purchase orders and other contractual obligations	142.7		72.2		56.1		11.7		2.7
Total contractual obligations	$	3,163.4	$	556.8	$	1,163.4	$	284.6	$	1,158.6

(a) Total at DP&L-operated units

Long-term debt:

DPL’s Long-term debt as of December 31, 2010, consists of DP&L’s first mortgage bonds and tax-exempt pollution control bonds and DPL’s unsecured senior notes. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

DP&L’s Long-term debt as of December 31, 2010, consists of its first mortgage bonds and tax-exempt pollution control bonds. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

See Note 5 of Notes to Consolidated Financial Statements.

Interest payments:

Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2010.

Pension and postretirement payments:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 7 of Notes to Consolidated Financial Statements. These estimated future benefit payments are projected through 2020.

Capital leases:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had one immaterial capital lease that expires in 2013.

Operating leases:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had several immaterial operating leases with various terms and expiration dates.

Coal contracts:

DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating plants it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

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Limestone contracts:

DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.

Purchase orders and other contractual obligations:

As of December 31, 2010, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

Reserve for uncertain tax positions:

Due to the uncertainty regarding the timing of future cash outflows associated with our unrecognized tax benefits of $19.4 million, we are unable to make a reliable estimate of the periods of cash settlement with the respective tax authorities and have not included such amounts in the contractual obligations table above.

MARKET RISK

We are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emissions and gas, changes in capacity prices and fluctuations in interest rates. We use various market risk sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Commodity Risk Management Committee (CRMC), comprising of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures relating to our DP&L-operated generation units. The CRMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.

Commodity Pricing Risk

Commodity pricing risk exposure includes the impacts of weather, market demand, increased competition and other economic conditions. To manage the volatility relating to these exposures at our DP&L-operated generation units, we use a variety of non-derivative and derivative instruments including forward contracts and futures contracts. These instruments are used principally for economic hedging purposes and none are held for trading purposes. Derivatives that fall within the scope of derivative accounting under GAAP must be recorded at their fair value and marked to market unless they qualify for cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur. We adjust the derivative instruments that do not qualify for cash flow hedging to fair value on a monthly basis and where applicable, we recognize a corresponding Regulatory asset for above-market costs or a Regulatory liability for below-market costs in accordance with regulatory accounting under GAAP.

The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2011 under contract, sales requirements may change, particularly for retail load. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic adjustments and some are priced based on market indices. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January 2010; our results of operations, financial condition or cash flows could be materially affected.

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In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), signed into law in July 2010, contains significant requirements relating to derivatives, including, among others, a requirement that certain transactions be cleared on exchanges that would necessitate the posting of cash collateral for these transactions. The Dodd-Frank Act provides a potential exception from these clearing and cash collateral requirements for commercial end-users. The Dodd-Frank Act requires the Commodity Futures Trading Commission to establish rules to implement the Dodd-Frank Act’s requirements and exceptions. Requirements to post collateral could reduce the cost-effectiveness of entering into derivative transactions to reduce commodity price and interest rate volatility or could increase the demands on our liquidity or require us to increase our levels of debt to enter into such derivative transactions. Even if we were to qualify for an exception from these requirements, our counterparties that do not qualify for the exception may pass along any increased costs incurred by them through higher prices and reductions in unsecured credit limits.

For purposes of potential risk analysis, we use a sensitivity analysis to quantify potential impacts of market rate changes on the statements of results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Commodity Derivatives

To minimize the risk of fluctuations in the market price of commodities, such as coal, power, and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counter-party at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months.

A 10% increase or decrease in the market price of our wholesale power forward contracts and heating oil forwards at December 31, 2010 would not have a significant effect on Net income.

The following table provides information regarding the volume and average market price of our NYMEX coal forward derivative contracts at December 31, 2010 and the effect to Net income if the market price were to increase or decrease by 10%:

NYMEX Coal Forwards	Contract Volume (in millions of Tons)	Weighted Average Market Price (per Ton)		Increase / Decrease in Net Income (in millions) (a)
2011-Purchase	1.0	$	80.30	$	1.4
2012-Purchase	2.9	$	83.53	$	4.8
2013-Purchase	0.1	$	86.08	$	0.5

(a) The Net Income effect of a 10% change in the market price of NYMEX Coal has been partially off-set by our partners’ share of the gain or loss associated with the jointly-owned power plants and also by the retail customers’ share of the gain or loss which is deferred on the balance sheet in conjunction with the fuel and purchased power recovery rider.

Wholesale Revenues

Approximately 17% of DPL’s and 16% of DP&L’s electric revenues for the year ended December 31, 2010 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

Approximately 16% of DPL’s and 15% of DP&L’s electric revenues for the year ended December 31, 2009 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

The table below provides the effect on annual Net income as of December 31, 2010, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):

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$ in millions	DPL		DP&L

Effect of 10% change in price per mWh	$	10.1	$	8.6

RPM Capacity Revenues and Costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year which runs from June 1 to May 31, has conducted auctions for capacity through the 2013/14 delivery year. The clearing prices for capacity during the PJM delivery periods from 2008/9 through 2013/14 are as follows:

	PJM Delivery Year
	2008/9	2009/10	2010/11	2011/12	2012/13	2013/14

Capacity clearing price ($/MW-day)	112	102	174	110	16	28

Our computed average capacity prices by calendar year are reflected in the table below:

	Calendar Year
	2009	2010	2011	2012	2013

Computed average capacity price ($/MW-day)	106	144	137	55	23

Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM’s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs. Although DP&L currently has an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Customer switching reduces the number of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.

The table below provides estimates of the effect on annual net income as of December 31, 2010, of a hypothetical increase or decrease of $10 in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the 2010 levels of customer switching. As of December 31, 2010, approximately 60% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions	DPL		DP&L

Effect of a $10 change in capacity auction pricing	$	4.4	$	3.1

Capacity revenues and costs are also impacted by, among other factors, the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.

Fuel and Purchased Power Costs

DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the years ended December 31, 2010 and 2009 were 34% and 33%, respectively. We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2011 under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2011; however, the exact consumption of SO2 allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOx allowances for 2011 depending on NOx emissions. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.

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Purchased power costs depend, in part, upon the timing and extent of planned and unplanned outages of our generating capacity. We will purchase power on a discretionary basis when wholesale market conditions provide opportunities to obtain power at a cost below our internal generation costs.

Effective January 1, 2010, DP&L was allowed to recover its SSO retail customers’ share of fuel and purchased power costs, of approximately 60% of retail sales, as part of the fuel rider approved by the PUCO. The table below provides the effect on annual net income as of December 31, 2010, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 60% recovery:

$ in millions	DPL		DP&L

Effect of 10% change in fuel and purchased power	$	13.0	$	12.6

Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL has fixed-rate long-term debt and DP&L has both fixed and variable-rate long-term debt. DP&L’s variable-rate debt is comprised of publicly held pollution control bonds. The variable-rate bonds bear interest based on a prevailing rate that is reset weekly based on a comparable market index. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions.

We partially hedge against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing. As of December 31, 2010, we have entered into interest rate hedging relationships with an aggregate notional amount of $200 million and $160 million related to planned future borrowing activities in calendar year 2011 and calendar year 2013, respectively. The average interest rate associated with the $200 million and $160 million aggregate notional amount interest rate hedging relationships is 4.1% and 3.8%, respectively. During the first quarter of 2011, we entered into additional interest rate hedging relationships with an aggregate notional amount of $75 million related to planned future borrowing activities in calendar year 2011. The average interest rate associated with the additional $75 million aggregate notional amount interest rate hedging relationships is 4.0%. We are limiting our exposure to changes in interest rates since we believe the market interest rates at which we will be able to borrow in the future may increase.

The carrying value of DPL’s debt was $1,324.1 million at December 31, 2010, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, DPL’s unsecured notes and DP&L’s capital lease. The fair value of this debt was $1,307.5 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

DPL

																			Carrying value at			Fair value at
																			December 31,			December 31,
$ in millions	2011			2012			2013			2014			2015			Thereafter			2010 (a)			2010 (a)
Long-term debt

Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0		$	100.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.3		%	0.3		%

Fixed-rate debt	$	297.5		$	0.1	(b)	$	470.0		$	—		$	—		$	456.5		$	1,224.1		$	1,207.5
Average interest rate	6.9		%	0.0		%	5.1		%	0.0		%	0.0		%	5.8		%	5.8		%

Total																			$	1,324.1		$	1,307.5

(a) Fixed rate debt totals include unamortized debt discounts.

(b) Amount represents a capital lease obligation.

The carrying value of DP&L’s debt was $884.1 million at December 31, 2010, consisting of its first mortgage bonds, tax-exempt pollution control bonds and a capital lease. The fair value of this debt was $850.6 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes:

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Principal Payments and Interest Rate Detail by Contractual Maturity Date

DP&L

																			Carrying value at			Fair value at
																			December 31,			December 31,
$ in millions	2011			2012			2013			2014			2015			Thereafter			2010 (a)			2010 (a)
Long-term debt

Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0		$	100.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.3		%	0.3		%

Fixed-rate debt	$	0.1	(b)	$	0.1	(b)	$	470.0		$	—		$	—		$	313.9		$	784.1		$	750.6
Average interest rate	0.0		%	0.0		%	5.1		%	0.0		%	0.0		%	4.8		%	5.0		%

Total																			$	884.1		$	850.6

(a) Fixed rate debt totals include unamortized debt discounts.

(b) Amount represents a capital lease obligation.

Debt maturities occurring in 2011 are discussed under FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS.

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at December 31, 2010 and 2009 for which an immediate adverse market movement causes a potential material impact on our financial condition, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of December 31, 2010 and 2009, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

DPL

	Carrying value at		Fair value at		One Percent		Carrying value at		Fair value at		One Percent
	December 31,		December 31,		Interest Rate		December 31,		December 31,		Interest Rate
$ in millions	2010		2010		Risk		2009		2009		Risk
Long-term debt

Variable-rate debt	$	100.0	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0

Fixed-rate debt	1,224.1		1,207.5		12.1		1,224.1		1,217.6		12.2

Total	$	1,324.1	$	1,307.5	$	13.1	$	1,324.1	$	1,317.6	$	13.2

DP&L

	Carrying value at		Fair value at		One Percent		Carrying value at		Fair value at		One Percent
	December 31,		December 31,		Interest Rate		December 31,		December 31,		Interest Rate
$ in millions	2010		2010		Risk		2009		2009		Risk
Long-term debt

Variable-rate debt	$	100.0	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0

Fixed-rate debt	784.1		750.6		7.5		784.3		744.5		7.5

Total	$	884.1	$	850.6	$	8.5	$	884.3	$	844.5	$	8.5

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed rate debt, the interest rate risk with respect to DPL’s long-term debt primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,224.1 million of fixed-rate debt and not on DPL’s financial condition or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DP&L’s $100 million variable-rate long-term debt outstanding as of December 31, 2010.

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DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $784.1 million of fixed-rate debt and not on DP&L’s financial condition or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100.0 million variable-rate long-term debt outstanding as of December 31, 2010.

Equity Price Risk

As of December 31, 2010, approximately 41% of the defined benefit pension plan assets were comprised of investments in equity securities and 59% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. The equity securities are carried at their market value of approximately $119.9 million at December 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $12.0 million reduction in fair value as of December 31, 2010 and approximately a $1.0 million increase to the 2011 pension expense.

Credit Risk

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We limit our credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continue to evaluate their creditworthiness after transactions have been originated. We use the three leading corporate credit rating agencies and other current market-based qualitative and quantitative data to assess the financial strength of counterparties on an ongoing basis. We may require various forms of credit assurance from counterparties in order to mitigate credit risk.

CRITICAL ACCOUNTING ESTIMATES

DPL’s and DP&L’s Consolidated Financial Statements are prepared in accordance with U.S. GAAP. In connection with the preparation of these financial statements, our management is required to make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and the related disclosure of contingent liabilities. These assumptions, estimates and judgments are based on our historical experience and assumptions that we believe to be reasonable at the time. However, because future events and their effects cannot be determined with certainty, the determination of estimates requires the exercise of judgment. Our critical accounting estimates are those which require assumptions to be made about matters that are highly uncertain.

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Impairments and Assets Held for Sale: In accordance with the provisions of GAAP relating to the accounting for impairments, long-lived assets to be held and used are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset. We determine the fair value of these assets based upon estimates of future cash flows, market value of similar assets, if available or independent appraisals, if required. In analyzing the fair value and recoverability using future cash flows, we make projections based on a number of assumptions and estimates of growth rates, future economic conditions, assignment of discount rates and estimates of terminal values. An impairment loss is recognized if the carrying amount of the long-lived asset is not recoverable from its undiscounted cash flows. The measurement of impairment loss is the difference between the carrying amount and fair value of the asset.

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Revenue Recognition (including Unbilled Revenue): We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. The determination of the energy sales to customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. We recognize revenues using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, projected line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Given our estimation method and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.

Income Taxes: Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since taxing authorities may interpret them differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to Net income and cash flows and adjustments to tax-related assets and liabilities could be material. We have adopted the provisions of GAAP relating to the accounting for uncertainty in income taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, these GAAP provisions establish standards for recognition and measurement in financial statements of positions taken, or expected to be taken, by an entity on its income tax returns. Positions taken by an entity on its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

Deferred income tax assets and liabilities represent future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets.

Regulatory Assets and Liabilities: Application of the provisions of GAAP relating to regulatory accounting requires us to reflect the effect of rate regulation in our Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as Regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize Regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenses that are not yet incurred. Regulatory assets are amortized into expense and Regulatory liabilities are amortized into income over the recovery period authorized by the regulator.

We evaluate our Regulatory assets to determine whether or not they are probable of recovery through future rates and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period the assessment is made. We currently believe the recovery of our Regulatory assets is probable. See Note 3 of Notes to Consolidated Financial Statements.

AROs: In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time.

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Insurance and Claims Costs: In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage solely to us, our subsidiaries and, in some cases, our partners in commonly-owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. Insurance and Claims Costs on the Consolidated Balance Sheets of DPL include insurance reserves of approximately $10.1 million and $16.2 million for 2010 and 2009, respectively. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has medical, life and disability reserves for claims costs below certain coverage thresholds of third-party providers. DPL and DP&L record these additional insurance and claims costs of approximately $19.0 million and $11.3 million for 2010 and 2009, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The MVIC reserves at DPL and the workers’ compensation, medical, life and disability reserves at DP&L are actuarially determined based on a reasonable estimation of insured events occurring. There is uncertainty associated with the loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

Pension and Postretirement Benefits: We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

For 2011, we have decreased our long-term rate of return assumption from 8.50% to 8.00% for pension plan assets. We are maintaining our long-term rate of return assumption of 6.00% for other postemployment benefit plan assets. These rates of return represent our long-term assumptions based on our current portfolio mixes. We have decreased our assumed discount rate to 5.31% from 5.75% for pension and to 4.96% from 5.35% for postretirement benefits expense to reflect current duration-based yield curve discount rates. A one percent change in the rate of return assumption for pension would result in an increase or decrease to the 2011 pension expense of approximately $2.9 million. A one percent change in the discount rate for pension would result in an increase or decrease to the 2011 pension expense of approximately $2.5 million. We do not anticipate any special adjustments to expense in 2011.

In future periods, differences in the actual return on pension and other post-employment benefit plan assets and assumed return, or changes in the discount rate, will affect the timing of contributions to the plans, if any. We provide postretirement health care benefits to employees who retired prior to 1987. A one percentage point change in the assumed health care cost trend rate would affect postretirement benefit costs by less than $1.0 million.

Contingent and Other Obligations: During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record reserves for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such reserves, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We, however, believe such estimates and assumptions are reasonable.

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LEGAL AND OTHER MATTERS

A discussion of LEGAL AND OTHER MATTERS is described in Note 16 of Notes to Consolidated Financial Statements and in Item 3 — LEGAL PROCEEDINGS. A discussion of environmental matters and competition and regulation matters affecting both DPL and DP&L is described in Item 1 — ENVIRONMENTAL CONSIDERATIONS and Item 1 — COMPETITION AND REGULATION. Such discussions are incorporated by reference in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

Recently Issued Accounting Pronouncements

A discussion of recently issued accounting pronouncements is described in Note 1 of Notes to Consolidated Financial Statements and such discussion is incorporated by reference in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and made a part hereof.

Item 7A — Quantitative and Qualitative Disclosures about Market Risk

The information required by this item of Form 10-K is set forth in the MARKET RISK section under Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8 — Financial Statements and Supplementary Data

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DPL INC.

CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	For the years ended December 31,
$ in millions except per share amounts	2010			2009			2008

Revenues	$	1,883.1		$	1,588.9		$	1,601.6

Cost of revenues:
Fuel	383.9			330.4			243.0
Purchased power	387.4			260.2			377.4
Total cost of revenues	771.3			590.6			620.4

Gross margin	1,111.8			998.3			981.2

Operating expenses:
Operation and maintenance	340.6			306.5			282.5
Depreciation and amortization	139.4			145.5			137.7
General taxes	127.4			118.1			125.5
Total operating expenses	607.4			570.1			545.7

Operating income	504.4			428.2			435.5

Other income / (expense), net
Investment income (loss)	1.8			(0.6		)	3.6
Interest expense	(70.6		)	(83.0		)	(90.7		)
Other income / (deductions)	(2.3		)	(3.0		)	(1.0		)
Total other income / (expense), net	(71.1		)	(86.6		)	(88.1		)

Earnings from continuing operations before income tax	433.3			341.6			347.4

Income tax expense	143.0			112.5			102.9

Net income	$	290.3		$	229.1		$	244.5

Average number of common shares outstanding (millions):
Basic	115.6			112.9			110.2
Diluted	116.1			114.2			115.4

Earnings per share of common stock:
Basic	$	2.51		$	2.03		$	2.22
Diluted	$	2.50		$	2.01		$	2.12

Dividends paid per share of common stock	$	1.21		$	1.14		$	1.10

See Notes to Consolidated Financial Statements.

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DPL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the years ended December 31,
$ in millions	2010			2009			2008
Cash flows from operating activities:
Net income	$	290.3		$	229.1		$	244.5
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	139.4			145.5			137.7
Deferred income taxes	59.9			201.6			43.1
Changes in certain assets and liabilities:
Accounts receivable	(1.5		)	39.3			(18.7		)
Inventories	10.4			(20.6		)	(0.2		)
Prepaid taxes	(9.0		)	—			—
Taxes applicable to subsequent years	(4.1		)	(1.5		)	(10.0		)
Deferred regulatory costs, net	16.0			(24.6		)	(12.9		)
Accounts payable	17.8			(65.0		)	27.0
Accrued taxes payable	1.2			(2.4		)	(46.1		)
Accrued interest payable	(5.1		)	(1.5		)	(0.8		)
Pension, retiree and other benefits	(58.2		)	15.2			31.2
Unamortized investment tax credit	(2.8		)	(2.8		)	(2.8		)
Insurance and claims costs	(6.1		)	(1.4		)	(2.4		)
Other	16.0			13.8			(28.4		)
Net cash provided by operating activities	464.2			524.7			361.2

Cash flows from investing activities:
Capital expenditures	(152.7		)	(172.3		)	(243.6		)
Proceeds from sale of property - other	—			1.2			—
Purchases of short-term investments and securities	(86.4		)	(20.7		)	(39.1		)
Sales of short-term investments and securities	17.1			25.7			34.2
Other investing activities, net	1.4			1.4			(4.4		)
Net cash used for investing activities	(220.6		)	(164.7		)	(252.9		)

Cash flows from financing activities:
Dividends paid on common stock	(139.7		)	(128.8		)	(120.5		)
Repurchase of DPL common stock	(56.4		)	(64.4		)	—
Repurchase of warrants	—			(25.2		)	—
Proceeds from exercise of warrants	—			77.7			—
Reissuance of treasury stock	—			—			6.4
Retirement of long-term debt	—			(175.0		)	(100.0		)
Early redemption of Capital Trust II notes	—			(52.4		)	—
Premium paid for early redemption of debt	—			(3.7		)	—
Issuance of pollution control bonds, net	—			—			98.4
Retirement of pollution control bonds	—			—			(90.0		)
Pollution control bond proceeds held in trust	—			—			(10.0		)
Withdrawal of restricted funds held in trust, net	—			14.5			32.5
Withdrawals from revolving credit facilities	—			260.0			115.0
Repayment of borrowings from revolving credit facilities	—			(260.0		)	(115.0		)
Exercise of stock options	1.4			9.0			2.2
Tax impact related to exercise of stock options	0.2			0.7			0.3
Net cash used for financing activities	(194.5		)	(347.6		)	(180.7		)

Cash and cash equivalents:
Net change	49.1			12.4			(72.4		)
Balance at beginning of period	74.9			62.5			134.9
Cash and cash equivalents at end of period	$	124.0		$	74.9		$	62.5

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	77.1		$	84.3		$	86.8
Income taxes (refunded) / paid, net	$	87.1		$	(94.6	)	$	127.3
Non-cash financing and investing activities:
Accruals for capital expenditures	$	23.2		$	20.8		$	34.1

See Notes to Consolidated Financial Statements.

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DPL INC.

CONSOLIDATED BALANCE SHEETS

	At December 31,
$ in millions	2010			2009

ASSETS

Current assets:
Cash and cash equivalents	$	124.0		$	74.9
Short-term investments	69.3			—
Accounts receivable, net (Note 2)	215.5			212.8
Inventories (Note 2)	115.3			125.7
Taxes applicable to subsequent years	63.7			59.5
Other prepayments and current assets	40.6			24.1
Total current assets	628.4			497.0

Property, plant and equipment:
Property, plant and equipment	5,353.6			5,269.2
Less: Accumulated depreciation and amortization	(2,555.2		)	(2,466.0		)
	2,798.4			2,803.2

Construction work in process	119.7			89.0
Total net property, plant and equipment	2,918.1			2,892.2

Other noncurrent assets:
Regulatory assets (Note 3)	189.0			214.2
Other deferred assets	77.8			38.3
Total other noncurrent assets	266.8			252.5

Total Assets	$	3,813.3		$	3,641.7

See Notes to Consolidated Financial Statements.

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DPL INC.

CONSOLIDATED BALANCE SHEETS

			At December 31,
$ in millions			2010			2009

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion - long-term debt (Note 5)			$	297.5		$	100.6
Accounts payable			98.7			77.2
Accrued taxes			68.1			70.2
Accrued interest			18.4			23.5
Customer security deposits			18.7			19.4
Other current liabilities			40.9			24.0
Total current liabilities			542.3			314.9

Noncurrent liabilities:
Long-term debt (Note 5)			1,026.6			1,223.5
Deferred taxes (Note 6)			625.4			569.1
Regulatory liabilities (Note 3)			139.4			125.4
Pension, retiree and other benefits			64.9			111.7
Unamortized investment tax credit			32.4			35.2
Insurance and claims costs			10.1			16.2
Other deferred credits			130.8			122.9
Total noncurrent liabilities			2,029.6			2,204.0

Redeemable preferred stock of subsidiary			22.9			22.9

Commitments and contingencies (Note 16)

Common shareholders’ equity:
Common stock, at par value of $0.01 per share:
	December 2010	December 2009
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	116,924,844	118,966,767	1.2			1.2
Warrants			2.7			2.9
Common stock held by employee plans			(12.5		)	(19.3		)
Accumulated other comprehensive loss			(18.9		)	(29.0		)
Retained earnings			1,246.0			1,144.1
Total common shareholders’ equity			1,218.5			1,099.9

Total Liabilities and Shareholders’ Equity			$	3,813.3		$	3,641.7

See Notes to Consolidated Financial Statements.

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DPL INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

								Common
								Stock			Accumulated
	Common Stock (b)							Held by			Other
	Outstanding							Employee			Comprehensive			Retained
in millions (except Outstanding Shares)	Shares		Amount		Warrants			Plans			Income / (Loss)			Earnings			Total

Beginning balance	113,558,444		$	1.1	$	50.0		$	(39.7	)	$	0.6		$	870.5		$	882.5

2008:
Net income														244.5
Change in unrealized gains (losses) on financial instruments, net of tax											(0.5		)
Change in deferred gains (losses) on cash flow hedges, net of tax											(1.7		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax											(21.5		)
Total comprehensive income																	220.8
Common stock dividends (a)														(120.5		)	(120.5		)
Treasury stock reissued	2,403,436		0.1		(19.0		)							21.2			2.3
Tax effects to equity														0.3			0.3
Employee / Director stock plans								12.1						(0.3		)	11.8
Other														(0.1		)	(0.1		)
Ending balance	115,961,880		$	1.2	$	31.0		$	(27.6	)	$	(23.1	)	$	1,015.6		$	997.1

2009:
Net income														229.1
Change in unrealized gains (losses) on financial instruments, net of tax											0.5
Change in deferred gains (losses) on cash flow hedges, net of tax											(3.7		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax											(2.7		)
Total comprehensive income																	223.2
Common stock dividends (a)														(128.8		)	(128.8		)
Repurchase of warrants					(13.6		)							(11.6		)	(25.2		)
Exercise of warrants	4,973,629				(14.5		)							92.2			77.7
Treasury stock purchased	(2,388,391	)												(64.4		)	(64.4		)
Treasury stock reissued	419,649													10.1			10.1
Tax effects to equity														0.8			0.8
Employee / Director stock plans								8.3						0.5			8.8
Other														0.6			0.6
Ending balance	118,966,767		$	1.2	$	2.9		$	(19.3	)	$	(29.0	)	$	1,144.1		$	1,099.9

2010:
Net income														290.3
Change in unrealized gains (losses) on financial instruments, net of tax											0.4
Change in deferred gains (losses) on cash flow hedges, net of tax											6.4
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax											3.3
Total comprehensive income																	300.4
Common stock dividends (a)														(139.7		)	(139.7		)
Repurchase of warrants					(0.2		)										(0.2		)
Exercise of warrants	18,288				—												—
Treasury stock purchased	(2,182,751	)												(56.4		)	(56.4		)
Treasury stock reissued	122,540													2.4			2.4
Tax effects to equity														0.2			0.2
Employee / Director stock plans								6.8						5.1			11.9
Ending balance	116,924,844		$	1.2	$	2.7		$	(12.5	)	$	(18.9	)	$	1,246.0		$	1,218.5

(a) Common stock dividends per share were $1.10 in 2008, $1.14 in 2009 and $1.21 per share in 2010.

(b) $0.01 par value, 250,000,000 shares authorized.

See Notes to Consolidated Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY

STATEMENTS OF RESULTS OF OPERATIONS

	For the years ended December 31,
$ in millions	2010			2009			2008

Revenues	$	1,790.5		$	1,550.4		$	1,572.9

Cost of revenues:
Fuel	371.9			323.6			231.4
Purchased power	383.5			259.2			379.9
Total cost of revenues	755.4			582.8			611.3

Gross margin	1,035.1			967.6			961.6

Operating expenses:
Operation and maintenance	330.1			293.4			273.0
Depreciation and amortization	130.7			135.5			127.8
General taxes	124.1			116.8			124.2
Total operating expenses	584.9			545.7			525.0

Operating income	450.2			421.9			436.6

Other income / (expense), net:
Investment income	1.7			2.8			7.0
Interest expense	(37.1		)	(38.5		)	(36.5		)
Other income (deductions)	(1.9		)	(2.8		)	(1.1		)
Total other income / (expense), net	(37.3		)	(38.5		)	(30.6		)

Earnings before income tax	412.9			383.4			406.0

Income tax expense	135.2			124.5			120.2

Net income	277.7			258.9			285.8

Dividends on preferred stock	0.9			0.9			0.9

Earnings on common stock	$	276.8		$	258.0		$	284.9

See Notes to Consolidated Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY

STATEMENTS OF CASH FLOWS

	For the years ended December 31,
$ in millions	2010			2009			2008
Cash flows from operating activities:
Net income	$	277.7		$	258.9		$	285.8
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	130.7			135.5			127.8
Deferred income taxes	54.3			200.1			40.9
Changes in certain assets and liabilities:
Accounts receivable	15.2			25.7			(3.5		)
Inventories	10.1			(20.5		)	(0.2		)
Prepaid taxes	(8.9		)	—			—
Taxes applicable to subsequent years	(3.6		)	(1.3		)	(9.9		)
Deferred regulatory costs, net	16.0			(24.6		)	(12.9		)
Accounts payable	16.9			(65.9		)	26.9
Accrued taxes payable	1.7			(0.9		)	(50.0		)
Accrued interest payable	(5.4		)	0.2			—
Pension, retiree and other benefits	(58.2		)	15.2			31.3
Unamortized investment tax credit	(2.8		)	(2.8		)	(2.8		)
Other	2.7			(5.9		)	(40.7		)
Net cash provided by operating activities	446.4			513.7			392.7

Cash flows from investing activities:
Capital expenditures	(150.0		)	(167.4		)	(242.0		)
Purchases of short-term investments and securities	1.4			1.4			1.9
Net cash used for investing activities	(148.6		)	(166.0		)	(240.1		)

Cash flows from financing activities:
Dividends paid on common stock to parent	(300.0		)	(325.0		)	(155.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)	(0.9		)
Issuance of pollution control bonds, net	—			—			98.4
Retirement of pollution control bonds	—			—			(90.0		)
Pollution control bond proceeds held in trust	—			—			(10.0		)
Withdrawal of restricted funds held in trust, net	—			14.5			32.5
Withdrawals from revolving credit facilities	—			260.0			115.0
Repayment of borrowings from revolving credit facilities	—			(260.0		)	(115.0		)
Payment of short-term debt held by parent	—			—			(20.0		)
Net cash used for financing activities	(300.9		)	(311.4		)	(145.0		)

Cash and cash equivalents:
Net change	(3.1		)	36.3			7.6
Balance at beginning of period	57.1			20.8			13.2
Cash and cash equivalents at end of period	$	54.0		$	57.1		$	20.8

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	45.1		$	39.5		$	33.4
Income taxes (refunded) / paid, net	$	87.0		$	(94.7	)	$	127.0
Non-cash financing and investing activities:
Accruals for capital expenditures	$	23.2		$	20.8		$	34.1

See Notes to Consolidated Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY

BALANCE SHEETS

	At December 31,
$ in millions	2010			2009

ASSETS

Current assets:
Cash and cash equivalents	$	54.0		$	57.1
Accounts receivable, net (Note 2)	178.0			192.0
Inventories (Note 2)	114.2			124.3
Taxes applicable to subsequent years	62.8			59.2
Other prepayments and current assets	42.7			26.0
Total current assets	451.7			458.6

Property, plant and equipment:
Property, plant and equipment	5,093.7			5,011.0
Less: Accumulated depreciation and amortization	(2,453.1		)	(2,370.7		)
	2,640.6			2,640.3

Construction work in process	119.6			87.9
Total net property, plant and equipment	2,760.2			2,728.2

Other noncurrent assets:
Regulatory assets (Note 3)	189.0			214.2
Other assets	74.5			56.4
Total other noncurrent assets	263.5			270.6

Total Assets	$	3,475.4		$	3,457.4

See Notes to Consolidated Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY

BALANCE SHEETS

	At December 31,
$ in millions	2010			2009

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:
Current portion - long-term debt (Note 5)	$	0.1		$	100.6
Accounts payable	95.7			75.1
Accrued taxes	66.6			68.6
Accrued interest	7.7			13.1
Customers security deposits	18.7			19.4
Other current liabilities	33.6			23.2
Total current liabilities	222.4			300.0

Noncurrent liabilities:
Long-term debt (Note 5)	884.0			783.7
Deferred taxes (Note 6)	598.0			553.0
Regulatory liabilities (Note 3)	139.4			125.4
Pension, retiree and other benefits	64.9			111.7
Unamortized investment tax credit	32.4			35.2
Other deferred credits	131.9			122.9
Total noncurrent liabilities	1,850.6			1,731.9

Redeemable preferred stock	22.9			22.9

Commitments and contingencies (Note 16)

Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	782.4			781.6
Accumulated other comprehensive loss	(20.2		)	(19.7		)
Retained earnings	616.9			640.3
Total common shareholder’s equity	1,379.5			1,402.6

Total Liabilities and Shareholder’s Equity	$	3,475.4		$	3,457.4

See Notes to Consolidated Financial Statements.

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THE DAYTON POWER AND LIGHT COMPANY

STATEMENTS OF SHAREHOLDER’S EQUITY

							Accumulated
	Common Stock (a)			Other			Other
	Outstanding			Paid-in			Comprehensive			Retained
in millions (except Outstanding Shares)	Shares	Amount		Capital			Income / (Loss)			Earnings			Total

Beginning balance	41,172,173	$	0.4	$	784.8		$	17.1		$	577.6		$	1,379.9

2008:
Net income										285.8
Change in unrealized gains (losses) on financial instruments, net of tax							(9.8		)
Change in deferred gains (losses) on cash flow hedges, net of tax							(1.7		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax							(21.7		)
Total comprehensive income													252.6
Common stock dividends										(155.0		)	(155.0		)
Preferred stock dividends										(0.9		)	(0.9		)
Tax effects to equity				0.3									0.3
Employee / Director stock plans				(2.0		)							(2.0		)
Ending balance	41,172,173	$	0.4	$	783.1		$	(16.1	)	$	707.5		$	1,474.9

2009:
Net income										258.9
Change in unrealized gains (losses) on financial instruments, net of tax							2.7
Change in deferred gains (losses) on cash flow hedges, net of tax							(3.7		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax							(2.7		)
Total comprehensive income													255.2
Common stock dividends										(325.0		)	(325.0		)
Preferred stock dividends										(0.9		)	(0.9		)
Tax effects to equity				0.8									0.8
Employee / Director stock plans				(2.5		)							(2.5		)
Other				0.2			0.1			(0.2		)	0.1
Ending balance	41,172,173	$	0.4	$	781.6		$	(19.7	)	$	640.3		$	1,402.6

2010:
Net income										277.7
Change in unrealized gains (losses) on financial instruments, net of tax							(1.0		)
Change in deferred gains (losses) on cash flow hedges, net of tax							(2.8		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax							3.3
Total comprehensive income													277.2
Common stock dividends										(300.0		)	(300.0		)
Preferred stock dividends										(0.9		)	(0.9		)
Tax effects to equity				0.2									0.2
Employee / Director stock plans				0.4									0.4
Other				0.2						(0.2		)	—
Ending balance	41,172,173	$	0.4	$	782.4		$	(20.2	)	$	616.9		$	1,379.5

(a) $0.01 par value, 50,000,000 shares authorized.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements

Some of the Notes presented in this report are only applicable to DPL or DP&L as indicated. The other Notes apply to both registrants and the financial information presented is segregated by registrant.

1. Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. During 2010, DPL, for the first time, met the GAAP requirements for separate segment reporting. DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 17 of Notes to Consolidated Financial Statements for more information relating to these reportable segments.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in generation, transmission, distribution and the sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.

DP&L’s sales reflect the general economic conditions and seasonal weather patterns of the area. DP&L sells any excess energy and capacity into the wholesale market.

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly-owned.

DPL also has a wholly-owned business trust, DPL Capital Trust II, formed for the purpose of issuing trust capital securities to investors.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

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Financial Statement Presentation

We prepare Consolidated Financial Statements for DPL. DPL’s Consolidated Financial Statements include the accounts of DPL and its wholly-owned subsidiaries except for DPL Capital Trust II which is not consolidated, consistent with the provisions of GAAP.

DP&L has undivided ownership interests in seven electric generating facilities and numerous transmission facilities. These undivided interests in jointly-owned facilities are accounted for on a pro rata basis in DP&L’s Financial Statements.

Certain immaterial amounts from prior periods have been reclassified to conform to the current reporting presentation.

All material intercompany accounts and transactions are eliminated in consolidation.

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenues and expenses of the periods reported. Actual results could differ from these estimates. Significant items subject to such estimates and judgments include: the carrying value of Property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits.

Revenue Recognition

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We consider revenue realized, or realizable, and earned when persuasive evidence of an arrangement exists, the products or services have been provided to the customer, the sales price is fixed or determinable, and collection is reasonably assured. Energy sales to customers are based on the reading of their meters that occurs on a systematic basis throughout the month. We recognize the revenues on our statements of results of operations using an accrual method for retail and other energy sales that have not yet been billed, but where electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. At the end of each month, unbilled revenues are determined by the estimation of unbilled energy provided to customers since the date of the last meter reading, estimated line losses, the assignment of unbilled energy provided to customer classes and the average rate per customer class.

All of the power produced at the generation plants is sold to an RTO and we in turn purchase it back from the RTO to supply our customers. These power sales and purchases are reported on a net hourly basis as revenues or purchased power on our statements of results of operations. We record expenses when purchased electricity is received and when expenses are incurred, with the exception of the ineffective portion of certain power purchase contracts that are derivatives and qualify for hedge accounting. We also have certain derivative contracts that do not qualify for hedge accounting, and their unrealized gains or losses are recorded prior to the receipt of electricity.

Allowance for Uncollectible Accounts

We establish provisions for uncollectible accounts by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues.

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. Capitalization of AFUDC ceases at either project completion or at the date specified by regulators. AFUDC capitalized in 2010, 2009 and 2008 was not material.

For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest. Capitalized interest was $1.5 million, $2.4 million and $8.9 million in 2010, 2009 and 2008, respectively.

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For substantially all depreciable property, when a unit of property is retired, the original cost of that property less any salvage value is charged to Accumulated depreciation and amortization consistent with the composite method of depreciation.

Property is evaluated for impairment when events or changes in circumstances indicate that its carrying amount may not be recoverable.

At December 31, 2010, neither DPL nor DP&L had any material plant acquisition adjustments or other plant-related adjustments.

Repairs and Maintenance

Costs associated with maintenance activities, primarily power plant outages, are recognized at the time the work is performed. These costs, which include labor, materials and supplies, and outside services required to maintain equipment and facilities, are capitalized or expensed based on defined units of property.

Depreciation Study — Change in Estimate

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation study concluded that many of DPL’s composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated. DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the year ended December 31, 2010, the net reduction in depreciation expense amounted to $4.8 million ($3.2 million net of tax) and increased diluted EPS by approximately $0.03 per share. On an annualized basis, the net reduction in depreciation expense is projected to be approximately $9.6 million ($6.4 million net of tax) or approximately $0.06 per diluted share.

For DPL’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 2.6% in 2010, 2.7% in 2009 and 2.7% in 2008.

The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2010 and 2009:

DPL

			Composite			Composite
$ in millions	2010		Rate	2009		Rate
Regulated:
Transmission	$	360.6	2.5%	$	355.3	2.4%
Distribution	1,256.5		3.4%	1,206.7		3.7%
General	79.6		3.7%	76.8		3.1%
Non-depreciable	58.6		N/A	57.8		N/A
Total regulated	$	1,755.3		$	1,696.6

Unregulated:
Production / Generation	$	3,543.6	2.3%	$	3,519.2	2.5%
Other	36.1		3.6%	35.0		3.7%
Non-depreciable	18.6		N/A	18.4		N/A
Total unregulated	$	3,598.3		$	3,572.6

Total property, plant and equipment in service	$	5,353.6	2.6%	$	5,269.2	2.7%

For DP&L’s generation, transmission, and distribution assets, straight-line depreciation is applied on an average annual composite basis using group rates that approximated 2.6% in 2010, 2.7% in 2009 and 2.6% in 2008.

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The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2010 and 2009:

DP&L

			Composite			Composite
$ in millions	2010		Rate	2009		Rate
Regulated:
Transmission	$	360.6	2.5%	$	355.3	2.4%
Distribution	1,256.5		3.4%	1,206.7		3.7%
General	79.5		3.7%	76.8		3.1%
Non-depreciable	58.7		N/A	57.8		N/A
Total regulated	$	1,755.3		$	1,696.6

Unregulated:
Production / Generation	$	3,323.0	2.3%	$	3,299.1	2.4%
Non-depreciable	15.4		N/A	15.3		N/A
Total unregulated	$	3,338.4		$	3,314.4

Total property, plant and equipment in service	$	5,093.7	2.6%	$	5,011.0	2.7%

AROs

We recognize AROs in accordance with GAAP which requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the related asset. Our legal obligations associated with the retirement of our long-lived assets consisted primarily of river intake and discharge structures, coal unloading facilities, loading docks, ice breakers and ash disposal facilities. Our generation AROs are recorded within other deferred credits on the balance sheets.

Estimating the amount and timing of future expenditures of this type requires significant judgment. Management routinely updates these estimates as additional information becomes available.

Changes in the Liability for Generation AROs

$ in millions	2010			2009
Balance at January 1	$	16.2		$	13.2
Accretion expense	0.2			0.8
Additions	0.8			2.1
Settlements	(0.3		)	(0.5		)
Estimated cash flow revisions	0.6			0.6
Balance at December 31	$	17.5		$	16.2

Asset Removal Costs

We continue to record cost of removal for our regulated transmission and distribution assets through our depreciation rates and recover those amounts in rates charged to our customers. There are no known legal AROs associated with these assets. We have recorded $107.9 million and $99.1 million in estimated costs of removal at December 31, 2010 and 2009, respectively, as regulatory liabilities for our transmission and distribution property. These amounts represent the excess of the cumulative removal costs recorded through depreciation rates versus the cumulative removal costs actually incurred. See Note 3 of Notes to Consolidated Financial Statements.

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Changes in the Liability for Transmission and Distribution Asset Removal Costs

$ in millions	2010			2009
Balance at January 1	$	99.1		$	96.0
Additions	11.2			6.5
Settlements	(2.4		)	(3.4		)
Balance at December 31	$	107.9		$	99.1

Regulatory Accounting

In accordance with GAAP, regulatory assets and liabilities are recorded in the balance sheets for our regulated transmission and distribution businesses. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and Regulatory liabilities represent current recovery of expected future costs.

We evaluate our Regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates. We record a return after it has been authorized in an order by a regulator. If we were required to terminate application of these GAAP provisions for all of our regulated operations, we would have to write off the amounts of all regulatory assets and liabilities to the statements of results of operations at that time. See Note 3 of Notes to Consolidated Financial Statements.

Inventories

Inventories are carried at average cost and include coal, limestone, oil and gas used for electric generation, and materials and supplies used for utility operations.

We account for our emission allowances as inventory and record emission allowance inventory at weighted average cost. We calculate the weighted average cost by each vintage (year) for which emission allowances can be used and charge to fuel costs the weighted average cost of emission allowances used each month. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the weighted average cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. During the periods ended December 31, 2010, 2009 and 2008, we recognized gains from the sale of emission allowances in the amounts of $0.8 million, $5.0 million and $34.8 million, respectively. Beginning in January 2010, a portion of the gains on emission allowances was used to reduce the overall fuel rider charged to our SSO retail customers.

Income Taxes

GAAP requires an asset and liability approach for financial accounting and reporting of income taxes with tax effects of differences, based on currently enacted income tax rates, between the financial reporting and tax basis of accounting reported as deferred tax assets or liabilities in the balance sheets. Deferred tax assets are recognized for deductible temporary differences. Valuation allowances are provided against deferred tax assets unless it is more likely than not that the asset will be realized.

Investment tax credits, which have been used to reduce federal income taxes payable, are deferred for financial reporting purposes and are amortized over the useful lives of the property to which they relate. For rate-regulated operations, additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that income taxes will be recoverable or refundable through future revenues.

DPL files a consolidated U.S. federal income tax return in conjunction with its subsidiaries. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 6 of Notes to Consolidated Financial Statements.

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Financial Instruments

We classify our investments in debt and equity financial instruments of publicly traded entities into different categories: held-to-maturity and available-for-sale. Available-for-sale securities are carried at fair value and unrealized gains and losses on those securities, net of deferred income taxes, are presented as a separate component of shareholders’ equity. Other-than-temporary declines in value are recognized currently in earnings. Financial instruments classified as held-to-maturity are carried at amortized cost. The cost basis for public equity security and fixed maturity investments is average cost and amortized cost, respectively.

Short-Term Investments

DPL utilizes VRDNs as part of its short-term investment strategy. The VRDNs are of high credit quality and are secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale back to the financial institution upon notice. Although DPL’s VRDN investments have original maturities over one year, they are frequently re-priced and trade at par. We account for these VRDNs as available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since they are highly liquid and are readily available to support DPL’s current operating needs.

DPL also holds investment-grade fixed income corporate securities in its short-term investment portfolio. These securities are accounted for as held-to-maturity investments.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DP&L collects certain excise taxes levied by state or local governments from its customers. DP&L’s excise taxes are accounted for on a gross basis and recorded as revenues and general taxes in the accompanying Statements of Results of Operations as follows:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
State/Local excise taxes	$	51.7	$	49.5	$	52.3

Share-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair-value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair-value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair-value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the statements of cash flows within Cash flows from financing activities. See Note 10 of Notes to Consolidated Financial Statements.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless they are designated as a cash flow hedge of a forecasted transaction or qualify for the normal purchases and sales exception.

We use forward contracts to reduce our exposure to changes in energy and commodity prices and as a hedge against the risk of changes in cash flows associated with expected electricity purchases. These purchases are used to hedge our full load requirements. We also hold forward sales contracts that hedge against the risk of changes in cash flows associated with power sales during periods of projected generation facility availability. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective and MTM accounting when the hedge or a portion of the hedge is not effective. See Note 9 of Notes to Consolidated Financial Statements.

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Insurance and Claims Costs

In addition to insurance obtained from third-party providers, MVIC, a wholly-owned captive subsidiary of DPL, provides insurance coverage to us, our subsidiaries and, in some cases, our partners in commonly owned facilities we operate, for workers’ compensation, general liability, property damage, and directors’ and officers’ liability. Insurance and claims costs on the Consolidated Balance Sheets of DPL include insurance reserves of approximately $10.1 million and $16.2 million for 2010 and 2009, respectively. Furthermore, DP&L is responsible for claim costs below certain coverage thresholds of MVIC for the insurance coverage noted above. In addition, DP&L has medical, life, and disability reserves for claims costs below certain coverage thresholds of third-party providers. We record these additional insurance and claims costs of approximately $19.0 million and $11.3 million for 2010 and 2009, respectively, within Other current liabilities and Other deferred credits on the balance sheets. The MVIC reserves at DPL and the workers’ compensation, medical, life and disability reserves at DP&L are actuarially determined based on a reasonable estimation of insured events occurring. There is uncertainty associated with these loss estimates and actual results may differ from the estimates. Modification of these loss estimates based on experience and changed circumstances is reflected in the period in which the estimate is re-evaluated.

DPL Capital Trust II

DPL has a wholly-owned business trust, DPL Capital Trust II (the Trust), formed for the purpose of issuing trust capital securities to third-party investors. Effective 2003, DPL deconsolidated the Trust upon adoption of the accounting standards related to variable interest entities and currently treats the Trust as a nonconsolidated subsidiary. The Trust holds mandatorily redeemable trust capital securities. The investment in the Trust, which amounts to $3.6 million and $3.8 million at December 31, 2010 and 2009, respectively, is included in Other deferred assets within Other noncurrent assets. DPL also has a note payable to the Trust amounting to $142.6 million at December 31, 2010 and 2009 that was established upon the Trust’s deconsolidation in 2003. See Note 5 of Notes to Consolidated Financial Statements.

In addition to the obligations under the note payable mentioned above, DPL also agreed to a security obligation which represents a full and unconditional guarantee of payments to the capital security holders of the Trust.

Related Party Transactions

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. All material intercompany accounts and transactions are eliminated in DPL’s Consolidated Financial Statements. The following table provides a summary of amounts transacted by DP&L with its related parties:

	For the years ended December 31,
$ in millions	2010			2009			2008

DP&L Revenues:
Sales to DPLER (a)	$	238.5		$	64.8		$	150.6

DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	$	(3.3	)	$	(3.4	)	$	(3.5	)
Expense recoveries for services provided to DPLER (c)	$	5.8		$	1.5		$	0.9

(a) DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues by DP&L. The increase in DP&L’s sales to DPLER during the year ended December 31, 2010 compared to the same period in 2009 is primarily due to customers electing to switch their generation service from DP&L to DPLER.

(b) MVIC, a wholly-owned captive insurance subsidiary of DPL, provides insurance coverage to DP&L and other DPL subsidiaries for workers’ compensation, general liability, property damages and directors’ and officers’ liability. These amounts represent insurance premiums paid by DP&L to MVIC.

(c) In the normal course of business DP&L incurs and records expenses on behalf of DPLER. Such expenses include but are not limited to employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. DP&L subsequently charges these expenses to DPLER at DP&L’s cost and credits the expense in which they were initially recorded.

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Recently Adopted Accounting Standards

Variable Interest Entities

We adopted ASU 2009-02 “Omnibus Update” (formerly SFAS No. 167, a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities”) (ASU 2009-02), on January 1, 2010. This standard updates FASC Topic 810 “Consolidation.” ASU 2009-02 changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar) rights should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. ASU 2009-02 did not have a material impact on our overall results of operations, financial condition or cash flows.

Fair Value Disclosures

We adopted ASU 2010-06 “Fair Value Measurements and Disclosures” (ASU 2010-06) on January 1, 2010. This standard updates FASC Topic 820 “Fair Value Measurements and Disclosures.” ASU 2010-06 requires additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and a higher level of disaggregation for the different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements are presented separately. ASU 2010-06 did not have a material impact on our overall results of operations, financial condition or cash flows. See Note 8 of Notes to Consolidated Financial Statements.

Recently Issued Accounting Standards

There were no recently issued accounting standards that could potentially have a significant impact on our financial statements.

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2. Supplemental Financial Information

DPL Inc.

	At			At
	December 31,			December 31,
$ in millions	2010			2009

Accounts receivable, net:
Unbilled revenue	$	84.5		$	74.9
Customer receivables	113.9			99.4
Amounts due from partners in jointly-owned plants	7.0			12.6
Coal sales	4.0			10.6
Other	7.0			16.4
Provision for uncollectible accounts	(0.9		)	(1.1		)
Total accounts receivable, net	$	215.5		$	212.8

Inventories, at average cost:
Fuel, limestone and emission allowances	$	73.2		$	85.8
Plant materials and supplies	38.8			38.5
Other	3.3			1.4
Total inventories, at average cost	$	115.3		$	125.7

DP&L

	At			At
	December 31,			December 31,
$ in millions	2010			2009

Accounts receivable, net:
Unbilled revenue	$	64.3		$	71.0
Customer receivables	95.6			94.4
Amounts due from partners in jointly-owned plants	7.0			12.6
Coal sales	4.0			10.6
Other	7.9			4.5
Provision for uncollectible accounts	(0.8		)	(1.1		)
Total accounts receivable, net	$	178.0		$	192.0

Inventories, at average cost:
Fuel, limestone and emission allowances	$	73.2		$	85.8
Plant materials and supplies	37.7			37.1
Other	3.3			1.4
Total inventories, at average cost	$	114.2		$	124.3

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3. Regulatory Matters

In accordance with GAAP, regulatory assets and liabilities are recorded in the consolidated balance sheets for our regulated electric transmission and distribution businesses. Regulatory assets are the deferral of costs expected to be recovered in future customer rates and regulatory liabilities represent current recovery of expected future costs or gains probable of recovery being reflected in future rates.

We evaluate our regulatory assets each period and believe recovery of these assets is probable. We have received or requested a return on certain regulatory assets for which we are currently recovering or seeking recovery through rates. We record a return after it has been authorized in an order by a regulator.

Regulatory assets and liabilities on the consolidated balance sheets of DPL and DP&L include:

			At		At
	Type of	Amortization	December 31,		December 31,
$ in millions	Recovery (a)	Through	2010		2009
Regulatory Assets:
Deferred recoverable income taxes	B/C	Ongoing	$	29.9	$	36.8
Pension benefits	C	Ongoing	81.1		85.2
Unamortized loss on reacquired debt	C	Ongoing	14.3		15.6
Electric Choice systems costs	F	2011	0.9		4.0
Regional transmission organization costs	D	2014	5.5		7.0
TCRR, transmission, ancillary and other PJM-related costs	F	2011	11.8		5.5
RPM capacity costs	F	2011	2.7		20.0
Deferred storm costs - 2008	D		16.9		16.0
Power plant emission fees	C	Ongoing	6.6		6.3
CCEM smart grid and advanced metering infrastructure costs	D		6.6		6.5
CCEM energy efficiency program costs	F	Ongoing	4.8		3.6
Other costs			7.9		7.7
Total regulatory assets			$	189.0	$	214.2

Regulatory Liabilities:
Estimated costs of removal - regulated property			$	107.9	$	99.1
SECA net revenue subject to refund			15.4		20.1
Postretirement benefits			6.1		5.1
Fuel and purchased power recovery costs	C	Ongoing	10.0		—
Other costs			—		1.1
Total regulatory liabilities			$	139.4	$	125.4

(a) B — Balance has an offsetting liability resulting in no impact on rate base.
C — Recovery of incurred costs without a rate of return.
D — Recovery not yet determined, but is probable of occurring in future rate proceedings.
F — Recovery of incurred costs plus rate of return.

Regulatory Assets

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as the result of amounts previously provided to customers. This is the cumulative flow through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes will decrease over time.

Pension benefits represent the qualifying FASC Topic 715 “Compensation — Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income (OCI), the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods. These costs are being amortized over the lives of the original issues in accordance with FERC and PUCO rules.

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Electric Choice systems costs represent costs incurred to modify the customer billing system for unbundled customer rates and electric choice utility bills relative to other generation suppliers and information reports provided to the state administrator of the low-income payment program. In March 2006, the PUCO issued an order that approved our tariff as filed. We began collecting this rider immediately and expect to recover all costs over five years.

Regional transmission organization costs represent costs incurred to join an RTO. The recovery of these costs will be requested in a future FERC rate case. In accordance with FERC precedence, we are amortizing these costs over a 10-year period that began in 2004 when we joined the PJM RTO.

TCRR, transmission, ancillary and other PJM-related costs represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. We review retail rates and are required to make true-up adjustments on an annual basis.

RPM capacity costs represent the costs related to PJM RPM assigned to DP&L that have not yet been recovered through the RPM rider. We review this rate and make true-up adjustments on an annual basis.

Deferred storm costs — 2008 relate to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other major 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.

Power plant emission fees represent costs paid to the State of Ohio since 2002. An application is pending before the PUCO to amend an approved rate rider that had been in effect to collect fees that were paid and deferred in years prior to 2002. The deferred costs incurred prior to 2002 have been fully recovered. As the previously approved rate rider continues to be in effect, we believe these costs are probable of future rate recovery.

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. Consistent with the ESP Stipulation, DP&L re-filed its smart grid and AMI business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a 10-year plan to deploy smart meters, distribution and substation automation, core telecommunications, supporting software and in-home technologies. On October 19, 2010, DP&L elected to withdraw the re-filed case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. These costs are being recovered through an energy efficiency rider that began July 1, 2009 and is subject to a two-year true-up for any over/under recovery of costs.

Other costs primarily include consumer education advertising costs regarding electric deregulation, settlement system costs, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.

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Regulatory Liabilities

Estimated costs of removal — regulated property reflect an estimate of amounts collected in customer rates for costs that are expected to be incurred in the future to remove existing transmission and distribution property from service when the property is retired.

SECA net revenue subject to refund represents our deferral of revenues and costs that were billed to PJM transmission customers and paid to transmission owners during 2005 and 2006, but which remain subject to litigation before the FERC and potential reversal. DP&L is both a transmission customer and a transmission owner. SECA revenue and expenses represent FERC-ordered transitional payments for the use of transmission lines within PJM. We began receiving and paying these transitional payments in May 2005, subject to refund. Since 2005, a large number of settlements have been entered into among various market participants including DP&L. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. DP&L, along with other transmission owners in PJM and the Midwest Independent System Operator (MISO) made a compliance filing at FERC on August 19, 2010 that fully demonstrated all payment obligations to and from all parties within PJM and the MISO. The FERC has made no ruling regarding the compliance filing and some parties have requested rehearing by FERC of its May 21, 2010 order. It is expected that any order on the compliance filing and any order regarding the rehearing request will be appealed for Court review. In October 2010, DP&L entered into another settlement agreement to settle a portion of SECA amounts still owed to DP&L. With respect to unsettled claims, DP&L management believes it has deferred as a regulatory liability the appropriate amounts that are subject to refund. The eventual outcome of this litigation is uncertain.

Postretirement benefits represent the qualifying FASC Topic 715 “Compensation — Retirement Benefits” gains related to our regulated operations that, for ratemaking purposes, are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be reflected as a gain to OCI.

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. DP&L is currently undergoing an audit of its fuel and purchased power recovery rider and, as a result, there is some uncertainty as to the costs that will be approved for recovery. Independent third parties conduct the fuel audit in accordance with the PUCO standards. DP&L anticipates that some of this uncertainty will be resolved during the summer of 2011 after completion of the fuel audit. As a result of the fuel audit, DP&L may record a favorable or unfavorable adjustment to earnings. Based on past PUCO precedent, we believe these deferred costs are probable of future recovery or repayment in the case of over recovery.

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4. Ownership of Coal-fired Facilities

DP&L and other Ohio utilities have undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of December 31, 2010, we had $56 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Statements of Results of Operations and DP&L’s share of the investment in the facilities is included in the Balance Sheets.

DP&L’s undivided ownership interest in such facilities as well as our wholly-owned coal fired Hutchings plant at December 31, 2010, is as follows:

			DP&L Investment
	DP&L Share						Construction		SCR and FGD Equipment Installed
	Ownership (%)	Production Capacity (MW)	Gross Plant In Service ($ in millions)		Accumulated Depreciation ($ in millions)		Work in Process ($ in millions)		and In Service (Yes/No)
Production Units:
Beckjord Unit 6	50.0	210	$	75	$	52	$	2	No
Conesville Unit 4	16.5	129	118		27		5		Yes
East Bend Station	31.0	186	200		131		1		Yes
Killen Station	67.0	402	611		288		3		Yes
Miami Fort Units 7 and 8	36.0	368	347		130		7		Yes
Stuart Station	35.0	820	697		266		25		Yes
Zimmer Station	28.1	365	1,059		612		12		Yes
Transmission (at varying percentages)			91		56		—
Total		2,480	$	3,198	$	1,562	$	55

Wholly-owned production unit:
Hutchings Station	100.0	388	$	123	$	111	$	1	No

DP&L’s share of operating costs associated with the jointly-owned generating facilities is included within the corresponding line in the Statements of Results of Operations.

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5. Debt Obligations

Long-term Debt

	At			At
	December 31,			December 31,
$ in millions	2010			2009
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%	35.3			35.3
Pollution control series maturing in January 2034 - 4.80%	179.1			179.1
Pollution control series maturing in September 2036 - 4.80%	100.0			100.0
Pollution control series maturing in November 2040 - variable rates: 0.16% - 0.35% and 0.24% - 0.85% (a)	100.0			—
	884.4			784.4

Obligation for capital lease	0.1			—
Unamortized debt discount	(0.5		)	(0.7		)
Total long-term debt - DP&L	$	884.0		$	783.7

DPL
Senior notes maturing in September 2011 - 6.875%	—			297.4
Note to DPL Capital Trust II maturing in September 2031 - 8.125%	142.6			142.6
Unamortized debt discount	—			(0.2		)
Total long-term debt - DPL	$	1,026.6		$	1,223.5

Current portion - Long-term Debt

	At		At
	December 31,		December 31,
$ in millions	2010		2009
DP&L
Pollution control series maturing in November 2040 - variable rates: 0.16% - 0.35% and 0.24% - 0.85% (a)	$	—	$	100.0
Obligation for capital lease	0.1		0.6
Total current portion - long-term debt - DP&L	$	0.1	$	100.6

DPL
Senior notes maturing in September 2011 - 6.875%	297.4		—
Total current portion - long-term debt - DPL	$	297.5	$	100.6

(a) Range of interest rates for the twelve months ended December 31, 2010 and December 31, 2009, respectively.

At December 31, 2010, maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions	DPL		DP&L
Due within one year	$	297.5	$	0.1
Due within two years	0.1		0.1
Due within three years	470.0		470.0
Due within four years	—		—
Due within five years	—		—
Thereafter	557.0		414.4
	$	1,324.6	$	884.6

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Debt

On November 21, 2006, DP&L entered into a $220 million unsecured revolving credit agreement. This agreement has a five-year term that expires on November 21, 2011 and provides DP&L with the ability to increase the size of the facility by an additional $50 million at any time. DP&L had no outstanding borrowings under this credit facility at December 31, 2010. Fees associated with this credit facility were approximately $1.2 million and $0.9 million during the years ended December 31, 2010 and 2009, respectively. Changes in DP&L’s credit ratings may affect fees and the applicable interest rate. This revolving credit agreement contains a $50 million letter of credit sublimit. As of December 31, 2010, DP&L had no outstanding letters of credit against the facility.

On December 4, 2008, the OAQDA issued $100 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby LOC issued by JPMorgan Chase Bank, N.A. This LOC facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. The bonds were classified within the current portion of long term debt at December 31, 2009 as the standby LOC backing the bonds was set to expire during the fourth quarter of 2010. During the fourth quarter of 2010, DP&L renewed the standby LOC to back the payment of principal and interest on each series of the bonds when due. The new LOC facility expires in December 2013 therefore the bonds have been reclassified to Long-term debt on the balance sheets of DPL and DP&L.

On March 31, 2009, DPL paid its $175 million 8.00% Senior notes when the notes became due.

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group. The agreement was for a 364-day term and expired on April 20, 2010.

On December 21, 2009, DPL purchased $52.4 million principal amount of DPL Capital Trust II 8.125% capital securities in a privately negotiated transaction. As part of this transaction, DPL paid a $3.7 million, or 7%, premium which was recorded within Interest expense on the Consolidated Statements of Results of Operations.

On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. DP&L had no outstanding borrowings under this credit facility at December 31, 2010. Fees associated with this credit facility were approximately $0.5 million during the period between April 20, 2010 and December 31, 2010. This facility also contains a $50 million letter of credit sublimit. As of December 31, 2010, DP&L had no outstanding letters of credit against the facility.

Substantially all property, plant and equipment of DP&L is subject to the lien of the mortgage securing DP&L’s First and Refunding Mortgage, dated October 1, 1935, with the Bank of New York Mellon as Trustee.

See Note 18 of Notes to Consolidated Financial Statements for additional discussion relating to DPL’s 8.125% Note to DPL — Capital Trust II.

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6. Income Taxes

For the years ended December 31, 2010, 2009 and 2008, DPL’s components of income tax expense were as follows:

DPL

	For the years ended
	December 31,
$ in millions	2010			2009			2008
Computation of Tax Expense
Federal income tax (a)	$	151.7		$	119.9		$	121.9

Increases (decreases) in tax resulting from:
State income taxes, net of federal effect	2.4			0.9			4.1
Depreciation of AFUDC - Equity	(2.2		)	(2.0		)	(4.3		)
Investment tax credit amortized	(2.8		)	(2.8		)	(2.8		)
Section 199 - domestic production deduction	(9.1		)	(4.6		)	(4.2		)
Accrual (settlement) for open tax years (b)	0.2			(1.4		)	(7.2		)
Other, net (c)	2.8			2.5			(4.6		)
Total tax expense	$	143.0		$	112.5		$	102.9

Components of Tax Expense
Federal - Current	$	84.8		$	(84.4	)	$	60.9
State and Local - Current	1.1			(1.8		)	1.8
Total Current	$	85.9		$	(86.2	)	$	62.7

Federal - Deferred	$	55.9		$	196.0		$	37.9
State and Local - Deferred	1.2			2.7			2.3
Total Deferred	$	57.1		$	198.7		$	40.2

Total tax expense	$	143.0		$	112.5		$	102.9

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2010			2009
Net Noncurrent Assets / (Liabilities)
Depreciation / property basis	$	(618.6	)	$	(583.5	)
Income taxes recoverable	(10.3		)	(12.9		)
Regulatory assets	(12.4		)	(16.5		)
Investment tax credit	11.3			12.3
Investment loss	(0.5		)	0.1
Compensation and employee benefits	21.0			35.8
Insurance	(1.5		)	0.8
Other (d)	(14.4		)	(5.2		)
Net noncurrent (liabilities)	$	(625.4	)	$	(569.1	)

Net Current Assets (e)
Other	$	1.1		$	3.7
Net current assets	$	1.1		$	3.7

(a)	The statutory tax rate of 35% was applied to pre-tax earnings from continuing operations.
(b)	*DPL* has recorded an expense of $0.2 million, benefits of $2.9 million and $40.7 million in 2010, 2009 and 2008, respectively, for tax deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is possible that these positions may be contested. The 2008 amount relates to the ODT settlement discussed further below in Note 6 of Notes to Consolidated Financial Statements.
(c)	Includes a benefit of $0.3 million, an expense of $2.0 million, a benefit of $3.8 million in 2010, 2009 and 2008, respectively, of income tax related to adjustments from prior years.
(d)	The Other noncurrent liabilities caption includes deferred tax assets of $13.1 million in 2010 and $12.0 million in 2009 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $13.1 million in 2010 and $12.0 million in 2009. As of December 31, 2010 and 2009, all deferred tax assets related to net operating losses were valued at zero. These net operating loss carryforwards expire from 2017 to 2025.
(e)	Amounts are included within Other prepayments and current assets on the Consolidated Balance Sheets of DPL.

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DPL has recorded $0.2 million, $0.7 million and $0.3 million in 2010, 2009 and 2008, respectively, for tax benefits related to stock-based compensation that were credited to Retained earnings. DPL has recorded $5.8 million of tax expense in 2010 and $1.7 million and $11.5 million of tax benefits in 2009 and 2008, respectively, for tax benefits related to pensions, postretirement benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.

For the years ended December 31, 2010, 2009 and 2008, DP&L’s components of income tax were as follows:

DP&L

	For the years ended
	December 31,
$ in millions	2010			2009			2008
Computation of Tax Expense
Federal income tax (a)	$	144.2		$	134.2		$	142.1

Increases (decreases) in tax resulting from:
State income taxes, net of federal effect	1.9			0.4			2.6
Depreciation of AFUDC - Equity	(2.2		)	(2.0		)	(4.3		)
Investment tax credit amortized	(2.8		)	(2.8		)	(2.8		)
Section 199 - domestic production deduction	(9.1		)	(4.6		)	(4.2		)
Accrual (settlement) for open tax years (b)	0.2			(1.4		)	(7.2		)
Other, net (c)	3.0			0.7			(6.0		)
Total tax expense	$	135.2		$	124.5		$	120.2

Components of Tax Expense
Federal - Current	$	83.1		$	(70.3	)	$	81.2
State and Local - Current	0.8			(2.5		)	0.9
Total Current	$	83.9		$	(72.8	)	$	82.1

Federal - Deferred	$	50.1		$	194.4		$	36.4
State and Local - Deferred	1.2			2.9			1.7
Total Deferred	$	51.3		$	197.3		$	38.1

Total tax expense	$	135.2		$	124.5		$	120.2

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2010			2009
Net Noncurrent Assets / (Liabilities)
Depreciation / property basis	$	(595.6	)	$	(563.7	)
Income taxes recoverable	(10.3		)	(12.9		)
Regulatory assets	(12.4		)	(16.5		)
Investment tax credit	11.3			12.3
Compensation and employee benefits	21.0			35.8
Other	(12.0		)	(8.0		)
Net noncurrent (liabilities)	$	(598.0	)	$	(553.0	)

Net Current Assets (d)
Other	$	1.2		$	3.7
Net current assets	$	1.2		$	3.7

(a)	The statutory tax rate of 35% was applied to pre-tax earnings.
(b)	*DP&L* has recorded an expense of $0.2 million and benefits of $2.9 million and $40.7 million in 2010, 2009 and 2008, respectively, of tax provisions for tax deduction or income positions taken in prior tax returns that we believe were properly treated on such tax returns but for which it is possible that these positions may be contested. The 2008 amount relates to the ODT settlement discussed further below in Note 6 of Notes to Consolidated Financial Statements.
(c)	Includes a benefit of $0.3 million, an expense of $0.8 million, and a benefit of $3.5 million in 2010, 2009 and 2008, respectively, of income tax related to adjustments from prior years.
(d)	Amounts are included within Other prepayments and current assets on the Balance Sheets of DP&L.

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DP&L has recorded $0.2 million, $0.7 million and $0.3 million in 2010, 2009 and 2008, respectively, for tax benefits related to stock-based compensation that were credited to Other paid-in capital. DP&L has recorded $0.1 million of tax expense in 2010 and $0.5 million and $16.5 million of tax benefits in 2009 and 2008, respectively, for tax benefits related to pensions, postretirement benefits, cash flow hedges and financial instruments that were credited to Accumulated other comprehensive loss.

Accounting for Uncertainty in Income Taxes

We apply the provisions of GAAP relating to the accounting for uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits for DPL and DP&L is as follows:

$ in millions	2010			2009
Balance at beginning of year	$	19.3		$	1.9
Tax positions taken during prior periods	(0.4		)	—
Tax positions taken during current period	—			20.6
Settlement with taxing authorities	0.3			(3.2		)
Lapse of applicable statute of limitations	0.2			—
Balance at end of year	$	19.4		$	19.3

Of the December 31, 2010 balance of unrecognized tax benefits, $20.6 million is due to uncertainty in the timing of deductibility offset by $1.1 million of unrecognized tax liabilities that would affect the effective tax rate.

We recognize interest and penalties related to unrecognized tax benefits in Income tax expense. The amount of interest and penalties accrued was an expense of $0.3 million as of December 31, 2010, a benefit of $0.1 million as of December 31, 2009 and an expense of less than $0.1 million as of December 31, 2008. The amount of interest and penalties recorded in the statements of results of operations for 2010, 2009 and 2008 was an expense of $0.2 million, and benefits of $0.1 million and $9.0 million, respectively.

Following is a summary of the tax years open to examination by major tax jurisdiction:

U.S. Federal — 2007 and forward

State and Local — 2005 and forward

None of the unrecognized tax benefits are expected to significantly increase or decrease within the next twelve months.

The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010. The examination is still ongoing and we do not expect the results of this examination to have a material impact on our financial condition, results of operations and cash flows.

On December 17, 2010, the Federal Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 was enacted. This legislation amends, creates and extends various Federal tax statutes. Among the various statutes is the extension and expansion of capital expensing provisions, commonly referred to as bonus depreciation, for 2010, 2011 and 2012. While these provisions are not expected to have a material impact on our results of operations, we anticipate they will result in positive cash flow contributions over the next few years.

On June 21, 2010, Ohio Senate Bill 232 was enacted. This legislation eliminates Ohio’s tangible personal property tax and real property taxes on generation for renewable and advanced energy project facilities that begin construction before January 1, 2012, produce energy by 2013 (or 2017 for nuclear, clean coal and cogeneration projects) and create Ohio jobs. Rules containing implementation provisions were proposed on September 29, 2010. We do not anticipate this law and the related rules will have a material impact on either DPL’s or DP&L’s financial condition, results of operations and cash flows.

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On February 13, 2006, we received correspondence from the ODT notifying us that the ODT had completed their examination and review of our Ohio Corporation Franchise Tax Returns for tax years 2002 through 2004 and that the final proposed audit adjustments resulted in a balance due of $90.8 million before interest and penalties. On June 27, 2008, we entered into a $42.0 million settlement agreement with the ODT resolving all outstanding audit issues and appeals, including uncertain tax positions for tax years 1998 through 2006. The $42 million payment was made to the ODT in July 2008. Due to this settlement agreement, the balance of our unrecognized state tax liabilities recorded at December 31, 2007, in the amount of $56.3 million, was reversed resulting in a recorded income tax benefit of $8.5 million, net of federal tax impact, in 2008.

7. Pension and Postretirement Benefits

DP&L sponsors a defined benefit pension plan for substantially all employees. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or upon a change of control or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination.

Management employees beginning employment on or after January 1, 2011 will be enrolled in a cash balance plan. Similar to the defined benefit pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan or upon a change of control or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain active and retired key executives. Benefits under this SERP have been frozen and no additional benefits can be earned. The SERP was replaced by the DPL Inc. Supplemental Executive Defined Contribution Retirement Plan (SEDCRP). The Compensation Committee of the Board of Directors designates the eligible employees. Pursuant to the SEDCRP, we provide a supplemental retirement benefit to participants by crediting an account established for each participant in accordance with the Plan requirements. We designate as hypothetical investment funds under the SEDCRP one or more of the investment funds provided under The Dayton Power and Light Company Employee Savings Plan. Each participant may change his or her hypothetical investment fund selection at specified times. If a participant does not elect a hypothetical investment fund(s), then we select the hypothetical investment fund(s) for such participant. We also have an unfunded liability related to agreements for retirement benefits of certain terminated and retired key executives. The unfunded liabilities for these agreements and the SEDCRP were $1.8 million and $1.4 million at December 31, 2010 and 2009, respectively.

We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. In February 2010, DP&L contributed $20.0 million to the defined benefit plan. In September 2010, DP&L contributed an additional $20.0 million to the defined benefit plan for a total contribution of $40.0 million in 2010.

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from their retirement until they are covered by Medicare at age 65. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.

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Regulatory assets and liabilities are recorded for the portion of the under- or over-funded obligations related to the transmission and distribution areas of our electric business and for the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. These regulatory assets and liabilities represent the regulated portion that would otherwise be charged or credited to AOCI. We have historically recorded these costs on the accrual basis and this is how these costs have been historically recovered. This factor, combined with the historical precedents from the PUCO and FERC, make these costs probable of future rate recovery.

The following tables set forth our pension and postretirement benefit plans’ obligations and assets recorded on the balance sheets as of December 31, 2010 and 2009. The amounts presented in the following tables for pension include both the defined benefit pension plan and the SERP in the aggregate, and use a measurement date of December 31, 2010 and 2009. The amounts presented for postretirement include both health and life insurance benefits and use a measurement date of December 31, 2010 and 2009.

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	Pension						Postretirement
$ in millions	2010			2009			2010			2009
Change in Benefit Obligation During Year
Benefit obligation at January 1	$	323.9		$	294.6		$	26.2		$	25.2
Service cost	4.8			3.6			0.1			—
Interest cost	17.7			18.1			1.2			1.5
Plan amendments	—			7.2			—			1.1
Actuarial (gain) / loss	8.0			20.3			(2.0		)	0.3
Benefits paid	(20.6		)	(19.9		)	(2.0		)	(1.9		)
Medicare Part D Reimbursement	—			—			0.2			—
Benefit obligation at December 31	$	333.8		$	323.9		$	23.7		$	26.2

Change in Plan Assets During Year
Fair value of plan assets at January 1	$	243.4		$	225.4		$	5.0		$	6.2
Actual return / (loss) on plan assets	28.6			37.5			0.3			0.4
Contributions to plan assets	40.4			0.4			1.5			0.3
Benefits paid	(20.6		)	(19.9		)	(2.0		)	(2.3		)
Medicare reimbursements	—			—			—			0.4
Fair value of plan assets at December 31	$	291.8		$	243.4		$	4.8		$	5.0

Funded Status of Plan	$	(42.0	)	$	(80.5	)	$	(18.9	)	$	(21.2	)

Amounts Recognized in the Balance Sheets at December 31
Current liabilities	$	(0.4	)	$	(0.4	)	$	(0.6	)	$	(0.4	)
Noncurrent liabilities	(41.6		)	(80.1		)	(18.3		)	(20.8		)
Net asset / (liability) at December 31	$	(42.0	)	$	(80.5	)	$	(18.9	)	$	(21.2	)

Amounts Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost / (credit)	$	16.8		$	20.4		$	0.9		$	1.1
Net actuarial loss / (gain)	125.4			130.9			(7.6		)	(6.9		)
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax	$	142.2		$	151.3		$	(6.7	)	$	(5.8	)

Recorded as:
Regulatory asset	$	80.0		$	84.6		$	0.5		$	0.6
Regulatory liability	—			—			(6.1		)	(5.1		)
Accumulated other comprehensive income	62.2			66.7			(1.1		)	(1.3		)
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax	$	142.2		$	151.3		$	(6.7	)	$	(5.8	)

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The accumulated benefit obligation for our defined benefit pension plans was $320.9 million and $314.0 million at December 31, 2010 and 2009, respectively.

The net periodic benefit cost (income) of the pension and postretirement benefit plans at December 31 were:

Net Periodic Benefit Cost / (Income)	Pension									Postretirement
$ in millions	2010			2009			2008			2010			2009			2008
Service cost	$	4.8		$	3.6		$	3.2		$	0.1		$	—		$	—
Interest cost	17.7			18.1			16.7			1.2			1.5			1.4
Expected return on assets (a)	(22.4		)	(22.5		)	(24.1		)	(0.3		)	(0.4		)	(0.4		)
Amortization of unrecognized:
Actuarial (gain) / loss	7.2			4.4			2.6			(1.1		)	(0.7		)	(0.9		)
Prior service cost	3.7			3.4			2.4			0.1			0.1			—
Net periodic benefit cost / (income) before adjustments	$	11.0		$	7.0		$	0.8		$	—		$	0.5		$	0.1

(a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be amortized into the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets was approximately $274 million in 2010, $275 million in 2009 and $293 million in 2008.

Other Changes in Plan Assets and Benefit Obligation Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities

	Pension						Postretirement
$ in millions	2010			2009			2010			2009
Net actuarial (gain) / loss	$	1.9		$	5.3		$	(1.9	)	$	0.3
Prior service cost / (credit)	—			7.2			—			1.1
Reversal of amortization item:
Net actuarial (gain) / loss	(7.2		)	(4.4		)	1.1			0.7
Prior service cost / (credit)	(3.7		)	(3.4		)	(0.1		)	(0.1		)
Transition (asset) / obligation	—			—			—			—

Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities	$	(9.0	)	$	4.7		$	(0.9	)	$	2.0

Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities	$	2.0		$	11.7		$	(0.9	)	$	2.5

Estimated amounts that will be amortized from Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2011 are:

$ in millions	Pension		Postretirement
Net actuarial (gain) / loss	$	9.1	$	0.1
Prior service cost / (credit)	2.2		(0.9		)

Our expected return on plan asset assumptions, used to determine benefit obligations, are based on historical long-term rates of return on investments, which use the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors, such as inflation and interest rates, as well as asset diversification and portfolio rebalancing, are evaluated when long-term capital market assumptions are determined. Peer data and historical returns are reviewed to verify reasonableness and appropriateness.

For 2011, we have decreased our expected long-term rate of return on assets assumption from 8.50% to 8.00% for pension plan assets. We are maintaining our expected long-term rate of return on assets assumption at approximately 6.00% for postretirement benefit plan assets. These expected returns are based primarily on portfolio investment allocation. There can be no assurance of our ability to generate these rates of return in the future.

Our overall discount rate was evaluated in relation to the December 31, 2010 Hewitt Top Quartile Yield Curve which represents a portfolio of top-quartile AA-rated bonds used to settle pension obligations. Peer data and historical returns were also reviewed to verify the reasonableness and appropriateness of our discount rate used in the calculation of benefit obligations and expense.

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The weighted average assumptions used to determine benefit obligations for the years ended December 31, 2010 and 2009 were:

	Pension				Postretirement
Benefit Obligation Assumptions	2010		2009		2010		2009
Discount rate for obligations	5.31	%	5.75	%	4.96	%	5.35	%
Rate of compensation increases	3.94	%	4.44	%	N/A		N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2010, 2009 and 2008 were:

Net Periodic Benefit	Pension						Postretirement
Cost / (Income) Assumptions	2010		2009		2008		2010		2009		2008
Discount rate	5.75	%	6.25	%	6.00	%	5.35	%	6.25	%	6.00	%
Expected rate of return on plan assets	8.50	%	8.50	%	8.50	%	6.00	%	6.00	%	6.00	%
Rate of compensation increases	4.44	%	5.44	%	5.44	%	N/A		N/A		N/A

The assumed health care cost trend rates at December 31, 2010 and 2009 are as follows:

	Expense				Benefit Obligations
Health Care Cost Assumptions	2010		2009		2010		2009
Pre - age 65
Current health care cost trend rate	9.50	%	9.50	%	8.50	%	9.50	%
Year trend reaches ultimate	2015		2014		2018		2015

Post - age 65
Current health care cost trend rate	9.00	%	9.00	%	8.00	%	9.00	%
Year trend reaches ultimate	2014		2013		2017		2014

Ultimate health care cost trend rate	5.00	%	5.00	%	5.00	%	5.00	%

The assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the net periodic postretirement benefit cost and the accumulated postretirement benefit obligation:

Effect of Change in Health Care Cost Trend Rate

	One-percent		One-percent
$ in millions	increase		decrease

Service cost plus interest cost	$	—	$	—
Benefit obligation	$	0.9	$	(0.8	)

The following benefit payments, which reflect future service, are expected to be paid as follows:

Estimated Future Benefit Payments and Medicare Part D Reimbursements

$ in millions	Pension		Postretirement

2011	$	21.3	$	2.5
2012	$	23.1	$	2.4
2013	$	23.1	$	2.4
2014	$	23.6	$	2.3
2015	$	24.0	$	2.1
2016 - 2020	$	122.9	$	8.8

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We expect to make contributions of $0.4 million to our SERP in 2011 to cover benefit payments. Additionally, we are considering making discretionary contributions of up to $40.0 million to our defined benefit pension plan during 2011. We also expect to contribute $2.5 million to our other postretirement benefit plans in 2011 to cover benefit payments.

The Pension Protection Act (the Act) of 2006 contained new requirements for our single employer defined benefit pension plan. In addition to establishing a 100% funding target for plan years beginning after December 31, 2008, the Act also limits some benefits if the funded status of pension plans drops below certain thresholds. Among other restrictions under the Act, if the funded status of a plan falls below a predetermined ratio of 80%, lump-sum payments to new retirees are limited to 50% of amounts that otherwise would have been paid and new benefit improvements may not go into effect. For the 2010 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 99.4% and is estimated to be 99.4% until the 2011 status is certified in September 2011 for the 2011 plan year. The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed into law on December 23, 2008, grants plan sponsors certain relief from funding requirements and benefit restrictions of the Act.

Plan Assets

Plan assets are invested using a total return investment approach whereby a mix of equity securities, debt securities and other investments are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan’s funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of Plan equity investments is to maximize the long-term real growth of Plan assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of Plan equity investments.

Long-term strategic asset allocation guidelines are determined by management and take into account the Plan’s long-term objectives as well as its short-term constraints. The target allocations for plan assets are 30-80% for equity securities, 30-65% for fixed income securities, 0-10% for cash and 0-25% for alternative investments. Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds and emerging market debt funds. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.

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The fair values of our pension plan assets at December 31, 2010 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2010

Asset Category $ in millions	Market Value at 12/31/10		Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)
Equity Securities (a)
Small/Mid Cap Equity	$	15.2	$	—	$	15.2	$	—
Large Cap Equity	49.4		—		49.4		—
DPL Inc. Common Stock	23.8		23.8		—		—
International Equity	31.5		—		31.5		—
Total Equity Securities	$	119.9	$	23.8	$	96.1	$	—

Debt Securities (b)
Emerging Markets Debt	$	5.2	$	—	$	5.2	$	—
Fixed Income	39.0		—		39.0
High Yield Bond	8.2		—		8.2		—
Long Duration Fund	58.9		—		58.9		—
Total Debt Securities	$	111.3	$	—	$	111.3	$	—

Cash and Cash Equivalents (c)
Cash	$	0.4	$	0.4	$	—	$	—

Other Investments (d)
Limited Partnership Interest	$	2.8	$	—	$	—	$	2.8
Common Collective Fund	57.4		—		—		57.4
Total Other Investments	$	60.2	$	—	$	—	$	60.2

Total Pension Plan Assets	$	291.8	$	24.2	$	207.4	$	60.2

(a) This category includes investments in equity securities of large, small and medium sized companies and equity securities of foreign companies including those in developing countries. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund except for the DPL common stock which is valued using the closing price on the New York Stock Exchange.

(b) This category includes investments in investment-grade fixed-income instruments, U.S. dollar-denominated debt securities of emerging market issuers and high yield fixed-income securities that are rated below investment grade. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

(d) This category represents a private equity fund that specializes in management buyouts and a hedge fund of funds made up of 30+ different hedge fund managers diversified over eight different hedge strategies. The fair value of the private equity fund is determined by the General Partner based on the performance of the individual companies. The fair value of the hedge fund is valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

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The fair values of our pension plan assets at December 31, 2009 by asset category are as follows:

Fair Value Measurements for Pension Plan Assets at December 31, 2009

Asset Category $ in millions	Market Value at 12/31/09		Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)
Equity Securities (a)
Small/Mid Cap Equity	$	4.5	$	—	$	4.5	$	—
Large Cap Equity	35.9		—		35.9		—
DPL Inc. Common Stock	25.5		25.5		—		—
International Equity	19.2		—		19.2		—
Total Equity Securities	$	85.1	$	25.5	$	59.6	$	—

Debt Securities (b)
Emerging Markets Debt	$	12.9	$	—	$	12.9	$	—
High Yield Bond	13.8		—		13.8		—
Long Duration Fund	77.4		—		77.4		—
Total Debt Securities	$	104.1	$	—	$	104.1	$	—

Cash and Cash Equivalents (c)
Cash	$	0.5	$	0.5	$	—	$	—

Other Investments (d)
Limited Partnership Interest	$	3.1	$	—	$	—	$	3.1
Common Collective Fund	50.6		—		—		50.6
Total Other Investments	$	53.7	$	—	$	—	$	53.7

Total Pension Plan Assets	$	243.4	$	26.0	$	163.7	$	53.7

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The change in the fair value for the pension assets valued using significant unobservable inputs (Level 3) was due to the following:

Fair Value Measurements of Pension Assets Using Significant Unobservable Inputs

(Level 3)

$ in millions	Limited Partnership Interest			Common Collective Fund
Beginning balance at December 31, 2008	$	3.1		$	33.1
Actual return on plan assets:
Relating to assets still held at the reporting date	0.1			1.3
Relating to assets sold during the period	—			—
Purchases, sales, and settlements	(0.1		)	16.2
Transfers in and / or out of Level 3	—			—
Ending balance at December 31, 2009	$	3.1		$	50.6

Actual return on plan assets:
Relating to assets still held at the reporting date	$	0.1		$	0.8
Relating to assets sold during the period	—			—
Purchases, sales, and settlements	(0.4		)	6.0
Transfers in and / or out of Level 3	—			—
Ending balance at December 31, 2010	$	2.8		$	57.4

The fair values of our other postretirement benefit plan assets at December 31, 2010 by asset category are as follows:

Fair Value Measurements for Postretirement Plan Assets at December 31, 2010

Asset Category $ in millions	Market Value at 12/31/10		Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)

JP Morgan Core Bond Fund (a)	$	4.8	$	—	$	4.8	$	—

(a) This category includes investments in U.S. government obligations and mortgage-backed and asset-backed securities. The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

The fair values of our other postretirement benefit plan assets at December 31, 2009 by asset category are as follows:

Fair Value Measurements for Postretirement Plan Assets at December 31, 2009

Asset Category $ in millions	Market Value at 12/31/09		Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs		Significant Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)

JP Morgan Core Bond Fund (a)	$	5.0	$	—	$	5.0	$	—

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8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other method is available to us. The fair value of our financial instruments represents estimates of possible value that may or may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at December 31, 2010 and 2009. See also Note 9 of Notes to Consolidated Financial Statements for the fair values of our derivative instruments.

	At December 31,				At December 31,
	2010				2009
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities	3.8		4.4		2.6		2.8
Debt Securities	5.2		5.5		5.3		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.2
Total Master Trust Assets	$	10.9	$	11.8	$	12.3	$	12.6

Short-term Investments - VRDNs	$	54.2	$	54.2	$	—	$	—
Short-term Investments - Bonds	15.1		15.1		—		—
Total Short-term Investments	$	69.3	$	69.3	$	—	$	—
Total Assets	$	80.2	$	81.1	$	12.3	$	12.6

Liabilities
Debt	$	1,324.1	$	1,307.5	$	1,324.1	$	1,317.6

DP&L
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities (a)	17.5		30.2		16.7		31.1
Debt Securities	5.2		5.5		5.3		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.2
Total Master Trust Assets	$	24.6	$	37.6	$	26.4	$	40.9

Liabilities
Debt	$	884.1	$	850.6	$	884.3	$	844.5

(a) DPL stock held in the DP&L Master Trust is eliminated in consolidation.

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Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at amortized cost in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2040.

Master Trust Assets

DP&L established a Master Trust to hold assets for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds and DPL common stock. The DPL common stock held by the DP&L Master Trust is eliminated in consolidation and is not reflected in DPL’s Consolidated Balance Sheets. The DPL common stock is valued using current public market prices, while the open-ended mutual funds are valued using the net asset value per unit. These investments are recorded at fair value within Other assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DPL had $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2010 and $0.3 million ($0.2 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2009.

DP&L had $13.0 million ($8.5 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at December 31, 2010 and $14.5 million ($9.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2009.

Approximately $1.0 million in unrealized gains are expected to be transferred to earnings in the next twelve months.

Short-term Investments

DPL utilizes VRDNs as part of its short-term investment strategy. The VRDNs are of high credit quality and are secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale upon notice back to the financial institution. Although DPL’s VRDN investments have original maturities over one year, they are frequently re-priced and trade at par. We account for these VRDNs as available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since they are highly liquid and are readily available to support DPL’s current operating needs.

DPL also holds investment-grade fixed income corporate bonds that are classified as held-to-maturity. Held-to-maturity securities are those securities that we have the intent and ability to hold until maturity. The held-to-maturity securities are carried at amortized cost which is determined based on specific identification. The bonds are classified as short-term since they will mature within the next twelve months.

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Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of December 31, 2010. These assets are part of the Master Trust and exclude DPL common stock which is valued using quoted market prices and not the NAV per unit. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of December 31, 2010, DPL did not have any investments for sale at a price different from the NAV per unit.

Fair Value Estimated Using Net Asset Value per Unit

$ in millions	Fair Value at December 31, 2010		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
Money Market Fund (a)	$	1.6	$	—	Immediate	None

Equity Securities (b)	4.4		—		Immediate	None

Debt Securities (c)	5.5		—		Immediate	None

Multi-Strategy Fund (d)	0.3		—		Immediate	None

Total	$	11.8	$	—

	(a)	This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit.

	(b)	This category includes investments in hedge funds representing an S&P 500 index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit.

	(c)	This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit.

	(d)	This category includes investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit.

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Fair Value Estimated Using Net Asset Value per Unit

$ in millions	Fair Value at December 31, 2009		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
Money Market Fund (a)	$	4.1	$	—	Immediate	None

Equity Securities (b)	2.8		—		Immediate	None

Debt Securities (c)	5.5		—		Immediate	None

Multi-Strategy Fund (d)	0.2		—		Immediate	None

Total	$	12.6	$	—

(a) This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit.

(b) This category includes investments in hedge funds representing an S&P 500 index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit.

(c) This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit.

(d) This category includes investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as Level 1 (quoted prices in active markets for identical assets or liabilities); Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or Level 3 (unobservable inputs).

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the twelve months ended December 31, 2010 and 2009. The fair value of assets and liabilities at December 31, 2010 and 2009 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:

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DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2010*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities	4.4		—		4.4		—		—			4.4
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	11.8	$	—	$	11.8	$	—	$	—		$	11.8

Derivative Assets
FTRs	$	0.3	$	—	$	0.3	$	—	$	—		$	0.3
Heating Oil Futures	1.6		1.6		—		—		(1.6		)	—
Interest Rate Hedge	20.7		—		20.7		—		—			20.7
Forward NYMEX Coal Contracts	37.5		—		37.5		—		(21.9		)	15.6
Forward Power Contracts	0.2		—		0.2		—		(0.2		)	—
Total Derivative Assets	$	60.3	$	1.6	$	58.7	$	—	$	(23.7	)	$	36.6

Short-term Investments - VRDNs	$	54.2	$	—	$	54.2	$	—	$	—		$	54.2
Short-term Investments - Bonds	15.1		—		15.1		—		—			15.1
Total Short-term investments	$	69.3	$	—	$	69.3	$	—	$	—		$	69.3

Total Assets	$	141.4	$	1.6	$	139.8	$	—	$	(23.7	)	$	117.7

Liabilities
Derivative Liabilities
Interest Rate Hedge	$	6.6	$	—	$	6.6	$	—	$	—		$	6.6
Forward Power Contracts	3.1		—		3.1		—		(1.1		)	2.0
Total Derivative Liabilities	$	9.7	$	—	$	9.7	$	—	$	(1.1	)	$	8.6

Total Liabilities	$	9.7	$	—	$	9.7	$	—	$	(1.1	)	$	8.6

*Includes credit valuation adjustments for counterparty risk.

DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2009*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2009
Assets
Master Trust Assets
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities	2.8		—		2.8		—		—			2.8
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	12.6	$	—	$	12.6	$	—	$	—		$	12.6

Derivative Assets
FTRs	$	0.8	$	—	$	0.8	$	—	$	—		$	0.8
Forward NYMEX Coal Contracts	5.5		—		5.5		—		(1.4		)	4.1
Forward Power Contracts	0.7		—		0.7		—		(0.7		)	—
Total Derivative Assets	$	7.0	$	—	$	7.0	$	—	$	(2.1	)	$	4.9

Total Assets	$	19.6	$	—	$	19.6	$	—	$	(2.1	)	$	17.5

Liabilities
Derivative Liabilities
Heating Oil Futures	$	1.2	$	1.2	$	—	$	—	$	(1.2	)	$	—
Forward Power Contracts	3.0		—		3.0		—		(0.7		)	2.3
Forward NYMEX Coal Contracts	1.2		—		1.2		—		—			1.2
Total Derivative Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

Total Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

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The fair value of assets and liabilities at December 31, 2010 and 2009 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows:

DP&L

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2010*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities (a)	30.2		25.8		4.4		—		—			30.2
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	37.6	$	25.8	$	11.8	$	—	$	—		$	37.6

Derivative Assets
FTRs	$	0.3	$	—	$	0.3	$	—	$	—		$	0.3
Heating Oil Futures	1.6		1.6		—		—		(1.6		)	—
Forward NYMEX Coal Contracts	37.5		—		37.5		—		(21.9		)	15.6
Forward Power Contracts	0.2		—		0.2		—		(0.2		)	—
Total Derivative Assets	$	39.6	$	1.6	$	38.0	$	—	$	(23.7	)	$	15.9

Total Assets	$	77.2	$	27.4	$	49.8	$	—	$	(23.7	)	$	53.5

Liabilities
Derivative Liabilities
Heating Oil Futures	$	—	$	—	$	—	$	—	$	—		$	—
Forward Power Contracts	3.1		—		3.1		—		(1.1		)	2.0
Forward NYMEX Coal Contracts	—		—		—		—		—			—
Total Derivative Liabilities	$	3.1	$	—	$	3.1	$	—	$	(1.1	)	$	2.0

Total Liabilities	$	3.1	$	—	$	3.1	$	—	$	(1.1	)	$	2.0

*Includes credit valuation adjustments for counterparty risk.

(a) DPL stock in the Master Trust is eliminated in consolidation.

DP&L

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2009*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2009
Assets
Master Trust Assets
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities (a)	31.1		28.3		2.8		—		—			31.1
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	40.9	$	28.3	$	12.6	$	—	$	—		$	40.9

Derivative Assets
FTRs	$	0.8	$	—	$	0.8	$	—	$	—		$	0.8
Forward NYMEX Coal Contracts	5.5		—		5.5		—		(1.4		)	4.1
Forward Power Contracts	0.7		—		0.7		—		(0.7		)	—
Total Derivative Assets	$	7.0	$	—	$	7.0	$	—	$	(2.1	)	$	4.9

Total Assets	$	47.9	$	28.3	$	19.6	$	—	$	(2.1	)	$	45.8

Liabilities
Derivative Liabilities
Heating Oil Futures	$	1.2	$	1.2	$	—	$	—	$	(1.2	)	$	—
Forward Power Contracts	3.0		—		3.0		—		(0.7		)	2.3
Forward NYMEX Coal Contracts	1.2		—		1.2		—		—			1.2
Total Derivative Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

Total Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

(a) DPL stock in the Master Trust is eliminated in consolidation.

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We use the market approach to value our financial instruments. Level 1 inputs are used for DPL common stock held by the Master Trust and for derivative contracts such as heating oil futures and natural gas futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as financial transmission rights (where the quoted prices are from a relatively inactive market), forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). VRDNs and bonds are considered Level 2 because they are priced using recent transactions for similar assets. Other Level 2 assets include: open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit, and interest rate hedges, which use observable inputs to populate a pricing model.

Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. There were $1.4 million and $2.7 million of gross additions to our existing landfill and asbestos AROs during the twelve months ended December 31, 2010 and 2009. In addition, it was determined that a river structure would be retired earlier than previously estimated. This resulted in a partial reduction to the ARO liability of $0.8 million in 2010.

Cash Equivalents

DPL had $29.9 million and $45.3 million in money market funds classified as cash and cash equivalents in its Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. The money market funds have quoted prices that are generally equivalent to par.

9. Derivative Instruments and Hedging Activities

In the normal course of business, DPL and DP&L enter into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges or marked to market each reporting period.

At December 31, 2010, DPL and DP&L had the following outstanding derivative instruments:

	Accounting		Purchases	Sales		Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs (1)	Mark to Market	MWh	9.0	—		9.0
Heating Oil Futures (1)	Mark to Market	Gallons	6,216.0	—		6,216.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	580.8	(572.9	)	7.9
Forward Power Contracts (1)	Mark to Market	MWh	195.6	(108.5	)	87.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	4,006.8	—		4,006.8
Interest Rate Swaps (2)	Cash Flow Hedge	USD	360,000.0	—		360,000.0

*Includes our partners’ share for the jointly-owned plants that DP&L operates.

(1) Reflected in both DPL’s and DP&L’s financial statements

(2) Reflected in only DPL’s financial statements

At December 31, 2009, both DPL and DP&L had the following outstanding derivative instruments:

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	Accounting		Purchases	Sales		Net Purchase/ (Sale)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs	Mark to Market	MWH	9.3	—		9.3
Heating Oil Futures	Mark to Market	Gallons	3,822.0	—		3,822.0
Forward Power Contracts	Cash Flow Hedge	MWH	84.6	(1,769.2	)	(1,684.6	)
NYMEX-quality Coal Contracts*	Mark to Market	Tons	3,844.0	(1,286.5	)	2,557.5

*Includes our partner’s share for the jointly-owned plants that DP&L operates.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges as determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.

We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. As of December 31, 2010, we have entered into interest rate hedging relationships with aggregate notional amounts of $200 million and $160 million related to planned future borrowing activities in calendar years 2011 and 2013, respectively. We reclassify gains and losses on interest rate derivative hedges related to our debt financings from AOCI into earnings in those periods in which hedged interest payments occur.

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The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges:

	December 31,						December 31,						December 31,
	2010						2009						2008
				Interest						Interest			Power and			Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge			Capacity			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(1.4	)	$	14.7		$	(0.2	)	$	17.2		$	(1.0	)	$	19.7

Net gains / (losses) associated with current period hedging transactions	3.1			9.2			2.2			—			4.8			—

Net gains reclassified to earnings
Interest Expense	—			(2.5		)	—			(2.5		)	—			(2.5		)
Revenues	(3.5		)	—			(3.4		)	—			(4.0		)	—

Ending accumulated derivative gain / (loss) in AOCI	$	(1.8	)	$	21.4		$	(1.4	)	$	14.7		$	(0.2	)	$	17.2

Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest expense	$	—		$	—		$	—		$	—		$	—		$	—
Revenues	$	—		$	—		$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(2.8	)	$	2.5

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	36			33

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges:

	December 31,						December 31,						December 31,
	2010						2009						2008
				Interest						Interest			Power and			Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge			Capacity			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(1.4	)	$	14.7		$	(0.2	)	$	17.2		$	(1.0	)	$	19.7

Net gains / (losses) associated with current period hedging transactions	3.1			—			2.2			—			4.8			—

Net gains reclassified to earnings
Interest Expense	—			(2.5		)	—			(2.5		)	—			(2.5		)
Revenues	(3.5		)	—			(3.4		)	—			(4.0		)	—

Ending accumulated derivative gain / (loss) in AOCI	$	(1.8	)	$	12.2		$	(1.4	)	$	14.7		$	(0.2	)	$	17.2

Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest expense	$	—		$	—		$	—		$	—		$	—		$	—
Revenues	$	—		$	—		$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(2.8	)	$	—

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	36			—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

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The following table shows the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at December 31, 2010

DPL

								Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in a Liability Position	$	(2.8	)	$	1.0		Other current liabilities	$	(1.8	)
Interest Rate Hedges in a Liability Position	(6.6		)	—			Other current liabilities	(6.6		)

Total short-term cash flow hedges	$	(9.4	)	$	1.0			$	(8.4	)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position	$	0.2		$	(0.2	)	Other deferred assets	$	—
Forward Power Contracts in a Liability Position	(0.2		)	0.1			Other deferred credits	(0.1		)
Interest Rate Hedges in an Asset Position	20.7			—			Other deferred credits	20.7

Total long-term cash flow hedges	$	20.7		$	(0.1	)		$	20.6

Total cash flow hedges	$	11.3		$	0.9			$	12.2

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments at December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at December 31, 2010

DP&L

								Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in a Liability Position	$	(2.8	)	$	1.0		Other current liabilities	$	(1.8	)

Total short-term cash flow hedges	$	(2.8	)	$	1.0			$	(1.8	)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position	$	0.2		$	(0.2	)	Other deferred assets	$	—
Forward Power Contracts in a Liability Position	(0.2		)	0.1			Other deferred credits	(0.1		)

Total long-term cash flow hedges	$	—		$	(0.1	)		$	(0.1	)

Total cash flow hedges	$	(2.8	)	$	0.9			$	(1.9	)

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

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The following table shows the fair value and balance sheet classification of DPL’s and DP&L’s derivative instruments designated as hedging instruments at December 31, 2009.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at December 31, 2009

								Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	0.7		$	(0.7	)	Other prepayments	$	—
							and current assets
Forward Power Contracts in a Liability Position	(2.8		)	0.7			Other current liabilities	(2.1		)

Total cash flow hedges	$	(2.1	)	$	—			$	(2.1	)

(1) Includes credit valuation adjustment

(2) Includes counterparty and collateral netting.

Mark to Market Accounting

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC Topic 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures, forward NYMEX-quality coal contracts, natural gas futures and certain forward power contracts.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to MTM accounting treatment and are recognized in the consolidated statements of results of operations on an accrual basis.

Regulatory Assets and Liabilities

In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ portion of the heating oil futures and the NYMEX-quality coal contracts are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.

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The following tables show the amount and classification within the consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s and DP&L’s derivatives not designated as hedging instruments for the twelve months ended December 31, 2010 and 2009.

For the Twelve Months Ended December 31, 2010

$ in millions	NYMEX Coal		Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	33.5	$	2.8		$	(0.6	)	$	0.1		$	35.8
Realized gain / (loss)	3.2		(1.6		)	(1.5		)	(0.1		)	—
Total	$	36.7	$	1.2		$	(2.1	)	$	—		$	35.8
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	20.1	$	—		$	—		$	—		$	20.1
Regulatory (asset) / liability	4.6		1.1			—			—			5.7

Recorded in Income Statement: gain / (loss)
Purchased power	$	—	$	—		$	(2.1	)	$	—		$	(2.1	)
Fuel	12.0		0.1			—			—			12.1
O&M	—		—			—			—			—
Total	$	36.7	$	1.2		$	(2.1	)	$	—		$	35.8

For the Twelve Months Ended December 31, 2009

$ in millions	NYMEX Coal		Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	4.1	$	5.1		$	0.8		$	(0.2	)	$	9.8
Realized gain / (loss)	1.1		(3.1		)	(0.4		)	—			(2.4		)
Total	$	5.2	$	2.0		$	0.4		$	(0.2	)	$	7.4
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	1.8	$	—		$	—		$	—		$	1.8
Regulatory (asset) / liability	1.5		(0.5		)	—			—			1.0

Recorded in Income Statement: gain / (loss)
Purchased power	$	—	$	—		$	0.4		$	(0.2	)	$	0.2
Fuel	1.9		2.3			—			—			4.2
O&M	—		0.2			—			—			0.2
Total	$	5.2	$	2.0		$	0.4		$	(0.2	)	$	7.4

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The following tables show the fair value and balance sheet classification of DPL’s and DP&L’s derivative instruments not designated as hedging instruments at December 31, 2010 and 2009.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at December 31, 2010

$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.3		$	—		Other prepayments and current assets	$	0.3
Forward Power Contracts in a Liability position	(0.1		)	—			Other current liabilities	(0.1		)
NYMEX-Quality Coal Forwards in an Asset position	14.0			(7.4		)	Other prepayments and current assets	6.6
Heating Oil Futures in an Asset position	0.5			(0.5		)	Other current liabllities	—

Total short-term derivative MTM positions	$	14.7		$	(7.9	)		$	6.8

Long-term Derivative Positions
NYMEX-Quality Coal Forwards in an Asset position	$	23.5		$	(14.5	)	Other deferred assets	$	9.0
Heating Oil Futures in an Asset position	1.1			(1.1		)	Other deferred credits	—

Total long-term derivative MTM positions	$	24.6		$	(15.6	)		$	9.0

Total MTM Position	$	39.3		$	(23.5	)		$	15.8

(1) Includes credit valuation adjustment

(2) Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at December 31, 2009

$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.8		$	—		Other prepayments and current assets	$	0.8
NYMEX-Quality Coal Forwards in an Asset position	2.4			—			Other prepayments and current assets	2.4
NYMEX-Quality Coal Forwards in a Liability position	(1.2		)	—			Other current liabilities	(1.2		)
Heating Oil Futures in a Liability position	(1.2		)	1.2			Other current liabllities	—
Forward Power Contracts in a Liability position	(0.2		)	—			Other current liabilities	(0.2		)

Total short-term derivative MTM positions	$	0.6		$	1.2			$	1.8

Long-term Derivative Positions
NYMEX-Quality Coal Forwards in an Asset position	$	2.9		$	(1.2	)	Other deferred assets	$	1.7

Total long-term derivative MTM positions	$	2.9		$	(1.2	)		$	1.7

Total MTM Position	$	3.5		$	—			$	3.5

(1) Includes credit valuation adjustment

(2) Includes counterparty and collateral netting.

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. The aggregate fair value of all commodity derivative instruments that are in a MTM loss position at December 31, 2010 is $3.1 million. This amount is offset by $1.0 million in a broker margin account which offsets our loss positions on the NYMEX Clearport traded forward power contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $0.2 million. If our debt were to fall below investment grade, we may have to post collateral for the remaining $1.9 million.

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10. Share-Based Compensation

In April 2006, DPL’s shareholders approved The DPL Inc. Equity and Performance Incentive Plan (the EPIP) which became immediately effective and will remain in effect for a term of ten years, unless terminated sooner in accordance with its terms. The Compensation Committee of the Board of Directors will designate the employees and directors eligible to participate in the EPIP and the times and types of awards to be granted. Under the EPIP, the Compensation Committee may grant equity-based compensation in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares and units, and other stock-based awards. Awards may be subject to the achievement of certain management objectives. In addition, the EPIP provides, upon recommendation of the Chief Executive Officer or Chairman of the Board, for a grant of a special equity award to recognize outstanding performance. A total of 4,500,000 shares of DPL common stock were reserved for issuance under the EPIP.

The following table summarizes share-based compensation expense recorded at DPL and DP&L:

	For the years ended
	December 31,
$ in millions	2010			2009			2008
Restricted stock units	$	—		$	—		$	(0.1	)
Performance shares	2.1			1.8			0.9
Restricted shares	1.7			0.7			0.3
Non-employee directors’ RSUs	0.4			0.5			0.5
Management performance shares	0.5			0.7			0.3
Share-based compensation included in Operation and maintenance expense	4.7			3.7			1.9
Income tax expense / (benefit)	(1.6		)	(1.3		)	(0.7		)
Total share-based compensation, net of tax	$	3.1		$	2.4		$	1.2

Share-based awards issued in DPL’s common stock will be distributed from treasury stock. DPL has sufficient treasury stock to satisfy all outstanding share-based awards.

Determining Fair Value

Valuation and Amortization Method — We estimate the fair value of stock options and RSUs using a Black-Scholes-Merton model; performance shares are valued using a Monte Carlo simulation; restricted shares are valued at the closing market price on the day of grant and the Directors’ RSUs are valued at the closing market price on the day prior to the grant date. We amortize the fair value of all awards on a straight-line basis over the requisite service periods, which are generally the vesting periods.

Expected Volatility — Our expected volatility assumptions are based on the historical volatility of DPL common stock. The volatility range captures the high and low volatility values for each award granted based on its specific terms.

Expected Life — The expected life assumption represents the estimated period of time from the grant date until the exercise date and reflects historical employee exercise patterns.

Risk-Free Interest Rate — The risk-free interest rate for the expected term of the award is based on the corresponding yield curve in effect at the time of the valuation for U.S. Treasury bonds having the same term as the expected life of the award, i.e., a five year bond rate is used for valuing an award with a five year expected life.

Expected Dividend Yield — The expected dividend yield is based on DPL’s current dividend rate, adjusted as necessary to capture anticipated dividend changes and the 12 month average DPL common stock price.

Expected Forfeitures — The forfeiture rate used to calculate compensation expense is based on DPL’s historical experience, adjusted as necessary to reflect special circumstances.

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Stock Options

In 2000, DPL’s Board of Directors adopted and DPL’s shareholders approved The DPL Inc. Stock Option Plan. With the approval of the EPIP in April 2006, no new awards will be granted under The DPL Inc. Stock Option Plan but shares relating to awards that are forfeited or terminated under The DPL Inc. Stock Option Plan may be granted under the EPIP. As of December 31, 2010, there were no unvested stock options.

Summarized stock option activity was as follows:

	For the years ended
	December 31,
	2010			2009			2008
Options:
Outstanding at beginning of year	417,500			836,500			946,500
Granted	—			—			—
Exercised	(66,000		)	(419,000		)	(110,000		)
Forfeited	—			—			—
Outstanding at year-end	351,500			417,500			836,500
Exercisable at year-end*	351,500			417,500			836,500

Weighted average option prices per share:
Outstanding at beginning of year	$	27.16		$	24.64		$	24.09
Granted	$	—		$	—		$	—
Exercised	$	21.00		$	21.53		$	18.56
Forfeited	$	—		$	—		$	—
Outstanding at year-end	$	28.04		$	27.16		$	24.64
Exercisable at year-end	$	28.04		$	27.16		$	24.64

*251,000 of these stock options expired on January 1, 2011.

The following table reflects information about stock options outstanding at December 31, 2010:

		Options Outstanding			Options Exercisable
		Weighted-	Weighted-			Weighted-
		Average	Average			Average
Range of Exercise		Contractual	Exercise			Exercise
Prices	Outstanding	Life (in Years)	Price		Exercisable	Price

$14.95 - $21.00	75,000	0.3	$	20.97	75,000	$	20.97
$21.01 - $29.63	276,500	0.1	$	29.42	276,500	$	29.42

The following table reflects information about stock option activity during the period:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
Weighted-average grant date fair value of options granted during the period	$	—	$	—	$	—
Intrinsic value of options exercised during the period	$	0.5	$	2.2	$	1.0
Proceeds from stock options exercised during the period	$	1.4	$	9.0	$	2.2
Excess tax benefit from proceeds of stock options exercised	$	0.1	$	0.7	$	0.3
Fair value of shares that vested during the period	$	—	$	—	$	—
Unrecognized compensation expense	$	—	$	—	$	—
Weighted average period to recognize compensation expense (in years)	—		—		—

No options were granted during 2010, 2009 or 2008.

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Restricted Stock Units (RSUs)

RSUs were granted to certain key employees prior to 2001. As of December 31, 2010, there were no RSUs outstanding.

			Weighted-Avg.
	Number of		Grant Date
$ in millions	RSUs		Fair Value
Non-vested at January 1, 2010	3,311		$	0.1
Granted in 2010	—		—
Vested in 2010	(3,311	)	(0.1		)
Forfeited in 2010	—		—
Non-vested at December 31, 2010	—		$	—

Summarized RSU activity was as follows:

	For the years ended
	December 31,
	2010		2009		2008
RSUs:
Outstanding at beginning of year	3,311		10,120		22,976
Granted	—		—		—
Dividends	—		—		—
Exercised	(3,311	)	(6,809	)	(11,253	)
Forfeited	—		—		(1,603	)
Outstanding at period end	—		3,311		10,120
Exercisable at period end	—		—		—

Compensation expense is recognized each quarter based on the change in the market price of DPL common stock.

As of December 31, 2010, 2009 and 2008, liabilities recorded for outstanding RSUs were zero, $0.1 million and $0.2 million, respectively, which are included in Other deferred credits on the balance sheets.

Performance Shares

Under the EPIP, the Board of Directors adopted a Long-Term Incentive Plan (LTIP) under which DPL will grant a targeted number of performance shares of common stock to executives. Grants under the LTIP will be awarded based on a Total Shareholder Return Relative to Peers performance. No performance shares will be earned in a performance period if the three-year Total Shareholder Return Relative to Peers is below the threshold of the 40th percentile. Further, the LTIP awards will be capped at 200% of the target number of performance shares, if the Total Shareholder Return Relative to Peers is at or above the threshold of the 90th percentile. The Total Shareholder Return Relative to Peers is considered a market condition in accordance with the accounting guidance for share-based compensation. There is a three year requisite service period for each portion of the performance shares.

The schedule of non-vested performance share activity for the year ended December 31, 2010 follows:

	Number of		Weighted-Avg.
	Performance		Grant Date
$ in millions	Shares		Fair Value
Non-vested at January 1, 2010	190,349		$	4.3
Granted in 2010	161,534		2.9
Vested in 2010	(110,734	)	(1.6		)
Forfeited in 2010	(29,651	)	(0.7		)
Non-vested at December 31, 2010	211,498		$	4.9

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	For the years ended
	December 31,
	2010		2009		2008
Performance shares:
Outstanding at beginning of year	237,704		156,300		142,108
Granted	161,534		124,588		93,298
Exercised	(91,253	)	—		—
Expired	—		(36,445	)	(37,426	)
Forfeited	(29,651	)	(6,739	)	(41,680	)
Outstanding at period end	278,334		237,704		156,300
Exercisable at period end	66,836		47,355		36,445

The following table reflects information about performance share activity during the period:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
Weighted-average grant date fair value of performance shares granted during the period	$	2.9	$	2.8	$	2.2
Intrinsic value of performance shares exercised during the period	$	2.5	$	—	$	—
Proceeds from performance shares exercised during the period	$	—	$	—	$	—
Excess tax benefit from proceeds of performance shares exercised	$	—	$	—	$	—
Fair value of performance shares that vested during the period	$	1.6	$	1.6	$	0.8
Unrecognized compensation expense	$	2.4	$	2.1	$	1.6
Weighted average period to recognize compensation expense (in years)	1.7		1.7		1.6

The following table shows the assumptions used in the Monte Carlo Simulation to calculate the fair value of the performance shares granted during the period:

	For the years ended
	December 31,
	2010	2009	2008
Expected volatility	24.3%	22.8% - 23.3%	15.0% - 15.7%
Weighted-average expected volatility	24.3%	22.8%	15.1%
Expected life (years)	3.0	3.0	3.0
Expected dividends	4.5%	5.4% - 5.6%	3.5% - 4.1%
Weighted-average expected dividends	4.5%	5.6%	4.1%
Risk-free interest rate	1.4%	0.3% - 1.5%	2.2% - 3.2%

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Restricted Shares

Under the EPIP, the Board of Directors have granted shares of DPL restricted shares to various executives. The restricted shares are registered in the executive’s name, carry full voting privileges, receive dividends as declared and paid on all DPL common stock and vest after a specified service period.

In July 2008, the Board of Directors granted restricted stock awards to a select group of management employees. The management restricted stock awards have a three-year requisite service period, carry full voting privileges and receive dividends as declared and paid on all DPL common stock.

On September 17, 2009, the Board of Directors approved a two-part equity compensation award under the EPIP for certain of DPL’s executive officers. The first part is a restricted share grant and the second part is a matching restricted share grant. These restricted shares generally vest after five years if the participant remains continuously employed with DPL or a DPL subsidiary and if the year over year average basic EPS has increased by at least 1% per year over the five year vesting period. Under the matching restricted share grant, participants will have a three-year period from the date of plan implementation during which they may purchase DPL common stock equal in value to up to two times their base salary. DPL will match the shares purchased with another grant of restricted stock (matching restricted share grant). The percentage match by DPL is detailed in the table below. The matching restricted share grant will generally vest over a three year period if the participant continues to hold the originally purchased shares and remains continuously employed with DPL or a subsidiary. The restricted shares are registered in the executive’s name, carry full voting privileges and receive dividends as declared and paid on all DPL common stock.

The matching criteria are:

Value (Cost Basis) of Shares Purchased as a % of 2009 Base Salary		Company % Match of Shares Purchased
<25%		25%
25% to <50%		50%
50% to <100%		75%
100% to 200%		125%

The matching percentage is applied on a cumulative basis and the resulting restricted shares grant is adjusted at the end of each quarter.

Restricted shares can only be awarded in DPL common stock.

	Number of		Weighted-Avg.
	Restricted		Grant Date
$ in millions	Shares		Fair Value
Non-vested at January 1, 2010	218,197		$	5.8
Granted in 2010	42,977		1.1
Vested in 2010	(20,803	)	(0.6		)
Forfeited in 2010	(20,980	)	(0.6		)
Non-vested at December 31, 2010	219,391		$	5.7

	For the years ended
	December 31,
	2010		2009		2008
Restricted shares:
Outstanding at beginning of year	218,197		69,147		42,200
Granted	42,977		159,050		39,347
Exercised	(20,803	)	(10,000	)	(1,000	)
Forfeited	(20,980	)	—		(11,400	)
Outstanding at period end	219,391		218,197		69,147
Exercisable at period end	—		—		—

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The following table reflects information about restricted share activity during the period:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
Weighted-average grant date fair value of restricted shares granted during the period	$	1.1	$	4.2	$	1.1
Intrinsic value of restricted shares exercised during the period	$	0.4	$	0.3	$	—
Proceeds from restricted shares exercised during the period	$	—	$	—	$	—
Excess tax benefit from proceeds of restricted shares exercised	$	0.1	$	—	$	—
Fair value of restricted shares that vested during the period	$	0.6	$	0.3	$	—
Unrecognized compensation expense	$	3.4	$	4.3	$	1.3
Weighted average period to recognize compensation expense (in years)	2.7		3.4		2.7

Non-Employee Director Restricted Stock Units

Under the EPIP, as part of their annual compensation for service to DPL and DP&L, each non-employee Director receives a retainer in RSUs on the date of the annual meeting of shareholders. The RSUs will become non-forfeitable on April 15 of the following year. All of the RSUs become non-forfeitable in the event of death, disability, or change in control; but if the Director resigns or retires prior to the April 15 vesting date, the vested shares will be distributed on a pro rata basis. The RSUs accrue quarterly dividends in the form of additional RSUs. Upon vesting, the RSUs will become exercisable and will be distributed in DPL common stock, unless the Director chooses to defer receipt of the shares until a later date. The RSUs are valued at the closing stock price on the day prior to the grant and the compensation expense is recognized evenly over the vesting period.

	Number of		Weighted-Avg.
	Director		Grant Date
$ in millions	RSUs		Fair Value
Non-vested at January 1, 2010	20,712		$	0.4
Granted in 2010	15,752		0.4
Dividends accrued in 2010	2,484		0.1
Vested, exercised and issued in 2010	(2,618	)	(0.1		)
Vested, exercised and deferred in 2010	(20,010	)	(0.4		)
Forfeited in 2010	—		—
Non-vested at December 31, 2010	16,320		$	0.4

	For the years ended
	December 31,
	2010		2009		2008
Restricted stock units:
Outstanding at beginning of year	20,712		15,546		13,573
Granted	15,752		20,016		17,022
Dividends accrued	2,484		1,737		931
Vested, exercised and issued	(2,618	)	(2,066	)	(7,910	)
Vested, exercised and deferred	(20,010	)	(14,521	)	(6,921	)
Forfeited	—		—		(1,149	)
Outstanding at period end	16,320		20,712		15,546
Exercisable at period end	—		—		—

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The following table reflects information about non-employee director RSU activity during the period:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
Weighted-average grant date fair value of non-employee director RSUs granted during the period	$	0.5	$	0.5	$	0.5
Intrinsic value of non-employee director RSUs exercised during the period	$	0.5	$	0.4	$	0.4
Proceeds from non-employee director RSUs exercised during the period	$	—	$	—	$	—
Excess tax benefit from proceeds of non-employee director RSUs exercised	$	—	$	—	$	—
Fair value of non-employee director RSUs that vested during the period	$	0.6	$	0.5	$	0.5
Unrecognized compensation expense	$	0.1	$	0.1	$	0.1
Weighted average period to recognize compensation expense (in years)	0.3		0.3		0.3

Management Performance Shares

Under the EPIP, the Board of Directors granted compensation awards for select management employees. The grants have a three year requisite service period and certain performance conditions during the performance period. The management performance shares can only be awarded in DPL common stock.

	Number of		Weighted-Avg.
	Mgt. Performance		Grant Date
$ in millions	Shares		Fair Value
Non-vested at January 1, 2010	84,241		$	2.1
Granted in 2010	37,480		0.9
Vested in 2010	(31,081	)	(0.9		)
Forfeited in 2010	(17,597	)	(0.4		)
Non-vested at December 31, 2010	73,043		$	1.7

	For the years ended
	December 31,
	2010		2009		2008
Management Performance Shares:
Outstanding at beginning of year	84,241		39,144		—
Granted	37,480		48,719		39,144
Exercised	—		—		—
Forfeited	(17,597	)	(3,622	)	—
Outstanding at period end	104,124		84,241		39,144
Exercisable at period end	31,081		—		—

The following table shows the assumptions used in the Monte Carlo Simulation to calculate the fair value of the management performance shares granted during the period:

	For the years ended
	December 31,
	2010		2009		2008
Expected volatility	24.3	%	22.8	%	14.9	%
Weighted-average expected volatility	24.3	%	22.8	%	14.9	%
Expected life (years)	3.0		3.0		3.0
Expected dividends	4.5	%	5.6	%	3.9	%
Weighted-average expected dividends	4.5	%	5.6	%	3.9	%
Risk-free interest rate	1.4	%	1.5	%	2.9	%

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The following table reflects information about management performance share activity during the period:

	For the years ended
	December 31,
$ in millions	2010		2009		2008
Weighted-average grant date fair value of management perfomance shares granted during the period	$	0.9	$	1.0	$	1.1
Intrinsic value of management performance shares exercised during the period	$	—	$	—	$	—
Proceeds from management performance shares exercised during the period	$	—	$	—	$	—
Excess tax benefit from proceeds of management performance shares exercised	$	—	$	—	$	—
Fair value of management performance shares that vested during the period	$	0.9	$	—	$	—
Unrecognized compensation expense	$	0.9	$	1.0	$	0.8
Weighted average period to recognize compensation expense (in years)	1.7		1.6		2.0

11. Redeemable Preferred Stock

DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 were outstanding as of December 31, 2010. DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding as of December 31, 2010. The table below details the preferred shares outstanding at December 31, 2010:

			Redemption		Shares	Par Value at		Par Value at
	Preferred		Price at		Outstanding at	December 31,		December 31,
	Stock		December 31,		December 31,	2010		2009
	Rate		2010		2010	($ in millions)		($ in millions)
DP&L Series A	3.75	%	$	102.50	93,280	$	9.3	$	9.3
DP&L Series B	3.75	%	$	103.00	69,398	7.0		7.0
DP&L Series C	3.90	%	$	101.00	65,830	6.6		6.6
Total					228,508	$	22.9	$	22.9

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the Balance Sheets as “Redeemable Preferred Stock” in a manner consistent with temporary equity.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its common stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its common stock subsequent to December 31, 1946, plus $1.2 million. This dividend restriction has historically not impacted DP&L’s ability to pay cash dividends and, as of December 31, 2010, DP&L’s retained earnings of $616.9 million were all available for common stock dividends payable to DPL. We do not expect this restriction to have an effect on the payment of cash dividends in the future. DPL records dividends on preferred stock of DP&L within Interest expense on the Statements of Results of Operations.

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12. Common Shareholders’ Equity

DPL has 250,000,000 authorized common shares, of which 116,924,844 are outstanding at December 31, 2010.

On October 27, 2010, the DPL Board of Directors approved a new Stock Repurchase Program under which DPL may repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. This 2010 Stock Repurchase Program is scheduled to run through December 31, 2013 but may be modified or terminated at any time without notice. Under this 2010 Stock Repurchase Program, DPL repurchased 2.04 million shares at an average per share price of $25.75 during the fourth quarter of 2010. At December 31, 2010, the amount still available that could be used to repurchase stock under this program is approximately $147.5 million.

Warrants

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may use proceeds from the exercise of DPL warrants by warrant holders to repurchase other outstanding DPL warrants or its common stock from time to time in the open market, through private transactions or otherwise. This 2009 Stock Repurchase Program is schedule to run through June 30, 2012, which is three months after the end of the warrant exercise period. Under this 2009 Stock Repurchase Program, DPL repurchased a total of 145,915 shares during the three months ended March 31, 2010 at an average per share price of $26.71, effectively utilizing the entire $3.9 million that was available to repurchase stock at December 31, 2009. However, additional funds could be available to repurchase stock if the 1.7 million warrants outstanding at December 31, 2010 are exercised for cash in the future.

In February 2000, DPL entered into a series of recapitalization transactions which included the issuance of 31.6 million warrants for an aggregate purchase price of $50 million. The warrants are exercisable, in whole or in part, for common shares at any time during the twelve-year period commencing on March 13, 2000. Each warrant is exercisable for one common share, subject to anti-dilution adjustments (e.g., stock split, stock dividend) at an exercise price of $21.00 per common share.

In addition, in the event of a declaration, issuance or consummation of any dividend, spin-off or other distribution or similar transaction by DPL of the capital stock of any of its subsidiaries, additional warrants of such subsidiary will be issued to the warrant holder so that after the transaction, the warrant holder will have the same interest in the fully diluted number of common shares of such subsidiary the warrant holder had in DPL immediately prior to such transaction.

Pursuant to the warrant agreement, DPL has authorized common shares sufficient to provide for the exercise in full of all outstanding warrants. At December 31, 2010, DPL had 1.7 million outstanding warrants which are exercisable in the future.

Dividend Reinvestment Plan

On March 1, 2009, DPL introduced a new direct stock purchase and dividend reinvestment plan. The plan provides both registered shareholders and new investors with the ability to purchase shares and also to reinvest their dividends. This plan is administered by Computershare Trust Company, N.A., and not by DPL.

Shareholder Rights Plan

In September 2001, DPL’s Board of Directors renewed its Shareholder Rights Plan, attaching one right to each common share outstanding at the close of business on December 13, 2001. The rights separate from the common shares and become exercisable at the exercise price of $130 per right in the event of certain attempted business combinations. In October 2010, DPL’s Board of Directors voted to amend the Shareholder Rights Plan to accelerate the expiration date. DPL expects the Shareholder Rights Plan to expire during the first quarter of 2011.

ESOP

During October 1992, our Board of Directors approved the formation of a Company-sponsored ESOP to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to eligible full-time employees. This leveraged ESOP is funded by an exempt loan, which is secured by the ESOP shares. As debt service payments are made on the loan, shares are released on a pro rata basis. ESOP shares used to fund matching contributions to DP&L’s 401(k) vest after three years of service; contributions after 2010 will vest after two years of service. Other compensation shares awarded vest immediately.

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In general, participants are eligible for lump sum payments upon termination of their employment and the submission and subsequent approval of an application for benefits. Earlier distributions can occur for a Qualified Domestic Relations Order or for death. Otherwise, distribution must occur within 60 days after the plan year in which the later of one of the following events occur: 65th birthday, 10th anniversary of participation, or termination of employment. Participants are allowed to take distributions during employment if older than 59½ and/or for a hardship as defined in the Plan document. Additionally, participants may elect on a quarterly basis to diversify their vested ESOP shares into DP&L’s 401(k) retirement savings plan. Distributions are made in cash unless the participant requests the distribution be made in stock. A repurchase obligation exists for vested shares held by the ESOP if they cannot be sold in the open market. The fair value of shares subject to the repurchase obligation at December 31, 2010 and 2009 was approximately $54.1 million and $57.6 million, respectively.

In 1992, the Plan entered into a $90 million loan agreement with DPL in order to purchase shares of DPL common stock in the open market. The term loan agreement provided for principal and interest on the loan to be paid prior to October 9, 2007, with the right to extend the loan for an additional ten years. In 2007, the maturity date was extended to October 7, 2017. Effective January 1, 2009, the interest on the loan was amended to a fixed rate of 2.06%, payable annually. Dividends received by the ESOP are used to repay the principal and interest on the ESOP loan to DPL. Dividends on the allocated shares are charged to retained earnings and the share value of these dividends is allocated to participants.

The ESOP used the full amount of the loan to purchase 4.7 million shares of DPL common stock in the open market. As a result of the 1997 stock split, the ESOP held 7.1 million shares of DPL common stock. The cost of shares held by the ESOP and not yet released is reported as a reduction of Common shareholders’ equity. At December 31, 2010, Common shareholders’ equity reflects the cost of 2.5 million unreleased shares held in suspense by the DPL Inc. Employee Stock Ownership Trust. The fair value of the 2.5 million ESOP shares held in suspense at December 31, 2010 was $65.3 million. When shares are committed to be released from the ESOP, compensation expense is recorded based on the fair value of the shares committed to be released, with a corresponding credit to our equity. Compensation expense associated with the ESOP, which is based on the fair value of the shares committed to be released for allocation, amounted to $6.7 million in 2010, $4.0 million in 2009 and $1.5 million in 2008.

For purposes of EPS computations and in accordance with GAAP, we treat ESOP shares as outstanding if they have been allocated to participants, released or have been committed to be released. As of December 31, 2010, the ESOP has 4.5 million shares allocated to participants with an additional 0.1 million shares which have been released or committed to be released but unallocated to participants. ESOP cumulative shares outstanding for the calculation of EPS were 4.6 million in 2010, 4.2 million in 2009 and 4.0 million in 2008.

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13. Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business entity during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: Net income (loss) and Other comprehensive income (loss).

The following table provides the tax effects allocated to each component of Other comprehensive income (loss) for the years ended December 31, 2010, 2009 and 2008:

	DPL									DP&L
	Amount			Tax						Amount			Tax
	before			(expense) /			Amount			before			(expense) /			Amount
$ in millions	tax			benefit			after tax			tax			benefit			after tax

2008:
Unrealized gains / (losses) on financial instruments	$	(0.8	)	$	0.3		$	(0.5	)	$	(15.0	)	$	5.2		$	(9.8	)
Deferred gains / (losses) on cash flow hedges	(1.3		)	(0.4		)	(1.7		)	(1.3		)	(0.4		)	(1.7		)
Unrealized gains / (losses) on pension and postretirement benefits	(33.1		)	11.6			(21.5		)	(33.4		)	11.7			(21.7		)
Other comprehensive income (loss)	$	(35.2	)	$	11.5		$	(23.7	)	$	(49.7	)	$	16.5		$	(33.2	)

2009:
Unrealized gains / (losses) on financial instruments	$	0.8		$	(0.3	)	$	0.5		$	4.2		$	(1.5	)	$	2.7
Deferred gains / (losses) on cash flow hedges	(4.3		)	0.6			(3.7		)	(4.3		)	0.6			(3.7		)
Unrealized gains / (losses) on pension and postretirement benefits	(4.1		)	1.4			(2.7		)	(4.1		)	1.4			(2.7		)
Other comprehensive income (loss)	$	(7.6	)	$	1.7		$	(5.9	)	$	(4.2	)	$	0.5		$	(3.7	)

2010:
Unrealized gains / (losses) on financial instruments	$	0.6		$	(0.2	)	$	0.4		$	(1.6	)	$	0.6		$	(1.0	)
Deferred gains / (losses) on cash flow hedges	11.0			(4.6		)	6.4			(3.1		)	0.3			(2.8		)
Unrealized gains / (losses) on pension and postretirement benefits	4.3			(1.0		)	3.3			4.3			(1.0		)	3.3
Other comprehensive income (loss)	$	15.9		$	(5.8	)	$	10.1		$	(0.4	)	$	(0.1	)	$	(0.5	)

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The following table provides the detail of each component of Other comprehensive income (loss) reclassified to Net income during the years ended December 31, 2010, 2009 and 2008:

DPL

$ in millions	2010			2009			2008

No unrealized gains or losses on financial instruments were transferred to income in 2010, 2009 or 2008.	$	—		$	—		$	—
Deferred gains/(losses) on cash flow hedges net of income tax (expenses)/benefits of $2.0 million, ($1.8) million and ($2.2) million, respectively.	(6.0		)	5.9			6.5
Unrealized losses on pension and postretirement benefits net of income tax benefits of $1.3 million, $1.1 million and $0.7 million, respectively.	(2.4		)	(2.1		)	(1.3		)
	$	(8.4	)	$	3.8		$	5.2

DP&L

$ in millions	2010			2009			2008

Unrealized gains/(losses) on financial instruments net of income tax (expenses)/benefits of zero, ($0.4) million and ($1.4) million, respectively.	$	(0.1	)	$	0.7		$	2.7
Deferred gains/(losses) on cash flow hedges net of income tax (expenses)/benefits of $2.0 million, ($1.8) million and ($2.2) million, respectively.	(6.0		)	5.9			6.5
Unrealized losses on pension and postretirement benefits net of income tax benefits of $1.3 million, $1.1 million and $0.7 million, respectively.	(2.4		)	(2.1		)	(1.3		)
	$	(8.5	)	$	4.5		$	7.9

Accumulated Other Comprehensive Income (Loss)

AOCI is included on our balance sheets within the Common shareholders’ equity sections. The following table provides the components that constitute the balance sheet amounts in AOCI at December 31, 2010 and 2009:

DPL

$ in millions	2010			2009

Financial instruments, net of tax	$	0.6		$	0.2
Cash flow hedges, net of tax	19.6			13.3
Pension and postretirement benefits, net of tax	(39.1		)	(42.5		)
Total	$	(18.9	)	$	(29.0	)

DP&L

$ in millions	2010			2009

Financial instruments, net of tax	$	8.4		$	9.5
Cash flow hedges, net of tax	10.5			13.3
Pension and postretirement benefits, net of tax	(39.1		)	(42.5		)
Total	$	(20.2	)	$	(19.7	)

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14. EPS

Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations are shares held by DP&L’s Master Trust Plan for deferred compensation and unreleased shares held by DPL’s ESOP.

The common-equivalent shares excluded from the calculation of diluted EPS, because they were anti-dilutive, were not material for all the periods ended December 31, 2010, 2009 and 2008. These shares may be dilutive in the future.

The following illustrates the reconciliation of the numerators and denominators of the basic and diluted EPS computations:

	2010					2009					2008
$ and shares in millions except				Per					Per					Per
per share amounts	Income		Shares	Share		Income		Shares	Share		Income		Shares	Share
Basic EPS	$	290.3	115.6	$	2.51	$	229.1	112.9	$	2.03	$	244.5	110.2	$	2.22

Effect of Dilutive Securities:
Warrants			0.3					1.1					5.0
Stock options, performance and restricted shares			0.2					0.2					0.2

Diluted EPS	$	290.3	116.1	$	2.50	$	229.1	114.2	$	2.01	$	244.5	115.4	$	2.12

15. Insurance Recovery

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim. The proceeds from the settlement amounted to $3.4 million, net of associated expenses, and were recorded as a reduction to operation and maintenance expense during the year ended December 31, 2010.

16. Contractual Obligations, Commercial Commitments and Contingencies

DPL — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE and DPLER on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s and DPLER’s intended commercial purposes.

At December 31, 2010, DPL had $57.8 million of guarantees to third parties for future financial or performance assurance under such agreements, on behalf of DPLE and DPLER. The guarantee arrangements entered into by DPL with these third parties cover all present and future obligations of DPLE and DPLER to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Consolidated Balance Sheets was $1.7 million and $0.6 million at December 31, 2010 and 2009, respectively.

To date, neither DPL nor DP&L have incurred any losses related to the guarantees of DPLE’s and DPLER’s obligations and we believe it is remote that either DPL or DP&L would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s and DPLER’s obligations.

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DP&L — Equity Ownership Interest

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2010, these include:

			Payment Year
$ in millions	Total		2011		2012-2013		2014-2015		Thereafter
DPL

Long-term debt	$	1,324.4	$	297.4	$	470.0	$	—	$	557.0
Interest payments	677.9		64.7		96.1		53.9		463.2
Pension and postretirement payments	258.5		23.8		51.0		52.0		131.7
Capital leases	0.2		0.1		0.1		—		—
Operating leases	0.9		0.4		0.3		0.2		—
Coal contracts (a)	1,409.0		415.2		501.3		177.6		314.9
Limestone contracts (a)	42.9		5.6		11.7		12.4		13.2
Purchase orders and other contractual obligations	141.5		71.1		56.0		11.7		2.7
Total contractual obligations	$	3,855.3	$	878.3	$	1,186.5	$	307.8	$	1,482.7

DP&L

Long-term debt	$	884.4	$	—	$	470.0	$	—	$	414.4
Interest payments	424.8		39.5		72.9		30.7		281.7
Pension and postretirement payments	258.5		23.8		51.0		52.0		131.7
Capital leases	0.2		0.1		0.1		—		—
Operating leases	0.9		0.4		0.3		0.2		—
Coal contracts (a)	1,409.0		415.2		501.3		177.6		314.9
Limestone contracts (a)	42.9		5.6		11.7		12.4		13.2
Purchase orders and other contractual obligations	142.7		72.2		56.1		11.7		2.7
Total contractual obligations	$	3,163.4	$	556.8	$	1,163.4	$	284.6	$	1,158.6

(a) Total at DP&L-operated units

Long-term debt:

DPL’s long-term debt as of December 31, 2010, consists of DP&L’s first mortgage bonds and tax-exempt pollution control bonds and DPL’s unsecured senior notes. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

DP&L’s long-term debt as of December 31, 2010, consists of first mortgage bonds and tax-exempt pollution control bonds. These long-term debt amounts include current maturities but exclude unamortized debt discounts.

See Note 5 and Note 18 of Notes to Consolidated Financial Statements.

Interest payments:

Interest payments are associated with the long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rate prevailing at December 31, 2010.

Pension and postretirement payments:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 7 of Notes to Consolidated Financial Statements. These estimated future benefit payments are projected through 2020.

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Capital leases:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had one immaterial capital lease that expires in 2013.

Operating leases:

As of December 31, 2010, DPL, through its principal subsidiary DP&L, had several immaterial operating leases with various terms and expiration dates.

Coal contracts:

DPL, through its principal subsidiary DP&L, has entered into various long-term coal contracts to supply the coal requirements for the generating plants it operates. Some contract prices are subject to periodic adjustment and have features that limit price escalation in any given year.

Limestone contracts:

DPL, through its principal subsidiary DP&L, has entered into various limestone contracts to supply limestone used in the operation of FGD equipment at its generating facilities.

Purchase orders and other contractual obligations:

As of December 31, 2010, DPL and DP&L had various other contractual obligations including non-cancelable contracts to purchase goods and services with various terms and expiration dates.

Reserve for uncertain tax positions:

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations, and other matters, including the matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2010, cannot be reasonably determined.

Environmental Matters

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. We have reserves of approximately $4.0 million for environmental matters. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our power plants. Some of these matters could have material adverse impacts on the operation of the power plants; especially the plants that do not have SCR and FGD equipment installed to further control certain emissions. Currently, Hutchings and Beckjord are our only coal-fired power plants that do not have this equipment installed. DP&L owns 100% of the Hutchings plant and a 50% interest in Beckjord Unit 6.

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Regulation Matters Related to Air Quality

Clean Air Act Compliance

Interstate Air Quality Rule

In the fourth quarter of 2007, DP&L began a program for selling excess emission allowances, including annual NOx emission allowances and SO2 emission allowances that were the subject of CAIR trading programs. In subsequent quarters, DP&L recognized gains from the sale of excess emission allowances to third parties. The Court’s CAIR decision affected the trading market for excess allowances and impacted DP&L’s program for selling additional excess allowances in 2008. In January 2009, we resumed selling excess allowances due to the revival of the emissions trading market. On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) which will effectively replace CAIR. We have reviewed this proposal and submitted comments to the USEPA on September 30, 2010. We are unable to determine the overall financial impact that these rules could have on our operations in the future.

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Mercury and Other Hazardous Air Pollutants

On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA “de-listed” mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005 and was published on May 18, 2005. On March 29, 2005, nine states sued the USEPA, opposing the cap-and-trade regulatory approach taken by the USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to “de-listing” a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for “listed” hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. The USEPA is expected to propose Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units during the quarter ending March 31, 2011 and finalize during the quarter ending December 31, 2011. Upon publication in the federal register following finalization, affected electric generating units (EGUs) will have three years to come into compliance with the new requirements. DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial condition or results of operations; however, a MACT standard could have a material adverse effect on our operations. We cannot predict the final costs we may incur to comply with proposed new regulations to control mercury or other hazardous air pollutants.

National Ambient Air Quality Standards

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Climate Change

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Plants

In 2004, eight states and the City of New York filed a lawsuit in Federal District Court for the Southern District of New York against American Electric Power Company, Inc. (AEP), one of AEP’s subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. A similar lawsuit was filed against these companies in the same court by Open Space Institute, Inc., Open Space Conservancy, Inc. and The Audubon Society of New Hampshire. The lawsuits allege that the companies’ emissions of CO2 contribute to global warming and constitute a public or private nuisance. The lawsuits seek injunctive relief in the form of specific emission reduction commitments. In 2005, the Federal District Court dismissed the lawsuits, holding that the lawsuits raised political questions that should not be decided by the courts. The plaintiffs appealed. Finding that the plaintiffs have standing to sue and can assert federal common law nuisance claims, the United States Court of Appeals for the Second Circuit on September 21, 2009 vacated the dismissal of the Federal District Court and remanded the lawsuits back to the Federal District Court for further proceedings. In response to a petition by the company defendants, the U.S. Supreme Court on December 6, 2010 granted a hearing on the matter. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could be affected by the outcome of these lawsuits. The outcome of these lawsuits could also encourage these or other plaintiffs to file similar lawsuits against other electric power companies, including DP&L. We are unable to predict the impact that these lawsuits might have on DP&L.

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On September 21, 2004, the Sierra Club filed a lawsuit against DP&L and the other owners of the J.M. Stuart generating station in the U.S. District Court for the Southern District of Ohio for alleged violations of the CAA and the station’s operating permit. On August 7, 2008, a consent decree was filed in the U.S. District Court in full settlement of these CAA claims. Under the terms of the consent decree, DP&L and the other owners of the J.M. Stuart generating station agreed to: (i) certain emission targets related to NOx, SO2 and particulate matter; (ii) make energy efficiency and renewable energy commitments that are conditioned on receiving PUCO approval for the recovery of costs; (iii) forfeit 5,500 SO2 allowances; and (iv) provide funding to a third party non-profit organization to establish a solar water heater rebate program. DP&L and the other owners of the station also entered into an attorneys’ fee agreement to pay a portion of the Sierra Club’s attorney and expert witness fees. The parties to the lawsuit filed a joint motion on October 22, 2008, seeking an order by the U.S. District Court approving the consent decree with funding for the third party non-profit organization set at $300,000. On October 23, 2008, the U.S. District Court approved the consent decree. On October 21, 2009, the Sierra Club filed with the U.S. District Court a motion for enforcement of the consent decree based on the Sierra Club’s interpretation of the consent decree that would require certain NOx emissions that DP&L has been excluding from its computations to be included for purposes of complying with the emission targets and reporting requirements of the consent decree. DP&L believed that it was properly computing and reporting NOx emissions under the consent decree, but participated in settlement discussions with the Sierra Club. A proposed settlement was agreed to by both parties, approved by the Judge and then filed into the official record on July 13, 2010. The settlement amends the Consent Decree and sets forth a more detailed and clear methodology to compute NOx emissions during start-up and shut-down periods. There were no cash payments under the terms of this settlement. The revision is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.

Notices of Violation Involving Co-Owned Plants

On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received a NOV and a Finding of Violation (FOV) from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. A second NOV and FOV with similar allegations was issued on November 4, 2010. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy Ohio Inc. is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.

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Other Issues Involving Co-Owned Plants

Notices of Violation Involving Wholly-Owned Plants

Regulation Matters Related to Water Quality

Clean Water Act — Regulation of Water Intake

Clean Water Act — Regulation of Water Discharge

On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station that continued our authority to discharge water from the station into the Ohio River. During the three-year term of the Permit, we conducted a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers. In December 2006, we submitted an application for the renewal of the Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA agreed to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised Permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which USEPA has agreed to conduct. If a public hearing is held, it is anticipated that it would be scheduled in the second half of 2011. We are attempting to resolve this issue with both the USEPA and Ohio EPA. The timing for issuance of a final permit is uncertain.

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In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. Subsequent to the information collection effort, it is anticipated that the USEPA will release a proposed rule by mid-2012 with a final regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

Regulation Matters Related to Land Use and Solid Waste Disposal

Regulation of Waste Disposal

Regulation of Ash Ponds

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Legal and Other Matters

As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC Orders issued in 2007 and thereafter regarding the allocation of costs of large transmission facilities within PJM, could result in additional costs being allocated to DP&L of approximately $12 million or more annually by 2012. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit which was consolidated with other appeals taken by other interested parties of the same FERC Orders and the consolidated cases were assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. Rehearings were filed by other interested litigants and denied by the Court, which then remanded the matter to the FERC for further proceedings. On January 21, 2010, the FERC issued a procedural order on remand establishing a paper hearing process under which PJM will make an informational filing in late February. Subsequently PJM and other parties, including DP&L, filed initial comments, testimony, and recommendations and reply comments. FERC did not establish a deadline for its issuance of a substantive order and the matter is still pending. DP&L cannot predict the timing or the likely outcome of the proceeding. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that DP&L is not one of these beneficiaries, any new credits or additional costs resulting from the ultimate outcome of this proceeding will be reflected in DP&L’s TCRR rider which already includes these costs.

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NERC is a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards including Critical Infrastructure Protection (CIP) reliability standards, across eight reliability regions. In June 2009, ReliabilityFirst Corporation (RFC), with responsibilities assigned to it by NERC over the reliability region that includes DP&L, commenced a routine audit of DP&L’s operations. The audit, which was for the period June 18, 2007 to June 25, 2009, evaluated DP&L’s compliance with 42 requirements in 18 NERC-reliability standards. DP&L is currently subject to a compliance audit at a minimum of once every three years as provided by the NERC Rules of Procedure. This audit was concluded in June 2009 and its findings revealed that DP&L had some Possible Alleged Violations (PAVs) associated with five NERC Reliability requirements of various Standards. In response to the report, DP&L filed mitigation plans with RFC/NERC to address the PAVs. These mitigation plans were accepted by RFC/NERC. In July 2010, DP&L negotiated a settlement with NERC wherein DP&L agreed to pay an immaterial amount in exchange for a resolution of all issues and obligations relating to the aforementioned PAVs. The settlement was approved on January 21, 2011 by the FERC.

17. Business Segments

During 2010, DPL began operating through two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment). Initiatives taken by state legislative bodies combined with changes in the market price of electricity have significantly impacted the manner in which electric utilities in certain parts of the United States, including Ohio, have traditionally conducted business. This has resulted in, among other things, a more competitive electricity marketplace. Accordingly, DPL increased its resources to participate in the more competitive retail electric service market. DPL believes that these reportable segments are consistent with how our management views its business and makes decisions on how to allocate resources and evaluate performance. Segment financial information for the periods 2009 and 2008 has been presented to conform to the 2010 disclosures, as required by GAAP.

Included within Other are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs which include interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin. The accounting policies of the reportable segments are the same as those described in Note 1 — Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation.

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The following table presents financial information for each of DPL’s reportable business segments:

$ in millions	Utility		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated

Year Ended December 31, 2010
Revenues from external customers	$	1,552.0	$	277.0		$	54.1		$	—		$	1,883.1
Intersegment revenues	238.5		—			4.5			(243.0		)	—
Total revenues	$	1,790.5	$	277.0		$	58.6		$	(243.0	)	$	1,883.1

Purchased power	383.5		238.5			3.9			(238.5		)	387.4

Gross margin	1,035.1		38.5			42.7			(4.5		)	1,111.8

Depreciation and amortization	130.7		0.2			8.5			—			139.4
Interest expense	37.1		—			33.5			—			70.6
Income tax expense (benefit)	135.2		10.5			(2.7		)	—			143.0
Net income (loss)	277.7		18.8			(3.5		)	(2.7		)	290.3

Total assets	3,475.4		35.7			302.2			—			3,813.3
Capital expenditures	148.2		—			3.2			—			151.4

Year Ended December 31, 2009
Revenues from external customers	$	1,485.6	$	65.5		$	37.8		$	—		$	1,588.9
Intersegment revenues	64.8		—			3.8			(68.6		)	—
Total revenues	$	1,550.4	$	65.5		$	41.6		$	(68.6	)	$	1,588.9

Purchased power	259.2		64.8			1.0			(64.8		)	260.2

Gross margin	967.6		0.7			33.7			(3.7		)	998.3

Depreciation and amortization	135.5		0.1			9.9			—			145.5
Interest expense	38.5		—			44.5			—			83.0
Income tax expense (benefit)	124.5		(0.8		)	(11.2		)	—			112.5
Net income (loss)	258.9		(2.7		)	(21.4		)	(5.7		)	229.1

Total assets	3,457.4		6.6			177.7			—			3,641.7
Capital expenditures	144.0		—			1.3			—			145.3

Year Ended December 31, 2008
Revenues from external customers	$	1,422.3	$	150.8		$	28.5		$	—		$	1,601.6
Intersegment revenues	150.6		—			6.4			(157.0		)	—
Total revenues	$	1,572.9	$	150.8		$	34.9		$	(157.0	)	$	1,601.6

Purchased power	379.9		150.6			0.1				(153.3	)	377.3

Gross margin	961.6		0.2			23.1			(3.7		)	981.2

Depreciation and amortization	127.8		0.2			9.7			—			137.7
Interest expense	36.5		—			54.2			—			90.7
Income tax expense (benefit)	120.2		0.6			(17.9		)	—			102.9
Net income (loss)	285.8		1.9			(37.6		)	(5.6		)	244.5

Total assets	3,397.7		13.5			225.8			—			3,637.0
Capital expenditures	225.4		—			2.4			—			227.8

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18. Subsequent Events

Contingent Redemption of DPL-Capital Trust II Securities

19. Selected Quarterly Information (Unaudited)

DPL

		For the three months ended
$ in millions except per share amount		March 31,				June 30,				September 30,				December 31,
and common stock market price		2010		2009		2010		2009		2010		2009		2010		2009
Revenues		$	451.2	$	415.0	$	445.5	$	361.2	$	516.9	$	407.3	$	469.5	$	405.4
Operating income		$	126.0	$	127.0	$	109.3	$	81.9	$	144.6	$	116.5	$	124.5	$	102.8
Net income		$	71.0	$	69.2	$	61.4	$	42.1	$	86.4	$	67.9	$	71.5	$	49.9

Earnings per share of common stock:
Basic		$	0.61	$	0.62	$	0.53	$	0.38	$	0.75	$	0.60	$	0.62	$	0.43
Diluted		$	0.61	$	0.61	$	0.53	$	0.37	$	0.74	$	0.59	$	0.62	$	0.43

Dividends declared and paid per share		$	0.3025	$	0.2850	$	0.3025	$	0.2850	$	0.3025	$	0.2850	$	0.3025	$	0.2850

Common stock market price	- High	$	28.47	$	23.28	$	28.18	$	23.46	$	26.65	$	26.53	$	27.51	$	28.68
	- Low	$	26.51	$	19.27	$	23.80	$	21.18	$	23.95	$	22.79	$	25.33	$	25.16

DP&L

	For the three months ended
	March 31,				June 30,				September 30,				December 31,
$ in millions	2010		2009		2010		2009		2010		2009		2010		2009
Revenues	$	438.0	$	403.6	$	423.9	$	351.9	$	487.0	$	398.2	$	441.6	$	396.7
Operating income	$	118.4	$	124.8	$	97.0	$	78.9	$	131.9	$	115.2	$	102.9	$	103.0
Net income	$	72.1	$	77.0	$	59.4	$	46.8	$	83.2	$	74.0	$	63.0	$	61.1
Earnings on common stock	$	71.9	$	76.8	$	59.2	$	46.6	$	83.0	$	73.8	$	62.7	$	60.8
Dividends paid on common stock to parent	$	90.0	$	175.0	$	60.0	$	45.0	$	—	$	50.0	$	150.0	$	55.0

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

DPL Inc.:

We have audited the accompanying Consolidated Balance Sheets of DPL Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related Consolidated Statements of Results of Operations, Shareholders’ Equity and Cash Flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we have audited the consolidated financial statement schedule, “Schedule II — Valuation and Qualifying Accounts.” We also have audited the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these consolidated financial statements, the financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements, the financial statement schedule, and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles, and the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Philadelphia, Pennsylvania
February 17, 2011

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder

The Dayton Power and Light Company:

We have audited the accompanying Balance Sheets of The Dayton Power and Light Company (DP&L) as of December 31, 2010 and 2009, and the related Statements of Results of Operations, Shareholder’s Equity and Cash Flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the financial statements, we also have audited the financial statement schedule, “Schedule II — Valuation and Qualifying Accounts.” These financial statements and the financial statement schedule are the responsibility of DP&L’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of DP&L as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Philadelphia, Pennsylvania

February 17, 2011

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Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries are communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective: (i) to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms; and (ii) to ensure that information required to be disclosed by us in the reports that we submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the most recently completed fiscal period that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

The following report is our report on internal control over financial reporting as of December 31, 2010.

Management’s Report on Internal Control over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on an evaluation under the framework in Internal Control - Integrated Framework, we concluded that our internal control over financial reporting was effective as of December 31, 2010.

Our internal control over financial reporting as of December 31, 2010, has been audited by KPMG LLP, the independent registered public accounting firm that audited the financial statements contained herein, as stated in their report which is included herein.

Item 9B — Other Information

None.

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PART III

Item 10 — Directors, Executive Officers and Corporate Governance

The information required to be furnished pursuant to this item with respect to Directors and Executive Officers of DPL will be set forth under the captions “Election of Directors” and “Executive Officers” in DPL’s proxy statement (the Proxy Statement) to be furnished to shareholders in connection with the solicitation of proxies by our Board of Directors for use at the 2011 Annual Meeting of Shareholders to be held on April 27, 2011 and is incorporated herein by reference.

The information required to be furnished pursuant to this item for DPL with respect to Section 16(a) Beneficial Ownership Reporting Compliance, the Audit Committee, the Audit Committee financial expert and the registrant’s code of ethics will be set forth under in the “Corporate Governance” section in the Proxy Statement and is incorporated herein by reference.

Item 11 — Executive Compensation

The information required to be furnished pursuant to this item for DPL will be set forth under the captions “Executive Compensation,” “Compensation Discussion and Analysis (CD&A)” and “Compensation Committee Report on Executive Compensation” in the Proxy Statement and is incorporated herein by reference.

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required to be furnished pursuant to this item for DPL will be set forth under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management” and “Equity Compensation Plan Information” in the Proxy Statement and is incorporated herein by reference.

Item 13 — Certain Relationships and Related Transactions, and Director Independence

The information required to be furnished pursuant to this item for DPL will be set forth under the caption “Related Person Transactions” and “Independence” in the Proxy Statement and is incorporated herein by reference.

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Item 14 — Principal Accountant Fees and Services

The information required to be furnished pursuant to this item for DPL will be set forth under the caption “Audit and Non-Audit Fees” in the Proxy Statement and is incorporated herein by reference.

Accountant Fees and Services

The following table presents the aggregate fees billed for professional services rendered to DPL and DP&L by KPMG LLP for 2010 and 2009. Other than as set forth below, no professional services were rendered or fees billed by KPMG LLP during 2010 and 2009.

KPMG LLP	2010 Fees Billed		2009 Fees Billed
Audit Fees (1)	$	1,269,200	$	1,394,680
Audit-Related Fees (2)	40,000		46,000
Tax Fees (3)	930		7,870
All Other Fees (4)	15,000		—
Total	$	1,325,130	$	1,448,550

(1) Audit fees relate to professional services rendered for the audit of our annual financial statements and the reviews of our quarterly financial statements.

(2) Audit-related fees relate to services rendered to us for assurance and related services.

(3) Tax fees consisted principally of tax compliance services. Tax compliance services are services rendered based upon facts already in existence or transactions that have already occurred to document, compute, and obtain government approval for amounts to be included in tax filings.

(4) Other fees relate to services rendered under an agreed upon procedure engagement related to environmental studies.

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PART IV

Item 15 — Exhibits and Financial Statement Schedules

		Page No.

(a) The following documents are filed as part of this report:

1. Financial Statements

DPL - Consolidated Statements of Results of Operations for each of the three years in the period ended December 31, 2010		74

DPL - Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2010		75

DPL - Consolidated Balance Sheets at December 31, 2010 and 2009		76

DPL - Consolidated Statement of Shareholders’ Equity for each of the three years in the period ended December 31, 2010		78

DP&L - Consolidated Statements of Results of Operations for each of the three years in the period ended December 31, 2010		79

DP&L - Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2010		80

DP&L - Consolidated Balance Sheets at December 31, 2010 and 2009		81

DP&L - Consolidated Statement of Shareholder’s Equity for each of the three years in the period ended December 31, 2010		83

Notes to Consolidated Financial Statements		84

DPL - Report of Independent Registered Public Accounting Firm		150

DP&L - Report of Independent Registered Public Accounting Firm		151

2. Financial Statement Schedule

For each of the three years in the period ended December 31, 2010:

Schedule II — Valuation and Qualifying Accounts		167

The information required to be submitted in Schedules I, III, IV and V is omitted as not applicable or not required under rules of Regulation S-X.

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3. Exhibits

DPL and DP&L exhibits are incorporated by reference as described unless otherwise filed as set forth herein.

The exhibits filed as part of DPL’s and DP&L’s Annual Report on Form 10-K, respectively, are:

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)
X		3(a)	Amended Articles of Incorporation of DPL Inc., as of September 25, 2001	Exhibit 3 to Report on Form 10-K/A for the year ended December 31, 2001 (File No. 1-9052)

X		3(b)	Amended Regulations of DPL Inc., as of April 27, 2007	Exhibit 3(b) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

	X	3(c)	Amended Articles of Incorporation of The Dayton Power and Light Company, as of January 4, 1991	Exhibit 3(b) to Report on Form 10-K/A for the year ended December 31, 1991 (File No. 1-2385)

	X	3(d)	Regulations of The Dayton Power and Light Company, as of April 9, 1981	Exhibit 3(a) to Report on Form 8-K filed on May 3, 2004 (File No. 1-2385)

X	X	4(a)	Composite Indenture dated as of October 1, 1935, between The Dayton Power and Light Company and Irving Trust Company, Trustee with all amendments through the Twenty-Ninth Supplemental Indenture	Exhibit 4(a) to Report on Form 10-K for the year ended December 31, 1985 (File No. 1-2385)

X	X	4(b)	Forty-First Supplemental Indenture dated as of February 1, 1999, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4(m) to Report on Form 10-K for the year ended December 31, 1998 (File No. 1-2385)

X	X	4(c)	Forty-Second Supplemental Indenture dated as of September 1, 2003, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4(r) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

X	X	4(d)	Forty-Third Supplemental Indenture dated as of August 1, 2005, between The Dayton Power and Light Company and The Bank of New York, Trustee	Exhibit 4.4 to Report on Form 8-K filed August 24, 2005 (File No. 1-2385)

X	X	4(e)	Rights Agreement dated September 25, 2001 between DPL Inc. and Equiserve Trust Company, N.A.	Exhibit 4 to Report on Form 8-K filed September 28, 2001 (File No. 1-9052)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X		4(f)	Securities Purchase Agreement dated as of February 1, 2000 by and among DPL Inc., and DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc. and certain exhibits thereto	Exhibit 99(b) to Schedule TO-I filed February 4, 2000 (File No. 1-9052)

X		4(g)	Amendment to Securities Purchase Agreement dated as of February 24, 2000 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Exhibit 4(g) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(h)	Form of Warrant to Purchase Common Shares of DPL Inc.	Exhibit 4(h) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(i)	Securityholders and Registration Rights Agreement dated as of March 13, 2000 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Exhibit 4(i) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(j)	Amendment to Securityholders and Registration Rights Agreement, dated August 24, 2001 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Exhibit 4(j) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(k)	Amendment to Securityholders and Registration Rights Agreement, dated December 6, 2004 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc.	Exhibit 4(k) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(l)	Amendment to Securityholders and Registration Rights Agreement, dated as of January 12, 2005 among DPL Inc., DPL Capital Trust I, Dayton Ventures LLC and Dayton Ventures, Inc	Exhibit 4(j) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		4(m)	Indenture dated as of March 1, 2000 between DPL Inc. and Bank One Trust Company, National Association	Exhibit 4(b) to Registration Statement No. 333-37972

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)
X		4(n)	Exchange and Registration Rights Agreement dated as of August 24, 2001 between DPL Inc., Morgan Stanley & Co. Incorporated, Bank One Capital Markets, Inc., Fleet Securities, Inc. and NatCity Investments, Inc.	Exhibit 4(a) to Registration Statement No. 333-74568

X		4(o)	Officer’s Certificate of DPL Inc. establishing exchange notes, dated August 31, 2001	Exhibit 4(c) to Registration Statement No. 333-74568

X		4(p)	Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, Trustee	Exhibit 4(a) to Registration Statement No. 333-74630

X		4(q)	First Supplemental Indenture dated as of August 31, 2001 between DPL Inc. and The Bank of New York, as Trustee	Exhibit 4(b) to Registration Statement No. 333-74630

X		4(r)	Amended and Restated Trust Agreement dated as of August 31, 2001 among DPL Inc., The Bank of New York, The Bank of New York (Delaware), the administrative trustees named therein, and several Holders as defined therein	Exhibit 4(c) to Registration Statement No. 333-74630

	X	4(s)	Forty-Fourth Supplemental Indenture dated as of September 1, 2006 between the Bank of New York, Trustee and The Dayton Power and Light Company	Exhibit 4(s) to Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2385)

X		4(t)	Exchange and Registration Rights Agreement dated as of August 24, 2001 among DPL Inc., DPL Capital Trust II and Morgan Stanley & Co. Incorporated	Exhibit 4(d) to Registration Statement No. 333-74630

X	X	4(u)	Forty-Sixth Supplemental Indenture dated as of December 1, 2008 between The Bank of New York Mellon, Trustee and The Dayton Power and Light Company	Exhibit 4(x) to Report on Form 10-K for the year ended December 31, 2008 (File No. 1-2385)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X	X	10(a)*	The Dayton Power and Light Company Directors’ Deferred Stock Compensation Plan, as amended through December 31, 2000	Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

X	X	10(b)*	The Dayton Power and Light Company 1991 Amended Directors’ Deferred Compensation Plan, as amended and restated through December 31, 2007	Exhibit 10(b) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10(c)*	The Dayton Power and Light Company Management Stock Incentive Plan as amended and restated through December 31, 2007	Exhibit 10(c) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10(d)*	The Dayton Power and Light Company Key Employees Deferred Compensation Plan, as amended through December 31, 2000	Exhibit 10(d) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

X	X	10(e)*	Amendment No. 1 to The Dayton Power and Light Company Key Employees Deferred Compensation Plan, as amended through December 31, 2000, dated as of December 7, 2004	Exhibit 10(g) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X	X	10(f)*	The Dayton Power and Light Company Supplemental Executive Retirement Plan, as amended February 1, 2000	Exhibit 10(f) to Report on Form 10-K for the year ended December 31, 2009 (File No. 1-9052)

X	X	10(g)*	Amendment No. 1 to The Dayton Power and Light Company Supplemental Executive Retirement Plan, as amended through February 1, 2000 and dated as of December 7, 2004	Exhibit 10(i) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		10(h)*	DPL Inc. Stock Option Plan	Exhibit 10(f) to Report on Form 10-K for the year ended December 31, 2000 (File No. 1-9052)

X		10(i)*	2003 Long-Term Incentive Plan of DPL Inc.	Exhibit 10(aa) to Report on Form 10-K for the year ended December 31, 2003 (File No. 1-9052)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X	X	10(j)*	Summary of Executive Medical Insurance Plan	Exhibit 10(m) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X		10(k)*	DPL Inc. Executive Incentive Compensation Plan, as amended and restated through December 31, 2007	Exhibit 10(l) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(l)*	DPL Inc. 2006 Equity and Performance Incentive Plan as amended and restated through December 31, 2007	Exhibit 10(m) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(m)*	Form of DPL Inc. Amended and Restated Long-Term Incentive Plan - Performance Shares Agreement	Exhibit 10(n) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(n)*	DPL Inc. Severance Pay and Change of Control Plan, as amended and restated through December 31, 2007	Exhibit 10(o) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(o)*	DPL Inc. Supplemental Executive Defined Contribution Retirement Plan, as amended and restated through December 31, 2007	Exhibit 10(p) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(p)*	DPL Inc. 2006 Deferred Compensation Plan For Executives, as amended and restated through December 31, 2007	Exhibit 10(q) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(q)*	DPL Inc. Pension Restoration Plan, as amended and restated through December 31, 2007	Exhibit 10(r) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10(r)*	Participation Agreement dated August 2, 2007 among DPL Inc., The Dayton Power and Light Company and Teresa F. Marrinan	Exhibit 10(s) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10 (s)*	Participation Agreement dated March 27, 2007 among DPL Inc., The Dayton Power and Light Company and Scott J. Kelly	Exhibit 10(t) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X	X	10(t)*	Participation Agreement and Waiver dated February 27, 2006 among DPL Inc., The Dayton Power and Light Company and Gary G. Stephenson	Exhibit 10(u) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10 (u)*	Participation Agreement dated January 13, 2007 among DPL Inc., The Dayton Power and Light Company and Daniel J. McCabe	Exhibit 10(x) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(v)*	Management Stock Option Agreement dated as of January 1, 2001 between DPL Inc. and Arthur G. Meyer	Exhibit 10(cc) to Report on Form 10-K for the year ended December 31, 2005 (File No. 1-9052)

X	X	10(w)*	Participation Agreement and Waiver dated March 6, 2006 among DPL Inc., The Dayton Power and Light Company and Arthur G. Meyer, dated March 6, 2006	Exhibit 10(w) to Report on Form 10-K for the year ended December 31, 2009 (File No. 1-9052)

X	X	10(x)*	Participation Agreement dated September 8, 2006 among DPL Inc., The Dayton Power and Light Company and Paul M. Barbas	Exhibit 10.2 to Form 8-K filed September 8, 2006 (File No. 1-9052)

X	X	10(y)*	Participation Agreement dated June 30, 2006 among DPL Inc., The Dayton Power and Light Company and Frederick J. Boyle	Exhibit 10.1 to Form 8-K filed July 3, 2006 (File No. 1-9052)

X		10(z)*	Letter Agreement between DPL Inc. and Glenn E. Harder, dated June 20, 2006	Exhibit 10.1 to Form 8-K filed June 21, 2006 (File No. 1-9052)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X	X	10(aa)	Credit Agreement, dated as of November 21, 2006 among The Dayton Power and Light Company, KeyBank National Association and certain lending institutions, and Amendment No. 1 to Credit Agreement, dated as of April 9, 2009	Exhibit 10(aa) to Report on Form 10-K for the year ended December 31, 2009 (File No. 1-2385)

X	X	10(bb)	Credit Agreement, dated as of April 21, 2009 by and among The Dayton Power and Light Company and the lenders party thereto and PNC Bank, National Association	Exhibit 10.1 to Form 8-K filed October 8, 2009 (File No. 1-2385)

X		10(cc)*	Form of DPL Inc. Amended and Restated Non-Employee Director Restricted Stock Units Agreement	Exhibit 10(uu) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X		10(dd)*	DPL Inc. 2006 Deferred Compensation Plan for Non-Employee Directors, as amended and restated through December 31, 2007	Exhibit 10(v v) to Report on Form 10-K for the year ended December 31, 2007 (File No. 1-9052)

X	X	10(ee)*	Separation Agreement dated as of September 17, 2010, by and between DPL Inc. and The Dayton Power and Light Company and Douglas C. Taylor	Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2010 (File No. 1-9052)

X		10(ff)*	Restricted Stock Agreement dated May 6, 2008 by and between DPL Inc. and Paul M. Barbas	Exhibit 99.1 to Form 8-K filed May 8, 2008 (File No. 1-9052)

X		10(gg)*	Form of DPL Inc. Restricted Stock Agreement	Exhibit 10(d) to Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-9052)

X		10(hh)*	Form of DPL Inc. 2009 Career Grant and Matching Restricted Stock Agreement	Exhibit 10(b) to Report on Form 10-Q for the quarter ended September 30, 2009 (File No. 1-9052)

X	X	10(ii)*	Participation Agreement dated May 18, 2009, among DPL Inc., The Dayton Power and Light Company and Joseph W. Mulpas	Exhibit 10(c) to Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-9052)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

X	X	10(jj)*	Credit Agreement, dated as of April 20, 2010, among the Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, PNC Capital Markets, LLC and U.S. Bank, National Association, as Co-Syndication Agents, and the other lenders party to the Credit Agreement	Exhibit 10.1 to Form 8-K filed April 22, 2010 (File No. 1-2385)

X	X	10(kk)*	Participation Agreement dated May 14, 2010, among DPL Inc., The Dayton Power and Light Company and Bryce W. Nickel	Exhibit 10(b) to Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-9052)

X	X	10(ll)*	Participation Agreement dated May 14, 2010, among DPL Inc., The Dayton Power and Light Company and Kevin W. Crawford	Exhibit 10(c) to Report on Form 10-Q for the quarter ended June 30, 2010 (File No. 1-9052)

X	X	10(mm)*	Participation Agreement dated February 3, 2011, among DPL Inc., The Dayton Power and Light Company and Craig L. Jackson	Filed herewith as Exhibit 10(mm)

X	X	21	List of Subsidiaries of DPL Inc. and The Dayton Power and Light Company	Filed herewith as Exhibit 21

X		23(a)	Consent of KPMG LLP	Filed herewith as Exhibit 23(a)

X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)

X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)

	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)

	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)

X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)

X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)

	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)

	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)

X	X	101.INS	XBRL Instance	Furnished herewith as Exhibit 101.INS

X	X	101.SCH	XBRL Taxonomy Extension Schema	Furnished herewith as Exhibit 101.SCH

X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Furnished herewith as Exhibit 101.CAL

X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Furnished herewith as Exhibit 101.DEF

X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Furnished herewith as Exhibit 101.LAB

X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Furnished herewith as Exhibit 101.PRE

* Management contract or compensatory plan

Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.

Pursuant to paragraph (b) (4) (iii) (A) of Item 601 of Regulation S-K, we have not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company has duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

		DPL Inc.


February 17, 2011	By:
		/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)


		The Dayton Power and Light Company


February 17, 2011	By:
		/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of DPL Inc. and The Dayton Power and Light Company and in the capacities and on the dates indicated.

/s/ P.M. Barbas	Director, President and Chief	February 16, 2011
(P.M. Barbas)	Executive Officer (principal
	executive officer)


/s/ R.D. Biggs	Director	February 16, 2011
(R. D. Biggs)


/s/ P.R. Bishop	Director and Vice-Chairman	February 16, 2011
(P. R. Bishop)


/s/ F.F. Gallaher	Director	February 16, 2011
(F.F. Gallaher)


/s/ B.S. Graham	Director	February 16, 2011
(B. S. Graham)


/s/ G.E. Harder	Director and Chairman	February 16, 2011
(G.E. Harder)


/s/ P.B. Morris	Director	February 16, 2011
(P.B. Morris)


/s/ N.J. Sifferlen	Director	February 16, 2011
(N.J. Sifferlen)


/s/ F.J. Boyle	Senior Vice President and	February 16, 2011
(F.J. Boyle)	Chief Financial Officer
	(principal financial officer)


/s/ J.W. Mulpas	Vice President, Controller and Chief	February 16, 2011
(J.W. Mulpas)	Accounting Officer (principal accounting officer)

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Table of Contents

Schedule II

DPL Inc.

VALUATION AND QUALIFYING ACCOUNTS

For the years ended December 31, 2008 - 2010

$ in thousands

	Balance at
	Beginning				Deductions		Balance at
Description	of Period		Additions		(1)		End of Period

2010:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,101	$	4,148	$	4,378	$	871

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	11,955	$	1,124	$	—	$	13,079

2009:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,084	$	5,168	$	5,151	$	1,101

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	10,685	$	1,270	$	—	$	11,955

2008:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,518	$	4,277	$	4,711	$	1,084

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	12,429	$	1,482	$	3,226	$	10,685

(1) Amounts written off, net of recoveries of accounts previously written off.

The Dayton Power and Light Company

VALUATION AND QUALIFYING ACCOUNTS

For the years ended December 31, 2008 - 2010

$ in thousands

	Balance at
	Beginning				Deductions		Balance at
Description	of Period		Additions		(1)		End of Period

2010:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,101	$	4,100	$	4,369	$	832

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	—	$	—	$	—	$	—

2009:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,084	$	5,168	$	5,151	$	1,101

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	—	$	—	$	—	$	—

2008:
Deducted from accounts receivable - Provision for uncollectible accounts	$	1,518	$	4,277	$	4,711	$	1,084

Deducted from deferred tax assets - Valuation allowance for deferred tax assets	$	348	$	—	$	348	$	—

(1) Amounts written off, net of recoveries of accounts previously written off.

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