DPL (DPL) 10-K 2009 FY Annual report

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, 2009

OR

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

For the transition period from                          to                         

		I.R.S. Employer
Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	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 o	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.	o
The Dayton Power and Light Company	o

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 Accelerated filer	Accelerated filer	Non-Accelerated filer	Smaller reporting 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, 2009 was approximately $2.7 billion based on a closing sale price of $23.17 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 10, 2010, 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	119,083,640
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 2010 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K.

DPL Inc. and The Dayton Power and Light Company

Index to Annual Report on Form 10-K

Fiscal Year Ended December 31, 2009

		Page No.
Glossary of Terms		3
	Part I
Item 1	Business	5
Item 1A	Risk Factors	22
Item 1B	Unresolved Staff Comments	31
Item 2	Properties	31
Item 3	Legal Proceedings	31
Item 4	Submission of Matters to a Vote of Security Holders	31
	Part II
Item 5	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	32
Item 6	Selected Financial Data	35
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	66
Item 8	Financial Statements and Supplementary Data	66
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	138
Item 9A	Controls and Procedures	138
Item 9B	Other Information	138
	Part III
Item 10	Directors and Executive Officers of the Registrant	139
Item 11	Executive Compensation	139
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	139
Item 13	Certain Relationships and Related Transactions	139
Item 14	Principal Accountant Fees and Services	139
	Part IV
Item 15	Exhibits and Financial Statement Schedules	140
	Other
	Signatures	149
	Schedule II Valuation and Qualifying Accounts	151
	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
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
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
DSM	Demand-Side Management, a program under which customers typically receive a discount, rebate or other form of incentive in return for agreeing to reduce their electricity consumption upon request by the utility.
EIR	Environmental Investment Rider
EITF	Emerging Issues Task Force
EPS	Earnings Per Share
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
GAAP	Generally Accepted Accounting Principles in the United States
GHG	Greenhouse Gas
kWh	Kilowatt hours
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

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Abbreviation or Acronym	Definition
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, L.L.C., 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 electric security plan or a market rate option 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
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.  The material terms of this Stipulation are discussed further in this report.
TCRR	Transmission Cost Recovery Rider
USEPA	U.S. Environmental Protection Agency
USF	Universal Service Fund

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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 98% of DPL’s total consolidated revenue and approximately 95% 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

DPL and DP&L 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 38 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.

DPL’s principal subsidiary is DP&L.  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.

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; DPLER, which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; 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.

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DPL and DP&L conduct their principal business in one business segment — Electric.  DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is not subject to such regulation.  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 1,581 persons as of January 31, 2010, of which 1,403 were full-time employees and 178 were part-time employees.  At that date, 1,396 of these full-time employees and all of the part-time employees were employed by DP&L.  Approximately 55% of the employees are under a collective bargaining agreement.

SIGNIFICANT DEVELOPMENTS

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	November 2009
Moody’s Investors Service	Baa1	Aa3	Stable	August 2009
Standard & Poor’s Corp.	BBB+	A	Stable	April 2009

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

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

Long-Term Debt Redemption

On March 31, 2009, DPL paid $175 million of the 8.00% Senior Notes when the notes became due.  In addition, on December 21, 2009, DPL paid down $52.4 million of the $195 million 8.125% Note to DPL Capital Trust II which is due 2031.

New Revolving Credit Facility

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group.  The agreement is for a 364-day term expiring on April 20, 2010.  The facility contains one financial covenant: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of December 31, 2009, this covenant is met with a ratio of 0.40 to 1.00.  As of December 31, 2009, there were no borrowings outstanding under this facility.

Warrants Repurchased and Exercised

During the year ended December 31, 2009, DPL repurchased a total of 8.6 million of its warrants at an average price of $2.94 each.  The repurchased warrants were cancelled by DPL on the dates they were repurchased.  Also during this period, warrant holders exercised a total of 9.2 million warrants, of which 5.5 million were exercised under cashless transactions and 3.7 million were exercised for cash.  As a result of these warrant exercise transactions, DPL issued a total of 5.0 million shares of common stock from treasury stock and in turn received total cash proceeds of $77.7 million.

Stock Repurchase Program

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may use proceeds from the exercise of warrants (discussed above) to repurchase common stock and warrants from time to time in the open market, through private transactions or otherwise. The Stock Repurchase Program will run through June 30, 2012, which is approximately three months after the end of the warrant exercise period.  Through December 31, 2009, DPL repurchased approximately 2.4 million shares of common stock under the Stock Repurchase Program at an average price per share of $26.96.

Approval of Stipulation

In compliance with SB 221, DP&L filed its ESP at the PUCO on October 10, 2008. Subsequently on February 24, 2009, DP&L filed the Stipulation signed by the Staff of the PUCO, the Office of the OCC and various intervening parties.  On June 24, 2009, the PUCO issued an order granting approval of the Stipulation.

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Transmission, Ancillary and Other PJM-related Costs

On February 19, 2009, the PUCO approved DP&L’s request to defer costs related to transmission, capacity, ancillary service and other costs incurred since July 31, 2008 consistent with the provisions of SB 221.  Subsequently, the PUCO approved two separate riders in November 2009, one for the recovery of RPM capacity costs and another rider for the recovery of transmission, ancillary and other PJM-related costs (TCRR).  Accordingly, during the period ended December 31, 2009, DP&L deferred net RTO and other costs in the amount of $25.5 million.  Of this amount, approximately $9.8 million relates to the period August 1, 2008 through December 31, 2008, and $15.7 million relates to the twelve month period ended December 31, 2009.  The deferral of these costs resulted in a favorable impact to our results of operations.

Increase in Dividends on DPL’s Common Stock

On December 9, 2009, DPL’s Board of Directors authorized a quarterly dividend rate increase of approximately 6%, increasing the quarterly dividend per DPL common share from $.2850 to $.3025.  If this dividend rate is maintained, the annualized dividend would increase from $1.14 per share to $1.21 per share.

ELECTRIC SALES AND REVENUES

	DPL						DP&L (a)
	2009		2008		2007		2009		2008		2007
Electric sales (millions of kWh)
Residential	5,120		5,533		5,535		5,120		5,533		5,535
Commercial	3,678		3,959		3,990		3,678		3,959		3,990
Industrial	3,353		3,986		4,241		3,353		3,986		4,241
Other retail	1,386		1,454		1,468		1,386		1,454		1,468
Total retail	13,537		14,932		15,234		13,537		14,932		15,234
Wholesale	3,130		2,240		3,364		3,053		2,173		3,364
Total	16,667		17,172		18,598		16,590		17,105		18,598
Operating revenues ($ in thousands)
Residential	$	560,223	$	544,561	$	532,956	$	560,223	$	544,561	$	532,956
Commercial	332,808		332,010		321,051		329,006		308,934		301,455
Industrial	228,458		240,041		244,260		186,293		133,832		132,359
Other retail	98,781		97,592		94,568		82,749		78,905		77,184
Other miscellaneous revenues	8,766		9,042		13,340		8,966		9,046		13,387
Total retail	1,229,036		1,223,246		1,206,175		1,167,237		1,075,278		1,057,341
Wholesale	122,519		149,874		180,254		181,871		293,500		331,722
RTO revenues	225,677		217,357		118,389		201,254		204,074		118,389
Other revenues	11,689		11,080		10,911		—		—		—
Total	$	1,588,921	$	1,601,557	$	1,515,729	$	1,550,362	$	1,572,852	$	1,507,452
Electric customers at end of period
Residential	456,144		456,770		456,989		456,144		456,770		456,989
Commercial	50,141		50,190		49,875		50,141		50,190		49,875
Industrial	1,773		1,797		1,818		1,773		1,797		1,818
Other	6,577		6,517		6,443		6,577		6,517		6,443
Total	514,635		515,274		515,125		514,635		515,274		515,125

(a)DP&L sells power to DPLER (a subsidiary of DPL).  The revenues associated with these sales are classified as wholesale sales on DP&L’s financial statements and retail sales for DPL.  The kWh volumes contain all volumes distributed on the DP&L system which include the retail sales by DPLER.  The sales for resale volumes are omitted from DP&L to avoid duplicate reporting.

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ELECTRIC OPERATIONS AND FUEL SUPPLY

	2009 Summer Generating Capacity
(Amounts in MWs)	Coal Fired	Peaking Units	Total
DPL	2,827	967	3,794
DP&L	2,827	422	3,249

DPL’s present summer generating capacity, including peaking units, is approximately 3,794 MW.  Of this capacity, approximately 2,827 MW, or 75%, is derived from coal-fired steam generating stations and the balance of approximately 967 MW, or 25%, consists of combustion turbine and diesel peaking units.

DP&L’s present summer generating capacity, including peaking units, is approximately 3,249 MW.  Of this capacity, approximately 2,827 MW, or 87%, is derived from coal-fired steam generating stations and the balance of approximately 422 MW, or 13%, consists of 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-Ohio (or its subsidiaries The Cincinnati Gas & Electric Company [CG&E], or Union Heat, Light & Power) and AEP (or its subsidiary Columbus Southern Power [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, CG&E 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 2009, we generated 99.5% of our electric output from coal-fired units and 0.5% from 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	126	765
Beckjord-Unit 6	C	CG&E	New Richmond, OH	207	414
Miami Fort-Units 7 & 8	C	CG&E	North Bend, OH	368	1,020
East Bend-Unit 2	C	CG&E	Rabbit Hash, KY	186	600
Zimmer	C	CG&E	Moscow, OH	365	1,300
Combustion Turbines or Diesel
Hutchings	W	DP&L	Miamisburg, OH	23	23
Yankee Street	W	DP&L	Centerville, OH	94	94
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	238	238
Tait Units 4-7	W	DPLE	Moraine, OH	307	307
Total approximate summer generating capacity				3,794	8,352

*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.

DPL has substantially all of the total expected coal volume needed to meet its retail and firm wholesale sales requirements for 2010 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 impacted 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.  Our emission allowance consumption was reduced in 2008 and 2009 due to the installation of FGD equipment (scrubbers) at our jointly-owned electric generating stations.  Due to the installation of this emission control equipment and barring any changes in the regulatory environment in which we operate, we expect to have emission allowance inventory in excess of our needs, which we plan to sell during 2010 and in future periods.  We were a net seller of SO2 allowances and NOx allowances in 2009, and we expect to be a net seller in 2010.

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

	Average Cost of Fuel
	Consumed (¢/kWh)
	2009	2008	2007
DPL	2.39	2.28	1.97
DP&L	2.36	2.22	1.91

SEASONALITY

The power generation and delivery business is seasonal and weather patterns have a material impact 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 retail customers are subject to rate regulation by the PUCO.  Beginning January 1, 2010, DP&L has a fuel rider in place for the collection of our prudently incurred fuel, purchased power, emission and other related costs.  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 retail rates charged by public utilities.  Regulation of retail rates encompasses the timing of applications, the effective date of rate increases, the recoverable costs basis upon which the rates are based 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

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, standard service offer 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 electric security plan or a market rate option that was to be in effect on January 1, 2009.  Under the market rate option, 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 set out in the bill.  Also, under this option, utilities that still own generation in the state are required to phase in the market rate option over a period of not less than five years.  An electric security plan may allow for adjustments to the standard service offer 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 electric security plan, 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 market rate option and electric security plan option involve a “substantially 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 electric security plan as well as a market rate option, 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.  The standard offer plan stated that DP&L intends to maintain its current rate plan through December 31, 2010, and addressed compliance issues related to the PUCO rules.

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.  After several revisions, rulings on rehearing and reissuance that occurred throughout 2009, the rules relating to renewable energy, energy efficiency, demand reduction and integrated resource plans were made effective on December 10, 2009.  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 increases in required percentages each year.  The annual targets for energy efficiency are expected to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to baseline energy usage.  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 and DPLER made several filings relating to their renewable energy and energy efficiency compliance plans.  DP&L and DPLER were able to obtain Renewable Energy Certificates sufficient to meet their overall renewable energy targets, but DP&L and DPLER together obtained only 36% of the separate requirement for 2009 Ohio-based solar power.  The companies asked for a waiver of any unmet 2009 Ohio solar requirements on grounds of force majeure because there are insufficient solar renewable energy credits available from Ohio resources.  In two separate filings, DP&L requested the PUCO’s consent that DP&L had met the 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. 

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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 electric security plan, which had been approved by the PUCO and is being implemented.  We are unable to predict at this time how the PUCO will respond to these filings, but believe that the outcome will not be material to our financial condition.  However, as the targets get increasingly larger over time, the costs of complying with the SB 221 targets and the PUCO’s implementing rules could have a material impact on our financial condition.

On February 24, 2009, DP&L filed the Stipulation with the PUCO which was signed by the Staff of the PUCO, the Office of the OCC and various intervening parties.  The material terms agreed to under the Stipulation include the following:

·DP&L’s current rate plan will be extended through 2012.

·DP&L will be permitted to implement a fuel and purchased power recovery mechanism beginning January 1, 2010 which will track and adjust fuel and purchased power costs on a quarterly basis.

·The rate stabilization surcharge remains a non-bypassable provider of last resort charge at its current rate amount, but may be bypassable by customers served by a government aggregator beginning 2011. If a government aggregator elects to avoid this surcharge in 2011 and 2012, its customers can only return to DP&L at a market-based rate.

·The last phase of the EIR increase will occur in 2010 as previously approved by the PUCO and thereafter will remain at that level through 2012.

·DP&L’s base distribution and generation rates will be frozen through 2012.

·DP&L may seek recovery of certain cost increases such as storm damage expenses, regulatory or tax changes, costs associated with new climate change or carbon regulations, certain costs associated with the operation of the Hutchings station, costs associated with TCRR and Regional Transmission Organization costs not covered by the TCRR.

·The significantly excessive earnings test will not apply to DP&L until 2012.

·DP&L will be permitted to begin its energy efficiency and demand response programs immediately with recovery scheduled to begin in 2009, with a two-year reconciliation.  DP&L’s smart grid deployment initiative will be revised and resubmitted to the PUCO for approval by September 2009 with the anticipation that the plans and recovery will begin January 1, 2010 also with a two year reconciliation.

·DP&L’s proposed alternative energy plans will be approved and recovery of these costs will begin in 2009 with an annual reconciliation.

·Mercantile (large use) customers can obtain exemption from the energy efficiency rider if self-directed energy and demand programs generate reductions equal to or greater than DP&L’s energy and demand reduction benchmarks.

On June 24, 2009, the PUCO issued an order granting approval of the 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 Stipulation, DP&L filed its smart grid and advanced metering infrastructure business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a three-year plan to deploy smart meter; and a ten-year plan for distribution and substation automation, core telecommunications, supporting software and in-home technologies.  On August 5, 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding under the Integrated and/or Crosscutting Systems topic area for the Smart Grid Investment Grant Program, seeking $145.1 million of matching funds.  On October 27, 2009, we were notified by the United States Department of Energy (DOE) that we will not receive funding under the ARRA.  A technical conference was held at the PUCO in October 2009 for the smart grid case, and a subsequent PUCO entry established a comment and reply comment period.  The PUCO Staff along with other interested parties provided comments and reply comments on DP&L’s plans.  A hearing is not yet scheduled for this case.

The Stipulation provided for the establishment of a fuel and purchased power recovery rider beginning January 1, 2010.  DP&L filed its proposed fuel rider on October 30, 2009.  On December 16, 2009 the PUCO issued an order stating the rate was consistent with the Stipulation provisions, that it does not appear to be unjust or unreasonable, and approved the rate to be implemented on January 1, 2010. The fuel rider will fluctuate based on actual costs and recoveries and will be modified at the start of each seasonal quarter:  March 1, June 1, September 1, and December 1 each year. Consistent with the Stipulation, an annual review and audit is scheduled to take place in the first quarter of 2011 for calendar year 2010.

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As a member of PJM, DP&L incurs costs and receives revenues from the RTO related to its transmission and generation assets, as well as its load obligations for retail customers.  SB 221 included a provision that allows Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits.  In early 2009, the PUCO approved DP&L’s request to defer costs associated with its transmission, capacity, ancillary service and other PJM-related charges incurred as a member of PJM consistent with the provisions of SB 221.  DP&L subsequently filed to establish the TCRR that would incorporate all charges and credits from the RTO as well as the amounts approved for deferral.  The TCRR was approved by the PUCO and on June 1, 2009 DP&L began recovery of these costs.  In June 2009, an application for rehearing was filed claiming the PUCO’s order allowing for recovery of RPM costs through this rider was unlawful.   On September 9, the PUCO granted rehearing, and issued an entry ordering DP&L to remove the RPM costs from the TCRR and refile its tariffs.  On September 23, 2009, the Company filed two separate riders, a TCRR without RPM costs, and an RPM recovery rider, which were both subsequently approved per PUCO Finding and Order issued on November 18, 2009, and implemented December 1, 2009.  There was no change to the level of recovery due to the rehearing process.

On September 9, 2009, the PUCO issued an entry establishing a significantly excessive earnings test (SEET) proceeding.  A workshop was held at the PUCO offices on October 5, 2009 to allow interested parties to present concerns and discuss issues related to the methodology for determining whether an electric utility has significantly excessive earnings pursuant to the provisions contained in SB 221.  On November 18, 2009, the PUCO Staff issued its recommendations to the PUCO.  DP&L filed its comments and reply comments along with other interested parties.  Although DP&L’s Stipulation provides that the SEET does not apply to it until 2013 based on 2012 earnings results, DP&L is actively participating in this proceeding.

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 on November 10, 2009.  Comments and reply comments were filed.  We expect this case will be set for hearing.  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

As of December 31, 2009, six unaffiliated marketers were registered as CRES providers in DP&L’s service territory.  While there has been some customer switching associated with unaffiliated marketers, it represented less than 0.11% of sales in 2009.  DPLER, an affiliated company, is also a registered CRES provider and accounted for 99% of the total kWh supplied by CRES providers within DP&L’s service territory in 2009.  During the first quarter of 2010, DPLER will begin providing CRES services to business customers who are currently not in DP&L’s service territory.  At this time, we do not expect these incremental costs and revenues to have a material impact on our results of operations, financial position or cash flows.  In 2003-2004, several communities in DP&L’s service area 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.

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 on how DP&L’s and DPLE’s price, terms and conditions compare to those of other suppliers.

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.

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The PJM RPM base residual auction for the 2012/13 period cleared at a per megawatt price of $16/day for our RTO area.  Prior to this auction, the per megawatt price for the 2011/2012 period was $110/day.  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 auctions.  We cannot predict the outcome of future auctions but if the current auction price is sustained, our future results of operations, financial condition and cash flows could be adversely impacted.

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 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 on March 18, 2008 challenging the allocation method.  The appeal 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, will be able to file initial comments, testimony, and recommendations and reply comments.  Absent future changes to the procedural schedule that may occur for a number of reasons including if settlement discussions are held, the paper hearing process should be complete and the case ready for FERC consideration in 2010.  FERC did not establish a deadline for its issuance of a substantive order.  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 is already in place to pass through RTO-related costs and credits.

DP&L provides transmission and wholesale electric service to twelve municipal customers in its service territory, which in turn distribute electricity principally within their incorporated limits.  DP&L also maintains an interconnection agreement with one municipality that has the capability to generate a portion of its own energy requirements.  Approximately one percent of total electricity sales in 2009 represented sales to these municipalities.

In June 2009, the NERC, a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, 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 Standards.  In response to the report, DP&L filed mitigation plans with NERC to address the PAVs.  These mitigation plans have been accepted and DP&L is currently awaiting a proposal for settlement from NERC.  While we are currently unable to determine the extent of penalties, if any, that may be imposed on DP&L, we do not believe such penalties will have a material impact on our results of operations.

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ENVIRONMENTAL CONSIDERATIONS

DPL 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 issued by the USEPA and Ohio EPA that require substantial reductions in SO2, particulates, mercury and NOx emissions.  DPL 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 reductions of GHGs.

·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 reportedly 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 probable estimated loss in accordance with the provisions of GAAP relating to the accounting for contingencies.  DPL, through its wholly-owned captive insurance subsidiary MVIC, has an actuarially calculated reserve of $1.2 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 position or cash flows.

Environmental Regulation and Litigation Related to Air Quality

Air Quality

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 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 new source review requirements, if new source review requirements were imposed on any of DP&L’s existing power plants, the results could be materially adverse to us.

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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 New Source Review (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 at this time predict the outcome of this rulemaking, any finalized rules could materially affect our operations.

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 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 to 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.  In January 2010, the Court ordered the USEPA to file a response to request for a USEPA decision filed by parties in the original case who are now seeking a Court order to require the USEPA to issue new regulations by March 1, 2010.  We are currently unable to predict the outcome of this request or the timing or impact of any new regulations relating to CAIR.  CAIR has and will continue to have a material effect on our operations.

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.

In the fourth quarter of 2007, DP&L began a program for selling excess emission allowances, including annual NOxemission 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.  Although in January 2009 we resumed selling excess allowances due to the revival of the trading market, the long-term impact of the court’s decision and of the actions the USEPA or others will take in response to this decision, is not fully known at this time and could have an adverse effect on us.

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 move forward on setting Maximum Available Control Technology (MACT) standards for coal- and oil-fired electric generating units.  Upon publication in the federal register following finalization, affected exempt generating units (EGUs) will have three years to come into compliance with the new requirements.  At this time, DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial position or results of operations; however, a MACT standard could have a material adverse effect on our operations, in particular, our unscrubbed units.  We cannot at this time project the final costs we may incur to comply with any resulting mercury restriction regulations.

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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 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 in late 2010 as part of its routine five-year rule review cycle.  At this time, DP&L is unable to determine the impact the revisions to the PM 2.5 standard will have on its financial position 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.

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 gases are pollutants under the CAA.  The USEPA has not yet identified the specifics of how these newly designated pollutants will be regulated.  In April 2009, the USEPA issued a proposed endangerment finding under the CAA.  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.  If the proposed finding is finalized, it could lead to the regulation of CO2 and other GHGs from sources other than motor vehicles, including coal-fired plants that we own and operate.  Recently, several bills have been introduced at the federal level to regulate GHG emissions.  In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES).  This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy-wide cap and trade program.  ACES also includes energy efficiency and renewable energy initiatives.  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 position.  However, due to the uncertainty associated with such legislation, we are currently unable to predict the final outcome or the financial impact that this legislation will have on us.  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.

On July 15, 2009, the USEPA proposed revisions to its primary NAAQS for nitrogen dioxide.  This change could affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton.  At this point, DP&L cannot determine the effect of this potential change, if any, on its operations.

The USEPA proposed revisions to its primary NAAQS for SO2 on November 16, 2009.  This would replace the current 24-hour standard and current annual standard.  This regulation is expected to be finalized in 2010.  At this time, DP&L cannot determine the effect of this potential change, if any, on its operations.

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.  At this point, DP&L cannot determine the effect of this potential change, if any, on its operations.

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Air Quality — Litigation Involving Co-Owned Plants

In March 2000, as amended in June 2004, the U.S. Department of Justice filed a complaint in the United States District Court, Southern District of Indiana, Indianapolis Division against Cinergy Corp. (now part of Duke Energy) and two Cinergy subsidiaries for alleged violations of the CAA at various generation units operated by PSI Energy, Inc. and CG&E, including generation units co-owned by DP&L (Beckjord Unit 6 and Miami Fort Unit 7).  A retrial has been held in which the second jury found for Duke Energy on some allegations, but for plaintiffs with respect to units at another one of Duke Energy’s wholly-owned facilities.  In a separate phase II remedies trial with respect to violations found in the first trial, Duke Energy was ordered to close down three of its wholly-owned generating units by September 2009, surrender some emission allowances and pay a fine.  None of the violations found or remedies ordered relate to generating units owned in part by DP&L.

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.  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 Second Circuit Court’s decision could also encourage these or other plaintiffs to file similar lawsuits against other electric power companies, including us.  We are unable at this time to predict with certainty the impact that these lawsuits might have on us.

On September 21, 2004, the Sierra Club filed a lawsuit against DP&L and the other owners of the 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 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 believes that it is properly computing and reporting NOx emissions under the consent decree and has opposed the Sierra Club’s motion.  A decision on the motion is expected before the end of the first quarter 2010.  Because Stuart Station’s NOx emissions are well below the 2009 and 2010 limits in the consent decree under either method of calculation, an adverse decision would have no effect in 2010 on operations or costs.  An adverse decision could affect compliance costs in future years when the NOx limits are further reduced under the consent decree.

Air Quality — Notices of Violation Involving Co-Owned Plants

On March 13, 2008, Duke Energy Ohio Inc., the operator of the Zimmer generating station, received a NOV and a Finding of Violation 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.  DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of this matter.  Duke Energy Ohio Inc. is expected to act on behalf of itself and the co-owners with respect to this matter.  At this time, DP&L is unable to predict the outcome of this matter.

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In June 2000, the USEPA issued a NOV to the DP&L-operated Stuart generating station (co-owned by DP&L, CG&E 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.  At this time, DP&L cannot predict the outcome of this matter.

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 CG&E (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 CG&E 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 December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and CG&E) 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.

Air Quality — 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 CG&E) and ultimately determined its SO2 and NOx emissions data was under reported.  DP&L has petitioned the USEPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter 2006.  DP&L has sufficient allowances in its general account to cover the understatement and is working with the USEPA to resolve the matter.  Management does not believe the ultimate resolution of this matter will have a material impact on results of operations, financial position or cash flows.

Air Quality — 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 has 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 New Source Review (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.

Water Quality

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 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 which it hopes to issue for public comment by mid-2010.

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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 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 have 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.  The timing for issuance of a final permit is uncertain.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities such as J.M. Stuart, Killen and O.H. Hutchings Stations.  The rulemaking will include 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 in 2011 with final regulations issued in late 2012 or early 2013.  At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

Land Use and Solid 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.  More recently, DP&L has received requests by the USEPA and the existing PRP group to allow access to be given to DP&L’s service center building site, which is across a street from the landfill site.  The USEPA requested access to drill monitoring and test wells to 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.  Pursuant to an Administrative Order issued by the USEPA requiring access to DP&L’s service center building site, DP&L has granted such access and drilling of soil borings and installation of monitoring wells occurred in the fall of 2009.  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.  While DP&L is unable at this time 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.  DP&L is also unable at this time to predict whether the monitoring and test wells may lead to any actions relating to the service center building site independent of the South Dayton Dump clean-up.

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 at this time 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.

In November 2007, a PRP group contacted DP&L seeking our financial participation in a settlement that the group had reached with the federal government with respect to the clean-up of an industrial site once owned by Carolina Transformer, Inc.  DP&L’s business records clearly show we did not conduct business with Carolina Transformer that would require our participation in any clean-up of the site.  DP&L has declined to participate in the clean-up of this site.  While DP&L is unable at this time 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.

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.  We frequently inspect our ash ponds and do not anticipate any similar failures.  It is widely expected that the federal government will propose new regulations covering ash generated

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from the combustion of coal including additional monitoring, testing, or construction standards with respect to ash ponds and ash landfills.  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 addition, during August and October 2009, representatives of the USEPA visited J.M. Stuart Station to collect information on plant operations relative to the production and handling of by-products.  The USEPA’s contractor has issued a draft report on their October 2009 visit to J.M. Stuart Station.  DP&L has provided comments on this document and additional related information to the agency.  Due to the wide range of possible outcomes, DP&L is unable at this time to predict the timing or the financial impact of any future governmental initiative that may occur.

In addition, as a result of the TVA ash pond spill, there has been increasing advocacy to regulate coal combustion byproducts as hazardous waste under the Resource Conservation Recovery Act, Subtitle C.  On October 15, 2009, the USEPA provided a draft rule to the Office of Management and Budget for interagency review.  The draft rule proposed to regulate coal ash as a hazardous waste, with limited beneficial reuse.  DP&L is unable at this time 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.

Legal and Other 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.  DP&L is unable to determine the ultimate resolution of this matter at this time.  In accordance with GAAP, DP&L has not recorded any assets relating to this lawsuit.

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal expenses associated with our litigation against certain former executives.  Arbitration on that claim occurred on May 13, 2009.  The arbitration panel issued a ruling in Phase 1 of the arbitration on September 25, 2009, finding that most of the claims involving the former executives were covered.  The matter is pending.

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 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 on March 18, 2008 challenging the allocation method.  The appeal 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, will be able to file initial comments, testimony, and recommendations and reply comments.  Absent future changes to the procedural schedule that may occur for a number of reasons including if settlement discussions are held, the paper hearing process should be complete and the case ready for FERC consideration in 2010.  FERC did not establish a deadline for its issuance of a substantive order.  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 is already in place to pass through RTO-related costs and credits.

In June 2009, the NERC, a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, 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 Standards.  In response to the report, DP&L filed mitigation plans with NERC to address the PAVs.  These mitigation plans have been accepted and DP&L is currently awaiting a proposal for settlement from NERC.  While we are currently unable to determine the extent of penalties, if any, that may be imposed on DP&L, we do not believe such penalties will have a material impact on our results of operations.

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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 $145 million, $228 million and $347 million in 2009, 2008 and 2007, respectively, and are expected to approximate $210 million in 2010.  Planned construction additions for 2010 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 $144 million, $225 million and $344 million in 2009, 2008 and 2007, respectively, and are expected to approximate $200 million in 2010.  Planned construction additions for 2010 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 approximate $21 million, $90 million and $209 million in 2009, 2008 and 2007, respectively.

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.

Regulation and Litigation

We are subject to extensive laws and regulation by federal, state and local authorities, such as the PUCO, the USEPA, the Ohio EPA, the FERC, the SEC 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, 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.

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Cost Recovery and Rates

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 electric security plan or a market rate option that was to be in effect on January 1, 2009, and established a significantly excessive earnings test for Ohio public utilities based on the earnings of other companies with similar business and financial risks.  The PUCO approved DP&L’s filed electric security plan on June 24, 2009.  DP&L’s electric security plan 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 not apply to DP&L until 2012.  DP&L’s electric security plan, and certain filings made by us in connection with this plan, are further discussed under “Ohio Retail Rates” in Item 1 — COMPETITION AND REGULATION.

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.  Accordingly, the rates DP&L is allowed to charge 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 and permitted rates of return; changes in DP&L’s ability to recover expenditures for environmental compliance, reliability initiatives, purchased power and fuel (which account for a substantial portion of our operating costs), capital expenditures and investments and other costs on a fully 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.

Advanced Energy and Energy Efficiency Requirements

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 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 0.5% from solar energy, and the remainder must be generated from advanced energy sources.  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 are expected to increase (and could increase materially) our power supply costs.  Pursuant to DP&L’s approved electric security plan, DP&L is entitled to recover costs associated with its alternative energy plans, as well as its energy efficiency and demand response programs, and 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.

Availability and Cost of Fuel

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 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 variable 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, we have hedged our coal requirements with coal mine operators and financial institutions to meet our committed burn through December 31, 2010.  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. 

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To the extent our suppliers and buyers do not meet their contractual commitments, we cannot secure adequate fuel or sell excess fuel in a timely or cost-effective manner or we are not hedged against price volatility, our results of operations, financial condition and cash flows could be materially adversely affected.  In addition, DP&L is a co-owner of certain generation facilities where it is a non-operating partner.  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 electric security plan, DP&L implemented a fuel and purchased power recovery mechanism beginning on January 1, 2010, which will track and adjust fuel costs 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.

Commodity Trading

We trade 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 trading 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.  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.

Environmental Compliance

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 reducing NOx, SO2, SO3 (sulfur trioxide) and mercury emissions and potential future control of GHG emissions as discussed in more detail in the next risk factor), water quality, wastewater discharge, solid waste (such as the potential  future regulation of ash generated from coal-based generating stations), hazardous waste and health and safety.  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 will increase 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 occurs in 2010 and remains at that level through 2012.  In addition, DP&L’s electric security plan 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 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 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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Regulation of GHGs

There is a growing concern nationally and internationally among regulators, investors and others concerning global climate change and the contribution of emissions of GHG, including most significantly, CO2.  This concern has led to increased interest in legislation and action at the federal and state levels, as well as litigation, relating to GHG emissions, including a recent declaration by the USEPA that GHGs pose a danger to the public health that may allow the USEPA to directly regulate greenhouse emissions.  There have been various GHG legislative proposals introduced in Congress (with one bill passed by the House of Representatives in 2009) 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 it 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 electric security plan 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.

Sales of Excess Emission Allowances

DP&L has a program for selling excess emission allowances.  During 2009 and 2008, DP&L sold excess emission allowances to various counterparties realizing total net gains of $5.0 million and $34.8 million, respectively.  Sales of 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 of excess emission allowances we sell to fluctuate, which could cause a material adverse effect on our results or operations, financial condition and cash flows for any particular period.

On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit issued a decision that vacated the CAIR and its associated Federal Implementation Plan. This decision remanded these issues back to the USEPA.  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.  The district court’s decision, in part, invalidated the new NOxannual 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 district court’s order to revise the program.  In January 2010, the Court ordered the USEPA to file a response to request for a USEPA decision filed by parties in the original case who are now seeking a Court order to require the USEPA to issue new regulations by March 1, 2010.  We cannot at this time predict the timing or the outcome of any new regulations relating to CAIR.

DP&L’s program for selling excess emission allowances includes sales of annual NOx emission allowances and SO2 emission allowances that were the subject of CAIR trading programs.  Although we continue selling emission allowances, the district court’s CAIR decision has affected the emission allowance trading market and DP&L’s program for selling additional excess allowances.  The long-term impact of the district court’s decision, and of the actions the USEPA or others will take in response to this decision, on DPL and DP&L is not fully known at this time, but could affect the amount of excess emission allowances we sell and thus have an adverse effect on us.

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Customer Switching

Customers can elect to take generation service from a CRES provider offering services to customers in DP&L’s service territory.  Although retail generation service has been a competitive service since January 1, 2001, the competitive generation market has not developed to date in DP&L’s service territory to any significant degree.  As of December 31, 2009, six unaffiliated CRES providers have been certified by the PUCO to provide generation service to DP&L customers.  DPLER, a wholly-owned subsidiary of DPL, is also a certified CRES provider and accounted for 99% of the total kWh consumed by customers served by CRES providers in DP&L’s service territory in 2009.  Increased competition by CRES providers in our service territory for retail generation service could result in the loss of existing customers and increased costs to retain or attract customers, which 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 CRES providers in the future:

·Low wholesale price levels could lead to existing CRES providers becoming more active in our service territory, and new 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.  Several communities in DP&L’s service territory passed ordinances during 2003-2004 allowing them to become government aggregators.  To date, no aggregation program has been implemented.

·Increased customer switching in other Ohio utility service territories could lead to new market entrants and more aggressive measures to secure customers by CRES providers.

Operation and Performance of Facilities

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 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 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 costs and enhanced risks associated with our aging generation units.  Our results of operations, financial condition and cash flows could be adversely affected due to the happening or continuation of these events.

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 pending 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.

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Reliability Standards

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 new 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.

Weather Conditions

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 electric security plan, 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.

Regional Transmission Organizational Risks

On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM.  The price at which we can sell our generation capacity and energy is now determined through supply and demand and the behavior of market participants.  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.  These sales are dependent upon prevailing market prices, which could fluctuate substantially over relatively short periods of time and adversely affect our results of operations, financial condition and cash flows.  The rules governing the various regional power markets also change from time to time which could affect our costs and revenues.  We incur fees and costs to participate in the RTO.  We may be limited with respect to the price at which power may be sold from certain generating units and we may be required to expand our transmission system according to decisions made by the RTO rather than our internal planning process.  While RTO 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, developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights may have a financial impact on us.  While the impact of the capacity market and other RTO developments on us at any given time will depend on a variety of factors, including the market behavior of various participants, our results of operations, financial condition and cash flows could be materially adversely affected.  Future capacity auction results will be dependent not only on the overall supply and demand of generation and load, but also by congestion and PJM’s business rules relating to bidding for Demand Response and Energy Efficiency resources in the auctions.  The PJM RPM base residual auction for the 2012/2013 period cleared at a per megawatt price of $16/day for our RTO area.  Prior to this auction, the per megawatt price for the 2011/2012 period was $110/day.  We cannot predict the outcome of future auctions, but if the current auction price is sustained or there is continued volatility in the auction market, our results of operations, financial condition and cash flows could be materially adversely affected.

SB 221 includes a provision that allows electric utilities to seek and obtain deferral and recovery of RTO related charges.  If in the future, however, we are unable to defer or recover all of these cost in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

As members of PJM, DP&L and DPLE are 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.

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PJM Infrastructure Risks

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.  On April 19, 2007, the FERC issued an order that 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.  The costs of the new facilities at lower voltages will continue to be assigned to the load centers that benefit from the new facilities.  With respect to the socialization of new high voltage facilities, DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit on March 18, 2008 challenging the allocation method.  The appeal was consolidated with other appeals taken by other petitioners 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 for new high voltage facilities that it had approved.  Subsequently, the 7th Circuit denied other petitioners’ rehearing requests 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. At this time, DP&L is unable to predict the outcome of this matter.  The overall impact of FERC’s allocation methodology cannot be definitively assessed at this time because not all new planned construction is likely to happen.  The additional costs allocated to DP&L for new large transmission approved projects were immaterial in 2009 and are not expected to be material in 2010, but could rise to approximately $12 million or more annually by 2012.  DP&L sought and obtained PUCO authority to defer and recover costs associated with these new high-voltage transmission projects through retail rates. However, if in the future we are unable to defer or recover these costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Credit and Capital Markets

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’s variable rate debt 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, our borrowing costs would increase, 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.

Value and Funding of Benefit Plan Assets

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 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 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 of 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.

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Reliance on Third Parties

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, which includes 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 be materially adversely affected.

Our Stock Price May Fluctuate

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 $31.91.  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.

Economic Conditions and Markets

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 global 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, increased 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, recession 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.

Warrant Exercise

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 1.8 million.  As a result, DPL could be required to issue up to 1.8 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 costs, thus affecting any existing guidance on EPS and adversely affecting our financial condition and cash flows.

Internal Controls and Information Reporting

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. 

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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.

Accounting Standards

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 position.  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. Under the SEC’s proposed roadmap, we could be required to prepare financial statements in accordance with IFRS in 2014.  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.

Qualified and Properly Motivated Workforce

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 be materially adversely affected.  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.

Collective Bargaining Agreements and Employee Relations

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.

Cyber Security and Terrorism

Man-made problems such as 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.  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 in a timely way, we would be unable to fulfill critical business functions and sensitive confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows.  In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  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 as Holding Company

DPL is a holding company and its investments in its subsidiaries are its primary assets.  Substantially all 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 materially adversely affect 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, 2009, cannot be reasonably determined.

The information about the legal and other proceedings contained in Item 1 – COMPETITION AND REGULATION under the heading “Ohio Retail Rates” and in Item 8 – Note 19 of Notes to Consolidated Financial Statements of this report under the headings “Governmental and Regulatory Inquiries”, “Air Quality – Litigation Involving Co-Owned Plants”, “Air Quality – Notices of Violation Involving Co-Owned Plants”, “Air Quality – Notices of Violation Involving Wholly-Owned Plants”, “Land Use and Solid Waste Disposal” and “Legal and Other Matters” is incorporated by reference into this Item.

Item 4 - Submission of Matters to a Vote of Security Holders

NONE

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PART II

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

As of February 10, 2010, there were 20,798 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 2009 and 2008:

	2009				2008
	High		Low		High		Low
First Quarter	$	23.28	$	19.27	$	30.18	$	24.58
Second Quarter	$	23.46	$	21.18	$	28.70	$	26.10
Third Quarter	$	26.53	$	22.79	$	26.76	$	23.00
Fourth Quarter	$	28.68	$	25.16	$	24.59	$	19.16

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, 2009, DP&L’s retained earnings of $640.3 million were all available for DP&L common stock dividends payable to DPL.

DPL paid regular quarterly cash dividends of $0.285 and $0.275 per share on our common stock during 2009 and 2008, respectively.  The annualized dividend rate was $1.14 per share in 2009 and $1.10 per share in 2008.

On December 9, 2009, DPL’s Board of Directors authorized a quarterly dividend rate increase of approximately 6%, increasing the quarterly dividend per DPL common share from $0.2850 to $0.3025, effective with the next dividend declaration.  If this dividend rate were maintained, the annualized dividend would increase from $1.14 per share to $1.21 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, 2009 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 2010 Annual Meeting of Shareholders.

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The following table details the repurchase by DPL of its common shares during 2009:

				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)
February	351	$	21.55	—	$	—
November	2,387,991	$	26.96	2,387,991	$	3,911,494
December	3,557	$	27.55	400	$	3,900,658
	2,391,899			2,388,391

(1) Based on a calendar month.

(2) Comprises shares purchased as part of DPL’s current repurchase program and shares surrendered to DPL by employees to satisfy individual tax withholding obligations upon vesting of previously issued shares of restricted common stock.  Shares totaling 3,508 were surrendered during 2009 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 restricted shares.

(4) On October 28, 2009, the DPL Board of Directors approved, and DPL publicly announced, a Stock Repurchase Program under which DPL may use proceeds from the exercise of warrants to repurchase warrants or DPL common stock from time to time in the open market, through private transactions or otherwise.  Through December 31, 2009, the amount of such proceeds available to be used under the Stock Repurchase Program approximated $68.3 million, of which $64.4 million was used during the quarter ended December 31, 2009 to purchase approximately 2.4 million shares at an average per share price of $26.96.  At December 31, 2009, the amount still available that could be used to repurchase stock under the Stock Repurchase Program is approximately $3.9 million but could be higher if additional warrants are exercised for cash in the future.  The Stock Repurchase Program will run through June 30, 2012, which is approximately three months after the end of the warrant exercise period.

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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, 2004 to December 31, 2009.

*$1000 invested on 12/31/04 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31.

Copyright© 2010 S&P, a division of The McGraw - -Hill Companies Inc. All rights reserved.

Copyright© 2010 Dow Jones & Co. All rights reserved.

	12/04		12/05		12/06		12/07		12/08		12/09
DPL Inc.	$	1,000.00	$	1,074.53	$	1,191.30	$	1,317.68	$	1,061.20	$	1,345.50
Dow Jones US Industrial Average	$	1,000.00	$	1,017.22	$	1,210.97	$	1,318.56	$	897.54	$	1,101.13
S&P Electric Utilities	$	1,000.00	$	1,176.57	$	1,449.66	$	1,784.80	$	1,323.70	$	1,368.40
S&P Utilities	$	1,000.00	$	1,168.41	$	1,413.66	$	1,687.61	$	1,198.53	$	1,341.26

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)	2009			2008			2007			2006			2005
DPL
Basic earnings (loss) per share of common stock:
Continuing operations (a)	$	2.03		$	2.22		$	1.97		$	1.12		$	1.03
Discontinued operations (b)	$	—		$	—		$	0.09		$	0.12		$	0.44
Cumulative effect of accounting change (c)	$	—		$	—		$	—		$	—		$	(0.03	)
Total basic earnings per common share	$	2.03		$	2.22		$	2.06		$	1.24		$	1.44
Diluted earnings (loss) per share of common stock:
Continuing operations (a)	$	2.01		$	2.12		$	1.80		$	1.03		$	0.97
Discontinued operations (b)	$	—		$	—		$	0.08		$	0.12		$	0.41
Cumulative effect of accounting change (c)	$	—		$	—		$	—		$	—		$	(0.03	)
Total dilutive earnings per common share	$	2.01		$	2.12		$	1.88		$	1.15		$	1.35
Dividends declared per share	$	1.14		$	1.10		$	1.04		$	1.00		$	0.96
Dividend payout ratio	56.2		%	49.5		%	50.5		%	80.7		%	66.7		%
Total electric sales (millions of kWh)	16,667			17,172			18,598			18,418			17,906
Results of operations:
Revenues	$	1,588.9		$	1,601.6		$	1,515.7		$	1,393.5		$	1,284.9
Earnings from continuing operations, net of tax (a)	$	229.1		$	244.5		$	211.8		$	125.6		$	124.7
Earnings from discontinued operations, net of tax	$	—		$	—		$	10.0		$	14.0		$	52.9
Cumulative effect of accounting change, net of tax	$	—		$	—		$	—		$	—		$	(3.2	)
Net income	$	229.1		$	244.5		$	221.8		$	139.6		$	174.4
Financial position items at December 31:
Total assets	$	3,641.7		$	3,637.0		$	3,566.6		$	3,612.2		$	3,791.7
Long-term debt (d)	$	1,223.5		$	1,376.1		$	1,541.5		$	1,551.8		$	1,677.1
Total construction additions	$	145.3		$	227.8		$	346.7		$	351.6		$	179.7
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-			BBB+			BBB+			BBB			BBB-
Moody’s Investors Service	Baa1			Baa2			Baa2			Baa3			Ba1
Standard & Poor’s Corporation	BBB+			BBB-			BBB-			BB			BB-
Number of shareholders - common stock	20,888			21,628			22,771			24,434			26,601
DP&L
Total electric sales (millions of kWh)	16,590			17,105			18,598			18,418			17,906
Results of operations:
Revenues	$	1,550.4		$	1,572.9		$	1,507.4		$	1,385.2		$	1,276.9
Earnings on common stock (a)	$	258.0		$	284.9		$	270.7		$	241.6		$	210.9
Financial position items at December 31:
Total assets	$	3,457.4		$	3,397.7		$	3,276.7		$	3,090.3		$	2,738.6
Long-term debt (d)	$	783.7		$	884.0		$	874.6		$	785.2		$	685.9
Redeemable preferred stock of subsidiary	$	22.9		$	22.9		$	22.9		$	22.9		$	22.9
Senior secured debt ratings at December 31:
Fitch Ratings	AA-			A+			A+			A			A-
Moody’s Investors Service	Aa3			A2			A2			A3			Baa1
Standard & Poor’s Corporation	A			A-			BBB+			BBB			BBB-
Number of shareholders - preferred stock	242			256			281			290			329

(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.  See Note 6 of the Notes to Consolidated Financial Statements.

(c)In 2005, we recorded a cumulative effect of an accounting change related to an additional obligation in response to the provisions of GAAP relating to the accounting for AROs.

(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

This report includes the combined filing of DPL Inc. (DPL) and The Dayton Power and Light Company (DP&L).  DP&L is the principal subsidiary of DPL providing approximately 98% of DPL’s total consolidated revenue and approximately 95% 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.

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 and through its principal subsidiary 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 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.

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, fuel supply and price risk and 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.

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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.

As we look forward, there are a number of issues that we believe may have a significant impact on our business and operations described above.  The following issues mentioned below are not meant to be exhaustive but to provide insight to matters that have or are likely to have an effect on our industry and business:

REGULATORY ENVIRONMENT

·Emissions – Climate Change Legislation

There is a growing concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly, CO2.  This concern has led to increased 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 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.  It is anticipated that this ruling will lead to the regulation of CO2 and other GHGs from electric generating units and other stationary sources of these emissions.  In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES).  This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy-wide cap and trade program.  ACES also includes energy efficiency and renewable energy initiatives.  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.  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 increases in required percentages each year.  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 entry establishing a significantly excessive earnings test (SEET) proceeding.  A workshop was held at the Commission offices on October 5, 2009 to allow interested parties to present concerns and discuss issues related to the methodology.  On November 18, 2009 the PUCO Staff issued its recommendations to the Commission.  Staff recommendations provided that off-system or wholesale sales should be included in the calculation, and that some threshold should be established based on a group of comparable companies that would determine if the utility had significantly excessive earnings in a given year.  DP&L filed its comments and reply comments along with other interested parties.  Although DP&L’s Stipulation provides that the SEET does not apply to DP&L until 2013 based on 2012 earnings results, DP&L is actively participating in this proceeding.

·CAIR decision by the U.S. Court of Appeals for the District of Columbia Circuit

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 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. 

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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.  In January 2010, the Court ordered the USEPA to file a response to a Petition for Mandamus filed by parties in the original case who are now seeking a Court order to require the USEPA to issue new regulations by March 1, 2010.  We cannot at this time predict the timing or the outcome of any new regulations in relation to CAIR.  CAIR has and will continue to have a material effect on our operations.

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 has affected the trading market for excess allowances and impacted DP&L’s program for selling additional excess allowances.  The overall impact of the court’s decision, and of the actions the USEPA or others will take in response to this decision, on DPL and DP&L is not fully known at this time and could have an adverse effect on us.  In January 2009, we resumed selling excess emission allowances due to the revival of the trading market.

COMPETITION AND PJM PRICING

·RPM Capacity Auction Price

The PJM RPM base residual auction for the 2012/2013 period cleared at a per megawatt price of $16/day for our RTO area.  Prior to this auction, the per megawatt price for the 2011/2012 period was $110/day.  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 auctions.  We cannot predict the outcome of future auctions but if the current auction price is sustained, our future results of operations, financial condition and cash flows could be adversely impacted.

·Ohio Competitive Considerations and Proceedings

Overall power market prices, as well as government aggregation initiatives, could lead to the entrance of competitors in our marketplace, affecting our results of operations, financial condition or cash flows.  During the year ended December 31, 2009, two additional unaffiliated marketers registered as CRES providers in DP&L’s service territory, bringing to six the total number of unaffiliated CRES providers in DP&L’s service territory.  While there has been some customer switching associated with unaffiliated marketers, it represented less than 0.11% of sales in 2009.  DPLER, an affiliated company, is also a registered CRES provider and accounted for 99% of the total kWh supplied by CRES providers within DP&L’s service territory in 2009.  During the first quarter of 2010, DPLER will begin providing CRES services to business customers in Ohio who are not in DP&L’s service territory.  At this time, we do not expect the incremental costs and revenues to have a material impact on our results of operations, financial position or cash flows.  We currently cannot determine the extent to which customer switching to unaffiliated CRES providers will occur in the future and the impact this will have on our operations.  In 2003-2004, several communities in DP&L’s service area 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.

FUEL AND RELATED COSTS

·Fuel and Commodity Prices

During 2009 and 2008, the coal market experienced significant price volatility.  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 in recent years.  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, 2010, we have hedged 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.  To the extent our suppliers do not meet their contractual commitments or we are not hedged against price volatility, our results of operations, financial position or cash flows could be materially affected.  Beginning in January 2010, the Ohio retail jurisdictional share of fuel price changes will be reflected in the operation of the fuel rider, subject to PUCO review.

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·Sales of Coal and Excess Emission Allowances

During 2009, DP&L sold coal and excess emission allowances to various counterparties realizing total net gains of $56.3 million and $5.0 million, respectively.  These gains are recorded as a component of DP&L’s fuel costs and reflected in operating income.  Coal sales are impacted by a range of factors but can be largely attributed to the following: variation in power demand, the market price of power compared to the cost to produce power, as well as optimization opportunities in the coal market.  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 2010 and beyond is not fully known at this time and could materially impact the amount of gains that will be recognized in the future.  In addition, beginning in January 2010 as part of the operation of the fuel rider, the Ohio retail jurisdictional share of the emission gains and a portion of the Ohio jurisdictional share of the coal gains will be used to reduce the overall rate charged to customers.

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, 2009, Net income for DPL was $229.1 million, or $2.01 per share, compared to Net income of $244.5 million, or $2.12 per share, for the same period in 2008.  All EPS amounts are on a diluted share basis.  The decrease in net income compared to the prior year was primarily due to the following:

·a decrease in retail sales volume due to the impacts of the economic slowdown and milder weather throughout the year,

·a decrease in wholesale power sales prices,

·a decrease in gains recognized from the sale of coal,

·a decrease in gains recognized from the sale of excess emission allowances,

·an increase in the cost of fuel due to the increased volume of generation by our power plants and higher average fuel costs, particularly for coal, and

·an increase in pension and employee benefit related costs.

Partially offsetting these items were:

·an increase in retail rates primarily as a result of an increase in the EIR and the implementation of the TCRR, RPM and Energy Efficiency riders,

·an improvement in generating plant performance which resulted in an increase in wholesale sales volume and a decrease in purchased power volumes,

·a decrease in power purchase prices and

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

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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 98% of the total revenues of DPL.  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	2009			2008			2007
Revenues:
Retail	$	1,229.0		$	1,223.3		$	1,206.2
Wholesale	122.5			149.9			180.3
RTO revenues	89.4			110.4			87.4
RTO capacity revenues	136.3			106.9			30.9
Other revenues	11.7			11.1			10.9
Total revenues	$	1,588.9		$	1,601.6		$	1,515.7
Cost of revenues:
Fuel costs	$	391.7		$	361.2		$	330.0
Gains from sale of coal	(56.3		)	(83.4		)	(0.6		)
Gains from sale of emission allowances	(5.0		)	(34.8		)	(1.2		)
Net fuel	330.4			243.0			328.2
Purchased power	46.9			148.7			156.9
RTO charges	105.0			127.8			101.9
RTO capacity charges	131.8			100.9			28.4
Recovery / (Deferral) of RTO related charges, net	(23.5		)	—			—
Net purchased power	260.2			377.4			287.2
Total cost of revenues	$	590.6		$	620.4		$	615.4
Gross margins (a)	$	998.3		$	981.2		$	900.3
Gross margin as a percentage of revenues	62.8		%	61.3		%	59.4		%
Operating income	$	428.2		$	435.5		$	370.1
Basic earnings per share:
Continuing operations	$	2.03		$	2.22		$	1.97
Discontinued operations	—			—			0.09
Total basic	$	2.03		$	2.22		$	2.06
Diluted earnings per share:
Continuing operations	$	2.01		$	2.12		$	1.80
Discontinued operations	—			—			0.08
Total diluted	$	2.01		$	2.12		$	1.88

(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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DPL – Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days.  Therefore, DPL’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year.  Since DPL plans to utilize its internal generating capacity to supply its 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 DPL’s wholesale sales volume each hour of the year include wholesale market prices; DPL’s retail demand; retail demand elsewhere throughout the entire wholesale market area; DPL and non-DPL plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DPL’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities not being utilized to meet its 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	2009 vs. 2008			2008 vs. 2007
Retail
Rate	$	119.6		$	45.1
Volume	(113.5		)	(23.7		)
Other	(0.4		)	(4.3		)
Total retail change	$	5.7		$	17.1
Wholesale
Rate	$	(87.0	)	$	29.8
Volume	59.6			(60.2		)
Total wholesale change	$	(27.4	)	$	(30.4	)
RTO capacity and other
RTO capacity and other revenues	$	9.0		$	99.2
Total revenues change	$	(12.7	)	$	85.9

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 third phase of 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 DPL’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.  Beginning June 1, 2009 when the TCRR and RPM rate riders became effective, the Ohio retail jurisdiction share of this change had no impact on net income.

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For the year ended December 31, 2008, Revenues increased $85.9 million, or 6%, to $1,601.6 million from $1,515.7 million in the prior year.  This increase was primarily the result of higher average rates for retail and wholesale sales as well as an increase in RTO capacity and other revenues, partially offset by lower retail and wholesale sales volumes.  The revenue components for the year ended December 31, 2008 are further discussed below:

·Retail revenues increased $17.1 million resulting primarily from a 4% increase in average retail rates due largely to the second phase of the EIR, partially offset by a 2% decrease in sales volume.  The decrease in retail sales volume was primarily a result of milder weather which caused cooling degree days to decrease by 26% to 853 days, combined with a 6% decrease in the volume of sales to industrial customers.  The lower sales volumes to industrial customers were driven largely by the downturn in the economy which severely affected the automotive and other related industries in the region resulting in plant closures and reduced production.  These decreases were partially offset by a 9% increase in heating degree days.

·Wholesale revenues decreased $30.4 million primarily as a result of a 33% decrease in sales volume due largely to unplanned outages, partially offset by a 25% increase in wholesale average rates, resulting in an unfavorable $60.2 million sales volume variance and a favorable $29.8 million wholesale price variance.

·RTO capacity and other revenues, consisting primarily of compensation for use of DPL’s transmission assets, regulation services, reactive supply and operating reserves as well as capacity payments under the RPM construct, increased $99.2 million compared to the prior year.  This increase primarily resulted from additional income realized from the PJM capacity auction and increased PJM transmission and congestion revenues.

DPL – Cost of Revenues

For the year ended December 31, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), 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.

·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.  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.

For the year ended December 31, 2008:

·Fuel costs, which include coal (net of gains on sales), gas, oil, and emission allowances (net of gains on sales), decreased $85.2 million, or 26%, compared to 2007, primarily due to increases in net gains of $33.6 million from the sale of DP&L’s excess emission allowances and $82.8 million realized from the sale of DP&L’s coal combined with a decrease in the usage of fuel due mainly to a 6% decrease in generation output largely attributable to unplanned outages.  These decreases were partially offset by increased fuel prices.  The successful installation of FGD equipment at Miami Fort, Killen and J.M. Stuart stations has allowed us the ability to burn coal with a wide range of sulfur content and, accordingly, we purchase and sell coal as we seek to achieve optimum levels of production efficiency.  Gains or losses from sales of coal and emission allowances are recorded as components of fuel costs.

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·Purchased power costs increased $90.2 million, or 31%, compared to 2007.  The increase in purchased power primarily results from a $15.3 million increase relating to higher average market rates and a $98.4 million increase in RTO capacity and other RTO charges, partially offset by a $23.5 million decrease relating to lower volumes of purchased power.  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.

DPL - Operation and Maintenance

$ 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
Group 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.

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 reserves.

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.

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$ in millions	2008 vs. 2007
Legal costs	$	(17.6	)
Deferred compensation	(8.1		)
ESOP	(7.1		)
Pension	(2.4		)
Insurance settlement	14.5
Generating facilities operating expenses	11.1
Gain on sale of corporate aircraft	6.0
Turbine maintenance costs	4.1
Boiler maintenance costs	1.0
Other, net	(2.6		)
Total operation and maintenance expense	$	(1.1	)

During the year ended December 31, 2008, Operation and maintenance expense decreased $1.1 million, or less than 1%, as compared to 2007.  This variance was primarily due to:

·a decrease in legal costs due largely to the litigation settlement with three of our former executives in May 2007,

·a decrease in deferred compensation costs associated to a large degree with deferred compensation liabilities for the three former executives,

·a decrease in employee compensation expense associated with the ESOP due mainly to the additional shares that were released from the ESOP in 2007 and

·lower pension costs primarily due to the plan funding made in November 2007.

These decreases were partially offset by:

·the 2007 insurance settlement which reimbursed us for legal fees relating to the litigation with three former executives,

·an increase in operating expenses largely due to the operation of FGD and SCR equipment and related gypsum disposal,

·the gain on sale of the corporate aircraft realized in 2007 and

·an increase in turbine maintenance costs incurred due to an unplanned outage at a jointly-owned production unit.

DPL – Depreciation and Amortization

During the year ended December 31, 2009, Depreciation and amortization expense increased $7.8 million, or 6%, 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.

During the year ended December 31, 2008, Depreciation and amortization expense increased $2.9 million, or 2%, as compared to 2007.  This increase was primarily a result of higher plant balances due largely to the installation of the FGD equipment, partially offset by the impact of lower depreciation rates for generation property which were put into effect on August 1, 2007.

DPL – General 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.

During the year ended December 31, 2008, General taxes increased $13.7 million, or 12%, as compared to 2007, primarily as a result of higher property taxes due mainly to capital improvements which have led to higher assessed property values, combined with increased tax rates.

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DPL – Investment Income (Loss)

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 relating to a loss incurred by DPL Capital Trust II, a nonconsolidated wholly-owned subsidiary.

During the year ended December 31, 2008, Investment income (loss) decreased $7.7 million, or 68%, as compared to 2007.  This decrease was primarily the result of:

·$3.2 million of gains realized in 2007 from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation which were used for the settlement payment to three former executives and

·lower cash and short-term investment balances combined with overall lower market yields on investments in 2008 compared to 2007.

DPL – Net Gain on Settlement of Executive Litigation

On May 21, 2007, we settled litigation with three former executives.  In exchange for our payment of $25 million, the three former executives relinquished and dismissed all of their claims, including those related to deferred compensation, RSUs, MVE incentives, stock options and legal fees.  As a result of this settlement, during 2007, DPL realized a net pre-tax gain in continuing operations of approximately $31.0 million.  See Note 17 of Notes to Consolidated Financial Statements.

DPL – Interest Expense

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.  These regulatory assets are further discussed in Note 3 of Notes to Consolidated Financial Statements.

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 on the early redemption of a portion of DPL’s Note to DPL Capital Trust II which is due 2031.  In December 2009, DPL redeemed $52.4 million of this $195 million 8.125% note.  This redemption is further discussed in Note 7 of Notes to Consolidated Financial Statements.

During the year ended December 31, 2008, Interest expense increased $9.7 million, or 12%, as compared to 2007 primarily due to:

·$12.9 million of lower capitalized interest due to the completion of the FGD projects at Miami Fort, Killen and J.M. Stuart stations,

·the write-off of unamortized debt issuance costs amounting to $1.6 million relating to pollution control bonds following their repurchase from the bondholders in April 2008 and

·$0.9 million of additional interest expense associated with DP&L’s $90 million variable rate pollution control bonds issued November 15, 2007 and repurchased in April 2008.

These increases were partially offset by a $7.0 million interest expense reduction due to the redemption of the $225 million 8.25% Senior Notes in March 2007 and the $100 million 6.25% Senior Notes in May 2008.

DPL – Other Income (Deductions)

During the year ended December 31, 2009, there were no material fluctuations in the balances of Other income (deductions).

During the year ended December 31, 2008, other deductions of $1.0 million changed from other income of $2.9 million recorded in 2007.  The change from other income to other deductions primarily resulted from the recognition in 2007 of a $2.1 million deferred credit related to a litigation settlement (which was not part of the executive litigation settlement).

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DPL – Income Tax Expense

For the year ended December 31, 2009, Income tax expense increased $9.6 million, or 9%, 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.

During 2008, Income tax expense decreased $19.6 million, or 16%, as compared to 2007, primarily due to a decrease in the effective tax rate reflecting the phase-out of the Ohio Franchise Tax and the 2008 settlement of the Ohio Franchise Tax issue which resulted in a recorded tax benefit of $8.5 million.

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

Income Statement Highlights – DP&L

	For the years ended December 31,
$ in millions	2009			2008			2007
Revenues:
Retail	$	1,167.2		$	1,075.3		$	1,057.4
Wholesale	181.9			293.5			331.7
RTO revenues	86.1			108.3			87.4
RTO capacity revenues	115.2			95.8			30.9
Total revenues	$	1,550.4		$	1,572.9		$	1,507.4
Cost of revenues:
Fuel costs	$	384.9		$	349.6		$	317.2
Gains from sale of coal	(56.3		)	(83.4		)	(0.6		)
Gains from sale of emission allowances	(5.0		)	(34.8		)	(1.2		)
Net fuel	323.6			231.4			315.4
Purchased power	46.9			152.4			170.0
RTO charges	104.1			126.6			101.9
RTO capacity charges	131.7			100.9			28.4
Recovery / (Deferral) of RTO related charges, net	(23.5		)	—			—
Net purchased power	259.2			379.9			300.3
Total cost of revenues	$	582.8		$	611.3		$	615.7
Gross margins (a)	$	967.6		$	961.6		$	891.7
Gross margin as a percentage of revenues	62.4		%	61.1		%	59.2		%
Operating income	$	421.9		$	436.6		$	375.1

(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

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days.  Therefore, DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year.  Since DP&L plans to utilize its internal generating capacity to supply its 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 DP&L’s wholesale sales volume each hour of the year include wholesale market prices; DP&L’s retail demand, retail demand elsewhere throughout the entire wholesale market area; DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region.  DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities that are not being utilized to meet its 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	2009 vs. 2008			2008 vs. 2007
Retail
Rate	$	191.7		$	43.0
Volume	(99.7		)	(20.8		)
Other	(0.1		)	(4.3		)
Total retail change	$	91.9		$	17.9
Wholesale
Rate	$	(230.5	)	$	79.2
Volume	118.9			(117.4		)
Total wholesale change	$	(111.6	)	$	(38.2	)
RTO capacity and other
RTO capacity and other revenues	$	(2.8	)	$	85.8
Total revenues change	$	(22.5	)	$	65.5

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 third phase of the EIR and the implementation of the TCRR, RPM, Energy Efficiency and Alternative Energy rate 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.  Beginning June 1, 2009 when the TCRR and RPM rate deferral riders became effective, the Ohio retail jurisdiction share of this change had no impact on Net income.

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For the year ended December 31, 2008, Revenues increased $65.5 million, or 4%, to $1,572.9 million from $1,507.4 million in the same period of the prior year.  This increase was primarily the result of higher average rates for retail and wholesale sales, as well as an increase in RTO capacity and other revenues, partially offset by lower retail and wholesale sales volumes.  The revenue components for the year ended December 31, 2008 are further discussed below:

·Retail revenues increased $17.9 million resulting primarily from a 4% increase in average retail rates due largely to the second phase of the EIR, partially offset by a 2% decrease in sales volume.  The decrease in retail sales volume was primarily a result of milder weather which caused cooling degree days to decrease by 26% to 853 days, combined with a 6% decrease in the volume of sales to industrial customers.  The lower sales volumes to industrial customers were driven largely by the downturn in the economy which has severely affected the automotive and other related industries in the region resulting in plant closures and reduced production.  These decreases were partially offset by a 9% increase in heating degree days.

·Wholesales revenues decreased $38.2 million primarily as a result of a 35% decrease in sales volume due largely to unplanned outages, partially offset by a 37% increase in wholesale average rates, resulting in an unfavorable $117.4 million sales volume variance and a favorable $79.2 million wholesale price 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 $85.8 million compared to the prior year.  This increase primarily resulted from additional income realized from the PJM capacity auction and increased PJM transmission and congestion revenues.

DP&L – Cost of Revenues

For the year ended December 31, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), 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.

·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.

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For the year ended December 31, 2008:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), decreased $84.0 million, or 27%, compared to 2007, primarily due to increases in net gains of $33.6 million from the sale of DP&L’s excess emission allowances and $82.8 million realized from the sale of DP&L’s coal combined with a decrease in the usage of fuel due mainly to a 6% decrease in generation output largely attributable to unplanned outages.  These decreases were partially offset by increased fuel prices.  The successful installation of FGD equipment at Miami Fort, Killen and J.M. Stuart stations has allowed us the ability to burn coal with a wide range of sulfur content and, accordingly, we purchase and sell coal as we seek to achieve optimum levels of production efficiency.  Gains or losses from sales of coal and emission allowances are recorded as components of fuel costs.

·Purchased power costs increased $79.6 million, or 27%, compared to 2007.  The increase in purchased power primarily results from an $11.8 million increase relating to higher average market rates and a $97.2 million increase in RTO capacity and other RTO charges, partially offset by a $29.3 million decrease relating to lower volumes of purchased power.  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.

DP&L – Operation and Maintenance

$ in millions	2009 vs. 2008
Pension	$	6.1
Low-income payment program (1)	6.1
Energy efficiency programs (1)	5.9
ESOP	3.3
Group 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 reserves.

These increases are 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.

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$ in millions	2008 vs. 2007
ESOP	$	(7.0	)
Deferred compensation	(5.8		)
Legal costs	(3.9		)
Pension	(2.4		)
Generating facilities operating expenses	11.1
Turbine maintenance costs	4.1
Boiler maintenance costs	1.0
Other, net	(5.9		)
Total operation and maintenance expense	$	(8.8	)

During the year ended December 31, 2008, Operation and maintenance expense decreased $8.8 million, or 3%, as compared to 2007.  This variance was primarily due to:

·a decrease in employee compensation expense associated with the ESOP due mainly to the additional shares that were released from the ESOP in 2007,

·a decrease in deferred compensation costs associated to a large degree with deferred compensation liabilities for three former executives,

·a decrease in legal fees and

·lower pension costs primarily due to the plan funding made in November 2007.

These decreases were partially offset by:

·an increase in operating expenses at our generating facilities largely due to the operation of the FGD and SCR equipment and related gypsum disposal,

·an increase in turbine maintenance costs incurred due to an unplanned outage at a jointly-owned production unit and

·an increase in boiler maintenance expenses in 2008.

DP&L – Depreciation and Amortization

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.

During the year ended December 31, 2008, Depreciation and amortization expense increased $3.3 million, or 3%, as compared to 2007.  This increase was primarily a result of higher plant balances due largely to the installation of FGD equipment, partially offset by the impact of lower depreciation rates for generation property which were put into effect on August 1, 2007.

DP&L – General 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.

During the year ended December 31, 2008, General taxes increased $13.9 million, or 13%, as compared to 2007, primarily as a result of higher property taxes due mainly to capital improvements which have led to higher assessed property values, combined with increased tax rates.

DP&L – Investment Income

During the year ended December 31, 2009, Investment income (loss) 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.

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During the year ended December 31, 2008, Investment income (loss) decreased $16.7 million, or 70%, as compared to 2007.  This decrease was primarily the result of:

·$14.8 million of gains realized in 2007 on the transfer of DPL common stock to the DP&L Retirement Income Plan Trust (Pension) and

·$3.2 million of gains realized in 2007 from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation which were used for the settlement payment to three former executives.

DP&L – Net Gain on Settlement of Executive Litigation

On May 21, 2007, we settled litigation with three former executives.  In exchange for our payment of $25 million, the three former executives relinquished and dismissed all of their claims, including those related to deferred compensation, RSUs, MVE incentives, stock options and legal fees.  As a result of this settlement, in 2007, DP&L realized a net pre-tax gain in continuing operations of approximately $35.3 million.  See Note 17 of Notes to Consolidated Financial Statements.

DP&L – Interest Expense

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:

·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.  These Regulatory assets are further discussed in Note 3 of Notes to Consolidated Financial Statements.

During the year ended December 31, 2008, Interest expense increased $14.2 million, or 64%, as compared to 2007 primarily as a result of:

·$12.9 million of lower capitalized interest due to the completion of the FGD projects at Miami Fort, Killen, and J.M. Stuart stations,

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

·$0.9 million of additional Interest expense associated with DP&L’s $90 million variable rate pollution control bonds issued in November 2007 and repurchased in April 2008.

DP&L – Other Income (Deductions)

During the year ended December 31, 2009, there were no material fluctuations in the balances of Other income (deductions).

During the year ended December 31, 2008, Other deductions of $1.1 million changed from Other income of $2.9 million recorded in 2007.  The change from Other income to Other deductions primarily resulted from the recognition in 2007 of a $2.1 million deferred credit related to a litigation settlement (which was not part of the executive litigation settlement).

DP&L –Income Tax Expense

For the year ended December 31, 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.

During 2008, Income tax expense decreased $22.9 million, or 16%, as compared to 2007, primarily due to a decrease in the effective tax rate reflecting the phase-out of the Ohio Franchise Tax and the 2008 settlement of the Ohio Franchise Tax issue which resulted in a recorded tax benefit of $8.5 million.

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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	2009			2008			2007
Net cash provided by operating activities	$	526.1		$	363.2		$	318.1
Net cash used for investing activities	(166.1		)	(248.5		)	(187.8		)
Net cash used for financing activities	(347.6		)	(187.1		)	(257.6		)
Net change	$	12.4		$	(72.4	)	$	(127.3	)
Cash and cash equivalents at beginning of period	62.5			134.9			262.2
Cash and cash equivalents at end of period	$	74.9		$	62.5		$	134.9

DP&L

	For the years ended December 31,
$ in millions	2009			2008			2007
Net cash provided by operating activities	$	515.1		$	394.6		$	353.0
Net cash used for investing activities	(167.4		)	(242.0		)	(343.2		)
Net cash used for financing activities	(311.4		)	(145.0		)	(42.7		)
Net change	$	36.3		$	7.6		$	(32.9	)
Cash and cash equivalents at beginning of period	20.8			13.2			46.1
Cash and cash equivalents at end of period	$	57.1		$	20.8		$	13.2

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

Net Cash Provided by Operating Activities

The tariff-based 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, 2009, 2008 and 2007 can be summarized as follows:

$ in millions	2009			2008			2007
Earnings from continuing operations	$	229.1		$	244.5		$	211.8
Depreciation and amortization	145.5			137.7			134.8
Deferred income taxes	201.6			43.1			3.1
Income tax settlement	—			(42.0		)	—
Regulatory expenditures under TCRR/RPM and 2008 storms	(15.7		)	(13.1		)	—
Net gain on settlement of executive litigation	—			—			(31.0		)
Other	(34.4		)	(7.0		)	(0.6		)
Net cash provided by operating activities	$	526.1		$	363.2		$	318.1

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;

·      the $15.7 million of cash used 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.

·      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, 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 and

·      the $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.

·      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, such as regulatory assets and liabilities.

For the year ended December 31, 2007, Net cash provided by operating activities was primarily a result of Earnings from continuing operations adjusted for noncash depreciation and amortization and the noncash impact of the net gain realized on settlement of the executive litigation.  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, such as regulatory assets and liabilities.

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DP&L – Net Cash provided by Operating Activities

DP&L’s Net cash provided by operating activities for the years ended December 31, 2009, 2008 and 2007 can be summarized as follows:

$ in millions	2009			2008			2007
Net income	$	258.9		$	285.8		$	271.6
Depreciation and amortization	135.5			127.8			124.5
Deferred income taxes	200.1			40.9			(0.2		)
Income tax settlement	—			(42.0		)	—
Regulatory expenditures under TCRR/RPM and 2008 storms	(15.7		)	(13.1		)	—
Net gain on settlement of executive litigation	—			—			(35.3		)
Other	(63.7		)	(4.8		)	(7.6		)
Net cash provided by operating activities	$	515.1		$	394.6		$	353.0

For the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008 and 2007 can be summarized as follows:

��

$ in millions	2009			2008			2007
DP&L environmental-related capital expenditures	$	(21.2	)	$	(90.2	)	$	(208.8	)
DP&L capital upgrades due to 2008 storms	—			(18.6		)	—
DP&L other plant-related asset acquisitions	(146.2		)	(133.2		)	(134.4		)
DP&L’s net cash used for investing activities	$	(167.4	)	$	(242.0	)	$	(343.2	)
Proceeds from sales of DPL assets	—			—			158.4
Other	1.3			(6.5		)	(3.0		)
DPL’s net cash used for investing activities	$	(166.1	)	$	(248.5	)	$	(187.8	)

For all years, the environmental-related capital expenditures relate to cash outflows incurred during the installation and upgrades of FGD and SCR equipment.  Other plant-related asset acquisitions relate to investments in other generation, transmission and distribution equipment.

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.

For the year ended December 31, 2007, the proceeds received from asset sales relate to the sale of two DPLE peaker units and an aircraft previously owned by a DPL subsidiary.

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DPL – Net Cash used for Financing Activities

DPL’s Net cash used for financing activities for the years ended December 31, 2009, 2008 and 2007 can be summarized as follows:

$ in millions	2009			2008			2007
Retirement of long-term debt	$	(227.4	)	$	(100.0	)	$	(225.0	)
Dividends paid on common stock	(128.8		)	(120.5		)	(111.7		)
Repurchase of DPL common stock	(64.4		)	—			—
Repurchase of warrants	(25.2		)	—			—
Proceeds from exercise of warrants	77.7			—			—
Cash withdrawn from restricted funds	14.5			32.5			63.2
Proceeds from exercise of stock options	9.0			2.2			14.6
Other	(3.0		)	(1.3		)	1.3
Net cash used for financing activities	$	(347.6	)	$	(187.1	)	$	(257.6	)

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 14 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.  In comparison to 2007, the lower cash withdrawals from restricted funds in 2008 were primarily due to the timing of costs incurred relating to the installation of FGD and SCR equipment.  In addition, the reduced cash proceeds in 2008 from the exercise of stock options were a direct result of fewer options exercised.

For the year ended December 31, 2007, DPL retired $225 million of long-term debt, paid common stock dividends of $111.7 million, withdrew $63.2 million from restricted funds to pay for environmental-related capital expenditures and received $14.6 million from the exercise of stock options.

DP&L – Net Cash used for Financing Activities

DP&L’s Net cash used for financing activities for the years ended December 31, 2009, 2008 and 2007 can be summarized as follows:

$ in millions	2009			2008			2007
Dividends paid on common stock to parent	$	(325.0	)	$	(155.0	)	$	(125.0	)
Net loan (paid to) / received from parent	—			(20.0		)	20.0
Cash withdrawn from restricted funds	14.5			32.5			63.2
Other	(0.9		)	(2.5		)	(0.9		)
Net cash used for financing activities	$	(311.4	)	$	(145.0	)	$	(42.7	)

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.

For the year ended December 31, 2007, DP&L paid $125 million in dividends to DPL, withdrew $63.2 million from restricted funds held in trust and received a net $20 million short-term loan from DPL.

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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, and interest and dividend payments.  For 2010 and in 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.

We have access to $320 million of short-term financing under two revolving credit facilities.  The first facility for $220 million expires 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 is a 364-day $100 million facility that matures April 2010.  A total of six banks participate in this facility, with no bank having more than 26% of the total commitment.  The two bank groups have no common members.  We are currently evaluating the impact the maturity of the $100 million facility will have on our future liquidity and would expect to be able to renew or replace this facility as needed.

					Amounts
					available as of
$ in millions	Type	Maturity	Commitment		December 31, 2009
DP&L	Revolving	11/21/2011	$	220.0	$	220.0
DP&L	Revolving	04/20/2010	$	100.0	$	100.0
			$	320.0	$	320.0

The $220 million revolver has a $50 million Letter of Credit (LOC) sublimit.  As of December 31, 2009, there were no outstanding LOCs.

Cash and cash equivalents for DPL and DP&L amounted to $74.9 million and $57.1 million, respectively, at December 31, 2009.

Capital Requirements

CONSTRUCTION ADDITIONS

	Actual						Projected
$ in millions	2009		2008		2007		2010		2011		2012
DPL	$	145	$	228	$	347	$	210	$	200	$	180
DP&L	$	144	$	225	$	344	$	200	$	190	$	175

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 is projecting to spend an estimated $590 million in capital projects for the period 2010 through 2012, mostly through its subsidiary DP&L.

Planned construction additions for 2010 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and transmission and distribution systems.  In addition to our capital requirements above, on August 4, 2009, DP&L re-filed its smart grid and advanced metering infrastructure (AMI) business cases with the PUCO under which it would spend approximately $270 million on capital projects during the period 2010 through 2012.  Approval from the PUCO of these cases is still pending.  The re-filing at the PUCO is further discussed in Note 3 of Notes to Consolidated Financial Statements.

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.

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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	November 2009
Moody’s Investors Service	Baa1	Aa3	Stable	August 2009
Standard & Poor’s Corp.	BBB+	A	Stable	April 2009

(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.

At December 31, 2009, DPL had $51 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 $0.6 million at December 31, 2009 and $1.6 million at December 31, 2008.

In two separate transactions in November and December 2006, DPL also agreed to be a guarantor of the obligations of DPLE regarding the sale in April 2007 of the Darby Electric Peaking Station to American Electric Power and the sale of the Greenville Electric Peaking Station to Buckeye Electric Power, Inc.  In both cases, DPL agreed to guarantee the obligations of DPLE over a multiple-year period as follows:

$ in millions	2008		2009		2010
Darby	$	23.0	$	15.3	$	7.7
Greenville	$	11.1	$	7.4	$	3.7

In 2009, neither DPL nor DP&L incurred any losses related to the guarantees of DPLE’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 obligations.

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company.  As of December 31, 2009, DP&L could be responsible for the repayment of 4.9%, or $54.4 million, of a $1,110 million debt obligation that matures in 2026.  This would only happen if OVEC defaulted on its debt payments.  As of December 31, 2009, we have no knowledge of such a default.

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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, 2009, these include:

			Payment Year
$ in millions	Total		2010		2011-2012		2013-2014		Thereafter
DPL
Long-term debt	$	1,324.4	$	100.0	$	297.4	$	470.0	$	457.0
Interest payments	740.0		71.5		115.1		71.4		482.0
Pension and postretirement payments	253.8		23.8		48.9		51.1		130.0
Capital leases	0.6		0.6		—		—		—
Operating leases	0.5		0.3		0.2		—		—
Coal contracts (a)	1,694.3		498.1		577.2		184.4		434.6
Limestone contracts (a)	48.4		5.5		11.4		12.0		19.5
Purchase orders and other contractual obligations	162.6		56.9		84.9		14.6		6.2
Total contractual obligations	$	4,224.6	$	756.7	$	1,135.1	$	803.5	$	1,529.3
DP&L
Long-term debt	$	884.4	$	100.0	$	—	$	470.0	$	314.4
Interest payments	454.8		39.4		78.3		48.2		288.9
Pension and postretirement payments	253.8		23.8		48.9		51.1		130.0
Capital leases	0.6		0.6		—		—		—
Operating leases	0.5		0.3		0.2		—		—
Coal contracts (a)	1,694.3		498.1		577.2		184.4		434.6
Limestone contracts (a)	48.4		5.5		11.4		12.0		19.5
Purchase orders and other contractual obligations	164.8		58.0		86.0		14.6		6.2
Total contractual obligations	$	3,501.6	$	725.7	$	802.0	$	780.3	$	1,193.6

(a)   Total at DP&L-operated units

Long-term debt:

DPL’s Long-term debt as of December 31, 2009, 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, 2009 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 7 of Notes to Consolidated Financial Statements.

Interest payments:

Interest payments 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, 2009.

Pension and postretirement payments:

As of December 31, 2009, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 9 of Notes to Consolidated Financial Statements.  These estimated future benefit payments are projected through 2019.

Capital leases:

As of December 31, 2009, DPL, through its principal subsidiary DP&L, had one immaterial capital lease that expires in September 2010.

Operating leases:

As of December 31, 2009, DPL, through its principal subsidiary DP&L, had several immaterial operating leases with various terms and expiration dates.

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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, 2009, 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 $19.3 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 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 derivative instruments are used principally for economic hedging purposes and none are held for trading purposes.  The majority of our commodity contracts are not considered derivative instruments under GAAP and are therefore excluded from MTM accounting.  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 hedge accounting.  MTM gains and losses on derivative instruments that qualify for hedge accounting are deferred in AOCI until the forecasted transactions occurs.  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.

During 2008 and 2009, the coal market has experienced unprecedented price volatility.  The coal market has increasingly been influenced by both international and domestic supply and consumption and, while we have all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2010 under contract, sales requirements may change, particularly for retail load.  To the extent we are not able to hedge against price volatility or recover increases through our fuel rider that began in January 2010, our results of operations, financial position or cash flows could be materially affected.

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The following table provides a reconciliation of the MTM positions of the commodity derivative contracts included on our balance sheets at December 31, 2009:

$ in millions	2009
Fair Value of Commodity Derivative Contracts:
Outstanding net asset / (liability) at January 1, 2009	$	(6.6	)
Gains / (losses) on settled contracts	(3.2		)
Changes in fair value on contracts still held	11.2
Outstanding net asset / (liability) at December 31, 2009	$	1.4

The impact of the change in the fair values of the commodity derivative contracts between January 1, 2009 and December 31, 2009 is detailed in the table below:

	Year ended
$ in millions	December 31,  2009
Effect on the statements of results of operations:	$	1.8
Effect on the balance sheets:
Accumulated other comprehensive income	$	3.4
Regulatory liability (net)	1.0
Partner payable	1.8
Total net change on balance sheets	$	6.2
Total net change	$	8.0

The net asset/liability of the MTM positions above are expected to mature within the next three years.

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.

Approximately 16% of DPL’s and 19% 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, 2009, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power, 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 wholesale sale would not be affected by the 10% change in wholesale prices):

$ in millions	DPL		DP&L
Effect of 10% change in price per mWh	$	7.9	$	12.0

DPL’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, 2009 and 2008 were 33% and 33%, respectively.  DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs were 33% and 34% for the years ended December 31, 2009 and 2008, respectively.  We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2010 under contract.  The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments.  We do not expect to purchase SO2 allowances for 2010; 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 do not plan to purchase NOx allowances for 2010.  Fuel costs are impacted 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 is allowed to recover its Ohio retail jurisdictional share of fuel and purchased power costs, of approximately 80%, as part of the fuel rider approved by the PUCO. The table below provides the effect on annual net income as of December 31, 2009, of a hypothetical increase or decrease of 10% adjusted for the approximate 80% recovery in the prices of fuel and purchased power:

$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	6.3	$	5.8

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.

The carrying value of DPL’s debt was $1,324.1 million at December 31, 2009, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, DP&L’s revolving credit facilities, DPL’s unsecured notes and DP&L’s capital lease.  The fair value of this debt was $1,317.6 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 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	2010			2011			2012		2013			2014		Thereafter			2009 (a)			2009 (a)
Long-term debt
Variable-rate debt	$	100.0		$	—		$	—	$	—		$	—	$	—		$	100.0		$	100.0
Average interest rate	0.3		%	N/A			N/A		N/A			N/A		N/A			0.3		%
Fixed-rate debt	$	0.6		$	297.4		$	—	$	470.0		$	—	$	456.1		$	1,224.1		$	1,217.6
Average interest rate	1.8		%	6.9		%	N/A		5.1		%	N/A		5.8		%	5.8		%
Total																	$	1,324.1		$	1,317.6

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

The carrying value of DP&L’s debt was $884.3 million at December 31, 2009, consisting of its first mortgage bonds, tax-exempt pollution control bonds, revolving credit facilities and a capital lease.  The fair value of this debt was $844.5 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 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	2010			2011		2012		2013			2014		Thereafter			2009 (a)			2009 (a)
Long-term debt
Variable-rate debt	$	100.0		$	—	$	—	$	—		$	—	$	—		$	100.0		$	100.0
Average interest rate	0.3		%	N/A		N/A		N/A			N/A		N/A			0.3		%
Fixed-rate debt	$	0.6		$	—	$	—	$	470.0		$	—	$	313.7		$	784.3		$	744.5
Average interest rate	1.8		%	N/A		N/A		5.1		%	N/A		4.8		%	5.0		%
Total																$	884.3		$	844.5

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

Debt maturities occurring in 2010 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, 2009 and 2008 for which an immediate adverse market movement causes a potential material impact on our financial position, 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, 2009 and 2008, 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	2009		2009		Risk		2008		2008		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		1,217.6		12.2		1,451.8		1,370.5		13.7
Total	$	1,324.1	$	1,317.6	$	13.2	$	1,551.8	$	1,470.5	$	14.7

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	2009		2009		Risk		2008		2008		Risk
Long-term debt
Variable-rate debt	$	100.0	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0
Fixed-rate debt	784.3		744.5		7.5		784.7		715.7		7.2
Total	$	884.3	$	844.5	$	8.5	$	884.7	$	815.7	$	8.2

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, excluding capital lease obligations, primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL $1,224.1 million of fixed-rate debt and not on DPL’s financial position 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, 2009.

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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 $784.3 million of fixed-rate debt and not on DP&L’s financial position 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 million variable-rate long-term debt outstanding as of December 31, 2009.

Equity Price Risk

As of December 31, 2009, approximately 35.0% of the defined benefit pension plan assets were comprised of investments in equity securities and 65.0% 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 $85.1 million at December 31, 2009.  A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8.5 million reduction in fair value as of December 31, 2009 and approximately a $0.5 million increase to the 2010 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 believed 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.  Long-lived assets to be disposed of or held for sale are reported at the lower of carrying amount or fair value less cost to sell.  We determine the fair value of these assets in the same manner as described for assets held and used.

63

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 whether or not recovery of our Regulatory assets through future rates is probable 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.

64

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 $16.2 million and $17.6 million for 2009 and 2008, 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 $11.3 million and $9.8 million for 2009 and 2008, 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 and long-term rate of return on assets, in determining the obligations, annual cost, and funding requirements of the plans.

For 2010, we are maintaining our long-term rate of return assumptions of 8.50% for pension and 6.00% for other postemployment benefit plan assets representing our long-term assumptions based on our current portfolio mix.  We have decreased our assumed discount rate to 5.75% for pension and 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 2010 pension expense of approximately $2.5 million.  A one percent change in the discount rate for pension would result in an increase or decrease to the 2010 pension expense of approximately $2.0 million.  We do not anticipate any special adjustments to expense in 2010.

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 approximately $0.1 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.

65

LEGAL AND OTHER MATTERS

A discussion of LEGAL AND OTHER MATTERS is described in Note 19 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

This report includes the combined filing of DPL and DP&L.  DP&L is the principal subsidiary of DPL providing approximately 98% of DPL’s total consolidated revenue and approximately 95% 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.

66

DPL INC.

CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	For the years ended December 31,
$ in millions except per share amounts	2009			2008			2007
Revenues	$	1,588.9		$	1,601.6		$	1,515.7
Cost of revenues:
Fuel	330.4			243.0			328.2
Purchased power	260.2			377.4			287.2
Total cost of revenues	590.6			620.4			615.4
Gross margin	998.3			981.2			900.3
Operating expenses:
Operation and maintenance	306.5			282.5			283.6
Depreciation and amortization	145.5			137.7			134.8
General taxes	118.1			125.5			111.8
Total operating expenses	570.1			545.7			530.2
Operating income	428.2			435.5			370.1
Other income / (expense), net
Investment income (loss)	(0.6		)	3.6			11.3
Net gain on settlement of executive litigation	—			—			31.0
Interest expense	(83.0		)	(90.7		)	(81.0		)
Other income (deductions)	(3.0		)	(1.0		)	2.9
Total other income / (expense), net	(86.6		)	(88.1		)	(35.8		)
Earnings from continuing operations before income tax	341.6			347.4			334.3
Income tax expense	112.5			102.9			122.5
Earnings from continuing operations	229.1			244.5			211.8
Earnings from discontinued operations, net of tax	—			—			10.0
Net income	$	229.1		$	244.5		$	221.8
Average number of common shares outstanding (millions)
Basic	112.9			110.2			107.9
Diluted	114.2			115.4			117.8
Earnings per share of common stock
Basic:
Earnings from continuing operations	$	2.03		$	2.22		$	1.97
Earnings from discontinued operations, net of tax	—			—			0.09
Total Basic	$	2.03		$	2.22		$	2.06
Diluted:
Earnings from continuing operations	$	2.01		$	2.12		$	1.80
Earnings from discontinued operations, net of tax	—			—			0.08
Total Diluted	$	2.01		$	2.12		$	1.88

See Notes to Consolidated Financial Statements.

67

DPL INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the years ended December 31,
$ in millions		2009			2008			2007
Cash flows from operating activities:
Net income		$	229.1		$	244.5		$	221.8
Less: Earnings from discontinued operations, net of tax		—			—			(10.0		)
Earnings from continuing operations		229.1			244.5			211.8
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization		145.5			137.7			134.8
Deferred income taxes		201.6			43.1			3.1
Net gain on settlement of executive litigation		—			—			(31.0		)
Net gain on sale of property		—			—			(6.0		)
Changes in certain assets and liabilities:
Accounts receivable	��	39.3			(18.7		)	(18.9		)
Inventories		(20.6		)	(0.2		)	(19.6		)
Taxes applicable to subsequent years		(1.5		)	(10.0		)	(0.1		)
Deferred regulatory costs, net		(24.6		)	(12.9		)	9.4
Accounts payable		(65.0		)	27.0			(0.5		)
Accrued taxes payable		(2.4		)	(46.1		)	19.9
Accrued interest payable		(1.5		)	(0.8		)	(9.4		)
Pension, retiree and other benefits		15.2			31.2			26.7
Unamortized investment tax credit		(2.8		)	(2.8		)	(2.8		)
Insurance and claims costs		(1.4		)	(2.4		)	(1.9		)
Other		15.2			(26.4		)	2.6
Net cash provided by operating activities		526.1			363.2			318.1
Cash flows from investing activities:
Capital expenditures		(172.3		)	(243.6		)	(346.2		)
Net proceeds from sale of property - peakers		—			—			151.0
Proceeds from sale of property - aircraft		—			—			7.4
Proceeds from sale of property - other		1.2			—			—
Purchases of short-term investments and securities		—			(4.9		)	—
Sales of short-term investments and securities		5.0			—			—
Net cash used for investing activities		(166.1		)	(248.5		)	(187.8		)
Cash flows from financing activities:
Dividends paid on common stock		(128.8		)	(120.5		)	(111.7		)
Repurchase of DPL common stock		(64.4		)	—			—
Repurchase of warrants		(25.2		)	—			—
Proceeds from exercise of warrants		77.7			—			—
Retirement of long-term debt		(175.0		)	(100.0		)	(225.0		)
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			90.0
Retirement of pollution control bonds		—			(90.0		)	—
Pollution control bond proceeds held in trust		—			(10.0		)	(90.0		)
Withdrawal of restricted funds held in trust, net		14.5			32.5			63.2
Withdrawals from revolving credit facilities		260.0			115.0			95.0
Repayment of borrowings from revolving credit facilities		(260.0		)	(115.0		)	(95.0		)
Exercise of stock options		9.0			2.2			14.6
Tax impact related to exercise of stock options		0.7			0.3			1.3
Net cash used for financing activities		(347.6		)	(187.1		)	(257.6		)
Cash and cash equivalents:
Net change		12.4			(72.4		)	(127.3		)
Balance at beginning of period		62.5			134.9			262.2
Cash and cash equivalents at end of period		$	74.9		$	62.5		$	134.9
Supplemental cash flow information:
Interest paid, net of amounts capitalized		$	84.3		$	86.8		$	87.8
Income taxes (refunded) / paid, net		$	(94.6	)	$	127.3		$	115.6
Non-cash financing and investing activities:
Accruals for capital expenditures		$	20.8		$	34.1		$	45.6

See Notes to Consolidated Financial Statements.

68

DPL INC.

CONSOLIDATED BALANCE SHEETS

	At December 31,
$ in millions	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	74.9		$	62.5
Restricted funds held in trust	—			14.5
Accounts receivable, net (Note 2)	212.8			259.9
Inventories (Note 2)	125.7			105.1
Taxes applicable to subsequent years	59.5			58.0
Other prepayments and current assets	24.1			26.7
Total current assets	497.0			526.7
Property, plant and equipment:
Property, plant and equipment	5,269.2			5,073.4
Less: Accumulated depreciation and amortization	(2,466.0		)	(2,350.6		)
	2,803.2			2,722.8
Construction work in process	89.0			153.6
Total net property, plant and equipment	2,892.2			2,876.4
Other noncurrent assets:
Regulatory assets (Note 3)	214.2			195.6
Other deferred assets	38.3			38.3
Total other noncurrent assets	252.5			233.9
Total Assets	$	3,641.7		$	3,637.0

See Notes to Consolidated Financial Statements.

69

DPL INC.

CONSOLIDATED BALANCE SHEETS

			At December 31,
$ in millions			2009			2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion - long-term debt			$	100.6		$	175.7
Accounts payable			77.2			178.3
Accrued taxes			70.2			72.9
Accrued interest			23.5			25.0
Customer security deposits			19.4			19.8
Other current liabilities			24.0			14.7
Total current liabilities			314.9			486.4
Noncurrent liabilities:
Long-term debt			1,223.5			1,376.1
Deferred taxes			569.1			374.1
Regulatory liabilities (Note 3)			125.4			121.9
Pension, retiree and other benefits			111.7			94.7
Unamortized investment tax credit			35.2			38.0
Insurance and claims costs			16.2			17.6
Other deferred credits			122.9			108.2
Total noncurrent liabilities			2,204.0			2,130.6
Redeemable preferred stock of subsidiary			22.9			22.9
Commitments and contingencies (Note 19)
Common shareholders’ equity:
Common stock, at par value of $0.01 per share:
	December 2009	December 2008
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	118,966,767	115,961,880	1.2			1.2
Warrants			2.9			31.0
Common stock held by employee plans			(19.3		)	(27.6		)
Accumulated other comprehensive loss			(29.0		)	(23.1		)
Retained earnings			1,144.1			1,015.6
Total common shareholders’ equity			1,099.9			997.1
Total Liabilities and Shareholders’ Equity			$	3,641.7		$	3,637.0

See Notes to Consolidated Financial Statements.

70

DPL INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

								Common
								Stock			Accumulated
	Common Stock (a)							Held by			Other
	Outstanding							Employee			Comprehensive			Retained
in millions (except Outstanding Shares)	Shares		Amount		Warrants			Plans			Income / (Loss)			Earnings			Total
Beginning balance	113,018,972		$	1.1	$	50.0		$	(69.0	)	$	4.8		$	736.5		$	723.4
2007:
Net income														221.8
Change in unrealized gains (losses) on financial instruments, net of tax											(0.9		)
Change in deferred gains (losses) on cash flow hedges, net of tax											(5.5		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax											2.2
Total comprehensive income																	217.6
Common stock dividends (a)														(111.7		)	(111.7		)
Treasury stock reissued	539,472													16.0			16.0
Tax effects to equity														1.3			1.3
Employee / Director stock plans								29.2						6.5			35.7
Other								0.1						0.1			0.2
Ending 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

(a)   Common stock dividends per share were $1.04 in 2007, $1.10 in 2008 and $1.14 in 2009.

See Notes to Consolidated Financial Statements.

71

THE DAYTON POWER AND LIGHT COMPANY

STATEMENTS OF RESULTS OF OPERATIONS

	For the years ended December 31,
$ in millions	2009			2008			2007
Revenues	$	1,550.4		$	1,572.9		$	1,507.4
Cost of revenues:
Fuel	323.6			231.4			315.4
Purchased power	259.2			379.9			300.3
Total cost of revenues	582.8			611.3			615.7
Gross margin	967.6			961.6			891.7
Operating expenses:
Operation and maintenance	293.4			273.0			281.8
Depreciation and amortization	135.5			127.8			124.5
General taxes	116.8			124.2			110.3
Total operating expenses	545.7			525.0			516.6
Operating income	421.9			436.6			375.1
Other income / (expense), net:
Investment income	2.8			7.0			23.7
Net gain on settlement of executive litigation	—			—			35.3
Interest expense	(38.5		)	(36.5		)	(22.3		)
Other income (deductions)	(2.8		)	(1.1		)	2.9
Total other income / (expense), net	(38.5		)	(30.6		)	39.6
Earnings before income tax	383.4			406.0			414.7
Income tax expense	124.5			120.2			143.1
Net income	258.9			285.8			271.6
Dividends on preferred stock	0.9			0.9			0.9
Earnings on common stock	$	258.0		$	284.9		$	270.7

See Notes to Consolidated Financial Statements.

72

THE DAYTON POWER AND LIGHT COMPANY

STATEMENTS OF CASH FLOWS

	For the years ended December 31,
$ in millions	2009			2008			2007
Cash flows from operating activities:
Net income	$	258.9		$	285.8		$	271.6
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	135.5			127.8			124.5
Deferred income taxes	200.1			40.9			(0.2		)
Gain on transfer of assets to pension plan	—			—			(14.8		)
Net gain on settlement of executive litigation	—			—			(35.3		)
Changes in certain assets and liabilities:
Accounts receivable	25.7			(3.5		)	(19.0		)
Inventories	(20.5		)	(0.2		)	(20.6		)
Taxes applicable to subsequent years	(1.3		)	(9.9		)	(0.1		)
Deferred regulatory costs, net	(24.6		)	(12.9		)	9.4
Accounts payable	(65.9		)	26.9			1.9
Accrued taxes payable	(0.9		)	(50.0		)	18.4
Accrued interest payable	0.2			—			0.3
Pension, retiree and other benefits	15.2			31.3			26.6
Unamortized investment tax credit	(2.8		)	(2.8		)	(2.8		)
Other	(4.5		)	(38.8		)	(6.9		)
Net cash provided by operating activities	515.1			394.6			353.0
Cash flows from investing activities:
Capital expenditures	(167.4		)	(242.0		)	(343.2		)
Net cash used for investing activities	(167.4		)	(242.0		)	(343.2		)
Cash flows from financing activities:
Dividends paid on common stock to parent	(325.0		)	(155.0		)	(125.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)	(0.9		)
Issuance of pollution control bonds, net	—			98.4			90.0
Retirement of pollution control bonds	—			(90.0		)	—
Pollution control bond proceeds held in trust	—			(10.0		)	(90.0		)
Withdrawal of restricted funds held in trust, net	14.5			32.5			63.2
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		)	(85.0		)
Issuance of short-term debt to parent	—			—			105.0
Net cash used for financing activities	(311.4		)	(145.0		)	(42.7		)
Cash and cash equivalents:
Net change	36.3			7.6			(32.9		)
Balance at beginning of period	20.8			13.2			46.1
Cash and cash equivalents at end of period	$	57.1		$	20.8		$	13.2
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	39.5		$	33.4		$	18.5
Income taxes (refunded) / paid, net	$	(94.7	)	$	127.0		$	114.7
Non-cash financing and investing activities:
Accruals for capital expenditures	$	20.8		$	34.1		$	45.6

See Notes to Consolidated Financial Statements.

73

THE DAYTON POWER AND LIGHT COMPANY

BALANCE SHEETS

	At December 31,
$ in millions	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	57.1		$	20.8
Restricted funds held in trust	—			14.5
Accounts receivable, net (Note 2)	192.0			225.4
Inventories (Note 2)	124.3			103.8
Taxes applicable to subsequent years	59.2			57.9
Other prepayments and current assets	26.0			23.9
Total current assets	458.6			446.3
Property, plant and equipment:
Property, plant and equipment	5,011.0			4,817.9
Less: Accumulated depreciation and amortization	(2,370.7		)	(2,265.5		)
	2,640.3			2,552.4
Construction work in process	87.9			153.0
Total net property, plant and equipment	2,728.2			2,705.4
Other noncurrent assets:
Regulatory assets (Note 3)	214.2			195.6
Other assets	56.4			50.4
Total other noncurrent assets	270.6			246.0
Total Assets	$	3,457.4		$	3,397.7

See Notes to Consolidated Financial Statements.

74

THE DAYTON POWER AND LIGHT COMPANY

BALANCE SHEETS

	At December 31,
$ in millions	2009			2008
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities:
Current portion - long-term debt	$	100.6		$	0.7
Accounts payable	75.1			176.6
Accrued taxes	68.6			70.5
Accrued interest	13.1			12.9
Customers security deposits	19.4			19.8
Other current liabilities	23.2			14.2
Total current liabilities	300.0			294.7
Noncurrent liabilities:
Long-term debt	783.7			884.0
Deferred taxes	553.0			358.3
Regulatory liabilities (Note 3)	125.4			121.9
Pension, retiree and other benefits	111.7			94.7
Unamortized investment tax credit	35.2			38.0
Other deferred credits	122.9			108.3
Total noncurrent liabilities	1,731.9			1,605.2
Redeemable preferred stock	22.9			22.9
Commitments and contingencies (Note 19)
Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	781.6			783.1
Accumulated other comprehensive loss	(19.7		)	(16.1		)
Retained earnings	640.3			707.5
Total common shareholder’s equity	1,402.6			1,474.9
Total Liabilities and Shareholder’s Equity	$	3,457.4		$	3,397.7

See Notes to Consolidated Financial Statements.

75

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	$	783.7		$	28.1		$	432.0		$	1,244.2
2007:
Net income										271.6
Change in unrealized gains (losses) on financial instruments, net of tax							(7.7		)
Change in deferred gains (losses) on cash flow hedges, net of tax							(5.5		)
Change in unrealized gains (losses) on pension and postretirement benefits, net of tax							2.2
Total comprehensive income													260.6
Common stock dividends										(125.0		)	(125.0		)
Preferred stock dividends										(0.9		)	(0.9		)
Tax effects to equity				1.3									1.3
Employee / Director stock plans				(0.3		)							(0.3		)
Other				0.1			—			(0.1		)	—
Ending 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

(a)  50,000,000 shares authorized.

See Notes to Consolidated Financial Statements.

76

Notes to Consolidated Financial Statements

This report includes the combined filing of DPL and DP&L.  DP&L is the principal subsidiary of DPL providing approximately 98% of DPL’s total consolidated revenue and approximately 95% 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.

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.  DPL’s principal subsidiary is DP&L.  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 engages in the operation of peaking generating facilities; DPLER, which is a CRES provider selling retail electric energy and other energy services; 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.

DPL and DP&L conduct their principal business in one business segment — Electric.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is not subject to such regulation.  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.

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.  DPL Capital Trust II is not consolidated, consistent with the provisions of GAAP relating to variable interest entities.

DP&L has an undivided ownership interest 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.

All material intercompany accounts and transactions are eliminated in consolidation.

We have evaluated all subsequent events through February 11, 2010 which is the date these financial statements were filed with the SEC.

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 revenue and expenses of the periods reported.  Actual results could differ from those 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.

77

Revisions

During the preparation of our annual report on Form 10-K for the year ended December 31, 2009, we identified certain immaterial items that had not been correctly presented in our prior period balance sheets.  Accordingly, we have made the following adjustments to our prior period balance sheets to conform to the current period presentation. These adjustments did not have any impact on our gross margin, operating income, net income, earnings per share or cash flows as previously reported.

Property Taxes

Certain accrued taxes representing property tax liabilities had been previously classified as a current liability and should have been classified as a noncurrent liability.  As a result of this reclassification, accrued taxes decreased at DPL by $57.5 million from $130.4 million to $72.9 million and also by the same $57.5 million at DP&L from $128.0 million to $70.5 million as of December 31, 2008.  This same reclassification also increased other deferred credits at DPL by $57.5 million from $50.7 million to $108.2 million and at DP&L by $57.5 million from $50.8 million to $108.3 million as of December 31, 2008.

Deferred Taxes

Certain deferred taxes that related to amounts recorded in accumulated other comprehensive income/(loss) for pension-related costs had been previously classified within deferred taxes and should have been classified within accumulated other comprehensive income/(loss).  In addition, certain deferred taxes that related to amounts recoverable from customers in future rates had also been incorrectly presented.  As a result of these two deferred tax items, deferred taxes decreased at DPL by $59.6 million from $433.7 million to $374.1 million and at DP&L by $59.5 million from $417.8 million to $358.3 million as of December 31, 2008.  These same reclassifications also decreased accumulated other comprehensive loss at DPL by $21.5 million from $44.6 million to $23.1 million and at DP&L by $21.4 million from $37.5 million to $16.1 million and decreased regulatory assets at both DPL and DP&L by $38.1 million from $233.7 million to $195.6 million as of December 31, 2008.  These reclassifications also resulted in an increase in accumulated other comprehensive income at DPL by $9.8 million from a loss of $9.2 million to income of $0.6 million and at DP&L by $10.6 million from $6.5 million to $17.1 million as of December 31, 2007 and an increase in accumulated other comprehensive income at DPL by $11.3 million from a loss of $6.5 million to income of $4.8 million and at DP&L by $13.0 million from $15.1 million to $28.1 million as of December 31, 2006.

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.  The determination of energy sales to customers is based on the reading of their meters and this 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, projected 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, as well as certain derivative contracts that do not qualify for hedge accounting, causing gains or losses to be 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.

78

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 2009, 2008 and 2007 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 $2.4 million in 2009, $8.9 million in 2008 and $21.8 million in 2007.

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.

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

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 FERC-defined units of property.

Depreciation

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 on an average annual composite basis using group rates that approximated 2.7% in 2009, 2.7% in 2008 and 2.9% in 2007.  In July 2007, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances during 2007.  The results of the depreciation study concluded that DPL’s depreciation rates should be reduced due to projected asset lives beyond previously estimated useful lives.  DPL adjusted the depreciation rates for its non-regulated generation property, effective August 1, 2007.  For the period from August 1, 2007 to December 31, 2007, the reduction in depreciation expense increased income from continuing operations by approximately $9.5 million, increased net income by approximately $6.0 million, and increased basic EPS by approximately $0.06 per share.

The following is a summary of DPL’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2009 and 2008:

DPL

			Composite				Composite
$ in millions	2009		Rate		2008		Rate
Regulated:
Transmission	$	355.3	2.4	%	$	350.2	2.4	%
Distribution	1,206.7		3.7	%	1,146.1		3.7	%
General	76.8		3.1	%	66.7		7.2	%
Non-depreciable	57.8		N/A		56.9		N/A
Total regulated	$	1,696.6			$	1,619.9
Unregulated:
Production / Generation	$	3,519.2	2.5	%	$	3,403.0	2.4	%
Other	35.0		3.7	%	31.8		3.5	%
Non-depreciable	18.4		N/A		18.7		N/A
Total unregulated	$	3,572.6			$	3,453.5
Total property, plant and equipment in service	$	5,269.2	2.7	%	$	5,073.4	2.7	%

79

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 2.7% in 2009, 2.6% in 2008 and 2.8% in 2007.

The following is a summary of DP&L’s Property, plant and equipment with corresponding composite depreciation rates at December 31, 2009 and 2008:

DP&L

			Composite				Composite
$ in millions	2009		Rate		2008		Rate
Regulated:
Transmission	$	355.3	2.4	%	$	350.2	2.4	%
Distribution	1,206.7		3.7	%	1,146.2		3.7	%
General	76.8		3.1	%	66.7		7.2	%
Non-depreciable	57.8		N/A		56.9		N/A
Total regulated	$	1,696.6			$	1,620.0
Unregulated:
Production	$	3,299.1	2.4	%	$	3,182.6	2.3	%
Non-depreciable	15.3		N/A		15.3		N/A
Total unregulated	$	3,314.4			$	3,197.9
Total property, plant and equipment in service	$	5,011.0	2.7	%	$	4,817.9	2.6	%

AROs

We recognize AROs in accordance with GAAP.  GAAP 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	2009			2008
Balance at January 1	$	13.2		$	12.5
Accretion expense	0.8			0.7
Additions	2.1			—
Settlements	(0.5		)	(1.0		)
Estimated cash flow revisions	0.6			1.0
Balance at December 31	$	16.2		$	13.2

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 $99.1 million and $96.0 million in estimated costs of removal at December 31, 2009 and 2008, 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	2009			2008
Balance at January 1	$	96.0		$	91.5
Additions	6.5			8.3
Settlements	(3.4		)	(3.8		)
Balance at December 31	$	99.1		$	96.0

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, 2009, 2008 and 2007, we recognized gains from the sale of emission allowances in the amounts of $5.0 million, $34.8 million and $1.2 million, respectively.  Beginning in January 2010, most of the gains on emission allowances will be used to reduce the overall fuel rider charged to the Ohio retail jurisdiction.

At December 31, 2009, we had substantially placed into service FGD equipment at most of our DP&L and partner-operated facilities.

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, have been deferred for financial reporting purposes.  These deferred investment tax credits are amortized over the useful lives of the property to which they are related.  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 8 of Notes to Consolidated Financial Statements.

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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	2009		2008		2007
State/Local excise taxes	$	49.5	$	52.3	$	53.2

Stock-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair-value of such equity 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 12 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 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.

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 and options 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 required to meet full load requirements during times of peak demand or during planned and unplanned generation facility outages.  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 is deemed to be effective and MTM accounting when the hedge is not effective.  See Note 11 of Notes to Consolidated Financial Statements.

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 $16.2 million and $17.6 million for 2009 and 2008, 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 $11.3 million and $9.8 million for 2009 and 2008, 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.

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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, which holds mandatorily redeemable trust capital securities, is reported as two components on DPL’s consolidated balance sheet.  The investment in the Trust, which amounts to $3.8 million and $5.5 million at December 31, 2009 and 2008, 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 and $195.0 million at December 31, 2009 and 2008, respectively, that was established upon the Trust’s deconsolidation in 2003.  See Note 7 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.

Pension and Postretirement Benefits

We recognize the funded status of our benefit plan; recognize as a component of other comprehensive income (OCI), net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost; measure defined benefit plan assets and obligations as of the date of our fiscal year-end; and disclose in Notes to Consolidated Financial Statements additional information about certain effects on net periodic benefit costs for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.  See Note 9 of Notes to Consolidated Financial Statements.

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 these transactions:

$ in millions	2009			2008			2007
DP&L Revenues:
Sales to DPLER (a)	$	64.8		$	150.6		$	151.5
DP&L Operation & Maintenance Expenses:
Insurance services provided by MVIC (b)	$	(3.4	)	$	(3.5	)	$	(4.9	)

(a)DP&L sells power to DPLER to satisfy the electric requirements of its retail customers.  The revenues associated with sales to DPLER are recorded as wholesale sales in DP&L’s Financial Statements.

(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.

Recently Adopted Accounting Standards

FASB Codification

We adopted FASC 105, “Generally Accepted Accounting Principles” (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162”), on September 30, 2009.  The objective of this Statement is to replace Statement No. 162 and to establish the FASC as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP.  Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants.  This update did not have a material impact on our overall results of operations, financial position or cash flows.

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Disclosures about Derivative Instruments and Hedging Activities

We adopted an update to FASC 815, “Derivatives and Hedging” (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment to FASB Statement No. 133”), on January 1, 2009.  This update requires an entity to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under FASC 815 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  This update did not have a material impact on our overall results of operations, financial position or cash flows.  See Note 11 of Notes to Consolidated Financial Statements.

Participating Securities and EPS

We adopted an update to FASC 260, “Earnings per Share” (formerly Staff Position EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”) on January 1, 2009.  This update clarifies that unvested share-based awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and must be included in the computation of EPS pursuant to the two-class method.  This update did not have a material impact on our overall results of operations, financial position or cash flows.

Meaning of “Indexed to a Company’s Own Stock”

We adopted an update to FASC 815, “Derivatives and Hedging” (formerly EITF Issue No. 07-5, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock”), on January 1, 2009.  This update gives guidance on when a financial instrument is considered to be indexed to a company’s own stock to meet the criteria for FASC 815-10-15-74(a) (formerly paragraph 11(a) of FASB Statement No. 133, “Accounting for Derivative Financial Instruments.”)  This update did not have a material impact on our overall results of operations, financial position or cash flows.

Interim Disclosures about Fair Value of Financial Instruments

We adopted an update of FASC 825, “Financial Instruments” (formerly Staff Position SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”), on June 30, 2009.  This update requires disclosure about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  This update did not have a material impact on our overall results of operations, financial position or cash flows.  See Note 10 of Notes to Consolidated Financial Statements.

Subsequent Events

We adopted FASC 855, “Subsequent Events” (formerly SFAS 165), on June 30, 2009.  FASC 855 incorporates the guidance in the American Institute of Certified Public Accountants’ Auditing Standard 560 — Subsequent Events, into the accounting guidance.  This new standard does not change current accounting practices.  FASC 855 did not have a material impact on our overall results of operations, financial position or cash flows.

Disclosures about Pensions and Other Postretirement Benefits

We adopted an update to FASC 715, “Compensation — Retirement Plans” (formerly Staff Position SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”), on December 31, 2009.  This update requires disclosures about benefit plan assets similar to the disclosure required in FASC 820, “Fair Value Measurements and Disclosures.”  It also requires discussions on investment allocation decisions, major categories of plan assets and significant concentrations of risk in plan assets for the period.  This update did not have a material impact on our overall results of operations, financial position or cash flows.  See Note 9 of Notes to Consolidated Financial Statements.

Redeemable Equity Instruments

We adopted ASU 2009-04, “Accounting for Redeemable Equity Instruments, an amendment to Section 480-10-S99,” (ASU 2009-04) on October 1, 2009.  ASU 2009-04 clarifies that SEC Accounting Series Release 268 pertains to preferred stocks and other redeemable securities including common stock, derivative instruments, non-controlling interest, securities held by an ESOP and share-based payment arrangements with employees.  This update did not have a material impact on our overall results of operations, financial position or cash flows.

Measuring Liabilities at Fair Value

We adopted ASU 2009-05, “Measuring Liabilities at Fair Value,” (ASU 2009-05) on October 1, 2009.  ASU 2009-05 provides additional guidance clarifying the measurement of liabilities at fair value.  This update did not have a material impact on our overall results of operations, financial position or cash flows.

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Investments in Certain Entities that Calculate Net Asset Value per Share

We adopted ASU 2009-12, “Fair Value Measurements and Disclosures,” (ASU 2009-12) on December 31, 2009.  ASU 2009-12 updates FASC 820-10, “Fair Value Measurements and Disclosures — Overall” and allows, as a practical expedient, a reporting entity to measure the fair value of an investment that is within the scope of these amendments on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a manner consistent with the measurement principles of FASC 946, “Financial Services — Investment Companies.”  This update did not have a material impact on our overall results of operations, financial position or cash flows.

Recently Issued Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued 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) that is effective for annual reporting periods beginning after November 15, 2009.  We expect to adopt this ASU in the first quarter of 2010.  This standard updates FASC 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.  We do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

Fair Value Disclosures

In January 2010, the FASB issued ASU 2010-06 “Fair Value Measurements and Disclosures” (ASU 2010-06) effective for annual reporting periods beginning after December 15, 2009.  We expect to adopt this ASU on January 1, 2010.  This standard updates FASC 820, “Fair Value Measurements.”  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 should be presented separately.  We do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

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2.  Supplemental Financial Information

DPL Inc.

	At			At
	December 31,			December 31,
$ in millions	2009			2008
Accounts receivable, net:
Unbilled revenue	$	74.9		$	82.5
Customer receivables	99.4			107.5
Amounts due from partners in jointly-owned plants	12.6			28.0
Coal sales	10.6			25.6
Other	16.4			17.4
Provision for uncollectible accounts	(1.1		)	(1.1		)
Total accounts receivable, net	$	212.8		$	259.9
Inventories, at average cost:
Fuel, limestone and emission allowances	$	85.8		$	68.7
Plant materials and supplies	38.5			36.3
Other	1.4			0.1
Total inventories, at average cost	$	125.7		$	105.1

DP&L

	At			At
	December 31,			December 31,
$ in millions	2009			2008
Accounts receivable, net:
Unbilled revenue	$	71.0		$	74.7
Customer receivables	94.4			96.7
Amounts due from partners in jointly-owned plants	12.6			28.0
Coal sales	10.6			25.6
Other	4.5			1.5
Provision for uncollectible accounts	(1.1		)	(1.1		)
Total accounts receivable, net	$	192.0		$	225.4
Inventories, at average cost:
Fuel, limestone and emission allowances	$	85.8		$	68.7
Plant materials and supplies	37.1			35.0
Other	1.4			0.1
Total inventories, at average cost	$	124.3		$	103.8

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3.  Regulatory Matters

In accordance with GAAP, regulatory assets and liabilities are recorded in the 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 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 balance sheets include:

			At		At
	Type of	Amortization	December 31,		December 31,
$ in millions	Recovery (a)	Through	2009		2008
Regulatory Assets:
Deferred recoverable income taxes	C/B	Ongoing	$	36.8	$	43.1
Pension benefits	C	Ongoing	85.2		83.3
Unamortized loss on reacquired debt	C	Ongoing	15.6		17.2
Electric Choice systems costs	F	2011	4.0		7.1
Regional transmission organization costs	D	2014	7.0		8.5
TCRR, transmission, ancillary and other PJM-related costs	F	2011	5.5		—
RPM capacity costs	F	2011	20.0		—
Deferred storm costs - 2008	D		16.0		13.1
Power plant emission fees	C	Ongoing	6.3		6.3
CCEM smart grid and advanced metering infrastructure costs	D		6.5		6.4
CCEM energy efficiency program costs	F	Ongoing	3.6		1.9
Other costs			7.7		8.7
Total regulatory assets			$	214.2	$	195.6
Regulatory Liabilities:
Estimated costs of removal - regulated property			$	99.1	$	96.0
SECA net revenue subject to refund			20.1		20.1
Postretirement benefits			5.1		5.8
Other costs			1.1		—
Total regulatory liabilities			$	125.4	$	121.9

(a)F – Recovery of incurred costs plus rate of return.

C – Recovery of incurred costs only.

B – Balance has an offsetting liability resulting in no impact on rate base.

D – Recovery not yet determined, but is probable of occurring in future rate proceedings.

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 are amortized.

Pension benefits represent the qualifying FASC 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 life of the original issues in accordance with FERC 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 a 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 beginning 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 able to make true-up adjustments on an annual basis.

On February 19, 2009, the PUCO approved DP&L’s request to defer transmission, capacity, ancillary and other costs incurred since July 31, 2008 consistent with the provisions of SB 221.  In May 2009, the PUCO granted DP&L authority to recover these costs through retail rates beginning June 1, 2009.  Subsequently, an application for rehearing was filed claiming the PUCO’s order allowing for recovery of RPM capacity costs through a TCRR was unlawful.  The PUCO issued an order granting rehearing and, on September 9, 2009, issued an order directing DP&L to remove the deferred and current RPM capacity costs from the TCRR rider but also indicating that these RPM capacity costs may be recoverable under a separate rider.  DP&L made a compliance filing on September 23, 2009, where it removed such costs from the TCRR rider and proposed a new RTO RPM rider for the recovery of such costs.  The PUCO approved the two separate riders in November 2009.  The sum of the rate collected through the current TCRR rider and the new RTO RPM rider equals the rate collected through the original TCRR rider.  Accordingly, during the period ended December 31, 2009, DP&L deferred total net RTO costs in the amount of $23.5 million.  In addition, DP&L also deferred $1.1 million relating to Regional Transmission Expansion Plan (RTEP) costs and $0.9 million relating to interest and operation and maintenance expenses.  Of the total deferred costs amounting to $25.5 million, $9.8 million relates to the period August 1, 2008 through December 31, 2008, and $15.7 million relates to the year ended December 31, 2009.  The deferral of these costs resulted in a favorable impact to our results of operations.

RPM capacity costs represent the PJM-related costs from the calculations of the PJM Reliability Pricing Model that allocates capacity among the users of the PJM System.  As discussed above, DP&L is recovering these costs through a PUCO-approved RTO RPM rider.  The sum of the rate collected through the current TCRR rider and the new RTO RPM rider equals the rate collected through the original TCRR rider.  We review this rate and are able to make true-up adjustments to it 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 for environmental monitoring.  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 advanced metering infrastructure costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of advanced metering infrastructure.  Consistent with the Stipulation, DP&L re-filed its smart grid and advanced metering infrastructure 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 August 5, 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding under the Integrated and/or Crosscutting Systems topic area for the Smart Grid Investment Grant Program.  On October 27, 2009, we were notified by the United States Department of Energy (DOE) that we will not receive funding under the ARRA.  A technical conference in this case was held at the PUCO in October 2009 for the smart grid case, and a subsequent PUCO entry established a comment and reply comment period.  A hearing is not yet scheduled for this case.  Based on past PUCO precedent and the Ohio legislature’s intent behind SB221, we believe these costs are probable of future recovery in rates.

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CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency.  A portion of these costs is being recovered over three years as part of the Stipulation beginning July 1, 2009; the remaining costs are subject to a two-year true-up process 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.

Regulatory Liabilities

Estimated costs of removal — regulated property reflect an estimate of amounts collected in customer rates that are expected to be incurred to remove existing transmission and distribution property from service upon retirement.

SECA net revenue subject to refund represents our deferral of amounts collected in customer rates during 2005 and 2006.  SECA revenue and expenses represent FERC-ordered transitional payments for the use of transmission lines within PJM.  A hearing was held in early 2006 to determine if these transitional payments are subject to refund, however, no ruling has been issued.  We began receiving and paying these transitional payments in May 2005.

Postretirement benefits represent the qualifying FASC 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.

Other costs primarily include derivative activity related to fuel costs that will be settled over various periods.

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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, 2009, we had $42 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, 2009, is as follows.

			DP&L Investment
									SCR and FGD
									Equipment
	DP&L Share						Construction		Installed
		Production	Gross Plant		Accumulated		Work in		and In
	Ownership	Capacity	In Service		Depreciation		Process		Service
	(%)	(MW)	($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:		��
Beckjord Unit 6	50.0	210	$	78	$	56	$	—	No
Conesville Unit 4	16.5	129	124		29		3		Yes
East Bend Station	31.0	186	200		129		—		Yes
Killen Station	67.0	402	605		276		2		Yes
Miami Fort Units 7 and 8	36.0	368	345		123		9		Yes
Stuart Station	35.0	820	683		248		21		Yes
Zimmer Station	28.1	365	1,056		597		7		Yes
Transmission (at varying percentages)			91		54		—
Total		2,480	$	3,182	$	1,512	$	42
Wholly-owned production unit:
Hutchings Station	100.0	388	$	122	$	108	$	1	No

DP&L’s share of operating costs associated with the jointly-owned generating facilities are included within the corresponding line in the statements of results of operations.

5.  Assets Sales

Peaker Sales

During 2006, in connection with DPLE’s (a wholly-owned subsidiary of DPL) decision to sell the Greenville Station and Darby Station electric peaking generation facilities, DPL concluded that the related assets were impaired.  Greenville Station consisted of four natural gas peaking units with a net book value of approximately $66 million. Darby Station consisted of six natural gas peaking units with a net book value of approximately $156 million.  During the fourth quarter of 2006, DPL recorded a $71.0 million impairment charge to write-down the assets to their fair value.  The Greenville Station and Darby Station assets were sold by DPLE in April 2007 for $49.2 million and $102.0 million, respectively, in two separate transactions.

Aircraft Sale

On June 7, 2007, Miami Valley CTC, Inc. (an indirect, wholly-owned subsidiary of DPL), sold its corporate aircraft and associated inventory and parts for $7.4 million.  The net book value of the assets sold was approximately $1.0 million, and severance and other costs of approximately $0.4 million were accrued.  Miami Valley CTC, Inc. recorded a net gain on the sale of approximately $6.0 million during the second quarter ending June 30, 2007, which was included in DPL’s Operation and maintenance expense.

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6.  Discontinued Operations

On February 13, 2005, DPL’s subsidiaries, MVE, Inc. (MVE) and MVIC, entered into an agreement to sell their respective interests in forty-six private equity funds to AlpInvest/Lexington 2005, LLC, a joint venture of AlpInvest Partners and Lexington Partners, Inc.  During 2005, MVE and MVIC completed the sale of their interests in forty-three funds and a portion of another of those private equity funds.  During 2005, MVE entered into alternative closing arrangements with AlpInvest/Lexington 2005, LLC for funds where legal title to said funds could not be transferred until a later time.  Pursuant to these arrangements, MVE transferred the economic aspects of the remaining private equity funds, consisting of two funds and a portion of one fund, to AlpInvest/Lexington 2005, LLC without a change in ownership of the interests.  The ownership interest in these funds was transferred in 2006 and 2007, at which time DPL recognized previously deferred gains.  DPL recognized $18.9 million ($12.1 million after tax) of these previously deferred gains in 2006 and the remaining balance of these gains in the amount of $7.9 million, net of associated expenses ($4.9 million after tax), were recognized in 2007.  This transaction was recorded in discontinued operations for each period presented.

As a result of the May 21, 2007 settlement of the litigation with three former executives (see Note 17 of Notes to Consolidated Financial Statements), 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.  Additionally, 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.

There were no discontinued operations recorded in 2009 or 2008.

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7.  Debt Obligations

Long-term Debt

	At			At
	December 31,			December 31,
$ in millions	2009			2008
DP&L -
First mortgage bonds maturing 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing 2028 - 4.70%	35.3			35.3
Pollution control series maturing 2034 - 4.80%	179.1			179.1
Pollution control series maturing 2036 - 4.80%	100.0			100.0
Pollution control series maturing 2040 - variable rates: 0.24% - 0.85% and 0.80% - 1.25% (a)	—			100.0
	784.4			884.4
Obligation for capital lease	—			0.6
Unamortized debt discount	(0.7		)	(1.0		)
Total long-term debt - DP&L	$	783.7		$	884.0
DPL Inc. -
Senior notes 6.875% series due 2011	297.4			297.4
Note to DPL Capital Trust II 8.125% due 2031	142.6			195.0
Unamortized debt discount	(0.2		)	(0.3		)
Total long-term debt - DPL	$	1,223.5		$	1,376.1

Current portion - Long-term Debt

	At		At
	December 31,		December 31,
$ in millions	2009		2008
DP&L
Pollution control series maturing 2040 - variable rates: 0.24% - 0.85% and 0.80% - 1.25% (a) (b)	$	100.0	$	—
Obligation for capital lease	0.6		0.7
Total current portion - long-term debt - DP&L	$	100.6	$	0.7
DPL Inc.
Senior notes 8.00% series due 2009	—		175.0
Total current portion - long-term debt - DPL	$	100.6	$	175.7

(a)	Range of interest rates for the year ended December 31, 2009 and the one month ended December 31, 2008, respectively.
	These pollution control bonds were issued on December 4, 2008.
(b)	Shown as current since bondholders could call bonds. See further discussion below.

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At December 31, 2009, maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions	DPL		DP&L
2010	$	100.6	$	100.6
2011	297.4		—
2012	—		—
2013	470.0		470.0
2014	—		—
Thereafter	457.0		314.4
	$	1,325.0	$	885.0

Debt and Debt Covenants

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 recognized as an expense in the fourth quarter of 2009 and recorded within interest expense on the Consolidated Statements of Results of Operations.

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group.  The agreement is for a 364-day term expiring on April 20, 2010.  The facility contains one financial covenant: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of December 31, 2009, this covenant is met with a ratio of 0.40 to 1.00.  As of December 31, 2009, there were no borrowings outstanding under this facility.  Fees associated with this credit facility were approximately $0.7 million in 2009.

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

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.  The payment of principal and interest on the bonds when due is backed by a standby letter of credit (LOC) issued by a syndicated bank group.  This LOC facility, which was for an initial two-year period expiring in December 2010, is irrevocable, has no subjective acceleration clauses and also contains a provision that all outstanding amounts drawn on the facility are due upon the LOC’s expiration date.  Since this LOC facility will expire in December 2010, at which point the bondholders could call the bonds, we have reflected these outstanding bonds 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 a renewal of this standby letter of credit or to explore alternative financing arrangements.  DP&L used $10 million of the proceeds from this bond issuance to finance its portion of the costs for acquiring, constructing and installing certain solid waste disposal and air quality facilities at the Conesville generation station.  The remaining $90 million was used to redeem the 2007 Series A Bonds as discussed in the next paragraph.

On November 15, 2007, the OAQDA issued $90 million of collateralized, variable rate OAQDA Revenue Bonds, 2007 Series A due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA.  The payment of principal and interest on the bonds when due was insured by an insurance policy issued by Financial Guaranty Insurance Company (FGIC).  During the first quarter of 2008, all three credit rating agencies downgraded FGIC.  These downgrades, as well as the downgrades of our major bond insurers, resulted in auction rate security bonds carrying substantially higher interest rates in succeeding auctions and incurring failed auctions.  On April 4, 2008, DP&L converted the 2007 Series A Bonds from Auction Rate Securities to Variable Rate Demand Notes.  At that time, DP&L repurchased these notes out of the market and placed them with the Trustee to be held until the capital markets corrected.  These notes were redeemed in December 2008.

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.  The facility contains one financial covenant:  DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of December 31, 2009, this covenant is met with a ratio of 0.40 to 1.00.  DP&L had no outstanding borrowings under this credit facility at December 31, 2009.  Fees associated with this credit facility were approximately $0.9 million in 2009 compared to $0.3 million in 2008.  Changes in credit ratings, however, may affect fees and the applicable interest.  This revolving credit agreement contains a $50 million letter of credit sublimit.  As of December 31, 2009, DP&L had no outstanding letters of credit against the facility.  DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions.

93

During the first quarter of 2006, the Ohio Department of Development (ODOD) awarded DP&L the ability to issue, through 2008, up to $200 million of qualified tax-exempt financing from the ODOD’s 2005 volume cap carryforward.  The PUCO approved DP&L’s application for this additional financing on July 26, 2006.  The entire $200 million financing was used to partially fund the FGD capital projects.

Substantially all property, plant and equipment 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.

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8.  Income Taxes

For the years ended December 31, 2009, 2008 and 2007, DPL’s components of income tax expense were as follows:

DPL

	For the years ended
	December 31,
$ in millions	2009			2008			2007
Computation of Tax Expense
Federal income tax (a)	$	119.9		$	121.9		$	117.3
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect (b)	0.9			4.1			11.6
Depreciation	(2.0		)	(4.3		)	(4.8		)
Investment tax credit amortized	(2.8		)	(2.8		)	(2.8		)
Section 199 - domestic production deduction	(4.6		)	(4.2		)	(2.0		)
Accrual (settlement) for open tax years (c)	(1.4		)	(7.2		)	2.7
Other, net (d)	2.5			(4.6		)	0.5
Total tax expense (e)	$	112.5		$	102.9		$	122.5
Components of Tax Expense
Federal - Current	$	(84.4	)	$	60.9		$	94.2
State and Local - Current	(1.8		)	1.8			6.6
Total Current	$	(86.2	)	$	62.7		$	100.8
Federal - Deferred	$	196.0		$	37.9		$	16.7
State and Local - Deferred	2.7			2.3			5.0
Total Deferred	$	198.7		$	40.2		$	21.7
Total tax expense	$	112.5		$	102.9		$	122.5

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2009			2008
Net Noncurrent Assets / (Liabilities)
Depreciation / property basis	$	(583.5	)	$	(391.9	)
Income taxes recoverable	(12.9		)	(15.1		)
Regulatory assets	(16.5		)	(7.7		)
Investment tax credit	12.3			13.3
Investment loss	0.1			0.1
Compensation and employee benefits	35.8			34.2
Insurance	0.8			0.8
Other (f)	(5.2		)	(7.8		)
Net noncurrent (liabilities)	$	(569.1	)	$	(374.1	)
Net Current Assets (g)
Other	$	3.7		$	2.2
Net current assets	$	3.7		$	2.2

(a)	The statutory tax rate of 35% was applied to pre-tax earnings from continuing operations before preferred dividends.
(b)	We have recorded a benefit of $0.2 million and an expense of $0.2 million and $0.5 million in 2009, 2008 and 2007, respectively, for state tax credits available related to the consumption of coal mined in Ohio. In addition, an expense of less than $0.1 million in 2009, a benefit of $0.5 million in 2008 and an expense of $0.9 million in 2007 were recorded as a result of the phase-out of the Ohio Franchise Tax.
(c)	We have recorded benefits of $2.9 million and $40.7 million and an expense of $2.7 million in 2009, 2008 and 2007, 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 below.
(d)	Includes an expense of $2.0 million, benefit of $3.8 million and expense of $5.0 million in 2009, 2008 and 2007, respectively, of income tax related to adjustments from prior years.
(e)	Excludes $6.0 million in 2007 of income taxes reported as discontinued operations.
(f)	The Other noncurrent liabilities caption includes deferred tax assets of $12.0 million in 2009 and $10.7 million in 2008 related to state and local tax net operating loss carryforwards, net of related valuation allowances of $12.0 million in 2009 and $10.7 million in 2008. As of December 31, 2009 and 2008, all deferred tax assets related to net operating losses were valued at zero. These net operating loss carryforwards expire from 2017 to 2024.
(g)	Amounts are included within Other prepayments and current assets on the Consolidated Balance Sheets of DPL.

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DPL has recorded $0.7 million, $0.3 million and $1.3 million in 2009, 2008 and 2007, respectively, for tax benefits related to stock-based compensation that were credited to Retained earnings.  We have recorded $1.7 million, $11.5 million and $0.9 million in 2009, 2008 and 2007, 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, 2009, 2008 and 2007, DP&L’s components of income tax were as follows:

DP&L

	For the years ended
	December 31,
$ in millions	2009			2008			2007
Computation of Tax Expense
Federal income tax (a)	$	134.2		$	142.1		$	145.1
Increases (decreases) in tax resulting from:
State income taxes, net of federal effect (b)	0.4			2.6			9.6
Depreciation	(2.0		)	(4.3		)	(4.7		)
Investment tax credit amortized	(2.8		)	(2.8		)	(2.8		)
Non-deductible compensation	—			—			—
Section 199 - domestic production deduction	(4.6		)	(4.2		)	(2.0		)
Accrual (settlement) for open tax years (c)	(1.4		)	(7.2		)	2.7
Other, net (d)	0.7			(6.0		)	(4.8		)
Total tax expense	$	124.5		$	120.2		$	143.1
Components of Tax Expense
Federal - Current	$	(70.3	)	$	81.2		$	117.1
State and Local - Current	(2.5		)	0.9			7.6
Total Current	$	(72.8	)	$	82.1		$	124.7
Federal - Deferred	$	194.4		$	36.4		$	16.3
State and Local - Deferred	2.9			1.7			2.1
Total Deferred	$	197.3		$	38.1		$	18.4
Total tax expense	$	124.5		$	120.2		$	143.1

Components of Deferred Tax Assets and Liabilities

	At December 31,
$ in millions	2009			2008
Net Noncurrent Assets (Liabilities)
Depreciation/property basis	$	(563.7	)	$	(373.8	)
Income taxes recoverable	(12.9		)	(15.1		)
Regulatory assets	(16.5		)	(13.3		)
Investment tax credit	12.3			13.3
Compensation and employee benefits	35.8			34.1
Other	(8.0		)	(3.5		)
Net noncurrent (liabilities)	$	(553.0	)	$	(358.3	)
Net Current Assets (e)
Other	$	3.7		$	2.3
Net current assets	$	3.7		$	2.3

(a)	The statutory tax rate of 35% was applied to pre-tax earnings before preferred dividends.
(b)	We have recorded a benefit of $0.2 million and expenses of $0.2 million and $0.5 million in 2009, 2008 and 2007, respectively, for state tax credits available related to the consumption of coal mined in Ohio. In addition, an expense of less than $0.1 million in 2009, a benefit of $0.5 million in 2008 and an expense of $0.9 million in 2007 were recorded as a result of the phase-out of the Ohio Franchise Tax.
(c)	We have recorded benefits of $2.9 million and $40.7 million and expense of $2.7 million in 2009, 2008 and 2007, 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 below.
(d)	Includes and expense of $0.8 million, benefit of $3.5 million and expense of $5.0 million in 2009, 2008 and 2007, respectively, of income tax related to adjustments from prior years.
(e)	Amounts are included within Other prepayments and current assets on the Balance Sheets of DP&L.

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DP&L has recorded $0.7 million, $0.3 million and $1.3 million in 2009, 2008 and 2007, respectively, for tax benefits related to stock-based compensation that were credited to Other paid-in capital.  We have recorded $0.5 million, $16.5 million and $4.6 million in 2009, 2008 and 2007, 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	2009			2008
Balance as of beginning of year	$	1.9		$	56.3
Tax positions taken during prior periods	—			—
Tax positions taken during current period	20.6			1.9
Settlement with taxing authorities	(3.2		)	(56.3		)
Lapse of applicable statute of limitations	—			—
Balance as of end of year	$	19.3		$	1.9

Of the December 31, 2009 balance of unrecognized tax benefits, $21.6 million is due to uncertainty in the timing of deductibility offset by $2.3 million of unrecognized tax liabilities that would affect the effective tax rate.

We recognize interest and penalties related to unrecognized tax benefits in income taxes.  The amount of interest and penalties accrued was 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 2009 and 2008 was a benefit of $0.1 million and $9.0 million, respectively, and an expense of $4.1 million for 2007.

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.

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.

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9.  Pension and Postretirement Benefits

DP&L sponsors a defined benefit 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, the defined benefit plan is based primarily on compensation and years of service.  We fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA).  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.  We also have unfunded liabilities related to retirement benefits for certain active, terminated and retired key executives.

On February 23, 2006, DPL’s Board of Directors approved a new compensation and benefits program that includes The DPL Inc. Supplemental Executive Defined Contribution Retirement Plan (SEDCRP) which replaces our SERP that was terminated as to new participants in 2000.  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.

A participant shall become 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.

Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits, while qualified employees who retired after 1987 are eligible for life insurance benefits only.  We have funded a portion of the union-eligible health benefits using a Voluntary Employee Beneficiary Association Trust.

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.

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The following tables set forth our pension and postretirement benefit plans’ obligations and assets recorded on the balance sheets as of December 31, 2009 and 2008.  The amounts presented in the following tables for pension include both the defined benefit pension plan and the Supplemental Executive Retirement Plan in the aggregate, and use a measurement date of December 31, 2009 and 2008.  The amounts presented for postretirement include both health and life insurance benefits and use a measurement date of December 31, 2009 and 2008.

	Pension						Postretirement
$ in millions	2009			2008			2009			2008
Change in Benefit Obligation During Year
Benefit obligation at January 1	$	294.6		$	285.0		$	25.2		$	26.4
Service cost	3.6			3.3			—			—
Interest cost	18.1			16.7			1.5			1.4
Plan amendments	7.2			6.9			1.1			—
Actuarial (gain) / loss	20.3			2.0			0.3			(0.1		)
Benefits paid	(19.9		)	(19.3		)	(1.9		)	(2.5		)
Benefit obligation at December 31	$	323.9		$	294.6		$	26.2		$	25.2
Change in Plan Assets During Year
Fair value of plan assets at January 1	$	225.4		$	291.0		$	6.2		$	6.5
Actual return / (loss) on plan assets	37.5			(46.7		)	0.4			0.2
Contributions to plan assets	0.4			0.4			0.3			2.1
Benefits paid	(19.9		)	(19.3		)	(2.3		)	(2.7		)
Medicare reimbursements	—			—			0.4			0.1
Fair value of plan assets at December 31	$	243.4		$	225.4		$	5.0		$	6.2
Funded Status of Plan	$	(80.5	)	$	(69.2	)	$	(21.2	)	$	(19.0	)
Amounts Recognized in the Balance Sheets at December 31
Current liabilities	$	(0.4	)	$	(0.4	)	$	(0.4	)	$	(0.4	)
Noncurrent liabilities	(80.1		)	(68.8		)	(20.8		)	(18.6		)
Net asset / (liability) at December 31	$	(80.5	)	$	(69.2	)	$	(21.2	)	$	(19.0	)
Amounts Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities, pre-tax
Components:
Prior service cost / (credit)	$	20.4		$	16.7		$	1.1		$	—
Net actuarial loss / (gain)	130.9			129.9			(6.9		)	(7.8		)
Accumulated other comprehensive income, regulatory assets and regulatory liabilities, pre-tax	$	151.3		$	146.6		$	(5.8	)	$	(7.8	)
Recorded as:
Regulatory asset	$	84.6		$	83.3		$	0.6		$	—
Regulatory liability	—			—			(5.1		)	(5.8		)
Accumulated other comprehensive income	66.7			63.3			(1.3		)	(2.0		)
Accumulated other comprehensive income, regulatoryassets and regulatory liabilities, pre-tax	$	151.3		$	146.6		$	(5.8	)	$	(7.8	)

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The accumulated benefit obligation for our defined benefit pension plans was $314.0 million and $283.3 million at December 31, 2009 and 2008, 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	2009			2008			2007			2009			2008			2007
Service cost	$	3.6		$	3.2		$	3.2		$	—		$	—		$	—
Interest cost	18.1			16.7			16.2			1.5			1.4			1.5
Expected return on assets (a)	(22.5		)	(24.1		)	(22.0		)	(0.4		)	(0.4		)	(0.5		)
Amortization of unrecognized:
Actuarial (gain) / loss	4.4			2.6			3.4			(0.7		)	(0.9		)	(0.9		)
Prior service cost	3.4			2.4			2.4			0.1			—			—
Transition obligation	—			—			—			—			—			0.2
Net periodic benefit cost / (income) before adjustments	$	7.0		$	0.8		$	3.2		$	0.5		$	0.1		$	0.3

(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 admitted into the MRVA equally over a period not to exceed five years.  We use a methodology under which we admit the difference between actual and estimated asset returns in the MRVA equally over a three year period.  The MRVA used in the 2009 calculation of expected return on pension plan assets was approximately $275 million.

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

	Pension						Postretirement
$ in millions	2009			2008			2009			2008
Net actuarial (gain) / loss	$	5.3		$	72.8		$	0.3		$	0.2
Prior service cost / (credit)	7.2			6.9			1.1			—
Reversal of amortization item:
Net actuarial (gain) / loss	(4.4		)	(2.6		)	0.7			0.9
Prior service cost / (credit)	(3.4		)	(2.4		)	(0.1		)	—
Transition (asset) / obligation	—			—			—			—
Total recognized in Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities	$	4.7		$	74.7		$	2.0		$	1.1
Total recognized in net periodic benefit cost and Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities	$	11.7		$	75.5		$	2.5		$	1.2

Estimated amounts that will be amortized from Accumulated other comprehensive income, Regulatory assets and Regulatory liabilities into net periodic benefit costs during 2010 are:

$ in millions	Pension		Postretirement
Net actuarial (gain) / loss	$	7.4	$	(0.5	)
Prior service cost / (credit)	3.6		0.1
Transition (asset) / obligation	—		—

On November 26, 2007, DP&L contributed $27.4 million in DPL common stock from its Master Trust assets to the Retirement Income Plan.

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.

Our overall expected long-term rate of return on assets is approximately 8.50% for pension plan assets and approximately 6.00% for retiree benefit plan assets.  This expected return is based primarily on historical returns and portfolio investment allocation.  There can be no assurance of our ability to generate those rates of return in the future.

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Our overall discount rate was evaluated in relation to the December 31, 2009 Hewitt Top Quartile Yield Curve which represents a portfolio of top-quartile AA-rated bonds used to settle pension obligations and the Citigroup Pension Discount Curve.  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.

The weighted average assumptions used to determine benefit obligations for the years ended December 31, 2009 and 2008 were:

	Pension				Postretirement
Benefit Obligation Assumptions	2009		2008		2009		2008
Discount rate for obligations	5.75	%	6.25	%	5.35	%	6.25	%
Rate of compensation increases	4.44	%	5.44	%	N/A		N/A

The weighted-average assumptions used to determine net periodic benefit cost (income) for the years ended December 31, 2009, 2008 and 2007 were:

Net Periodic Benefit	Pension						Postretirement
Cost / (Income) Assumptions	2009		2008		2007		2009		2008		2007
Discount rate	6.25	%	6.00	%	5.75	%	6.25	%	6.00	%	5.75	%
Expected rate of return on plan assets	8.50	%	8.50	%	8.50	%	6.00	%	6.00	%	6.75	%
Rate of compensation increases	5.44	%	5.44	%	5.44	%	N/A		N/A		N/A

The assumed health care cost trend rates at December 31, 2009 and 2008 are as follows:

	Expense				Benefit Obligations
Health Care Cost Assumptions	2009		2008		2009		2008
Pre - age 65
Current health care cost trend rate	9.50	%	10.00	%	9.50	%	9.50	%
Year trend reaches ultimate	2014		2013		2015		2014
Post - age 65
Current health care cost trend rate	9.00	%	10.00	%	9.00	%	9.00	%
Year trend reaches ultimate	2013		2013		2014		2013
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	$	0.1	$	(0.1	)
Benefit obligation	$	1.2	$	(1.1	)

The following benefit payments, which reflect future service, are expected to be paid as follows:

Estimated Future Benefit Payments
$ in millions	Pension		Postretirement
2010	$	21.2	$	2.6
2011	$	21.6	$	2.5
2012	$	22.4	$	2.4
2013	$	23.1	$	2.3
2014	$	23.6	$	2.1
2015 - 2019	$	121.6	$	8.4

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We expect to contribute $10.4 million to our pension plans and $2.6 million to our other postretirement benefit plans in 2010.

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 which is 80% in 2010, 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 2009 plan year, the funded status of our defined benefit pension plan as calculated under the requirements of the Act was 101.7% and is estimated to be 91.7% until the 2010 status is certified in September 2010 for the 2010 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, 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

(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.

(c)This category comprises cash held to pay beneficiaries.  The fair value of cash equals its book value.

(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 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

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	$	—

(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.

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10.  Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible.  We rely on modelled valuations only when no other method exists.  The fair value of our financial instruments represents estimates of possible value that may not be realized in the future.  The table below presents the fair value and cost of our non-derivative instruments at December 31, 2009 and 2008.

	At December 31,
	2009				2008
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL
Assets
Master Trust Assets	$	12.3	$	12.6	$	13.6	$	13.1
Liabilities
Debt	$	1,324.1	$	1,317.6	$	1,551.8	$	1,470.5
DP&L
Assets
Master Trust Assets	$	26.4	$	40.9	$	29.8	$	40.2
Liabilities
Debt	$	884.3	$	844.5	$	884.7	$	815.7

Debt

Debt is fair valued 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 2010 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 accounted for as available-for-sale securities and are recorded at fair value.  Any unrealized gains or losses are recognized in AOCI until the securities are sold.

DPL had $0.3 million ($0.2 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at December 31, 2009 and no unrealized gains and $0.5 million ($0.3 million after tax) in unrealized losses in AOCI at December 31, 2008.

DP&L has $14.5 million ($9.5 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at December 31, 2009 and $10.9 million ($7.0 million after tax) in unrealized gains and $0.5 million ($0.3 million after tax) in unrealized losses in AOCI at December 31, 2008.

No unrealized gains or losses are expected to be transferred to earnings in 2010.

Transfer of Master Trust Assets to Pension

On October 26, 2007, the Board of Directors approved a resolution permitting the transfer of 925,000 shares of DPL common stock from the DP&L Master Trust to The Dayton Power and Light Company Retirement Income Plan Trust (Pension).  This transaction was completed on November 26, 2007, contributing shares of DPL common stock with a fair value of $27.4 million to the pension plan.

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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, 2009.  These assets are part of the Master Trust and exclude DPL common stock which is valued using quoted market prices and not the NAV.  Fair values estimated using the net asset value per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV on the reporting date.  Investments that have restrictions on the redemption of the investments are Level 3 inputs.  As of December 31, 2009, DPL did not have any investments for sale at a price different than the NAV.

Fair Value Estimated using Net Asset Value per Unit

Investment			Unfunded		Redemption	Redemption
$ in millions	Fair Value		Commitments		Frequency	Notice Period
Money Market Mutual 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 (MCSI) 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 the Global Corporate Cumulative Average Default Rates.

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The fair value of assets and liabilities measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:

DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on Consolidated
$ in millions	Fair Value at December 31, 2009*		Based on Quoted Prices in Active Market		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2009
Assets
Master Trust Assets	$	12.6	$	—	$	12.6	$	—	$	—		$	12.6
Derivative Assets	6.3		—		6.3		—		(1.4		)	4.9
Total	$	18.9	$	—	$	18.9	$	—	$	(1.4	)	$	17.5
Liabilities
Derivative Liabilities	$	4.7	$	1.2	$	3.5	$	—	$	(1.2	)	$	3.5
Total	$	4.7	$	1.2	$	3.5	$	—	$	(1.2	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

The fair value of assets and liabilities 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, 2009*		Based on Quoted Prices in Active Market		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2009
Assets
Master Trust Assets (a)	$	40.9	$	28.3	$	12.6	$	—	$	—		$	40.9
Derivative Assets	6.3		—		6.3		—		(1.4		)	4.9
Total	$	47.2	$	28.3	$	18.9	$	—	$	(1.4	)	$	45.8
Liabilities
Derivative Liabilities	$	4.7	$	1.2	$	3.5	$	—	$	(1.2	)	$	3.5
Total	$	4.7	$	1.2	$	3.5	$	—	$	(1.2	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

(a)  DP&L holds DPL stock in the Master Trust that is eliminated in consolidation.

Level 1 inputs are used for DPL common stock held by the Master Trust and for derivative contracts such as heating oil 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; and open-ended mutual funds that are in the Master Trust valued using the end of day NAV.

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Non-recurring fair value measurements

The fair value of an ARO is 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.  We added a new ARO for a landfill and additional layers to our existing landfill and asbestos AROs in the amount of $2.7 million during 2009.

DPL had $45.3 million and $15.0 million in money market funds classified as cash and cash equivalents in its Consolidated Balance Sheets at December 31, 2009 and 2008, respectively.  The money market funds have quoted prices that are generally equivalent to par.

11.  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.  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 generally 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 a cash flow hedge or marked to market each reporting period.

At December 31, 2009, DP&L had the following outstanding derivative instruments:

	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 MTM 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 when the hedged forecasted transaction takes place or when the hedged forecasted 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 currently use cash flow hedging with forward power contracts and in 2003 we entered into an interest rate swap which was settled that same year.  Approximately $2.1 million ($1.4 million net of tax) of accumulated losses in AOCI related to the above mentioned power hedges are expected to be reclassified to earnings over the next twelve months.  The balance of the remaining deferred gain from the interest rate swap in AOCI is being amortized into earnings over the life of the related bonds.  Approximately $2.5 million ($1.6 million net of tax) of accumulated gains in AOCI related to the above referenced interest rate hedge are expected to be reclassified to earnings over the next twelve months.  As of December 31, 2009, the maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions is 23 months and 106 months for the forward power positions and the interest rate hedge, respectively.

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The following table provides information concerning gains or losses recognized in AOCI for the cash flow hedges:

	December 31,						December 31,						December 31,
	2009						2008						2007
				Interest			Power and			Interest			Power and			Interest
$ in millions (net of tax)	Power			Rate Hedge			Capacity			Rate Hedge			Capacity			Rate Hedge
Beginning accumulated derivative gain / (loss) in AOCI	$	(0.2	)	$	17.2		$	(1.0	)	$	19.7		$	2.1		$	22.1
Net gains / (losses) associated with current period hedging transactions	2.2			—			4.8			—			(0.4		)	—
Net gains reclassified to earnings	(3.4		)	(2.5		)	(4.0		)	(2.5		)	(2.7		)	(2.4		)
Ending accumulated derivative gain / (loss) in AOCI	$	(1.4	)	$	14.7		$	(0.2	)	$	17.2		$	(1.0	)	$	19.7

The following table shows the amount and income statement classification of the gains and losses incurred during the period on DP&L’s derivatives designated as hedging instruments for the year ended December 31, 2009.

For the year ended December 31, 2009

$ in millions (net of tax)	Amount of Gains Recognized in AOCI on Derivative (Effective Portion)		Location of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)		Location of Gains Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives Designated as Hedging Instruments
Interest Rate Hedge	$	—	Interest expense	$	2.5	Interest expense	$	—
Forward Power Contracts	2.2		Revenues	3.4		Revenues	—
(Decrease) / Increase on the Statements of Results of Operations of DP&L for Derivative Instruments Designated as Hedging Instruments	$	2.2		$	5.9		$	—

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The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments.

Fair Values of Derivative Instruments Designated as Hedging Instruments

At December 31, 2009

$ in millions	Fair Value			Netting*			Balance Sheet Location	Fair Value on 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	)

*Includes counterparty netting.

Mark to Market

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 purchase and sales exceptions under FASC 815.  Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the 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 currently MTM Financial Transmission Rights (FTRs), heating oil futures and forward NYMEX-quality coal contracts.

DP&L enters into coal contracts from time to time to supply its generating plants.  We perform a quarterly evaluation of the different coal markets to determine if these coal contracts are considered derivative instruments under FASC 815.  DP&L has concluded that NYMEX and NYMEX look-a-like coal contracts are considered derivative instruments because they have been determined to be readily convertible to cash under FASC 815.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided in FASC 815.  Derivative contracts that have been designated as normal purchases or normal sales under FASC 815 are not subject to MTM accounting treatment and are recognized in the statements of results of operations on an accrual basis.

Regulatory Assets and Liabilities

Under FASC 980, “Regulated Operations,” if a cost is probable of recovery in future rates, it should be deferred as a regulatory asset.  If a gain is probable of being returned to customers, it 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 factor approved by the PUCO beginning January 1, 2010.  Therefore, the Ohio jurisdictional retail 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 table shows the amount and statement of results of operations or balance sheet classification of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the period ended December 31, 2009.

For the year 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:
Partner’s 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

*Includes gains and losses on financially settled derivative contracts and cost to market adjustments on physically settled derivative contracts.

The following table shows the fair value and Balance Sheet classification of DP&L’s derivative instruments not designated as hedging instruments.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

At December 31, 2009

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.8		$	—		Other prepayments and current assets	$	0.8
Heating Oil Futures in a Liability position	(1.2		)	1.2			Other current liabllities	—
NYMEX-Quality Coal Forwards in an Asset position	2.6			(0.2		)	Other prepayments and current assets	2.4
NYMEX-Quality Coal Forwards in a Liability position	(1.2		)	—			Other current liabilities	(1.2		)
Forward Power Contracts in a Liability position	(0.2		)	—			Other current liabilities	(0.2		)
Total short-term derivative MTM positions	$	0.8		$	1.0			$	1.8
Long-term Derivative Positions
NYMEX-Quality Coal Forwards in an Asset position	$	2.9		$	(1.2	)	Other assets	$	1.7
Total long-term derivative MTM positions	$	2.9		$	(1.2	)		$	1.7
Total MTM Position	$	3.7		$	(0.2	)		$	3.5

*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 derivative instruments that are in a MTM loss position at December 31, 2009, is $4.7 million.  This amount is offset by $1.2 million in a broker margin account which offsets our loss positions on the NYMEX Clearport traded heating oil and coal contracts.  If our debt were to fall below investment grade, we would have to post collateral for the remaining $3.5 million.

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12.  Stock-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 and 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	2009			2008			2007
Stock options	$	—		$	—		$	—
Restricted stock units	—			(0.1		)	—
Performance shares	1.8			0.9			1.5
Restricted shares	0.7			0.3			0.3
Non-employee directors’ RSUs	0.5			0.5			0.3
Management performance shares	0.7			0.3			—
Share-based compensation included in Operation and maintenance expense	3.7			1.9			2.1
Income tax expense / (benefit)	(1.3		)	(0.7		)	(0.7		)
Total share-based compensation, net of tax	$	2.4		$	1.2		$	1.4

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 grant until exercise 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.  On April 26, 2006, DPL’s shareholders approved The DPL Inc. 2006 Equity and Performance Incentive Plan (EPIP).  With the approval of the EPIP, 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, 2009, there were no unvested stock options.

Summarized stock option activity was as follows:

	For the years ended
	December 31,
	2009			2008			2007
Options:
Outstanding at beginning of year	836,500			946,500			5,091,500
Granted	—			—			—
Exercised	(419,000		)	(110,000		)	(525,000		)
Forfeited (a)	—			—			(3,620,000		)
Outstanding at year-end	417,500			836,500			946,500
Exercisable at year-end	417,500			836,500			946,500
Weighted average option prices per share:
Outstanding at beginning of year	$	24.64		$	24.09		$	21.95
Granted	$	—		$	—		$	—
Exercised	$	21.53		$	18.56		$	26.79
Forfeited	$	—		$	—		$	20.38
Outstanding at year-end	$	27.16		$	24.64		$	24.09
Exercisable at year-end	$	27.16		$	24.64		$	24.09

(a)  As a result of the settlement of the former executive litigation on May 21, 2007, 3.6 million outstanding options shown above were forfeited in the second quarter of 2007 and another approximately one million disputed options not shown above were also forfeited.

The following table reflects information about stock options outstanding at December 31, 2009:

		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	141,000	0.7	$	20.97	141,000	$	20.97
$21.01 - $29.63	276,500	1.0	$	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	2009		2008		2007
Weighted-average grant date fair value of options granted during the period	$	—	$	—	$	—
Intrinsic value of options exercised during the period	$	2.2	$	1.0	$	2.3
Proceeds from stock options exercised during the period	$	9.0	$	2.2	$	14.6
Excess tax benefit from proceeds of stock options exercised	$	0.7	$	0.3	$	1.3
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 2007, 2008 or 2009.

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Restricted Stock Units (RSUs)

RSUs were granted to certain key employees prior to 2001.  As a result of the settlement of the former executive litigation, all disputed RSUs (1.3 million) were forfeited by three former executives (see Note 17 of Notes to Consolidated Financial Statements).  There were 3,311 RSUs outstanding as of December 31, 2009, none of which has vested.  The non-vested RSUs will be paid in cash upon vesting in 2010.  Non-vested RSUs are valued quarterly at fair value using the Black-Scholes-Merton model to determine the amount of compensation expense to be recognized.  Non-vested RSUs do not earn dividends.

			Weighted-Avg.
	Number of		Grant Date
$ in millions	RSUs		Fair Value
Non-vested at January 1, 2009	10,120		$	0.2
Granted in 2009	—		—
Vested in 2009	(6,809	)	(0.1		)
Forfeited in 2009	—		—
Non-vested at December 31, 2009	3,311		$	0.1

Summarized RSU activity was as follows:

	For the years ended
	December 31,
	2009		2008		2007
RSUs:
Outstanding at beginning of year	10,120		22,976		1,334,339
Granted	—		—		—
Dividends	—		—		11,656
Exercised	(6,809	)	(11,253	)	(20,097	)
Forfeited	—		(1,603	)	(1,302,922	)
Outstanding at period end	3,311		10,120		22,976
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, 2009, 2008 and 2007, liabilities recorded for outstanding RSUs were $0.1 million, $0.2 million and $0.6 million, respectively, which are included in Other deferred credits on the balance sheets.

The following table shows the assumptions used in the Black-Scholes-Merton model to calculate the fair value of the non-vested RSUs during the respective periods:

	For the years ended
	December 31,
	2009	2008	2007
Expected volatility	17.9%	24.8% - 28.1%	6.1% - 15.3%
Weighted-average expected volatility	17.9%	26.0%	13.0%
Expected life (years)	0.6	1.0 - 2.0	1.0 - 3.0
Expected dividends	5.1%	4.5%	3.8%
Weighted-average expected dividends	5.1%	4.5%	3.8%
Risk-free interest rate	0.2%	0.2% - 0.4%	3.0% - 3.3%

Performance Shares

Under the EPIP, the Board 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 under FASC 718.  There is a three year requisite service period for each portion of the performance shares.

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The schedule of non-vested performance share activity for the year ended December 31, 2009 follows:

	Number of		Weighted-Avg.
	Performance		Grant Date
$ in millions	Shares		Fair Value
Non-vested at January 1, 2009	119,855		$	3.3
Granted in 2009	124,588		2.8
Vested in 2009	(47,355	)	(1.6		)
Forfeited in 2009	(6,739	)	(0.2		)
Non-vested at December 31, 2009	190,349		$	4.3

	For the years ended
	December 31,
	2009		2008		2007
Performance shares:
Outstanding at beginning of year	156,300		142,108		154,768
Granted	124,588		93,298		78,559
Exercised	—		—		(22,462	)
Expired	(36,445	)	(37,426	)	(21,583	)
Forfeited	(6,739	)	(41,680	)	(47,174	)
Outstanding at period end	237,704		156,300		142,108
Exercisable at period end	47,355		36,445		37,426

The following table reflects information about performance share activity during the period:

	For the years ended
	December 31,
$ in millions	2009		2008		2007
Weighted-average grant date fair value of performance shares granted during the period	$	2.8	$	2.2	$	2.6
Intrinsic value of performance shares exercised during the period	$	—	$	—	$	0.6
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	$	0.8	$	0.8
Unrecognized compensation expense	$	2.1	$	1.6	$	1.9
Weighted average period to recognize compensation expense (in years)	1.7		1.6		1.7

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,
	2009	2008	2007
Expected volatility	22.8% - 23.3%	15.0% - 15.7%	15.8% - 17.3%
Weighted-average expected volatility	22.8%	15.1%	16.6%
Expected life (years)	3.0	3.0	3.0
Expected dividends	5.4% - 5.6%	3.5% - 4.1%	3.3% - 3.9%
Weighted-average expected dividends	5.6%	4.1%	3.4%
Risk-free interest rate	0.3% - 1.5%	2.2% - 3.2%	4.5% - 4.9%

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Restricted Shares

Under the EPIP, the Board 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 compensation 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 DPL Board of Directors approved a two-part equity compensation award under DPL’s 2006 Equity and Performance Incentive Plan 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.  A total of 90,036 restricted shares were granted on September 17, 2009 as part of the restricted share grant.  These restricted shares generally vest after five years if the participant remains continuously employed with DPL or a subsidiary and if the year over year average basic EPS has increased by at least 1% per year from 2009 - 2013.  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	Company % Match of
% of 2009 Base Salary	Shares Purchased
<25%	25%
25% to <50%	50%
50% to <100%	75%
100% to 200%	125%

The matching percentage will be applied on a cumulative basis and adjusted at the end of each quarter.

Restricted stock 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, 2009	69,147		$	1.9
Granted in 2009	159,050		4.2
Vested in 2009	(10,000	)	(0.3		)
Forfeited in 2009	—		—
Non-vested at December 31, 2009	218,197		$	5.8

	For the years ended
	December 31,
	2009		2008		2007
Restricted shares:
Outstanding at beginning of year	69,147		42,200		19,000
Granted	159,050		39,347		23,200
Exercised	(10,000	)	(1,000	)	—
Forfeited	—		(11,400	)	—
Outstanding at period end	218,197		69,147		42,200
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	2009		2008		2007
Weighted-average grant date fair value of restricted shares granted during the period	$	4.2	$	1.1	$	0.7
Intrinsic value of restricted shares exercised during the period	$	0.3	$	—	$	—
Proceeds from restricted shares exercised during the period	$	—	$	—	$	—
Excess tax benefit from proceeds of restricted shares exercised	$	—	$	—	$	—
Fair value of restricted shares that vested during the period	$	0.3	$	—	$	—
Unrecognized compensation expense	$	4.3	$	1.3	$	0.9
Weighted average period to recognize compensation expense (in years)	3.4		2.7		2.8

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, 2009	15,546		$	0.4
Granted in 2009	20,016		0.5
Dividends accrued in 2009	1,737		—
Exercised and issued in 2009	(2,066	)	(0.1		)
Exercised and deferred in 2009	(14,521	)	(0.4		)
Forfeited in 2009	—		—
Non-vested at December 31, 2009	20,712		$	0.4
	For the years ended
	December 31,
	2009		2008			2007
Restricted stock units:
Outstanding at beginning of year	15,546		13,573			—
Granted	20,016		17,022			14,920
Dividends accrued	1,737		931			348
Exercised and issued	(2,066	)	(7,910		)	(142	)
Exercised and deferred	(14,521	)	(6,921		)	—
Forfeited	—		(1,149		)	(1,553	)
Outstanding at period end	20,712		15,546			13,573
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	2009		2008		2007
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	$	0.4	$	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	$	0.5	$	0.5	$	0.3
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

On May 28, 2008, 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, 2009	39,144		$	1.1
Granted in 2009	48,719		1.0
Vested in 2009	—		—
Forfeited in 2009	(3,622	)	(0.1		)
Non-vested at December 31, 2009	84,241		$	2.0
	For the years ended
	December 31,
	2009		2008			2007*
Management Performance Shares:
Outstanding at beginning of year	39,144		—			—
Granted	48,719		39,144			—
Exercised	—		—			—
Forfeited	(3,622	)	—			—
Outstanding at period end	84,241		39,144			—
Exercisable at period end	—		—			—

*Management performance shares were not issued in 2007.

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,
	2009		2008		2007*
Expected volatility	22.8	%	14.9	%	0.0	%
Weighted-average expected volatility	22.8	%	14.9	%	0.0	%
Expected life (years)	3.0		3.0		—
Expected dividends	5.6	%	3.9	%	0.0	%
Weighted-average expected dividends	5.6	%	3.9	%	0.0	%
Risk-free interest rate	1.5	%	2.9	%	0.0	%

*Management performance shares were not issued in 2007.

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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	2009		2008		2007*
Weighted-average grant date fair value of management perfomance shares granted during the period	$	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	$	—	$	—	$	—
Unrecognized compensation expense	$	1.0	$	0.8	$	—
Weighted average period to recognize compensation expense (in years)	1.6		2.0		—

*Management performance shares were not issued in 2007.

13.  Redeemable Preferred Stock

DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 are outstanding as of December 31, 2009.  DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which was outstanding as of December 31, 2009.  The table below details the preferred shares outstanding at December 31, 2009.

			Redemption		Shares	Par Value at		Par Value at
	Preferred		Price at		Outstanding at	December 31,		December 31,
	Stock		December 31,		December 31,	2009		2008
	Rate		2009		2009	($ 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, 2009, DP&L’s retained earnings of $640.3 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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14.  Common Shareholders’ Equity

DPL has 250,000,000 authorized common shares, of which 118,966,767 are outstanding at December 31, 2009.

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.  The renewed plan expires on December 31, 2011.

Warrants

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.

The table below details the net change during 2009 of DPL’s outstanding warrants:

	Number
in millions	of Warrants
Outstanding warrants at January 1, 2009	19.6
Warrants repurchased at an average price of $2.94 each	(8.6	)
Warrants exercised under cashless transactions	(5.5	)
Warrants exercised for cash	(3.7	)
Outstanding warrants at December 31, 2009	1.8

The warrants repurchased were cancelled by DPL on the dates they were repurchased.  As a result of the warrants exercised under both cash and cashless provisions, DPL issued a total of 5.0 million shares of common stock from treasury stock and in turn received total cash proceeds of $77.7 million.  DPL used a portion of the proceeds to repurchase warrants directly from holders and the remaining proceeds were used to repurchase shares under its Stock Repurchase Program discussed below.

Stock Repurchase Program

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may use proceeds from the exercise of warrants to repurchase warrants or its common stock from time to time in the open market, through private transactions or otherwise. The Stock Repurchase Program will run through June 30, 2012, which is three months after the end of the warrant exercise period.  Under the Stock Repurchase Program, DPL repurchased a total of 2.4 million shares at an average per share price of $26.96 during the quarter ended December 31, 2009.  At December 31, 2009, the amount still available that could be used to repurchase stock under the Stock Repurchase Program is approximately $3.9 million but could be higher if additional warrants are exercised for cash in the future.

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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; other compensation shares awarded vest immediately.

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, 2009 and 2008 was approximately $57.6 million and $42.4 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 for unallocated shares are used to repay the principal and interest on the ESOP loan to DPL.  Dividends on the allocated shares are charged to retained earnings.

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, 2009, Common shareholders’ equity reflects the cost of 2.8 million unreleased shares held in suspense by the DPL Inc. Employee Stock Ownership Trust.  The fair value of the 2.8 million ESOP shares held in suspense at December 31, 2009 was $77.5 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 $4.0 million in 2009, $1.5 million in 2008 and $9.0 million in 2007.

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, 2009, the ESOP has 4.2 million shares allocated to participants with an additional 21 thousand shares which have been released but unallocated to participants.  ESOP cumulative shares outstanding for the calculation of EPS were 4.2 million in 2009, 4.0 million in 2008 and 3.9 million in 2007.

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15.  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, 2009, 2008 and 2007:

	DPL									DP&L
	Amount			Tax						Amount			Tax
	before			(expense) /			Amount			before			(expense) /			Amount
$ in millions	tax			benefit			after tax			tax			benefit			after tax
2007:
Unrealized gains / (losses) on financial instruments	$	(1.4	)	$	0.5		$	(0.9	)	$	(11.9	)	$	4.2		$	(7.7	)
Deferred gains / (losses) on cash flow hedges	(7.1		)	1.6			(5.5		)	(7.1		)	1.6			(5.5		)
Unrealized gains / (losses) on pension and postretirement benefits	3.4			(1.2		)	2.2			3.4			(1.2		)	2.2
Other comprehensive income (loss)	$	(5.1	)	$	0.9		$	(4.2	)	$	(15.6	)	$	4.6		$	(11.0	)
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	)

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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, 2009, 2008 and 2007:

DPL

$ in millions	2009			2008			2007
Unrealized gains on financial instruments net of income tax expense of $1.1 million in 2007. There were no unrealized gains or losses reclassified to earnings in 2009 or 2008.	$	—		$	—		$	2.0
Deferred gains on cash flow hedges net of income tax expenses of $1.8 million, $2.2 million and $1.5 million, respectively.	5.9			6.5			5.1
Unrealized losses on pension and postretirement benefits net of income tax benefits of $1.1 million, $0.7 million and $0.8 million, respectively.	(2.1		)	(1.3		)	(1.5		)
	$	3.8		$	5.2		$	5.6

DP&L

$ in millions	2009			2008			2007
Unrealized gains on financial instruments net of income tax expenses of $0.4 million, $1.4 million and $6.3 million, respectively.	$	0.7		$	2.7		$	11.6
Deferred gains on cash flow hedges net of income tax expenses of $1.8 million, $2.2 million and $1.5 million, respectively.	5.9			6.5			5.1
Unrealized losses on pension and postretirement benefits net of income tax benefits of $1.1 million, $0.7 million and $0.8 million, respectively.	(2.1		)	(1.3		)	(1.5		)
	$	4.5		$	7.9		$	15.2

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, 2009 and 2008:

DPL

$ in millions	2009			2008
Financial instruments, net of tax	$	0.2		$	(0.3	)
Cash flow hedges, net of tax	13.3			17.0
Pension and postretirement benefits, net of tax	(42.5		)	(39.8		)
Total	$	(29.0	)	$	(23.1	)

DP&L

$ in millions	2009			2008
Financial instruments, net of tax	$	9.5		$	6.7
Cash flow hedges, net of tax	13.3			17.0
Pension and postretirement benefits, net of tax	(42.5		)	(39.8		)
Total	$	(19.7	)	$	(16.1	)

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16.  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, 2009, 2008 and 2007.  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:

	2009					2008					2007
$ and shares in millions except				Per					Per		(a)			Per
per share amounts	Income		Shares	Share		Income		Shares	Share		Income		Shares	Share
Basic EPS	$	229.1	112.9	$	2.03	$	244.5	110.2	$	2.22	$	221.8	107.9	$	2.06
Effect of Dilutive Securities:
Stock Incentive Units			—					—					0.5
Warrants (b)			1.1					5.0					8.6
Stock options, performance and restricted shares (c)			0.2					0.2					0.8
Diluted EPS	$	229.1	114.2	$	2.01	$	244.5	115.4	$	2.12	$	221.8	117.8	$	1.88

(a)    Income after discontinued operations.

(b)    For information relating to warrant activity, see Note 14 of Notes to Consolidated Financial Statements.

(c)    Starting January 1, 2009, restricted shares are included in Basic Shares pursuant to the update to FASC 260,

“Earnings per Share.”  See Note 1 of Notes to Consolidated Financial Statements.

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17.  Executive Litigation

On May 21, 2007, we settled litigation with three former executives.  As part of this settlement, the three former executives relinquished and dismissed all their claims including those related to certain deferred compensation, RSUs, MVE incentives, stock options and legal fees. The RSUs and stock options relinquished and forfeited were 1.3 million and 3.6 million, respectively.  Prior to the settlement date, we had accrued obligations of $64.2 million.  Included in these amounts was $3.1 million associated with the forfeiture of stock options.  In exchange for our payment of $25 million and the relinquishment by the former executives of certain contested compensation discussed above, all of these claims by all parties were settled and released.

DPL

As a result of this settlement, during 2007, DPL realized a net pre-tax gain in continuing and discontinued operations of approximately $31.0 million and $8.2 million, respectively.  The net gain is comprised of the reversal of the $64.2 million of accrued obligations less the $25 million settlement.  The obligations related to the discontinued operations were associated with the management of DPL’s financial asset portfolio, which was conducted in our MVE subsidiary.  The MVE operations were discontinued in 2005 with the sale of the financial asset portfolio.  The $25 million settlement expense was allocated between continuing and discontinued operations based on the proportionate share of the obligations of each.

DP&L

As a result of this settlement during 2007, DP&L realized a net pre-tax gain in continuing operations of $35.3 million.  Accrued obligations associated with the former executives’ litigation were recorded by DP&L since the obligations were associated with our non-qualified benefit plans.  DP&L had no ownership of DPL’s discontinued financial asset portfolio business, therefore these liabilities were reversed and DP&L’s net pre-tax gain was recorded within continuing operations.

The $25 million settlement was funded from the sale of financial assets held in DP&L’s Master Trust Plan for deferred compensation.  As part of this transaction, during the second quarter ended June 30, 2007, DPL and DP&L recorded a $3.2 million realized gain which was reflected in investment income.

18.  Insurance Recovery

On April 30, 2007, DP&L executed a settlement agreement for $14.5 million with one of our insurers, Associated Electric & Gas Insurance Services (AEGIS), under a fiduciary liability policy to recoup a portion of legal fees associated with our litigation against three former executives.  This was recorded as a reduction to operation and maintenance expense during 2007.

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal expenses associated with our litigation against certain former executives.  Arbitration on that claim occurred on May 13, 2009.  The arbitration panel issued a ruling in Phase 1 of the arbitration on September 25, 2009, finding that most of the claims involving the former executives were covered.  In accordance with GAAP, DPL recorded expenses totaling $7.5 million in 2008 but has not recorded any assets for possible recovery of these expenses.  The matter is pending.

19.  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, 2009, DPL had $51 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 $0.6 million and $1.6 million at December 31, 2009 and 2008, respectively.

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In two separate transactions in November and December 2006, DPL also agreed to be a guarantor of the obligations of DPLE regarding the sale, in April 2007, of the Darby Electric Peaking Station to American Electric Power and the sale of the Greenville Electric Peaking Station to Buckeye Electric Power, Inc.  In both cases, DPL agreed to guarantee the obligations of DPLE over a multiple-year period as follows:

$ in millions	2008		2009		2010
Darby	$	23.0	$	15.3	$	7.7
Greenville	$	11.1	$	7.4	$	3.7

To date, neither DPL nor DP&L have incurred any losses related to the guarantees of DPLE’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 obligations.

DP&L — Equity Ownership Interest

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, 2009, DP&L could be responsible for the repayment of 4.9%, or $54.4 million, of a $1,110 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, 2009, we have no knowledge of such a default.

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, 2009, these include:

			Payment Year
$ in millions	Total		2010		2011-2012		2013-2014		Thereafter
DPL
Long-term debt	$	1,324.4	$	100.0	$	297.4	$	470.0	$	457.0
Interest payments	740.0		71.5		115.1		71.4		482.0
Pension and postretirement payments	253.8		23.8		48.9		51.1		130.0
Capital leases	0.6		0.6		—		—		—
Operating leases	0.5		0.3		0.2		—		—
Coal contracts (a)	1,694.3		498.1		577.2		184.4		434.6
Limestone contracts (a)	48.4		5.5		11.4		12.0		19.5
Purchase orders and other contractual obligations	162.6		56.9		84.9		14.6		6.2
Total contractual obligations	$	4,224.6	$	756.7	$	1,135.1	$	803.5	$	1,529.3
DP&L
Long-term debt	$	884.4	$	100.0	$	—	$	470.0	$	314.4
Interest payments	454.8		39.4		78.3		48.2		288.9
Pension and postretirement payments	253.8		23.8		48.9		51.1		130.0
Capital leases	0.6		0.6		—		—		—
Operating leases	0.5		0.3		0.2		—		—
Coal contracts (a)	1,694.3		498.1		577.2		184.4		434.6
Limestone contracts (a)	48.4		5.5		11.4		12.0		19.5
Purchase orders and other contractual obligations	164.8		58.0		86.0		14.6		6.2
Total contractual obligations	$	3,501.6	$	725.7	$	802.0	$	780.3	$	1,193.6

(a)  Total at DP&L-operated units

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Long-term debt:

DPL’s long-term debt as of December 31, 2009, 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, 2009, 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 7 of Notes to Consolidated Financial Statements.

Interest payments:

Interest payments 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, 2009.

Pension and postretirement payments:

As of December 31, 2009, DPL, through its principal subsidiary DP&L, had estimated future benefit payments as outlined in Note 9 of Notes to Consolidated Financial Statements.  These estimated future benefit payments are projected through 2019.

Capital leases:

As of December 31, 2009, DPL, through its principal subsidiary DP&L, had one immaterial capital lease that expires in September 2010.

Operating leases:

As of December 31, 2009, 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, 2009, 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 $19.3 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.

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, 2009, cannot be reasonably determined.

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Governmental and Regulatory Inquiries

On March 10, 2004, DPL’s and DP&L’s Corporate Controller sent a memorandum (the Memorandum) to the Chairman of the Audit Committee of our Board of Directors.  The Memorandum expressed the Corporate Controller’s “concerns, perspectives and viewpoints” regarding financial reporting and governance issues within DPL and DP&L.  In response, the Board initiated an internal investigation whose findings and recommendations led to corrective action taken regarding internal controls, process issues and the tone at the top.

On May 28, 2004, the U.S. Attorney’s Office for the Southern District of Ohio, assisted by the Federal Bureau of Investigation, notified DPL and DP&L that it had initiated an inquiry involving matters connected to our internal investigation.  This inquiry remains pending.

On or about June 24, 2004, the SEC commenced a formal investigation into the issues raised by the Memorandum.  This investigation remains pending.

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.  DPL, through its wholly owned captive insurance subsidiary MVIC, has an actuarially calculated reserve of $1.2 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 position or cash flows.

Air Quality

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 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 new source review requirements, if new source review requirements were imposed on any of DP&L’s existing power plants, the results could be materially adverse 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 New Source Review (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 at this time predict the outcome of this rulemaking, any finalized rules could materially affect our operations.

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 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

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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.  In January 2010, the Court ordered the USEPA to file a response to a Petition for Mandamus filed by parties in the original case who are now seeking a Court order to require the USEPA to issue new regulations by March 1, 2010.  We are currently unable to predict the outcome of this Petition or the timing or impact of any new regulations relating to CAIR.  CAIR has and will continue to have a material effect on our operations.

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.

In the fourth quarter of 2007, DP&L began a program for selling excess emission allowances, including annual NOxemission 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.  Although in January 2009 we resumed selling excess allowances due to the revival of the trading market, the long-term impact of the court’s decision, and of the actions the USEPA or others will take in response to this decision, is not fully known at this time and could have an adverse effect on us.

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 move forward on setting Maximum Available Control Technology (MACT) standards for coal- and oil-fired electric generating units.  Upon publication in the federal register following finalization, affected exempt generating units (EGUs) will have three years to come into compliance with the new requirements.  At this time, DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial position or results of operations; however, a MACT standard could have a material adverse effect on our operations, in particular, our unscrubbed units.  We cannot at this time project the final costs we may incur to comply with any resulting mercury restriction regulations.

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 in late 2010 as part of its routine five-year rule review cycle.  At this time, DP&L is unable to determine the impact the revisions to the PM 2.5 standard will have on its financial position or results of operations.

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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.

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 gases are pollutants under the CAA.  The USEPA has not yet identified the specifics of how these newly designated pollutants will be regulated.  In April 2009, the USEPA issued a proposed endangerment finding under the CAA.  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.  If the proposed finding is finalized, it could lead to the regulation of CO2 and other GHGs from sources other than motor vehicles, including coal-fired plants that we own and operate.  Recently, several bills have been introduced at the federal level to regulate GHG emissions.  In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES).  This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy wide cap and trade program.  ACES also includes energy efficiency and renewable energy initiatives.  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 position.  However, due to the uncertainty associated with such legislation, we are currently unable to predict the final outcome or the financial impact that this legislation will have on us.  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.

On July 15, 2009, the USEPA proposed revisions to its primary National Ambient Air Quality Standard (NAAQS) for nitrogen dioxide.  This change could affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton.  At this point, DP&L cannot determine the effect of this potential change, if any, on its operations.

The USEPA proposed revisions to its primary NAAQS for SO2 on November 16, 2009.  This would replace the current 24-hour standard and current annual standard.  This regulation is expected to be finalized in 2010.  At this time, DP&L cannot determine the effect of this potential change, if any, on its operations.

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.  At this point, DP&L cannot determine the effect of this potential change, if any, on its operations.

Air Quality — Litigation Involving Co-Owned Plants

In March 2000, as amended in June 2004, the U.S. Department of Justice filed a complaint in the United States District Court, Southern District of Indiana, Indianapolis Division against Cinergy Corp. (now part of Duke Energy) and two Cinergy subsidiaries for alleged violations of the CAA at various generation units operated by PSI Energy, Inc. and CG&E, including generation units co-owned by DP&L (Beckjord Unit 6 and Miami Fort Unit 7).  A retrial has been held in which the second jury found for Duke Energy on some allegations, but for plaintiffs with respect to units at another one of Duke Energy’s wholly-owned facilities.  In a separate phase II remedies trial with respect to violations found in the first trial, Duke Energy was ordered to close down three of its wholly-owned generating units by September 2009, surrender some emission allowances and pay a fine.  None of the violations found or remedies ordered relate to generating units owned in part by DP&L.

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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.  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 Second Circuit Court’s decision could also encourage these or other plaintiffs to file similar lawsuits against other electric power companies, including us.  We are unable at this time to predict with certainty the impact that these lawsuits might have on us.

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 believes that it is properly computing and reporting NOx emissions under the consent decree and has opposed the Sierra Club’s motion.  A decision on the motion is expected before the end of the first quarter 2010.  Because J.M. Stuart Station’s NOx emissions are well below the 2009 and 2010 limits in the consent decree under either method of calculation, an adverse decision would have no effect in 2010 on operations or costs.  An adverse decision could affect compliance costs in future years when the NOx limits are further reduced under the consent decree.

Air Quality — Notices of Violation Involving Co-Owned Plants

On March 13, 2008, Duke Energy Ohio Inc., the operator of the Zimmer generating station, received a NOV and a Finding of Violation 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.  DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of this matter.  Duke Energy Ohio Inc. is expected to act on behalf of itself and the co-owners with respect to this matter.  At this time, DP&L is unable to predict the outcome of this matter.

In June 2000, the USEPA issued a NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, CG&E, 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.  At this time, DP&L cannot predict the outcome of this matter.

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 CG&E (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 CG&E 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.

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In December 2007, the Ohio EPA issued a NOV to the DP&L-operated Killen generating station (co-owned by DP&L and CG&E) 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.

Air Quality — 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 CG&E) 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 2006.  DP&L has sufficient allowances in its general account to cover the understatement and is working with the USEPA to resolve the matter.  Management does not believe the ultimate resolution of this matter will have a material impact on results of operations, financial position or cash flows.

Air Quality — 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 has 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 New Source Review (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 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.

Water Quality

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 which it hopes to issue for public comment by mid-2010.

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 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 have 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 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 such as J.M. Stuart, Killen and O.H. Hutchings Stations.  The rulemaking will include 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 in 2011 with final regulations issued in late 2012 or early 2013.  At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

Land Use and Solid 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.  More recently, DP&L has received requests by the USEPA and the existing PRP group to allow access to be given to DP&L’s service center building site, which is across the street from the landfill site.  The USEPA requested access to drill monitoring and test wells to 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.  Pursuant to an Administrative Order issued by the USEPA requiring access to DP&L’s service center building site, DP&L has granted such access and drilling of soil borings and installation of monitoring wells occurred in the fall of 2009.  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.  While DP&L is unable at this time 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.  DP&L is also unable at this time to predict whether the monitoring and test wells may lead to any actions relating to the service center building site independent of the South Dayton Dump clean-up.

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 at this time 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.

In November 2007, a PRP group contacted DP&L seeking our financial participation in a settlement that the group had reached with the federal government with respect to the clean-up of an industrial site once owned by Carolina Transformer, Inc.  DP&L’s business records clearly show we did not conduct business with Carolina Transformer that would require our participation in any clean-up of the site.  DP&L has declined to participate in the clean-up of this site.  While DP&L is unable at this time 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.

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.  We frequently inspect our ash ponds and do not anticipate any similar failures.  It is widely expected that the federal government will propose new regulations covering ash generated from the combustion of coal and including additional monitoring, testing, or construction standards with respect to ash ponds and ash landfills.  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 addition, during August and October 2009, representatives of the USEPA visited J.M. Stuart Station to collect information on plant operations relative to the production and handling of by-products.  Due to the wide range of possible outcomes, DP&L is unable at this time to predict the timing or the financial impact of any future governmental initiative that may occur.

In addition, as a result of the TVA ash pond spill, there has been increasing advocacy to regulate coal combustion byproducts as hazardous waste under the Resource Conservation Recovery Act, Subtitle C.  On October 15, 2009, the USEPA provided a draft rule to the Office of Management and Budget for interagency review.  The draft rule proposed to regulate coal ash as a hazardous waste, with limited beneficial reuse.  DP&L is unable at this time 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.

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Legal and Other 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.  DP&L is unable to determine the ultimate resolution of this matter at this time.  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 expenses associated with our litigation against certain former executives.  Arbitration on that claim occurred on May 13, 2009.  The arbitration panel issued a ruling in Phase 1 of the arbitration on September 25, 2009, finding that most of the claims involving the former executives were covered.  The matter is pending.

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 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 on March 18, 2008 challenging the allocation method.  The appeal 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, will be able to file initial comments, testimony, and recommendations and reply comments.  Absent future changes to the procedural schedule that may occur for a number of reasons including if settlement discussions are held, the paper hearing process should be complete and the case ready for FERC consideration in 2010.  FERC did not establish a deadline for its issuance of a substantive order.  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 is already in place to pass through RTO-related costs and credits.

In June 2009, the NERC, a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, 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 Standards.  In response to the report, DP&L filed mitigation plans with NERC to address the PAVs.  These mitigation plans have been accepted and DP&L is currently awaiting a proposal for settlement from NERC.  While we are currently unable to determine the extent of penalties, if any, that may be imposed on DP&L, we do not believe such penalties will have a material impact on our results of operations.

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20.  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		2009		2008		2009		2008		2009		2008		2009		2008
Revenues		$	415.0	$	416.1	$	361.2	$	378.8	$	407.3	$	414.5	$	405.4	$	392.2
Operating income		127.0		142.7		81.9		85.6		116.5		96.2		102.8		111.0
Net income		$	69.2	$	77.3	$	42.1	$	47.6	$	67.9	$	48.0	$	49.9	$	71.6
Earnings per share of common stock:
Basic		$	0.62	$	0.71	$	0.38	$	0.43	$	0.60	$	0.44	$	0.43	$	0.64
Diluted		$	0.61	$	0.66	$	0.37	$	0.41	$	0.59	$	0.42	$	0.43	$	0.63
Dividends declared and paid per share		$	0.285	$	0.275	$	0.285	$	0.275	$	0.285	$	0.275	$	0.285	$	0.275
Common stock market price	— High	$	23.28	$	30.18	$	23.46	$	28.70	$	26.53	$	26.76	$	28.68	$	24.59
	— Low	$	19.27	$	24.58	$	21.18	$	26.10	$	22.79	$	23.00	$	25.16	$	19.16

DP&L

	For the three months ended
	March 31,				June 30,				September 30,				December 31,
$ in millions	2009		2008		2009		2008		2009		2008		2009		2008
Revenues	$	403.6	$	413.9	$	351.9	$	376.4	$	398.2	$	401.5	$	396.7	$	381.1
Operating income	$	124.8	$	146.4	$	78.9	$	90.5	$	115.2	$	93.5	$	103.0	$	106.2
Net income	$	77.0	$	89.0	$	46.8	$	63.3	$	74.0	$	54.8	$	61.1	$	78.7
Earnings on common stock	$	76.8	$	88.8	$	46.6	$	63.1	$	73.8	$	54.6	$	60.8	$	78.4
Dividends paid on common stock to parent	$	175.0	$	80.0	$	45.0	$	—	$	50.0	$	—	$	55.0	$	75.0

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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, 2009 and 2008, 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, 2009. 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, 2009, 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, 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 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, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Philadelphia, Pennsylvania
February 11, 2010

136

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, 2009 and 2008, 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, 2009. In connection with our audits of the financial statements, we have audited the financial statement schedule, “Schedule II — Valuation and Qualifying Accounts.” We also have audited DP&L’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). DP&L’s management is responsible for these financial statements, 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 financial statements and an opinion on DP&L’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 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 financial statements referred to above present fairly, in all material respects, the financial position of DP&L as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, DP&L maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Philadelphia, Pennsylvania

February 11, 2010

137

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, 2009.

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, 2009.

Our internal control over financial reporting as of December 31, 2009, 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.

138

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 2010 Annual Meeting of Shareholders to be held on April 28, 2010 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.

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 2009 and 2008.  Other than as set forth below, no professional services were rendered or fees billed by KPMG LLP during 2009 and 2008.

KPMG LLP	2009 Fees Billed		2008 Fees Billed
Audit Fees (1)	$	1,394,680	$	1,409,800
Audit-Related Fees (2)	46,000		84,800
Tax Fees (3)	7,870		—
All Other Fees	—		—
Total	$	1,448,550	$	1,494,600

(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.

139

PART IV

Item 15 — Exhibits and Financial Statement Schedules

(a)       The following documents are filed as part of this report:

	Page No.
1.             Financial Statements
DPL - Consolidated Statements of Results of Operations for each of the three years in the period ended December 31, 2009	67
DPL - Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2009	68
DPL - Consolidated Balance Sheets at December 31, 2009 and 2008	69
DPL - Consolidated Statement of Shareholders’ Equity for each of the three years in the period ended December 31, 2009	71
DP&L - Consolidated Statements of Results of Operations for each of the three years in the period ended December 31, 2009	72
DP&L - Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2009	73
DP&L - Consolidated Balance Sheets at December 31, 2009 and 2008	74
DP&L - Consolidated Statement of Shareholder’s Equity for each of the three years in the period ended December 31, 2009	76
Notes to Consolidated Financial Statements	77
DPL - Report of Independent Registered Public Accounting Firm	136
DP&L - Report of Independent Registered Public Accounting Firm	137
2.             Financial Statement Schedule
For each of the three years in the period ended December 31, 2009:
Schedule II — Valuation and Qualifying Accounts	151

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.

140

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)

141

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

142

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	Filed herewith as Exhibit 4(s)
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)

143

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	Filed herewith as Exhibit 10(f)
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)

144

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)

145

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	Filed herewith as Exhibit 10(w)
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)

146

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	Filed herewith as Exhibit 10(aa)
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)*	Participation Agreement dated January 3, 2008 among DPL Inc., The Dayton Power and Light Company and Douglas C. Taylor	Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2008 (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)

147

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location(1)
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)
	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)

* 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.

148

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 11, 2010	By:
		/s/ Paul M. Barbas
		Paul M. Barbas President and Chief Executive Officer
		(principal executive officer)

		The Dayton Power and Light Company
	By:
February 11, 2010		/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)

149

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 Executive Officer	February 10, 2010
(P.M. Barbas)	(principal executive officer)
/s/ R. D. Biggs	Director	February 10, 2010
(R. D. Biggs)
/s/ P. R. Bishop	Director and Vice-Chairman	February 10, 2010
(P. R. Bishop)
/s/ F.F. Gallaher	Director	February 10, 2010
(F.F. Gallaher)
/s/ B. S. Graham	Director	February 10, 2010
(B. S. Graham)
/s/ G.E. Harder	Director and Chairman	February 10, 2010
(G.E. Harder)
/s/ L.L. Lyles	Director	February 10, 2010
(L.L. Lyles)
/s/ P.B. Morris	Director	February 10, 2010
(P.B. Morris)
/s/ N.J. Sifferlen	Director	February 10, 2010
(N.J. Sifferlen)
/s/ F.J. Boyle	Senior Vice President, Chief Financial Officer and	February 10, 2010
(F.J. Boyle)	Treasurer (principal financial officer)
/s/ J.W. Mulpas	Vice President, Controller and Chief Accounting Officer	February 10, 2010
(J.W. Mulpas)	(principal accounting officer)

150

Schedule II

DPL Inc.

VALUATION AND QUALIFYING ACCOUNTS

For the years ended December 31, 2007 - 2009

$ in thousands

	Balance at
	Beginning				Deductions		Balance at
Description	of Period		Additions		(1)		End of Period
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
2007:
Deducted from accounts receivable — Provision for uncollectible accounts	$	1,430	$	5,678	$	5,590	$	1,518
Deducted from deferred tax assets — Valuation allowance for deferred tax assets	$	10,132	$	2,676	$	379	$	12,429

(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, 2007 - 2009

$ in thousands

	Balance at
	Beginning				Deductions		Balance at
Description	of Period		Additions		(1)		End of Period
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	$	—
2007:
Deducted from accounts receivable — Provision for uncollectible accounts	$	1,430	$	5,678	$	5,590	$	1,518
Deducted from deferred tax assets — Valuation allowance for deferred tax assets	$	277	$	71	$	—	$	348

(1) Amounts written off, net of recoveries of accounts previously written off.

151