DAYTON POWER & LIGHT CO - FORM 10-Q

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EX-32.D - EX-32.D - DAYTON POWER & LIGHT CO	a10-6123_1ex32dd.htm
EX-31.C - EX-31.C - DAYTON POWER & LIGHT CO	a10-6123_1ex31dc.htm
EX-32.C - EX-32.C - DAYTON POWER & LIGHT CO	a10-6123_1ex32dc.htm
EX-31.A - EX-31.A - DAYTON POWER & LIGHT CO	a10-6123_1ex31da.htm
EX-31.D - EX-31.D - DAYTON POWER & LIGHT CO	a10-6123_1ex31dd.htm
EX-31.B - EX-31.B - DAYTON POWER & LIGHT CO	a10-6123_1ex31db.htm
EX-32.B - EX-32.B - DAYTON POWER & LIGHT CO	a10-6123_1ex32db.htm
EX-32.A - EX-32.A - DAYTON POWER & LIGHT CO	a10-6123_1ex32da.htm

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

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

For the transition period from to

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

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

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

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

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

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

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

As of April 26, 2010, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, $0.01 par value	118,942,223

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

This combined Form 10-Q 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.

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DPL Inc. and The Dayton Power and Light Company

Index

		Page No.

Glossary of Terms		3

Part I Financial Information

Item 1	Financial Statements — DPL and DP&L

	Condensed Consolidated Statements of Results of Operations — DPL	6

	Condensed Consolidated Statements of Cash Flows — DPL	7

	Condensed Consolidated Balance Sheets — DPL	8

	Condensed Statements of Results of Operations — DP&L	10

	Condensed Statements of Cash Flows — DP&L	11

	Condensed Balance Sheets — DP&L	12

	Notes to Condensed Consolidated Financial Statements	14

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46

	Electric Sales and Revenues	69

Item 3	Quantitative and Qualitative Disclosures about Market Risk	70

Item 4	Controls and Procedures	70

Part II Other Information

Item 1	Legal Proceedings	70

Item 1A	Risk Factors	71

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	71

Item 3	Defaults Upon Senior Securities	71

Item 4	Removed and Reserved	71

Item 5	Other Information	71

Item 6	Exhibits	72

Other

Signatures		73

Certifications		74

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GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition
AOCI		Accumulated Other Comprehensive Income
ARO		Asset Retirement Obligation
ASU		Accounting Standards Update
BTU		British Thermal Units
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 that owns and operates peaking generation facilities from which it makes wholesale sales
DPLER		DPL Energy Resources, Inc., a wholly owned subsidiary of DPL that 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 that 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
Dth		Decatherm, the unit of measure for natural gas (1,000,000 BTU)
EIR		Environmental Investment Rider
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

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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.
TCRR		Transmission Cost Recovery Rider
USEPA		U.S. Environmental Protection Agency
USF		Universal Service Fund
VRDN		Variable Rate Demand Note

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DPL and DP&L file current, annual and quarterly reports, proxy statements (DPL only) 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 room. 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 46 for more information about forward-looking statements contained in this report.

Part 1 — Financial Information

This report includes the combined filing of DPL and DP&L. DP&L is the principal subsidiary of DPL providing approximately 97% of DPL’s total consolidated revenue and approximately 94% 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.

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Item 1 — Financial Statements

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended March 31,
$ in millions except per share amounts	2010			2009

Revenues	$	451.2		$	415.0

Cost of revenues:
Fuel	101.9			81.4
Purchased power	72.8			59.7
Total cost of revenues	174.7			141.1

Gross margin	276.5			273.9

Operating expenses:
Operation and maintenance	80.6			78.9
Depreciation and amortization	37.4			35.9
General taxes	32.5			32.1
Total operating expenses	150.5			146.9

Operating income	126.0			127.0

Other income / (expense), net:
Investment income	0.1			0.5
Interest expense	(17.9		)	(21.7		)
Other income (deductions)	(0.8		)	(0.2		)
Total other income / (expense), net	(18.6		)	(21.4		)

Earnings before income tax	107.4			105.6

Income tax expense	36.4			36.4
Net income	$	71.0		$	69.2

Average number of common shares outstanding (millions):
Basic	115.6			112.1
Diluted	116.2			112.7

Earnings per share of common stock:
Basic	$	0.61		$	0.62
Diluted	$	0.61		$	0.61

Dividends paid per share of common stock	$	0.3025		$	0.2850

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
$ in millions	2010			2009
Cash flows from operating activities:
Net income	$	71.0		$	69.2
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	37.4			35.9
Deferred income taxes	10.5			3.6
Unamortized investment tax credit	(0.7		)	(0.7		)
Changes in certain assets and liabilities:
Accounts receivable	(3.1		)	35.6
Inventories	3.0			(11.7		)
Taxes applicable to subsequent years	14.9			14.5
Deferred regulatory costs, net	(2.5		)	(22.4		)
Accounts payable	6.4			(44.8		)
Accrued taxes payable	(0.8		)	(3.1		)
Accrued interest payable	(5.6		)	(6.7		)
Pension, retiree and other benefits	(21.1		)	2.1
Insurance and claims costs	—			0.8
Other	13.2			1.0
Net cash provided by operating activities	122.6			73.3

Cash flows from investing activities:
Capital expenditures	(39.8		)	(50.2		)
Purchases of short-term investments and securities	(33.7		)	(5.1		)
Sales of short-term investments and securities	—			10.1
Other	2.2			2.3
Net cash used for investing activities	(71.3		)	(42.9		)

Cash flows from financing activities:
Dividends paid on common stock	(35.0		)	(32.1		)
Repurchase of warrants	—			(15.9		)
Retirement of long-term debt	—			(175.0		)
Withdrawal of restricted funds held in trust, net	—			6.7
Withdrawals from revolving credit facilities	—			150.0
Repurchase of DPL common stock	(3.9		)	—
Exercise of stock options	1.4			—
Tax impact related to exercise of stock options	0.2			—
Net cash used for financing activities	(37.3		)	(66.3		)

Cash and cash equivalents:
Net change	14.0			(35.9		)
Balance at beginning of period	74.9			62.5
Cash and cash equivalents at end of period	$	88.9		$	26.6

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	23.7		$	28.4
Income taxes refunded, net	$	5.1		$	5.0
Non-cash financing and investing activities:
Accruals for capital expenditures	$	13.3		$	15.9

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

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

ASSETS

Current assets:
Cash and cash equivalents	$	88.9		$	74.9
Short-term investments	33.7			—
Accounts receivable, net (Note 2)	221.3			212.8
Inventories (Note 2)	122.7			125.7
Taxes applicable to subsequent years	44.6			59.5
Other prepayments and current assets	30.8			24.1
Total current assets	542.0			497.0

Property, plant and equipment:
Property, plant and equipment	5,289.8			5,269.2
Less: Accumulated depreciation and amortization	(2,483.5		)	(2,466.0		)
	2,806.3			2,803.2

Construction work in process	85.7			89.0
Total net property, plant and equipment	2,892.0			2,892.2

Other noncurrent assets:
Regulatory assets (Note 3)	215.2			214.2
Other deferred assets	33.8			38.3
Total other noncurrent assets	249.0			252.5

Total Assets	$	3,683.0		$	3,641.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

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

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion - long-term debt			$	100.4		$	100.6
Accounts payable			81.5			77.2
Accrued taxes			69.6			70.2
Accrued interest			18.0			23.5
Customer security deposits			19.0			19.4
Other current liabilities			26.2			24.0
Total current liabilities			314.7			314.9

Noncurrent liabilities:
Long-term debt			1,223.6			1,223.5
Deferred taxes			582.0			569.1
Regulatory liabilities (Note 3)			127.9			125.4
Pension, retiree and other benefits			89.0			111.7
Unamortized investment tax credit			34.5			35.2
Insurance and claims costs			16.2			16.2
Other deferred credits			129.3			122.9
Total noncurrent liabilities			2,202.5			2,204.0

Redeemable preferred stock of subsidiary			22.9			22.9

Commitments and contingencies (Note 14)

Common shareholders’ equity:
Common stock, at par value of $0.01 per share:
	March 2010	December 2009
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	118,942,223	118,966,767	1.2			1.2
Warrants			2.9			2.9
Common stock held by employee plans			(18.4		)	(19.3		)
Accumulated other comprehensive loss			(22.7		)	(29.0		)
Retained earnings			1,179.9			1,144.1
Total common shareholders’ equity			1,142.9			1,099.9

Total Liabilities and Shareholders’ Equity			$	3,683.0		$	3,641.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended March 31,
$ in millions	2010			2009

Revenues	$	438.0		$	403.6

Cost of revenues:
Fuel	100.6			78.8
Purchased power	72.6			59.1
Total cost of revenues	173.2			137.9

Gross margin	264.8			265.7

Operating expenses:
Operation and maintenance	79.3			75.6
Depreciation and amortization	34.8			33.4
General taxes	32.3			31.9
Total operating expenses	146.4			140.9

Operating income	118.4			124.8

Other income / (expense), net:
Investment income	0.5			1.5
Interest expense	(9.4		)	(8.7		)
Other income (deductions)	(0.6		)	(0.2		)
Total other income / (expense), net	(9.5		)	(7.4		)

Earnings before income tax	108.9			117.4

Income tax expense	36.8			40.4

Net income	72.1			77.0

Dividends on preferred stock	0.2			0.2

Earnings on common stock	$	71.9		$	76.8

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
$ in millions	2010			2009
Cash flows from operating activities:
Net income	$	72.1		$	77.0
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	34.8			33.4
Deferred income taxes	9.9			3.3
Unamortized investment tax credit	(0.7		)	(0.7		)
Changes in certain assets and liabilities:
Accounts receivable	4.7			13.0
Net receivable due from parent	—			(10.0		)
Inventories	2.7			(11.7		)
Taxes applicable to subsequent years	14.8			14.5
Deferred regulatory costs, net	(2.5		)	(22.4		)
Accounts payable	6.0			(45.2		)
Accrued taxes payable	0.5			12.0
Accrued interest payable	2.2			2.4
Pension, retiree and other benefits	(21.1		)	2.1
Other	11.4			(3.4		)
Net cash provided by operating activities	134.8			64.3

Cash flows from investing activities:
Capital expenditures	(39.4		)	(48.9		)
Other	2.2			2.2
Net cash used for investing activities	(37.2		)	(46.7		)

Cash flows from financing activities:
Dividends paid on common stock to parent	(90.0		)	(175.0		)
Dividends paid on preferred stock	(0.2		)	(0.2		)
Withdrawal of restricted funds held in trust, net	—			6.7
Withdrawals from revolving credit facilities	—			150.0
Net cash used for financing activities	(90.2		)	(18.5		)

Cash and cash equivalents:
Net change	7.4			(0.9		)
Balance at beginning of period	57.1			20.8
Cash and cash equivalents at end of period	$	64.5		$	19.9

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	7.6		$	6.8
Income taxes refunded, net	$	5.1		$	5.1
Non-cash financing and investing activities:
Accruals for capital expenditures	$	13.3		$	15.9

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

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

ASSETS

Current assets:
Cash and cash equivalents	$	64.5		$	57.1
Accounts receivable, net (Note 2)	192.6			192.0
Inventories (Note 2)	121.6			124.3
Taxes applicable to subsequent years	44.4			59.2
Other prepayments and current assets	32.0			26.0
Total current assets	455.1			458.6

Property, plant and equipment:
Property, plant and equipment	5,030.9			5,011.0
Less: Accumulated depreciation and amortization	(2,386.1		)	(2,370.7		)
	2,644.8			2,640.3

Construction work in process	85.3			87.9
Total net property, plant and equipment	2,730.1			2,728.2

Other noncurrent assets:
Regulatory assets (Note 3)	215.2			214.2
Other deferred assets	50.8			56.4
Total other noncurrent assets	266.0			270.6

Total Assets	$	3,451.2		$	3,457.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

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

LIABILITIES AND SHAREHOLDER'S EQUITY

Current liabilities:
Current portion - long-term debt	$	100.4		$	100.6
Accounts payable	79.1			75.1
Accrued taxes	69.0			68.6
Accrued interest	15.4			13.1
Customer security deposits	18.9			19.4
Other current liabilities	25.6			23.2
Total current liabilities	308.4			300.0

Noncurrent liabilities:
Long-term debt	783.7			783.7
Deferred taxes	565.1			553.0
Regulatory liabilities (Note 3)	127.9			125.4
Pension, retiree and other benefits	89.0			111.7
Unamortized investment tax credit	34.5			35.2
Other deferred credits	129.3			122.9
Total noncurrent liabilities	1,729.5			1,731.9

Redeemable preferred stock	22.9			22.9

Commitments and contingencies (Note 14)

Common shareholder's equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	781.8			781.6
Accumulated other comprehensive loss	(13.9		)	(19.7		)
Retained earnings	622.1			640.3
Total common shareholder's equity	1,390.4			1,402.6

Total Liabilities and Shareholder's Equity	$	3,451.2		$	3,457.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

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 owns and operates peaking generating facilities from which it makes wholesale sales of electricity; 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.

DPL and its subsidiaries employed 1,586 persons as of March 31, 2010, of which 1,579 employees were employed by DP&L. Approximately 55% of the employees are under a collective bargaining agreement which expires in October 2011.

Financial Statement Presentation

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

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

All material intercompany accounts and transactions are eliminated in consolidation.

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These financial statements have been prepared in accordance with GAAP for interim financial statements and with the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

In the opinion of our management, the financial statements presented in this report contain all adjustments necessary to fairly state our financial condition as of March 31, 2010; our results of operations for the three months ended March 31, 2010; and our cash flows for the three months ended March 31, 2010. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three months ended March 31, 2010 may not be indicative of our results that will be realized for the full year ending December 31, 2010.

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.

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 during the three-month periods ended March 31, 2010 and 2009 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.

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.

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

Short-Term Investments

DPL has short-term investments consisting of VRDNs. These VRDNs are of high credit quality and are secured by irrevocable letters of credit from major financial institutions. These investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale upon notice (every seven days) back to the financial institution. Although DPL’s VRDNs have original maturities over one year, they are frequently re-priced and trade on a par-in par-out basis. We account for these VRDNs as available-for-sale securities and record them as short-term investments as they are highly liquid and are readily available to support DPL’s current operating needs.

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:

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	Three Months Ended
	March 31,
$ in millions	2010		2009
State/Local excise taxes	$	14.2	$	14.0

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 Condensed Consolidated Financial Statements. The following table provides a summary of these transactions:

	Three Months Ended March 31,
$ in millions	2010			2009

DP&L Revenues:
Sales to DPLER (a)	$	37.3		$	12.9

DP&L Operation & Maintenance Expenses:
Insurance services provided by MVIC (b)	$	(0.9	)	$	(0.9	)

(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. The increase in DP&L’s sales to DPLER during the three months ended March 31, 2010 compared to the similar period in 2009 is primarily due to customers electing to switch their generation service from DP&L to DPLER.

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

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Recently Adopted Accounting Standards

Variable Interest Entities

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

Fair Value Disclosures

We adopted ASU 2010-06 “Fair Value Measurements and Disclosures” (ASU 2010-06) effective for annual reporting periods beginning after December 15, 2009. 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 are presented separately. ASU 2010-06 did not have a material impact on our overall results of operations, financial position or cash flows. See Note 8 of Notes to Condensed Consolidated Financial Statements.

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2. Supplemental Financial Information and Comprehensive Income

DPL Inc.

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

Accounts receivable, net:
Unbilled revenue	$	59.0		$	74.9
Customer receivables	125.6			99.4
Amounts due from partners in jointly-owned plants	20.3			12.6
Coal sales	6.0			10.6
Other	11.4			16.4
Provision for uncollectible accounts	(1.0		)	(1.1		)
Total accounts receivable, net	$	221.3		$	212.8

Inventories, at average cost:
Fuel, limestone and emission allowances	$	81.4		$	85.8
Plant materials and supplies	38.4			38.5
Other	2.9			1.4
Total inventories, at average cost	$	122.7		$	125.7

DP&L

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

Accounts receivable, net:
Unbilled revenue	$	48.3		$	71.0
Customer receivables	114.3			94.4
Amounts due from partners in jointly-owned plants	20.3			12.6
Coal sales	6.0			10.6
Other	4.7			4.5
Provision for uncollectible accounts	(1.0		)	(1.1		)
Total accounts receivable, net	$	192.6		$	192.0

Inventories, at average cost:
Fuel, limestone and emission allowances	$	81.4		$	85.8
Plant materials and supplies	37.2			37.1
Other	3.0			1.4
Total inventories, at average cost	$	121.6		$	124.3

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Supplemental Financial Information and Comprehensive Income (continued)

DPL Inc.

	Three Months Ended March 31,
	2010		2009
Comprehensive income:
Net income	$	71.0	$	69.2
Net change in unrealized gains (losses) on financial instruments, net of income tax expense of $0.1 million and $0.1 million, respectively	0.2		(0.1		)
Net change in deferred gains (losses) on cash flow hedges, net of income tax expenses of $2.7 million and $0.5 million, respectively	4.3		(0.1		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax benefit of $0.6 million and income tax expense of $0.1 million, respectively	1.8		0.6
Comprehensive income	$	77.3	$	69.6

DP&L

	Three Months Ended March 31,
	2010			2009
Comprehensive income:
Net income	$	72.1		$	77.0
Net change in unrealized gains (losses) on financial instruments, net of income tax benefits of $0.2 million and $0.5 million, respectively	(0.3		)	(1.3		)
Net change in deferred gains (losses) on cash flow hedges, net of income tax expenses of $2.7 million and $0.5 million, respectively	4.3			(0.1		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax benefit of $0.6 million and income tax expense of $0.1 million, respectively	1.8			0.6
Comprehensive income	$	77.9		$	76.2

3. Regulatory Matters

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

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

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Regulatory assets and liabilities on the condensed consolidated balance sheets include:

$ in millions	Type of Recovery (a)	Amortization Through	At March 31, 2010		At December 31, 2009
Regulatory Assets:
Deferred recoverable income taxes	C/B	Ongoing	$	37.1	$	36.8
Pension benefits	C	Ongoing	83.6		85.2
Unamortized loss on reacquired debt	C	Ongoing	15.3		15.6
Electric Choice systems costs	F	2011	3.1		4.0
Regional transmission organization costs	D	2014	6.6		7.0
TCRR, transmission, ancillary and other PJM-related costs	F	2011	12.0		5.5
RPM capacity costs	F	2011	16.3		20.0
Deferred storm costs - 2008	D		16.2		16.0
Power plant emission fees	C	Ongoing	6.2		6.3
CCEM smart grid and advanced metering infrastructure costs	D		6.6		6.5
CCEM energy efficiency program costs	F	Ongoing	1.4		3.6
Other costs			10.8		7.7
Total regulatory assets			$	215.2	$	214.2

Regulatory Liabilities:
Estimated costs of removal - regulated property			$	103.5	$	99.1
SECA net revenue subject to refund			20.1		20.1
Postretirement benefits			4.3		5.1
Other costs			—		1.1
Total regulatory liabilities			$	127.9	$	125.4

(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.

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.

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

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 June 2009, DP&L began recovery of these costs. In a subsequent rehearing process, DP&L was ordered to separate the costs into two separate riders (a TCRR and a PJM RPM rider) which were approved 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. The deferral of these costs, net of recoveries, resulted in a favorable impact to our results of operations in 2009.

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 the rate on an annual basis.

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

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

CCEM smart grid and 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. 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. We are discussing a possible settlement of this case with the PUCO staff and interveners. Based on past PUCO precedent and the Ohio legislature’s intent behind SB 221, we believe these costs are probable of future recovery in rates.

CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. 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 their over/under recovery.

Other costs primarily include consumer education advertising costs regarding electric deregulation, settlement system costs, other PJM and rate case costs, derivative activity related to fuel costs that will be recovered over various periods 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 revenues and costs that were billed to PJM transmission customers and paid to transmission owners during 2005 and 2006, but which remain subject to litigation before the FERC and potential reversal. DP&L is both a transmission customer and a transmission owner. SECA revenue and expenses represent FERC-ordered transitional payments for the use of transmission lines within PJM. An initial decision by an Administrative Law Judge was issued in 2006, and was appealed by many parties to the FERC, which has not yet issued a ruling on appeal. We began receiving and paying these transitional payments in May 2005.

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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.

4. Ownership of Coal-fired Facilities

DP&L with certain other Ohio utilities has 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 March 31, 2010, we had $45 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 Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

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

	DP&L Share		DP&L Investment
									SCR and FGD
									Equipment
							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	$	76	$	54	$	1	No
Conesville Unit 4	16.5	129	118		24		3		Yes
East Bend Station	31.0	186	200		130		1		Yes
Killen Station	67.0	402	605		280		5		Yes
Miami Fort Units 7 and 8	36.0	368	345		125		10		Yes
Stuart Station	35.0	820	688		254		18		Yes
Zimmer Station	28.1	365	1,057		600		7		Yes
Transmission (at varying percentages)			90		52		—
Total		2,480	$	3,179	$	1,519	$	45

Wholly-owned production unit:
Hutchings Station	100.0	388	$	122	$	109	$	—	No

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

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5. Debt Obligations

Long-term Debt

	At			At
	March 31,			December 31,
$ in millions	2010			2009
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
	784.4			784.4

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

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			142.6
Unamortized debt discount	(0.1		)	(0.2		)
Total long-term debt - DPL	$	1,223.6		$	1,223.5

Current portion - Long-term Debt

	At		At
	March 31,		December 31,
$ in millions	2010		2009
DP&L
Pollution control series maturing 2040 - variable rates: 0.16% - 0.35% and 0.24% - 0.85% (a) (b)	$	100.0	$	100.0
Obligation for capital lease	0.4		0.6
Total current portion - long-term debt - DP&L and DPL	$	100.4	$	100.6

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

(b) Shown as current since LOC facility will expire in December 2010, at which point the bondholders could put the bonds to DP&L. Management continues to monitor and evaluate market conditions and intends to seek a renewal of this standby LOC.

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

$ in millions	DPL		DP&L
3/31/2011 (a)	$	100.4	$	100.4
3/31/2012	297.4		—
3/31/2013	—		—
3/31/2014	470.0		470.0
3/31/2015	—		—
Thereafter	457.0		314.4
	$	1,324.8	$	884.8

(a) $100 million variable rate pollution control series note maturing 2040 shown as current since LOC facility will expire in December 2010, at which point the bondholders could put the bonds to DP&L. Management continues to monitor and evaluate market conditions and intends to seek a renewal of this standby LOC.

Debt and Debt Covenants

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 March 31, 2010, this covenant is met with a ratio of 0.4 to 1.00. DP&L had no outstanding borrowings under this credit facility at March 31, 2010. Fees associated with this credit facility were approximately $0.2 million during the three months ended March 31, 2010. Changes in DP&L’s credit ratings may affect fees and the applicable interest. This revolving credit agreement contains a $50 million letter of credit sublimit. As of March 31, 2010, DP&L had no outstanding letters of credit against the facility.

On December 4, 2008, the OAQDA issued $100 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA. 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 put the bonds to DP&L, 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 intends to 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.

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

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

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group. The agreement was for a 364-day term and expired on April 20, 2010. The facility contained one financial covenant: DP&L’s total debt to total capitalization ratio was not to exceed 0.65 to 1.00. As of March 31, 2010, this covenant was met with a ratio of 0.4 to 1.00. As of March 31, 2010, there were no borrowings outstanding under this facility. Fees associated with this credit facility were less than $0.1 million during the three months ended March 31, 2010.

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On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. The facility contains one financial covenant:

DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. This facility also contains a $50 million letter of credit sublimit.

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

6. Income Taxes

The following table details the effective tax rates for the three months ended March 31, 2010 and 2009.

	Three Months Ended
	March 31,
	2010		2009

DPL	33.9	%	34.5	%

DP&L	33.8	%	34.4	%

Income tax expenses for the three months ended March 31, 2010 and 2009 reflect estimated annual effective income tax rates of 33.0% and 34.2%, respectively. Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates recognized.

Income tax expenses for the three months ended March 31, 2010 and 2009 were calculated using the estimated annual effective income tax rates for 2010 and 2009, respectively.

For the three months ended March 31, 2010, the decrease in DPL’s effective tax rate compared to the same period in 2009 primarily reflects the increased benefits from the Section 199 Domestic Production Deduction. The decrease in DP&L’s effective tax rate primarily reflects the increased benefits from the Section 199 Domestic Production Deduction.

Deferred tax liabilities for both DPL and DP&L increased by approximately $12.9 million and $12.1 million, respectively, during the three months ended March 31, 2010. These increases were related to a $7.0 million temporary difference due to a pension contribution and other temporary differences arising from routine changes in balance sheet accounts giving rise to deferred taxes.

We have been advised by the Internal Revenue Service that our 2008 Federal income tax return will be examined. At this time, we do not expect the results of this examination to have a material impact on our financial statements.

7. 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.

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 benefits using a Voluntary Employee Beneficiary Association Trust.

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The amounts presented in the following tables for pension include both the defined benefit pension plan and the SERP in the aggregate, and the amounts presented for postretirement include both health and life insurance.

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months ended March 31, 2010 and 2009 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
$ in millions	2010			2009			2010			2009
Service cost	$	1.1		$	0.9		$	—		$	—
Interest cost	4.5			4.4			0.4			0.4
Expected return on assets (a)	(5.6		)	(5.6		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Actuarial (gain) / loss	1.8			1.1			(0.3		)	(0.2		)
Prior service cost	1.0			0.8			0.1			—
Net periodic benefit cost / (income) before adjustments	$	2.8		$	1.6		$	0.1		$	0.1

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

In February 2010, DP&L contributed $20.0 million to the defined benefit plan.

Estimated Future Benefit Payments

$ in millions	Pension		Postretirement

2010	$	15.9	$	1.9
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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8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. 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 March 31, 2010 and December 31, 2009. See also Note 9 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.

	At March 31,				At December 31,
	2010				2009
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities	2.9		3.2		2.6		2.8
Debt Securities	5.3		5.5		5.3		5.4
Multi-Strategy Fund	0.3		0.2		0.3		0.3
Total Master Trust Assets	$	10.1	$	10.5	$	12.3	$	12.6

Short-term investments - VRDNs	$	33.7	$	33.7	$	—	$	—

Total Assets	$	43.8	$	44.2	$	12.3	$	12.6

Liabilities
Debt	$	1,324.0	$	1,314.8	$	1,324.1	$	1,317.6

DP&L
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities (a)	16.7		30.5		16.7		31.1
Debt Securities	5.3		5.5		5.3		5.4
Multi-Strategy Fund	0.3		0.2		0.3		0.3
Total Master Trust Assets	$	23.9	$	37.8	$	26.4	$	40.9

Liabilities
Debt	$	884.1	$	854.5	$	884.3	$	844.5

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

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 2011 to 2040.

Master Trust Assets

DP&L established a Master Trust to hold assets for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds and DPL common stock. The DPL common stock held by the DP&L Master Trust is eliminated in consolidation and is not reflected in DPL’s Condensed 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. Any unrealized gains or losses are recognized in AOCI until the securities are sold.

DPL had $0.5 million ($0.3 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at March 31, 2010 and $0.3 million ($0.2 million after tax) in unrealized gains and no unrealized losses in AOCI at December 31, 2009.

DP&L has $14.1 million ($9.2 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at March 31, 2010 and $14.5 million ($9.5 million after tax) in unrealized gains and no unrealized losses in AOCI at December 31, 2009.

No unrealized gains or losses are expected to be transferred to earnings in the next twelve months.

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Short-Term Investments

DPL has short-term investments consisting of variable rate demand notes (VRDNs). DPL’s VRDNs are of high credit quality and secured by irrevocable letters of credit from major financial institutions. These investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale upon notice (every seven days) back to the financial institution. Although DPL’s VRDNs have original maturities over one year, they are frequently re-priced and traded on a par-in par-out basis. The VRDNs are considered available-for-sale securities and classified as short-term investments as they are highly liquid and readily available to support the Company’s current operating needs.

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 March 31, 2010. These assets are part of the Master Trust and exclude DPL common stock which is valued using quoted market prices and not the NAV. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of March 31, 2010, DPL did not have any investments for sale at a price different than the NAV.

Fair Value Estimated using Net Asset Value per Unit

$ in millions	Fair Value at March 31, 2010		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
Money Market Fund (a)	$	1.6	$	—	Immediate	None

Equity Securities (b)	3.2		—		Immediate	None

Debt Securities (c)	5.5		—		Immediate	None

Multi-Strategy Fund (d)	0.2		—		Immediate	None

Total	$	10.5	$	—

(a) This category includes investments in high-quality, short-term securities. Investments in this category can be redeemed immediately at the current net asset value per unit.

(b) This category includes investments in hedge funds representing an S&P 500 index and the Morgan Stanley Capital International (MSCI) U.S. Small Cap 1750 Index. Investments in this category can be redeemed immediately at the current net asset value per unit.

(c) This category includes investments in U.S. Treasury obligations and U.S. investment grade bonds. Investments in this category can be redeemed immediately at the current net asset value per unit.

(d) This category includes investments in stocks, bonds and short-term investments in a mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. These inputs are then categorized as Level 1 (quoted prices in active markets for identical assets or liabilities); Level 2 (observable inputs such as quoted prices for similar assets or liabilities or quoted prices in markets that are not active); or Level 3 (unobservable inputs).

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using the Global Corporate Cumulative Average Default Rates.

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy.

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The fair value of assets and liabilities at March 31, 2010 and December 31, 2009 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
$ in millions	Fair Value at March 31, 2010		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Fair Value on Balance Sheet at March 31, 2010
Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities	3.2		—		3.2		—		—			3.2
Debt Securities	5.5		—		5.5		—		—			5.5
Mutli-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	10.5	$	—	$	10.5	$	—	$	—		$	10.5

Derivative Assets
FTRs	$	0.4	$	—	$	0.4	$	—	$	—		$	0.4
Forward NYMEX Coal Contracts	3.7		—		3.7		—		(1.6		)	2.1
Forward Power Contracts	8.8		—		8.8		—		(1.4		)	7.4
Total Derivative Assets	$	12.9	$	—	$	12.9	$	—	$	(3.0	)	$	9.9

Short-term investments - VRDNs	$	33.7	$	—	$	33.7	$	—	$	—		$	33.7

Total Assets	$	57.1	$	—	$	57.1	$	—	$	(3.0	)	$	54.1

Liabilities
Derivative Liabilities
Heating Oil Futures	$	0.4	$	0.4	$	—	$	—	$	(0.4	)	$	—
Natural Gas Futures	1.0		1.0		—		—		(1.0		)	—
Forward Power Contracts	2.4		—		2.4		—		(0.5		)	1.9
Forward NYMEX Coal Contracts	11.0		—		11.0		—		(5.1		)	5.9
Total Derivative Liabilities	$	14.8	$	1.4	$	13.4	$	—	$	(7.0	)	$	7.8

Total Liabilities	$	14.8	$	1.4	$	13.4	$	—	$	(7.0	)	$	7.8

*Includes credit valuation adjustments for counterparty risk.

DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2009		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Balance Sheet at December 31, 2009
Assets
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities	2.8		—		2.8		—		—			2.8
Debt Securities	5.4		—		5.4		—		—			5.4
Mutli-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	12.6	$	—	$	12.6	$	—	$	—		$	12.6

Derivative Assets
FTRs	$	0.8	$	—	$	0.8	$	—	$	—		$	0.8
Forward NYMEX Coal Contracts	5.5		—		5.5		—		(1.4		)	4.1
Forward Power Contracts	0.7		—		0.7		—		(0.7		)	—
Total Derivative Assets	$	7.0	$	—	$	7.0	$	—	$	(2.1	)	$	4.9

Total Assets	$	19.6	$	—	$	19.6	$	—	$	(2.1	)	$	17.5

Liabilities
Derivative Liabilities
Heating Oil Futures	$	1.2	$	1.2	$	—	$	—	$	(1.2	)	$	—
Forward Power Contracts	3.0		—		3.0		—		(0.7		)	2.3
Forward NYMEX Coal Contracts	1.2		—		1.2		—		—			1.2
Total Derivative Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

Total Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

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The fair value of assets and liabilities at March 31, 2010 and December 31, 2009 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows:

DP&L

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3
$ in millions	Fair Value at March 31, 2010		Based on Quoted Prices in Active Market		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Fair Value on Balance Sheet at March 31, 2010
Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities (a)	30.5		27.3		3.2		—		—			30.5
Debt Securities	5.5		—		5.5		—		—			5.5
Mutli-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	37.8	$	27.3	$	10.5	$	—	$	—		$	37.8

Derivative Assets
FTRs	$	0.4	$	—	$	0.4	$	—	$	—		$	0.4
Forward NYMEX Coal Contracts	3.7		—		3.7		—		(1.6		)	2.1
Forward Power Contracts	8.8		—		8.8		—		(1.4		)	7.4
Total Derivative Assets	$	12.9	$	—	$	12.9	$	—	$	(3.0	)	$	9.9

Total Assets	$	50.7	$	27.3	$	23.4	$	—	$	(3.0	)	$	47.7

Liabilities
Derivative Liabilities
Heating Oil Futures	$	0.4	$	0.4	$	—	$	—	$	(0.4	)	$	—
Natural Gas Futures	1.0		1.0		—		—		(1.0		)	—
Forward Power Contracts	2.4		—		2.4		—		(0.5		)	1.9
Forward NYMEX Coal Contracts	11.0		—		11.0		—		(5.1		)	5.9
Total Derivative Liabilities	$	14.8	$	1.4	$	13.4	$	—	$	(7.0	)	$	7.8

Total Liabilities	$	14.8	$	1.4	$	13.4	$	—	$	(7.0	)	$	7.8

*Includes credit valuation adjustments for counterparty risk.

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

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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
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities (a)	31.1		28.3		2.8		—		—			31.1
Debt Securities	5.4		—		5.4		—		—			5.4
Mutli-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	40.9	$	28.3	$	12.6	$	—	$	—		$	40.9

Derivative Assets
FTRs	$	0.8	$	—	$	0.8	$	—	$	—		$	0.8
Forward NYMEX Coal Contracts	5.5		—		5.5		—		(1.4		)	4.1
Forward Power Contracts	0.7		—		0.7		—		(0.7		)	—
Total Derivative Assets	$	7.0	$	—	$	7.0	$	—	$	(2.1	)	$	4.9

Total Assets	$	47.9	$	28.3	$	19.6	$	—	$	(2.1	)	$	45.8

Liabilities
Derivative Liabilities
Heating Oil Futures	$	1.2	$	1.2	$	—	$	—	$	(1.2	)	$	—
Forward Power Contracts	3.0		—		3.0		—		(0.7		)	2.3
Forward NYMEX Coal Contracts	1.2		—		1.2		—		—			1.2
Total Derivative Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

Total Liabilities	$	5.4	$	1.2	$	4.2	$	—	$	(1.9	)	$	3.5

*Includes credit valuation adjustments for counterparty risk.

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

We use the market approach to value our financial instruments. Level 1 inputs are used for DPL common stock held by the Master Trust and for derivative contracts such as heating oil futures and natural gas futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as financial transmission rights where the quoted prices are from a relatively inactive market; forward power contracts and forward NYMEX-quality coal contracts which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market; VRDNs which are priced using recent transactions for similar assets; and open-ended mutual funds that are in the Master Trust valued using the end of day NAV.

Approximately 95% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring fair value measurements

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. We added additional layers to our existing landfill AROs in the amount of $0.5 million during the three months ended March 31, 2010.

DPL had $12.3 million and $45.3 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009, respectively. The money market funds have quoted prices that are generally equivalent to par.

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9. Derivative Instruments and Hedging Activities

In the normal course of business, DPL and DP&L enter into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. 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 March 31, 2010, 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	3.7	—		3.7
Heating Oil Futures	Mark to Market	Gallons	2,478.0	—		2,478.0
Natural Gas Futures	Mark to Market	Dth	1,290.0	—		1,290.0
Forward Power Contracts	Cash Flow Hedge	MWH	434.4	(1,586.6	)	(1,152.2	)
Forward Power Contracts	Mark to Market	MWH	—	(172.8	)	(172.8	)
NYMEX-quality Coal Contracts*	Mark to Market	Tons	3,782.0	(961.0	)	2,821.0

*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 using specific identification of each contract 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 certain forward power contracts and in 2003 we entered into an interest rate swap which was settled that same year. Approximately $7.4 million ($4.8 million net of tax) of accumulated gains 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 March 31, 2010, the maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions is 33 months and 101 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:

	March 31,						March 31,
	2010						2009
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(1.4	)	$	14.7		$	(0.2	)	$	17.2

Net gains / (losses) associated with current period hedging transactions	5.2			—			1.1			—

Net gains reclassified to earnings
Interest expense	—			(0.6		)	—			(0.6		)
Revenues	(0.2		)	—			(0.4		)	—

Ending accumulated derivative gain / (loss) in AOCI	$	3.6		$	14.1		$	0.5		$	16.6

Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest expense	—			—			—			—
Revenues	—			—			—			—

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The following tables show the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments for the three months ended March 31, 2010 and year ended December 31, 2009.

Fair Values of Derivative Instruments Designated as Hedging Instruments

At March 31, 2010

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-Term Derivative Positions
Forward Power Contracts in an Asset position	$	7.9		$	(0.5	)	Other prepayments and current assets	$	7.4
Forward Power Contracts in a Liability position	(0.5		)	0.5			Other current liabilities	—
Total Short-Term Cash Flow Hedges	$	7.4		$	—			$	7.4

Long-Term Derivative Positions
Forward Power Contracts in a Liability position	(1.9		)	—			Other deferred credits	(1.9		)
Total Long-Term Cash Flow Hedges	$	(1.9	)	$	—			$	(1.9	)
Total Cash Flow Hedges	$	5.5		$	—			$	5.5

*Includes counterparty and collateral netting.

Fair Values of Derivative Instruments 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
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 and collateral 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 mark to market Financial Transmission Rights (FTRs), heating oil futures, forward NYMEX-quality coal contracts, natural gas futures and certain forward power contracts.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided 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 rider approved by the PUCO which began 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 tables show the amount and classification within the Condensed Statements of Results of Operations or Condensed Balance Sheets of gains and losses on DP&L’s derivatives not designated as hedging instruments for the three months ended March 31, 2010 and 2009.

For the three months ended March 31, 2010

$ in millions	NYMEX Coal*			Heating Oil			FTRs			Power			Natural Gas			Total
Change in unrealized gain / (loss)	$	(11.5	)	$	0.8		$	(0.4	)	$	1.1		$	(1.0	)	$	(11.0	)
Realized gain / (loss)	(0.7		)	(0.5		)	(0.7		)	(0.1		)	—			(2.0		)
Total	$	(12.2	)	$	0.3		$	(1.1	)	$	1.0		$	(1.0	)	$	(13.0	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(6.0	)	$	—		$	—		$	—		$	—		$	(6.0	)
Regulatory (asset) / liability	(3.7		)	0.3			—			—			—			(3.4		)

Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	—		$	—		$	—		$	1.0		$	—		$	1.0
Purchased power	—			—			(1.1		)	—			—			(1.1		)
Fuel	(2.5		)	(0.2		)	—			—			(1.0		)	(3.7		)
O&M	—			0.2			—			—			—			0.2
Total	$	(12.2	)	$	0.3		$	(1.1	)	$	1.0		$	(1.0	)	$	(13.0	)

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

For the three months ended March 31, 2009

$ in millions	NYMEX Coal*			Heating Oil			FTRs			Total
Change in unrealized gain / (loss)	$	(1.2	)	$	—		$	—		$	(1.2	)
Realized gain / (loss)	1.0			(1.1		)	(0.1		)	(0.2		)
Total	$	(0.2	)	$	(1.1	)	$	(0.1	)	$	(1.4	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(0.7	)	$	—		$	—		$	(0.7	)
Regulatory (asset) / liability	1.2			(2.0		)	—			(0.8		)

Recorded in Income Statement: gain / (loss)
Purchased power	$	—		$	—		$	(0.1	)	$	(0.1	)
Fuel	(0.7		)	1.1			—			0.4
O&M	—			(0.2		)	—			(0.2		)
Total	$	(0.2	)	$	(1.1	)	$	(0.1	)	$	(1.4	)

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

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The following tables show the fair value and balance sheet classification of DP&L’s derivative instruments not designated as hedging instruments at March 31, 2010 and December 31, 2009.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

At March 31, 2010

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.4		$	—		Other prepayments and current assets	$	0.4
Forward Power Contracts in an Asset position	0.9			(0.9		)	Other prepayments and current assets	—
NYMEX-Quality Coal Forwards in an Asset position	2.8			(0.7		)	Other prepayments and current assets	2.1
NYMEX-Quality Coal Forwards in a Liability position	(2.7		)	1.6			Other current liabilities	(1.1		)
Heating Oil Futures in a Liability position	(0.4		)	0.4			Other current liabllities	—
Natural Gas Futures in a Liability position	(1.0		)	1.0			Other current liabilities	—
Total short-term derivative MTM positions	$	—		$	1.4			$	1.4

Long-term Derivative Positions
NYMEX-Quality Coal Forwards in an Asset position	$	0.9		$	(0.9	)	Other deferred assets	$	—
NYMEX-Quality Coal Forwards in a Liability position	(8.3		)	3.5			Other deferred credits	(4.8		)
Total long-term derivative MTM positions	$	(7.4	)	$	2.6			$	(4.8	)

Total MTM Position	$	(7.4	)	$	4.0			$	(3.4	)

*Includes counterparty and collateral netting.

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
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		)
Heating Oil Futures in a Liability position	(1.2		)	1.2			Other current liabllities	—
Forward Power Contracts in a Liability position	(0.2		)	—			Other current liabilities	(0.2		)
Total short-term derivative MTM positions	$	0.8		$	1.0			$	1.8

Long-term Derivative Positions
NYMEX-Quality Coal Forwards in an Asset position	$	2.9		$	(1.2	)	Other deferred assets	$	1.7
Total long-term derivative MTM positions	$	2.9		$	(1.2	)		$	1.7

Total MTM Position	$	3.7		$	(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 March 31, 2010 is $14.9 million. This amount is offset by $5.1 million in a broker margin account which offsets our loss positions on the NYMEX Clearport traded heating oil, coal, and natural gas contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $3.3 million. If our debt were to fall below investment grade, we would have to post collateral for the remaining $6.5 million.

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10. Share-Based Compensation

Share-based compensation expense was not significant for the three months ended March 31, 2010 and 2009.

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.

Summarized share-based compensation activity for the three months ended March 31, 2010 and 2009 was as follows:

	Options			RSUs		Performance Shares
	2010		2009	2010	2009	2010		2009
Outstanding at beginning of year	417,500		836,500	3,311	10,120	237,704		156,300
Granted	—		—	—	—	117,636		115,357
Dividends	—		—	—	—	—		—
Exercised	(66,000	)	—	—	—	(47,355	)	—
Expired	—		—	—	—	—		(36,445	)
Forfeited	—		—	—	—	—		—
Outstanding at period end	351,500		836,500	3,311	10,120	307,985		235,212
Exercisable at period end	351,500		836,500	—	—	—		—

					Management Performance
	Restricted Shares				Shares
	2010		2009		2010		2009
Outstanding at beginning of year	218,197		69,147		84,241		39,144
Granted	10,588		—		37,480		48,719
Dividends	—		—		—		—
Exercised	(9,003	)	(1,000	)	—		—
Expired	—		—		—		—
Forfeited	—		—		(11,015	)	—
Outstanding at period end	219,782		68,147		110,706		87,863
Exercisable at period end	—		—		—		—

	Director RSUs
	2010		2009
Outstanding at beginning of year	20,712		15,546
Granted	—		—
Dividends accrued	471		316
Exercised and issued	—		—
Exercised and deferred	(239	)	(95	)
Forfeited	—		—
Outstanding at period end	20,944		15,767
Exercisable at period end	—		—

11. Common Shareholders’ Equity

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 145,915 shares during the three months ended March 31, 2010 at an average per share price of $26.71, effectively utilizing the entire $3.9 million that was available to repurchase stock at December 31, 2009. However, additional funds could be available to repurchase stock if the 1.8 million warrants outstanding at March 31, 2010 are exercised for cash in the future.

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12. 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 the three months ended March 31, 2010 and 2009. 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:

Three Months Ended March 31,

2010

2009

$ and shares in millions except

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

71.0

115.6

0.61

69.2

112.1

0.62

Effect of Dilutive Securities:

Warrants

0.4

0.5

Stock options, performance and restricted shares

0.2

0.1

Diluted EPS

71.0

116.2

0.61

69.2

112.7

0.61

13. Insurance Recovery

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim. The proceeds from the settlement amounted to $3.4 million, net of associated expenses, and were recorded as a reduction to operation and maintenance expense during the three months ended March 31, 2010.

14. Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned generating 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. There have been no material changes to our guarantees as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Through March 31, 2010, neither DPL nor DP&L have incurred any losses related to the guarantees of DPLE’s and DPLER’s obligations and we believe it is unlikely that either DPL or DP&L would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s and DPLER’s obligations.

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 March 31, 2010, DP&L could be responsible for the repayment of 4.9%, or $54.0 million, of a $1,103 million debt obligation that matures in 2026. This would only happen if this electric generation company defaulted on its debt payments. As of March 31, 2010, we have no knowledge of such a default.

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Other than the guarantees discussed in our Annual Report on Form 10-K and the guarantees discussed above, DPL and DP&L do not have any other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commercial Commitments and Contractual Obligations

There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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 Condensed 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 discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of March 31, 2010, cannot be reasonably determined.

Environmental Matters

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. As of March 31, 2010, 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 (NSR) requirements, including the imposition of stricter emission limits. On December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. On June 6, 2005, the USEPA issued its final response on the reconsideration of the ERP exclusion. The USEPA clarified its position, but did not change any aspect of the 2003 final rules. This decision was appealed and the D.C. Circuit vacated the final rules on March 17, 2006. The scope of the RMRR exclusion remains uncertain due to this action by the D.C. Circuit, as well as multiple litigations not directly involving us where courts are defining the scope of the exception with respect to the specific facts and circumstances of the particular power plants and activities before the courts. While we believe that we have not engaged in any activities with respect to our existing power plants that would trigger the NSR requirements, if NSR requirements were imposed on any of DP&L’s existing power plants, the results could 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 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.

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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 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. 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 NOx emission allowances and SO2 emission allowances that were the subject of CAIR trading programs. In subsequent quarters, DP&L recognized gains from the sale of excess emission allowances to third parties. The court’s CAIR decision affected the trading market for excess allowances and impacted DP&L’s program for selling additional excess allowances in 2008. 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 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.

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

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. 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 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 has been properly computing and reporting NOx emissions under the consent decree, but has agreed to participate in settlement discussions with the Sierra Club. A proposed settlement has been tentatively agreed upon by both parties. If finalized, an amendment to the Consent Decree will incorporate the terms of the settlement agreement which are not expected to have a material effect on DP&L’s results of operations, financial position or cash flows in the future.

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 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.

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 continued to submit various other operational and performance data to the USEPA in compliance with its request. DP&L is currently unable to determine the timing, costs or method by which the issues may be resolved and continues to work with the USEPA on this issue.

On November 18, 2009, the USEPA issued a NOV to DP&L for alleged NSR violations of the CAA at the O.H. Hutchings Station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that 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.

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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 the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA 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. 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.

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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. 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 initiatives to more stringently regulate ash ponds or the ultimate disposal of coal combustion products.

During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart stations. Subsequently the USEPA collected similar information for O.H. Hutchings Station. In October 2009, USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds and has requested a response. DP&L is reviewing the report and will be providing a reply to the agency. At this time, DP&L is not able to predict the cost to address any of the report’s recommendations.

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. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

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

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. Rehearing requests 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. PJM made an informational filing on April 13, 2010 that quantified the differences in the levels of allocated costs among PJM member transmission owners depending on the allocation methodology used. 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, new credits or additional costs resulting from the ultimate outcome of this proceeding should be recoverable through DP&L’s TCRR rider which is already in place to pass through RTO-related costs and credits.

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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.

Item 2. 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 97% of DPL’s total consolidated revenue and approximately 94% 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 Condensed Consolidated Financial Statements and related footnotes included in Part I — Financial Information.

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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.

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.

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

REGULATORY ENVIRONMENT

· 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 on December 15, 2009. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. In December 2009, USEPA finalized this endangerment finding with a regulatory effective date of January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision. This endangerment finding, if not changed, is expected to lead to the regulation of CO2 and other GHGs from electric generating units and other stationary sources of these emissions. 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.

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· 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. DP&L filed its comments and reply comments along with other interested parties. A question and answer session was held before the Commission on April 1, 2010 to allow the Commission to gain a better understanding of the issues. DP&L’s Stipulation provides that the SEET does not apply to DP&L until 2013 based on 2012 earnings results.

· 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. 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. 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.

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.

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· 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 quarter ended March 31, 2010, one additional unaffiliated marketer registered as a CRES provider in DP&L’s service territory, bringing the total number of unaffiliated CRES providers in DP&L’s service territory to seven. There has been a slight increase in customer switching associated with unaffiliated marketers representing less than 0.1% of sales during the quarter ended March 31, 2010. DPLER, an affiliated company, is also a registered CRES provider and accounted for approximately 720 million kWh of the total 723 million kWh supplied by CRES providers within DP&L’s service territory in the quarter ended March 31, 2010.

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.

In addition, during the quarter ended March 31, 2010, DPLER began 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.

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. 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 fully 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. Effective January 2010, the Ohio retail jurisdictional share of fuel price changes is reflected in the operation of the fuel rider, subject to PUCO review.

· Sales of Coal and Excess Emission Allowances

During the three months ended March 31, 2010, DP&L sold coal and excess emission allowances to various counterparties realizing total net gains of $0.2 million and $0.2 million, respectively, compared to total net gains of $20.7 million and $2.2 million, respectively, realized over the same period in 2009. 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: price volatility within the different grades of coal based on market conditions, 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. Effective 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 are used to reduce the overall rate charged to customers.

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OHIO REGULATORY MATTERS

Ohio Retail Rates

In compliance with SB 221, DP&L filed its electric security plan at the PUCO on October 10, 2008. On February 24, 2009, DP&L filed the Stipulation that, among other things, extended the Company’s rate plan through 2012, provided for recovery of the Ohio jurisdictional retail portion of fuel and purchased power costs beginning January 2010, provided for recovery of certain SB 221 compliance costs, and required DP&L to refile its Smart Grid and Advanced Metering Infrastructure (AMI) business cases by September 1, 2009. The material terms of the Stipulation were discussed in greater detail in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. The Smart Grid and AMI portion of the case is still pending before the PUCO.

On October 30, 2009, DP&L filed its application for the establishment of a fuel and purchased power recovery rider for the collection of prudently incurred fuel, purchased power, emission and other related costs beginning January 1, 2010. On December 16, 2009 the PUCO issued an order stating the rider was consistent with the Stipulation provisions, that it does not appear to be unjust or unreasonable, and approved the rider to be effective January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel rider on January 1, 2010.

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 would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. On February 19, 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. In June 2009, DP&L began recovery of these costs. In a subsequent rehearing process, DP&L was ordered to separate the costs into two separate riders (a TCRR and a PJM RPM rider) which were approved in November 2009. On February 16, 2010, DP&L filed its annual true up of these two riders.

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. On March 29, 2010 DP&L entered into a settlement establishing the new reliability targets. This settlement is pending PUCO approval. According to the ESSS rules, DP&L will be subject to financial penalties if the established targets are not met for two consecutive years.

SB 221 Compliance

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 Credits 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 resources. 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 March 2010, the PUCO ruled that DP&L’s 2009 Ohio solar target would be reduced to the amount that it had procured, but that any unmet requirement must be added to the 2010 target. The Commission has not yet ruled on DPLER’s filing.

On April 15, 2010, DP&L made its first of annual required filings related to compliance with renewable and advanced energy targets contained in SB 221. Pursuant to PUCO rules, each April 15, electric utilities are required to provide a status report on how the utility met the renewable benchmarks of the previous year, as well as a ten-year plan outlining the utility’s plans to meet future annual renewable targets. DPLER, an electric services company pursuant to Ohio Revised Code, is also required to meet SB 221 renewable benchmarks and therefore filed its first reports on that same day. In addition, on April 15 of each year, each utility that owns an electric generating facility in Ohio must report to the PUCO regarding its greenhouse gas emissions, and plans to reduce those emissions (environmental control plan) as well as a long-term forecast report which includes a plan to provide sufficient resources to meet customer load obligations (resource plan). These plans were filed timely.

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.

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 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.

Air Quality

Land Use and Solid Waste Disposal

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FINANCIAL OVERVIEW

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

For the three months ended March 31, 2010, Net income for DPL was $71.0 million, or $0.61 per share, compared to Net income of $69.2 million, or $0.61 per share, for the same period in 2009. All EPS amounts are on a diluted share basis. The significant highlights during the three-month period ended March 31, 2010 compared to the similar period of the prior year comprise the following:

· an increase in retail rates primarily as a result of an increase in the EIR and the implementation of the Fuel, 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 net reduction in interest costs primarily as a result of certain outstanding debt redemptions, and

· a decrease in the average cost of fuel due primarily to lower coal prices.

Partially offsetting these items were:

· an increase in purchased power prices,

· 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, and

· an increase in the volume of fuel consumed due to increased generation by our power plants.

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RESULTS OF OPERATIONS — DPL

DPL’s results of operations include the results of its subsidiaries, including the results of its principal subsidiary DP&L. DP&L provides approximately 97% 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

	Three Months Ended
	March 31,
$ in millions	2010			2009

Revenues:
Retail	$	354.6		$	320.3
Wholesale	40.2			30.9
RTO revenues	21.1			25.5
RTO capacity revenues	32.3			35.4
Other revenues	3.0			2.9
Total revenues	$	451.2		$	415.0

Cost of revenues:
Fuel costs	$	102.3		$	104.3
Gains from sale of coal	(0.2		)	(20.7		)
Gains from sale of emission allowances	(0.2		)	(2.2		)
Net fuel	101.9			81.4

Purchased power	13.7			15.7
RTO charges	30.6			30.6
RTO capacity charges	30.7			36.4
Recovery / (Deferral) of RTO expenses, net	(2.2		)	(23.0		)
Net purchased power	72.8			59.7

Total cost of revenues	$	174.7		$	141.1

Gross margins (a)	$	276.5		$	273.9

Gross margin as a percentage of revenues	61.3		%	66.0		%

Operating income	$	126.0		$	127.0

Earnings per share of common stock:
Basic EPS from operations	$	0.61		$	0.62
Diluted EPS from operations	0.61			0.61

(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 the prior period:

	Three Months Ended
	March 31,
$ in millions	2010 vs. 2009

Retail
Rate	$	34.5
Volume	0.3
Other miscellaneous	(0.5		)
Total retail change	$	34.3

Wholesale
Rate	$	(0.9	)
Volume	10.2
Total wholesale change	$	9.3

RTO capacity & other
RTO capacity and other revenues	$	(7.4	)

Total revenues change	$	36.2

For the three months ended March 31, 2010, Revenues increased $36.2 million to $451.2 million from $415.0 million in the same period of the prior year. This increase was primarily the result of higher average retail rates and higher wholesale sales volume, partially offset by a decrease in RTO capacity and other RTO revenues.

· Retail revenues increased $34.3 million resulting primarily from a 11% increase in average retail rates due largely to the implementation of the fuel, TCRR, RPM and Energy Efficiency riders, combined with the incremental effect of the recovery of costs under the EIR. Retail volumes saw a slight decrease compared to those in the prior year period. The above resulted in a favorable $34.5 million retail price variance and a favorable $0.3 million retail sales volume variance.

· Wholesale revenues increased $9.3 million for the three months ended March 31, 2010 primarily as a result of a 33% increase in wholesale sales volumes, partially offset by a 2% decrease in wholesale average prices. This resulted in a favorable $10.2 million wholesale volume variance and an unfavorable wholesale price variance of $0.9 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DPL’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $7.4 million compared to the same period in 2009. This decrease to RTO capacity and other RTO revenues was primarily the result of a $3.1 million decrease in revenues realized from the PJM capacity auction combined with a $4.4 million decrease in transmission and congestion revenues.

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DPL — Cost of Revenues

For the three months ended March 31, 2010:

· Fuel costs, which include coal, gas, oil and emission allowance costs, increased $20.5 million, or 25%, compared to the same period in 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the first three months of 2010, DP&L realized $0.2 million and $0.2 million in gains from the sale of coal and excess emission allowances, respectively, compared to $20.7 million and $2.2 million, respectively, during the same period in 2009. Also contributing to the increase in fuel costs was the impact of a 4% increase in the volume of generation by our plants. The effect of these increases was partially offset by a 5% decrease in the average cost of fuel consumed per kilowatt-hour due largely to lower coal prices.

· Purchased power increased $13.1 million, or 22%, compared to the same period in 2009 primarily reflecting the impact of the deferral of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. During the first three months of 2010, DP&L deferred $2.2 million of such costs compared to $23.0 million during the same period in 2009. Also contributing to the higher purchased power costs was an increase of $4.2 million relating to higher average market prices. The effects of these increases were partially offset by the impact of higher generation at our plants that saw purchased power volumes decrease by an equivalent of $6.2 million, combined with a $5.7 million decrease in RTO capacity and other RTO charges over the same period in 2009. 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

	Three Months Ended
	March 31,
$ in millions	2010 vs. 2009
Energy efficiency programs (1)	$	4.2
Pension	1.2
Group insurance	1.0
Low-income payment program (1)	0.9
Insurance settlement, net	(3.4		)
Generating facilities operating and maintenance expenses	(3.2		)
Other, net	1.0
Total operation and maintenance expense	$	1.7

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

During the three months ended March 31, 2010, operation and maintenance expense increased $1.7 million, or 2%, compared to the same period in 2009. This variance was primarily the result of:

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

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

· increased health insurance costs that were partially due to higher disability reserves, and

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

These increases were partially offset by

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

· decreases in expenses for generating facilities largely due to lower maintenance activity at jointly-owned production units.

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DPL — Depreciation and Amortization

For the three months ended March 31, 2010, depreciation and amortization expense increased $1.5 million compared to the same period in 2009 primarily as a result of higher asset balances at the generating stations. The higher asset balances are primarily due to continuing capital expenditures on FGD projects and other plant-related asset acquisitions.

DPL — Interest Expense

For the three months ended March 31, 2010, interest expense decreased $3.8 million primarily due to the redemption of DPL’s $175 million 8.00% Senior Notes in March 2009 combined with the early redemption in December 2009 of $52.4 million of the $195 million 8.125% Note to DPL Capital Trust II.

DPL — Income Tax Expense

For the three months ended March 31, 2010, income taxes decreased less than $0.1 million compared to the same period in 2009, primarily reflecting a decrease in the estimated annual effective tax rate. The decrease in the estimated annual effective tax rate is primarily due to increased benefits from the Section 199 Domestic Production Deduction.

RESULTS OF OPERATIONS — DP&L

Income Statement Highlights — DP&L

	Three Months Ended
	March 31,
$ in millions	2010			2009

Revenues:
Retail	$	314.1		$	308.1
Wholesale	76.3			41.0
RTO revenues	20.2			24.5
RTO capacity revenues	27.4			30.0
Total revenues	$	438.0		$	403.6

Cost of revenues:
Fuel costs	$	101.0		$	101.7
Gains from sale of coal	(0.2		)	(20.7		)
Gains from sale of emission allowances	(0.2		)	(2.2		)
Net fuel	100.6			78.8

Purchased power	13.6			15.6
RTO charges	30.5			30.1
RTO capacity charges	30.7			36.4
Recovery / (Deferral) of RTO expenses, net	(2.2		)	(23.0		)
Total purchased power	72.6			59.1

Total cost of revenues	173.2			137.9

Gross margins (a)	$	264.8		$	265.7

Gross margin as a percentage of revenues	60.5		%	65.8		%

Operating Income	$	118.4		$	124.8

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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 will 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.

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

	Three Months Ended
	March 31,
$ in millions	2010 vs. 2009

Retail
Rate	$	6.3
Volume	—
Other miscellaneous	(0.3		)
Total retail change	$	6.0

Wholesale
Rate	$	19.6
Volume	15.7
Total wholesale change	$	35.3

RTO capacity and other
RTO capacity and other RTO revenues	$	(6.9	)

Total revenues change	$	34.4

For the three months ended March 31, 2010, revenues increased $34.4 million, or 9%, to $438.0 million from $403.6 million in the same period of the prior year. This increase was primarily the result of higher wholesale sales volumes combined with higher average retail and wholesale prices, partially offset by a decrease in RTO capacity and other RTO revenues.

· Retail revenues increased $6.0 million, primarily as a result of a 2% increase in average retail rates due largely to the implementation of the fuel, TCRR, RPM, and energy efficiency riders combined with the incremental effect of the recovery of costs under the EIR. The effects of these increases were partially offset by the impact of customers switching their generation service from DP&L to DPLER, an affiliated CRES provider. DP&L continues to provide distribution services to those customers within its service territory who have elected to switch their generation service to DPLER.

· Wholesale revenues increased $35.3 million for the three months ended March 31, 2010 primarily as a result of a 38% increase in wholesale sales volume combined with an increase in average wholesale prices due in large part to the effect of the customer switching discussed in the immediately preceding paragraph. This resulted in a favorable $19.6 million wholesale price variance as well as a favorable wholesale volume variance of $15.7 million.

· RTO capacity and other RTO revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $6.9 million compared to the same period in 2009. This decrease to RTO capacity and other RTO revenues was primarily the result of a $2.6 million decrease in revenues realized from the PJM capacity auction combined with a $4.3 million decrease in transmission and congestion revenues.

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DP&L — Cost of Revenues

For the three months ended March 31, 2010:

· Fuel costs, which include coal, gas, oil, and emission allowance costs, increased $21.8 million, or 28%, compared to the same period in 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the first three months of 2010, DP&L realized $0.2 million and $0.2 million in gains from the sale of coal and excess emission allowances, respectively, compared to $20.7 million and $2.2 million, respectively, during the same period in 2009. Also contributing to the increase in fuel costs was the impact of a 4% increase in the volume of generation by our plants. The effect of these increases was partially offset by a 5% decrease in the average cost of fuel consumed per kilowatt-hour due largely to lower coal prices.

· Purchased power increased $13.5 million, or 23%, compared to the same period in 2009, primarily reflecting the impact of the deferral of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. During the first three months of 2010, DP&L deferred $2.2 million of such costs compared to $23.0 million during the same period in 2009. Also contributing to the higher purchased power costs was an increase of $4.2 million relating to higher average market prices. The effects of these increases were partially offset by the impact of higher generation at our plants that saw purchased power volumes decrease by an equivalent of $6.2 million, and also a $5.3 million decrease in RTO capacity and other RTO charges over the same period in 2009. 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

	Three Months Ended
	March 31,
$ in millions	2010 vs. 2009
Energy efficiency programs (1)	$	4.2
Pension	1.2
Group insurance	1.0
Low-income payment program (1)	0.9
Generating facilities operating and maintenance expenses	(3.1		)
Other, net	(0.5		)
Total operation and maintenance expense	$	3.7

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

For the three months ended March 31, 2010, operation and maintenance expense increased $3.7 million, or 5%, compared to the same period in 2009. This variance was primarily the result of:

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

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

· increased health insurance costs that were partially due to higher disability reserves, and

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

These increases were partially offset by decreases in expenses for generating facilities largely due to lower maintenance activity at jointly-owned production units.

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DP&L — Depreciation and Amortization

For the three months ended March 31, 2010, depreciation and amortization expense increased $1.4 million compared to the same period in 2009 primarily as a result of higher asset balances at the generating stations. The higher asset balances are primarily due to plant-related asset acquisitions.

DP&L — Income Tax Expense

For the three months ended March 31, 2010, income tax expense decreased $3.6 million, or 9%, compared to the same period in 2009, primarily reflecting a decrease in pre-tax book income combined with a decrease in the effective tax rate resulting from the phase-out of the Ohio Franchise Tax and the increased benefits from the Section 199 Domestic Production Deduction.

DP&L — Investment Income

For the three months ended March 31, 2010, investment income decreased $1.0 million primarily due to lower gains realized from DP&L’s Master Trust Plan used for deferred compensation distributions. The lower gains were largely a result of overall lower market yields on investments in 2010 compared to 2009.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

DPL’s financial condition, liquidity and capital requirements include the 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 three months
	ended March 31,
$ in millions	2010			2009

Net cash provided by operating activities	$	122.6		$	73.3
Net cash used for investing activities	(71.3		)	(42.9		)
Net cash used for financing activities	(37.3		)	(66.3		)

Net change	$	14.0		$	(35.9	)
Cash and cash equivalents at beginning of period	74.9			62.5
Cash and cash equivalents at end of period	$	88.9		$	26.6

DP&L

	For the three months
	ended March 31,
$ in millions	2010			2009

Net cash provided by operating activities	$	134.8		$	64.3
Net cash used for investing activities	(37.2		)	(46.7		)
Net cash used for financing activities	(90.2		)	(18.5		)

Net change	$	7.4		$	(0.9	)
Cash and cash equivalents at beginning of period	57.1			20.8
Cash and cash equivalents at end of period	$	64.5		$	19.9

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

Net Cash Provided by Operating Activities

The 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 three months ended March 31, 2010 and 2009 can be summarized as follows:

	Three Months Ended
	March 31,
$ in millions	2010			2009

Earnings from continuing operations	$	71.0		$	69.2
Depreciation and amortization	37.4			35.9
Deferred income taxes	10.5			3.6
Contribution to pension plan	(20.0		)	—
Regulatory expenditures under TCRR/RPM	(2.2		)	(9.5		)
Other	25.9			(25.9		)
Net cash provided by operating activities	$	122.6		$	73.3

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

· The $10.5 million increase to Deferred income taxes primarily results from a $7.0 million temporary difference due to a pension contribution and other temporary differences arising from routine changes in balance sheet accounts.

· In February 2010, DP&L contributed $20.0 million to the defined benefit plan.

· The $2.2 million of cash used to pay for transmission, capacity and other PJM-related costs incurred during 2010, net of recoveries. These costs are recorded as a Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Condensed Consolidated Financial Statements) and are expected to be collected from customers in future periods.

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

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

· The $9.5 million of cash used to pay for transmission, capacity and other PJM-related costs incurred during the three months ended March 31, 2009. 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 Condensed 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.

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DP&L — Net Cash provided by Operating Activities

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

	Three Months Ended
	March 31,
$ in millions	2010			2009

Net income	$	72.1		$	77.0
Depreciation and amortization	34.8			33.4
Deferred income taxes	9.9			3.3
Contribution to pension plan	(20.0		)	—
Regulatory expenditures under TCRR/RPM	(2.2		)	(9.5		)
Other	40.2			(39.9		)
Net cash provided by operating activities	$	134.8		$	64.3

For the three months ended March 31, 2010 and 2009, 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 three months ended March 31, 2010 and 2009 can be summarized as follows:

	Three Months Ended
	March 31,
$ in millions	2010			2009

Environmental and renewable energy capital expenditures	$	(3.9	)	$	(9.3	)
Other plant-related asset acquisitions, net	(35.5		)	(39.6		)
Other	2.2			2.2
DP&L’s Net cash used for investing activities	$	(37.2	)	$	(46.7	)

Proceeds from maturity of short-term investments	—			10.1
Purchases of short-term investments	(33.7		)	(5.1		)
Other	(0.4		)	(1.2		)
DPL’s Net cash used for investing activities	$	(71.3	)	$	(42.9	)

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

For the three months ended March 31, 2010, DP&L continued to see reductions in its environmental capital expenditures due to the completion of FGD and SCR projects. The expenditures incurred during 2010 relate primarily to the construction of a solar energy facility at Yankee station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment. During this period, DPL also paid $33.7 million to purchase VRDN securities from various institutional securities brokers. The VRDN securities are backed by irrevocable letters of credit. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.

For the three months ended March 31, 2009, DP&L’s cash outflows associated with environmental-related expenditures primarily relate to FGD and SCR equipment installation. During this period, DPL paid $5.1 million to purchase VRDN securities from various institutional securities brokers. In addition, DPL received $5.0 million from the maturity of its held-to-maturity bond investments and $5.1 million from the tender of the aforementioned purchased VRDN securities.

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DPL — Net Cash used for Financing Activities

DPL’s Net cash used for financing activities for the three months ended March 31, 2010 and 2009 can be summarized as follows:

	Three Months Ended
	March 31,
$ in millions	2010			2009

Dividends paid on common stock	$	(35.0	)	$	(32.1	)
Repurchase of DPL common stock	(3.9		)	—
Retirement of long-term debt	—			(175.0		)
Repurchase of warrants	—			(15.9		)
Withdrawals from revolving credit facility	—			150.0
Cash withdrawn from restricted funds	—			6.7
Other	1.6			—
Net cash used for financing activities	$	(37.3	)	$	(66.3	)

For the three months ended March 31, 2010, DPL paid common stock dividends of $35 million. In addition, under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 11 of Notes to Condensed Consolidated Financial Statements), DPL repurchased approximately 145,915 DPL common shares for $3.9 million.

For the three months ended March 31, 2009, DPL retired $175 million of long-term debt, paid common stock dividends of $32.1 million, and repurchased approximately 7.1 million warrants at a total cost of $15.9 million. DPL’s cash inflows included withdrawals of $150 million from its revolving credit facility and $6.7 million from restricted funds held in trust to pay for environmental-related capital expenditures.

DP&L — Net Cash used for Financing Activities

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

	Three Months Ended
	March 31,
$ in millions	2010			2009

Dividends paid on common stock to parent	$	(90.0	)	$	(175.0	)
Withdrawals from revolving credit facility	—			150.0
Cash withdrawn from restricted funds	—			6.7
Other	(0.2		)	(0.2		)
Net cash used for financing activities	$	(90.2	)	$	(18.5	)

For the three months ended March 31, 2010, DP&L’s net cash used for financing activities primarily relates to $90 million in dividends paid to DPL

For the three months ended March 31, 2009, DP&L paid $175 million in dividends to DPL and made withdrawals of $150 million from its revolving credit facility and $6.7 million from restricted funds held in trust to pay for environmental-related capital expenditures.

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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.

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

$ in millions	Type	Maturity	Commitment		Amounts available as of April 29, 2010

DP&L	Revolving	November 2011	$	220.0	$	220.0

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

Each revolving credit facility has a $50 million Letter of Credit (LOC) sublimit. As of March 31, 2010 and through the date of filing this quarterly report on Form 10-Q, there were no outstanding LOCs on either facility.

Cash and cash equivalents for DPL and DP&L amounted to $88.9 million and $64.5 million, respectively, at March 31, 2010. At that date, DPL also had short-term investments amounting to $33.7 million.

Capital Requirements

DPL’s construction additions were $30.2 million and $29.8 million during the three month periods ended March 31, 2010 and 2009, respectively. DPL is expected to spend approximately $210 million in 2010 on construction additions. Planned construction additions for 2010 relate to DP&L’s environmental compliance program, power plant equipment, and its transmission and distribution system.

DP&L’s construction additions were $29.8 million and $29.2 million during the three month periods ended March 31, 2010 and 2009, respectively. DP&L is expected to spend approximately $198 million in 2010 on construction additions. Planned construction additions for 2010 relate to DP&L’s environmental compliance program, power plant equipment, and its transmission and distribution system.

Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. DPL, through its subsidiary DP&L, is projecting to spend an estimated $610 million in capital projects for the period of 2010 through 2012. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds, and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt, and cash flows from operations.

Debt

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

Debt Covenants

There have been no material changes to our debt covenants as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. We are in compliance with all of our debt covenants.

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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 Inc.(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 Inc. - Guarantees

Commercial Commitments and Contractual Obligations

See Note 14 of Notes to Condensed Consolidated Financial Statements.

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), comprised 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 transaction 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.

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The coal market has increasingly been influenced by both international and domestic supply and consumption, making the price of coal more volatile than in the past, and while we have 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.

The following table provides a reconciliation of the changes in the balance of our commodity derivatives included on our balance sheets at March 31, 2010:

$ in millions	2010

Fair Value of Commodity Derivative Contracts:
Outstanding net asset / (liability) at January 1, 2010	$	1.4
Gains / (losses) on settled contracts	0.8
Changes in fair value on contracts still held	(4.3		)
Outstanding net asset / (liability) at March 31, 2010	$	(2.1	)

The impact of the change in the fair values of the commodity derivative contracts between January 1, 2010 and March 31, 2010 is detailed in the table below:

	Three Months
	Ended
$ in millions	March 31, 2010

Effect on the statements of results of operations:	$	(2.1	)

Effect on the balance sheets:
Accumulated other comprehensive income	$	8.0
Regulatory liability (net)	(6.0		)
Partner payable	(3.4		)
Total net change on balance sheets	$	(1.4	)

Total net change	$	(3.5	)

The net asset/liability of the MTM positions above is 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 24% of DP&L’s electric revenues for the three months ended March 31, 2010 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 March 31, 2010, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power:

$ in millions	DPL		DP&L

Effect of 10% change in price per mWh	$	8.9	$	15.0

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DPL’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the three months ended March 31, 2010 and 2009 were 35% and 34%, respectively. DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs were 36% and 34% for the three months ended March 31, 2010 and 2009, 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.

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 75%, as part of the fuel rider approved by the PUCO. The table below provides the effect on annual Net income as of March 31, 2010, of a hypothetical increase or decrease of 10% adjusted for the approximate 75% recovery in the prices of fuel and purchased power:

$ in millions	DPL		DP&L

Effect of 10% change in fuel and purchased power	$	7.6	$	7.4

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 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 indices can be affected by market demand, supply, market interest rates and other economic conditions.

The carrying value of DPL’s debt was $1,324.0 million at March 31, 2010, 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 $1,314.8 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
																	March 31,			March 31,
$ in millions	2010			2011			2012		2013			2014		Thereafter			2010 (a)			2010 (a)
Long-term debt

Variable-rate debt	$	100.0		$	—		$	—	$	—		$	—	$	—		$	100.0	(b)	$	100.0
Average interest rate	0.3		%	N/A			N/A		N/A			N/A		N/A			0.3		%

Fixed-rate debt	$	0.4		$	297.4		$	—	$	470.0		$	—	$	456.2		$	1,224.0		$	1,214.8
Average interest rate	1.8		%	6.9		%	N/A		5.1		%	N/A		5.8		%	5.8		%

Total																	$	1,324.0		$	1,314.8

(a)		Fixed rate debt totals include unamortized debt discounts.
(b)		Shown as current since LOC facility will expire in December 2010, at which point the bondholders could put the bonds to DP&L. Management continues to monitor and evaluate market conditions and intends to seek a renewal of this standby LOC.

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The carrying value of DP&L’s debt was $884.1 million at March 31, 2010, 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 $854.5 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:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

DP&L

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

Variable-rate debt	$	100.0		$	—	$	—	$	—		$	—	$	—		$	100.0	(b)	$	100.0
Average interest rate	0.3		%	N/A		N/A		N/A			N/A		N/A			0.3		%

Fixed-rate debt	$	0.4		$	—	$	—	$	470.0		$	—	$	313.7		$	784.1		$	754.5
Average interest rate	1.8		%	N/A		N/A		5.1		%	N/A		4.8		%	5.0		%

Total																$	884.1		$	854.5

(a)		Fixed rate debt totals include unamortized debt discounts.
(b)		Shown as current since LOC facility will expire in December 2010, at which point the bondholders could put the bonds to DP&L. Management continues to monitor and evaluate market conditions and intends to seek a renewal of this standby LOC.

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 March 31, 2010 and December 31, 2009 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 March 31, 2010 and December 31, 2009, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

DPL

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

Variable-rate debt	$	100.0	(a)	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0

Fixed-rate debt	1,224.0			1,214.8		12.1		1,276.7		1,214.3		12.1

Total	$	1,324.0		$	1,314.8	$	13.1	$	1,376.7	$	1,314.3	$	13.1

DP&L

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

Variable-rate debt	$	100.0	(a)	$	100.0	$	1.0	$	100.0	$	100.0	$	1.0

Fixed-rate debt	784.1			754.5		7.5		784.6		733.5		7.3

Total	$	884.1		$	854.5	$	8.5	$	884.6	$	833.5	$	8.3

(a)

Shown as current since LOC facility will expire in December 2010, at which point the bondholders could put the bonds to DP&L. Management continues to monitor and evaluate market conditions and intends to seek a renewal of this standby LOC.

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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’s $1,224.0 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 March 31, 2010.

DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $784.1 million of fixed-rate debt and not on DP&L’s financial 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 March 31, 2010.

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 condensed consolidated financial statements are prepared in accordance with 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; income taxes; valuation of regulatory assets and liabilities; the valuation of insurance and claims costs; the valuation of assets and liabilities related to employee benefits; and the valuation of contingent and other obligations. Actual results may differ from those estimates. Refer to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

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ELECTRIC SALES AND REVENUES

	DPL				DP&L (a)
	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2010		2009		2010		2009
Electric sales (millions of kWh)
Residential	1,595		1,601		1,595		1,601
Commercial	886		916		883		916
Industrial	801		760		800		760
Other retail	337		338		337		338
Total retail	3,619		3,615		3,615		3,615

Wholesale	759		571		746		540

Total	4,378		4,186		4,361		4,155

Operating revenues ($ in thousands)
Residential	$	180,086	$	160,251	$	180,081	$	160,251
Commercial	89,000		80,555		79,335		80,623
Industrial	57,601		53,841		37,240		45,086
Other retail	26,427		23,720		15,801		20,165
Other miscellaneous revenues	1,486		1,975		1,683		1,992
Total retail	354,600		320,342		314,140		308,117

Wholesale	40,233		30,904		76,342		41,078

RTO revenues	53,428		60,912		47,489		54,413

Other revenues	2,937		2,862		—		—

Total	$	451,198	$	415,020	$	437,971	$	403,608

Electric customers at end of period
Residential	456,813		457,328		456,813		457,328
Commercial	50,417		50,181		50,203		50,181
Industrial	1,794		1,798		1,773		1,798
Other	6,595		6,520		6,595		6,520

Total	515,619		515,827		515,384		515,827

(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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Item 3. Quantitative and Qualitative Disclosures about Market Risk

See the “MARKET RISK” section in Item 2 of this Part I.

Item 4. 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 three months ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, internal control over reporting.

PART II

Item 1 - 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 March 31, 2010, cannot be reasonably determined.

Our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, and the Notes to the Consolidated Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in this Item 1 of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings, as well as certain new legal proceedings since the filing of such Annual Report on Form 10-K, and should be read in conjunction with our Annual Report on Form 10-K. Information concerning the legal proceedings discussed in Item 2 – UPDATES/OTHER MATTERS of Part I of this Quarterly Report on Form 10-Q is incorporated by reference into this Item.

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

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Item 1a – Risk Factors

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in our stock is provided in our most recent Annual Report on Form 10-K. The Form 10-K may be obtained as discussed on Page 5 of this report. If any of these events occur, our business, financial position or results of operation could be materially affected.

Item 2 – Unregistered Sale of Equity Securities and Use of Proceeds

The following table details the repurchase by DPL of its common shares during the three months ended March 31, 2010:

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

January	39,898	$	27.37	—	$	3,900,658
February	149,069	$	26.71	145,915	$	—
March	702	$	27.23	—	$	—
	189,669			145,915

(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 equity awards that are settled in DPL common stock. Shares totaling 43,754 were surrendered during the three months ended March 31, 2010 to satisfy these individual tax withholding obligations.

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

(4) On October 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. At December 31, 2009, the amount available to be used under the Stock Repurchase Program approximated $3.9 million. This amount was effectively utilized during the three months ended March 31, 2010 to repurchase 145,915 shares of DPL common stock. However, additional funds could become available under the program to repurchase stock to the extent that any of the 1.8 million warrants outstanding at March 31, 2010 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.

Item 3 – Defaults Upon Senior Securities

None

Item 4 – Removed and Reserved

Item 5 – Other Information

None

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Item 6 – Exhibits

		Exhibit
DPL Inc.	DP&L	Number	Exhibit	Location
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)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

		DPL Inc.
		The Dayton Power and Light Company
		(Registrants)


Date:	April 29, 2010	/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)


	April 29, 2010	/s/ Frederick J. Boyle
		Frederick J. Boyle
		Senior Vice President, Chief Financial Officer, and Treasurer
		(principal financial officer)


	April 29, 2010	/s/ Joseph W. Mulpas
		Joseph W. Mulpas
		Vice President, Controller and Chief Accounting Officer
		(principal accounting officer)