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 June 30, 2009
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                          to                         

CommissionFile Number	Registrant, State of Incorporation,Address and Telephone Number	I.R.S. EmployerIdentification 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 July 27, 2009, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding
DPL Inc.	Common Stock, $0.01 par value	115,972,529
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.

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 Consolidated Statements of Results of Operations – DP&L	10
	Condensed Consolidated Statements of Cash Flows – DP&L	11
	Condensed Consolidated 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	38
	Electric Sales and Revenues	59
Item 3	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4	Controls and Procedures	59
Part II  Other Information
Item 1	Legal Proceedings	60
Item 1A	Risk Factors	60
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 3	Defaults Upon Senior Securities	60
Item 4	Submission of Matters to a Vote of Security Holders	61
Item 5	Other Information	61
Item 6	Exhibits	62
Other
Signatures		63
Certifications		1

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
CAA	Clean Air Act
CO2	Carbon Dioxide
CCEM	Customer Conservation and Energy Management
CRES	Competitive Retail Electric Service
DPL	DPL Inc., the parent company
DPLE	DPL Energy, LLC, a wholly owned subsidiary of DPL which engages in the operation of peaking facilities
DPLER	DPL Energy Resources, Inc., a wholly owned subsidiary of DPL which sells retail electric energy and other energy services under contract to major industrial and commercial customers in West Central Ohio
DP&L	The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio
DSM	Demand-Side Management. A program under which customers typically receive a discount, rebate or some other form of incentive in return for agreeing to reduce their electricity consumption upon request by the utility.
EITF	Emerging Issues Task Force
EPS	Earnings Per Share
ESOP	Employee Stock Ownership Plan
ESP	Electric Security Plans, filed with the PUCO, pursuant to Ohio law
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
FGIC	Financial Guaranty Insurance Company, an unaffiliated insurance company
Fitch	Fitch Ratings, Inc.
FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles
IRS	U.S. Internal Revenue Service
KWh	Kilowatt hours
Moody’s	Moody’s Investors Service, Inc.
MVIC	Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance sources to DPL and its subsidiaries
NOx	Nitrogen Oxide
NYMEX	New York Mercantile Exchange
OAQDA	Ohio Air Quality Development Authority
ODOD	Ohio Department of Development
Ohio EPA	Ohio Environmental Protection Agency
OTC	Over-The-Counter
OVEC	Ohio Valley Electric Corporation, an electric generating company in which DP&L owns a 4.9% equity interest
PJM	PJM Interconnection, L.L.C., a regional transmission organization
PUCO	Public Utilities Commission of Ohio
RSU	Restricted Stock Units

3

Abbreviation or Acronym	Definition
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
RPM	Reliability Pricing Model
SB 221	On May 1, 2008, substitute Senate Bill 221, an Ohio electric energy bill, was signed by the Governor and went into effect July 31, 2008. This new law states that all Ohio distribution utilities must have filed either an electric security plan or a market rate option to be in effect January 1, 2009. The law also contains 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
S&P	Standard & Poor’s Ratings Service
SO2	Sulfur Dioxide
The Stipulation	On February 24, 2009, DP&L filed a Stipulation and Recommendation on its ESP filing pursuant to SB 221, which was signed by the Staff of the PUCO, the Office of the Ohio Consumers’ Counsel and various intervening parties. The PUCO approved the Stipulation on June 24, 2009. The material terms of this Stipulation were discussed further in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.
USEPA	U.S. Environmental Protection Agency
USF	Universal Service Fund
VRDNs	Variable Rate Demand Notes

4

DPL Inc. and The Dayton Power and Light Company file current, annual and quarterly reports, proxy statements (DPL Inc. 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 web site at http://www.sec.gov.

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

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

Forward-looking Statements:  Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.  Please see page 38 for more information about forward-looking statements contained in this report.

Part I – 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 95% of DPL’s total consolidated asset base.  Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise.  Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

5

Item 1 – Financial Statements

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions except per share amounts	2009			2008			2009			2008
Revenues	$	361.2		$	378.8		$	776.2		$	794.9
Cost of revenues:
Fuel	75.9			68.4			157.3			130.3
Purchased power	63.3			86.1			123.0			169.1
Total cost of revenues	139.2			154.5			280.3			299.4
Gross margin	222.0			224.3			495.9			495.5
Operating expenses:
Operation and maintenance	75.5			69.8			152.5			132.2
Depreciation and amortization	35.8			34.0			71.7			67.2
General taxes	27.5			32.5			59.6			62.3
Amortization of regulatory assets	1.3			2.4			3.2			5.5
Total operating expenses	140.1			138.7			287.0			267.2
Operating income	81.9			85.6			208.9			228.3
Other income / (expense), net
Investment income	0.1			0.9			0.6			2.6
Interest expense	(19.4		)	(25.0		)	(41.1		)	(46.0		)
Other income / (deductions)	(0.9		)	0.2			(1.1		)	(0.5		)
Total other income / (expense), net	(20.2		)	(23.9		)	(41.6		)	(43.9		)
Earnings before income tax	61.7			61.7			167.3			184.4
Income tax expense	19.6			14.1			56.0			59.5
Net income	$	42.1		$	47.6		$	111.3		$	124.9
Average number of common shares outstanding (millions):
Basic	112.2			109.4			112.2			109.4
Diluted	113.2			117.3			112.9			116.8
Earnings per share of common stock:
Basic	$	0.38		$	0.43		$	0.99		$	1.14
Diluted	$	0.37		$	0.41		$	0.99		$	1.07
Dividends paid per share of common stock	$	0.285		$	0.275		$	0.570		$	0.550

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

6

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
$ in millions	2009			2008
Cash flows from operating activities:
Net income	$	111.3		$	124.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	71.7			67.2
Amortization of regulatory assets	3.2			5.5
Deferred income taxes	127.9			28.5
Changes in certain assets and liabilities:
Accounts receivable	36.8			(12.2		)
Deposits and other advances	4.7			(0.1		)
Accounts payable	(44.7		)	36.1
Accrued taxes payable	(74.0		)	(38.6		)
Accrued interest payable	0.2			(0.8		)
Prepayments	(0.2		)	(0.1		)
Deferred regulatory costs	(34.2		)	(3.5		)
Inventories	(21.9		)	(0.9		)
Other	3.9			(5.6		)
Net cash provided by operating activities	184.7			200.4
Cash flows from investing activities:
Capital expenditures	(89.6		)	(118.4		)
Proceeds from sale of property	1.2			—
Maturity of short-term investment	5.0			—
Net cash used for investing activities	(83.4		)	(118.4		)
Cash flows from financing activities:
Exercise of stock options	—			1.1
Tax impact related to exercise of stock options	—			0.1
Repurchase of warrants	(15.9		)	—
Retirement of long-term debt	(175.0		)	(100.0		)
Withdrawals of restricted funds held in trust, net	6.7			20.5
Repurchase of pollution control bonds	—			(90.0		)
Withdrawals from revolving credit facility	155.0			90.0
Repayment of borrowings from revolving credit facility	(15.0		)	—
Dividends paid on common stock	(63.8		)	(59.9		)
Net cash used for financing activities	(108.0		)	(138.2		)
Cash and cash equivalents:
Net change	(6.7		)	(56.2		)
Balance at beginning of period	62.5			134.9
Cash and cash equivalents at end of period	$	55.8		$	78.7
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	41.0		$	43.4
Income taxes paid, net of refunds	$	8.6		$	70.4
Non-cash financing and investing activities:
Restricted funds held in trust	$	7.9		$	16.5
Accruals for capital expenditures	$	22.6		$	36.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

7

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	June 30,			December 31,
$ in millions	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	55.8		$	62.5
Restricted funds held in trust	7.9			14.5
Accounts receivable, less provision for uncollectible accounts of $1.9 and $1.1, respectively	282.1			259.9
Inventories, at average cost	127.0			105.1
Taxes applicable to subsequent years	28.3			58.0
Other current assets	23.5			26.7
Total current assets	524.6			526.7
Property:
Property, plant and equipment	5,293.6			5,227.0
Less: Accumulated depreciation and amortization	(2,409.7		)	(2,350.6		)
Total net property	2,883.9			2,876.4
Other noncurrent assets:
Regulatory assets (Note 3)	263.8			233.7
Other deferred assets	42.0			38.3
Total other noncurrent assets	305.8			272.0
Total Assets	$	3,714.3		$	3,675.1

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

8

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At		At
	June 30,		December 31,
$ in millions	2009		2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion - long-term debt	$	0.7	$	175.7
Accounts payable	116.0		178.3
Accrued taxes	91.9		130.4
Accrued interest	25.4		25.0
Revolving credit borrowings	140.0		—
Other current liabilities	43.3		34.5
Total current liabilities	417.3		543.9
Noncurrent liabilities:
Long-term debt	1,375.9		1,376.1
Deferred taxes	566.5		433.7
Regulatory liabilities (Note 3)	123.7		121.9
Unamortized investment tax credit	36.6		38.0
Insurance and claims costs	16.1		17.6
Other deferred credits	139.4		145.4
Total noncurrent liabilities	2,258.2		2,132.7
Redeemable preferred stock of subsidiary	22.9		22.9
Commitments and contingencies (Note 11)
Common shareholders’ equity:
Common stock, at par value of $0.01 per share:

	June 2009	December 2008
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	115,962,529	115,961,880	1.2			1.2
Warrants			19.8			31.0
Common stock held by employee plans			(20.8		)	(27.6		)
Accumulated other comprehensive loss			(42.5		)	(44.6		)
Retained earnings			1,058.2			1,015.6
Total common shareholders’ equity			1,015.9			975.6
Total Liabilities and Shareholders’ Equity			$	3,714.3		$	3,675.1

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

9

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions	2009			2008			2009			2008
Revenues	$	351.9		$	376.4		$	755.5		$	790.3
Cost of revenues:
Fuel	74.4			65.9			153.2			126.6
Purchased power	63.3			87.8			122.4			171.7
Total cost of revenues	137.7			153.7			275.6			298.3
Gross margin	214.2			222.7			479.9			492.0
Operating expenses:
Operation and maintenance	73.6			66.0			147.3			125.6
Depreciation and amortization	33.2			31.5			66.6			62.2
General taxes	27.2			32.3			59.1			61.8
Amortization of regulatory assets	1.3			2.4			3.2			5.5
Total operating expenses	135.3			132.2			276.2			255.1
Operating income	78.9			90.5			203.7			236.9
Other income / (expense), net
Investment income	0.5			4.2			2.0			5.7
Interest expense	(10.0		)	(11.2		)	(18.7		)	(17.8		)
Other income / (deductions)	(0.7		)	0.1			(0.9		)	(0.6		)
Total other income / (expense), net	(10.2		)	(6.9		)	(17.6		)	(12.7		)
Earnings before income tax	68.7			83.6			186.1			224.2
Income tax expense	21.9			20.3			62.3			71.9
Net income	46.8			63.3			123.8			152.3
Dividends on preferred stock	0.2			0.2			0.4			0.4
Earnings on common stock	$	46.6		$	63.1		$	123.4		$	151.9

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

10

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
$ in millions	2009			2008
Cash flows from operating activities:
Net income	$	123.8		$	152.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	66.6			62.2
Amortization of regulatory assets	3.2			5.5
Deferred income taxes	127.7			27.2
Changes in certain assets and liabilities:
Accounts receivable	26.9			(13.7		)
Deposits and other advances	4.7			(0.3		)
Accounts payable	(44.8		)	34.5
Accrued taxes payable	(87.2		)	(37.3		)
Accrued interest payable	0.2			—
Prepayments	0.3			0.2
Deferred regulatory costs	(34.2		)	(3.5		)
Inventories	(21.8		)	(0.9		)
Deferred compensation	(1.0		)	(5.4		)
Other	(1.7		)	(7.9		)
Net cash provided by operating activities	162.7			212.9
Cash flows from investing activities:
Capital expenditures	(86.7		)	(117.7		)
Net cash used for investing activities	(86.7		)	(117.7		)
Cash flows from financing activities:
Payment of short-term debt	—			(20.0		)
Withdrawals of restricted funds held in trust, net	6.7			20.5
Repurchase of pollution control bonds	—			(90.0		)
Withdrawals from revolving credit facility	155.0			90.0
Repayment of borrowings from revolving credit facility	(15.0		)	—
Dividends paid on common stock to parent	(220.0		)	(80.0		)
Dividends paid on preferred stock	(0.4		)	(0.4		)
Net cash used for financing activities	(73.7		)	(79.9		)
Cash and cash equivalents:
Net change	2.3			15.3
Balance at beginning of period	20.8			13.2
Cash and cash equivalents at end of period	$	23.1		$	28.5
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	19.3		$	15.2
Income taxes paid, net of refunds	$	8.5		$	69.9
Non-cash financing and investing activities:
Restricted funds held in trust	$	7.9		$	16.5
Accruals for capital expenditures	$	22.6		$	36.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

11

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	June 30,			December 31,
$ in millions	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	23.1		$	20.8
Restricted funds held in trust	7.9			14.5
Accounts receivable, less provision for uncollectible accounts of $1.0 and $1.1, respectively	272.3			225.4
Inventories, at average cost	125.6			103.8
Taxes applicable to subsequent years	28.2			57.9
Other current assets	24.5			23.8
Total current assets	481.6			446.2
Property:
Property, plant and equipment	5,037.1			4,970.9
Less: Accumulated depreciation and amortization	(2,320.2		)	(2,265.5		)
Total net property	2,716.9			2,705.4
Other noncurrent assets:
Regulatory assets (Note 3)	263.8			233.7
Other deferred assets	52.3			50.5
Total other noncurrent assets	316.1			284.2
Total Assets	$	3,514.6		$	3,435.8

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

12

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	June 30,			December 31,
$ in millions	2009			2008
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities:
Current portion - long-term debt	$	0.7		$	0.7
Accounts payable	114.8			176.6
Accrued taxes	91.1			128.0
Accrued interest	13.4			12.9
Revolving credit borrowings	140.0			—
Other current liabilities	43.1			34.0
Total current liabilities	403.1			352.2
Noncurrent liabilities:
Long-term debt	883.8			884.0
Deferred taxes	549.8			417.8
Regulatory liabilities (Note 3)	123.7			121.9
Unamortized investment tax credit	36.6			38.0
Other deferred credits	139.3			145.5
Total noncurrent liabilities	1,733.2			1,607.2
Redeemable preferred stock	22.9			22.9
Commitments and contingencies (Note 11)
Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	780.4			783.1
Accumulated other comprehensive loss	(36.2		)	(37.5		)
Retained earnings	610.8			707.5
Total common shareholder’s equity	1,355.4			1,453.5
Total Liabilities and Shareholder’s Equity	$	3,514.6		$	3,435.8

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

13

Notes to Condensed Consolidated Financial Statements

(unaudited)

1.     Basis of Presentation

Description of Business

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

DPL’s principal subsidiary is DP&L.  DP&L is a public utility incorporated in 1911 under the laws of Ohio.  DP&L sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio.  DP&L also sells electricity to DPLER, an affiliate, to satisfy the electric requirements of their retail customers.  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 significant subsidiaries (all of which are wholly owned) include DPLE, which engages in the operation of peaking generating facilities; DPLER, which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries.

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

Financial Statement Presentation

We prepare consolidated financial statements in accordance with GAAP in the United States of America.  The condensed consolidated financial statements include the accounts of DPL and its wholly-owned subsidiaries, including DP&L.  Undivided interests in jointly owned generation facilities are consolidated on a pro rata basis.  All material intercompany accounts and transactions are eliminated in consolidation.  Interim results for the three months and six months ended June 30, 2009 may not be indicative of our results that will be realized for the full year ending December 31, 2009.

Pursuant to the SEC rules, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from interim reports. 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, 2008.  In the opinion of our management, the condensed consolidated financial statements in this report contain all adjustments necessary to fairly state our financial condition as of June 30, 2009; our results of operations for the three months and six months ended June 30, 2009; and our cash flows for the six months ended June 30, 2009 in accordance with GAAP.  Certain amounts from prior periods have been reclassified to conform to the current reporting presentation.

We have evaluated all subsequent events through July 29, 2009 which is the date these financial statements were filed with the SEC.

Estimates and Judgments

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 at the date of the financial statements, and the revenue and expenses of the periods reported.  We record liabilities for probable estimated losses in accordance with Statement of Financial Accounting Standards No. 5 (SFAS 5), “Accounting for Contingencies.”  To the extent a probable loss can only be estimated by reference to a range of equally probable outcomes and no amount within the range appears to be a better estimate than any other amount, we accrue for the low end of the range.  Because of uncertainties related to these matters, accruals are based on the best information available at the time.  We evaluate the potential liability related to probable losses quarterly and may revise our estimates.  Judgments and uncertainties affecting the application of these estimates may result in materially different amounts being reported under different conditions or circumstances that may affect our financial position and results of operations.  Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment;

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unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims costs; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to employee benefits.

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 in the accompanying condensed consolidated statements of results of operations for the three months and six months ended June 30, 2009 and 2008, respectively, as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
$ in millions	2009		2008		2009		2008
State/local excise taxes	$	11.2	$	11.7	$	25.2	$	26.1

Recently Adopted Accounting Standards

Disclosures about Derivative Instruments and Hedging Activities

We adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment to FASB Statement No. 133” (SFAS 161), on January 1, 2009.  SFAS 161 requires an entity to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  SFAS 161 did not have a material impact on our overall results of operations, financial position or cash flows.  See Note 9 of Notes to Condensed Consolidated Financial Statements.

Participating Securities and Earnings per Share (EPS)

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

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

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

Interim Disclosures about Fair Value of Financial Instruments

We adopted Staff Position SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP SFAS 107-1), on June 30, 2009.  This FSP requires disclosure about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FSP SFAS 107-1 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.

Subsequent Events

We adopted Statement of Financial Accounting Standards No. 165, “Subsequent Events” (SFAS 165), on June 30, 2009.  SFAS 165 incorporates the guidance in the American Institute of Certified Public Accountants’ Auditing Standard 560 – Subsequent Events, into the accounting guidance.  This new standard is not expected to change current accounting practices.  SFAS 165 did not have a material impact on our overall results of operations, financial position or cash flows.

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Recently Issued Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued SFAS No. 167, “a revision to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities” (SFAS 167) effective for annual reporting periods beginning after November 15, 2009.  SFAS 167 changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated.  The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.  We are currently evaluating the impact of adopting SFAS 167 and have not yet determined the significance of these new rules to our overall results of operations, financial position or cash flows.

Disclosures about Pensions and Other Postretirement Benefits

In December 2008, the FASB issued Staff Position SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” FSP SFAS 132(R)-1, effective for fiscal years ending after December 15, 2009.  We expect to adopt FSP SFAS 132(R)-1 on December 31, 2009.  FSP SFAS 132(R)-1 requires disclosures about benefit plan assets similar to the disclosure required in SFAS 157, “Fair Value Measurements.”  It also requires discussions on investment allocation decisions, major categories of plan assets and significant concentrations of risk in plan assets for the period.  We have evaluated FSP SFAS 132(R)-1 and do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

FASB Codification

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162”, effective for interim and annual periods ending after September 15, 2009.  The objective of this Statement is to replace Statement 162 and to establish the FASB Accounting Standards Codification (Codification) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP.  Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants.  We have evaluated SFAS 168 and do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

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2.     Supplemental Financial Information

	At			At
DPL Inc.	June 30,			December 31,
$ in millions	2009			2008
Accounts receivable, net:
Unbilled revenue	$	75.6		$	82.5
Retail customers	67.1			70.8
Partners in commonly-owned plants	23.4			28.0
PJM including financial transmission rights	20.3			27.0
Coal sales	9.2			25.6
Wholesale and subsidiary customers	6.5			9.7
Refundable tax	79.9			14.9
Other	2.0			2.5
Provision for uncollectible accounts	(1.9		)	(1.1		)
Total accounts receivable, net	$	282.1		$	259.9
Inventories, at average cost:
Fuel and emission allowances	$	89.4		$	68.7
Plant materials and supplies	37.4			36.3
Other	0.2			0.1
Total inventories, at average cost	$	127.0		$	105.1
Other current assets:
Prepayments	$	6.4		$	6.8
Deposits and other advances	5.8			10.5
Insurance and damage claims	3.7			0.9
Current deferred income taxes	2.8			2.2
Short-term investment	—			5.0
Other	4.8			1.3
Total other current assets	$	23.5		$	26.7
Property, plant and equipment:
Property, plant and equipment	$	5,147.0		$	5,073.4
Construction work in process	146.6			153.6
Total property, plant and equipment	$	5,293.6		$	5,227.0
Other deferred assets:
Master Trust assets	$	11.5		$	13.3
Unamortized debt expense	8.8			9.3
Investments	7.6			8.0
Unamortized contracted costs	6.3			—
Commercial activities tax benefit	6.1			6.8
Other	1.7			0.9
Total other deferred assets	$	42.0		$	38.3
Accounts payable:
Trade payables	$	48.6		$	68.7
Fuel accruals	39.3			51.9
Purchased power accruals	10.1			11.8
Other	18.0			45.9
Total accounts payable	$	116.0		$	178.3
Other current liabilities:
Customer security deposits	$	19.8		$	19.8
Unrealized losses on derivatives	13.1			7.6
Low income service plan	3.0			2.4
Pension and retiree benefits payable	0.8			0.8
Other	6.6			3.9
Total other current liabilities	$	43.3		$	34.5
Other deferred credits:
Pension and retiree benefits	$	95.3		$	94.7
Asset retirement obligations - generation property	13.4			13.2
Deferred compensation obligations	12.1			14.3
Litigation and claims reserve	2.1			2.1
Employee benefit reserves	7.6			7.7
Customer advances in aid of construction	3.3			3.4
Taxes payable	—			9.8
Obligations for contracted costs	3.7			—
Other	1.9			0.2
Total other deferred credits	$	139.4		$	145.4

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2.     Supplemental Financial Information (continued)

	At			At
DP&L	June 30,			December 31,
$ in millions	2009			2008
Accounts receivable, net:
Unbilled revenue	$	71.6		$	74.7
Retail customers	67.1			70.8
Partners in commonly-owned plants	23.4			28.0
PJM including financial transmission rights	18.9			23.3
Coal sales	9.2			25.6
Wholesale customers	1.4			2.6
Refundable tax	79.9			—
Other	1.8			1.5
Provision for uncollectible accounts	(1.0		)	(1.1		)
Total accounts receivable, net	$	272.3		$	225.4
Inventories, at average cost:
Fuel and emission allowances	$	89.4		$	68.7
Plant materials and supplies	36.0			35.0
Other	0.2			0.1
Total inventories, at average cost	$	125.6		$	103.8
Other current assets:
Prepayments	$	7.6		$	8.6
Deposits and other advances	5.8			10.5
Insurance and damage claims	3.7			0.9
Current deferred income taxes	2.6			2.3
Other	4.8			1.5
Total other current assets	$	24.5		$	23.8
Property, plant and equipment:
Property, plant and equipment	$	4,890.8		$	4,817.9
Construction work in process	146.3			153.0
Total property, plant and equipment	$	5,037.1		$	4,970.9
Other deferred assets:
Master Trust assets	$	35.3		$	40.4
Unamortized debt expense	8.4			8.6
Unamortized contracted costs	6.3			—
Other	2.3			1.5
Total other deferred assets	$	52.3		$	50.5
Accounts payable:
Trade payables	$	48.4		$	68.6
Fuel accruals	38.7			50.4
Purchased power accruals	9.8			11.8
Other	17.9			45.8
Total accounts payable	$	114.8		$	176.6
Other current liabilities:
Customer security deposits	$	19.8		$	19.8
Unrealized losses on derivatives	13.1			7.6
Low income service plan	3.0			2.4
Pension and retiree benefits payable	0.8			0.8
Other	6.4			3.4
Total other current liabilities	$	43.1		$	34.0
Other deferred credits:
Pension and retiree benefits	$	95.3		$	94.7
Asset retirement obligations - generation property	13.4			13.2
Deferred compensation obligations	12.1			14.3
Employee benefit reserves	7.6			7.7
Obligations for contracted costs	3.7			—
Customer advances in aid of construction	3.3			3.4
Litigation and claims reserve	2.1			2.1
Taxes payable	—			9.8
Other	1.8			0.3
Total other deferred credits	$	139.3		$	145.5

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2.     Supplemental Financial Information (continued)

	Three Months Ended June 30,						Six Months Ended June 30,
DPL Inc.	2009			2008			2009			2008
Comprehensive income:
Net income	$	42.1		$	47.6		$	111.3		$	124.9
Net change in unrealized gains (losses) on financial instruments	0.3			(0.2		)	0.2			(0.4		)
Net change in deferred gains (losses) on cash flow hedges	0.7			(1.3		)	1.2			(4.7		)
Net change in unrealized gains (losses) on pension and postretirement benefits	0.8			0.6			1.6			1.0
Deferred income taxes related to unrealized gains and (losses)	(0.6		)	0.3			(0.9		)	1.4
Comprehensive income	$	43.3		$	47.0		$	113.4		$	122.2

	Three Months Ended June 30,						Six Months Ended June 30,
DP&L	2009			2008			2009			2008
Comprehensive income:
Net income	$	46.8		$	63.3		$	123.8		$	152.3
Net change in unrealized gains (losses) on financial instruments	0.9			(2.1		)	(0.9		)	(10.3		)
Net change in deferred gains (losses) on cash flow hedges	0.7			(1.3		)	1.2			(4.7		)
Net change in unrealized gains (losses) on pension and postretirement benefits	0.8			0.5			1.6			1.0
Deferred income taxes related to unrealized gains and (losses)	(0.8		)	1.0			(0.6		)	5.5
Comprehensive income	$	48.4		$	61.4		$	125.1		$	143.8

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3.  Regulatory Matters

We apply the provisions of FASB SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71) to our regulated operations.  This accounting standard defines regulatory assets as the deferral of costs expected to be recovered in future customer rates and regulatory liabilities as current cost recovery of expected future expenditures.

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

			At		At
	Type of	Amortization	June 30,		December 31,
$ in millions	Recovery (a)	Through	2009		2008
Regulatory Assets:
Deferred recoverable income taxes	C/B	Ongoing	$	83.2	$	81.2
Pension benefits	C	Ongoing	81.2		83.3
Unamortized loss on reacquired debt	C	Ongoing	16.4		17.2
Electric Choice systems costs	F	2010	5.5		7.1
Regional transmission organization costs	D		7.7		8.5
Transmission, capacity and other PJM-related costs	F	2011	30.3		—
Deferred storm costs - 2008	D		15.4		13.1
PJM administrative costs	F	2009	—		0.5
Power plant emission fees	C	Ongoing	5.7		6.3
Rate case expenses	F	2010	0.4		0.5
Settlement system costs	D		3.1		3.1
Customer conservation and energy management costs	D/F	2012	10.4		8.3
PJM integration costs	F	2015	0.6		0.7
Other costs			3.9		3.9
Total regulatory assets			$	263.8	$	233.7
Regulatory Liabilities:
Asset retirement obligations - regulated property			$	98.0	$	96.0
Postretirement benefits			5.6		5.8
SECA net revenue subject to refund			20.1		20.1
Total regulatory liabilities			$	123.7	$	121.9

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

C – Recovery of incurred costs only.

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

D – Recovery not yet determined.

Regulatory Assets

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.

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.  Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, deferred recoverable income taxes are amortized.

Pension benefits represent the unfunded benefit obligation related to the transmission and distribution areas of our electric business.  We have historically recorded these costs on the accrual basis and this is how these costs have historically been recovered through rates.  This factor, combined with the historical precedents from the PUCO and the FERC, makes these costs probable of future rate recovery.

Unamortized loss on reacquired debt represents costs associated with bond redemptions financed by other issues.  These costs are being amortized over the life of the original issues.

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Electric Choice systems costs represent costs incurred to modify the customer billing system for unbundled rates and electric choice 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 has not yet been determined.

Transmission, capacity and other PJM-related costs represent the costs associated with transmission, capacity, ancillary service and other PJM-related charges that are incurred as a member of PJM.  On February 19, 2009, the PUCO approved DP&L’s request to defer such costs incurred since July 31, 2008 consistent with the provisions of SB 221.  Accordingly, during the six months ended June 30, 2009, DP&L deferred net RTO costs in the amount of $28.6 million.  Of this amount, $13.5 million relates to the period August 1, 2008 through December 31, 2008, and $15.1 million relates to the six month period ended June 30, 2009.  Also included in the total deferred amount of $30.3 million is $1.1 million relating to RTEP costs as well as $0.6 million relating to interest and operation and maintenance expenses.  On May 27, 2009, the PUCO granted DP&L authority to recover these costs through retail rates over two years beginning June 1, 2009.  Subsequently, on June 19, 2009, the Industrial Energy Users of Ohio (IEU-OH) filed an application for rehearing claiming the PUCO’s May 27, 2009 order allowing for recovery of RPM costs through this rider was unlawful.  On July 15, 2009, the PUCO issued an order granting rehearing for additional review.  The outcome of this proceeding cannot be determined at this time but based on past precedent, we continue to believe that these costs are probable of recovery.

Deferred storm costs - 2008 relate to the repair of 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.

PJM administrative costs contain the administrative fees billed by PJM to us as a member of the PJM RTO.  Pursuant to a PUCO order issued on January 25, 2006, these deferred costs were recovered over a 3-year period from retail ratepayers beginning February 2006.  Recovery of these costs was completed in January 2009.

Power plant emission fees represent costs paid to the State of Ohio for environmental monitoring.  A PUCO-approved rate rider has been in effect to collect fees that were paid and deferred in years prior to 2002.  Pending before the PUCO is an application to amend that rider to collect fees paid since 2002.

Rate case expenses represent costs incurred in connection with the Rate Stabilization Surcharge that was approved by the PUCO and implemented in January 2006.  These costs are being amortized over a five-year period.

Settlement system costs represent costs to implement a settlement system that reconciles the amount of energy a CRES supplier delivers to its customers and what its customers actually use.  Based on case precedent in other utilities’ cases, the cost of this system is recoverable through DP&L’s next transmission rate case that will be filed at the FERC.  The recovery of these costs has not yet been determined.

Customer conservation and energy management costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of advanced metering infrastructure, as well as DSM program development and various new customer programs addressing energy efficiency.  The portion of these costs related to energy efficiency is being recovered over three years as part of the Stipulation beginning July 1, 2009.  DP&L intends to file a request for the recovery of the remaining costs related to the advanced metering and smart grid infrastructure later this summer.

PJM integration costs include infrastructure costs and other related expenses incurred by PJM and reimbursed by DP&L to integrate us into the RTO.  Pursuant to a FERC order, the costs are being recovered over a 10-year period beginning May 2005 from wholesale customers within PJM.

Other costs primarily include consumer education advertising regarding electric deregulation as well as derivative activity related to fuel and will be recovered over various periods.

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Regulatory Liabilities

Asset retirement obligations - regulated property reflect an estimate of amounts recovered in rates that are expected to be expended to remove existing transmission and distribution property from service upon retirement.

Postretirement benefits reflect a regulatory liability that was recorded for the portion of the unrealized gain on our postretirement trust assets related to the transmission and distribution areas of our electric business.  We have historically recorded these transactions on the accrual basis and this is how these costs have historically been recovered through rates.  This factor, combined with the historical precedents from the PUCO and the FERC, make it probable that these amounts will be reflected in future rates.

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

4.  Ownership of Facilities

We and other Ohio utilities have undivided ownership interests in seven 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 and plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests.  As of June 30, 2009, we had $113 million of construction work in progress at such facilities.  Our share of the operating cost of such facilities is included within the corresponding line in the condensed consolidated statements of results of operations and our share of the investment in the facilities is included in the condensed consolidated balance sheets.  The majority of the construction work in progress at the Conesville Unit 4 is related to a new FGD installation.

Our undivided ownership interest in such facilities at June 30, 2009, is as follows:

			DP&L Investment
	DP&L Share		Gross Plant		Accumulated		Construction
		Production	In Service		Depreciation		Work in Progress
	Ownership (%)	Capacity (MW)	($ in millions)		($ in millions)		($ in millions)
Production Units:
Beckjord Unit 6	50.0	210	$	78	$	55	$	1
Conesville Unit 4	16.5	129	37		28		85
East Bend Station	31.0	186	199		129		3
Killen Station	67.0	402	603		269		1
Miami Fort Units 7&8	36.0	368	348		121		6
Stuart Station	35.0	820	682		236		12
Zimmer Station	28.1	365	1,058		593		5
Transmission (at varying percentages)			90		53		—
Total		2,480	$	3,095	$	1,484	$	113

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5.             Long-term Debt

		At			At
DPL Inc.		June 30,			December 31,
$ in millions		2009			2008
DP&L -	First mortgage bonds maturing
	2013 - 5.125%	$	470.0		$	470.0
DP&L -	Pollution control series maturing
	2028 through 2034 - 4.78% (a)	214.4			214.4
DP&L -	Pollution control series maturing
	2036 - 4.80%	100.0			100.0
DP&L -	Pollution control series maturing
	2040 - variable rates: 0.24% - 0.85% and 0.80% - 1.25% (b)	100.0			100.0
		884.4			884.4
DPL Inc. -	Senior Notes 6.875% Series due 2011	297.4			297.4
DPL Inc. -	Note to Capital Trust II 8.125% due 2031	195.0			195.0
DP&L -	Obligation for capital lease	0.2			0.6
Unamortized debt discount		(1.1		)	(1.3		)
Total		$	1,375.9		$	1,376.1

(a)Weighted average interest rate for six months ended June 30, 2009 and 2008.

(b)Range of interest rates for six months ended June 30, 2009 and the one month ended December 31, 2008, respectively.  These pollution control bonds were issued on December 4, 2008.

		At			At
DP&L		June 30,			December 31,
$ in millions		2009			2008
DP&L -	First mortgage bonds maturing
	2013 - 5.125%	$	470.0		$	470.0
DP&L -	Pollution control series maturing
	2028 through 2034 - 4.78% (a)	214.4			214.4
DP&L -	Pollution control series maturing
	2036 - 4.80%	100.0			100.0
DP&L -	Pollution control series maturing
	2040 - variable rates: 0.24% - 0.85% and 0.80% - 1.25% (b)	100.0			100.0
		884.4			884.4
DP&L -	Obligation for capital lease	0.2			0.6
Unamortized debt discount		(0.8		)	(1.0		)
Total		$	883.8		$	884.0

(a)Weighted average interest rate for six months ended June 30, 2009 and 2008.

(b)Range of interest rates for six months ended June 30, 2009 and the one month ended December 31, 2008, respectively.  These pollution control bonds were issued on December 4, 2008.

At June 30, 2009, DPL’s scheduled maturities of long-term debt, including capital lease obligations, over the next five years are $0.7 million through June 30, 2010; $0.2 million from July 1, 2010 through June 30, 2011; $297.4 million from July 1, 2011 through June 30, 2012; $0 from July 1, 2012 through June 30, 2013; and $470.0 million from July 1, 2013 through June 30, 2014.

At June 30, 2009, DP&L’s scheduled maturities of long-term debt, including capital lease obligations, over the next five years are $0.7 million through June 30, 2010; $0.2 million from July 1, 2010 through June 30, 2011; $0 from July 1, 2011 through June 30, 2013; and $470.0 million from July 1, 2013 through June 30, 2014.  Substantially all property of DP&L is subject to the mortgage lien securing the first mortgage bonds.

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Debt and Debt Covenants

On November 21, 2006, DP&L entered into a $220 million unsecured revolving credit agreement replacing its $100 million facility.  This agreement has a five-year term that expires 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 June 30, 2009, DP&L was in compliance with this covenant with a ratio of 0.44 to 1.00.  As of June 30, 2009, DP&L had $140 million outstanding under this credit facility.  Fees associated with this credit facility are approximately $0.7 million per year.  Changes in credit ratings, however, may affect fees and the applicable interest rate.  This revolving credit agreement also contains a $50 million letter of credit sub-limit.  As of June 30, 2009, DP&L had no outstanding letters of credit against the facility.  DP&L has certain contractual agreements for the sale and purchase of power, fuel and related energy services that contain credit rating related clauses allowing the counter parties to seek additional surety under certain conditions.

During the second quarter ended June 30, 2007, DPL made a short-term loan to DP&L for $105 million.  DP&L paid down $15 million of this loan during the third quarter ended September 30, 2007, an additional $70 million during the fourth quarter ended December 31, 2007, and the final $20 million during the first quarter ended March 31, 2008.  This short-term loan did not violate any covenants in our other debt instruments.  There are no other intercompany debt collateralizations or debt guarantees between DPL, DP&L and their affiliates.  None of the debt obligations of DPL or DP&L are guaranteed or secured by affiliates and no cross-collateralization exists between any subsidiaries.

On November 15, 2007, the OAQDA issued $90 million of collateralized, variable rate OAQDA Revenue Bonds, 2007 Series A due November 1, 2040.  In turn, DP&L borrowed these funds from the OAQDA.  The payment of principal and interest on the bonds when due was insured by an insurance policy issued by FGIC.  During the first quarter of 2008, all three credit rating agencies downgraded FGIC.  As a direct result of these downgrades, bonds which were subject to the auction clearing process carried substantially higher interest rates in succeeding auctions.  On April 4, 2008, DP&L converted the 2007 Series A Bonds from Auction Rate Securities to Variable Rate Demand Notes.  At that time, DP&L purchased these notes out of the market and placed them with the bond trustee.  These notes were redeemed in December 2008 as discussed in the following paragraph.

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 issued by a syndicated bank group.  DP&L is using $10 million of the proceeds from these bonds to finance its portion of the costs of 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 discussed above.

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

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group.  The agreement is for a 364-day term expiring on April 20, 2010.  The facility contains one financial covenant: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of June 30, 2009, DP&L was in compliance with this covenant with a ratio of 0.44 to 1.00.  As of June 30, 2009, DP&L had no outstanding borrowings under this facility.

On July 29, 2009, DP&L repaid $105 million of the $140 million borrowing that was outstanding under the $220 million unsecured revolving credit agreement. This repayment was made using $25 million of cash on hand and an $80 million withdrawal that was made on July 28, 2009 from the $100 million facility referred to in the preceding paragraph.  After this transaction, the borrowings outstanding under both revolving credit facilities amount to $115 million and the combined cash available to DP&L under these revolving credit facilities amounts to $205 million.

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6.     Pension and Postretirement Benefits

We sponsor 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.  We also have unfunded liabilities related to retirement benefits for certain active, terminated and retired key executives.  These liabilities totaled approximately $1.2 million at June 30, 2009 and $1.0 million at December 31, 2008.

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.  We have funded the union-eligible health benefit using a Voluntary Employee Beneficiary Association Trust.

The net periodic benefit cost of the pension and postretirement benefit plans for both DPL and DP&L for the three months ended June 30, 2009 and 2008 was:

Net periodic benefit cost

	Pension						Postretirement
$ in millions	2009			2008			2009			2008
Service cost	$	0.9		$	0.8		$	—		$	—
Interest cost	4.4			4.1			0.5			0.4
Expected return on assets (a)	(5.6		)	(6.0		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Actuarial (gain) loss	1.1			0.7			(0.2		)	(0.2		)
Prior service cost	0.9			0.6			—			—
Net periodic benefit cost	$	1.7		$	0.2		$	0.2		$	0.1

(a)The market-related value of assets is equal to the fair value of assets at implementation with subsequent asset gains and losses recognized in the market-value systematically over a three-year period.

The net periodic benefit cost of the pension and postretirement benefit plans for both DPL and DP&L for the six months ended June 30, 2009 and 2008 was:

Net periodic benefit cost

	Pension						Postretirement
$ in millions	2009			2008			2009			2008
Service cost	$	1.8		$	1.6		$	—		$	—
Interest cost	8.8			8.2			0.9			0.8
Expected return on assets (a)	(11.2		)	(12.0		)	(0.2		)	(0.2		)
Amortization of unrecognized:
Actuarial (gain) loss	2.2			1.4			(0.4		)	(0.4		)
Prior service cost	1.7			1.2			—			—
Net periodic benefit cost	$	3.3		$	0.4		$	0.3		$	0.2

(a)The market-related value of assets is equal to the fair value of assets at implementation with subsequent asset gains and losses recognized in the market-value systematically over a three-year period.

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

Estimated Future Benefit Payments:

$ in millions	Pension		Postretirement
2009	$	10.3	$	1.3
2010	$	21.2	$	2.7
2011	$	21.6	$	2.6
2012	$	22.3	$	2.5
2013	$	23.1	$	2.4
2014 — 2018	$	120.8	$	9.7

7.     Share-Based Compensation

The following table summarizes share-based compensation expense:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions	2009			2008			2009			2008
Stock options	$	—		$	—		$	—		$	—
Restricted stock units	—			—			—			(0.1		)
Performance shares	0.4			0.4			0.8			0.6
Restricted shares	0.2			0.1			0.3			0.2
Non-employee directors’ RSUs	0.1			0.1			0.2			0.2
Management performance shares	0.2			0.1			0.3			0.1
Share-based compensation included in operations and maintenance expense	$	0.9		$	0.7		$	1.6		$	1.0
Income tax benefit	(0.3		)	(0.2		)	(0.6		)	(0.3		)
Total share-based compensation, net of tax	$	0.6		$	0.5		$	1.0		$	0.7

Share-based awards issued in DPL’s common stock will be distributed from treasury stock.  DPL believes it has sufficient treasury stock to satisfy all outstanding share-based awards.

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Summarized share-based compensation activity for both DPL and DP&L for the six months ended June 30, 2009 and 2008 was as follows:

	Options				RSUs			Performance Shares
	2009		2008		2009	2008		2009		2008
Outstanding at beginning of year	836,500		946,500		10,120	22,976		156,300		142,108
Granted	—		—		—	—		124,588		93,298
Dividends	—		—		—	—		—		—
Exercised	—		(50,000	)	—	(1,605	)	—		—
Expired	—		—		—	—		(36,445	)	(37,426	)
Forfeited	—		—		—	(1,603	)	(6,739	)	(7,253	)
Outstanding at period end	836,500		896,500		10,120	19,768		237,704		190,727
Exercisable at period end	836,500		896,500		—	—		—		—
	Restricted Shares				Management Performance Shares
	2009		2008		2009	2008
Outstanding at beginning of year	69,147		42,200		39,144	—
Granted	2,500		20,000		48,719	39,144
Dividends	—		—		—	—
Exercised	(1,000	)	(1,000	)	—	—
Expired	—		—		—	—
Forfeited	—		—		—	—
Outstanding at period end	70,647		61,200		87,863	39,144
Exercisable at period end	—		—		—	—
	Director RSUs
	2009		2008
Outstanding at beginning of year	15,546		13,573
Granted	20,016		15,752
Dividends accrued	836		382
Exercised and issued	(2,066	)	(13,721	)
Exercised and deferred	(14,060	)	—
Forfeited	—		—
Outstanding at period end	20,272		15,986
Exercisable at period end	—		—

8.     Fair Value Measurements

We follow Statement of Financial Accounting Standards No.157, “Fair Value Measurements” (SFAS 157), when determining the fair value of our financial instruments.  SFAS 157 defines fair value 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.  SFAS 157 also establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The standard describes three levels of inputs that may be used to measure fair value:

Level 1

Level 1 inputs are defined as quoted prices in active markets for identical assets or liabilities.  Our Level 1 assets and liabilities include equity securities held in various deferred compensation trusts and futures contracts that are traded in an active exchange market.

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Level 2

Level 2 inputs are observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.  Our Level 2 assets and liabilities include open-ended investment funds in the Master Trust and forward contracts with quoted prices from OTC markets or direct broker quotes that are traded less frequently than exchange-traded instruments.

Level 3

Level 3 inputs are unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.  Our Level 3 assets and liabilities include asset retirement obligations that are initially recognized at fair value.

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk.  With the issuance of SFAS 157, the accounting industry clarified that these values must also take into account a company’s own credit standing.

Master Trust Assets

DP&L established a Master Trust to hold assets for the benefit of employees participating in DP&L’s Deferred Compensation Plan and other employee benefit purposes and these assets are not used for general operating purposes.  These assets are primarily comprised of mutual funds and DPL common stock.  The DPL common stock held by the Master Trust in DP&L’s consolidated balance sheet is eliminated in consolidation and is not reflected in DPL’s consolidated balance sheet. These assets are valued using current public market prices on a quarterly basis.  Any unrealized gains or losses are recognized in Other Comprehensive Income until the securities are sold.

DPL had no unrealized gains and $0.3 million of unrealized losses on the Master Trust assets in OCI at June 30, 2009 and no unrealized gains and $0.5 million of unrealized losses in OCI at December 31, 2008. 

DP&L had $9.7 million in unrealized gains and $0.3 million of unrealized losses on the Master Trust assets in OCI at June 30, 2009 and $10.9 million in unrealized gains and $0.5 in unrealized losses in OCI at December 31, 2008. 

No unrealized gains or losses are expected to be transferred to earnings in 2009.  The unrealized losses are predominantly from a mutual fund invested in a Vanguard 500 Index which is expected to recover its full value.

Long-term Debt

Long-term 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 long-term debt is presented at amortized cost in the financial statements.  The long-term debt amounts include the current portion payable in the next twelve months and have maturities that range from 2009 to 2040.

Derivative Instruments

In the normal course of business, DPL and DP&L enter into various derivative financial instruments.  We use derivatives principally to manage the risk of changes in market prices for commodities.  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.  See Note 9 of Notes to Condensed Consolidated Financial Statements.

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The fair values of our financial instruments and debt are based on market quotes of similar instruments and represent estimates of possible value that may not be realized in the future.  The table below presents the fair value and cost of these instruments at June 30, 2009 and December 31, 2008.

	At June 30, 2009				At December 31, 2008
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL Inc.
Assets
Master Trust Assets	$	11.8	$	11.5	$	13.6	$	13.1
Derivative Assets	—		3.8		—		—
Total Assets	$	11.8	$	15.3	$	13.6	$	13.1
Liabilities
Debt	$	1,376.7	$	1,285.9	$	1,553.0	$	1,471.6
Derivative Liabilities	—		13.1		—		6.6
Total Liabilities	$	1,376.7	$	1,299.0	$	1,553.0	$	1,478.2
DP&L
Assets
Master Trust Assets	$	25.8	$	35.3	$	29.9	$	40.2
Derivative Assets	—		3.8		—		—
Total Assets	$	25.8	$	39.1	$	29.9	$	40.2
Liabilities
Debt	$	884.5	$	814.3	$	884.8	$	815.7
Derivative Liabilities	—		13.1		—		6.6
Total Liabilities	$	884.5	$	827.4	$	884.8	$	822.3

The fair value of assets measured on a recurring basis was determined as follows:

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1				Level 2				Level 3
	Fair Value at				Based on Quoted Prices in Active				Other Observable				Unobservable
	June 30, 2009				Market				Inputs				Inputs
$ in millions	DPL		DP&L (a)		DPL		DP&L (a)		DPL		DP&L(a)		DPL		DP&L
Assets
Master Trust Assets	$	11.5	$	35.3	$	—	$	23.8	$	11.5	$	11.5	$	—	$	—
Derivative Assets	3.8		3.8		—		—		3.8		3.8		—		—
Total	$	15.3	$	39.1	$	—	$	23.8	$	15.3	$	15.3	$	—	$	—
Liabilities
Derivative Liabilities	$	13.1	$	13.1	$	3.0	$	3.0	$	10.1	$	10.1	$	—	$	—
Total	$	13.1	$	13.1	$	3.0	$	3.0	$	10.1	$	10.1	$	—	$	—

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

Level 1 inputs are used for DPL stock held by the Master Trust and for heating oil futures.  The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions.  Level 2 inputs are used to value derivatives such as financial transmission rights and capacity swap contracts where the quoted prices are from a relatively inactive market; forward power contracts and forward NYMEX-quality coal contracts which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market; and open-ended funds that are in the Master Trust valued using the end of day Net Asset Value (NAV).

The fair value of an asset retirement obligation (ARO) is estimated by discounting expected cash outflows to their present value at the initial recording of the liability.  Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or management judgment.  During the three months ended June 30, 2009, DP&L added a minimal amount to an asbestos removal ARO and an ash landfill ARO due to changes in costs and timing estimates for the asbestos removal and landfill retirement.  This non-recurring fair value would be considered a Level 3 input.

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At June 30, 2009, DPL had $10.0 million of investments in money market mutual funds classified as cash and cash equivalents in its condensed consolidated balance sheet.  The money market funds have quoted prices that are generally equivalent to par.

9.     Derivative Instruments and Hedging Activities

Effective January 1, 2009, we adopted Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment to FASB Statement No. 133” (SFAS 161). SFAS 161 requires an entity to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.

In the normal course of business, DPL and DP&L enter into various 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 this risk are governed by our risk management policies for forward and futures contracts.  Our 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 sufficient volumes are available 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.  We rely on modeled valuations only when no other method exists.  (See Note 8 of Notes to Condensed Consolidated Financial Statements.)  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.

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 mark-to-market 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 Other Comprehensive Income (OCI) and transferred to earnings when the hedged forecasted transaction takes place or when the hedged forecasted transaction is no longer probable of occurring.  The ineffective portion of the cash flow hedge is recognized in earnings in the current period.  All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

We currently use cash flow hedging with forward power contracts and in 2003 we entered into an interest rate swap which was settled that same year.  As of June 30, 2009, the maximum length of time that we are hedging (with SFAS 133 designated contracts) our exposure to variability in future cash flows related to forecasted transactions is 18 months.  Approximately $2.2 million of accumulated gains in OCI 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 OCI is being amortized into earnings over the life of the related bonds.  Approximately $2.5 million of accumulated gains in OCI related to the above referenced interest rate hedge are expected to be reclassified to earnings over the next twelve months.

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

	For the six months ended June 30,
	2009						2008
$ in millions	Power			Interest Rate Hedge			Power and Capacity			Interest Rate Hedge
Beginning Accumulated Derivative (Gain) /Loss in OCI	$	0.3		$	(17.2	)	$	1.5		$	(19.7	)
Net change associated with current period hedging transactions	(3.1		)	—			5.4			—
Net amount of any reclassification into earnings	0.7			1.2			(1.9		)	1.2
Ending Accumulated Derivative (Gain) /Loss in OCI	$	(2.1	)	$	(16.0	)	$	5.0		$	(18.5	)

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 SFAS 133, as amended.  Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred.  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 and forward NYMEX-quality coal contracts that do not qualify for cash flow hedge accounting.

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DP&L enters into coal contracts from time to time to supply its generating plants.  We perform a quarterly evaluation of the different coal markets to determine if these coal contracts are considered derivative instruments under SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133).  DP&L has concluded that NYMEX and NYMEX look-a-like coal contracts will be considered derivative instruments under SFAS 133 because they have been determined to be readily convertible to cash under SFAS 133.  These contracts were marked to market and are further discussed in Note 8 of Notes to Condensed Consolidated Financial Statements.

Regulatory Assets and Liabilities

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 probable of recovery as part of the fuel clause in the Stipulation and Recommendation (the Stipulation) filed with the PUCO on February 24, 2009.  The Stipulation was discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.  On June 24, 2009, the PUCO issued an order granting approval of the Stipulation as filed authorizing DP&L to implement rates associated with alternative energy and energy efficiency compliance costs beginning July 1, 2009.  Under SFAS 71, “Accounting for the Effects of Certain Types of Regulation”, 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.  DP&L believes these costs, if incurred after the fuel rate becomes effective on January 1, 2010, are probable of recovery.  The Ohio jurisdictional retail portion of the heating oil futures and the NYMEX-quality coal contracts will be deferred as a regulatory asset or liability account 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.

As of June 30, 2009, DP&L had the following outstanding derivative instruments that were entered into to economically hedge changes in cash flows due to changes in the price of the underlying commodity:

Commodity	Accounting Treatment	Volume
FTRs	Mark to Market	20,417 MW
Heating Oil Futures	Mark to Market	6,216,000 Gallons
Forward Power Contracts	Cash Flow Hedge	1,148,400 MWH
NYMEX-quality Coal Contracts	Mark to Market	1,457,000 Tons
(includes our partners’ share)

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The following table shows the fair value and balance sheet classification of our derivative instruments.

Fair Values of Derivative Instruments

	Asset Derivatives			Liability Derivatives
	As of June 30, 2009			As of June 30, 2009
$ in millions	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under FAS 133
Forward Power Contracts	Other Assets	$	2.1		$	—
Total Derivatives designated as hedging instruments under FAS 133		$	2.1		$	—
Derivatives not designated as hedging instruments under FAS 133
FTRs	Other Assets	$	1.7		$	—
Heating Oil Futures		—		Other Liabilities	2.9
NYMEX-Quality Coal Forwards		—		Other Liabilities	10.2
Total Derivatives not designated as hedging instruments under FAS 133		$	1.7		$	13.1
Total Derivatives		$	3.8		$	13.1

The following table shows the amount and income statement classification of the gains and losses on our derivative instruments for the three-month period ending June 30, 2009.

Derivatives Designated as Hedging Instruments (Cash Flow Hedges) (three months ending June 30, 2009):

$ in millions	Amount of Gain or (Loss) Recognized in AOCI on Derivative (Effective Portion)		Location of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)		Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives Designated as Hedging Instruments Under FAS 133
Interest Rate Hedge	$	—	Interest Expense	$	0.6	Interest Expense	$	—
Forward Power Contracts	1.5		Wholesale Revenue	0.1		Wholesale Revenue	—
Total Effect of Derivative Instruments Designated as Hedging Instruments on the Income Statement
	$	1.5		$	0.7		$	—

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Derivatives Not Designated as Hedging Instruments (MTM) (three months ending June 30, 2009);

$ in millions	Amount of Gain or (Loss) in Regulatory (Asset)/Liability on Derivative per SFAS 71			Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
Derivatives Not Designated as Hedging Instruments Under FAS 133
FTRs	$	—		Purchased Power	$	1.6
Heating Oil Futures	0.9			Fuel Costs(2)	1.4
Heating Oil Futures	—			O&M Expense	0.4
NYMEX-Quality Coal Forwards(1)	(4.4		)
NYMEX-Quality Coal Forwards	(0.7		)	Fuel Costs(3)	(5.8		)
Total Effect of Derivative Instruments Not Designated as Hedging Instruments on the Income Statement
	$	(4.2	)		$	(2.4	)

(1) A proportional share of MTM on NYMEX-quality coal forwards that will be passed to the partners of the jointly owned generating plants when the contracts settle has been deferred in a partner account on the balance sheet.

(2) Includes a MTM gain of $2.0 million on open positions and a realized loss on settlement of closed contracts of $0.6 million.

(3) Includes a MTM loss of $3.8 million on open positions, a realized loss on physically settled coal contracts of $3.2 million and a realized gain on the sale of coal contracts of $1.2 million.

The following table shows the amount and income statement classification of the gains and losses on our derivative instruments for the six-month period ending June 30, 2009.

Derivatives Designated as Hedging Instruments (Cash Flow Hedges) (six months ending June 30, 2009):

$ in millions	Amount of Gain or (Loss) Recognized in AOCI on Derivative (Effective Portion)		Location of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from AOCI into Income (Effective Portion)		Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives Designated as Hedging Instruments Under FAS 133
Interest Rate Hedge	$	—	Interest Expense	$	1.2	Interest Expense	$	—
Forward Power Contracts	3.2		Wholesale Revenue	0.7		Wholesale Revenue	—
Total Effect of Derivative Instruments Designated as Hedging Instruments on the Income Statement
	$	3.2		$	1.9		$	—

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Derivatives Not Designated as Hedging Instruments (MTM) (six months ending June 30, 2009);

$ in millions	Amount of Gain or (Loss) in Regulatory (Asset)/Liability on Derivative per SFAS 71			Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
Derivatives Not Designated as Hedging Instruments Under FAS 133
FTRs	$	—		Purchased Power	$	1.7
Heating Oil Futures	(1.1		)	Fuel Costs (2)	2.4
Heating Oil Futures	—			O&M Expense	0.4
NYMEX-Quality Coal Forwards(1)	(5.1		)
NYMEX-Quality Coal Forwards	0.5			Fuel Costs (3)	(6.5		)
Total Effect of Derivative Instruments Not Designated as Hedging Instruments on the Income Statement
	$	(5.7	)		$	(2.0	)

(1)A proportional share of MTM on NYMEX-quality coal forwards that will be passed to the partners of the jointly owned generating plants when the contracts settle has been deferred in a partner account on the balance sheet.

(2)Includes a MTM gain of $4.0 million on open positions and a realized loss on settlement of closed contracts of $1.6 million.

(3)  Includes a MTM loss of $5.5 million on open positions, a realized loss on physically settled coal contracts of $3.2 million and a realized gain on the sale of coal contracts of $2.2 million.

Certain of our derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from the 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 mark to market loss.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position June 30, 2009, is $13.2 million.  We have not posted collateral for this risk because our debt is above the lowest investment grade level.

10.  Earnings per Share

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 following table represents common-equivalent shares excluded from the calculation of diluted EPS because they were anti-dilutive.  These shares may be dilutive in the future.

	Three Months Ended June 30,		Six Months Ended June 30,
In millions	2009	2008	2009	2008
Common equivalent shares	0.3	0.3	0.3	0.3

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The following illustrates the reconciliation of the numerators and denominators of the basic and diluted earnings per share computations:

	Three Months Ended June 30,
	2009					2008
$ in millions except per	Net			Per		Net			Per
share amounts	Income		Shares	Share		Income		Shares	Share
Basic EPS	$	42.1	112.2	$	0.38	$	47.6	109.4	$	0.43
Effect of Dilutive Securities:
Warrants (a)			0.8					7.7
Stock options and performance shares			0.2					0.2
Diluted EPS	$	42.1	113.2	$	0.37	$	47.6	117.3	$	0.41

	Six Months Ended June 30,
	2009					2008
$ in millions except per	Net			Per		Net			Per
share amounts	Income		Shares	Share		Income		Shares	Share
Basic EPS	$	111.3	112.2	$	0.99	$	124.9	109.4	$	1.14
Effect of Dilutive Securities:
Warrants (a)			0.6					7.2
Stock options and performance shares			0.1					0.2
Diluted EPS	$	111.3	112.9	$	0.99	$	124.9	116.8	$	1.07

(a)On March 20, 2009, DPL repurchased 7.06 million warrants, each at a price of $2.25.  The repurchased warrants were cancelled by DPL on the date they were repurchased.  See Note 13 of Notes to Condensed Consolidated Financial Statements.

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11.  Contractual Obligations, Commitments and Contingencies

DPL Inc. — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned generating subsidiary, DPLE providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s intended commercial purposes.  Such agreements fall outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”  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, 2008.  Through June 30, 2009, DPL has not incurred any losses related to the guarantees of DPLE’s obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s obligations.

DP&L — Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in OVEC, an electric generation company.  As of June 30, 2009, DP&L could be responsible for the repayment of 4.9%, or $55.3 million, of a $1,127.9 million debt obligation that matures in 2026.  This would only happen if OVEC defaulted on its debt payments.  As of June 30, 2009, OVEC has not defaulted on its debt payment obligations.

Other than 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.

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 June 30, 2009, cannot be reasonably determined.

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, 2008.

Environmental Matters

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws.  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 have been identified, either by a government agency or by a private party seeking contribution to site clean-up costs, as a potentially responsible party (PRP) at two sites pursuant to state and federal laws.  We record liabilities for probable estimated loss in accordance with SFAS 5 as discussed in Note 1 of Notes to Condensed Consolidated Financial Statements.  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 and financial position.

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12.  Redeemable Preferred Stock

DP&L has $100 par value preferred stock, 4,000,000 shares authorized, of which 228,508 are outstanding.  DP&L also has $25 par value preferred stock, 4,000,000 shares authorized, none of which were outstanding at June 30, 2009.  The table below details the shares outstanding at June 30, 2009.

					Current Shares	Par Value at		Par Value at
	Preferred		Current		Outstanding at	June 30,		December 31,
	Stock		Redemption		June 30,	2009		2008
	Rate		Price		2009	($ in millions)		($ in millions)
DP&L Series A	3.75	%	$	102.50	93,280	$	9.3	$	9.3
DP&L Series B	3.75	%	$	103.00	69,398	7.0		7.0
DP&L Series C	3.90	%	$	101.00	65,830	6.6		6.6
Total					228,508	$	22.9	$	22.9

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share prices indicated, plus cumulative accrued dividends.  In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends.  Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the balance sheet as “Redeemable Preferred Stock” in a manner consistent with temporary equity as defined in EITF Topic No. 98, “Classification and Measurement of Redeemable Securities”.

As long as any DP&L preferred stock is outstanding, DP&L’s Amended Articles of Incorporation also contain provisions restricting the payment of cash dividends on any of its Common Stock if, after giving effect to such dividend, the aggregate of all such dividends distributed subsequent to December 31, 1946 exceeds the net income of DP&L available for dividends on its Common Stock subsequent to December 31, 1946, plus $1.2 million.  As of June 30, 2009, all earnings reinvested in the business of DP&L were available for Common Stock dividends.  We do not expect this restriction to have an effect on the payment of cash dividends in the future.  DPL records dividends on preferred stock of DP&L as part of interest expense.  We expect all 2009 earnings reinvested in the business of DP&L to be available for DP&L common stock dividends, payable to DPL.

13.  Common Shareholders’ Equity

In February 2000, DPL entered into a series of recapitalization transactions which included the issuance of 31.6 million warrants for an aggregate purchase price of $50 million.  The warrants are exercisable, in whole or in part, for common shares at any time during the twelve-year period commencing on March 13, 2000.  Each warrant is exercisable for one common share, subject to anti-dilution adjustments (e.g., stock split, stock dividend) at an exercise price of $21.00 per common share.

At December 31, 2008, DPL had 19.6 million outstanding warrants.  On March 20, 2009, DPL re-purchased 7,060,000 of such warrants at a price of $2.25 each.  The repurchased warrants were cancelled by DPL on the date they were repurchased.  Accordingly, at June 30, 2009, DPL had 12.5 million warrants outstanding.

14.  Income Taxes

During the three months ended June 30, 2009, DP&L recorded a current tax receivable in the amount of $79.9 million, a reduction in current income tax liabilities of $28.9 million and a net non-current deferred tax liability of $108.8 million.  These recorded amounts were due to the recognition of certain income tax benefits relating to a change in the tax accounting method for deductions pertaining to repairs, depreciation and mixed service costs.  These benefits, which are expected to reduce current year tax payments and result in a refund of prior period taxes, have been recorded under the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”  The recognition of these benefits did not have a material impact on our results of operation for the three months and six months ended June 30, 2009.

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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 95% of DPL’s total consolidated asset base.  Throughout this report the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise.  Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in this section.

Certain statements contained in this report 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, oil, and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; performance of our suppliers and other counterparties; 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 and regulations, rate structures or tax laws; changes in federal and/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, employee, 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, including impacts the current financial crisis may have on our business and financial condition; the outcomes of litigation and regulatory investigations, proceedings or inquiries; general economic conditions; and the risks and other factors discussed in DPL’s and DP&L’s 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 unaudited financial statements and related footnotes included in Part 1 — Financial Information.

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BUSINESS OVERVIEW

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

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

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

DPL’s significant subsidiaries (all of which are wholly owned) include DPLE, which engages in the operation of peaking generating facilities; DPLER, which sells retail electric energy under contract to major industrial and commercial customers in West Central Ohio; and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries.

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

In addition to the issues disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, which we believe are likely to have a significant impact on our results of operations and financial condition, we have identified certain additional 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:

·Emissions

Rules issued by the USEPA and Ohio EPA that require substantial reductions in SO2, NOx, and mercury emissions impact our business and operations.  In addition, emissions legislation has recently been passed by the House of Representatives and is being considered by the Senate.  We are installing (and have installed) emission control technology and are taking other measures to comply with required reductions in the emissions.

In addition to the requirements related to emissions of SO2, NOx and mercury noted above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases, including most significantly, CO2.  This concern has led to increased interest in legislation at the federal level and actions at the state level as well as litigation relating to greenhouse gas emissions, including a U.S. Supreme Court decision holding that the USEPA has the authority to regulate CO2 emissions from motor vehicles under the CAA.  In response to the Supreme Court’s decision, the USEPA made a finding that carbon dioxide and certain other gases are pollutants under the CAA.  On April 17, 2009, the USEPA also made a declaration that CO2 and five other greenhouse gases are a danger to public health and welfare.  The USEPA has not yet identified the specifics of how these newly designated pollutants will be regulated.Increased pressure for carbon dioxide emissions reduction is also coming from investor organizations and the international community.  If legislation or regulations are passed at the federal or state levels that impose mandatory reductions of CO2 and other greenhouse gases on generation facilities, the cost to DPL and DP&L of such reductions could be material.

·RPM Auction Price

The PJM RPM base residual auction (BRA) for the 2012/13 period cleared at a per megawatt price of $16.46/day for the 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.  We currently cannot determine the extent to which these future auction results will impact our operations.

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UPDATES / OTHER MATTERS

Competition and Regulation Updates

Ohio Matters Updates

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 reached an agreement with the majority of the parties to that case.  The resulting Stipulation extends DP&L’s rate plan through 2012, provides for recovery of the Ohio jurisdictional retail portion of fuel and purchased power costs beginning January 2010, provides for recovery of certain SB 221 compliance costs, and requires DP&L to refile its Smart Grid and Advanced Metering Infrastructure business cases by September 1, 2009.  The terms of the Stipulation were discussed in greater detail in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.  On June 24, 2009, the PUCO issued an order granting approval of the Stipulation as filed and authorized DP&L to implement rates associated with alternative energy and energy efficiency compliance costs beginning July 1, 2009.  DP&L is preparing its Smart Grid and Advanced Metering infrastructure business cases and plans to resubmit this information to the PUCO prior to September 1, 2009.

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 consistent with the provisions of SB 221.  As a result, at June 30, 2009, we have recorded a net regulatory asset in the amount of $30.3 million. See Note 3 of Notes to Condensed Consolidated Financial Statements.  On March 28, 2009, DP&L filed for recovery of these PJM-related costs.  Through this filing, DP&L eliminated seven retail riders related to transmission and ancillary services and replaced them with a single Transmission Cost Recovery Rider (TCRR) that would incorporate all charges and credits from the RTO as well as the amounts approved for deferral.  On May 27, 2009 the PUCO granted approval of this filing, authorizing DP&L to recover the new rate beginning June 1, 2009.  On June 19, 2009, the Industrial Energy Users of Ohio (IEU-OH) filed an application for rehearing claiming the PUCO’s May 27, 2009 order allowing for recovery of reliability pricing model (RPM) costs through this rider was unlawful.  On July 15, 2009, the PUCO issued an order granting rehearing for additional review.  DP&L does not have any information that would indicate that the PUCO will agree or disagree with IEU-OH’s claims, therefore the outcome of this proceeding cannot be determined at this time.  However, based on past precedent, we continue to believe that these costs are probable of recovery.

On June 17, 2009, the PUCO issued in final form its rules relating to energy efficiency, demand response, alternative energy and long-term forecast reports.  This was the last phase of SB 221 implementation rules.  These rules require electric utilities to file compliance reports demonstrating how they plan to meet the energy efficiency and demand response targets, what programs they have implemented, what the results of the programs were and what they expect customer response to future programs to be.  The rules also require DP&L to file an annual integrated resource plan that demonstrates the generation resources it plans to utilize to meet customer electric demands as well as alternative resource requirements, and the net impact of energy efficiency and demand response programs over a ten-year horizon.  In a subsequent entry, the PUCO established a proceeding whereby all Ohio electric utilities and interested parties are invited to work cooperatively to establish an energy efficiency measurement and verification manual that is designed to assist in verifying and measuring efficiency programs in the state of Ohio.  These proceedings are ongoing and may impact DP&L’s ability or inability to meet the energy efficiency and demand response targets established in SB 221.

Ohio Competitive Considerations and Proceedings

As of June 30, 2009, four unaffiliated marketers were registered as Competitive Retail Electric Service (CRES) providers in DP&L’s service territory, and a fifth unaffiliated marketer began the registration process but is not yet fully registered.  While there has been some customer switching associated with unaffiliated marketers, it represented less than 0.12% of sales in 2008.  DPLER, an affiliated company, is also a registered CRES provider and accounted for 99.4% of the total kWh supplied by CRES providers within DP&L’s service territory in 2008.

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Environmental Updates

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 SFAS No. 5 “Accounting for Contingencies” as discussed in Note 1 of Notes to Condensed Consolidated Financial Statements.   DPL, through its wholly owned captive insurance subsidiary MVIC, has an actuarially calculated reserve for environmental matters.  We evaluate the potential liability related to probable losses quarterly and may revise our estimates.  Such revisions in the estimates of the potential liabilities could have a material effect on our results of operations, financial position or cash flows.

Environmental Regulation and Litigation Related to Air Quality

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other gases are pollutants under the CAA.  The USEPA has not yet identified the specifics of how these newly designated pollutants will be regulated.

Pursuant tothe Clean Air Interstate Rule (CAIR) previously discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, the Ohio EPA initiated an Early Reduction Credit (ERC) program for annual NOx emission allowances for 2008 and 2009.  DP&L qualified and filed for the maximum number of ERCs that were initially allocable to DP&L.  DP&L has been informed that because certain unrelated entities failed to meet all requirements for their allocated ERCs, additional ERCs would be allocated to all entities that did qualify.  DP&L is expected to be allocated approximately 28% more ERCs than its initial allocation.

DP&L’s 2008 10-K filed in 2009 reports on litigation challenging USEPA final non-attainment designations for the national ambient air quality standard for Fine Particulate Matter 2.5 (PM2.5), including geographic areas in which DP&L has ownership in generation facilities. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting DP&L generation plants. At this point, DP&L cannot determine the effect of the ruling, if any, on its operations.

DP&L’s 2008 10-K filed in 2009 reports on litigation between the U.S. Department of Justice and 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.

DP&L’s 2008 10-K filed in 2009 reports on litigation between various residents of the Village of Moscow, Ohio sued CG&E, as the operator of Zimmer generating station (co-owned by CG&E,  DP&L and CSP).  A proposed settlement was filed on June 3, 2009, where it is pending court consideration after the requisite period runs for comment and for the exercise of any opt-out rights for members of the class.  The cash portion of the settlement was for $900,000, of which DP&L expects to be invoiced 28.1% based on its ownership share.  Non-cash portions of the settlement are not expected to have material effects on the future operation of the station.

DP&L’s 2008 10-K filed in 2009 reports on NOVs issued in 2007, by the Ohio EPA and the USEPA to DP&L for alleged violations of the CAA at the O.H. Hutchings station.  During 2009, DP&L has continued to submit various other operational and performance data to USEPA.  DP&L is unable to determine the timing, costs, or method by which the issues may be resolved.

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Environmental Regulation and Litigation Related to Land Use and Solid Waste Disposal

DP&L’s 2008 10-K filed in 2009 reports on a special notice received in 2002, that USEPA considers DP&L and other parties to be PRPs for the clean-up of hazardous substances at the South Dayton Dump landfill site.  No recent activity has occurred with respect to that notice or PRP status.  More recently, DP&L has received requests by the USEPA and the existing PRP group to allow access to be given to DP&L’s service center building site, which is across a street from the landfill site.  The USEPA requested access to drill monitoring and test wells to determine whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site.  DP&L has declined to grant such access and is unable to predict whether there will be further activity with respect to this request.  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.

FINANCIAL OVERVIEW

As more fully discussed in later sections of this Form 10-Q, the following were significant themes and events for the three months and six months ended June 30, 2009:

·During the three months and six months ended June 30, 2009, DP&L realized total gains of $14.4 million and $35.1 million, respectively, from sales of coal to various counterparties in connection with both DP&L and partner-operated generation facilities.  The gains realized from coal sales during the similar periods in 2008 amounted to $8.6 million and $11.8 million, respectively.  Net gains realized from coal sales are recorded as a component of fuel costs and reflected in operating income.

·During the three months and six months ended June 30, 2009, DP&L realized total gains of $1.2 million and $3.4 million, respectively, from sales of excess emission allowances to various counterparties compared to total gains of $4.0 million and $30.5 million realized during the respective periods in 2008.  Net gains realized from emission allowance sales are also recorded as a component of fuel costs and reflected in operating income.

·On February 19, 2009, the PUCO approved DP&L’s request to defer the net costs associated with transmission, capacity, ancillary service and other PJM-related charges that are incurred as a member of PJM, consistent with the provisions of SB 221.  Accordingly, during the six months ended June 30, 2009, DP&L deferred RTO costs in the amount of $28.6 million.  Of this amount, $13.5 million relates to the period August 1, 2008 through December 31, 2008, and $15.1 million relates to the six-month period ended June 30, 2009.  These RTO costs were capitalized as a regulatory asset resulting in a favorable impact to DP&L’s operating income.  Also included in the total deferred amount of $30.3 million is $1.1 million relating to RTEP costs as well as $0.6 million relating to interest and operation and maintenance expenses.  See Note 3 of Notes to Condensed Consolidated Financial Statements.

Also, for the three months ended June 30, 2009:

·DPL’s revenue decreased by 5% over the same period in 2008 mainly due to decreased retail sales volume and wholesale prices as well as lower RTO revenues, partially offset by increased retail prices and wholesale volume as well as increased RTO capacity revenues.

·DPL’s fuel costs increased by 11% over the same period in 2008 mainly due to an overall higher average cost of fuel consumed combined with the impact of lower gains realized in 2009 from the sale of emission allowances.  These increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal.

·DPL’s purchased power costs decreased by 26% over the same period in 2008 mainly as a result of lower RTO charges combined with the impact of decreased purchased power volumes and prices.  These decreases to purchased power costs were partially offset by increased RTO capacity charges.

·DPL’s operation and maintenance expenses increased by 8% over the same period in 2008 due to various factors which are discussed in later sections of this Item 2.

·DP&L’s revenues decreased by 7% over the same period in 2008 mainly due to decreased retail sales volume and wholesale prices as well as lower RTO revenues, partially offset by increased retail prices and wholesale volume as well as increased RTO capacity revenues.

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·DP&L’s fuel costs increased by 13% over the same period in 2008 mainly due to an overall higher average cost of fuel consumed combined with the impact of lower gains realized in 2009 from the sale of emission allowances.  These increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal.

·DP&L’s purchased power costs decreased by 28% over the same period in 2008 mainly as a result of lower RTO charges combined with the impact of decreased purchased power volumes and prices.  These decreases to purchased power costs were partially offset by increased RTO capacity charges.

·DP&L’s operation and maintenance expenses increased by 12% over the same period in 2008 due to various factors which are discussed in later sections of this Item 2.

For the six months ended June 30, 2009:

·DPL’s revenue decreased by 2% over the same period in 2008 mainly due to decreased retail and wholesale volumes, lower wholesale prices and decreased other RTO revenues.  These decreases were partially offset by increased retail prices and higher RTO capacity revenues.

·DPL’s fuel costs increased by 21% over the same period in 2008 mainly due to an overall higher average cost of fuel consumed combined with the impact of lower gains realized in 2009 from the sale of emission allowances.  These increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal as well as a decrease in generation output during 2009 compared to 2008.

·DPL’s purchased power costs decreased by 27% over the same period in 2008 mainly as a result of the deferral of RTO costs as discussed above, lower RTO charges and the impact of decreased purchased power volumes and prices.  These decreases to purchased power costs were partially offset by increased RTO capacity charges.

·DPL’s operation and maintenance expenses increased by 15% over the same period in 2008 due to various factors which are discussed in later sections of this Item 2.

·DP&L’s revenue decreased by 4% over the same period in 2008 mainly due to decreased retail and wholesale volumes, lower wholesale prices and decreased other RTO revenues.  These decreases were partially offset by increased retail prices and higher RTO capacity revenues.

·DP&L’s fuel costs increased by 21% over the same period in 2008 mainly due to an overall higher average cost of fuel consumed combined with the impact of lower gains realized in 2009 from the sale of emission allowances.  These increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal as well as a decrease in 2009 generation output compared to 2008.

·DP&L’s purchased power costs decreased by 29% over the same period in 2008 mainly as a result of the deferral of RTO costs as discussed above, lower RTO charges and the impact of decreased purchased power volumes and prices.  These decreases to purchased power costs were partially offset by increased RTO capacity charges.

·DP&L’s operation and maintenance expenses increased by 17% over the same period in 2008 due to various factors which are discussed in later sections of this Item 2.

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RESULTS OF OPERATIONS — DPL Inc.

DPL’s results of operations include the results of its subsidiaries, including 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						Six Months Ended
	June 30,						June 30,
$ in millions except per share amounts	2009			2008			2009			2008
Revenues:
Retail	$	282.2		$	287.0		$	602.5		$	605.1
Wholesale	19.7			39.8			50.6			96.9
RTO revenues	21.4			28.2			46.9			53.1
RTO capacity revenues	34.7			20.7			70.1			33.9
Other revenues	3.2			3.1			6.1			5.9
Total revenues	$	361.2		$	378.8		$	776.2		$	794.9
Cost of revenues:
Fuel costs	$	91.5		$	81.0		$	195.8		$	172.6
Gains from sale of coal	(14.4		)	(8.6		)	(35.1		)	(11.8		)
Gains from sale of emission allowances	(1.2		)	(4.0		)	(3.4		)	(30.5		)
Net fuel	75.9			68.4			157.3			130.3
Purchased power	14.0			29.8			29.7			65.4
RTO charges	22.2			37.2			52.8			72.5
RTO capacity charges	32.7			19.1			69.1			31.2
Deferral of RTO related charges	(5.6		)	—			(28.6		)	—
Total purchased power	63.3			86.1			123.0			169.1
Total cost of revenues	$	139.2		$	154.5		$	280.3		$	299.4
Gross margin (a)	$	222.0		$	224.3		$	495.9		$	495.5
Gross margin as a percentage of revenues	61		%	59		%	64		%	62		%
Operating income	$	81.9		$	85.6		$	208.9		$	228.3
Earnings per share of common stock:
Basic	$	0.38		$	0.43		$	0.99		$	1.14
Diluted	$	0.37		$	0.41		$	0.99		$	1.07

(a) For purposes of discussing operating results, we present and discuss gross margin. 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 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 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.

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

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2009 vs. 2008			2009 vs. 2008
Retail
Rate	$	18.9		$	48.5
Volume	(23.7		)	(50.5		)
Other	—			(0.6		)
Total retail change	$	(4.8	)	$	(2.6	)
Wholesale
Rate	$	(22.7	)	$	(26.1	)
Volume	2.6			(20.2		)
Total wholesale change	$	(20.1	)	$	(46.3	)
RTO capacity and other
RTO capacity and other revenues	$	7.3		$	30.2
Total revenues	$	(17.6	)	$	(18.7	)

For the three months ended June 30, 2009, revenues decreased $17.6 million, or 5%, to $361.2 million from $378.8 million for the same period in the prior year.  This decrease was primarily the result of lower retail sales volume and lower wholesale average rates, partially offset by higher average rates for retail sales, increased RTO capacity and other revenues, as well as increased wholesale sales volume. The revenue components for the three months ended June 30, 2009, are further discussed below:

·Retail revenues decreased $4.8 million resulting from an 8% decrease in sales volume driven largely by the economic recession, partially offset by a 7% increase in average retail rates due largely to the incremental effect of the recovery of costs under the second phase of the environmental investment rider (EIR) combined with the implementation of the Transmission Cost Recovery Rider (TCRR). The recovery of costs under the TCRR began on June 1, 2009.  As a result, retail revenues had an unfavorable $23.7 million sales volume variance and a favorable $18.9 million price variance.

·Wholesale revenues decreased $20.1 million primarily as a result of a 54% decrease in wholesale average rates, partially offset by a 6% increase in sales volume, resulting in an unfavorable $22.7 million wholesale price variance and a favorable $2.6 million volume variance.

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·RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $7.3 million compared to the same period in the prior year.  This increase to RTO capacity and other RTO revenues was primarily the result of additional revenue of $14.0 million that was realized from the PJM capacity auction, partially offset by a decrease in PJM transmission and congestion revenues of $6.8 million.

For the six months ended June 30, 2009, revenues decreased $18.7 million, or 2%, to $776.2 million from $794.9 million for the same period in the prior year.  This decrease was primarily the result of lower retail and wholesale sales volume as well as decreased wholesale average rates, partially offset by higher average retail rates and an increase in RTO capacity and other revenues. The revenue components for the six months ended June 30, 2009, are further discussed below:

·Retail revenues decreased $2.6 million resulting primarily from an 8% decrease in sales volume driven largely by the economic recession and milder weather conditions, partially offset by a 9% increase in average retail rates due largely to the incremental effect of the recovery of costs under the second phase of the EIR combined with the implementation of the TCRR.  As a result, retail revenues had an unfavorable $50.5 million sales volume variance and a favorable $48.5 million price variance.

·Wholesale revenues decreased $46.3 million primarily as a result of a 34% decrease in wholesale average rates combined with a 21% decrease in sales volume, resulting in an unfavorable $26.1 million wholesale price variance and an unfavorable $20.2 million volume variance.

·RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $30.2 million compared to the same period in the prior year.  This increase was primarily the result of additional revenue of $36.2 million that was realized from the PJM capacity auction, partially offset by a decrease in PJM transmission and congestion revenues of $6.2 million.

DPL — Cost of Revenues

For the three months ended June 30, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $7.5 million, or 11%, compared to the same period in 2008, primarily due to a 14% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from increased coal prices and outages at lower-cost units.  Also contributing to the increase in fuel costs was the impact of lower gains realized from the sale of excess emission allowances.  In 2009, DP&L realized $1.2 million in gains from the sale of excess emission allowances compared to $4.0 million during the same period in 2008.  The above increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal.  Gains from the sale of coal amounted to $14.4 million compared to $8.6 million for the same period in 2008.

·Purchased power decreased $22.8 million, or 26%, compared to the same period in 2008.  The decrease in purchased power primarily resulted from a $10.7 million decrease relating to lower average market rates, a $7.0 million decrease in RTO capacity and other RTO charges, and a $5.0 million decrease relating to lower volumes of purchased power.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

For the six months ended June 30, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $27.0 million, or 21%, compared to the same period in 2008, primarily due to a 19% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from increased coal prices and outages at lower-cost units.  Also contributing to the increase in fuel costs was the impact of lower gains realized from the sale of excess emission allowances.  In 2009, DP&L realized $3.4 million in gains from the sale of excess emission allowances compared to $30.5 million during the same period in 2008.  The above increases to fuel costs were partially offset by a decrease in the usage of fuel due mainly to a 4% decrease in generation output, as well as higher gains realized in 2009 from the sale of coal.  In 2009, gains from the sale of coal amounted to $35.1 million compared to $11.8 million for the same period in 2008.

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·Purchased power decreased $46.1 million compared to the same period in 2008.  The net decrease in purchased power is partly a result of the deferral in 2009 of costs relating to DPL’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM.  The deferral is discussed in greater detail in the Financial Overview section above.  Also contributing to the decrease in purchased power were decreases of $14.8 million and $20.9 million relating to lower average market rates and lower volumes of purchased power, respectively.  These decreases were partially offset by increased RTO capacity and other RTO charges.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

DPL — Operation and Maintenance

The following table provides a summary of the significant changes from the prior periods of the operation and maintenance expense items.

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2009 vs. 2008			2009 vs. 2008
Generating facilities operating and maintenance expenses	$	2.6		$	7.2
Low-income payment program	1.3			3.4
Pension	1.5			2.9
ESOP	0.7			2.1
Other, net	(0.4		)	4.7
Total operation and maintenance expense	$	5.7		$	20.3

During the three months and six months ended June 30, 2009, operation and maintenance expense increased $5.7 million, or 8%, and $20.3 million, or 15%, respectively, compared to similar periods in 2008.  These variances were primarily the result of:

·increases in operating and maintenance expenses for generating facilities largely due to costs associated with an unplanned outage at a jointly-owned production unit as well as the operation of FGD and SCR equipment,

·increases in the USF rate rider related to assistance for low-income retail customers,

·higher pension costs due primarily to a decline in the values of pension plan assets and increased benefits, and

·increases in employee incentive and benefit expense funded by the ESOP.

DPL — Depreciation and Amortization

For the three months and six months ended June 30, 2009, depreciation and amortization expense increased $1.8 million and $4.5 million, respectively, compared to the similar periods in 2008 primarily as a result of higher asset balances at the generating stations.  These higher balances were due largely to the completion of the FGD projects in 2008.

DPL — General Taxes

For the three months and six months ended June 30, 2009, general taxes decreased $5.0 million and $2.7 million, respectively, to $27.5 million and $59.6 million, respectively, compared to the similar periods in 2008.  These decreases were primarily the result of lower property tax accruals in 2009 compared to 2008.

DPL — Amortization of Regulatory Assets

For the three months and six months ended June 30, 2009, the amortization of regulatory assets was $1.1 million and $2.3 million, respectively, lower than that of the similar periods in 2008, primarily reflecting the 2008 amortization of incremental costs incurred in 2004 and 2005 for severe storms.  These storm costs were fully amortized in the third quarter of 2008.

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DPL — Interest Expense

For the three months ended June 30, 2009, interest expense decreased $5.6 million compared to the same period in 2008 primarily due to:

·a $4.3 million reduction in interest expense due to the redemption of DPL’s $175 million 8.00% Senior Notes and the $100 million 6.25% Senior Notes on March 31, 2009 and May 15, 2008, respectively, and

·a $1.6 million write-off in 2008 of unamortized debt issuance costs relating to DP&L’s $90 million variable rate pollution control bonds following their repurchase from the bondholders on April 4, 2008.

For the six months ended June 30, 2009, interest expense decreased $4.9 million compared to the same period in 2008 primarily due to:

·a $5.8 million reduction in interest expense due to the redemption of DPL’s $175 million 8.00% Senior Notes and the $100 million 6.25% Senior Notes on March 31, 2009 and May 15, 2008, respectively,

·a $1.6 million write-off in 2008 of unamortized debt issuance costs relating to DP&L’s $90 million variable rate pollution control bonds following their repurchase from the bondholders on April 4, 2008, and

·lower rates of interest on the $100 million Revenue Refunding Bonds issued in December 2008, as compared to the $90 million Revenue Bonds which were issued in November 2007 and redeemed in December 2008.

The above decreases were partially offset by $4.8 million of lower capitalized interest in 2009 compared to 2008, due largely to the completion of the FGD projects at the generation stations.

DPL — Income Tax Expense

For the three months ended June 30, 2009, income taxes increased $5.5 million, or 39%, compared to the same period in 2008, primarily reflecting a 2008 decrease in tax expense due to the $42 million settlement of the Ohio Franchise Tax issues, partially offset by a decrease in the effective tax rate resulting from the phase-out of the Ohio Franchise Tax.

For the six months ended June 30, 2009, income taxes decreased $3.5 million, or 6%, compared to the same period in 2008, primarily reflecting a decrease in pre-tax book income and a decrease in the effective tax rate resulting from the phase-out of the Ohio Franchise Tax, partially offset by a 2008 decrease in tax expense due to the settlement of the Ohio Franchise Tax issues mentioned above.

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

Income Statement Highlights — DP&L

	Three Months Ended June 30,						Six Months Ended June 30,
$ in millions	2009			2008			2009			2008
Revenues:
Retail	$	265.9		$	248.7		$	574.0		$	531.5
Wholesale	36.0			78.8			77.0			171.8
RTO revenues	20.7			28.2			45.2			53.1
RTO capacity revenues	29.3			20.7			59.3			33.9
Total revenues	$	351.9		$	376.4		$	755.5		$	790.3
Cost of revenues:
Fuel costs	$	90.0		$	78.5		$	191.7		$	168.9
Gains from sale of coal	(14.4		)	(8.6		)	(35.1		)	(11.8		)
Gains from sale of emission allowances	(1.2		)	(4.0		)	(3.4		)	(30.5		)
Net fuel	74.4			65.9			153.2			126.6
Purchased power	14.1			31.5			29.7			68.0
RTO charges	22.2			37.2			52.3			72.5
RTO capacity charges	32.6			19.1			69.0			31.2
Deferral of RTO related charges	(5.6		)	—			(28.6		)	—
Total purchased power	$	63.3		$	87.8		$	122.4		$	171.7
Total cost of revenues	$	137.7		$	153.7		$	275.6		$	298.3
Gross margin (a)	$	214.2		$	222.7		$	479.9		$	492.0
Gross margin as a percentage of revenues	61		%	59		%	64		%	62		%
Operating income	$	78.9		$	90.5		$	203.7		$	236.9

(a)For purposes of discussing operating results, we present and discuss gross margin. 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.

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.

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

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2009 vs. 2008			2009 vs. 2008
Retail
Rate	$	37.6		$	87.3
Volume	(20.4		)	(44.3		)
Other	—			(0.5		)
Total retail change	$	17.2		$	42.5
Wholesale
Rate	$	(45.7	)	$	(53.5	)
Volume	2.8			(41.3		)
Total wholesale change	$	(42.9	)	$	(94.8	)
RTO capacity and other
RTO capacity and other revenues	$	1.2		$	17.5
Total revenues	$	(24.5	)	$	(34.8	)

For the three months ended June 30, 2009, revenues decreased $24.5 million, or 7%, to $351.9 million from $376.4 million in the same period of the prior year.  This decrease was primarily the result of lower average rates for wholesale sales and lower retail sales volume, partially offset by higher average rates for retail sales and higher wholesale volumes. The revenue components for the three months ended June 30, 2009, are further discussed below:

·Retail revenues increased $17.2 million resulting primarily from a 17% increase in average retail rates due largely to the incremental effect of the recovery of costs under the second phase of the EIR combined with the implementation of the TCRR.  The recovery of costs under the TCRR began on June 1, 2009.  This increase was partially offset by an 8% decrease in sales volume driven largely by the economic recession.  As a result, retail revenues had a favorable $37.6 million price variance and an unfavorable $20.4 million sales volume variance.

·Wholesale revenues decreased $42.9 million primarily as a result of a 56% decrease in wholesale average rates, partially offset by a 3% increase in sales volume, resulting in an unfavorable $45.7 million wholesale price variance and a favorable $2.8 million volume variance.

·RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $1.2 million compared to the same period in the prior year.  This increase primarily resulted from additional revenue of $8.6 million that was realized from the PJM capacity auction, partially offset by a decrease in PJM transmission and congestion revenues of $7.5 million.

50

For the six months ended June 30, 2009, revenues decreased $34.8 million, or 4%, to $755.5 million from $790.3 million in the same period of the prior year.  This decrease was primarily the result of lower retail and wholesale sales volume and lower wholesale average rates, partially offset by higher retail average rates and an increase in RTO capacity and other revenues. The revenue components for the six months ended June 30, 2009, are further discussed below:

·Retail revenues increased $42.5 million resulting primarily from an 18% increase in average retail rates due largely to the second phase of the EIR and the implementation of the TCRR, partially offset by an 8% decrease in retail sales volume.  As a result, retail revenues had a favorable $87.3 million price variance and an unfavorable $44.3 million sales volume variance.

·Wholesale revenues decreased $94.8 million primarily as a result of a 41% decrease in wholesale average rates, combined with a 24% decrease in sales volume, resulting in an unfavorable $53.5 million wholesale price variance and an unfavorable $41.3 million volume variance.

·RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $17.5 million compared to the same period in the prior year.  This increase primarily resulted from additional revenue of $25.4 million that was realized from the PJM capacity auction, partially offset by a $7.9 million decrease in PJM transmission and congestion revenues.

DP&L — Cost of Revenues

For the three months ended June 30, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $8.5 million, or 13%, compared to the same period in 2008 primarily due to a 16% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from increased coal prices and outages at lower-cost units. Also contributing to the increase in fuel costs was the impact of lower gains realized from the sale of excess emission allowances.  In 2009, DP&L realized $1.2 million in gains from the sale of excess emission allowances compared to $4.0 million during the same period in 2008.  The above increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal.  Gains from the sale of coal amounted to $14.4 million compared to $8.6 million for the same period in 2008.

·Purchased power decreased $24.5 million, or 28%, compared to the same period in 2008.  The decrease in purchased power primarily results from an $11.6 million decrease relating to lower average market rates, a $6.9 million decrease in RTO capacity and other RTO charges, and a $5.9 million decrease relating to lower volumes of purchased power.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

For the six months ended June 30, 2009:

·Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $26.6 million, or 21%, compared to the same period in 2008, primarily due to a 19% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from increased coal prices and outages at lower-cost units.  Also contributing to the increase in fuel costs was the impact of lower gains realized from the sale of excess emission allowances.  In 2009, DP&L realized $3.4 million in gains from the sale of excess emission allowances compared to $30.5 million during the same period in 2008.  The above increases to fuel costs were partially offset by a decrease in the usage of fuel due mainly to a 5% decrease in generation output, as well as higher gains realized in 2009 from the sale of coal.  Gains from the sale of coal amounted to $35.1 million compared to $11.8 million for the same period in 2008.

·Purchased power decreased $49.3 million compared to the same period in 2008.  The net decrease in purchased power is partly a result of the deferral in 2009 of costs relating to DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM.  See Financial Overview section above.  Also contributing to the decrease in purchased power were lower incurred RTO charges as well as decreases of $15.7 million and $22.6 million relating to lower average market rates and lower volumes of purchased power, respectively.  These decreases were partially offset by increased RTO capacity charges.  We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unanticipated outages, or when market prices are below the marginal costs associated with our generating facilities.

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DP&L — Operation and Maintenance

The following table provides a summary of the significant changes from the prior periods of the operation and maintenance expense items:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
$ in millions	2009 vs. 2008		2009 vs. 2008
Generating facilities operating and maintenance expenses	$	2.6	$	7.2
Low-income payment program	1.3		3.4
Pension	1.5		2.9
ESOP	0.7		2.1
Other, net	1.5		6.1
Total operation and maintenance expense	$	7.6	$	21.7

During the three months and six months ended June 30, 2009, operation and maintenance expense increased $7.6 million, or 12%, and $21.7 million, or 17%, respectively, compared to similar periods in 2008.  These variances were primarily the result of:

·increases in operating and maintenance expenses for generating facilities largely due to costs associated with an unplanned outage at a jointly-owned production unit as well as the operation of FGD and SCR equipment,

·increases in the USF rate rider related to assistance for low-income retail customers,

·higher pension costs due primarily to a decline in the values of pension plan assets and increased benefits, and

·increases in employee incentive and benefit expense funded by the ESOP.

DP&L — Depreciation and Amortization

For the three months and six months ended June 30, 2009, depreciation and amortization expense increased $1.7 million and $4.4 million, respectively, compared to the similar periods in 2008 primarily as a result of higher asset balances at the generating stations.  These higher balances were due largely to the completion of the FGD projects in 2008.

DP&L — General Taxes

For the three months and six months ended June 30, 2009, general taxes decreased $5.1 million and $2.7 million, respectively, to $27.2 million and $59.1 million, respectively, compared to the similar periods in 2008.  These decreases were primarily the result of lower property tax accruals in 2009 compared to 2008.

DP&L — Amortization of Regulatory Assets

For the three months and six months ended June 30, 2009, the amortization of regulatory assets was $1.1 million and $2.3 million, respectively, lower than that of the similar periods in 2008, primarily reflecting the 2008 amortization of incremental costs incurred in 2004 and 2005 for severe storms.  These storm costs were fully amortized in the third quarter of 2008.

DP&L — Interest Expense

Interest expense for the three months ended June 30, 2009 decreased $1.2 million compared to the same period of the prior year primarily as a result of a $1.6 million write-off in 2008 of unamortized debt issuance costs relating to DP&L’s $90 million variable rate pollution control bonds following their repurchase from the bondholders on April 4, 2008.

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Interest expense for the six months ended June 30, 2009 increased $0.9 million compared to the same period of the prior year primarily as a result of $4.8 million of lower capitalized interest in 2009 compared to 2008, due largely to the completion of the FGD projects at the generation stations.  This increase was partially offset by:

·a $1.6 million write-off in 2008 of unamortized debt issuance costs relating to DP&L’s $90 million variable rate pollution control bonds following their repurchase from the bondholders on April 4, 2008, and

·lower rates of interest on the $100 million Revenue Refunding Bonds issued in December 2008, as compared to the $90 million Revenue Bonds which were issued in November 2007 and redeemed in December 2008.

DP&L — Income Tax Expense

For the three months ended June 30, 2009, income taxes increased $1.6 million, or 8%, compared to the same period in the prior year, primarily reflecting a 2008 decrease in tax expense due to the $42 million settlement of the Ohio Franchise Tax issues, partially offset by a decrease in pre-tax book income and a decrease in the effective tax rate resulting from the phase-out of the Ohio Franchise Tax.

For the six months ended June 30, 2009, income taxes decreased $9.6 million, or 13%, compared to the same period in the prior year, primarily reflecting a decrease in pre-tax book income and a decrease in the effective tax rate resulting from the phase-out of the Ohio Franchise Tax, partially offset by a 2008 decrease in tax expense due to the settlement of the Ohio Franchise Tax issues mentioned above.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

DPL’s financial condition, liquidity and capital requirements include the consolidated results of DP&L and DPL’s consolidated subsidiaries.  All material intercompany accounts and transactions have been eliminated in consolidation.

DPL’s Cash Position

DPL’s cash and cash equivalents totaled $55.8 million at June 30, 2009, compared to $62.5 million at December 31, 2008, a decrease of $6.7 million.  The decrease in cash and cash equivalents was primarily attributed to the retirement of $175 million of long-term debt, $89.6 million of capital expenditures, $63.8 million of dividends paid on common stock, $15.9 million used to repurchase outstanding stock warrants, and a $15 million repayment on the revolving credit facility, partially offset by a $155 million cash borrowing from the revolving credit facility, cash generated from operating activities of $184.7 million, net withdrawals of $6.7 million from restricted funds drawn to fund pollution control capital expenditures and $5 million of cash from the maturity of a short-term investment.  At June 30, 2009, DPL had $7.9 million in restricted funds held in trust to fund pollution control capital expenditures.

DP&L’s Cash Position

DP&L’s cash and cash equivalents totaled $23.1 million at June 30, 2009, compared to $20.8 million at December 31, 2008, an increase of $2.3 million. The increase in cash and cash equivalents was primarily attributed to $162.7 million in cash generated from operating activities, a $155 million borrowing from the revolving credit facility and net withdrawals of $6.7 million from restricted funds to pay for pollution control capital expenditures.  These cash inflows were partially offset by $220 million in dividends paid on common stock to our parent DPL, $86.7 million used for capital expenditures, and a $15 million repayment on the revolving credit facility.  At June 30, 2009, DP&L had $7.9 million in restricted funds held in trust to fund pollution control capital expenditures.

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Operating Activities

For the six months ended June 30, 2009 and 2008, cash flows from operations were as follows:

Net Cash provided by Operating Activities

	Six Months Ended
	June 30,
$ in millions	2009		2008
DPL	$	184.7	$	200.4
DP&L	$	162.7	$	212.9

The tariff-based revenue from our energy business continues to be the principal source of cash from operating activities.  Management believes that the diversified retail customer mix of residential, commercial and industrial classes coupled with the rate relief approved by the PUCO will provide us with a reasonably predictable gross cash flow from operations.

DPL’s Cash provided by Operating Activities

DPL generated net cash from operating activities of $184.7 million and $200.4 million in the six-month periods ended June 30, 2009 and 2008, respectively.  The net cash provided by operating activities for 2009 and 2008 was primarily the result of cash received from utility customers, partially offset by cash used for fuel, purchased power, operating expenditures, interest and taxes.  The fluctuations in certain assets and liabilities result from the timing of payments made and cash receipts from our utility customers.

DP&L’s Cash provided by Operating Activities

DP&L generated net cash from operating activities of $162.7 million and $212.9 million in the six-month periods ended June 30, 2009 and 2008, respectively.  The net cash provided by operating activities for 2009 and 2008 was primarily the result of cash received from utility customers, partially offset by cash used for fuel, purchased power, operating expenditures, interest and taxes.  The fluctuations in certain assets and liabilities result from the timing of payments made and cash receipts from our utility customers.

Investing Activities

For the six months ended June 30, 2009 and 2008, cash flows from investing activities were as follows:

Net Cash used for Investing Activities

	Six Months Ended
	June 30,
$ in millions	2009			2008
DPL	$	(83.4	)	$	(118.4	)
DP&L	$	(86.7	)	$	(117.7	)

DPL’s Cash used for Investing Activities

DPL’s net cash used for investing activities was $83.4 million and $118.4 million in the six-month periods ended June 30, 2009 and 2008, respectively.  Net cash flows used for investing activities during both of these periods were primarily related to capital expenditures.

DP&L’s Cash used for Investing Activities

DP&L’s net cash used for investing activities were $86.7 million and $117.7 million in the six-month periods ended June 30, 2009 and 2008, respectively.  Net cash flows used for investing activities during both of these periods were related to capital expenditures.

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Financing Activities

For the six months ended June 30, 2009 and 2008, cash flows from financing activities were as follows:

Net Cash used for Financing Activities

	Six Months Ended
	June 30,
$ in millions	2009			2008
DPL	$	(108.0	)	$	(138.2	)
DP&L	$	(73.7	)	$	(79.9	)

DPL’s Cash used for Financing Activities

DPL’s net cash used for financing activities in the six months ended June 30, 2009 was $108 million compared to $138.2 million during the same period of the prior year.  Net cash flows used for financing activities in the six months ended June 30, 2009 were primarily the result of cash used to retire $175 million of long-term debt, to pay dividends of $63.8 million to stockholders, to repurchase $15.9 million of outstanding stock warrants, and to repay $15 million on the revolving credit facility, partially offset by a borrowing of $155 million from the revolving credit facility and net withdrawals of $6.7 million from the restricted funds held in trust.  Net cash flows used for financing activities in the six months ended June 30, 2008 were primarily the result of cash used to redeem the $100 million of long-term debt and to pay dividends of $59.9 million to stockholders, partially offset by net withdrawals of $20.5 million from the restricted funds held in trust.

DP&L’s Cash used for Financing Activities

DP&L’s net cash used for financing activities in the six months ended June 30, 2009 were $73.7 million compared to $79.9 million during the same period of the prior year.  Net cash flows used for financing activities in the six months ended June 30, 2009 were primarily the result of cash used to pay common stock dividends of $220 million to our parent DPL and a $15 million repayment on the revolving credit facility, partially offset by a borrowing of $155 million from the revolving credit facility and $6.7 million in net withdrawals from restricted funds held in trust.  Net cash flows used for financing activities for the six months ended June 30, 2008 were primarily the result of cash used to pay common stock dividends of $80 million to our parent DPL and the repayment of a short-term loan from DPL of $20 million, partially offset by net withdrawals of $20.5 million from restricted funds held in trust.

DPL and DP&L have obligations to make future payments for capital expenditures, debt agreements, lease agreements and other long-term purchase obligations and have certain contingent commitments such as guarantees.  We believe our cash flows from operations, the credit facilities (existing or future arrangements), the senior notes and other short- and long-term debt financing, will be sufficient to satisfy our future working capital, capital expenditures and other financing requirements for the foreseeable future.  Our ability to generate positive cash flows is dependent on general economic conditions, competitive pressures and other business and risk factors described in Item 1a of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and supplemented by those described in Part II, Item 1a of this quarterly report.  If we are unable to generate sufficient cash flows, or otherwise comply with the terms of our credit facilities, the senior notes and other long-term debt, we may be required to refinance all or a portion of our existing debt or seek additional financing alternatives.  A discussion of each of our critical liquidity commitments is outlined below.

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Revolving Credit Facility

On April 21, 2009, DP&L entered into a $100 million unsecured revolving credit agreement with a syndicated bank group.  The agreement is for a 364-day term expiring on April 20, 2010.  The facility contains one financial covenant: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00.  As of June 30, 2009, DP&L was in compliance with this covenant with a ratio of 0.44 to 1.00.  As of June 30, 2009, DP&L had no outstanding borrowings under this facility.

Future Liquidity

On July 29, 2009, DP&L repaid $105 million of the $140 million borrowing that was outstanding under the $220 million unsecured revolving credit agreement. This repayment was made using $25 million of cash on hand and an $80 million withdrawal that was made on July 28, 2009 from the $100 million facility referred to in the preceding paragraph.  After this transaction, the borrowings outstanding under both revolving credit facilities amount to $115 million and the combined cash available to DP&L under these revolving credit facilities amounts to $205 million.

In addition, at June 30, 2009, DP&L had a net tax receivable in the amount of $79.9 million resulting from the recognition of certain tax benefits (see Note 14 of Notes to Condensed Consolidated Financial Statements).  This receivable is available to be offset against future income tax liabilities and is expected to be fully recouped within the next 12 months.

Capital Requirements

DPL’s construction additions were $72.5 million and $106.5 million during the six-month periods ended June 30, 2009 and 2008, respectively.  DPL is expected to spend approximately $87 million for the remainder of 2009.

DP&L’s construction additions were $71.5 million and $105.8 million during the six-month periods ended June 30, 2009 and 2008, respectively.  DP&L is expected to spend approximately $86 million for the remainder of 2009.  Planned construction additions for 2009 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 $500 million in capital projects for the period 2009 through 2011.  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 in 2009 with a combination of cash on hand, short-term financing, long-term debt and cash flows from operations.

Debt Covenants

There have been no changes to our debt covenants as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.  We are in compliance with these debt covenants.

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.  Standard & Poor’s Corporation and Moody’s Investors Service revised their rating and outlook in April 2009 and June 2009, respectively, for both DPL and DP&L.

	DPL Inc. (a)	DP&L (b)	Outlook	Effective
Fitch Ratings	BBB+	A+	Positive	April 2008
Moody’s Investors Service	Baa1	A1	Stable	June 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.

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Off-Balance Sheet Arrangements

DPL Inc. - Guarantees

In the normal course of business, DPL enters into various agreements with our wholly owned generating subsidiary DPLE providing financial or performance assurance to third parties.  These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s intended commercial purposes.  Such agreements fall outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”  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, 2008.

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, 2008.

MARKET RISK

In the normal course of business, we are subject to certain market risks including, but not limited to, changes in commodity prices for electricity, coal, environmental emissions and gas, as well as fluctuations in interest rates.  Economic pressures, as well as changing global market conditions and other factors related to physical energy and financial trading activities, which include price, credit, liquidity, volatility, capacity, transmission and interest rates also can have a significant effect on our operations and the operations of our customers.  Commodity pricing exposure includes the impacts of weather, market demand, increased competition and other economic conditions.  For purposes of potential risk analysis, we use sensitivity analysis to quantify potential impacts of market rate changes on the results of operations. The sensitivity analysis represents hypothetical changes in market values that may or may not occur in the future.

Our Commodity Risk Management Committee (CRMC) is responsible for establishing risk management policies and the monitoring and reporting of risk exposures. 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

In 2008 and during the six months ended June 30, 2009, the coal market has experienced unprecedented price volatility.  The coal market has increasingly been influenced by international rather than solely domestic supply and consumption, and coal prices, while still volatile week to week, have been generally exhibiting a downward trend since the second half of 2008.   While we have all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2009 under contract, sales requirements may change, particularly for retail load.  To the extent we are not able to hedge against price volatility, our results of operations, financial position or cash flows could be materially affected.

Approximately 7% of DPL’s and 10% of DP&L’s electric revenues for the six months ended June 30, 2009 were from sales of excess energy 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. As of June 30, 2009, a hypothetical increase or decrease of 10% in DPL’s annual wholesale revenues could result in approximately a $7 million increase or decrease to net income, assuming no increases in fuel and purchased power costs.  As of June 30, 2009, a hypothetical increase or decrease of 10% in DP&L’s annual wholesale revenues could result in approximately a $10 million increase or decrease to net income, assuming no increases in fuel and purchased power costs.

DPL’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs in the six months ended June 30, 2009 and 2008 were 49% and 53%, respectively.   DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs were 50% and 54% for the six-month periods ending June 30, 2009 and 2008, respectively.  We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2009 under contract.  The majority of our contracted coal is purchased at fixed prices.  Some contracts provide for periodic adjustment and some are priced based on market indices.  Substantially all contracts have features that limit price escalations in any given year.  We do not expect to purchase SO2

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allowances for 2009, 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 2009.  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.  Based on higher volume and price, fuel costs excluding the effect of emission allowance sales are forecasted to be 15% to 20% higher in 2009 compared to 2008.

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 production costs. As of June 30, 2009, a hypothetical increase or decrease of 10% in DPL’s annual fuel and purchased power costs could result in approximately a $30 million increase or decrease to net income.  As of June 30, 2009, a hypothetical increase or decrease of 10% in DP&L’s annual fuel and purchased power costs could result in approximately a $30 million increase or decrease to net income.

Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities.  We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations.  DPL has fixed-rate long-term debt and DP&L has both fixed and variable-rate long-term debt.  DP&L’s variable-rate debt is comprised of 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 long-term debt was $1,376.6 million at June 30, 2009, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, DPL’s unsecured notes and DP&L’s capital lease.  The fair value of this debt was $1,285.9 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities.

The carrying value of DP&L’s long-term debt was $884.5 million at June 30, 2009, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds and DP&L’s capital lease.  The fair value of this debt was $814.3 million, based on current market prices or discounted cash flows using rates for similar issues with similar terms and remaining maturities.

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, 2008 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 Inc.								DP&L (a)
	Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
	2009		2008		2009		2008		2009		2008		2009		2008
Electric sales (millions in kWh)
Residential	1,024		1,089		2,625		2,769		1,024		1,089		2,625		2,769
Commercial	922		987		1,838		1,946		922		987		1,838		1,946
Industrial	853		996		1,613		1,963		853		996		1,613		1,963
Other retail	358		369		696		716		358		369		696		716
Total retail	3,157		3,441		6,772		7,394		3,157		3,441		6,772		7,394
Wholesale	553		520		1,124		1,419		538		520		1,078		1,419
Total	3,710		3,961		7,896		8,813		3,695		3,961		7,850		8,813
Operating revenues ($ in thousands)
Residential	$	115,609	$	113,921	$	275,860	$	269,590	$	115,609	$	113,921	$	275,860	$	269,590
Commercial	82,087		85,767		162,642		164,671		81,100		79,137		161,723		153,409
Industrial	57,035		60,070		110,876		118,207		45,904		33,301		90,990		64,687
Other retail	25,246		25,021		48,966		47,852		21,073		20,183		41,238		39,079
Other miscellaneous revenues	2,138		2,173		4,113		4,749		2,186		2,188		4,178		4,747
Total retail	282,115		286,952		602,457		605,069		265,872		248,730		573,989		531,512
Wholesale	19,679		39,854		50,583		96,925		35,873		78,755		76,951		171,810
RTO revenues	56,119		48,969		117,031		87,022		50,167		48,968		104,580		87,022
Other revenues	3,231		3,042		6,093		5,899		—		—		—		—
Total	$	361,144	$	378,817	$	776,164	$	794,915	$	351,912	$	376,453	$	755,520	$	790,344
Electric customers at end of period
Residential	455,809		456,308		455,809		456,308		455,809		456,308		455,809		456,308
Commercial	50,109		49,961		50,109		49,961		50,109		49,961		50,109		49,961
Industrial	1,788		1,800		1,788		1,800		1,788		1,800		1,788		1,800
Other	6,546		6,473		6,546		6,473		6,546		6,473		6,546		6,473
Total	514,252		514,542		514,252		514,542		514,252		514,542		514,252		514,542

(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.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

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 is 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 June 30, 2009 that has materially affected, or is reasonably likely to materially affect, internal control over reporting.

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Part II — Other Information

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 believe the amounts provided in our condensed 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 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 June 30, 2009, cannot be reasonably determined.

Our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and Quarterly Report on Form 10-Q for the three months ended March 31, 2009, contain descriptions of certain legal proceedings in which we are or were involved.  The information in this Item 1 of this Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and should be read in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, and our Quarterly Report on Form 10-Q for the three months ended March 31, 2009.

As previously reported, on May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal expenses associated with our litigation against certain former executives.  Arbitration on that claim occurred on May 13, 2009 and the outcome is pending.  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.

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 6 of this report.  If any of these events occur, our business, financial position or results of operation could be materially affected.

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

None

Item 3 — Defaults Upon Senior Securities

None

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

DPL held its Annual Meeting of Shareholders on April 29, 2009, at which security holders elected the three directors nominated for three-year terms expiring 2012.  The results of the voting were as follows:

	FOR	WITHHELD	BROKER NON-VOTE
Paul R. Bishop	95,710,770	1,365,527	—
Frank F. Gallaher	95,770,159	1,306,138	—
General Lester L. Lyles (Ret.)	95,091,201	1,985,096	—

The other directors whose terms of office continued after the Annual Meeting are Robert D. Biggs, Pamela B. Morris and Ned J. Sifferlen (each of the class of 2010) and Paul M. Barbas, Barbara S. Graham and Glenn E. Harder (each of the class of 2011).

Security holders also voted to ratify the selection of KPMG LLP as DPL’s independent public accountant for 2009.  The results of the voting were as follows:

FOR	AGAINST	ABSTAIN	BROKER NON-VOTE
95,658,932	788,016	629,347	—

Item 5 — Other Information

None

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Item 6 — Exhibits

		Exhibit
DPL Inc.	DP&L	Number	Exhibit	Location
X	X	10(a)	Amendment No. 1, dated as of April 9, 2009, to Credit Agreement, dated as of November 21, 2006, among the Dayton Power and Light Company, KeyBank National Association and certain lending institutions	Filed herewith as Exhibit 10(a)
X	X	10(b)	Credit Agreement by and among The Dayton Power and Light Company and the lenders party thereto and PNC Bank, National Association, as Administrative Agent, dated as of April 21, 2009	Exhibit 10.1 to Form 8-K filed April 24, 2009 (File No. 1-2385)
X	X	10(c)*	Participation Agreement dated May 18, 2009, among DPL Inc., The Dayton Power and Light Company and Joseph W. Mulpas	Exhibit 10.1 to Form 8-K filed May 18, 2009 (File No. 1-9052)
X		10(d)	Form of DPL Inc. Restricted Stock Agreement	Filed herewith as Exhibit 10(d)
X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)

* Management contract or compensatory plan

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, DPL Inc. and The Dayton Power and Light Company has duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

		DPL Inc.
		The Dayton Power and Light Company
		(Registrants)
Date:	July 29, 2009	/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer (principal executive officer)
	July 29, 2009	/s/ Frederick J. Boyle
		Frederick J. Boyle
		Senior Vice President, Chief Financial Officer and Treasurer (principal financial officer)
	July 29, 2009	/s/ Joseph W. Mulpas
		Joseph W. Mulpas
		Vice President, Controller and Chief Accounting Officer (principal accounting officer)

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