DAYTON POWER & LIGHT CO - FORM 10-Q

Attached files

file	filename
EX-32.C - EX-32.C - DAYTON POWER & LIGHT CO	a09-31198_1ex32dc.htm
EX-31.D - EX-31.D - DAYTON POWER & LIGHT CO	a09-31198_1ex31dd.htm
EX-31.C - EX-31.C - DAYTON POWER & LIGHT CO	a09-31198_1ex31dc.htm
EX-32.B - EX-32.B - DAYTON POWER & LIGHT CO	a09-31198_1ex32db.htm
EX-10.B - EX-10.B - DAYTON POWER & LIGHT CO	a09-31198_1ex10db.htm
EX-31.A - EX-31.A - DAYTON POWER & LIGHT CO	a09-31198_1ex31da.htm
EX-32.A - EX-32.A - DAYTON POWER & LIGHT CO	a09-31198_1ex32da.htm
EX-32.D - EX-32.D - DAYTON POWER & LIGHT CO	a09-31198_1ex32dd.htm
EX-31.B - EX-31.B - DAYTON POWER & LIGHT CO	a09-31198_1ex31db.htm

Table of Contents

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 September 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

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

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

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

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

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

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

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

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

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

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

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

As of October 27, 2009, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, $0.01 par value	119,765,729

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.

Table of Contents

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	42

	Electric Sales and Revenues	66

Item 3	Quantitative and Qualitative Disclosures about Market Risk	66

Item 4	Controls and Procedures	66

Part II Other Information

Item 1	Legal Proceedings	67

Item 1A	Risk Factors	67

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	68

Item 3	Defaults Upon Senior Securities	68

Item 4	Submission of Matters to a Vote of Security Holders	68

Item 5	Other Information	68

Item 6	Exhibits	69

Other

Signatures		70

Certifications

Table of Contents

GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition
AOCI		Accumulated Other Comprehensive Income
ASU		Accounting Standards Update
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 generation facilities
DPLER		DPL Energy Resources, Inc., a wholly owned subsidiary of DPL which sells retail electric energy and other energy services
DP&L		The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio
DSM		Demand-Side Management, a program under which customers typically receive a discount, rebate or other form of incentive in return for agreeing to reduce their electricity consumption upon request by the utility.
EITF		Emerging Issues Task Force
EPS		Earnings Per Share
ESOP		Employee Stock Ownership Plan
ESP		Electric Security Plans, filed with the PUCO, pursuant to Ohio law
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulfurization
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gases
KWh		Kilowatt hours
MVIC		Miami Valley Insurance Company, a wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries
NOx		Nitrogen Oxide
NYMEX		New York Mercantile Exchange
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

Table of Contents

Abbreviation or Acronym		Definition
PJM		PJM Interconnection, L.L.C., a regional transmission organization
PRP		Potentially Responsible Party
PUCO		Public Utilities Commission of Ohio
RSU		Restricted Stock Units
RTO		Regional Transmission Organization
RPM		Reliability Pricing Model
SB 221		Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This new law required all Ohio distribution utilities to file either an electric security plan or a market rate option to be in effect January 1, 2009. The law also contains annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission
SECA		Seams Elimination Charge Adjustment
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur Dioxide
Stipulation		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.
TCRR		Transmission Cost Recovery Rider
USEPA		U.S. Environmental Protection Agency
USF		Universal Service Fund

Table of Contents

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 42 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.

Table of Contents

Item 1 — Financial Statements

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions except per share amounts	2009			2008			2009			2008

Revenues	$	407.3		$	414.5		$	1,183.5		$	1,209.4

Cost of revenues:
Fuel	84.4			62.2			241.7			192.5
Purchased power	65.0			119.8			188.0			288.9
Total cost of revenues	149.4			182.0			429.7			481.4

Gross margin	257.9			232.5			753.8			728.0

Operating expenses:
Operation and maintenance	73.8			68.2			226.3			200.4
Depreciation and amortization	36.1			35.3			107.8			102.5
General taxes	30.2			30.7			89.8			93.0
Amortization of regulatory assets	1.3			2.1			4.5			7.6
Total operating expenses	141.4			136.3			428.4			403.5

Operating income	116.5			96.2			325.4			324.5

Other income / (expense), net:
Investment income	0.1			0.5			0.7			3.1
Interest expense	(19.6		)	(21.9		)	(60.7		)	(67.9		)
Other income / (deductions)	(0.9		)	(0.4		)	(2.0		)	(0.9		)
Total other income / (expense), net	(20.4		)	(21.8		)	(62.0		)	(65.7		)

Earnings before income tax	96.1			74.4			263.4			258.8

Income tax expense	28.2			26.4			84.2			85.9
Net income	$	67.9		$	48.0		$	179.2		$	172.9

Average number of common shares outstanding (millions):
Basic	112.4			109.9			112.2			109.6
Diluted	114.4			115.0			113.4			116.2

Earnings per share of common stock:
Basic	$	0.60		$	0.44		$	1.60		$	1.58
Diluted	$	0.59		$	0.42		$	1.58		$	1.49

Dividends paid per share of common stock	$	0.285		$	0.275		$	0.855		$	0.825

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2009			2008

Cash flows from operating activities:
Net income	$	179.2		$	172.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	107.8			102.5
Amortization of regulatory assets	4.5			7.6
Deferred income taxes	203.5			32.7
Changes in certain assets and liabilities:
Accounts receivable	43.1			(1.9		)
Deposits and other advances	4.3			(3.7		)
Accounts payable	(66.7		)	24.3
Accrued taxes	(128.3		)	(66.4		)
Accrued interest payable	(6.5		)	(7.6		)
Pension and retiree benefits	6.4			(0.7		)
Prepayments	(0.3		)	0.3
Deferred regulatory costs, net	(34.5		)	(12.8		)
Inventories	(22.9		)	(4.6		)
Other	2.6			(0.1		)
Net cash provided by operating activities	292.2			242.5

Cash flows from investing activities:
Capital expenditures	(134.6		)	(173.8		)
Proceeds from sale of property	1.2			—
Purchases of short-term investments	—			(9.9		)
Proceeds from maturity of short-term investment	5.0			—
Net cash used for investing activities	(128.4		)	(183.7		)

Cash flows from financing activities:
Exercise of stock options	1.3			1.7
Tax impact related to exercise of stock options	0.1			0.3
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 facilities	260.0			105.0
Repayment of borrowings from revolving credit facility	(145.0		)	(15.0		)
Dividends paid on common stock	(95.7		)	(89.9		)
Net cash used for financing activities	(163.5		)	(167.4		)

Cash and cash equivalents:
Net change	0.3			(108.6		)
Balance at beginning of period	62.5			134.9
Cash and cash equivalents at end of period	$	62.8		$	26.3

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	67.1		$	71.6
Income taxes (refunded)/paid, net	$	(4.8	)	$	112.7
Non-cash financing and investing activities:
Accruals for capital expenditures	$	9.3		$	43.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2009			2008

ASSETS

Current assets:
Cash and cash equivalents	$	62.8		$	62.5
Restricted funds held in trust	7.9			14.5
Accounts receivable, net (Note 2)	292.0			259.9
Inventories (Note 2)	128.0			105.1
Prepaid income taxes	33.0			—
Taxes applicable to subsequent years	14.2			58.0
Other prepayments and current assets	22.9			26.7
Total current assets	560.8			526.7

Property, plant and equipment:
Property, plant and equipment	5,170.5			5,073.4
Less: Accumulated depreciation and amortization	(2,432.1		)	(2,350.6		)
	2,738.4			2,722.8

Construction work in process	142.0			153.6
Total net property, plant and equipment	2,880.4			2,876.4

Other noncurrent assets:
Regulatory assets (Note 3)	258.7			233.7
Other deferred assets	42.9			38.3
Total other noncurrent assets	301.6			272.0

Total Assets	$	3,742.8		$	3,675.1

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

			At			At
			September 30,			December 31,
$ in millions			2009			2008

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion - long-term debt			$	0.7		$	175.7
Accounts payable			71.0			178.3
Accrued taxes			67.2			130.4
Accrued interest			18.8			25.0
Revolving credit borrowings			115.0			—
Customer security deposits			19.4			19.8
Other current liabilities			26.2			14.7
Total current liabilities			318.3			543.9

Noncurrent liabilities:
Long-term debt			1,375.8			1,376.1
Deferred taxes			637.0			433.7
Regulatory liabilities (Note 3)			125.3			121.9
Pension and retiree benefits			97.8			94.7
Unamortized investment tax credit			35.9			38.0
Insurance and claims costs			15.1			17.6
Other deferred credits			58.6			50.7
Total noncurrent liabilities			2,345.5			2,132.7

Redeemable preferred stock of subsidiary			22.9			22.9

Commitments and contingencies (Note 14)

Common shareholders’ equity:
Common stock, at par value of $0.01 per share:

	September 2009	December 2008
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	116,115,729	115,961,880	1.2			1.2
Warrants			19.0			31.0
Common stock held by employee plans			(19.5		)	(27.6		)
Accumulated other comprehensive loss			(41.6		)	(44.6		)
Retained earnings			1,097.0			1,015.6
Total common shareholders’ equity			1,056.1			975.6

Total Liabilities and Shareholders’ Equity			$	3,742.8		$	3,675.1

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2009			2008			2009			2008

Revenues	$	398.2		$	401.5		$	1,153.7		$	1,191.8

Cost of revenues:
Fuel	83.0			57.0			236.2			183.6
Purchased power	64.7			120.1			187.1			291.8
Total cost of revenues	147.7			177.1			423.3			475.4

Gross margin	250.5			224.4			730.4			716.4

Operating expenses:
Operation and maintenance	70.2			65.4			217.5			191.0
Depreciation and amortization	33.6			32.8			100.2			95.0
General taxes	30.2			30.6			89.3			92.4
Amortization of regulatory assets	1.3			2.1			4.5			7.6
Total operating expenses	135.3			130.9			411.5			386.0

Operating income	115.2			93.5			318.9			330.4

Other income / (expense), net:
Investment income	0.4			0.6			2.4			6.3
Interest expense	(10.2		)	(8.9		)	(28.9		)	(26.7		)
Other income / (deductions)	(0.9		)	(0.4		)	(1.8		)	(1.0		)
Total other income / (expense), net	(10.7		)	(8.7		)	(28.3		)	(21.4		)

Earnings before income tax	104.5			84.8			290.6			309.0

Income tax expense	30.5			30.0			92.8			101.9
Net income	74.0			54.8			197.8			207.1

Dividends on preferred stock	0.2			0.2			0.6			0.6

Earnings on common stock	$	73.8		$	54.6		$	197.2		$	206.5

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2009			2008

Cash flows from operating activities:
Net income	$	197.8		$	207.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	100.2			95.0
Amortization of regulatory assets	4.5			7.6
Deferred income taxes	202.6			31.2
Changes in certain assets and liabilities:
Accounts receivable	34.1			0.7
Deposits and other advances	6.6			(3.9		)
Accounts payable	(66.0		)	23.5
Accrued taxes	(143.9		)	(61.1		)
Accrued interest payable	2.5			2.3
Prepayments	(0.4		)	(0.3		)
Pension and retiree benefits	6.4			(0.7		)
Deferred regulatory costs, net	(34.5		)	(12.8		)
Inventories	(22.8		)	(4.7		)
Other	(8.4		)	(10.1		)
Net cash provided by operating activities	278.7			273.8

Cash flows from investing activities:
Capital expenditures	(129.9		)	(173.1		)
Net cash used for investing activities	(129.9		)	(173.1		)

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 facilities	260.0			105.0
Repayment of borrowings from revolving credit facility	(145.0		)	(15.0		)
Dividends paid on common stock to parent	(270.0		)	(80.0		)
Dividends paid on preferred stock	(0.6		)	(0.6		)
Net cash used for financing activities	(148.9		)	(80.1		)

Cash and cash equivalents:
Net change	(0.1		)	20.6
Balance at beginning of period	20.8			13.2
Cash and cash equivalents at end of period	$	20.7		$	33.8

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	27.3		$	21.7
Income taxes (refunded)/paid, net	$	(4.9	)	$	112.2
Non-cash financing and investing activities:
Accruals for capital expenditures	$	9.3		$	43.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2009			2008

ASSETS

Current assets:
Cash and cash equivalents	$	20.7		$	20.8
Restricted funds held in trust	7.9			14.5
Accounts receivable, net (Note 2)	281.3			225.4
Inventories (Note 2)	126.6			103.8
Prepaid income taxes	36.7			—
Taxes applicable to subsequent years	14.1			57.9
Other prepayments and current assets	24.8			23.8
Total current assets	512.1			446.2

Property, plant and equipment:
Property, plant and equipment	4,912.4			4,817.9
Less: Accumulated depreciation and amortization	(2,339.3		)	(2,265.5		)
	2,573.1			2,552.4

Construction work in process	141.2			153.0
Total net property, plant and equipment	2,714.3			2,705.4

Other noncurrent assets:
Regulatory assets (Note 3)	258.7			233.7
Other deferred assets	57.7			50.5
Total other noncurrent assets	316.4			284.2

Total Assets	$	3,542.8		$	3,435.8

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	September 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	70.7			176.6
Accrued taxes	67.7			128.0
Accrued interest	15.8			12.9
Revolving credit borrowings	115.0			—
Customer security deposits	19.4			19.8
Other current liabilities	26.2			14.2
Total current liabilities	315.5			352.2

Noncurrent liabilities:
Long-term debt	883.6			884.0
Deferred taxes	620.8			417.8
Regulatory liabilities (Note 3)	125.3			121.9
Pension and retiree benefits	97.8			94.7
Unamortized investment tax credit	35.9			38.0
Other deferred credits	58.7			50.8
Total noncurrent liabilities	1,822.1			1,607.2

Redeemable preferred stock	22.9			22.9

Commitments and contingencies (Note 14)

Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	780.7			783.1
Accumulated other comprehensive loss	(33.3		)	(37.5		)
Retained earnings	634.5			707.5
Total common shareholder’s equity	1,382.3			1,453.5

Total Liabilities and Shareholder’s Equity	$	3,542.8		$	3,435.8

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

Table of Contents

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 DPLER’s 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 other significant subsidiaries include DPLE, which engages in the operation of peaking generating facilities; DPLER, which is a CRES provider selling retail electric energy and other energy services; and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly owned.

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

Financial Statement Presentation

We prepare consolidated financial statements. DPL’s condensed consolidated financial statements include the accounts of DPL and its wholly-owned subsidiaries, including DP&L. DP&L has an undivided ownership interest in seven electric generating facilities and numerous transmission facilities. These undivided interests in jointly owned facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions are eliminated in consolidation.

These financial statements have been prepared in accordance with GAAP for interim financial statements and with the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 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 September 30, 2009; our results of operations for the three months and nine months ended September 30, 2009; and our cash flows for the nine months ended September 30, 2009. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, interim results for the three months and nine months ended September 30, 2009 may not be indicative of our results that will be realized for the full year ending December 31, 2009.

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

We have evaluated all subsequent events through October 28, 2009 which is the date these financial statements were filed with the SEC.

Table of Contents

The preparation of financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the revenue and expenses of the periods reported. Actual results could differ from those estimates. Significant items subject to such estimates and judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of asset retirement obligations; 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 nine months ended September 30, 2009 and 2008, respectively, as follows:

Three Months Ended

Nine Months Ended

September 30,

$ in millions

2009

2008

2009

2008

State/local excise taxes

12.8

14.0

38.0

40.1

Recently Adopted Accounting Standards

FASB Codification

We adopted FASC 105, “Generally Accepted Accounting Principles” (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162”), on September 30, 2009. The objective of this Statement is to replace Statement 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 SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This update did not have a material impact on our overall results of operations, financial position or cash flows.

Disclosures about Derivative Instruments and Hedging Activities

We adopted an update to FASC 815, “Derivatives and Hedging” (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment to FASB Statement No. 133”), on January 1, 2009. This update requires an entity to provide enhanced disclosures about: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedged items are accounted for under FASC 815 and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This update did not have a material impact on our overall results of operations, financial position or cash flows. See Note 13 of Notes to Condensed Consolidated Financial Statements.

Participating Securities and Earnings per Share (EPS)

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

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

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

Table of Contents

Interim Disclosures about Fair Value of Financial Instruments

We adopted an update of FASC 825, “Financial Instruments” (formerly Staff Position SFAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments”), on June 30, 2009. This update requires disclosure about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This update did not have a material impact on our overall results of operations, financial position or cash flows. See Note 12 of Notes to Condensed Consolidated Financial Statements.

Subsequent Events

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

Recently Issued Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued ASU 2009-02 “Omnibus Update” (formerly SFAS No. 167, a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,”) (ASU 2009-02) effective for annual reporting periods beginning after November 15, 2009. This standard updates FASC 810, “Consolidation.” ASU 2009-02 changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. We are currently evaluating the impact of adopting ASU 2009-02 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 an update to FASC 715, “Compensation — Retirement Plans” (formerly Staff Position SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”), effective for fiscal years ending after December 15, 2009. We expect to adopt this update on December 31, 2009. This update requires disclosures about benefit plan assets similar to the disclosure required in FASC 820, “Fair Value Measurements and Disclosures.” It also requires discussions on investment allocation decisions, major categories of plan assets and significant concentrations of risk in plan assets for the period. We have evaluated this update and do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

Redeemable Equity Instruments

In August 2009, the FASB issued ASU 2009-04, “Accounting for Redeemable Equity instruments, an amendment to Section 480-10-S99,” (ASU 2009-04) effective for the first reporting period (including interim periods) beginning after its issuance. ASU 2009-04 clarifies that SEC Accounting Series Release 268 pertains to preferred stocks and other redeemable securities including common stock, derivative instruments, non-controlling interest, securities held by an employee stock ownership plan and share-based payment arrangements with employees. We have evaluated ASU 2009-04 and do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

Measuring Liabilities at Fair Value

In August 2009, the FASB issued ASU 2009-05, “Measuring Liabilities at Fair Value,” (ASU 2009-05) effective for the first reporting period (including interim periods) beginning after its issuance. ASU 2009-05 provides additional guidance clarifying the measurement of liabilities at fair value. We are currently evaluating the impact of adopting ASU 2009-05 and have not yet determined the significance of these new rules to our overall results of operations, financial position or cash flows.

Table of Contents

Investments in Certain Entities that Calculate Net Asset Value per Share

In September 2009, the FASB issued ASU 2009-12, “Fair Value Measurements and Disclosures,” (ASU 2009-12) effective for interim and annual periods ending after December 15, 2009. ASU 2009-12 updates FASC 820-10, “Fair Value Measurements and Disclosures — Overall” and allows, as a practical expedient, a reporting entity to measure the fair value of an investment that is within the scope of these amendments on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a manner consistent with the measurement principles of FASC 946, “Financial Services — Investment Companies.” We are currently evaluating the impact of adopting ASU 2009-12 and have not yet determined the significance of these new rules to our overall results of operations, financial position or cash flows.

2. Supplemental Financial Information and Comprehensive Income

DPL Inc.

	At			At
	September 30,			December 31,
$ in millions	2009			2008

Accounts receivable, net:
Unbilled revenue	$	65.0		$	82.5
Customer receivables	104.7			107.5
Amounts due from partners in jointly-owned plants	18.5			28.0
Coal sales	11.8			25.6
Refundable taxes (a)	90.8			14.9
Other	2.3			2.5
Provision for uncollectible accounts	(1.1		)	(1.1		)
Total accounts receivable, net	$	292.0		$	259.9

Inventories, at average cost:
Fuel and emission allowances	$	89.3		$	68.7
Plant materials and supplies	38.1			36.3
Other	0.6			0.1
Total inventories, at average cost	$	128.0		$	105.1

DP&L

	At			At
	September 30,			December 31,
$ in millions	2009			2008

Accounts receivable, net:
Unbilled revenue	$	61.3		$	74.7
Customer receivables	99.3			96.7
Amounts due from partners in jointly-owned plants	18.5			28.0
Coal sales	11.8			25.6
Refundable taxes (a)	90.8			—
Other	0.7			1.5
Provision for uncollectible accounts	(1.1		)	(1.1		)
Total accounts receivable, net	$	281.3		$	225.4

Inventories, at average cost:
Fuel and emission allowances	$	89.3		$	68.7
Plant materials and supplies	36.7			35.0
Other	0.6			0.1
Total inventories, at average cost	$	126.6		$	103.8

(a) The tax receivable at September 30, 2009 results from the recognition of certain tax benefits relating to a change in the tax accounting method for deductions pertaining to repairs, depreciation and mixed service costs. This receivable is available to be offset against future income tax liabilities and is expected to be collected within the next 12 months.

Table of Contents

2. Supplemental Financial Information and Comprehensive Income (continued)

DPL Inc.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Comprehensive income:
Net income	$	67.9		$	48.0		$	179.2		$	172.9
Net change in unrealized gains (losses) on financial instruments	0.5			(0.2		)	0.7			(0.6		)
Net change in deferred gains (losses) on cash flow hedges	—			2.5			1.2			(2.2		)
Net change in unrealized gains (losses) on pension and postretirement benefits	0.8			0.5			2.4			1.5
Deferred income taxes related to unrealized gains and (losses)	(0.4		)	(1.1		)	(1.3		)	0.3
Comprehensive income	$	68.8		$	49.7		$	182.2		$	171.9

DP&L

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Comprehensive income:
Net income	$	74.0		$	54.8		$	197.8		$	207.1
Net change in unrealized gains (losses) on financial instruments	3.5			(2.2		)	2.6			(12.5		)
Net change in deferred gains (losses) on cash flow hedges	—			2.5			1.2			(2.2		)
Net change in unrealized gains (losses) on pension and postretirement benefits	0.8			0.5			2.4			1.5
Deferred income taxes related to unrealized gains and (losses)	(1.4		)	(0.4		)	(2.0		)	5.1
Comprehensive income	$	76.9		$	55.2		$	202.0		$	199.0

3. Regulatory Matters

Accounting standards define regulatory assets as the deferral of costs expected to be recovered in future customer rates and regulatory liabilities as current cost recovery in customer rates of expected future expenditures. DP&L has applied these accounting standards to its regulated businesses, which include its electric transmission and distribution businesses.

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

			At		At
	Type of	Amortization	September 30,		December 31,
$ in millions	Recovery (a)	Through	2009		2008
Regulatory Assets:
Deferred recoverable income taxes	C/B	Ongoing	$	80.7	$	81.2
Pension benefits	C	Ongoing	80.0		83.3
Unamortized loss on reacquired debt	C	Ongoing	16.0		17.2
Electric Choice systems costs	F	2011	4.7		7.1
Regional transmission organization costs	D		7.4		8.5
Transmission, capacity and other PJM-related costs	F	2011	29.5		—
Deferred storm costs - 2008	D		15.7		13.1
Power plant emission fees	C	Ongoing	6.1		6.3
CCEM smart grid and advanced metering infrastructure	D		6.5		6.4
CCEM energy efficiency programs	F	Ongoing	4.5		1.9
Other costs			7.6		8.7
Total regulatory assets			$	258.7	$	233.7

Regulatory Liabilities:
Asset retirement obligations - regulated property			$	99.0	$	96.0
SECA net revenue subject to refund			20.1		20.1
Postretirement benefits and other			6.2		5.8
Total regulatory liabilities			$	125.3	$	121.9

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

C – Recovery of incurred costs only.

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

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

Table of Contents

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. This is the cumulative flow-through benefit given to regulated customers that will be collected from them in future years. Since currently existing temporary differences between the financial statements and the related tax basis of assets will reverse in subsequent periods, these deferred recoverable income taxes are amortized.

Pension benefits represent the qualifying FASC 715, “Compensation — Retirement Benefits” (formerly SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment to FASB Statements No. 87, 88, 106 and 132(R)”) costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income (OCI), the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed in prior periods. These costs are being amortized over the life of the original issues.

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

Regional transmission organization costs represent costs incurred to join a RTO. The recovery of these costs has not yet been determined.

Transmission, capacity and other PJM-related costs represent the costs related to transmission, capacity, ancillary service and other PJM-related charges that have been 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. On May 27, 2009, the PUCO granted DP&L authority to recover these costs through retail rates beginning June 1, 2009. Subsequently, 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 a TCRR was unlawful. The PUCO issued an order granting rehearing for additional review and, on September 9, 2009, issued an order directing DP&L to remove the deferred and current RPM capacity costs from the TCRR rider yet also indicating that these RPM capacity costs may be recoverable under a separate rider. DP&L made a compliance filing on September 23, 2009, where it removed such costs from the TCRR rider and proposed an RTO RPM rider for the recovery of such costs. On October 21, 2009, the PUCO Staff filed a staff report in the case recommending that the PUCO approve both of DP&L’s proposed riders. The outcome of this proceeding cannot be determined at this time, but, based on past precedent and the PUCO’s orders received thus far, we continue to believe that these costs are probable of recovery. At September 30, 2009, the net total of deferred RPM capacity costs amounted to $24.4 million.

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

Power plant emission fees represent costs paid to the State of Ohio since 2002 for environmental monitoring. An application is pending before the PUCO to amend an approved rate rider that had been in effect to collect fees that were paid and deferred in years prior to 2002. These deferred costs incurred prior to 2002 have been fully recovered. Based on past precedent from the PUCO, we believe these costs are probable of future rate recovery.

Table of Contents

CCEM smart grid and advanced metering infrastructure costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of advanced metering infrastructure. Consistent with the Stipulation, DP&L re-filed its smart grid and advanced metering infrastructure business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a 10-year plan to deploy smart meters, distribution and substation automation, core telecommunications, supporting software and in-home technologies. On August 5, 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding under the Integrated and/or Crosscutting Systems topic area for the Smart Grid Investment Grant Program. The application, which sought $145.1 million of matching funds, focused on the first three years of DP&L’s 10-year plan. On October 27, 2009, we were notified by the United States Department of Energy (DOE) that we will not receive funding under the ARRA.

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

Other costs primarily include consumer education advertising costs regarding electric deregulation, settlement system costs, other PJM and rate case costs; and derivative activity related to fuel costs that will be recovered over various periods.

Regulatory Liabilities

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

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

Postretirement benefits and other represent the qualifying FASC 715, “Compensation — Retirement Benefits” (formerly SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment to FASB Statements No. 87, 88, 106 and 132(R)”) gains related to our regulated operations that for ratemaking purposes are probable of being reflected in future rates. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of OCI, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory liability represents the regulated portion that would otherwise be charged as a gain to OCI.

4. Ownership of Facilities

DP&L 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, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of September 30, 2009, we had $114 million of construction work in progress at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the condensed consolidated statements of results of operations and DP&L’s 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 and is expected to be completed in the fourth quarter of 2009.

Table of Contents

DP&L’s undivided ownership interest in such facilities at September 30, 2009, is as follows:

	DP&L Share		DP&L Investment
			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	41		28		85
East Bend Station	31.0	186	200		128		1
Killen Station	67.0	402	604		273		1
Miami Fort Units 7&8	36.0	368	344		120		6
Stuart Station	35.0	820	682		243		17
Zimmer Station	28.1	365	1,055		593		3
Transmission (at varying percentages)			91		53		—
Total		2,480	$	3,095	$	1,493	$	114

5. Long-term Debt and Revolving Credit Borrowings

	At			At
	September 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 - 4.70%	35.3			35.3
DP&L - Pollution control series maturing
2034 - 4.80%	179.1			179.1
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% (a)	100.0			100.0
	884.4			884.4

DP&L - Obligation for capital lease	—			0.6
Unamortized debt discount	(0.8		)	(1.0		)
Total long-term debt - DP&L	$	883.6		$	884.0

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
Unamortized debt discount	(0.2		)	(0.3		)
Total long-term debt - DPL	$	1,375.8		$	1,376.1

(a)

Range of interest rates for nine months ended September 30, 2009 and the one month ended December 31, 2008, respectively. These pollution control bonds were issued on December 4, 2008.

Table of Contents

At September 30, 2009, scheduled maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions	DPL		DP&L
2010	$	0.7	$	0.7
2011	297.4		—
2012	—		—
2013	470.0		470.0
2014	—		—
Thereafter	609.4		414.4
	$	1,377.5	$	885.1

Significant changes in our long-term debt and revolving credit borrowings since the beginning of 2009 include the following:

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 September 30, 2009, DP&L was in compliance with this covenant with a ratio of 0.43 to 1.00. As of September 30, 2009, the borrowings outstanding under this facility amounted to $80 million. On October 28, 2009, DP&L paid off the $80 million that was outstanding under this facility. This repayment was made using cash on hand as well as proceeds from the October 26, 2009 exercise of warrants as discussed in Note 10 of Notes to Condensed Consolidated Financial Statements.

On July 29, 2009, DP&L repaid $105 million of the $140 million borrowing that was outstanding under its $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. At September 30, 2009, the borrowings outstanding under this facility amounted to $35 million. On October 28, 2009, DP&L repaid an additional $10 million that was outstanding under this facility. This repayment was made using cash on hand as well as proceeds from the warrant exercise mentioned in the preceding paragraph.

After considering the payments made on October 28, 2009 as discussed in the preceding paragraphs, borrowings under the $100 million facility were paid off while those outstanding under the $220 million facility amounted to $25 million as of that date. At October 28, 2009, the combined cash available to DP&L under these revolving credit facilities amounted to $295 million.

The weighted average interest rate paid on outstanding borrowings during both the three and nine months ended September 30, 2009 was 2.3% under both revolving credit facilities.

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. Benefits under this SERP have been frozen and no additional benefits can be earned.

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

Table of Contents

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

The net periodic benefit cost of the pension and postretirement benefit plans for both DPL and DP&L for the three months ended September 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	4.5			4.1			0.4			0.4
Expected return on assets	(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	$	1.8		$	0.2		$	0.1		$	0.1

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

Net periodic benefit cost

	Pension						Postretirement
$ in millions	2009			2008			2009			2008
Service cost	$	2.7		$	2.4		$	—		$	—
Interest cost	13.3			12.3			1.3			1.2
Expected return on assets	(16.8		)	(18.0		)	(0.3		)	(0.3		)

Amortization of unrecognized:
Actuarial (gain) loss	3.3			2.1			(0.6		)	(0.6		)
Prior service cost	2.6			1.8			—			—
Net periodic benefit cost	$	5.1		$	0.6		$	0.4		$	0.3

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	$	5.2	$	0.7
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

Table of Contents

7. Share-Based Compensation

Share-based compensation expense was not significant for the three months or nine months ended September 30, 2009.

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.

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

	Options				RSUs				Performance Shares
	2009		2008		2009		2008		2009	2008
Outstanding at beginning of period	836,500		896,500		10,120		19,768		237,704	190,727
Granted	—		—		—		—		—	—
Dividends	—		—		—		—		—	—
Exercised	(60,000	)	(40,400	)	(6,809	)	(9,648	)	—	—
Expired	—		—		—		—		—	—
Forfeited	—		—		—		—		—	—
Outstanding at period end	776,500		856,100		3,311		10,120		237,704	190,727
Exercisable at period end	776,500		856,100		—		—		—	—

					Management Performance
	Restricted Shares				Shares
	2009		2008		2009		2008
Outstanding at beginning of period	70,647		61,200		87,863		39,144
Granted	95,036		19,347		—		—
Dividends	—		—		—		—
Exercised	—		—		—		—
Expired	—		—		—		—
Forfeited	—		—		(3,622	)	—
Outstanding at period end	165,683		80,547		84,241		39,144
Exercisable at period end	—		—		—		—

	Director RSUs
	2009		2008
Outstanding at beginning of period	20,272		15,986
Granted	—		—
Dividends accrued	474		248
Exercised and issued	—		—
Exercised and deferred	(242	)	—
Forfeited	—		(1,149	)
Outstanding at period end	20,504		15,085
Exercisable at period end	—		—

Table of Contents

Summarized share-based compensation activity for both DPL and DP&L for the nine months ended September 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	(60,000	)	(90,400	)	(6,809	)	(11,253	)	—		—
Expired	—		—		—		—		(36,445	)	(37,426	)
Forfeited	—		—		—		(1,603	)	(6,739	)	(7,253	)
Outstanding at period end	776,500		856,100		3,311		10,120		237,704		190,727
Exercisable at period end	776,500		856,100		—		—		—		—

					Management Performance
	Restricted Shares				Shares
	2009		2008		2009		2008
Outstanding at beginning of year	69,147		42,200		39,144		—
Granted	97,536		39,347		48,719		39,144
Dividends	—		—		—		—
Exercised	(1,000	)	(1,000	)	—		—
Expired	—		—		—		—
Forfeited	—		—		(3,622	)	—
Outstanding at period end	165,683		80,547		84,241		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	1,310		630
Exercised and issued	(2,066	)	(13,721	)
Exercised and deferred	(14,302	)	—
Forfeited	—		(1,149	)
Outstanding at period end	20,504		15,085
Exercisable at period end	—		—

On September 17, 2009, the DPL Board of Directors approved a two-part equity compensation award under DPL’s 2006 Equity and Performance Incentive Plan for certain of DPL’s executive officers. The first part is a restricted share grant and the second part is a matching restricted share grant. A total of 90,036 restricted shares were granted on September 17, 2009 as part of the restricted share grant. These restricted shares vest after five years if the participant remains continuously employed with DPL and if the year over year average EPS has increased by at least 1% from 2009 - 2013. Under the matching restricted share grant, participants will have a three-year period from the date of plan implementation during which they may purchase DPL common shares equal in value to up to two times their base salary. DPL will match the shares purchased with another grant of restricted stock (matching restricted share grant). The percentage match by DPL is detailed in the table below. The matching restricted share grant will vest over a three year period if the participant continues to hold the originally purchased shares and remains continuously employed with DPL. The restricted shares are registered in the executive’s name, carry full voting privileges and receive dividends as declared and paid on all DPL common shares.

The matching criteria are:

Value (Cost Basis) of Shares Purchased as a % of 2009 Base Salary		Company % Match of Value of Shares Purchased
<25%		25%
25% to 50%		50%
50% to 100%		75%
100% to 200%		125%

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

Table of Contents

8. 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 unreleased shares held by DPL’s ESOP.

The common-equivalent shares excluded from the calculation of diluted EPS, because they were anti-dilutive, were not material for both the three months and nine months ended September 30, 2009.

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

Three Months Ended September 30,

2009

2008

$ in millions except per

Net

Per

Net

Per

share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

67.9

112.4

0.60

48.0

109.9

0.44

Effect of Dilutive Securities:

Warrants (a)

1.8

4.9

Stock options and performance shares

0.2

0.2

Diluted EPS

67.9

114.4

0.59

48.0

115.0

0.42

Nine Months Ended September 30,

2009

2008

$ in millions except per

Net

Per

Net

Per

share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

179.2

112.2

1.60

172.9

109.6

1.58

Effect of Dilutive Securities:

Warrants (a)

1.0

6.4

Stock options and performance shares

0.2

0.2

Diluted EPS

179.2

113.4

1.58

172.9

116.2

1.49

(a) On March 20, 2009, DPL repurchased 7.1 million warrants, each at a price of $2.25. The repurchased warrants were cancelled by DPL on the date they were repurchased. Also, on September 17, 2009, a warrant holder exercised 0.5 million warrants under a cashless exercise transaction resulting in the issuance by DPL of 93,200 shares of common stock. See Note 10 of Notes to Condensed Consolidated Financial Statements.

Table of Contents

9. Redeemable Preferred Stock

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

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

The DP&L preferred stock may be redeemed at DP&L’s option as determined by its Board of Directors at the per-share redemption prices indicated above, plus cumulative accrued dividends. In addition, DP&L’s Amended Articles of Incorporation contain provisions that permit preferred stockholders to elect members of the Board of Directors in the event that cumulative dividends on the preferred stock are in arrears in an aggregate amount equivalent to at least four full quarterly dividends. Since this potential redemption-triggering event is not solely within the control of DP&L, the preferred stock is presented on the balance sheet as “Redeemable Preferred Stock” in a manner consistent with temporary equity as defined in GAAP.

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 September 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.

10. 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 7.1 million of such warrants at a price of $2.25 each. The repurchased warrants were cancelled by DPL on the date they were repurchased. In addition, on September 17, 2009, a warrant holder exercised 0.5 million warrants under a cashless exercise transaction resulting in the issuance by DPL of 93,200 shares of common stock from treasury stock. Accordingly, at September 30, 2009, DPL had approximately 12 million warrants outstanding.

On October 26, 2009, a warrant holder exercised 3.5 million warrants for cash. As a result of this exercise, DPL issued 3.5 million shares of common stock from treasury stock and in turn received $73.5 million in cash. DPL used the proceeds from this transaction to pay down borrowings under its revolving credit facilities. However, ultimately it intends to use an amount equal to such proceeds to repurchase shares under its Stock Repurchase Program discussed below. See Note 5 of Notes to Condensed Consolidated Financial Statements. At October 28, 2009, DPL had approximately 8.5 million warrants outstanding.

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program (the Program) under which DPL may use proceeds from the exercise of warrants to repurchase common stock from time to time in the open market, through private transactions or otherwise. The Program will run through June 30, 2012, which is three months after the end of the warrant exercise period.

Table of Contents

11. Income Taxes

The following table details the effective tax rates for the three months and nine months ended September 30, 2009 and 2008:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008

DPL	29.3	%	35.5	%	32.0	%	33.2	%

DP&L	29.2	%	35.4	%	31.9	%	33.0	%

For both DPL and DP&L and for the three and nine months ended September 30, 2009, the decreases in the effective tax rates from the same periods in 2008 are primarily due to estimate-to-actual tax adjustments related to the Internal Revenue Code Section 199 – domestic production deduction (Section 199 deduction) and state tax liabilities for 2008 and to changes to the 2009 estimated tax benefits related to the Section 199 deduction and the phase-out of the Ohio Franchise Tax. During the three months ended September 30, 2009, we recorded tax benefits in the amounts of $4.6 million and $2.9 million relating to the Section 199 deduction and state tax liabilities, respectively.

Deferred tax liabilities for both DPL and DP&L increased by approximately $203 million during the nine months ended September 30, 2009. This increase is related to the tax effects resulting from 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; and the tax effects of other temporary differences primarily associated with accelerated depreciation of additions to property, plant and equipment.

12. Fair Value Measurements

The fair values of our financial instruments 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 our non-derivative financial instruments at September 30, 2009 and December 31, 2008.

	September 30, 2009				December 31, 2008
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL Inc.
Assets
Master Trust Assets	$	12.0	$	12.2	$	13.6	$	13.1

Liabilities
Debt	$	1,376.6	$	1,348.3	$	1,551.8	$	1,470.5

DP&L
Assets
Master Trust Assets	$	26.1	$	39.0	$	29.9	$	40.2

Liabilities
Debt	$	884.4	$	846.4	$	884.7	$	815.7

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.

Table of Contents

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

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

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

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
	Fair Value at September 30, 2009*		Based on Quoted Prices in Active Market		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at September 30, 2009
$ in millions	DPL											DPL
Assets
Master Trust Assets	$	12.2	$	—	$	12.2	$	—	$	—		$	12.2
Derivative Assets	13.8		—		13.8		—		(4.4		)	9.4
Total	$	26.0	$	—	$	26.0	$	—	$	(4.4	)	$	21.6

Liabilities
Derivative Liabilities	$	9.0	$	2.7	$	6.3	$	—	$	(5.9	)	$	3.1
Total	$	9.0	$	2.7	$	6.3	$	—	$	(5.9	)	$	3.1

*Includes credit valuation adjustments for counterparty risk.

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

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
	Fair Value at September 30, 2009*		Based on Quoted Prices in Active Market		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at September 30, 2009
$ in millions	DP&L (a)											DP&L
Assets
Master Trust Assets	$	39.0	$	26.8	$	12.2	$	—	$	—		$	39.0
Derivative Assets	13.8		—		13.8		—		(4.4		)	9.4
Total	$	52.8	$	26.8	$	26.0	$	—	$	(4.4	)	$	48.4

Liabilities
Derivative Liabilities	$	9.0	$	2.7	$	6.3	$	—	$	(5.9	)	$	3.1
Total	$	9.0	$	2.7	$	6.3	$	—	$	(5.9	)	$	3.1

*Includes credit valuation adjustments for counterparty risk.

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

Table of Contents

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

The fair value of assets and liabilities measured on a non-recurring basis are based on Level 3 inputs. 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 September 30, 2009, DP&L did not have any new ARO costs or increases to current AROs.

At September 30, 2009, we did not have any investments in money market funds classified as cash and cash equivalents in our condensed consolidated balance sheets. The money market funds have quoted prices that are generally equivalent to par.

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 open-ended 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 $0.2 million in unrealized gains and no unrealized losses on the Master Trust assets in OCI at September 30, 2009 and no unrealized gains and $0.5 million in unrealized losses in OCI at December 31, 2008.

DP&L had $12.9 million in unrealized gains and no unrealized losses on the Master Trust assets in OCI at September 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.

Derivative Instruments

In the normal course of business, DPL and DP&L enter into various derivative financial instruments. See Note 13 of Notes to Condensed Consolidated Financial Statements.

13. Derivative Instruments and Hedging Activities

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. 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.

Table of Contents

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 probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

We currently use cash flow hedging with forward power contracts and in 2003 we entered into an interest rate swap which was settled that same year. As of September 30, 2009, the maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions is 108 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 nine months ended September 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	6.2			—			(5.5		)	—
Net amount of any reclassification into earnings	(3.1		)	(1.8		)	4.9			(1.8		)
Ending Accumulated Derivative Gain/(Loss) in OCI	$	2.8		$	15.4		$	(2.1	)	$	17.9

Mark to Market

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and sales exceptions under FASC 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred. This is commonly referred to as “mark to market” accounting. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We currently mark to market Financial Transmission Rights (FTRs), heating oil futures and forward NYMEX-quality coal contracts that do not qualify for cash flow hedge accounting.

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

Regulatory Assets and Liabilities

Under FASC 980, “Regulated Operations,” if a cost is probable of recovery in future rates, it should be deferred as a regulatory asset. If a gain is probable of being returned to customers, it should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements will be included as part of the fuel clause approved in the Stipulation beginning January 1, 2010. The terms of the Stipulation were discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008. As a result, DP&L believes certain fuel 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 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.

Table of Contents

At September 30, 2009, DP&L had the following outstanding derivative instruments:

(In Thousands)

Commodity	Accounting Treatment	Unit	Purchases	Sales		Net Purchase/ (Sale)
FTRs	Mark to Market	MW	16.7	—		16.7
Heating Oil Futures	Mark to Market	Gallons	5,166.0	—		5,166.0
Forward Power Contracts	Cash Flow Hedge	MWH	—	(2,043.4	)	(2,043.4	)
NYMEX-quality Coal Contracts*	Mark to Market	Tons	3,348.0	(1,550.0	)	1,798.0

*Includes our partner’s share for the jointly-owned plants that DP&L operates.

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

Fair Values of Derivative Instruments Designated as Hedging Instruments

							At September 30, 2009
$ in millions	Fair Value			Netting*			Balance Sheet Location	Fair Value on Balance Sheet
Short-Term Derivative Positions

Forward Power Contracts in an Asset position	$	3.4		$	(0.9	)	Other Current Assets	$	2.5

Forward Power Contracts in a Liability position	(1.3		)	0.9			Other Current Liabilities	(0.4		)

Total short-term derivative cash flow positions	$	2.1		$	—			$	2.1

Long-Term Derivative Positions
Forward Power Contracts in an Asset position	$	0.5		$	—		Other Deferred Assets	$	0.5
Forward Power Contracts in a Liability position	—			—			Other Deferred Credits	—

Total long-term derivative cash flow positions	$	0.5		$	—			$	0.5

Total Cash Flow Hedges	$	2.6		$	—			$	2.6

*Includes counterparty netting.

The following tables show the amount and income statement classification of the gains and losses on DP&L’s derivatives designated as hedging instruments for the three- and nine-month periods ending September 30, 2009.

For the three months ending September 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
Interest Rate Hedge	$	—	Interest Expense	$	0.6		Interest Expense	$	—
Forward Power Contracts	3.2		Wholesale Revenue	(2.5		)	Wholesale Revenue	—
Total Effect of Derivative Instruments Designated as Hedging Instruments on the Income Statement
	$	3.2		$	(1.9	)		$	—

Table of Contents

For the nine months ending September 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
Interest Rate Hedge	$	—	Interest Expense	$	1.8		Interest Expense	$	—
Forward Power Contracts	6.2		Wholesale Revenue	(3.2		)	Wholesale Revenue	—
Total Effect of Derivative Instruments Designated as Hedging Instruments on the Income Statement
	$	6.2		$	(1.4	)		$	—

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

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

							At September 30, 2009
$ in millions	Fair Value			Netting*			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	1.3		$	—		Other Current Assets	$	1.3
Heating Oil Futures in a Liability position	(2.5		)	2.5			Other Current Liabilities	—
NYMEX-Quality Coal Forwards in an Asset position	4.6			(1.4		)	Other Current Assets	3.2
NYMEX-Quality Coal Forwards in a Liability position	(3.1		)	1.4			Other Current Liabilities	(1.7		)

Total short-term derivative MTM positions	$	0.3		$	2.5			$	2.8

Long-term Derivative Positions
Power Contracts in a Liability Position	$	(0.2	)	$	—		Other Deferred Credits	$	(0.2	)
Heating Oil Futures in a Liability position	(0.2		)	0.2			Other Deferred Credits	—
NYMEX-Quality Coal Forwards in an Asset position	4.0			(2.1		)	Other Deferred Assets	1.9
NYMEX-Quality Coal Forwards in a Liability position	(1.7		)	0.9			Other Deferred Credits	(0.8		)

Total long-term derivative MTM positions	$	1.9		$	(1.0	)		$	0.9

Total MTM Position	$	2.2		$	1.5			$	3.7

*Includes counterparty and collateral netting.

Table of Contents

The following tables show the amount and income statement or balance sheet classification of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three- and nine-month periods ending September 30, 2009.

For the Three Months Ending September 30, 2009

$ in millions	NYMEX Coal*			Heating Oil			FTRs		Total
Unrealized (gain)/loss	$	(13.9	)	$	(0.3	)	$	0.4	$	(13.8	)
Realized (gain)/loss	0.8			0.7			0.2		1.7
Total	$	(13.1	)	$	0.4		$	0.6	$	(12.1	)
Recorded on Balance Sheet: debit/(credit)
Partner’s share of (gain)/loss	$	(7.1	)	$	—		$	—	$	(7.1	)
Regulatory asset/liability	(1.4		)	0.1			—		(1.3		)

Recorded in Income Statement: debit/(credit)
Purchased power	—			—			0.6		0.6
Fuel	(4.6		)	0.3			—		(4.3		)
O&M	—			—			—		—
Total	$	(13.1	)	$	0.4		$	0.6	$	(12.1	)

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

For the Nine Months Ended September 30, 2009

$ in millions	NYMEX Coal*			Heating Oil			FTRs			Total
Unrealized (gain)/loss	$	(3.8	)	$	(3.6	)	$	(1.3	)	$	(8.7	)
Realized (gain)/loss	—			2.5			0.1			2.6
Total	$	(3.8	)	$	(1.1	)	$	(1.2	)	$	(6.1	)
Recorded on Balance Sheet: debit/(credit)
Partner’s share of (gain)/loss	$	(1.9	)	$	—		$	—		$	(1.9	)
Regulatory asset/liability	(1.8		)	1.2			—			(0.6		)

Recorded in Income Statement: debit/(credit)
Purchased power	—			—			(1.2		)	(1.2		)
Fuel	(0.1		)	(2.2		)	—			(2.3		)
O&M	—			(0.1		)	—			(0.1		)
	$	(3.8	)	$	(1.1	)	$	(1.2	)	$	(6.1	)

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

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the mark to market loss. The aggregate fair value of all derivative instruments that are in a mark to market loss position at September 30, 2009, is $9.0 million. This amount is offset by $2.7 million in a broker margin account which offsets our loss positions on the NYMEX Clearport traded heating oil and coal contracts. If our debt were to fall below investment grade, we would have to post collateral for the remaining $6.3 million.

Table of Contents

14. Contractual Obligations, Commitments and Contingencies

DPL Inc. — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned 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. 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 September 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 September 30, 2009, DP&L could be responsible for the repayment of 4.9%, or $54.9 million, of a $1,120.7 million debt obligation that matures in 2026. This would only happen if OVEC defaulted on its debt payments. As of September 30, 2009, we are not aware of any default by OVEC 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.

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.

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, including the 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 September 30, 2009, cannot be reasonably determined.

Environmental Matters

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities.

As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. 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.

Air Quality

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

Table of Contents

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

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

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

Pursuant to the CAIR, the Ohio EPA initiated an Early Reduction Credit (ERC) program for annual NOx emission allowances for 2008 and 2009. DP&L qualified for ERCs in excess of what was initially allocated to DP&L and submitted the data for all ERCs generated. 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 generated ERCs in excess of their initial allocation. DP&L is expected to be allocated between 28% - 33% more ERCs than its initial allocation.

We cannot at this time predict the timing or the outcome of any new regulations relating to CAIR. CAIR has and will continue to have a material effect on our operations. In 2007, the Ohio EPA revised their State Implementation Plan (SIP) to incorporate a CAIR program consistent with the IAQR. The Ohio EPA had received partial approval from USEPA and had been awaiting full program approval from the USEPA when the U.S. Court of Appeals issued its July 11, 2008 decision. As a result of the December 23, 2008 order, the Ohio EPA proposed revised rules on May 11, 2009, which were finalized on July 15, 2009. On September 25, 2009, the USEPA issued a full SIP approval for the Ohio CAIR program. DP&L does not expect that full SIP approval of the Ohio CAIR program will have a significant impact on operations.

Table of Contents

In the fourth quarter of 2007, DP&L began a program for selling excess emission allowances, including annual NOx emission allowances and SO2 emission allowances that were the subject of CAIR trading programs. In subsequent quarters, DP&L recognized gains from the sale of excess emission allowances to third parties. The court’s CAIR decision affected the trading market for excess allowances and impacted DP&L’s program for selling additional excess allowances in 2008. Although in January 2009 we resumed selling excess allowances due to the revival of the trading market, the long-term impact of the court’s decision, and of the actions the USEPA or others will take in response to this decision, is not fully known at this time and could have an adverse effect on us.

On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA “de-listed” mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005 and was published on May 18, 2005. On March 29, 2005, nine states sued USEPA, opposing the cap-and-trade regulatory approach taken by USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the Court of Appeals struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to “de-listing” a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for “listed” hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. USEPA will have to move forward to set Maximum Available Control Technology (MACT) standards for coal- and oil-fired electric generating units. We anticipate that it will take a few years for the USEPA to gather new data to promulgate updated MACT standards and for the regulations to become effective. At this time, DP&L is unable to determine the impact of the promulgation of new MACT standards on its financial position or results of operations; however, a MACT standard could have a material adverse effect on our operations, in particular, our unscrubbed units. We cannot at this time project the final costs we may incur to comply with any resulting mercury restriction regulations.

On July 15, 2003, the Ohio EPA submitted to the USEPA its recommendations for eight-hour ozone non-attainment boundaries for the metropolitan areas within Ohio. On April 15, 2004, the USEPA issued its list of ozone non-attainment designations. Since these initial designations, the Ohio EPA has recommended that nine areas designated non-attainment be designated as attainment. Currently USEPA has redesignated eight of those areas as attainment for the eight-hour ozone national ambient air quality standards, including counties where DP&L owns and/or operates a number of facilities. In redesignating these counties as attainment, the Ohio EPA submitted and USEPA approved amendments to the SIP that include maintenance plans for these areas. In June 2007, the Ohio EPA submitted a plan to USEPA for attaining the eight-hour ozone standard for the Cincinnati-Hamilton area in which DP&L owns a number of facilities. While DP&L cannot predict the outcome of this redesignation effort at this time, any such redesignation could have a material adverse effect on us.

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

Table of Contents

In September 2004, the Sierra Club filed a lawsuit against DP&L and the other owners of the Stuart generating station in the U.S. District Court for the Southern District of Ohio for alleged violations of the CAA and the station’s operating permit. On August 7, 2008, a consent decree was filed in the U.S. District Court in full settlement of these CAA claims. Under the terms of the consent decree, DP&L and the other owners of the Stuart generating station agreed to: (i) certain emission targets related to NOx, SO2 and particulate matter; (ii) make energy efficiency and renewable energy commitments that are conditioned on receiving PUCO approval for the recovery of costs; (iii) forfeit 5,500 sulfur dioxide allowances; and (iv) provide funding to a third party non-profit organization to establish a solar water heater rebate program. DP&L and the other owners of the station also entered into an attorneys’ fee agreement to pay a portion of the Sierra Club’s attorney and expert witness fees. The parties to the lawsuit filed a joint motion on October 22, 2008, seeking an order by the U.S. District Court approving the consent decree with funding for the third party non-profit organization set at $300,000. On October 23, 2008, the U.S. District Court approved the consent decree. On October 21, 2009, the Sierra Club filed with the U.S. District Court a motion for enforcement of the consent decree based on the Sierra Club’s interpretation of the consent decree that would require certain NOx emissions that DP&L has been excluding from its computations to be included for purposes of complying with the emission targets and reporting requirements of the consent decree. DP&L believes that it is properly computing and reporting NOx emissions under the consent decree and will oppose the Sierra Club’s motion.

On January 5, 2005, the USEPA published its final non-attainment designations for the national ambient air quality standard for Fine Particulate Matter 2.5 (PM 2.5). These designations included counties and partial counties in which DP&L operates and/or owns generating facilities. On March 4, 2005, DP&L and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, USEPA denied the petitions for reconsideration. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting DP&L’s generation plants, however, on October 8, 2009, the USEPA issued new designations based on 2008 monitoring data that showed all areas in attainment to the standard with the exception of several counties in northeastern Ohio.

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

In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other gases are pollutants under the CAA. The USEPA has not yet identified the specifics of how these newly designated pollutants will be regulated. In April, 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO2 and other Green House Gases (GHGs) from motor vehicles threaten the health and welfare of future generations by contributing to climate change. If the proposed finding is finalized, it could lead to the regulation of CO2 and other GHGs from sources other than motor vehicles, including coal-fired plants that we own and operate. Recently, several bills have been introduced at the federal level to regulate GHG emissions. In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES). This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy wide cap and trade program. ACES also includes energy efficiency and renewable energy initiatives. Proposed GHG legislation finalized at a future date is expected to have a significant effect on DP&L’s operations and costs, which could adversely affect our net income and financial position. However, due to the uncertainty associated with such legislation, DP&L is currently unable to predict the final outcome or the financial impact that this legislation will have on it. On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. The first report will be submitted in March 2011 for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

Table of Contents

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

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

Air Quality — Litigation Involving Co-Owned Plants

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

Air Quality — Notices of Violation Involving Co-Owned Plants

On March 13, 2008, Duke Energy Ohio Inc., the operator of the Zimmer generating station, received a Notice of Violation (NOV) and a Finding of Violation from the USEPA alleging violations of the CAA, the Ohio State Implementation Program (SIP) and permits for the Station in areas including SO2, opacity and increased heat input. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of this matter. Duke Energy Ohio Inc. is expected to act on behalf of itself and the co-owners with respect to this matter. At this time, DP&L is unable to predict the outcome of this matter.

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

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

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

Air Quality — Other Issues Involving Co-Owned Plants

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

Table of Contents

Air Quality — Notices of Violation Involving Wholly-Owned Plants

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

Water Quality

On July 9, 2004, the USEPA issued final rules pursuant to the Clean Water Act governing existing facilities that have cooling water intake structures. The rules require an assessment of impingement and/or entrainment of organisms as a result of cooling water withdrawal. A number of parties appealed the rules to the Federal Court of Appeals for the Second Circuit in New York and the Court issued an opinion on January 25, 2007 remanding several aspects of the rule to USEPA for reconsideration. Several parties petitioned the U.S. Supreme Court for review of the lower court decision. On April 14, 2008, the Supreme Court elected to review the lower court decision on the issue of whether USEPA can compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Briefs were submitted to the Court in the summer of 2008 and oral arguments were held in December 2008. In April 2009, the U.S. Supreme Court ruled that USEPA did have the authority to compare costs with benefits in determining best technology available. USEPA is developing proposed regulations which it hopes to issue for public comment by mid-2010.

On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station that continued our authority to discharge water from the station into the Ohio River. During the three-year term of the Permit, we conducted a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers. In December 2006, we submitted an application for the renewal of the Permit that was due to expire on June 30, 2007. In July 2007 we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008 we received a letter from Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA have agreed to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to USEPA in response to their request to Ohio EPA. The timing for issuance of a final permit is uncertain.

Land Use and Solid Waste Disposal

In September 2002, DP&L and other parties received a special notice that the USEPA considers us to be PRPs for the clean-up of hazardous substances at the South Dayton Dump landfill site. In August 2005, DP&L and other parties received a general notice regarding the performance of a Remedial Investigation and Feasibility Study (RI/FS) under a Superfund Alternative Approach. In October 2005, DP&L received a special notice letter inviting it to enter into negotiations with USEPA to conduct the RI/FS. No recent activity has occurred with respect to that notice or PRP status. More recently, DP&L has received requests by the USEPA and the existing PRP group to allow access to be given to DP&L’s service center building site, which is across a street from the landfill site. The USEPA requested access to drill monitoring and test wells to determine the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. Pursuant to an Administrative Order issued by USEPA requiring access to DP&L’s service center building site, DP&L has granted such access and has met with USEPA’s contractor to facilitate access. DP&L believes the chemicals used at its service center building site were appropriately disposed of and have not contributed to the contamination at the South Dayton Dump landfill site. While DP&L is unable at this time to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.

Table of Contents

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

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

During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. DP&L has ash ponds at the Killen, Hutchings and J.M. Stuart stations which it operates, and also at generating stations operated by others but in which DP&L has an ownership interest. We frequently inspect our ash ponds and do not anticipate any similar failures. It is widely expected that the federal government will develop new regulations covering ash generated from the combustion of coal and impose additional monitoring, testing, or construction standards with respect to ash ponds and ash landfills. During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart stations. Subsequently USEPA collected similar information for Hutchings Station. Due to the wide range of possible outcomes, DP&L is unable at this time to predict the timing or the financial impact of any future governmental initiative that may occur.

Legal and Other Matters

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

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal expenses associated with our litigation against certain former executives. Arbitration on that claim occurred on May 13, 2009. The arbitration panel issued a ruling in Phase 1 of the arbitration on September 25, 2009, finding that most of the claims involving the former executives were covered. Further arbitration proceedings are scheduled to determine the amount of legal and fee expenses (if any) that the insurer must pay. DPL has, in accordance with GAAP, previously recorded these legal expenses totaling $7.5 million to expense but has not recorded any assets for possible recovery of these expenses.

As a member of PJM, DP&L is subject to charges and costs associated with PJM operations as approved by the FERC. FERC Orders issued in 2007 regarding the allocation of costs of large transmission facilities within PJM, could result in additional costs being allocated to DP&L of approximately $12 million or more annually by 2012. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit on March 18, 2008. The appeal has been consolidated with other appeals taken by other interested parties of the same FERC Orders and the consolidated cases have been assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. On September 18, 2009, two interveners, Baltimore Gas and Electric Company and Old Dominion Electric Cooperative, jointly filed a petition before the 7th Circuit seeking rehearing. DP&L and others of the original petitioners oppose the petition for rehearing. At this time, DP&L is unable to predict the outcome of the petition for rehearing or whether there may be further appeals to the U.S. Supreme Court. The Court will not issue a mandate and FERC will take no actions until all rehearing and appeals are resolved. Until such time as FERC may act in response to a court mandate, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. At this time, DP&L is unable to predict the outcome of this matter.

Table of Contents

In June 2009, the North American Electric Reliability Corporation (NERC), a FERC-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards, commenced a routine audit of DP&L’s operations. The audit, which was for the period June 18, 2007 to June 25, 2009, evaluated DP&L’s compliance with 42 requirements in 18 NERC-reliability standards. DP&L is currently subject to a compliance audit at a minimum of once every three years as provided by the NERC Rules of Procedure. This audit was concluded during the three months ended September 30, 2009 and its findings revealed that DP&L had some Possible Alleged Violations (PAVs) associated with five NERC Reliability Standards. In response to the report, DP&L filed mitigation plans with NERC to address the PAVs. These mitigation plans have been accepted and DP&L is currently awaiting a proposal for settlement from NERC. At this time, we are unable to determine the extent, if any, of penalties that will be imposed on DP&L.

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

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.

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 this section.

Table of Contents

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.

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 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 — Climate Change Legislation

Rules issued by the USEPA and Ohio EPA that require substantial reductions in SO2, NOx, and mercury emissions impact our business and operations. We are installing (and have installed) emission control technology and are taking other measures to comply with existing requirements for reductions in emissions.

In addition, 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, 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. In April 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO2 and other GHG from motor vehicles threaten the health and welfare of future generations by contributing to climate change. If the proposed finding is finalized, it could lead to the regulation of CO2 and other GHG from sources other than motor vehicles. Recently, several bills have been introduced at the federal level to regulate GHG emissions. In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES). This proposed legislation targets a reduction in the emission of GHG from large sources by 80% in 2050 through an economy wide cap and trade program. ACES also includes energy efficiency and renewable energy initiatives. Increased pressure for 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.

Table of Contents

· RPM Capacity Auction Price

The PJM RPM base residual auction (BRA) for the 2012/13 period cleared at a per megawatt price of $16/day for our RTO area. Prior to this auction, the per megawatt price for the 2011/2012 period was $110/day. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for Demand Response and Energy Efficiency resources in the RPM auctions. We cannot predict the outcome of future auctions but if the current auction price is sustained, our future results of operations, financial condition and cash flows could be adversely impacted.

· Ohio Competitive Considerations

Overall power market prices, as well as government aggregation initiatives, could lead to the entrance of competitors in our marketplace, affecting our results of operations, financial condition or cash flows. During the three months ended September 30, 2009, one additional unaffiliated marketer registered as a CRES provider in DP&L’s service territory, bringing to five the total number of unaffiliated CRES providers in DP&L’s service territory. While there has been some customer switching associated with unaffiliated marketers, it represented less than 0.11% of sales through September 30, 2009. DPLER, an affiliated company, is also a registered CRES provider and accounted for 99% of the total kWh supplied by CRES providers within DP&L’s service territory through September 30, 2009. We currently cannot determine the extent to which customer switching to unaffiliated CRES providers will occur in the future and the impact this will have on our operations.

· SB 221 Requirements

SB 221 and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction, and energy efficiency standards. The standards require that, by the year 2025, 25% of the total number of kilowatt hours of electricity sold by the utility to retail electric consumers must come from alternative energy resources, which include “advanced energy resources” such as distributed generation, clean coal, advanced nuclear, energy efficiency, and fuel cell technology; and “renewable energy resources” such as solar, hydro, wind, geothermal, and biomass. At least half of the 25% must be generated from renewable energy resources, including 0.5% from solar energy. The advanced energy portfolio and energy efficiency standards began in 2009 with increases in required percentages each year. SB 221 and the implementation rules do not include interim annual targets for energy efficiency and peak demand reductions, but require that energy efficiency programs save 22.3% compared to a baseline energy usage by 2025 and that peak demand reductions reach 7.75% by 2018. If any targets are not met, compliance penalties will apply. While we have started undertaking efforts to comply with this law, we currently cannot predict the extent of our compliance with the applicable targets or the future impact these rules will have on our operations.

REGULATION UPDATES

Ohio Retail Matters

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 and provides for recovery of certain SB 221 compliance costs. 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.

Consistent with the Stipulation, DP&L filed its Smart Grid and Advanced Metering infrastructure business cases at the PUCO on August 4, 2009 seeking recovery of costs associated with a 10-year plan to deploy smart meters, distribution and substation automation, core telecommunications, supporting software and in-home technologies. On August 5, 2009, DP&L submitted an application for American Recovery and Reinvestment Act (ARRA) funding under the Integrated and/or Crosscutting Systems topic area for the Smart Grid Investment Grant Program. The application, which sought $145.1 million of matching funds, focused on the first three years of DP&L’s 10-year plan. On October 27, 2009, we were notified by the United States Department of Energy (DOE) that we will not receive funding under the ARRA.

Table of Contents

The Stipulation provided for the establishment of a fuel and purchased power recovery rider beginning January 1, 2010. Per the provisions of the Stipulation, DP&L is required to file its proposed fuel rider no later than November 1, 2009. DP&L is in the process of developing this filing and anticipates an October 30, 2009 filing date.

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 includes a provision that allows 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. DP&L subsequently filed to establish the TCRR that would incorporate all charges and credits from the RTO as well as the amounts approved for deferral. On May 27, 2009 the PUCO granted approval of this filing and DP&L began recovery of these costs on June 1, 2009. On June 19, 2009, the Industrial Energy Users of Ohio (IEU-OH) filed an application for rehearing claiming the PUCO’s order allowing for recovery of reliability pricing model (RPM) costs through this rider was unlawful. On September 9, 2009, the PUCO granted rehearing, and issued an entry ordering DP&L to remove the RPM costs from the TCRR and refile its tariffs. The Commission noted that although the RPM costs are not recoverable through the TCRR, those costs may be recoverable through a separate rider. On September 23, 2009, DP&L filed two separate riders, a TCRR without RPM costs, and an RPM recovery rider. On October 21, 2009, the PUCO Staff filed a staff report in the case recommending the Commission approve both of DP&L’s proposed riders. The outcome of this proceeding cannot be determined at this time, but, based on past precedent and the PUCO’s orders received thus far, we continue to believe that these costs are probable of recovery.

As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC Orders issued in 2007 regarding the allocation of costs of large transmission facilities within PJM, could result in additional costs being allocated to DP&L of approximately $12 million or more annually by 2012. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit on March 18, 2008. The appeal has been consolidated with other appeals taken by other interested parties of the same FERC Orders and the consolidated cases have been assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. On September 18, 2009, two interveners, Baltimore Gas and Electric Company and Old Dominion Electric Cooperative, jointly filed a petition before the 7th Circuit seeking rehearing. DP&L and others of the original petitioners oppose the petition for rehearing. At this time, DP&L is unable to predict the outcome of the petition for rehearing or whether there may be further appeals to the U.S. Supreme Court. The Court will not issue a mandate and FERC will take no actions until all rehearing and appeals are resolved. Until such time as FERC may act in response to a court mandate, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. On November 7, 2008, DP&L filed a request at the PUCO for authority to defer its costs associated with transmission, capacity, ancillary service and other PJM related charges incurred as a member of PJM. This filing was approved and is further discussed in the immediately preceding paragraph.

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.

Table of Contents

The rules were remanded to the PUCO from the legislative committee that oversees rules implementing Ohio legislation. The PUCO re-issued the rules in final form on October 15, 2009 with only slight modifications.

On September 9, 2009, the PUCO issued an entry establishing a significantly excessive earnings test (SEET) proceeding. A workshop was held at the Commission offices on October 5, 2009 to allow interested parties to present concerns and discuss issues related to the methodology for determining whether an electric utility has significantly excessive earnings pursuant to the provisions contained in SB 221. The order directs PUCO staff to develop and file recommendations for the SEET and states that a procedural schedule will be established to allow for comments and reply comments by interested parties. Although DP&L’s Stipulation provides that the SEET does not apply to DP&L until 2013 based on 2012 earnings results, DP&L will actively participate in this proceeding.

Federal Matters

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 our facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. DPL, through its wholly owned captive insurance subsidiary MVIC, has an actuarially calculated reserve 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. In April, 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO2 and other Green House Gases (GHGs) from motor vehicles threaten the health and welfare of future generations by contributing to climate change. If the proposed finding is finalized, it could lead to the regulation of CO2 and other GHGs from sources other than motor vehicles. Recently, several bills have been introduced at the federal level to regulate GHG emissions. In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES). This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy wide cap and trade program. ACES also includes energy efficiency and renewable energy initiatives. Proposed GHG legislation finalized at a future date is expected to have a significant effect on DP&L’s operations. However, due to the uncertainty associated with such future regulations, DP&L is currently unable to predict the final outcome or the financial impact that this new legislation will have on its future operations. On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. The first report will be submitted in March 2011 for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

Table of Contents

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

Pursuant to the Clean Air Interstate Rule (CAIR) previously discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, (our “2008 10-K”) the Ohio EPA initiated an Early Reduction Credit (ERC) program for annual NOx emission allowances for 2008 and 2009. DP&L qualified for ERCs in excess of what was initially allocated to DP&L and submitted the data for all ERCs generated. 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 generated ERCs in excess of their initial allocation. DP&L is expected to be allocated between 28% - 33% more ERCs than its initial allocation.

As previously reported in more detail in our 2008 10-K, on October 23, 2008, the U.S. District Court for the Southern District of Ohio approved a consent decree that settled a lawsuit initiated by the Sierra Club against DP&L and the other owners of the Stuart generating station for alleged violations of the CAA and the station’s operating permit. On October 21, 2009, the Sierra Club filed with the U.S. District Court a motion for enforcement of the consent decree based on the Sierra Club’s interpretation of the consent decree that would require certain NOx emissions that DP&L has been excluding from its computations to be included for purposes of complying with the emission targets and reporting requirements of the consent decree. DP&L believes that it is properly computing and reporting NOx emissions under the consent decree and will oppose the Sierra Club’s motion.

Our 2008 10-K 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’s generation plants. However, on October 8, 2009, the USEPA issued new designations based on 2008 monitoring data that showed all areas in attainment to the standard with the exception of several counties in northeastern Ohio.

Our 2008 10-K 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 certain emission allowances and pay a fine. None of the violations found or remedies ordered relate to generating units owned in part by DP&L.

Our 2008 10-K 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), for alleged violations of the CAA and air pollution nuisances. A settlement was finalized during the three months ended September 30, 2009. The cash portion of the settlement was $900,000, of which DP&L expects to be invoiced 28.1% based on its ownership share. DP&L has accrued its portion of the cash settlement. Non-cash portions of the settlement are not expected to have material effects on the future operation of the station.

Table of Contents

Our 2008 10-K 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.

On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHG from large GHG emissions sources in the U.S. Several DPL facilities will begin collecting data January 1, 2010. The first emission report is due on March 31, 2011, for emissions during 2010.

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

Our 2008 10-K reports on a special notice received in 2002, stating that the 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 the extent of the landfill site’s contamination as well as to assess whether certain chemicals used at the service center building site might have migrated through groundwater to the landfill site. Pursuant to an Administrative Order issued by USEPA requiring access to DP&L’s service center building site, DP&L has granted such access and has met with USEPA’s contractor to facilitate access. DP&L believes the chemicals used at its service center building site were appropriately disposed of and have not contributed to the contamination at the South Dayton Dump landfill site. While DP&L is unable at this time to predict the outcome of this matter, if DP&L were required to contribute to the clean-up of the site, it could have a material adverse effect on us.

During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. DP&L has ash ponds at the Killen, Hutchings and J.M. Stuart stations which it operates, and also at generating stations operated by others but in which DP&L has an ownership interest. We frequently inspect our ash ponds and do not anticipate any similar failures. It is widely expected that the federal government will develop new regulations covering ash generated from the combustion of coal and impose additional monitoring, testing, or construction standards with respect to ash ponds and ash landfills. During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart stations. Subsequently USEPA collected similar information for Hutchings Station. Due to the wide range of possible outcomes, DP&L is currently unable to assess the timing or the financial impact of any future governmental initiative that may occur.

Table of Contents

FINANCIAL OVERVIEW

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

For the three months ended September 30, 2009, net income was $67.9 million, or $0.59 per share, compared to net income of $48 million, or $0.42 per share, for the same period in 2008. The increase in net income compared to the prior year was primarily due to:

· an increase in retail rates primarily as a result of an increase in the environmental investment rider and the TCRR,

· an increase in the volume of wholesale power sales,

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

· a decrease in power purchase prices,

· a decrease in the average cost of fuel, and

· a decrease in the estimated annual effective income tax rate.

Partially offsetting these items were:

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

· a decrease in wholesale power sales prices,

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

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

For the nine months ended September 30, 2009, net income was $179.2 million, or $1.58 per share, compared to net income of $172.9 million, or $1.49 per share, for the same period in 2008. The increase in net income compared to the prior year was primarily due to the following:

· an increase in retail rates primarily as a result of an increase in the environmental investment rider and the TCRR,

· an increase in the volume of wholesale power sales,

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

· a decrease in power purchase prices,

· increased gains recognized from the sale of coal, and

· reduced interest costs as a result of certain outstanding debt redemptions.

Partially offsetting these items were:

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

· a decrease in wholesale power sales prices,

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

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

· an increase in pension and employee benefit related costs.

Table of Contents

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 discussion of the results of operations for DP&L is presented elsewhere in this report.

Income Statement Highlights — DPL

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions except per share amounts	2009			2008			2009			2008

Revenues:
Retail	$	318.8		$	315.7		$	921.3		$	920.8
Wholesale	30.9			27.9			81.5			124.8
RTO revenues	21.5			31.3			68.4			84.4
RTO capacity revenues	33.1			36.8			103.2			70.7
Other revenues	3.0			2.8			9.1			8.7
Total revenues	$	407.3		$	414.5		$	1,183.5		$	1,209.4

Cost of revenues:
Fuel costs	$	95.9		$	90.7		$	291.7		$	263.3
Gains from sale of coal	(10.8		)	(28.5		)	(45.9		)	(40.3		)
Gains from sale of emission allowances	(0.7		)	—			(4.1		)	(30.5		)
Net fuel	84.4			62.2			241.7			192.5

Purchased power	7.0			56.8			36.7			122.2
RTO charges	25.9			29.2			78.7			101.7
RTO capacity charges	31.2			33.8			100.3			65.0
Recovery/(Deferral) of RTO related charges	0.9			—			(27.7		)	—
Total purchased power	65.0			119.8			188.0			288.9

Total cost of revenues	$	149.4		$	182.0		$	429.7		$	481.4

Gross margin (a)	$	257.9		$	232.5		$	753.8		$	728.0

Gross margin as a percentage of revenues	63		%	56		%	64		%	60		%

Operating income	$	116.5		$	96.2		$	325.4		$	324.5

Earnings per share of common stock:
Basic	$	0.60		$	0.44		$	1.60		$	1.58
Diluted	$	0.59		$	0.42		$	1.58		$	1.49

(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.

Table of Contents

DPL — Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DPL’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Since DPL plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa.

The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DPL’s wholesale sales volume each hour of the year include wholesale market prices; DPL’s retail demand; retail demand elsewhere throughout the entire wholesale market area; DPL and non-DPL plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DPL’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities not being utilized to meet its retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

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

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2009 vs. 2008			2009 vs. 2008

Retail
Rate	$	39.4		$	88.0
Volume	(36.0		)	(86.6		)
Other	(0.3		)	(0.9		)
Total retail change	$	3.1		$	0.5

Wholesale
Rate	$	(43.3	)	$	(62.8	)
Volume	46.3			19.5
Total wholesale change	$	3.0		$	(43.3	)

RTO capacity and other
RTO capacity and other revenues	$	(13.3	)	$	16.9

Total revenues	$	(7.2	)	$	(25.9	)

For the three months ended September 30, 2009, revenues decreased $7.2 million, or 2%, to $407.3 million from $414.5 million for the same period in the prior year. This decrease was primarily the result of lower retail sales volume and lower wholesale average prices and decreased RTO capacity and other revenues, partially offset by higher average rates for retail sales, as well as increased wholesale sales volume. The revenue components for the three months ended September 30, 2009 are further discussed below:

· Retail revenues increased $3.1 million resulting primarily from a 14% increase in average retail rates due largely to the incremental effect of the recovery of costs under the third phase of the environmental investment rider (EIR) combined with the implementation of the TCRR. The recovery of costs under the TCRR began on June 1, 2009. The increase was partially offset by an 11% decrease in sales volume driven largely by milder weather conditions which saw cooling degree days decrease 29%, and the effects of the economic recession. As a result, retail revenues had a favorable $39.4 million price variance and an unfavorable $36.0 million sales volume variance.

· Wholesale revenues increased $3.0 million primarily as a result of a 167% increase in sales volume, partially offset by a 58% decrease in wholesale average prices resulting in a favorable $46.3 million volume variance and an unfavorable $43.3 million wholesale price variance.

Table of Contents

· 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, decreased $13.3 million compared to the same period in the prior year. The decrease to RTO capacity and other RTO revenues was primarily the result of a decrease in revenues from the PJM capacity auction of $3.7 million, combined with a decrease in PJM transmission and congestion revenues of $9.8 million.

For the nine months ended September 30, 2009, revenues decreased $25.9 million, or 2%, to $1,183.5 million from $1,209.4 million for the same period in the prior year. This decrease was primarily the result of lower retail sales volume as well as decreased wholesale average prices, partially offset by higher average retail rates, increased wholesale sales volume and an increase in RTO capacity and other revenues. The revenue components for the nine months ended September 30, 2009 are further discussed below:

· Retail revenues increased $0.5 million resulting primarily from an 11% increase in average retail rates due largely to the incremental effect of the recovery of costs under the third phase of the EIR combined with the implementation of the TCRR, partially offset by a 9% decrease in sales volume driven largely by the effects of the economic recession and milder weather conditions. Heating and cooling degree days decreased by 4% and 14% to 3,521 days and 731 days, respectively. As a result, retail revenues had a favorable $88.0 million price variance and an unfavorable $86.6 million sales volume variance.

· Wholesale revenues decreased $43.3 million primarily as a result of a 43% decrease in wholesale average prices partially offset by a 16% increase in sales volume, resulting in an unfavorable $62.8 million wholesale price variance and a favorable $19.5 million sales volume variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $16.9 million compared to the same period in the prior year. This increase was primarily the result of additional revenue of $32.5 million that was realized from the PJM capacity auction, partially offset by a decrease in PJM transmission and congestion revenues of $16.0 million.

DPL — Cost of Revenues

For the three months ended September 30, 2009:

· Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $22.2 million, or 36%, compared to the same period in 2008, primarily due to the impact of lower gains realized from the sale of coal. In 2009, gains from the sale of coal amounted to $10.8 million compared to $28.5 million during the same period in 2008. Also contributing to the increase in fuel costs was a 23% increase in the usage of fuel due mainly to improved performance of our generating facilities, which resulted in increased generation output and a reduced demand for higher-cost purchased power. The above increases to fuel costs were partially offset by a 14% decrease in the average cost of fuel consumed per kilowatt-hour largely resulting from overall lower market prices of coal during the two comparative periods.

· Purchased power decreased $54.8 million, or 46%, compared to the same period in 2008. The decrease in purchased power primarily resulted from a $39.7 million decrease relating to lower volumes of purchased power, a $10.1 million decrease related to lower average market rates, and a $5.0 million net decrease in 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.

For the nine months ended September 30, 2009:

· Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $49.2 million, or 26%, compared to the same period in 2008, primarily due to the impact of lower gains realized from the sale of excess emission allowances. In 2009, DP&L realized $4.1 million in gains from the sale of excess emission allowances compared to $30.5 million during the same period in 2008. Also contributing to the increase in fuel costs was a 7% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from higher market prices of coal combined with outages at lower-cost units, as well as a 4% increase in the usage of fuel due mainly to improved performance of our generating facilities. This improved performance of our generating facilities resulted in increased generation output and a reduced demand for higher-cost purchased power. The above increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal. In 2009, gains from the sale of coal amounted to $45.9 million compared to $40.3 million for the same period in 2008.

Table of Contents

· Purchased power decreased $100.9 million compared to the same period in 2008. The net decrease in purchased power is partly a result of decreases of $59.2 million and $26.3 million relating to lower volumes of purchased power and lower average market rates, respectively. Also contributing to the decrease in purchased power is 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 Note 3 of Notes to Condensed Consolidated Financial Statements. 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			Nine Months Ended
	September 30,			September 30,
$ in millions	2009 vs. 2008			2009 vs. 2008
Pension	$	2.0		$	5.4
Low-income payment program	1.3			4.7
Generating facilities operating and maintenance expenses	(4.1		)	3.1
ESOP	0.7			2.8
Deferred compensation	1.4			2.6
Group insurance	1.8			1.7
Other, net	2.5			5.6
Total operation and maintenance expense	$	5.6		$	25.9

During the three months ended September 30, 2009, operation and maintenance expense increased $5.6 million, or 8%, compared to the similar period in 2008. This variance was primarily the result of:

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

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

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

· increased deferred compensation costs, and

· increased health insurance costs primarily related to higher disability reserves.

These increases were partially offset by lower operating and maintenance expenses at our generating facilities due largely to higher maintenance expenses incurred in the prior year related to unplanned outages at jointly-owned production units combined with lower operating costs in 2009.

During the nine months ended September 30, 2009, operation and maintenance expense increased $25.9 million, or 13%, compared to the similar period in 2008. This variance was primarily the result of:

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

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

· increases in operating and maintenance expenses for generating facilities largely due to costs associated with unplanned outages at jointly-owned production units,

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

· increased deferred compensation costs, and

· increased health insurance costs primarily related to higher disability reserves.

Table of Contents

DPL — Depreciation and Amortization

For the three months and nine months ended September 30, 2009, depreciation and amortization expense increased $0.8 million and $5.3 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 nine months ended September 30, 2009, general taxes decreased $3.2 million compared to the similar period in 2008 primarily due to lower property tax accruals in 2009 compared to 2008 and lower KWh excise taxes resulting from lower retail sales volume.

DPL — Amortization of Regulatory Assets

For the nine months ended September 30, 2009, the amortization of regulatory assets was $3.1 million lower than that of the similar period 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.

DPL — Investment Income

For the nine months ended September 30, 2009, investment income decreased $2.4 million compared to the similar period in 2008 primarily as a result of lower cash and short-term investment balances in 2009 combined with overall lower market yields on investments.

DPL — Interest Expense

For the three months ended September 30, 2009, interest expense decreased $2.3 million compared to the same period in 2008 primarily due to a $3.5 million reduction in interest expense due to the redemption of DPL’s $175 million 8.00% Senior Notes on March 31, 2009, partially offset by $1.0 million of lower capitalized interest, due largely to the completion of the FGD projects at the generating stations.

For the nine months ended September 30, 2009, interest expense decreased $7.2 million compared to the same period in 2008 primarily due to:

· a $9.3 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,

· 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

· $1.6 million of deferred interest carrying costs on regulatory assets primarily associated with TCRR and the 2008 incremental storm costs. These regulatory assets are further discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

The above decreases were partially offset by $5.9 million of lower capitalized interest in 2009 compared to 2008, due largely to the completion of the FGD projects at the generating stations.

DPL — Income Tax Expense

For the three months ended September 30, 2009, income taxes increased $1.8 million, or 7%, compared to the same period in 2008, primarily reflecting an increase in pre-tax book income partially offset by a decrease in the effective tax rate resulting from estimate-to-actual adjustments of 2008 taxes and 2009 estimated tax benefits related to a Section 199 — domestic production deduction (Section 199 deduction) and the phase-out of the Ohio Franchise Tax.

For the nine months ended September 30, 2009, income taxes decreased $1.7 million, or 2%, compared to the same period in 2008, primarily due to decreases reflecting a lower effective tax rate resulting from estimate-to-actual adjustments of 2008 taxes and 2009 estimated tax benefits related to an Internal Revenue Code Section 199 deduction, the phase-out of the Ohio Franchise Tax and a 2008 settlement relating to Ohio Franchise Taxes. These decreases were partially offset by an increase in pre-tax book income.

Table of Contents

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

Income Statement Highlights — DP&L

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2009			2008			2009			2008

Revenues:
Retail	$	301.8		$	278.0		$	875.8		$	809.5
Wholesale	47.8			61.9			124.7			233.7
RTO revenues	20.7			30.4			66.0			83.5
RTO capacity revenues	27.9			31.2			87.2			65.1
Total revenues	$	398.2		$	401.5		$	1,153.7		$	1,191.8

Cost of revenues:
Fuel costs	$	94.5		$	85.5		$	286.2		$	254.4
Gains from sale of coal	(10.8		)	(28.5		)	(45.9		)	(40.3		)
Gains from sale of emission allowances	(0.7		)	—			(4.1		)	(30.5		)
Net fuel	83.0			57.0			236.2			183.6

Purchased power	6.9			58.0			36.6			126.0
RTO charges	25.6			28.3			77.8			100.8
RTO capacity charges	31.3			33.8			100.4			65.0
Recovery/(Deferral) of RTO related charges	0.9			—			(27.7		)	—
Total purchased power	$	64.7		$	120.1		$	187.1		$	291.8

Total cost of revenues	$	147.7		$	177.1		$	423.3		$	475.4

Gross margin (a)	$	250.5		$	224.4		$	730.4		$	716.4

Gross margin as a percentage of revenues	63		%	56		%	63		%	60		%

Operating income	$	115.2		$	93.5		$	318.9		$	330.4

(a)

DP&L — Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, DP&L’s retail sales volume is impacted by the number of heating and cooling degree days occurring during a year. Since DP&L plans to utilize its internal generating capacity to supply its retail customers’ needs first, increases in retail demand may decrease the volume of internal generation available to be sold in the wholesale market and vice versa.

The wholesale market covers a multi-state area and settles on an hourly basis throughout the year. Factors impacting DP&L’s wholesale sales volume each hour of the year include wholesale market prices; DP&L’s retail demand, retail demand elsewhere throughout the entire wholesale market area; DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities that are not being utilized to meet its retail demand or when margin opportunities exist between the wholesale sales and power purchase prices.

Table of Contents

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

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2009 vs. 2008			2009 vs. 2008

Retail
Rate	$	55.7		$	143.2
Volume	(31.6		)	(76.0		)
Other	(0.3		)	(0.9		)
Total retail change	$	23.8		$	66.3

Wholesale
Rate	$	(134.3	)	$	(142.9	)
Volume	120.2			33.9
Total wholesale change	$	(14.1	)	$	(109.0	)

RTO capacity and other
RTO capacity and other revenues	$	(13.0	)	$	4.6

Total revenues	$	(3.3	)	$	(38.1	)

For the three months ended September 30, 2009, revenues decreased $3.3 million, or 1%, to $398.2 million from $401.5 million in the same period of the prior year. This decrease was primarily the result of lower average prices for wholesale sales, lower retail sales volume and decreased RTO capacity and other revenues. These decreases were partially offset by higher average rates for retail sales and higher wholesale volumes. The revenue components for the three months ended September 30, 2009 are further discussed below:

· Retail revenues increased $23.8 million resulting primarily from a 23% increase in average retail rates due largely to the incremental effect of the recovery of costs under the third phase of the EIR combined with the implementation of the TCRR. The recovery of costs under the TCRR began on June 1, 2009. This increase was partially offset by an 11% decrease in sales volume driven largely by milder weather conditions which saw cooling degree days decrease 29% , and the effects of the economic recession. As a result, retail revenues had a favorable $55.7 million price variance and an unfavorable $31.6 million sales volume variance.

· Wholesale revenues decreased $14.1 million primarily as a result of a 74% decrease in wholesale average prices, partially offset by a 194% increase in sales volume, resulting in an unfavorable $134.3 million wholesale price variance and a favorable $120.2 million sales volume variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $13.0 million compared to the same period in the prior year. This decrease primarily resulted from decreased revenue of $3.3 million that was realized from the PJM capacity auction, combined with a decrease in PJM transmission and congestion revenues of $9.7 million.

For the nine months ended September 30, 2009, revenues decreased $38.1 million, or 3%, to $1,153.7 million from $1,191.8 million in the same period of the prior year. This decrease was primarily the result of lower wholesale average prices and lower retail sales volume, partially offset by higher average retail rates, increased wholesale sales volume and an increase in RTO capacity and other revenues. The revenue components for the nine months ended September 30, 2009 are further discussed below:

· Retail revenues increased $66.3 million resulting primarily from a 20% increase in average retail rates due largely to the third phase of the EIR and the implementation of the TCRR, partially offset by a 9% decrease in retail sales volume driven largely by the effects of the economic recession and milder weather conditions. Heating and cooling degree days decreased by 4% and 14% to 3,521 days and 731 days, respectively. As a result, retail revenues had a favorable $143.2 million price variance and an unfavorable $76.0 million sales volume variance.

· Wholesale revenues decreased $109.0 million primarily as a result of a 53% decrease in wholesale average prices, partially offset by a 14% increase in sales volume, resulting in an unfavorable $142.9 million wholesale price variance and a favorable $33.9 million sales volume variance.

Table of Contents

· 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 $4.6 million compared to the same period in the prior year. This increase primarily resulted from additional revenue of $22.1 million that was realized from the PJM capacity auction, partially offset by a $17.5 million decrease in PJM transmission and congestion revenues.

DP&L — Cost of Revenues

For the three months ended September 30, 2009:

· Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $26.0 million, or 46%, compared to the same period in 2008 primarily due to the impact of lower gains realized from the sale of coal. In 2009, gains from the sale of coal amounted to $10.8 million compared to $28.5 million during the same period in 2008. Also contributing to the increase in fuel costs was a 23% increase in the usage of fuel due mainly to improved performance of our generating facilities and which resulted in increased generation output and a reduced demand for higher-cost purchased power. The above increases to fuel costs were partially offset by a 10% decrease in the average cost of fuel consumed per kilowatt-hour largely resulting from overall lower market prices of coal during the two comparative periods.

· Purchased power decreased $55.4 million, or 46%, compared to the same period in 2008. The decrease in purchased power primarily resulted from a $40.6 million decrease relating to lower volumes of purchased power, a $10.4 million decrease relating to lower average market rates and a $4.3 million net decrease in 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.

For the nine months ended September 30, 2009:

· Fuel costs, which include coal (net of gains on sales), gas, oil and emission allowances (net of gains on sales), increased $52.6 million, or 29%, compared to the same period in 2008, primarily due to the impact of lower gains realized from the sale of excess emission allowances. In 2009, DP&L realized $4.1 million in gains from the sale of excess emission allowances compared to $30.5 million during the same period in 2008. Also contributing to the increase in fuel costs was an 8% increase in the average cost of fuel consumed per kilowatt-hour largely resulting from higher market prices of coal combined with outages at lower-cost units, as well as a 4% increase in the usage of fuel due mainly to improved performance of our generating facilities. This improved performance of our generating facilities resulted in increased generation output and a reduced demand for higher-cost purchased power. The above increases to fuel costs were partially offset by higher gains realized in 2009 from the sale of coal. In 2009, gains from the sale of coal amounted to $45.9 million compared to $40.3 million for the same period in 2008.

· Purchased power decreased $104.7 million compared to the same period in 2008. The net decrease in purchased power is partly a result of decreases of $61.7 million and $27.6 million relating to lower volumes of purchased power and lower average market rates, respectively. Also contributing to the decrease in purchased power is 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 Note 3 of Notes to Condensed Consolidated Financial Statements. 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.

Table of Contents

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			Nine Months Ended
	September 30,			September 30,
$ in millions	2009 vs. 2008			2009 vs. 2008
Pension	$	2.0		$	5.4
Low-income payment program	1.3			4.7
Generating facilities operating and maintenance expenses	(4.1		)	3.1
ESOP	0.6			2.7
Group insurance	1.8			1.8
Deferred compensation	0.3			0.6
Other, net	2.9			8.2
Total operation and maintenance expense	$	4.8		$	26.5

During the three months ended September 30, 2009, operation and maintenance expense increased $4.8 million, or 7%, compared to the similar period in 2008. This variance was primarily the result of:

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

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

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

· increased health insurance costs primarily related to higher disability reserves, and

· increased deferred compensation costs.

During the nine months ended September 30, 2009, operation and maintenance expense increased $26.5 million, or 14%, compared to the similar periods in 2008. This variance was primarily the result of:

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

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

· increases in operating and maintenance expenses for generating facilities largely due to costs associated with unplanned outages at jointly-owned production units ,

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

· increased health insurance costs primarily related to higher disability reserves, and

· increased deferred compensation costs.

DP&L — Depreciation and Amortization

For the three months and nine months ended September 30, 2009, depreciation and amortization expense increased $0.8 million and $5.2 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 nine months ended September 30, 2009, general taxes decreased $3.1 million compared to the similar period in 2008 primarily due to lower property tax accruals in 2009 compared to 2008 and lower KWh excise taxes resulting from lower retail sales volumes.

Table of Contents

DP&L — Amortization of Regulatory Assets

DP&L — Investment Income

For the nine months ended September 30, 2009, investment income decreased $3.9 million compared to the same period in 2008 primarily as a result of lower market yields on investments.

DP&L — Interest Expense

Interest expense for the three months ended September 30, 2009 increased $1.3 million compared to the same period of the prior year primarily as a result of $1.0 million of lower capitalized interest in 2009 due largely to the completion of the FGD projects at the generating stations.

Interest expense for the nine months ended September 30, 2009 increased $2.2 million compared to the same period of the prior year primarily as a result of $5.9 million of lower capitalized interest due largely to the completion of the FGD projects at the generating stations. This increase was partially offset by:

DP&L — Income Tax Expense

For the three months ended September 30, 2009, income taxes increased $0.5 million, or 2%, compared to the same period in 2008, primarily reflecting an increase in pre-tax book income. This increase was partially offset by a decrease in the effective tax rate resulting from estimate-to-actual adjustments of 2008 taxes and 2009 estimated tax benefits related to a Section 199 — domestic production deduction (Section 199 deduction) and the phase-out of the Ohio Franchise Tax.

For the nine months ended September 30, 2009, income taxes decreased $9.1 million, or 9%, compared to the same period in 2008, primarily due to decreases reflecting a lower pre-tax book income, a lower effective tax rate resulting from estimate-to-actual adjustments of 2008 taxes and 2009 estimated tax benefits related to a Section 199 deduction, the phase-out of the Ohio Franchise Tax and a 2008 settlement relating to Ohio Franchise Taxes.

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 $62.8 million at September 30, 2009, compared to $62.5 million at December 31, 2008, an increase of $0.3 million. The increase in cash and cash equivalents was primarily attributed to $292.2 million of cash generated from operating activities, net borrowings from the revolving credit facilities of $115 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, partially offset by cash paid to retire $175 million of long-term debt, $134.6 million of capital expenditures, $95.7 million of dividends paid on common stock, and $15.9 million used to repurchase outstanding stock warrants. At September 30, 2009, DPL had $7.9 million in restricted funds held in trust to fund pollution control capital expenditures.

Table of Contents

DP&L’s Cash Position

DP&L’s cash and cash equivalents totaled $20.7 million at September 30, 2009, compared to $20.8 million at December 31, 2008, a decrease of $0.1 million. The decrease in cash and cash equivalents was primarily attributed to $270 million in dividends paid on common stock to our parent DPL, and $129.9 million used for capital expenditures. These cash inflows were partially offset by $278.7 million in cash generated from operating activities, net borrowings of $115 million from the revolving credit facilities and net withdrawals of $6.7 million from restricted funds to pay for pollution control capital expenditures. At September 30, 2009, DP&L had $7.9 million in restricted funds held in trust to fund pollution control capital expenditures.

Operating Activities

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

Net Cash provided by Operating Activities

	Nine Months Ended
	September 30,
$ in millions	2009		2008

DPL	$	292.2	$	242.5

DP&L	$	278.7	$	273.8

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 $292.2 million and $242.5 million in the nine-month periods ended September 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 $278.7 million and $273.8 million in the nine-month periods ended September 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 nine months ended September 30, 2009 and 2008, cash flows from investing activities were as follows:

Net Cash used for Investing Activities

	Nine Months Ended
	September 30,
$ in millions	2009			2008

DPL	$	(128.4	)	$	(183.7	)

DP&L	$	(129.9	)	$	(173.1	)

Table of Contents

DPL’s Cash used for Investing Activities

DPL’s net cash used for investing activities was $128.4 million and $183.7 million in the nine-month periods ended September 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 $129.9 million and $173.1 million in the nine-month periods ended September 30, 2009 and 2008, respectively. Net cash flows used for investing activities during both of these periods were related to capital expenditures.

Financing Activities

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

Net Cash used for Financing Activities

	Nine Months Ended
	September 30,
$ in millions	2009			2008

DPL	$	(163.5	)	$	(167.4	)

DP&L	$	(148.9	)	$	(80.1	)

DPL’s Cash used for Financing Activities

DPL’s net cash used for financing activities in the nine months ended September 30, 2009 was $163.5 million compared to $167.4 million during the same period of the prior year. Net cash flows used for financing activities in the nine months ended September 30, 2009 were primarily the result of cash used to retire $175 million of long-term debt, to pay dividends of $95.7 million to stockholders, and to repurchase $15.9 million of outstanding stock warrants, partially offset by net borrowings of $115 million from the revolving credit facilities and net withdrawals of $6.7 million from the restricted funds held in trust. Net cash flows used for financing activities in the nine months ended September 30, 2008 were primarily the result of cash used to redeem the $100 million of long-term debt and to pay dividends of $89.9 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 nine months ended September 30, 2009 was $148.9 million compared to $80.1 million during the same period of the prior year. Net cash flows used for financing activities in the nine months ended September 30, 2009 were primarily the result of cash used to pay common stock dividends of $270 million to our parent DPL partially offset by net borrowings of $115 million from the revolving credit facilities and $6.7 million in net withdrawals from restricted funds held in trust. Net cash flows used for financing activities for the nine months ended September 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 from time to time in Part II, Item 1A of our subsequent Quarterly Reports on Form 10-Q. If we are unable to generate sufficient cash flows, or otherwise comply with the terms of our credit facilities, 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.

Table of Contents

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 September 30, 2009, DP&L was in compliance with this covenant with a ratio of 0.43 to 1.00. As of September 30, 2009, the borrowings outstanding under this facility amounted to $80 million. This revolving credit facility is also discussed in the liquidity section below.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated obligations. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. For the remainder of 2009 and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. We also expect that the borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

We have access to $320 million of short-term financing under two revolving credit facilities. The first facility for $220 million expires November 2011 and has three participating banks; the lead bank has a total commitment of 36% while the other two have commitments of 32% each. The second is a 364-day $100 million facility that matures April 2010. A total of six banks participate in this facility, with no bank having more than 26% of the total commitment. The two bank groups have no common members. We are currently evaluating the impact the maturity of the $100 million facility will have on our future liquidity and would expect to be able to renew or replace this facility as needed.

					Amounts available as of
					September 30, 2009
$ in millions	Type	Maturity	Commitment		DPL		DP&L

Dayton Power & Light Co.	Revolving	11/21/2011	$	220.0	$	185.0	$	185.0

Dayton Power & Light Co.	Revolving	04/20/2010	$	100.0	$	20.0	$	20.0

			$	320.0	$	205.0	$	205.0

As further discussed in Note 5 of Notes to Condensed Consolidated Financial Statements, on October 28, 2009, DP&L repaid $90 million of the borrowings outstanding under the revolving credit facilities. After considering these payments, the total cash available under both facilities at that date amounted to $295 million.

The $220 million revolver has a $40 million Letter of Credit (LOC) sublimit. As of September 30, 2009, there were no outstanding LOCs.

Also, cash and cash equivalents for DPL and DP&L amounted to $62.8 million and $20.7 million, respectively, at September 30, 2009.

In addition, at September 30, 2009, DP&L had a net tax receivable in the amount of $90.8 million resulting from the recognition of certain tax benefits. This receivable is available to be offset against future income tax liabilities and is expected to be collected within the next 12 months.

Capital Requirements

DPL’s construction additions were $100.7 million and $168.1 million during the nine-month periods ended September 30, 2009 and 2008, respectively. DPL is expected to spend approximately $60 million for the remainder of 2009.

DP&L’s construction additions were $99.3 million and $166.9 million during the nine-month periods ended September 30, 2009 and 2008, respectively. DP&L is expected to spend approximately $60 million for the remainder of 2009. The remaining planned construction additions for 2009 relate to DP&L’s environmental compliance program, power plant equipment and its transmission and distribution system.

Table of Contents

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 and its subsidiary DP&L, are projecting to spend approximately $540 million and $530 million, respectively, in capital projects for the period 2009 through 2011, which includes amounts already spent during the first nine months of 2009 as quantified above.

On August 4, 2009, DP&L re-filed its smart grid and advanced metering infrastructure (AMI) business cases with the PUCO. In addition to the capital projects mentioned in the preceding paragraph, DPL and DP&L are projecting to spend approximately $188 million on capital projects for the period 2009 through 2011 related to the smart grid and AMI programs, pending approval from the PUCO. The re-filing at the PUCO is further discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds and the reasonable cost of external funds. We expect to finance our construction additions in 2009 with a combination of cash on hand, short-term financing 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 with the exception of the additional covenant relating to the $100 million revolving credit facility entered into on April 21, 2009 (discussed above). We are in compliance with these debt covenants at September 30, 2009.

Credit Ratings

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

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

Fitch Ratings	BBB+	A+	Positive	April 2008
Moody’s Investors Service	Baa1	Aa3	Stable	August 2009
Standard & Poor’s Corp.	BBB+	A	Stable	April 2009

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

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

Off-Balance Sheet Arrangements

DPL Inc. - Guarantees

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. 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

Table of Contents

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 nine months ended September 30, 2009, the coal market has experienced unprecedented price volatility. The coal market has increasingly been influenced by both international and domestic supply and consumption and, while we have all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 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 11% of DP&L’s electric revenues for the nine months ended September 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 September 30, 2009, a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power could result in approximately a $7 million increase or decrease to DPL’s annual net income. This includes the impact of a corresponding 10% change in the portion of purchased power used as part of the sale. The share of the internal generation used to meet the wholesale sale would not be affected by the 10% change in wholesale prices.

As of September 30, 2009, a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power, including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale, could result in approximately a $10 million increase or decrease to DP&L’s annual net income.

DPL’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs in the nine months ended September 30, 2009 and 2008 were 50% and 54%, respectively. DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percent of total operating costs were 51% and 55% for the nine-month periods ending September 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 although some contracts provide for periodic pricing adjustments. Substantially all contracts have features that limit price escalations in any given year. We do not expect to purchase SO2 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 the remainder of 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.

Table of Contents

As of September 30, 2009, a hypothetical increase or decrease of 10% in the prices of fuel and purchased power could result in approximately a $30 million increase or decrease to DPL’s annual net income.

As of September 30, 2009, a hypothetical increase or decrease of 10% in the prices of fuel and purchased power could result in approximately a $29 million increase or decrease to DP&L’s annual 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 $1,376.5 million at September 30, 2009, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, DPL’s unsecured notes and revolving credit facilities, and DP&L’s capital lease. The fair value of this debt was $1,348.3 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 $884.3 million at September 30, 2009, consisting of DP&L’s first mortgage bonds, DP&L’s tax-exempt pollution control bonds, DP&L’s revolving credit facilities and DP&L’s capital lease. The fair value of this debt was $846.4 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.

Table of Contents

ELECTRIC SALES AND REVENUES

	DPL Inc.								DP&L (a)
	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
	2009		2008		2009		2008		2009		2008		2009		2008
Electric sales (millions in kWh)
Residential	1,237		1,375		3,862		4,144		1,237		1,375		3,862		4,144
Commercial	961		1,055		2,799		3,001		961		1,055		2,799		3,001
Industrial	909		1,099		2,522		3,062		909		1,099		2,522		3,062
Other retail	353		380		1,049		1,096		353		380		1,049		1,096
Total retail	3,460		3,909		10,232		11,303		3,460		3,909		10,232		11,303

Wholesale	915		343		2,039		1,762		897		305		1,975		1,724

Total	4,375		4,252		12,271		13,065		4,357		4,214		12,207		13,027

Operating revenues ($ in thousands)
Residential	$	143,668	$	139,759	$	419,528	$	409,349	$	143,668	$	139,759	$	419,528	$	409,349
Commercial	86,491		84,402		249,133		249,073		85,420		78,831		247,143		232,240
Industrial	61,218		64,039		172,094		182,246		49,569		36,955		140,559		101,642
Other retail	25,324		25,121		74,290		72,973		20,943		19,949		62,181		59,028
Other miscellaneous revenues	2,135		2,444		6,248		7,193		2,168		2,452		6,346		7,199
Total retail	318,836		315,765		921,293		920,834		301,768		277,946		875,757		809,458

Wholesale	30,951		27,820		81,534		124,745		47,777		61,937		124,728		233,747

RTO revenues	54,547		68,101		171,578		155,123		48,668		61,583		153,248		148,605

Other revenues	3,025		2,810		9,118		8,709		—		—		—		—

Total	$	407,359	$	414,496	$	1,183,523	$	1,209,411	$	398,213	$	401,466	$	1,153,733	$	1,191,810

Electric customers at end of period
Residential	455,318		455,537		455,318		455,537		455,318		455,537		455,318		455,537
Commercial	50,026		50,071		50,026		50,071		50,026		50,071		50,026		50,071
Industrial	1,773		1,806		1,773		1,806		1,773		1,806		1,773		1,806
Other	6,560		6,489		6,560		6,489		6,560		6,489		6,560		6,489

Total	513,677		513,903		513,677		513,903		513,677		513,903		513,677		513,903

(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 (as defined in Rule 13a — 15(e) under the Securities Exchange Act of 1934, as amended). 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 September 30, 2009 that has materially affected, or is reasonably likely to materially affect, internal control over reporting.

Table of Contents

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, including the 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 September 30, 2009, cannot be reasonably determined.

Our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and Quarterly Reports on Form 10-Q for the three months ended March 31, 2009 and June 30, 2009, contain descriptions of certain legal proceedings in which we are or were involved. The information in this Item 1 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 Reports on Form 10-Q for the three months ended March 31, 2009 and June 30, 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. The arbitration panel issued a ruling in Phase 1 of the arbitration on September 25, 2009, finding that most of the claims involving the former executives were covered. Further arbitration proceedings are scheduled to determine the amount of legal and fee expenses (if any) that the insurer must pay. DPL has, in accordance with GAAP, previously recorded these legal expenses totaling $7.5 million to expense but has not recorded any assets for possible recovery of these expenses.

Information concerning the legal proceedings discussed in the REGULATORY UPDATES and ENVIRONMENTAL UPDATES sections of Item 2 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 information presented below amends and restates in its entirety one of those risk factors, and should be read in conjunction with the other risk factors and information disclosed in our most recent Annual Report on Form 10-K. If any of these events occur, our business, financial position or results of operation could be materially affected. The Form 10-K may be obtained as discussed on Page 6 of this report.

Regional Transmission Organizational Risks

On October 1, 2004, in compliance with Ohio law, DP&L turned over control of its transmission functions and fully integrated into PJM. The price at which DPL and DP&L can sell its generation capacity and energy is now more dependent upon the overall operation of the PJM market. While DP&L can continue to make bi-lateral transactions to sell its generation through a willing-buyer and willing-seller relationship, any transactions that are not pre-arranged are subject to market conditions at PJM. The rules governing the various regional power markets also change from time to time which could affect DP&L’s costs and revenues. DP&L incurs fees and costs to participate in the RTO. We may be limited with respect to the price at which power may be sold from certain generating units and we may be required to expand our transmission system according to decisions made by the RTO rather than our internal planning process. While RTO transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place at FERC may cause transmission rates to change from time to time. In addition, developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights may have a financial impact on DP&L. Likewise, in December 2006, FERC approved PJM’s RPM. RPM became effective in 2007 and provides forward and locational pricing for generation capacity.

Table of Contents

While the impact of RPM and other RTO developments on us will depend on a variety of factors, including the market behavior of various participants, our results of operations, financial condition and cash flows could be adversely affected. For example, the PJM RPM base residual auction for the 2012/13 period cleared at a per megawatt price of $16/day for our RTO area. Prior to this auction, the per megawatt price for the 2011/2012 period was $110/day. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for Demand Response and Energy Efficiency resources in the RPM auctions. We cannot predict the outcome of future auctions but if the current auction price is sustained, our future results of operations, financial condition and cash flows could be adversely impacted.

SB 221 includes a provision that allows electric utilities to seek and obtain deferral and recovery of RTO related charges. If in the future, however, we are unable to defer or recover all of these costs, it could have a material adverse effect on us.

As a member of PJM, DP&L and DPLE are subject to certain additional risks including those associated with the allocation among PJM members of losses caused by unreimbursed defaults of other participants in PJM markets and those associated with complaint cases filed against PJM that may seek refunds of revenues previously earned by PJM members including DP&L and DPLE.

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

None

Item 3 — Defaults Upon Senior Securities

None

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

None

Item 5 — Other Information

None

Table of Contents

Item 6 — Exhibits

DPL Inc.	DP&L	Number	Exhibit	Location
X		10(a)*	Form of DPL Inc. Restricted Stock Agreement	Exhibit 10(d) to Form 10-Q filed July 30, 2009 (File No. 1-9052)

X		10(b)*	Form of DPL Inc. 2009 Career Grant and Matching Restricted Stock Agreement	Filed herewith as Exhibit 10(b)

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

Table of Contents

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:	October 28, 2009	/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)


	October 28, 2009	/s/ Frederick J. Boyle
		Frederick J. Boyle
		Senior Vice President, Chief Financial Officer and Treasurer
		(principal financial officer)


	October 28, 2009	/s/ Joseph W. Mulpas
		Joseph W. Mulpas
		Vice President, Controller and Chief Accounting Officer
		(principal accounting officer)