10-Q 1 a10-17259_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

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, 2010

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

For the transition period from to

		I.R.S.
		Employer
Commission	Registrant, State of Incorporation,	Identification
File Number	Address and Telephone Number	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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

Indicate by check mark 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 26, 2010, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, $0.01 par value	118,943,392

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

This combined Form 10-Q is separately filed by DPL Inc. and The Dayton Power and Light Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

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DPL Inc. and The Dayton Power and Light Company

Index

		Page No.
Glossary of Terms		3

Part I Financial Information

Item 1	Financial Statements — DPL and DP&L

	Condensed Consolidated Statements of Results of Operations — DPL	6

	Condensed Consolidated Statements of Cash Flows — DPL	7

	Condensed Consolidated Balance Sheets — DPL	8

	Condensed Statements of Results of Operations — DP&L	10

	Condensed Statements of Cash Flows — DP&L	11

	Condensed Balance Sheets — DP&L	12

	Notes to Condensed Consolidated Financial Statements	14

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

	Electric Sales and Revenues	84

Item 3	Quantitative and Qualitative Disclosures about Market Risk	84

Item 4	Controls and Procedures	85

Part II Other Information

Item 1	Legal Proceedings	85

Item 1A	Risk Factors	86

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	86

Item 3	Defaults Upon Senior Securities	86

Item 4	Removed and Reserved	86

Item 5	Other Information	86

Item 6	Exhibits	87

Other

Signatures		88

Certifications		90

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GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition
AMI		Advanced Metering Infrastructure
AOCI		Accumulated Other Comprehensive Income
ARO		Asset Retirement Obligation
ASU		Accounting Standards Update
BTU		British Thermal Units
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CG&E		The Cincinnati Gas & Electric Company, a subsidiary of Duke Energy-Ohio
CSP		Columbus Southern Power, a subsidiary of AEP
CO2		Carbon Dioxide
CCEM		Customer Conservation and Energy Management
CRES		Competitive Retail Electric Service
DPL		DPL Inc., the parent company
DPLE		DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales
DPLER		DPL Energy Resources, Inc., a wholly-owned subsidiary of DPL that sells retail electric energy and other energy services
DP&L		The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility that sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio
DSM		Demand-Side Management, a program under which customers typically receive a discount, rebate or other form of incentive in return for agreeing to reduce their electricity consumption upon request by the utility
Dth		Decatherm, the unit of measure for natural gas (1,000,000 BTU)
EIR		Environmental Investment Rider
EPS		Earnings Per Share
ESOP		Employee Stock Ownership Plan
ESP		Electric Security Plans, filed with the PUCO pursuant to Ohio law
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
FGD		Flue Gas Desulfurization
FTRs		Financial Transmission Rights
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
kWh		Kilowatt hours
LOC		Letter of Credit
MTM		Mark to Market
MVIC		Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries
MWh		Megawatt hours
NERC		North American Electric Reliability Corporation
NOV		Notice of Violation

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Abbreviation or Acronym		Definition
NOx		Nitrogen Oxide
NYMEX		New York Mercantile Exchange
OAQDA		Ohio Air Quality Development Authority
Ohio EPA		Ohio Environmental Protection Agency
OTC		Over-The-Counter
OVEC		Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest
PJM		PJM Interconnection, L.L.C., a regional transmission organization
PRP		Potentially Responsible Party
PUCO		Public Utilities Commission of Ohio
RSU		Restricted Stock Units
RTO		Regional Transmission Organization
RPM		Reliability Pricing Model
SB 221		Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an electric security plan or a market rate option to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards.
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission
SECA		Seams Elimination Charge Adjustment
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur Dioxide
Stipulation		A Stipulation and Recommendation filed by DP&L with the PUCO on February 24, 2009 regarding DP&L’s ESP filing pursuant to SB 221. The Stipulation was signed by the Staff of the PUCO, the Office of the Ohio Consumers’ Counsel and various intervening parties. The PUCO approved the Stipulation on June 24, 2009.
TCRR		Transmission Cost Recovery Rider
USEPA		U.S. Environmental Protection Agency
USF		Universal Service Fund
VRDN		Variable Rate Demand Note

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

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

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

Forward-looking Statements: Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Please see page 53 for more information about forward-looking statements contained in this report.

Part 1 — Financial Information

This report includes the combined filing of DPL and DP&L. DP&L is the principal subsidiary of DPL providing approximately 95% of DPL’s total consolidated revenue and approximately 94% of DPL’s total consolidated asset base. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

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Item 1 — Financial Statements

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions except per share amounts	2010			2009			2010			2009

Revenues	$	516.9		$	407.3		$	1,413.6		$	1,183.5

Cost of revenues:
Fuel	104.3			84.4			297.1			241.7
Purchased power	119.0			65.0			282.7			188.0
Total cost of revenues	223.3			149.4			579.8			429.7

Gross margin	293.6			257.9			833.8			753.8

Operating expenses:
Operation and maintenance	84.2			75.1			252.3			230.8
Depreciation and amortization	32.2			36.1			105.3			107.8
General taxes	32.6			30.2			96.3			89.8
Total operating expenses	149.0			141.4			453.9			428.4

Operating income	144.6			116.5			379.9			325.4

Other income / (expense), net:
Investment income	0.3			0.1			0.6			0.7
Interest expense	(17.6		)	(19.6		)	(53.0		)	(60.7		)
Other income / (deductions)	(0.5		)	(0.9		)	(1.8		)	(2.0		)
Total other income / (expense), net	(17.8		)	(20.4		)	(54.2		)	(62.0		)

Earnings before income tax	126.8			96.1			325.7			263.4

Income tax expense	40.4			28.2			106.9			84.2
Net income	$	86.4		$	67.9		$	218.8		$	179.2

Average number of common shares outstanding (millions):
Basic	115.8			112.4			115.7			112.2
Diluted	116.3			114.4			116.2			113.4

Earnings per share of common stock:
Basic	$	0.75		$	0.60		$	1.89		$	1.60
Diluted	$	0.74		$	0.59		$	1.88		$	1.58

Dividends paid per share of common stock	$	0.3025		$	0.2850		$	0.9075		$	0.8550

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2010			2009
Cash flows from operating activities:
Net income	$	218.8		$	179.2
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	105.3			107.8
Deferred income taxes	38.7			205.5
Unamortized investment tax credit	(2.1		)	(2.1		)
Changes in certain assets and liabilities:
Accounts receivable	7.9			(32.9		)
Inventories	10.6			(22.9		)
Prepaid taxes	(0.9		)	(33.0		)
Taxes applicable to subsequent years	44.2			43.9
Deferred regulatory costs, net	7.0			(30.0		)
Accounts payable	(4.7		)	(66.7		)
Accrued taxes payable	(58.1		)	(63.4		)
Accrued interest payable	(5.6		)	(6.5		)
Pension, retiree and other benefits	(54.6		)	6.4
Insurance and claims costs	(0.3		)	(2.5		)
Other	25.4			7.7
Net cash provided by operating activities	331.6			290.5

Cash flows from investing activities:
Capital expenditures	(113.7		)	(134.6		)
Purchases of short-term investments and securities	(62.7		)	(10.1		)
Sales of short-term investments and securities	14.4			15.1
Other	1.7			2.9
Net cash used for investing activities	(160.3		)	(126.7		)

Cash flows from financing activities:
Dividends paid on common stock	(104.8		)	(95.7		)
Repurchase of warrants	—			(15.9		)
Retirement of long-term debt	—			(175.0		)
Withdrawal of restricted funds held in trust	—			6.7
Withdrawals from revolving credit facilities	—			260.0
Repayment of borrowings from revolving credit facilities	—			(145.0		)
Repurchase of DPL common stock	(3.9		)	—
Exercise of stock options	1.4			1.3
Tax impact related to exercise of stock options	0.2			0.1
Net cash used for financing activities	(107.1		)	(163.5		)

Cash and cash equivalents:
Net change	64.2			0.3
Balance at beginning of period	74.9			62.5
Cash and cash equivalents at end of period	$	139.1		$	62.8

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	59.6		$	67.1
Income taxes paid / (refunded), net	$	60.8		$	(4.8	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	14.1		$	9.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2010			2009

ASSETS

Current assets:
Cash and cash equivalents	$	139.1		$	74.9
Short-term investments	48.3			—
Accounts receivable, net (Note 2)	208.6			212.8
Inventories (Note 2)	115.1			125.7
Taxes applicable to subsequent years	15.3			59.5
Other prepayments and current assets	34.1			24.1
Total current assets	560.5			497.0

Property, plant and equipment:
Property, plant and equipment	5,333.2			5,269.2
Less: Accumulated depreciation and amortization	(2,532.2		)	(2,466.0		)
	2,801.0			2,803.2

Construction work in process	101.5			89.0
Total net property, plant and equipment	2,902.5			2,892.2

Other noncurrent assets:
Regulatory assets (Note 3)	200.5			214.2
Other deferred assets	44.2			38.3
Total other noncurrent assets	244.7			252.5

Total Assets	$	3,707.7		$	3,641.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At		At
	September 30,		December 31,
$ in millions	2010		2009

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Current portion - long-term debt (Note 5)	$	397.4	$	100.6
Accounts payable	69.5		77.2
Accrued taxes	70.9		70.2
Accrued interest	18.3		23.5
Customer security deposits	18.3		19.4
Other current liabilities	56.3		24.0
Total current liabilities	630.7		314.9

Noncurrent liabilities:
Long-term debt (Note 5)	926.4		1,223.5
Deferred taxes	600.4		569.1
Regulatory liabilities (Note 3)	131.6		125.4
Pension, retiree and other benefits	65.1		111.7
Unamortized investment tax credit	33.1		35.2
Insurance and claims costs	16.0		16.2
Other deferred credits	71.7		122.9
Total noncurrent liabilities	1,844.3		2,204.0

Redeemable preferred stock of subsidiary	22.9		22.9

Commitments and contingencies (Note 14)

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

	September 2010	December 2009
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	118,943,392	118,966,767	1.2			1.2
Warrants			2.9			2.9
Common stock held by employee plans			(14.2		)	(19.3		)
Accumulated other comprehensive loss			(40.1		)	(29.0		)
Retained earnings			1,260.0			1,144.1
Total common shareholders’ equity			1,209.8			1,099.9

Total Liabilities and Shareholders’ Equity			$	3,707.7		$	3,641.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2010			2009			2010			2009

Revenues	$	487.0		$	398.2		$	1,348.9		$	1,153.7

Cost of revenues:
Fuel	97.4			83.0			286.5			236.2
Purchased power	116.4			64.7			279.3			187.1
Total cost of revenues	213.8			147.7			565.8			423.3

Gross margin	273.2			250.5			783.1			730.4

Operating expenses:
Operation and maintenance	78.7			71.5			243.4			222.0
Depreciation and amortization	30.4			33.6			98.4			100.2
General taxes	32.2			30.2			94.0			89.3
Total operating expenses	141.3			135.3			435.8			411.5

Operating income	131.9			115.2			347.3			318.9

Other income / (expense), net:
Investment income	0.4			0.4			1.3			2.4
Interest expense	(9.4		)	(10.2		)	(27.9		)	(28.9		)
Other income / (deductions)	(0.3		)	(0.9		)	(1.4		)	(1.8		)
Total other income / (expense), net	(9.3		)	(10.7		)	(28.0		)	(28.3		)

Earnings before income tax	122.6			104.5			319.3			290.6

Income tax expense	39.4			30.5			104.6			92.8

Net income	83.2			74.0			214.7			197.8

Dividends on preferred stock	0.2			0.2			0.6			0.6

Earnings on common stock	$	83.0		$	73.8		$	214.1		$	197.2

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2010			2009
Cash flows from operating activities:
Net income	$	214.7		$	197.8
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	98.4			100.2
Deferred income taxes	36.9			204.7
Unamortized investment tax credit	(2.1		)	(2.1		)
Changes in certain assets and liabilities:
Accounts receivable	27.5			(56.7		)
Inventories	10.3			(22.8		)
Prepaid taxes	(0.9		)	(36.7		)
Taxes applicable to subsequent years	44.0			43.8
Deferred regulatory costs, net	7.0			(30.0		)
Accounts payable	(6.1		)	(66.0		)
Accrued taxes payable	(55.6		)	(60.3		)
Accrued interest payable	2.2			2.5
Pension, retiree and other benefits	(54.6		)	6.4
Other	16.3			(3.8		)
Net cash provided by operating activities	338.0			277.0

Cash flows from investing activities:
Capital expenditures	(112.3		)	(129.9		)
Other	1.7			1.7
Net cash used for investing activities	(110.6		)	(128.2		)

Cash flows from financing activities:
Dividends paid on common stock to parent	(150.0		)	(270.0		)
Dividends paid on preferred stock	(0.6		)	(0.6		)
Withdrawal of restricted funds held in trust	—			6.7
Repayment of borrowings from revolving credit facility	—			(145.0		)
Withdrawals from revolving credit facility	—			260.0
Net cash used for financing activities	(150.6		)	(148.9		)

Cash and cash equivalents:
Net change	76.8			(0.1		)
Balance at beginning of period	57.1			20.8
Cash and cash equivalents at end of period	$	133.9		$	20.7

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	27.6		$	27.3
Income taxes paid / (refunded), net	$	60.7		$	(4.9	)
Non-cash financing and investing activities:
Accruals for capital expenditures	$	14.1		$	9.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2010			2009

ASSETS

Current assets:
Cash and cash equivalents	$	133.9		$	57.1
Accounts receivable, net (Note 2)	168.2			192.0
Inventories (Note 2)	114.0			124.3
Taxes applicable to subsequent years	15.2			59.2
Other prepayments and current assets	36.2			26.0
Total current assets	467.5			458.6

Property, plant and equipment:
Property, plant and equipment	5,073.7			5,011.0
Less: Accumulated depreciation and amortization	(2,431.3		)	(2,370.7		)
	2,642.4			2,640.3

Construction work in process	101.6			87.9
Total net property, plant and equipment	2,744.0			2,728.2

Other noncurrent assets:
Regulatory assets (Note 3)	200.5			214.2
Other deferred assets	61.9			56.4
Total other noncurrent assets	262.4			270.6

Total Assets	$	3,473.9		$	3,457.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2010			2009

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:
Current portion - long-term debt (Note 5)	$	100.0		$	100.6
Accounts payable	66.0			75.1
Accrued taxes	71.5			68.6
Accrued interest	15.6			13.1
Customer security deposits	18.3			19.4
Other current liabilities	35.7			23.2
Total current liabilities	307.1			300.0

Noncurrent liabilities:
Long-term debt (Note 5)	783.8			783.7
Deferred taxes	588.8			553.0
Regulatory liabilities (Note 3)	131.6			125.4
Pension, retiree and other benefits	65.1			111.7
Unamortized investment tax credit	33.1			35.2
Other deferred credits	72.0			122.9
Total noncurrent liabilities	1,674.4			1,731.9

Redeemable preferred stock	22.9			22.9

Commitments and contingencies (Note 14)

Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	782.1			781.6
Accumulated other comprehensive loss	(17.3		)	(19.7		)
Retained earnings	704.3			640.3
Total common shareholder’s equity	1,469.5			1,402.6

Total Liabilities and Shareholder’s Equity	$	3,473.9		$	3,457.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

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

1. Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s principal subsidiary is DP&L. DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in generation, transmission, distribution and the sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.

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

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity; DPLER, which is a CRES provider selling retail electric energy and other energy services; and MVIC, our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s subsidiaries are wholly-owned.

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

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

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is not subject to such regulation. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries have 1,499 employees as of September 30, 2010, 1,492 of which are employed by DP&L. Approximately 54% of the employees are under a collective bargaining agreement which expires in October 2011.

Financial Statement Presentation

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

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

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

All material intercompany accounts and transactions are eliminated in consolidation.

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

In the opinion of our management, the financial statements presented in this report contain all adjustments necessary to fairly state our financial condition as of September 30, 2010; our results of operations for the three and nine months ended September 30, 2010; and our cash flows for the nine months ended September 30, 2010. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to various factors, including but not limited to, seasonal weather variations, the timing of outages of electric generating units, changes in economic conditions involving commodity prices and competition, and other factors, interim results for the three and nine months ended September 30, 2010 may not be indicative of our results that will be realized for the full year ending December 31, 2010.

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

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. Capitalization of AFUDC ceases at either project completion or at the date specified by regulators. AFUDC capitalized during the three and nine month periods ended September 30, 2010 and 2009 was not material.

For unregulated generation property, cost includes direct labor and material, allocable overhead expenses and interest capitalized during construction using the provisions of GAAP relating to the accounting for capitalized interest.

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

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

At September 30, 2010, neither DPL nor DP&L had any material plant acquisition adjustments or other plant-related adjustments.

Depreciation Study — Change in Estimate

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation study concluded that many of DPL’s composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated. DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the three months ended September 30, 2010, the net reduction in depreciation expense amounted to $2.4 million ($1.6 million net of tax) and increased diluted EPS by approximately $0.01 per share. Each future quarter is expected to be equally impacted such that on an annualized basis, the net reduction in depreciation expense is projected to increase operating income by approximately $9.6 million ($6.4 million net of tax) or approximately $0.06 per diluted share.

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Short-Term Investments

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

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

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

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

Three Months Ended

Nine Months Ended

September 30,

$ in millions

2010

2009

2010

2009

State/Local excise taxes

14.6

12.8

40.1

38.0

Related Party Transactions

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2010			2009			2010			2009

DP&L Revenues:
Sales to DPLER (a)	$	75.8		$	17.8		$	165.9		$	47.7

DP&L Operation & Maintenance Expenses:
Insurance services provided by MVIC (b)	$	0.8		$	0.8		$	2.5		$	2.5
Expense recoveries for services provided to DPLER (c)	$	(1.6	)	$	(0.3	)	$	(4.0	)	$	(0.8	)

(a) DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenues associated with sales to DPLER are recorded as wholesale sales in DP&L’s Condensed Financial Statements. The increase in DP&L’s sales to DPLER during the three and nine months ended September 30, 2010 compared to the same period in 2009 is primarily due to customers electing to switch their generation service from DP&L to DPLER.

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

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

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Recently Adopted Accounting Standards

Variable Interest Entities

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

Fair Value Disclosures

We adopted ASU 2010-06 “Fair Value Measurements and Disclosures” (ASU 2010-06) effective for annual reporting periods beginning after December 15, 2009. This standard updates FASC Topic 820 “Fair Value Measurements and Disclosures.” ASU 2010-06 requires additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and a higher level of disaggregation for the different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements are presented separately. ASU 2010-06 did not have a material impact on our overall results of operations, financial position or cash flows. See Note 8 of Notes to Condensed Consolidated Financial Statements.

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2. Supplemental Financial Information and Comprehensive Income

DPL Inc.

	At			At
	September 30,			December 31,
$ in millions	2010			2009

Accounts receivable, net:
Unbilled revenue	$	64.4		$	74.9
Customer receivables	124.3			99.4
Amounts due from partners in jointly-owned plants	9.8			12.6
Coal sales	5.7			10.6
Income tax receivable	—			10.2
Other	5.3			6.2
Provision for uncollectible accounts	(0.9		)	(1.1		)
Total accounts receivable, net	$	208.6		$	212.8

Inventories, at average cost:
Fuel, limestone and emission allowances	$	72.1		$	85.8
Plant materials and supplies	39.7			38.5
Other	3.3			1.4
Total inventories, at average cost	$	115.1		$	125.7

DP&L

	At			At
	September 30,			December 31,
$ in millions	2010			2009

Accounts receivable, net:
Unbilled revenue	$	46.9		$	71.0
Customer receivables	103.6			94.4
Amounts due from partners in jointly-owned plants	9.8			12.6
Coal sales	5.7			10.6
Other	3.1			4.5
Provision for uncollectible accounts	(0.9		)	(1.1		)
Total accounts receivable, net	$	168.2		$	192.0

Inventories, at average cost:
Fuel, limestone and emission allowances	$	72.2		$	85.8
Plant materials and supplies	38.6			37.1
Other	3.2			1.4
Total inventories, at average cost	$	114.0		$	124.3

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Supplemental Financial Information and Comprehensive Income (continued)

Comprehensive income for the three months ended September 30, 2010 and 2009 was as follows:

DPL Inc.

	Three Months Ended
	September 30,
$ in millions	2010			2009
Comprehensive income:
Net income	$	86.4		$	67.9
Net change in unrealized gains (losses) on financial instruments, net of income tax expense of $0.2 million and $0.1 million, respectively	0.3			0.4
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $3.7 million and income tax expense of $0.1 million, respectively	(9.1		)	(0.1		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.4 million and $0.4 million, respectively	0.8			0.4
Comprehensive income	$	78.4		$	68.6

DP&L

	Three Months Ended
	September 30,
$ in millions	2010			2009
Comprehensive income:
Net income	$	83.2		$	74.0
Net change in unrealized gains (losses) on financial instruments, net of income tax expense of $0.9 million and $1.1 million, respectively	1.8			2.4
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense of $0.2 million and $0.1 million, respectively	(0.2		)	(0.1		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.4 million and $0.4 million, respectively	0.8			0.4
Comprehensive income	$	85.6		$	76.7

Comprehensive income for the nine months ended September 30, 2010 and 2009 was as follows:

DPL Inc.

	Nine Months Ended
	September 30,
$ in millions	2010			2009
Comprehensive income:
Net income	$	218.8		$	179.2
Net change in unrealized gains (losses) on financial instruments, net of income tax expense of $0.1 million and $0.1 million, respectively	0.2			0.6
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $6.0 million and income tax expense of $1.0 million, respectively	(14.7		)	0.2
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.3 million and $1.0 million, respectively	3.4			1.4
Comprehensive income	$	207.7		$	181.4

DP&L

	Nine Months Ended
	September 30,
$ in millions	2010			2009
Comprehensive income:
Net income	$	214.7		$	197.8
Net change in unrealized gains (losses) on financial instruments, net of income tax benefits of $0.5 million and income tax expense of $0.8 million, respectively	(0.9		)	1.8
Net change in deferred gains (losses) on cash flow hedges, net of income tax expenses of $1.0 million and $1.0 million, respectively	(0.1		)	0.2
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.3 million and $1.0 million, respectively	3.4			1.4
Comprehensive income	$	217.1		$	201.2

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3. Regulatory Matters

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

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

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

			At		At
	Type of	Amortization	September 30,		December 31,
$ in millions	Recovery (a)	Through	2010		2009
Regulatory Assets:
Deferred recoverable income taxes	B/C	Ongoing	$	35.3	$	36.8
Pension benefits	C	Ongoing	81.0		85.2
Unamortized loss on reacquired debt	C	Ongoing	14.6		15.6
Electric Choice systems costs	F	2011	1.6		4.0
Regional transmission organization costs	D	2014	5.9		7.0
TCRR, transmission, ancillary and other PJM-related costs	F	2011	13.1		5.5
RPM capacity costs	F	2011	5.0		20.0
Deferred storm costs - 2008	D		16.7		16.0
Power plant emission fees	C	Ongoing	6.2		6.3
CCEM smart grid and advanced metering infrastructure costs	D		6.6		6.5
CCEM energy efficiency program costs	F	Ongoing	3.5		3.6
Fuel and purchased power recovery costs	C	Ongoing	3.2		—
Other costs			7.8		7.7
Total regulatory assets			$	200.5	$	214.2

Regulatory Liabilities:
Estimated costs of removal - regulated property			$	106.5	$	99.1
SECA net revenue subject to refund			19.4		20.1
Postretirement benefits			4.7		5.1
Other costs			1.0		1.1
Total regulatory liabilities			$	131.6	$	125.4

(a) B — Balance has an offsetting liability resulting in no impact on rate base.

C — Recovery of incurred costs without a rate of return.

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

F — Recovery of incurred costs plus rate of return.

Regulatory Assets

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

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

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

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

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

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

RPM capacity costs represent the PJM-related costs from the calculations of the PJM RPM that allocates capacity among the users of the PJM system. We review this rate and make true-up adjustments on an annual basis.

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

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

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. Consistent with the Stipulation, DP&L re-filed its smart grid and AMI business cases with the PUCO on August 4, 2009 seeking recovery of costs associated with a 10-year plan to deploy smart meters, distribution and substation automation, core telecommunications, supporting software and in-home technologies. On October 19, 2010, DP&L elected to withdraw the re-filed case pertaining to the Smart Grid and AMI and to monitor other utilities’ Smart Grid and AMI programs. We plan to file to recover these deferred costs in future regulatory rate proceedings. Based on past PUCO precedent, we believe these costs are probable of future recovery in rates.

CCEM energy efficiency program costs represent costs incurred to develop and implement various new customer programs addressing energy efficiency. A portion of these costs is being recovered over three years as part of the Stipulation beginning July 1, 2009. The remaining costs are being collected through a two-year rate, beginning July 1, 2009, that is trued-up for any over/under recovery of costs.

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, emission and other related costs which will be recovered from customers in the future through the operation of the fuel and purchased power recovery rider. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel rider on January 1, 2010. DP&L has not yet been subject to an audit of its fuel rider and, as a result, there is some uncertainty as to the costs that will be approved for recovery. The fuel audit is conducted by independent third parties in accordance with the PUCO standards. DP&L anticipates that some of this uncertainty will be resolved during the first half of 2011 after completion of the fuel audit. Based on past PUCO precedent, we believe these deferred costs are probable of future recovery.

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

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Regulatory Liabilities

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

SECA net revenue subject to refund represents our deferral of revenues and costs that were billed to PJM transmission customers and paid to transmission owners during 2005 and 2006, but which remain subject to litigation before the FERC and potential reversal. DP&L is both a transmission customer and a transmission owner. SECA revenue and expenses represent FERC-ordered transitional payments for the use of transmission lines within PJM. We began receiving and paying these transitional payments in May 2005, subject to refund. Since 2005, a large number of settlements have been entered into among various market participants including DP&L. An initial decision by an Administrative Law Judge was issued in 2006 to address unsettled claims, which was appealed by many parties to the FERC. On May 21, 2010, the FERC issued an Order that affirmed some aspects of the initial decision and reversed other aspects. Overall, the FERC Order is favorable to the positions taken by DP&L with respect to its unsettled and outstanding claims. DP&L filed for rehearing on those aspects of the FERC Order that were not favorable. Other parties adverse to DP&L’s interests also filed for rehearing with respect to aspects of the FERC Order that DP&L supports. The eventual outcome of this litigation is uncertain.

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

4. Ownership of Coal-fired Facilities

DP&L with certain other Ohio utilities has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials, operating supplies and capital additions are allocated to the owners in accordance with their respective ownership interests. As of September 30, 2010, we had $42 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

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DP&L’s undivided ownership interests in such facilities as well as in our wholly-owned coal fired Hutchings plant at September 30, 2010, are as follows:

	DP&L Share		DP&L Investment
									SCR and FGD
									Equipment
							Construction		Installed
		Production	Gross Plant		Accumulated		Work in		and In
	Ownership	Capacity	In Service		Depreciation		Process		Service
	(%)	(MW)	($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	210	$	75	$	51	$	1	No
Conesville Unit 4	16.5	129	118		26		4		Yes
East Bend Station	31.0	186	200		131		—		Yes
Killen Station	67.0	402	609		286		3		Yes
Miami Fort Units 7 and 8	36.0	368	350		130		6		Yes
Stuart Station	35.0	820	696		261		17		Yes
Zimmer Station	28.1	365	1,058		608		11		Yes
Transmission (at varying percentages)			91		55		—
Total		2,480	$	3,197	$	1,548	$	42

Wholly-owned production unit:
Hutchings Station	100.0	388	$	123	$	110	$	2	No

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

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5. Debt Obligations

Long-term Debt

	At			At
	September 30,			December 31,
$ in millions	2010			2009
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%	35.3			35.3
Pollution control series maturing in January 2034 - 4.80%	179.1			179.1
Pollution control series maturing in September 2036 - 4.80%	100.0			100.0
	784.4			784.4

Obligation for capital lease	—			—
Unamortized debt discount	(0.6		)	(0.7		)
Total long-term debt - DP&L	$	783.8		$	783.7

DPL
Senior notes maturing in September 2011 - 6.875%	—			297.4
Note to DPL Capital Trust II maturing in September 2031 - 8.125%	142.6			142.6
Unamortized debt discount	—			(0.2		)
Total long-term debt - DPL	$	926.4		$	1,223.5

Current portion - Long-term Debt

	At		At
	September 30,		December 31,
$ in millions	2010		2009
DP&L
Pollution control series maturing in November 2040 - variable rates: 0.16% - 0.35% and 0.24% - 0.85% (a) (b)	$	100.0	$	100.0
Obligation for capital lease	—		0.6
Total current portion - long-term debt - DP&L	$	100.0	$	100.6

DPL
Senior notes maturing in September 2011 - 6.875%	297.4		—
Total current portion - long-term debt - DPL	$	397.4	$	100.6

(a)	Range of interest rates for the nine months ended September 30, 2010 and the twelve months ended December 31, 2009, respectively.
(b)	Shown as current since related LOC facility will expire in December 2010, at which point the bonds are subject to mandatory purchase. Management is currently in negotiations with a lender to extend this LOC facility before it expires.

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At September 30, 2010, maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions	DPL		DP&L
Due within one year (a)	$	397.4	$	100.0
Due within two years	—		—
Due within three years	—		—
Due within four years	470.0		470.0
Due within five years	—		—
Thereafter	457.0		314.4
	$	1,324.4	$	884.4

(a)

$100 million variable rate pollution control series note maturing in 2040 is shown as current since the related LOC facility will expire in December 2010, at which point the applicable bonds are subject to mandatory purchase. Management is currently in negotiations with a lender to extend the LOC facility before it expires.

Debt

On November 21, 2006, DP&L entered into a $220 million unsecured revolving credit agreement. This agreement has a five-year term that expires on November 21, 2011 and provides DP&L with the ability to increase the size of the facility by an additional $50 million at any time. DP&L had no outstanding borrowings under this credit facility at September 30, 2010. Fees associated with this credit facility were approximately $0.4 million and $0.8 million during the three and nine months ended September 30, 2010, respectively. Changes in DP&L’s credit ratings may affect fees and the applicable interest rate. This revolving credit agreement contains a $50 million letter of credit sublimit. As of September 30, 2010, DP&L had no outstanding letters of credit against the facility.

On December 4, 2008, the OAQDA issued $100 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby LOC issued by a syndicated bank group. This LOC facility, which is for an initial two-year period expiring in December 2010, is irrevocable and has no subjective acceleration clauses. Since the LOC facility will expire in December 2010, at which point the bonds are subject to mandatory purchase, we have reflected our obligations as a current liability. DP&L is currently in negotiations with a lender to extend the LOC facility before it expires.

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

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

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

On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. DP&L had no outstanding borrowings under this credit facility at September 30, 2010. Fees associated with this credit facility were approximately $0.3 million during the period between April 20, 2010 and September 30, 2010. This facility also contains a $50 million letter of credit sublimit. As of September 30, 2010, DP&L had no outstanding letters of credit against the facility.

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

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6. Taxes

The following table details the effective income tax rates for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

DPL	31.9	%	29.3	%	32.8	%	32.0	%

DP&L	32.1	%	29.2	%	32.8	%	31.9	%

Income tax expense for both DPL and DP&L for the three and nine months ended September 30, 2010 and 2009 reflects estimated annual effective income tax rates of 32.6% and 32.5%, respectively. Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates recognized.

For the three months and nine months ended September 30, 2010, the increase in DPL’s and DP&L’s effective tax rate compared to the same periods in 2009 primarily reflects the benefits recorded in 2009 for the Internal Revenue Code Section 199 Domestic Production Deduction and the phase-out of the Ohio Franchise Tax partially offset by a current quarter Domestic Production Deduction benefit due to a longer net operating loss carryback period.

Deferred tax liabilities for both DPL and DP&L increased approximately $31.6 million and $36.0 million, respectively, for the nine months ended September 30, 2010. The increases were related to estimate-to-actual adjustments for pension contributions, depreciation expense and repair expense and other temporary differences arising from routine changes in balance sheet accounts giving rise to deferred taxes.

The Internal Revenue Service began an examination of our 2008 Federal income tax return during the second quarter of 2010 and has continued through the current quarter. At this time, we do not expect the results of this examination to have a material impact on our financial statements.

On June 21, 2010, Ohio Senate Bill 232 was enacted. This legislation eliminates Ohio’s tangible personal property tax and real property taxes on generation for renewable and advanced energy project facilities that begin construction before January 1, 2012, produce energy by 2013 (or 2017 for nuclear, clean coal and cogeneration projects) and create Ohio jobs. Rules containing implementation provisions were proposed on September 29, 2010. We are currently evaluating the impact this law and related rules will have on both DPL’s and DP&L’s financial condition, results of operations and cash flows as a result of constructing the solar energy facility at Yankee Station and any future construction of similar facilities.

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7. Pension and Postretirement Benefits

DP&L sponsors a defined benefit plan for substantially all employees. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees, the defined benefit plan is based primarily on compensation and years of service. We generally fund pension plan benefits as accrued in accordance with the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and, in addition, make voluntary contributions from time to time. In February 2010, DP&L contributed $20.0 million to the defined benefit plan. In September 2010, DP&L contributed an additional $20.0 million to the defined benefit plan. In addition, we have a Supplemental Executive Retirement Plan (SERP) for certain active and retired key executives. Benefits under this SERP have been frozen and no additional benefits can be earned. We also have unfunded liabilities related to retirement benefits for certain active, terminated and retired key executives.

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

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

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months ended September 30, 2010 and 2009 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
$ in millions	2010			2009			2010			2009
Service cost	$	1.0		$	0.9		$	0.1		$	—
Interest cost	4.5			4.5			0.3			0.4
Expected return on assets (a)	(5.6		)	(5.6		)	—			(0.1		)
Amortization of unrecognized:
Actuarial (gain) / loss	2.0			1.1			(0.2		)	(0.2		)
Prior service cost	0.9			0.9			—			—
Net periodic benefit cost / (income) before adjustments	$	2.8		$	1.8		$	0.2		$	0.1

(a)

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

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the nine months ended September 30, 2010 and 2009 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
$ in millions	2010			2009			2010			2009
Service cost	$	3.2		$	2.7		$	0.1		$	—
Interest cost	13.5			13.3			1.0			1.3
Expected return on assets (a)	(16.8		)	(16.8		)	(0.2		)	(0.3		)
Amortization of unrecognized:
Actuarial (gain) / loss	5.6			3.3			(0.6		)	(0.6		)
Prior service cost	2.8			2.6			0.1			—
Net periodic benefit cost / (income) before adjustments	$	8.3		$	5.1		$	0.4		$	0.4

(a)

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The chart below presents the estimated future pension and postretirement benefit payments to be made over the next ten years.

Estimated Future Benefit Payments

$ in millions	Pension		Postretirement

2010	$	5.3	$	0.6
2011	$	21.6	$	2.5
2012	$	22.4	$	2.4
2013	$	23.1	$	2.3
2014	$	23.6	$	2.1
2015 - 2019	$	121.6	$	8.4

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The fair value of our financial instruments represents estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at September 30, 2010 and December 31, 2009. See also Note 9 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.

	At September 30,				At December 31,
	2010				2009
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities	3.5		3.8		2.6		2.8
Debt Securities	5.3		5.6		5.3		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.2
Total Master Trust Assets	$	10.7	$	11.3	$	12.3	$	12.6

Short-term Investments - VRDNs	$	33.0	$	33.0	$	—	$	—
Short-term Investments - Bonds	15.3		15.3		—		—
Total Short-term Investments	$	48.3	$	48.3	$	—	$	—

Total Assets	$	59.0	$	59.6	$	12.3	$	12.6

Liabilities
Debt	$	1,323.8	$	1,346.7	$	1,324.1	$	1,317.6

DP&L
Assets
Money Market Funds	$	1.6	$	1.6	$	4.1	$	4.1
Equity Securities (a)	17.2		30.0		16.7		31.1
Debt Securities	5.3		5.6		5.3		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.2
Total Master Trust Assets	$	24.4	$	37.5	$	26.4	$	40.9

Liabilities
Debt	$	883.8	$	881.0	$	884.3	$	844.5

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

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Debt

The fair value of debt is based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the financial statements as debt is presented at amortized cost in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2040.

Master Trust Assets

DP&L established a Master Trust to hold assets for the benefit of employees participating in employee benefit plans and these assets are not used for general operating purposes. These assets are primarily comprised of open-ended mutual funds and DPL common stock. The DPL common stock held by the DP&L Master Trust is eliminated in consolidation and is not reflected in DPL’s Condensed Consolidated Balance Sheets. The DPL common stock is valued using current public market prices, while the open-ended mutual funds are valued using the net asset value per unit. Any unrealized gains or losses are recognized in AOCI until the securities are sold.

DPL had $0.7 million ($0.5 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at September 30, 2010 and $0.3 million ($0.2 million after tax) in unrealized gains and no unrealized losses in AOCI at December 31, 2009.

DP&L had $13.1 million ($8.5 million after tax) in unrealized gains and no unrealized losses on the Master Trust assets in AOCI at September 30, 2010 and $14.5 million ($9.5 million after tax) in unrealized gains and no unrealized losses in AOCI at December 31, 2009.

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

Short-Term Investments

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

DPL also holds investment-grade fixed income corporate bonds that are classified as held-to-maturity. Held-to-maturity securities are those securities that we have the intent and ability to hold until maturity. The held-to-maturity securities are carried at amortized cost which is determined based on specific identification. The bonds are classified as short-term since they will mature within the next twelve months.

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Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 2010. These assets are part of the Master Trust and exclude DPL common stock which is valued using quoted market prices and not the NAV per unit. Fair values estimated using the NAV per unit are considered Level 2 inputs within the fair value hierarchy, unless they cannot be redeemed at the NAV per unit on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of September 30, 2010, DPL did not have any investments for sale at a price different from the NAV per unit.

Fair Value Estimated Using Net Asset Value per Unit

$ in millions	Fair Value at September 30, 2010		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
Money Market Fund (a)	$	1.6	$	—	Immediate	None

Equity Securities (b)	3.8		—		Immediate	None

Debt Securities (c)	5.6		—		Immediate	None

Multi-Strategy Fund (d)	0.3		—		Immediate	None

Total	$	11.3	$	—

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

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

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

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

Fair Value Hierarchy

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

Valuations of assets and liabilities reflect the value of the instrument including the values associated with counterparty risk. We include our own credit risk and our counterparty’s credit risk in our calculation of fair value using global average default rates based on an annual study conducted by a large rating agency.

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value hierarchy during the three and nine months ended September 30, 2010.

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The fair value of assets and liabilities at September 30, 2010 and December 31, 2009 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:

DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at September 30, 2010		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Balance Sheet at September 30, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities	3.8		—		3.8		—		—			3.8
Debt Securities	5.6		—		5.6		—		—			5.6
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	11.3	$	—	$	11.3	$	—	$	—		$	11.3

Derivative Assets
FTRs	$	0.4	$	—	$	0.4	$	—	$	—		$	0.4
Heating Oil Futures	0.6		0.6		—		—		(0.6		)	—
Forward NYMEX Coal Contracts	6.2		—		6.2		—		(2.8		)	3.4
Forward Power Contracts	4.5		—		4.5		—		(1.4		)	3.1
Total Derivative Assets	$	11.7	$	0.6	$	11.1	$	—	$	(4.8	)	$	6.9

Short-term Investments - VRDNs	$	33.0	$	—	$	33.0	$	—	$	—		$	33.0
Short-term Investments - Bonds	15.3		—		15.3		—		—			15.3
Total Short-term investments	$	48.3	$	—	$	48.3	$	—	$	—		$	48.3

Total Assets	$	71.3	$	0.6	$	70.7	$	—	$	(4.8	)	$	66.5

Liabilities
Derivative Liabilities
Heating Oil Futures	$	0.3	$	0.3	$	—	$	—	$	(0.3	)	$	—
Interest Rate Hedge	21.6		—		21.6		—		—			21.6
Forward Power Contracts	3.4		—		3.4		—		(1.4		)	2.0
Forward NYMEX Coal Contracts	3.1		—		3.1		—		(2.1		)	1.0
Total Derivative Liabilities	$	28.4	$	0.3	$	28.1	$	—	$	(3.8	)	$	24.6

Total Liabilities	$	28.4	$	0.3	$	28.1	$	—	$	(3.8	)	$	24.6

*Includes credit valuation adjustments for counterparty risk.

DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2009		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Balance Sheet at December 31, 2009
Assets
Master Trust Assets
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities	2.8		—		2.8		—		—			2.8
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	12.6	$	—	$	12.6	$	—	$	—		$	12.6

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

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

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

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

*Includes credit valuation adjustments for counterparty risk.

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DP&L

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at September 30, 2010		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Balance Sheet at September 30, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities (a)	30.0		26.2		3.8		—		—			30.0
Debt Securities	5.6		—		5.6		—		—			5.6
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	37.5	$	26.2	$	11.3	$	—	$	—		$	37.5

Derivative Assets
FTRs	$	0.4	$	—	$	0.4	$	—	$	—		$	0.4
Heating Oil Futures	0.6		0.6		—		—		(0.6		)	—
Forward NYMEX Coal Contracts	6.2		—		6.2		—		(2.8		)	3.4
Forward Power Contracts	4.5		—		4.5		—		(1.4		)	3.1
Total Derivative Assets	$	11.7	$	0.6	$	11.1	$	—	$	(4.8	)	$	6.9

Total Assets	$	49.2	$	26.8	$	22.4	$	—	$	(4.8	)	$	44.4

Liabilities
Derivative Liabilities
Heating Oil Futures	$	0.3	$	0.3	$	—	$	—	$	(0.3	)	$	—
Forward Power Contracts	3.4		—		3.4		—		(1.4		)	2.0
Forward NYMEX Coal Contracts	3.1		—		3.1		—		(2.1		)	1.0
Total Derivative Liabilities	$	6.8	$	0.3	$	6.5	$	—	$	(3.8	)	$	3.0

Total Liabilities	$	6.8	$	0.3	$	6.5	$	—	$	(3.8	)	$	3.0

*Includes credit valuation adjustments for counterparty risk.

(a) DPL stock in the Master Trust is eliminated in consolidation.

DP&L

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2009		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting*			Balance Sheet at December 31, 2009
Assets
Master Trust Assets
Money Market Funds	$	4.1	$	—	$	4.1	$	—	$	—		$	4.1
Equity Securities (a)	31.1		28.3		2.8		—		—			31.1
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	40.9	$	28.3	$	12.6	$	—	$	—		$	40.9

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

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

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

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

*Includes credit valuation adjustments for counterparty risk.

(a) DPL stock in the Master Trust is eliminated in consolidation.

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

Approximately 99% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring Fair Value Measurements

We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. There were no additions to our existing AROs during the three months ended September 30, 2010.

DPL had $59.1 million and $45.3 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009, respectively. The money market funds have quoted prices that are generally equivalent to par.

9. Derivative Instruments and Hedging Activities

In the normal course of business, DPL and DP&L enter into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities and interest rate risk associated with our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges or marked to market each reporting period.

At September 30, 2010, DPL and DP&L had the following outstanding derivative instruments:

	Accounting		Purchases	Sales		Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs (1)	Mark to Market	MWh	14.4	—		14.4
Heating Oil Futures (1)	Mark to Market	Gallons	6,846.0	—		6,846.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	512.0	(1,005.4	)	(493.4	)
Forward Power Contracts (1)	Mark to Market	MWh	195.6	(87.6	)	108.0
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	3,549.5	(341.0	)	3,208.5
Interest Rate Swaps (2)	Cash Flow Hedge	USD	360,000.0	—		360,000.0

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

(1) Reflected in both DPL and DP&L financial statements

(2) Reflected in only DPL financial statements

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Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair value of cash flow hedges as determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to earnings using specific identification of each contract when the forecasted hedged transaction takes place or when the forecasted hedged transaction is probable of not occurring. The ineffective portion of the cash flow hedge is recognized in earnings in the current period. All risk components were taken into account to determine the hedge effectiveness of the cash flow hedges.

We enter into forward power contracts to manage commodity price risk exposure related to our generation of electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in those periods in which the contracts settle.

We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. As of September 30, 2010, we have entered into interest rate hedging relationships with aggregate notional amounts of $200 million and $160 million related to planned future borrowing activities in calendar years 2011 and 2013, respectively. We reclassify gains and losses on interest rate derivative hedges related to our debt financings from AOCI into earnings in those periods in which hedged interest payments occur.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 2010 and 2009:

	September 30,						September 30,
	2010						2009
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	—		$	7.7		$	1.3		$	16.0

Net gains / (losses) associated with current period hedging transactions	(0.4		)	(8.9		)	(1.6		)	—

Net gains reclassified to earnings
Interest expense	—			(0.6		)	—			(0.6		)
Revenues	0.8			—			2.1			—

Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	(1.8	)	$	1.8		$	15.4

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

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 2010 and 2009:

	September 30,						September 30,
	2010						2009
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	—		$	13.5		$	1.3		$	16.0

Net gains / (losses) associated with current period hedging transactions	(0.4		)	—			(1.6		)	—

Net gains reclassified to earnings
Interest expense	—			(0.6		)	—			(0.6		)
Revenues	0.8			—			2.1			—

Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	12.9		$	1.8		$	15.4

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

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The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the nine months ended September 30, 2010 and 2009:

DPL

	September 30,						September 30,
	2010						2009
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

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

Net gains / (losses) associated with current period hedging transactions	3.3			(14.7		)	4.0			—

Net gains reclassified to earnings
Interest expense	—			(1.8		)	—			(1.8		)
Revenues	(1.5		)	—			(2.0		)	—

Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	(1.8	)	$	1.8		$	15.4

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

Portion expected to be reclassified to earnings in the next twelve months*	$	3.2		$	2.5

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	39			36

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the nine months ended September 30, 2010 and 2009:

DP&L

	September 30,						September 30,
	2010						2009
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

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

Net gains / (losses) associated with current period hedging transactions	3.3			—			4.0			—

Net gains reclassified to earnings
Interest expense	—			(1.8		)	—			(1.8		)
Revenues	(1.5		)	—			(2.0		)	—

Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	12.9		$	1.8		$	15.4

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

Portion expected to be reclassified to earnings in the next twelve months*	$	3.2		$	2.5

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	39			—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.

The following table shows the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at September 30, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at September 30, 2010

DPL

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	3.9		$	(1.0	)	Other prepayments and current assets	$	2.9
Forward Power Contracts in a Liability Position	(1.3		)	0.9			Other current liabilities	(0.4		)
Interest Rate Hedges in a Liability Position	(20.6		)	—			Other current liabilities	(20.6		)

Total short-term cash flow hedges	$	(18.0	)	$	(0.1	)		$	(18.1	)

Long-term Derivative Positions

Interest Rate Hedges in a Liability Position	$	(1.0	)	$	—		Other deferred credits	$	(1.0	)
Forward Power Contracts in an Asset Position	0.1			(0.1		)	Other deferred assets	—
Forward Power Contracts in a Liability Position	(1.2		)	0.3			Other deferred credits	(0.9		)

Total long-term cash flow hedges	$	(2.1	)	$	0.2			$	(1.9	)

Total cash flow hedges	$	(20.1	)	$	0.1			$	(20.0	)

*Includes counterparty and collateral netting.

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The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments at September 30, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at September 30, 2010

DP&L

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	3.9		$	(1.0	)	Other prepayments and current assets	$	2.9
Forward Power Contracts in a Liability Position	(1.3		)	0.9			Other current liabilities	(0.4		)

Total short-term cash flow hedges	$	2.6		$	(0.1	)		$	2.5

Long-term Derivative Positions

Forward Power Contracts in an Asset Position	$	0.1		$	(0.1	)	Other deferred assets	$	—
Forward Power Contracts in a Liability Position	(1.2		)	0.3			Other deferred credits	(0.9		)

Total long-term cash flow hedges	$	(1.1	)	$	0.2			$	(0.9	)

Total cash flow hedges	$	1.5		$	0.1			$	1.6

*Includes counterparty and collateral netting.

The following table shows the fair value and balance sheet classification of DPL’s and DP&L’s derivative instruments designated as hedging instruments at December 31, 2009.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at December 31, 2009

								Fair Value on
$ in millions	Fair Value			Netting*			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	0.7		$	(0.7	)	Other prepayments and current assets	$	—
Forward Power Contracts in a Liability Position	(2.8		)	0.7			Other current liabilities	(2.1		)

Total cash flow hedges	$	(2.1	)	$	—			$	(2.1	)

*Includes counterparty and collateral netting.

Mark to Market Accounting

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchases and sales exceptions under FASC Topic 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the condensed consolidated statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures, forward NYMEX-quality coal contracts, natural gas futures and certain forward power contracts.

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

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Regulatory Assets and Liabilities

Under FASC Topic 980 “Regulated Operations,” if a cost is probable of recovery in future rates, it should be deferred as a regulatory asset. If a gain is probable of being returned to customers, it should be deferred as a regulatory liability. Portions of the derivative contracts that are marked to market each reporting period and are related to the retail portion of DP&L’s load requirements are included as part of the fuel rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio jurisdictional retail portion of the heating oil futures and the NYMEX-quality coal contracts are deferred as a regulatory asset or liability until the contracts settle. If these unrealized gains and losses are no longer deemed to be probable of recovery through our rates, they will be reclassified into earnings in the period such determination is made.

The following tables show the amount and classification within the condensed consolidated statements of results of operations or balance sheets of the gains and losses on DPL’s and DP&L’s derivatives not designated as hedging instruments for the three and nine months ended September 30, 2010 and 2009.

For the Three Months Ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power		Natural Gas		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	—	$	(2.1	)
Realized gain / (loss)	0.6			(0.4		)	(0.4		)	—		—		(0.2		)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	—	$	(2.3	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(1.6	)	$	—		$	—		$	—	$	—	$	(1.6	)
Regulatory (asset) / liability	(1.0		)	0.7			—			—		—		(0.3		)

Recorded in Income Statement: gain / (loss)
Purchased power	$	—		$	—		$	(0.5	)	$	0.5	$	—	$	—
Fuel	(0.6		)	0.2			—			—		—		(0.4		)
O&M	—			—			—			—		—		—
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	—	$	(2.3	)

For the Three Months Ended September 30, 2009

$ in millions	NYMEX Coal			Heating Oil			FTRs		Total
Change in 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:
Partners’ share of gain / (loss)	$	(7.1	)	$	—		$	—	$	(7.1	)
Regulatory (asset) / liability	(1.4		)	0.1			—		(1.3		)

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

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For the Nine Months Ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Natural Gas		Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	—	$	0.8
Realized gain / (loss)	1.6			(1.5		)	(1.4		)	(0.1		)	—		(1.4		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	—	$	(0.6	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	0.2		$	—		$	—		$	—		$	—	$	0.2
Regulatory (asset) / liability	(0.6		)	0.6			—			—			—		—

Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	—		$	—		$	—		$	(0.1	)	$	—	$	(0.1	)
Purchased power	—			—			(1.8		)	0.7			—		(1.1		)
Fuel	1.0			(0.5		)	—			—			—		0.5
O&M	—			(0.1		)	—			—			—		(0.1		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	—	$	(0.6	)

For the Nine Months Ended September 30, 2009

$ in millions	NYMEX Coal			Heating Oil			FTRs			Total
Change in 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:
Partners’ share of gain / (loss)	$	(1.9	)	$	—		$	—		$	(1.9	)
Regulatory (asset) / liability	(1.8		)	1.2			—			(0.6		)

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

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The following tables show the fair value and balance sheet classification of DPL’s and DP&L’s derivative instruments not designated as hedging instruments at September 30, 2010 and December 31, 2009.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at September 30, 2010

$ in millions	Fair Value			Netting*			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.4		$	—		Other prepayments and current assets	$	0.4
Forward Power Contracts in an Asset position	0.3			(0.1		)	Other prepayments and current assets	0.2
Forward Power Contracts in a Liability position	(0.7		)	0.2			Other current liabilities	(0.5		)
NYMEX-Quality Coal Forwards in an Asset position	3.8			(1.1		)	Other prepayments and current assets	2.7
NYMEX-Quality Coal Forwards in a Liability position	(2.0		)	1.0			Other current liabilities	(1.0		)
Heating Oil Futures in a Liability position	(0.3		)	0.3			Other current liabllities	—

Total short-term derivative MTM positions	$	1.5		$	0.3			$	1.8

Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.1		$	(0.1	)	Other deferred assets	$	—
Forward Power Contracts in a Liability position	(0.2		)	0.1			Other deferred credits	(0.1		)
NYMEX-Quality Coal Forwards in an Asset position	2.5			(1.8		)	Other deferred assets	0.7
NYMEX-Quality Coal Forwards in a Liability position	(1.1		)	1.1			Other deferred credits	—
Heating Oil Futures in an Asset position	0.6			(0.6		)	Other deferred credits	—

Total long-term derivative MTM positions	$	1.9		$	(1.3	)		$	0.6

Total MTM Position	$	3.4		$	(1.0	)		$	2.4

*Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at December 31, 2009

$ in millions	Fair Value			Netting*			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset position	$	0.8		$	—		Other prepayments and current assets	$	0.8
NYMEX-Quality Coal Forwards in an Asset position	2.6			(0.2		)	Other prepayments and current assets	2.4
NYMEX-Quality Coal Forwards in a Liability position	(1.2		)	—			Other current liabilities	(1.2		)
Heating Oil Futures in a Liability position	(1.2		)	1.2			Other current liabllities	—
Forward Power Contracts in a Liability position	(0.2		)	—			Other current liabilities	(0.2		)

Total short-term derivative MTM positions	$	0.8		$	1.0			$	1.8

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

Total long-term derivative MTM positions	$	2.9		$	(1.2	)		$	1.7

Total MTM Position	$	3.7		$	(0.2	)		$	3.5

*Includes counterparty and collateral netting.

Certain of our OTC commodity derivative contracts are under master netting agreements that contain provisions that require our debt to maintain an investment grade credit rating from credit rating agencies. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization of the MTM loss. The aggregate fair value of all commodity derivative instruments that are in a MTM loss position at September 30, 2010 is $6.8 million. This amount is offset by $1.0 million in a broker margin account which offsets our loss positions on the NYMEX Clearport traded heating oil, power and coal contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $3.4 million. If our debt were to fall below investment grade, we may have to post collateral for the remaining $2.4 million.

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10. Share-Based Compensation

Share-based compensation expense was $1.2 million and $1.0 million for the three months ended September 30, 2010 and 2009, respectively, and $3.8 million and $2.6 million for the nine months ended September 30, 2010 and 2009, respectively.

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

Summarized share-based compensation activity for the three months ended September 30, 2010 and 2009 was as follows:

	Options				RSUs				Performance Shares
	2010		2009		2010		2009		2010	2009
Outstanding at beginning of period	351,500		836,500		3,311		10,120		307,985	237,704
Granted	—		—		—		—		—	—
Dividends	—		—		—		—		—	—
Exercised	—		(60,000	)	(3,311	)	(6,809	)	—	—
Expired	—		—		—		—		—	—
Forfeited	—		—		—		—		—	—
Outstanding at period end	351,500		776,500		—		3,311		307,985	237,704
Exercisable at period end	351,500		776,500		—		—		—	—

					Management Performance
	Restricted Shares				Shares
	2010		2009		2010		2009
Outstanding at beginning of period	249,101		70,647		110,706		87,863
Granted	2,617		95,036		—		—
Dividends	—		—		—		—
Exercised	(1,800	)	—		—		—
Expired	—		—		—		—
Forfeited	(7,635	)	—		(1,494	)	(3,622	)
Outstanding at period end	242,283		165,683		109,212		84,241
Exercisable at period end	—		—		—		—

	Director RSUs
	2010		2009
Outstanding at beginning of period	15,944		20,272
Granted	—		—
Dividends accrued	655		474
Exercised and issued	—		—
Exercised and deferred	(471	)	(242	)
Forfeited	—		—
Outstanding at period end	16,128		20,504
Exercisable at period end	—		—

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Summarized share-based compensation activity for the nine months ended September 30, 2010 and 2009 was as follows:

	Options				RSUs				Performance Shares
	2010		2009		2010		2009		2010		2009
Outstanding at beginning of year	417,500		836,500		3,311		10,120		237,704		156,300
Granted	—		—		—		—		161,534		124,588
Dividends	—		—		—		—		—		—
Exercised	(66,000	)	(60,000	)	(3,311	)	(6,809	)	(91,253	)	—
Expired	—		—		—		—		—		(36,445	)
Forfeited	—		—		—		—		—		(6,739	)
Outstanding at period end	351,500		776,500		—		3,311		307,985		237,704
Exercisable at period end	351,500		776,500		—		—		—		—

					Management Performance
	Restricted Shares				Shares
	2010		2009		2010		2009
Outstanding at beginning of year	218,197		69,147		84,241		39,144
Granted	42,796		97,536		37,480		48,719
Dividends	—		—		—		—
Exercised	(10,803	)	(1,000	)	—		—
Expired	—		—		—		—
Forfeited	(7,907	)	—		(12,509	)	(3,622	)
Outstanding at period end	242,283		165,683		109,212		84,241
Exercisable at period end	—		—		—		—

	Director RSUs
	2010		2009
Outstanding at beginning of year	20,712		15,546
Granted	15,752		20,016
Dividends accrued	1,809		1,310
Exercised and issued	(2,618	)	(2,066	)
Exercised and deferred	(19,527	)	(14,302	)
Forfeited	—		—
Outstanding at period end	16,128		20,504
Exercisable at period end	—		—

11. Common Shareholders’ Equity

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may use proceeds from the exercise of DPL warrants by warrant holders to repurchase other outstanding DPL warrants or its common stock from time to time in the open market, through private transactions or otherwise. The Stock Repurchase Program will run through June 30, 2012, which is three months after the end of the warrant exercise period. Under the Stock Repurchase Program, DPL repurchased a total of 145,915 shares during the nine months ended September 30, 2010 at an average per share price of $26.71, effectively utilizing the entire $3.9 million that was available to repurchase stock at December 31, 2009. There were no shares repurchased during the three months ended September 30, 2010. However, additional funds could be available to repurchase stock if the 1.8 million warrants outstanding at September 30, 2010 are exercised for cash in the future.

On October 27, 2010, the DPL Board of Directors approved a new Stock Repurchase Program under which DPL may repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. This Stock Repurchase Program will run through December 31, 2013 but may be modified or terminated at any time without notice.

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12. EPS

Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations are shares held by DP&L’s Master Trust Plan for deferred compensation and unreleased shares held by DPL’s ESOP.

The common-equivalent shares excluded from the calculation of diluted EPS because they were anti-dilutive, were not material for the three and nine months ended September 30, 2010 and 2009. These shares may be dilutive in the future.

The following illustrates the reconciliation of the numerators and denominators of the basic and diluted EPS computations:

Three Months Ended September 30,

2010

2009

$ and shares in millions except

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

86.4

115.8

0.75

67.9

112.4

0.60

Effect of Dilutive Securities:

Warrants

0.3

1.8

Stock options, performance and restricted shares

0.2

0.2

Diluted EPS

86.4

116.3

0.74

67.9

114.4

0.59

Nine Months Ended September 30,

2010

2009

$ and shares in millions except

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

218.8

115.7

1.89

179.2

112.2

1.60

Effect of Dilutive Securities:

Warrants

0.3

1.0

Stock options, performance and restricted shares

0.2

0.2

Diluted EPS

218.8

116.2

1.88

179.2

113.4

1.58

13. Insurance Recovery

On May 16, 2007, DPL filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, DPL and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim. The proceeds from the settlement amounted to $3.4 million, net of associated expenses, and were recorded as a reduction to operation and maintenance expense during the nine months ended September 30, 2010.

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14. Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned generating subsidiary, DPLE and its competitive retail electric supplier subsidiary, DPLER, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE and DPLER on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s and DPLER’s intended commercial purposes. There have been no material changes to our guarantees as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Through September 30, 2010, DPL has not incurred any losses related to the guarantees of DPLE’s and DPLER’s obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s and DPLER’s obligations.

DP&L — Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of September 30, 2010, DP&L could be responsible for the repayment of 4.9%, or $62.9 million, of a $1,283.7 million debt obligation that matures in 2026. This would only happen if this electric generation company defaulted on its debt payments. As of September 30, 2010, we have no knowledge of such a default.

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

Commercial Commitments and Contractual Obligations

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

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2010, cannot be reasonably determined.

Environmental Matters

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. As of September 30, 2010, DPL has an immaterial reserve for environmental matters. A portion of this reserve is recorded at MVIC, DPL’s wholly-owned captive insurance subsidiary. 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.

We have several pending environmental matters associated with our power plants. Some of these matters could have material adverse impacts on the operation of the power plants, especially the plants that do not have SCR and FGD equipment installed to further control certain emissions. Currently, Hutchings and Beckjord are our only coal-fired power plants that do not have this equipment installed. DP&L owns 100% of the Hutchings plant and a 50% interest in Beckjord Unit 6.

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Air Quality

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

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

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

On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap SO2 and NOx emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and ozone pollution in other downwind states in the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, now renamed the CAIR. The final rules were signed on March 10, 2005 and were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. On August 24, 2005, the USEPA proposed additional revisions to the CAIR. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision to vacate the USEPA’s CAIR and its associated Federal Implementation Plan and remanded to the USEPA with instructions to issue new regulations that conformed with the procedural and substantive requirements of the CAA. The Court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program established by the March 10, 2005 rules, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. The USEPA and a group representing utilities filed a request on September 24, 2008 for a rehearing before the entire Court. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 11, 2008 decision. In the fourth quarter of 2007, DP&L began a program for selling excess emission allowances, including annual NOx emission allowances and SO2 emission allowances that were the subject of CAIR trading programs. In subsequent quarters, DP&L recognized gains from the sale of excess emission allowances to third parties. The court’s CAIR decision affected the trading market for excess allowances and impacted DP&L’s program for selling additional excess allowances in 2008. In January 2009 we resumed selling excess allowances due to the revival of the emissions trading market. On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) which will effectively replace CAIR. We have reviewed this proposal and submitted comments to the USEPA on September 30, 2010. At this time, we are unable to determine the overall financial impact that these rules could have on our operations in the future.

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

On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA “de-listed” mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005 and was published on May 18, 2005. On March 29, 2005, nine states sued the USEPA, opposing the cap-and-trade regulatory approach taken by the USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to “de-listing” a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for “listed” hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. The USEPA is expected to move forward on setting Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. Upon publication in the federal register following finalization, affected electric generating units (EGUs) will have three years to come into compliance with the new requirements. 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 predict at this time the final costs we may incur to comply with any resulting mercury restriction regulations.

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

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

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

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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. The American Power Act was introduced by Senators John Kerry and Joe Lieberman on May 12, 2010. This Climate Legislation proposes a reduction in GHG emissions of 83% by 2050 through an economy-wide cap-and-trade program. The American Power Act also encourages nuclear energy and renewable energy initiatives and the development of a national strategy for carbon capture and sequestration. Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. Proposed GHG legislation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial position. However, due to the uncertainty associated with such legislation, we cannot predict at this time the final outcome or the financial impact that this legislation will have on DP&L.

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

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

On June 3, 2010, the USEPA finalized revisions to its primary NAAQS for SO2 replacing the current 24-hour standard and annual standard with a one hour standard. At this time, DP&L cannot determine the effect of this potential change, if any, on its operations.

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

On April 29, 2010, the USEPA issued a proposed rule that would reduce emissions of toxic air pollutants from new and existing industrial, commercial and institutional boilers, and process heaters at major and area source facilities. This regulation may affect five auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The proposed regulations contain emissions limitations, operating limitations and other requirements. The compliance schedule will be three years from the effective date of the rule. We cannot predict, at this time, the effect of compliance costs, if any, on DP&L’s operations; however, such costs are not expected to be material.

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

Air Quality — Litigation Involving Co-Owned Plants

In 2004, eight states and the City of New York filed a lawsuit in Federal District Court for the Southern District of New York against American Electric Power Company, Inc. (AEP), one of AEP’s subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. A similar lawsuit was filed against these companies in the same court by Open Space Institute, Inc., Open Space Conservancy, Inc. and The Audubon Society of New Hampshire. The lawsuits allege that the companies’ emissions of CO2 contribute to global warming and constitute a public or private nuisance. The lawsuits seek injunctive relief in the form of specific emission reduction commitments. In 2005, the Federal District Court dismissed the lawsuits, holding that the lawsuits raised political questions that should not be decided by the courts. The plaintiffs appealed. Finding that the plaintiffs have standing to sue and can assert federal common law nuisance claims, the United States Court of Appeals for the Second Circuit on September 21, 2009 vacated the dismissal of the Federal District Court and remanded the lawsuits back to the Federal District Court for further proceedings. On August 2, 2010, the company defendants petitioned the U.S. Supreme Court for a hearing on the matter. Although we are not named as a party to these lawsuits, DP&L is a co-owner of coal-fired plants with Duke Energy and AEP (or their subsidiaries) that could be affected by the outcome of these lawsuits. The 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.

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

Air Quality — Notices of Violation Involving Co-Owned Plants

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

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

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

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

Air Quality — Other Issues Involving Co-Owned Plants

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

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Air Quality — Notices of Violation Involving Wholly-Owned Plants

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

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

Water Quality

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

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

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking will include the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. Subsequent to the information collection effort, it is anticipated that the USEPA will release a proposed rule. At present, DP&L is unable to predict the timing of the issuance or impact this rulemaking will have on its operations.

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Land Use and Solid Waste Disposal

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

In December 2003, DP&L and other parties received a special notice that the USEPA considers us to be a PRP for the clean-up of hazardous substances at the Tremont City landfill site. Information available to DP&L does not demonstrate that it contributed hazardous substances to the site. While DP&L is unable 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.

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

During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station. In October 2009, the USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, the USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds and has requested a response. In May 2010, DP&L responded to the USEPA final inspection report with our plans to address the recommendations. At this time, a final determination has not been made regarding the report’s recommendations and DP&L continues to work with the USEPA on this matter.

Similarly, in August 2010, the USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. The report relating to the inspection has not been received and DP&L is unable to predict the outcome this initiative will have on its operations.

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

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Legal and Other Matters

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

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

As a member of PJM, DP&L is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC Orders issued in 2007 regarding the allocation of costs of large transmission facilities within PJM, could result in additional costs being allocated to DP&L of approximately $12 million or more annually by 2012. DP&L filed a notice of appeal to the U.S. Court of Appeals, D.C. Circuit on March 18, 2008 challenging the allocation method. The appeal was consolidated with other appeals taken by other interested parties of the same FERC Orders and the consolidated cases were assigned to the 7th Circuit. On August 6, 2009, the 7th Circuit ruled that the FERC had failed to provide a reasoned basis for the allocation method it had approved. Rehearing requests were filed by other interested litigants and denied by the Court, which then remanded the matter to the FERC for further proceedings. On January 21, 2010, the FERC issued a procedural order on remand establishing a paper hearing process. PJM made an informational filing on April 13, 2010 that quantified the differences in the levels of allocated costs among PJM member transmission owners depending on the allocation methodology used. Subsequently PJM and other parties, including DP&L, will be able to file initial comments, testimony, and recommendations and reply comments. Absent future changes to the procedural schedule that may occur for a number of reasons including if settlement discussions are held, we expect the paper hearing process should be complete and the case ready for FERC consideration in 2010. FERC did not establish a deadline for its issuance of a substantive order. DP&L cannot predict the timing or the likely outcome of the proceeding. Until such time as FERC may act to approve a change in methodology, PJM will continue to apply the allocation methodology that had been approved by FERC in 2007. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that DP&L is not one of these beneficiaries, new credits or additional costs resulting from the ultimate outcome of this proceeding are and will continue to be included in DP&L’s TCRR rider which is in place and approved by the PUCO.

In connection with DP&L and other utilities joining PJM, in 2006 the FERC ordered utilities to eliminate certain charges to implement transitional payments, known as SECA, effective December 1, 2004 through March 31, 2006, subject to refund. Through this proceeding, DP&L was obligated to pay SECA charges to other utilities, but received a net benefit from these transitional payments. A hearing was held and an initial decision was issued in August 2006. A final FERC order on this issue was issued on May 21, 2010 that substantially supports DP&L’s and other utilities’ position that SECA obligations should be paid by parties that used the transmission system during the timeframe stated above. DP&L, along with other transmission owners in PJM and the Midwest Independent System Operator (MISO) made a compliance filing at FERC on August 19, 2010 that fully demonstrated all payment obligations to and from all parties within PJM and the MISO. Prior to this final order being issued, DP&L entered into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. Further, in October 2010, DP&L entered into another settlement agreement to settle a portion of SECA amounts still owed to DP&L. DP&L management believes it has deferred as a regulatory liability the appropriate amounts that are subject to refund (see SECA net revenue subject to refund within Note 3 of Notes to Condensed Consolidated Financial Statements) and therefore the results of this proceeding are not expected to have a material adverse effect on DP&L’s results of operations.

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

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

This report includes the combined filing of DPL Inc. (DPL) and The Dayton Power and Light Company (DP&L). DP&L is the principal subsidiary of DPL providing approximately 95% of DPL’s total consolidated revenue and approximately 94% of DPL’s total consolidated asset base. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

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

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

The following discussion should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes included in Part I — Financial Information.

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BUSINESS OVERVIEW

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

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

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

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

REGULATORY ENVIRONMENT

· Emissions — Climate Change Legislation

There is a growing concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly, CO2. This concern has led to increased interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions. In 2007, a U.S. Supreme Court decision upheld that the USEPA has the authority to regulate CO2 emissions from motor vehicles under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the CAA, which was finalized and published on December 15, 2009. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. In December 2009, USEPA finalized this endangerment finding with a regulatory effective date of January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision. This endangerment finding, if not changed, is expected to lead to the regulation of CO2 and other GHGs from electric generating units and other stationary sources of these emissions. In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act (ACES). This proposed legislation targets a reduction in the emission of GHGs from large sources by 80% in 2050 through an economy-wide cap and trade program. ACES also includes energy efficiency and renewable energy initiatives. The American Power Act was introduced by Senators John Kerry and Joe Lieberman on May 12, 2010. This climate legislation proposes a reduction in GHG emissions of 83% by 2050 through an economy-wide cap and trade program. The American Power Act also encourages nuclear energy and renewable energy initiatives and the development of a national strategy for carbon capture and sequestration. Increased pressure for CO2 emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. If legislation or regulations are passed at the federal or state levels that impose mandatory reductions of CO2 and other GHGs on generation facilities, the cost to DPL and DP&L of such reductions could be material.

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· SB 221 Requirements

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

SB 221 also contains provisions for determining whether an electric utility has significantly excessive earnings. On September 9, 2009, the PUCO issued an entry establishing a significantly excessive earnings test (SEET) proceeding. After receiving comments from interested parties including DP&L, the PUCO issued an entry on June 30, 2010 to establish general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. Pursuant to the Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and SEET may have a material impact on operations.

· NOx and SO2 Emissions — CAIR

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

· Dodd-Frank Financial Reform Bill

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was passed by Congress on July 15, 2010 and was signed into law on July 21, 2010. The Act, among other things, establishes a Financial Stability Oversight Council (FSOC) and a Consumer Financial Protection Bureau (CFPB) whose duties will include the monitoring of domestic and international financial regulatory proposals and developments, as well as the protection of consumers. The FSOC may submit comments to the SEC and any standard-setting body with respect to an existing or proposed accounting principle, standard or procedure. The Act also creates increased oversight of the over-the-counter derivative market, requiring certain OTC transactions to be cleared through a clearing house and requiring cash margins to be posted for those transactions. Many regulations will be issued to implement the Act over the next twelve to twenty-four months. We are currently unable to determine the final impact that the Act will have on our operations until these regulations have been issued.

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COMPETITION AND PJM PRICING

· RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the 2013/2014 period cleared at a per megawatt price of $28/day for our RTO area. The per megawatt price for the 2012/2013 period was $16/day and the per megawatt price for the 2011/2012 period was $110/day based on previous auctions. Future RPM auction results will be dependent not only on the overall supply and demand of generation and load, but may also be impacted by congestion as well as PJM’s business rules relating to bidding for Demand Response and Energy Efficiency resources in the RPM capacity auctions. Increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. We cannot predict the outcome of future auctions or customer switching but if the current auction prices are sustained or drop lower, or if customer switching continues, our future results of operations, financial condition and cash flows could be adversely impacted.

· Ohio Competitive Considerations and Proceedings

Overall power market prices, as well as government aggregation initiatives, could lead to the entrance of additional competitors in our service territory. During the three months ended September 30, 2010, one additional unaffiliated marketer registered as a CRES provider in DP&L’s service territory, bringing the total number of CRES providers in DP&L’s service territory to eleven. DPLER, an affiliated company and one of the eleven registered CRES providers, has been marketing transmission and generation services to DP&L customers. DPLER accounted for approximately 3,091 million kWh of the total 3,167 million kWh supplied by CRES providers within DP&L’s service territory in the nine months ended September 30, 2010, which represents approximately 29% of DP&L’s total distribution sales volume during the nine months then ended. During the three months ended September 30, 2010, DPLER accounted for approximately 1,338 million kWh of the total 1,397 million kWh supplied by CRES providers within DP&L’s service territory, which represents approximately 35% of DP&L’s total distribution sales volume during the three months then ended. The reduction in gross margin as a result of customers switching to CRES providers for the three months and nine months ended September 30, 2010 is estimated for DPL to be approximately $6 million and $10 million, respectively, and for DP&L is estimated to be approximately $13 million and $31 million, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the impact this will have on our operations, but any additional switching could adversely affect our future results of operations, financial condition and cash flows.

In 2003-2004, several communities in DP&L’s service area passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, none of these communities have aggregated their generation load.

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

FUEL AND RELATED COSTS

· Fuel and Commodity Prices

The coal market is a global market in which domestic prices are affected by international supply disruptions and demand balance. In addition, domestic issues like government-imposed direct costs and permitting issues are affecting mining costs and supply availability. Our approach is to hedge the fuel costs for our anticipated electric sales. For the year ending December 31, 2010, we have hedged substantially all our coal requirements to meet our committed sales. We may not be able to hedge the entire exposure of our operations from commodity price volatility. Effective January 2010, the Ohio retail jurisdictional share of fuel price changes, including coal requirements and purchased power costs, is reflected in the implementation of the fuel rider, subject to PUCO review. If our suppliers do not meet their contractual commitments or we are not hedged against price volatility and we are unable to recover costs through the fuel rider, our results of operations, financial position or cash flows could be materially affected.

· Sales of Coal and Excess Emission Allowances

During the nine months ended September 30, 2010, DP&L sold coal and excess emission allowances to various counterparties realizing total net gains of $2.4 million and $0.7 million, respectively, compared to total net gains of $45.9 million and $4.1 million, respectively, realized over the same period in 2009. These gains are recorded as a component of DP&L’s fuel costs and are reflected in operating income. Coal sales are impacted by a range of factors but can be largely attributed to the following: price volatility among the different coal basins or the quality of coal based on market conditions (coal optimization), variation in power demand, and the market price of power compared to the cost to produce power. Sales of excess emission allowances are impacted, among other factors, by: general economic conditions; fluctuations in market demand and pricing; availability of excess inventory available for sale; and changes to the regulatory environment in which we operate. The combined impact of these factors on our ability to sell coal and emission allowances in 2010 and beyond is not fully known at this time and could materially impact the amount of gains that will be recognized in the future. Effective January 2010, as part of the operation of the fuel rider, the Ohio retail jurisdictional share of the emission gains and a portion of the Ohio jurisdictional share of the coal gains are used to reduce the overall rate charged to customers.

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OHIO REGULATORY MATTERS

Ohio Retail Rates

In compliance with SB 221, DP&L filed its electric security plan at the PUCO on October 10, 2008. On February 24, 2009, DP&L filed the Stipulation that, among other things, extended the Company’s rate plan through 2012, provided for recovery of the Ohio jurisdictional retail portion of fuel and purchased power costs beginning January 2010, provided for recovery of certain SB 221 compliance costs, and required DP&L to re-file its Smart Grid and AMI business cases by September 1, 2009. The material terms of the Stipulation were discussed in greater detail in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. On October 19, 2010, DP&L elected to withdraw the re-filed case pertaining to the Smart Grid and AMI and to monitor other utilities’ Smart Grid and AMI programs.

On October 30, 2009, DP&L filed its application for the establishment of a fuel and purchased power recovery rider for the collection of prudently incurred fuel, purchased power, emission and other related costs beginning January 1, 2010. On December 16, 2009 the PUCO issued an order stating the rider was consistent with the Stipulation provisions, that it does not appear to be unjust or unreasonable, and that the rider was approved to be effective January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel rider on January 1, 2010. DP&L has been deferring a portion of its fuel and purchased power costs that exceed the amount being recovered in rates and that management believes is probable of future recovery. DP&L has not yet been subject to an audit of its fuel rider and as a result there is some uncertainty as to the costs that will be approved for recovery. The fuel audit is conducted by independent third parties in accordance with the PUCO standards. DP&L anticipates that some of this uncertainty will be resolved during the first half of 2011 after completion of the fuel audit. At such time, DP&L may be required to adjust the amount of fuel and purchase power costs that are probable of recovery from its customers. Such an adjustment could be material to our results of operations, financial condition and cash flows.

As a member of PJM, DP&L incurs costs and receives revenues from the RTO related to its transmission and generation assets, as well as its load obligations for retail customers. SB 221 included a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. On February 19, 2009, the PUCO approved DP&L’s request to defer costs associated with its transmission, capacity, ancillary service and other PJM-related charges incurred as a member of PJM. In June 2009, DP&L began recovery of these costs. In a subsequent rehearing process, DP&L was ordered to separate the costs into two separate riders (a TCRR and a PJM RPM rider) which were approved in November 2009. Both the TCRR and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of jurisdictional retail load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching decreases DP&L’s jurisdictional retail load and sales volumes. Therefore, increases in customer switching causes more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation. DP&L’s annual true-up of these two riders was approved by the PUCO by an order dated April 28, 2010. On October 15, 2010 DP&L made an interim adjustment to both the TCRR and the RPM riders that has no material change to the rate recovery amounts.

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

SB 221 Compliance

In December 2009, DP&L and DPLER made several filings relating to their renewable energy and energy efficiency compliance plans. DP&L and DPLER were able to obtain Renewable Energy Credits sufficient to meet their non-solar renewable energy targets, but DP&L and DPLER together obtained only 36% of the separate requirement for 2009 Ohio-based solar resources. The companies asked for a waiver of any unmet 2009 Ohio solar requirements on grounds of force majeure because there were insufficient solar renewable energy credits available from Ohio resources. In March 2010, the PUCO ruled that DP&L’s 2009 Ohio solar target would be reduced to the amount that it had procured, but that any unmet requirement must be added to the 2010 target. The Commission has not yet ruled on DPLER’s filing.

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On April 15, 2010, DP&L made its first annual required filing related to compliance with renewable and advanced energy targets contained in SB 221. Pursuant to PUCO rules, each April 15, electric utilities are required to provide a status report on how the utility met the renewable benchmarks of the previous year, as well as a ten-year plan outlining the utility’s plans to meet future annual renewable targets. DPLER, an electric services company pursuant to Ohio Revised Code, is also required to meet SB 221 renewable benchmarks and therefore filed its first reports on that same day. In addition, on April 15 of each year, each utility that owns an electric generating facility in Ohio must report to the PUCO regarding its greenhouse gas emissions, and plans to reduce those emissions (environmental control plan) as well as a long-term forecast report which includes a plan to provide sufficient resources to meet customer load obligations (resource plan). DP&L’s long-term forecast filing is expected to be set for hearing and a public hearing was held on July 13, 2010. DP&L expects that the need for the Yankee solar facility will be one issue that will be fully addressed through this process. Settlement discussions are on-going.

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

In addition, the rules that became effective December 10, 2009 required that on January 1, 2010, DP&L file an extensive energy efficiency portfolio plan, outlining how DP&L plans to comply with the energy efficiency and demand reduction benchmarks. DP&L filed a separate request for a finding that it had already complied with this requirement in the form of DP&L’s portfolio plan that had been filed in 2008 as part of its electric security plan, which had been approved by the PUCO and is being implemented. On May 19, 2010 the Commission approved in part and denied in part DP&L’s request that the Commission find that it met the 2009 energy efficiency portfolio requirements and directed DP&L to file a measurement and verification plan as well as a market potential study within 60 days of the date of the entry. We made this filing on July 15, 2010. A hearing has been scheduled to occur December 14, 2010 and we believe that the outcome will not be material to our financial condition. Since the energy efficiency and demand response targets get increasingly larger over time, the costs of complying with the SB 221 targets and the PUCO’s implementing rules could have a material impact on our financial condition.

ENVIRONMENTAL MATTERS

DPL, DP&L and our subsidiaries’ facilities and operations are subject to a wide range of environmental regulations and laws by federal, state and local authorities. As well as imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. In the normal course of business, we have investigatory and remedial activities underway at these facilities to comply, or to determine compliance, with such regulations. We record liabilities for losses that are probable of occurring and can be reasonably estimated. As of September 30, 2010, DPL has an immaterial reserve for environmental matters. A portion of this reserve is recorded at MVIC, DPL’s wholly owned captive insurance subsidiary. 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.

The following issues mentioned below are not meant to be exhaustive but to provide insight on our environmental matters that have had significant updates during the nine month period ended September 30, 2010. These issues should be read along with the environmental matters included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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

Land Use and Solid Waste Disposal

During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. DP&L has ash ponds at the Killen, O.H. Hutchings and J.M. Stuart stations which it operates, and also at generating stations operated by others but in which DP&L has an ownership interest. During March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station. In October 2009, USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds and has requested a response. In May 2010, DP&L responded to the USEPA final inspection report with our plans to address the recommendations. At this time, DP&L is not able to predict the cost to address any of the report’s recommendations.

Similarly, in August 2010, USEPA conducted an inspection of the O.H. Hutchings Station ash ponds. The report relating to the inspection has not been received and DP&L is unable to predict the outcome this initiative will have on its operations.

In addition, as a result of the TVA ash pond spill, there has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On October 15, 2009, the USEPA provided a draft rule to the Office of Management and Budget for interagency review. On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion products including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. DP&L is unable at this time to predict the financial impact of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse impact on operations.

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OTHER MATTERS

NERC Audit

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, 2010, Net income for DPL was $86.4 million or $0.74 per share, compared to Net income of $67.9 million or $0.59 per share, for the same period in 2009. All EPS amounts are presented on a diluted share basis. The significant highlights during the three-month period ended September 30, 2010, compared to the same period of the prior year, are comprised of the following:

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

· increased retail sales volumes due to favorable weather and improved economic conditions,

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

· increased wholesale revenues due to higher market prices.

Partially offsetting these items were:

· an increase in purchased power prices,

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

· unscheduled outages at jointly-owned production units which resulted in a decrease in wholesale sales volume and an increase in purchased power volumes,

· an increase in the average cost of fuel due primarily to higher coal prices,

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

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

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

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For the nine months ended September 30, 2010, Net income for DPL was $218.8 million or $1.88 per share, compared to Net income of $179.2 million or $1.58 per share, for the same period in 2009. All EPS amounts are presented on a diluted share basis. The significant highlights during the nine-month period ended September 30, 2010 compared to the same period of the prior year are comprised of the following:

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

· increased sales volumes due to favorable weather and improved economic conditions,

· an overall improvement in generating plant performance which resulted in a decrease in purchased power volumes,

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

· increased wholesale revenues due to higher wholesale sales volumes and market prices.

Partially offsetting these items were:

· an increase in purchased power prices,

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

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

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

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

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

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RESULTS OF OPERATIONS — DPL

DPL’s results of operations include the results of its subsidiaries, including the results of its principal subsidiary DP&L. DP&L provides approximately 95% of the total revenues of DPL. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.

Income Statement Highlights — DPL

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2010			2009			2010			2009

Revenues:
Retail	$	402.6		$	318.8		$	1,099.9		$	921.3
Wholesale	31.2			30.9			110.5			81.5
RTO revenues	23.4			21.5			64.6			68.4
RTO capacity revenues	57.0			33.1			129.7			103.2
Other revenues	2.7			3.0			8.9			9.1
Total revenues	$	516.9		$	407.3		$	1,413.6		$	1,183.5

Cost of revenues:
Fuel costs	$	105.5		$	95.9		$	300.2		$	291.7
Gains from sale of coal	(1.1		)	(10.8		)	(2.4		)	(45.9		)
Gains from sale of emission allowances	(0.1		)	(0.7		)	(0.7		)	(4.1		)
Net fuel	104.3			84.4			297.1			241.7

Purchased power	26.1			7.0			61.1			36.7
RTO charges	33.5			25.9			91.1			78.7
RTO capacity charges	52.9			31.2			121.8			100.3
Recovery / (Deferral) of RTO expenses, net	6.5			0.9			8.7			(27.7		)
Net purchased power	119.0			65.0			282.7			188.0

Total cost of revenues	$	223.3		$	149.4		$	579.8		$	429.7

Gross margins (a)	$	293.6		$	257.9		$	833.8		$	753.8

Gross margin as a percentage of revenues	56.8		%	63.3		%	59.0		%	63.7		%

Operating income	$	144.6		$	116.5		$	379.9		$	325.4

Earnings per share of common stock:
Basic EPS from operations	$	0.75		$	0.60		$	1.89		$	1.60
Diluted EPS from operations	$	0.74		$	0.59		$	1.88		$	1.58

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

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Revenues

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Number of days	2010	2009	2010	2009

Heating degree days (a)	52	75	3,475	3,521
Cooling degree days (a)	849	424	1,225	731

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

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

DPL — Revenues

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

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2010 vs. 2009			2010 vs. 2009

Retail
Rate	$	36.1		$	112.1
Volume	47.0			65.8
Other miscellaneous	0.7			0.7
Total retail change	$	83.8		$	178.6

Wholesale
Rate	$	10.0		$	23.7
Volume	(9.7		)	5.3
Total wholesale change	$	0.3		$	29.0

RTO capacity & other
RTO capacity and other revenues	$	25.5		$	22.5

Total revenues change	$	109.6		$	230.1

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For the three months ended September 30, 2010, Revenues increased $109.6 million to $516.9 million from $407.3 million in the same period of the prior year. This increase was primarily the result of higher average retail and wholesale rates, higher retail sales volume, increased RTO capacity and other revenues, partially offset by lower wholesale sales volume.

· Retail revenues increased $83.8 million resulting primarily from a 15% increase in retail sales volumes compared to those in the prior year period, largely due to more favorable weather and improved economic conditions. Also contributing to the increase in retail revenues was a 10% increase in average retail rates due largely to the implementation of the fuel and energy efficiency riders as well as an increase in the TCRR and RPM rates combined with the incremental effect of the recovery of costs under the EIR. The above resulted in a favorable $47.0 million retail sales volume variance and a favorable $36.1 million retail price variance.

· Wholesale revenues increased $0.3 million primarily as a result of a 47% increase in wholesale average prices partially offset by a 32% decrease in wholesale sales volumes which was largely a result of reduced generation by our power plants. This resulted in a favorable $10.0 million wholesale price variance and an unfavorable wholesale volume variance of $9.7 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DPL’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $25.5 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $23.9 million increase in revenues realized from the PJM capacity auction and a $1.9 million increase in transmission and congestion revenues.

For the nine months ended September 30, 2010, Revenues increased $230.1 million to $1,413.6 million from $1,183.5 million in the same period of the prior year. This increase was primarily the result of higher average retail and wholesale rates, higher retail and wholesale sales volume, and increased RTO capacity and other revenues.

· Retail revenues increased $178.6 million resulting primarily from an 11% increase in average retail rates due largely to the implementation of the fuel and energy efficiency riders, an increase in the TCRR and RPM rates, combined with the incremental effect of the recovery of costs under the EIR. Retail volumes had a 7% increase compared to those in the prior year period largely due to more favorable weather and improved economic conditions. The above resulted in a favorable $112.1 million retail price variance and a favorable $65.8 million retail sales volume variance.

· Wholesale revenues increased $29.0 million primarily as a result of a 27% increase in wholesale average prices combined with a 7% increase in wholesale sales volumes which was largely a result of higher generation by our power plants. This resulted in a favorable $23.7 million wholesale price variance and a favorable wholesale volume variance of $5.3 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DPL’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $22.5 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $26.5 million increase in revenues realized from the PJM capacity auction, partially offset by a $3.8 million decrease in transmission and congestion revenues.

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DPL — Cost of Revenues

For the three months ended September 30, 2010:

· Fuel costs, which include coal, gas, oil and emission allowance costs, increased $19.9 million, or 24%, compared to the same period in 2009, primarily due to an 11% increase in the average cost of fuel consumed per kilowatt-hour due largely to higher coal prices, combined with a $6.4 million increase in gas costs primarily attributable to a higher volume of generation by DPLE-owned peaking units. Also contributing to the increase in fuel costs was the impact of lower gains realized from the sale of DP&L’s coal. During the three months ended September 30, 2010, DP&L realized $1.1 million in gains from the sale of coal compared to $10.8 million realized during the same period in 2009. The effect of these increases was partially offset by an overall 5% decrease in the volume of generation by our plants.

· Purchased power increased $54.0 million, or 83%, compared to the same period in 2009 primarily reflecting an increase of $34.9 million in RTO capacity and other charges, including the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. Also contributing to the higher purchased power costs was an increase of $14.9 million relating to higher average market prices and a $4.2 million increase related to higher purchased power volumes primarily resulting from unscheduled maintenance at some jointly-owned production units. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

For the nine months ended September 30, 2010:

· Fuel costs, which include coal, gas, oil and emission allowance costs, increased $55.4 million, or 23%, compared to the same period in 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the nine months ended September 30, 2010, DP&L realized $2.4 million and $0.7 million in gains from the sale of coal and excess emission allowances, respectively, compared to $45.9 million and $4.1 million, respectively, realized during the same period in 2009. Also contributing to the increase in fuel costs was the impact of a 2% increase in the volume of generation by our plants.

· Purchased power increased $94.7 million, or 50%, compared to the same period in 2009 primarily reflecting the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. During the nine months ended September 30, 2010, DP&L had a net over-recovery of $8.7 million of such costs compared to a net deferral of $27.7 million during the same period in 2009, resulting in a $36.4 million increase to purchased power costs. Also contributing to the higher purchased power costs was an increase of $33.9 million in RTO capacity and other charges as well as a $29.3 million increase relating to higher average market prices over the same period in 2009. The effect of these increases was partially offset by a $4.9 million decrease related to lower purchased power volumes primarily resulting from higher generation at our plants. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

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DPL — Operation and Maintenance

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2010 vs. 2009			2010 vs. 2009
Group insurance / long-term disability	$	4.0		$	10.2
Energy efficiency programs (1)	2.9			9.0
Pension	0.9			3.1
Low-income payment program (1)	1.9			4.0
Generating facilities operating and maintenance expenses	3.2			0.1
Insurance settlement, net	—			(3.4		)
Other, net	(3.8		)	(1.5		)
Total operation and maintenance expense	$	9.1		$	21.5

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

For the three months ended September 30, 2010, Operation and maintenance expense increased $9.1 million, or 12%, compared to the same period in 2009. This variance was primarily the result of:

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

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

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

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

These increases were partially offset by:

· a decrease in Other, net primarily related to an increase in billings to our partners related to increased employee benefit costs for employees at our jointly-owned generation facilities.

For the nine months ended September 30, 2010, Operation and maintenance expense increased $21.5 million, or 9%, compared to the same period in 2009. This variance was primarily the result of:

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

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

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

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

· increased third quarter expenses at our jointly-owned generating facilities as discussed above, almost completely offset by decreases in expense for generating facilities during the first and second quarter largely due to lower maintenance activity.

These increases were partially offset by:

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

· a decrease in Other, net primarily related to an increase in billings to our partners related to increased employee benefit costs for employees at our jointly-owned generation facilities.

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DPL — Depreciation and Amortization

For the three months and nine months ended September 30, 2010, Depreciation and amortization expense decreased $3.9 million and $2.5 million, respectively, as compared to the same periods in 2009. The decrease primarily reflects the impact of lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by $2.4 million during the three months ended September 30, 2010.

DPL — Interest Expense

For the three months ended September 30, 2010, Interest expense decreased $2.0 million compared to the same period in 2009 primarily due to the early payment in December 2009 of $52.4 million of the $195 million 8.125% Note to DPL Capital Trust II. For the nine months ended September 30, 2010, Interest expense decreased $7.7 million primarily due to the payment of DPL’s $175 million 8.00% Senior Notes in March 2009 combined with the early redemption of the Note to DPL Capital Trust II referred to above.

DPL — General Taxes

For the three months and nine months ended September 30, 2010, General taxes increased $2.4 million and $6.5 million, respectively, to $32.6 million and $96.3 million, respectively, as compared to the same periods in 2009. These increases were primarily the result of higher property tax accruals in 2010 compared to 2009, increased state excise taxes due to increased revenue and an adjustment to future credits against state gross receipt taxes.

DPL — Income Tax Expense

For the three and nine months ended September 30, 2010, Income tax expense increased $12.2 million and $22.7 million, respectively, compared to the same periods in 2009 primarily due to increases in pre-tax income and the estimated annual effective tax rate. The increase in the effective tax rate primarily reflects the benefits recorded in 2009 for the Internal Revenue Code Section 199 Domestic Production Deduction and the phase-out of the Ohio Franchise Tax offset by a current quarter Domestic Production Deduction benefit due to a longer net operating loss carry-back period.

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RESULTS OF OPERATIONS — DP&L

Income Statement Highlights — DP&L

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2010			2009			2010			2009

Revenues:
Retail	$	319.8		$	301.8		$	915.2		$	875.8
Wholesale	97.3			47.8			263.2			124.7
RTO revenues	21.6			20.7			60.8			66.0
RTO capacity revenues	48.3			27.9			109.7			87.2
Total revenues	$	487.0		$	398.2		$	1,348.9		$	1,153.7

Cost of revenues:
Fuel costs	$	98.6		$	94.5		$	289.6		$	286.2
Gains from sale of coal	(1.1		)	(10.8		)	(2.4		)	(45.9		)
Gains from sale of emission allowances	(0.1		)	(0.7		)	(0.7		)	(4.1		)
Net fuel	97.4			83.0			286.5			236.2

Purchased power	25.9			6.9			60.9			36.6
RTO charges	31.0			25.6			87.9			77.8
RTO capacity charges	53.0			31.3			121.8			100.4
Recovery / (Deferral) of RTO expenses, net	6.5			0.9			8.7			(27.7		)
Total purchased power	116.4			64.7			279.3			187.1

Total cost of revenues	213.8			147.7			565.8			423.3

Gross margins (a)	$	273.2		$	250.5		$	783.1		$	730.4

Gross margin as a percentage of revenues	56.1		%	62.9		%	58.1		%	63.3		%

Operating Income	$	131.9		$	115.2		$	347.3		$	318.9

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DP&L — Revenues

The following table provides a summary of changes in DP&L’s revenues from the prior period:

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2010 vs. 2009			2010 vs. 2009

Retail
Rate	$	(23.3	)	$	(18.0	)
Volume	40.4			56.2
Other miscellaneous	0.9			1.2
Total retail change	$	18.0		$	39.4

Wholesale
Rate	$	26.0		$	52.2
Volume	23.5			86.3
Total wholesale change	$	49.5		$	138.5

RTO capacity and other
RTO capacity and other RTO revenues	$	21.3		$	17.3

Total revenues change	$	88.8		$	195.2

For the three months ended September 30, 2010, Revenues increased $88.8 million, or 22%, to $487.0 million from $398.2 million in the same period of the prior year. This increase was primarily the result of higher retail and wholesale sales volumes, higher average wholesale prices as well as increased RTO capacity and other revenues, partially offset by lower average retail rates.

· Retail revenues increased $18.0 million resulting primarily from a 14% increase in retail sales volumes compared to those in the prior year period, largely due to more favorable weather and improved economic conditions. Although DP&L had a number of customers that switched their generation service from DP&L to DPLER, an affiliated CRES provider, DP&L continues to provide distribution services to those customers within its service territory. The average retail rates decreased 7% overall primarily as a result of customers switching from DP&L to DPLER for transmission and generation services. The remaining distribution services are billed at a lower rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by the implementation of the fuel and energy efficiency riders, increased TCRR and RPM rates, and the incremental effect of the recovery of costs under the EIR. The above resulted in a favorable $40.4 million retail sales volume variance and an unfavorable $23.3 million retail price variance.

· Wholesale revenues increased $49.5 million primarily as a result of a 37% increase in average wholesale prices combined with a 49% increase in wholesale sales volume, due in large part to the effect of the customer switching discussed in the immediately preceding paragraph. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in a favorable wholesale price variance of $26.0 million and a favorable $23.5 million wholesale 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 $21.3 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $20.4 million increase in revenues realized from the PJM capacity auction, combined with a $0.9 million increase in transmission and congestion revenues.

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For the nine months ended September 30, 2010, Revenues increased $195.2 million, or 17%, to $1,348.9 million from $1,153.7 million in the same period of the prior year. This increase was primarily the result of higher retail and wholesale sales volumes, higher average wholesale prices as well as increased RTO capacity and other revenues, partially offset by lower average retail rates.

· Retail revenues increased $39.4 million primarily as a result of a 7% increase in retail sales volumes compared to those in the prior year period largely due to more favorable weather and improved economic conditions. Average retail rates decreased 2% due primarily to the same reasons discussed under DP&L’s three-month retail revenue analysis above. This resulted in a favorable $56.2 million retail sales volume variance and an unfavorable $18.0 million retail price variance.

· Wholesale revenues increased $138.5 million primarily as a result of a 25% increase in average wholesale prices combined with a 69% increase in wholesale sales volume due in large part to the effect of the customer switching discussed under DP&L’s three-month retail revenue analysis above. DP&L records wholesale revenues from its sale of transmission and generation services to DPLER associated with these switched customers. This resulted in a favorable $86.3 million wholesale sales volume variance and a favorable wholesale price variance of $52.2 million.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $17.3 million compared to the same period in 2009. This increase in RTO capacity and other revenues was primarily the result of a $22.5 million increase in revenues realized from the PJM capacity auction partially offset by a decrease of $5.2 million in transmission and congestion revenues.

DP&L — Cost of Revenues

For the three months ended September 30, 2010:

· Fuel costs, which include coal, gas, oil, and emission allowance costs, increased $14.4 million, or 17%, compared to the same period in 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal. During the three months ended September 30, 2010, DP&L realized $1.1 million in gains from the sale of coal compared to $10.8 million during the same period in 2009. Also contributing to the increase in fuel costs was the impact of an 11% increase in the average cost of fuel consumed per kilowatt-hour due largely to higher coal prices. The effect of these increases was partially offset by a 7% decrease in the volume of generation by our plants.

· Purchased power increased $51.7 million, or 80%, compared to the same period in 2009, primarily reflecting an increase of $32.7 million in RTO capacity and other charges, including the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. Also contributing to the higher purchased power costs was an increase of $14.8 million relating to higher average market prices and a $4.2 million increase related to higher purchased power volumes primarily resulting from unscheduled maintenance at some jointly-owned production units. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

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For the nine months ended September 30, 2010:

· Fuel costs, which include coal, gas, oil, and emission allowance costs, increased $50.3 million, or 21%, compared to the same period in 2009, primarily due to the impact of lower gains realized from the sale of DP&L’s coal and excess emission allowances. During the nine months ended September 30, 2010, DP&L realized $2.4 million and $0.7 million in gains from the sale of coal and excess emission allowances, respectively, compared to $45.9 million and $4.1 million, respectively, during the same period in 2009. Also contributing to the increase in fuel costs was the impact of a 2% increase in the volume of generation by our plants.

· Purchased power increased $92.2 million, or 49%, compared to the same period in 2009, primarily reflecting the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges which were incurred as a member of PJM. During the nine months ended September 30, 2010, DP&L had a net over-recovery of $8.7 million of such costs compared to a net deferral of $27.7 million during the same period in 2009, resulting in a $36.4 million increase to purchased power costs. Also contributing to the higher purchased power costs was an increase of $31.5 million in RTO capacity and other charges as well as a $29.2 million increase relating to higher average market prices over the same period in 2009. The effect of these increases was partially offset by a $4.9 million decrease related to lower purchased power volumes primarily resulting from higher generation at our plants. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

DP&L — Operation and Maintenance

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2010 vs. 2009			2010 vs. 2009
Group insurance / long-term disability	$	4.1		$	10.2
Energy efficiency programs (1)	2.9			9.0
Pension	0.9			3.1
Low-income payment program (1)	1.9			4.0
Generating facilities operating and maintenance expenses	3.2			(1.3		)
Other, net	(5.8		)	(3.6		)
Total operation and maintenance expense	$	7.2		$	21.4

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

For the three months ended September 30, 2010, Operation and maintenance expense increased $7.2 million, or 10%, compared to the same period in 2009. This variance was primarily the result of:

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

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

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

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

These increases were partially offset by:

· a decrease in Other, net primarily related to an increase in billings to our partners related to increased employee benefits costs for employees at our jointly-owned generation facilities.

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For the nine months ended September 30, 2010, Operation and maintenance expense increased $21.4 million, or 10%, compared to the same period in 2009. This variance was primarily the result of:

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

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

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

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

These increases were partially offset by:

· decreased expenses for generating facilities during the first and second quarter largely due to lower maintenance activity at jointly-owned production units which were partially offset by increased third quarter expenses as discussed above, and

· a decrease in Other, net primarily related to an increase in billings to our partners related to increased employee benefits costs for employees at our jointly-owned generation facilities.

DP&L — Depreciation and Amortization

For the three months and nine months ended September 30, 2010, Depreciation and amortization expense decreased $3.2 million and $1.8 million, respectively, as compared to the same periods in 2009. The decrease primarily reflects the impact of lower depreciation rates on generation property which were implemented on July 1, 2010, reducing the expense by $2.4 million during the three months ended September 30, 2010.

DP&L — General Taxes

For the three months and nine months ended September 30, 2010, General taxes increased $2.0 million and $4.7 million, respectively, to $32.2 million and $94.0 million, respectively, compared to the same periods in 2009. These increases were primarily the result of higher property tax accruals in 2010 compared to 2009, increased state excise taxes due to increased revenue and an adjustment to future credits against state gross receipt taxes.

DP&L — Income Tax Expense

For the three months and nine months ended September 30, 2010, Income tax expense increased $8.9 million and $11.8 million, respectively, compared to the same periods in 2009 primarily due to increases in pre-tax income and the estimated annual effective tax rate. The increase in the effective tax rate primarily reflects the benefits recorded in 2009 for the Internal Revenue Code Section 199 Domestic Production Deduction and the phase-out of the Ohio Franchise Tax offset by a current quarter Domestic Production Deduction benefit due to a longer net operating loss carry-back period.

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FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

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

DPL

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Net cash provided by operating activities	$	331.6		$	290.5
Net cash used for investing activities	(160.3		)	(126.7		)
Net cash used for financing activities	(107.1		)	(163.5		)

Net change	$	64.2		$	0.3
Cash and cash equivalents at beginning of period	74.9			62.5
Cash and cash equivalents at end of period	$	139.1		$	62.8

Cash and cash equivalents for DPL amounted to $139.1 million at September 30, 2010. At that date, DPL also had short-term investments amounting to $48.3 million.

DP&L

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Net cash provided by operating activities	$	338.0		$	277.0
Net cash used for investing activities	(110.6		)	(128.2		)
Net cash used for financing activities	(150.6		)	(148.9		)

Net change	$	76.8		$	(0.1	)
Cash and cash equivalents at beginning of period	57.1			20.8
Cash and cash equivalents at end of period	$	133.9		$	20.7

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

Net Cash Provided by Operating Activities

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

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DPL — Net Cash provided by Operating Activities

DPL’s Net cash provided by operating activities for the nine months ended September 30, 2010 and 2009 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Earnings from continuing operations	$	218.8		$	179.2
Depreciation and amortization	105.3			107.8
Deferred income taxes	38.7			96.7
Contributions to pension plan	(40.0		)	—
Regulatory expenditures under TCRR/RPM	8.7			(10.9		)
Other	0.1			(82.3		)
Net cash provided by operating activities	$	331.6		$	290.5

For the nine months ended September 30, 2010, Net cash provided by operating activities was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

· The $38.7 million increase to Deferred income taxes primarily results from a $14.0 million temporary difference due to pension contributions and estimate-to-actual adjustments of depreciation expense, repair expense and other temporary differences arising from routine changes in balance sheet accounts.

· In February 2010, DP&L contributed $20.0 million to the defined benefit pension plan and another $20.0 million in September 2010.

· $8.7 million of cash collected to pay for transmission, capacity and other PJM-related costs incurred during 2010, in excess of cash expenditures. These costs reduced the Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Condensed Consolidated Financial Statements) and are expected to reduce the amount to be collected from customers in future periods.

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

For the nine months ended September 30, 2009, Net cash provided by operating activities was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

· Deferred income taxes increased by $205.5 million. Of that amount, $108.8 million reflects a non-cash entry recorded by DP&L, increasing non-current deferred tax liabilities. The offset to this entry was an increase to current tax receivable of $79.9 million and a reduction of income tax liabilities of $28.9 million. This entry was the result of the recognition of certain tax benefits for the 2008 and 2009 tax years relating to a change in the tax method for deductions pertaining to repairs, depreciation and mixed service costs. The remaining $96.7 million was primarily driven by temporary differences arising from routine changes in balance sheet accounts.

· $10.9 million of cash used to pay for transmission, capacity and other PJM-related costs incurred during the nine months ended September 30, 2009. These costs were recorded as a Regulatory asset in accordance with the provisions of GAAP relating to regulatory accounting (see Note 3 of Notes to Condensed Consolidated Financial Statements) and are expected to be collected from customers during future years.

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DP&L — Net Cash provided by Operating Activities

DP&L’s Net cash provided by operating activities for the nine months ended September 30, 2010 and 2009 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Earnings from continuing operations	$	214.7		$	197.8
Depreciation and amortization	98.4			100.2
Deferred income taxes	36.9			95.9
Contributions to pension plan	(40.0		)	—
Regulatory expenditures under TCRR/RPM	8.7			(10.9		)
Other	19.3			(106.0		)
Net cash provided by operating activities	$	338.0		$	277.0

For the nine months ended September 30, 2010 and 2009, the significant components of DP&L’s Net cash provided by operating activities are similar to those discussed under DPL’s Net cash provided by operating activities above.

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

DPL and DP&L’s Net cash used for investing activities for the nine months ended September 30, 2010 and 2009 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2010			2009

DP&L
Environmental and renewable energy capital expenditures	$	(8.2	)	$	(23.1	)
Other plant-related asset acquisitions, net	(104.1		)	(106.8		)
Other	1.7			1.7
DP&L’s Net cash used for investing activities	$	(110.6	)	$	(128.2	)

DPL
Proceeds from maturity of short-term investments	14.4			15.1
Purchases of short-term investments	(62.7		)	(10.1		)
Other	(1.4		)	(3.5		)
DPL’s Net cash used for investing activities	$	(160.3	)	$	(126.7	)

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

For the nine months ended September 30, 2010, DP&L continued to see reductions in its environmental capital expenditures due to the completion of FGD and SCR projects. The expenditures incurred during 2010 relate primarily to the construction of a solar energy facility at Yankee station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment. During this period, DPL also purchased VRDN securities at a net total of $33 million from various institutional securities brokers as well as $15 million of investment-grade fixed income corporate bonds. The VRDN securities are backed by irrevocable letters of credit. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. DPL can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.

For the nine months ended September 30, 2009, DP&L’s cash outflows associated with environmental-related expenditures primarily relate to FGD and SCR equipment installation. During this period, DPL paid $5.1 million to purchase VRDN securities from various institutional securities brokers. In addition, DPL received $5.0 million from the maturity of its held-to-maturity bond investments and $5.1 million from the tender of the aforementioned purchased VRDN securities.

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DPL — Net Cash used for Financing Activities

DPL’s Net cash used for financing activities for the nine months ended September 30, 2010 and 2009 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Dividends paid on common stock	$	(104.8	)	$	(95.7	)
Repurchase of DPL common stock	(3.9		)	—
Retirement of long-term debt	—			(175.0		)
Repurchase of warrants	—			(15.9		)
Withdrawals from revolving credit facility, net	—			115.0
Withdrawal of restricted funds held in trust	—			6.7
Other	1.6			1.4
Net cash used for financing activities	$	(107.1	)	$	(163.5	)

For the nine months ended September 30, 2010, DPL paid common stock dividends of $104.8 million. In addition, under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 11 of Notes to Condensed Consolidated Financial Statements), DPL repurchased approximately 145,915 DPL common shares for $3.9 million.

For the nine months ended September 30, 2009, DPL retired $175 million of long-term debt, paid common stock dividends of $95.7 million, and repurchased approximately 7.1 million warrants at a total cost of $15.9 million. DPL’s cash inflows included net withdrawals of $115 million from its revolving credit facility and withdrawals of $6.7 million from restricted funds held in trust to pay for environmental-related capital expenditures.

DP&L — Net Cash used for Financing Activities

DP&L’s Net cash used for financing activities for the nine months ended September 30, 2010 and 2009 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2010			2009

Dividends paid on common stock to parent	$	(150.0	)	$	(270.0	)
Withdrawals from revolving credit facility, net	—			115.0
Withdrawal of restricted funds held in trust	—			6.7
Other	(0.6		)	(0.6		)
Net cash used for financing activities	$	(150.6	)	$	(148.9	)

For the nine months ended September 30, 2010, DP&L’s Net cash used for financing activities primarily relates to $150 million in dividends.

For the nine months ended September 30, 2009, DP&L paid $270 million in dividends to DPL and made net withdrawals of $115 million from its revolving credit facility and withdrawals of $6.7 million from restricted funds held in trust to pay for environmental-related capital expenditures.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated obligations. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities, and interest and dividend payments. For 2010 and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

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

					Amounts
					Available at
$ in millions	Type	Maturity	Commitment		September 30, 2010

DP&L	Revolving	November 2011	$	220.0	$	220.0

DP&L	Revolving	April 2013	$	200.0	$	200.0

			$	420.0	$	420.0

Each revolving credit facility has a $50 million LOC sublimit. As of September 30, 2010 and through the date of filing this quarterly report on Form 10-Q, there were no outstanding LOCs on either facility.

Cash and cash equivalents for DPL and DP&L amounted to $139.1 million and $133.9 million, respectively, at September 30, 2010. At that date, DPL also had short-term investments amounting to $48.3 million.

Capital Requirements

DPL’s construction expenditures were $113.7 million and $134.6 million during the nine month periods ended September 30, 2010 and 2009, respectively. DPL is expected to spend approximately $180 million in 2010 on construction additions. Planned construction additions for 2010 relate to DP&L’s environmental compliance program, power plant equipment, and its transmission and distribution system.

DP&L’s construction expenditures were $112.3 million and $129.9 million during the nine month periods ended September 30, 2010 and 2009, respectively. DP&L is expected to spend approximately $175 million in 2010 on construction additions. Planned construction additions for 2010 relate to DP&L’s environmental compliance program, power plant equipment, and its transmission and distribution system.

Capital projects are subject to continuing review and are revised in light of changes in financial and economic conditions, load forecasts, legislative and regulatory developments and changing environmental standards, among other factors. DPL, through its subsidiary DP&L, is projecting to spend an estimated $760 million in capital projects for the period of 2010 through 2012. Approximately $20 million of this projected amount is to enable DP&L to meet the recently revised reliability standards of the North American Electric Reliability Corporation (NERC). DP&L is subject to the mandatory reliability standards of NERC, and ReliabilityFirst Corporation (RFC), one of the eight NERC regions, of which DP&L is a member. NERC has recently changed the definition of the Bulk Electric System (BES) to include 100 kV and above facilities, thus expanding the facilities to which the reliability standards apply. DP&L’s 138 kV facilities were previously not subject to these reliability standards. Accordingly, DP&L anticipates spending approximately $100 million within the next 5 years to reinforce its 138 kV system to comply with these new NERC standards. Our ability to complete capital projects and the reliability of future service will be affected by our financial condition, the availability of internal funds, and the reasonable cost of external funds. We expect to finance our construction additions with a combination of cash on hand, short-term financing, long-term debt, and cash flows from operations.

Debt

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

Debt Covenants

As mentioned above, DP&L has access to $420 million of short-term financing under its two revolving credit facilities. The following financial covenant is contained in each revolving credit facility: DP&L’s total debt to total capitalization ratio is not to exceed 0.65 to 1.00. As of September 30, 2010, this covenant was met with a ratio of 0.39 to 1.00. The above ratio is calculated as the sum of DP&L’s current portion of long-term debt and long-term debt, including its guaranty obligations, divided by the total of DP&L’s shareholders’ equity and total debt including guaranty obligations.

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Credit Ratings

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

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

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

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

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

Off-Balance Sheet Arrangements

DPL — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to DPLE and DPLER on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish DPLE’s and DPLER’s intended commercial purposes. There have been no material changes to our guarantees as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Through September 30, 2010, DPL has not incurred any losses related to the guarantees of DPLE’s and DPLER’s obligations and we believe it is unlikely that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s and DPLER’s obligations.

Commercial Commitments and Contractual Obligations

See Note 14 of Notes to Condensed Consolidated Financial Statements.

MARKET RISK

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

Commodity Pricing Risk

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

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

The following table provides a reconciliation of the changes in the balance of our commodity derivatives included on our balance sheets at September 30, 2010:

$ in millions	2010

Fair Value of Commodity Derivative Contracts:
Outstanding net asset / (liability) at January 1, 2010	$	(1.4	)
Gains / (losses) on settled contracts	3.6
Changes in fair value on contracts still held	(6.2		)
Outstanding net asset / (liability) at September 30, 2010	$	(4.0	)

The impact of the change in the fair values of the commodity derivative contracts between January 1, 2010 and September 30, 2010 is detailed in the table below:

	Nine Months
	Ended
$ in millions	September 30, 2010

Effect on the statements of results of operations:	$	(2.8	)

Effect on the balance sheets:
Accumulated other comprehensive income	$	6.0
Net collateral	(0.8		)
Regulatory liability (net)	—
Partner payable	0.2
Total net change on balance sheets	$	5.4

Total net change	$	2.6

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

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

Approximately 17% of DPL’s and 14% of DP&L’s electric revenues for the three months ended September 30, 2010 and approximately 17% of DPL’s and 15% of DP&L’s electric revenues for the nine months ended September 30, 2010 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

The table below provides the effect on annual Net income as of September 30, 2010, of a hypothetical increase or decrease of 10% in the price per megawatt hour of wholesale power (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER):

$ in millions	DPL		DP&L

Effect of 10% change in price per MWh	$	10.1	$	10.3

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DPL’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs for both the three and nine months ended September 30, 2010 were 35% and in the three and nine months ended September 30, 2009 were 31% and 32%, respectively. DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs were 35% and 35% for both the three and nine months ended September 30, 2010 and in the three and nine months ended September 30, 2009 were 32% and 33%, respectively. We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2010 under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We do not expect to purchase SO2 allowances for 2010; however, the exact consumption of SO2 allowances will depend on market prices for power, availability of our generation units and the actual sulfur content of the coal burned. We may purchase some NOx allowances for 2010 depending on NOx emissions. Fuel costs are impacted by changes in volume and price and are driven by a number of variables including weather, reliability of coal deliveries, scheduled outages and generation plant mix.

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

Effective January 1, 2010, DP&L is allowed to recover its Ohio retail jurisdictional share of fuel and purchased power costs, of approximately 60%, as part of the fuel rider approved by the PUCO. The table below provides the effect on annual Net income as of September 30, 2010, of a hypothetical increase or decrease of 10% adjusted for the approximate 60% recovery in the prices of fuel and purchased power:

$ in millions	DPL		DP&L

Effect of 10% change in fuel and purchased power	$	13.0	$	12.8

Interest Rate Risk

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

We partially hedge against interest rate fluctuations by entering into interest rate swap agreements to effectively fix or limit the interest rate exposure on the underlying financing. As of September 30, 2010, we have entered into interest rate hedging relationships with an aggregate notional amount of $200 million and $160 million related to planned future borrowing activities in calendar year 2011 and calendar year 2013, respectively. We are locking in our exposure to changes in interest rates since we believe the market interest rates at which we will be able to borrow in the future may increase.

The carrying value of DPL’s debt was $1,323.8 million at September 30, 2010, consisting of DP&L’s first mortgage bonds, DP&L’s debt related to tax-exempt pollution control bonds and DPL’s unsecured notes. The fair value of this debt was $1,346.7 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DPL’s debt obligations that are sensitive to interest rate changes:

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Principal Payments and Interest Rate Detail by Contractual Maturity Date

DPL

																	Carrying Value at			Fair Value at
																	September 30,			September 30,
$ in millions	2010			2011			2012		2013			2014		Thereafter			2010 (a)			2010 (a)
Long-term debt

Variable-rate debt	$	100.0		$	—		$	—	$	—		$	—	$	—		$	100.0	(b)	$	100.0
Average interest rate	0.2		%	N/A			N/A		N/A			N/A		N/A			0.2		%

Fixed-rate debt	$	—		$	297.4		$	—	$	470.0		$	—	$	456.4		$	1,223.8		$	1,246.7
Average interest rate	N/A			6.9		%	N/A		5.1		%	N/A		5.8		%	5.8		%

Total																	$	1,323.8		$	1,346.7

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

(b) Shown as current since related LOC facility will expire in December 2010, at which point the bonds are subject to mandatory purchase. Management continues to monitor and evaluate market conditions and is currently in negotiations with a lender to extend the LOC facility before it expires

The carrying value of DP&L’s debt was $883.8 million at September 30, 2010, consisting of its first mortgage bonds and debt tied to tax-exempt pollution control bonds. The fair value of this debt was $881.0 million, based on current market prices or discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The following table provides information about DP&L’s debt obligations that are sensitive to interest rate changes:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

																September 30,			September 30,
$ in millions	2010			2011		2012		2013			2014		Thereafter			2010 (a)			2010 (a)
Long-term debt

Variable-rate debt	$	100.0		$	—	$	—	$	—		$	—	$	—		$	100.0	(b)	$	100.0
Average interest rate	0.2		%	N/A		N/A		N/A			N/A		N/A			0.2		%

Fixed-rate debt	$	—		$	—	$	—	$	470.0		$	—	$	313.8		$	783.8		$	781.0
Average interest rate	1.9		%	N/A		N/A		5.1		%	N/A		4.8		%	5.0		%

Total																$	883.8		$	881.0

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

Debt maturities occurring in 2010 are discussed under FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS.

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Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at September 30, 2010 for which an immediate adverse market movement causes a potential material impact on our financial position, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of September 30, 2010 we did not hold any market risk sensitive instruments which were entered into for trading purposes.

DPL

	Carrying Value at			Fair Value at		One Percent
	September 30,			September 30,		Interest Rate
$ in millions	2010			2010		Risk
Long-term debt

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

Fixed-rate debt	1,223.8			1,246.7		12.5

Total	$	1,323.8		$	1,346.7	$	13.5

DP&L

	Carrying Value at			Fair Value at		One Percent
	September 30,			September 30,		Interest Rate
$ in millions	2010			2010		Risk
Long-term debt

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

Fixed-rate debt	783.8			781.0		7.8

Total	$	883.8		$	881.0	$	8.8

(a) Shown as current since related LOC facility will expire in December 2010, at which point the bonds are subject to mandatory purchase. Management continues to monitor and evaluate market conditions and is currently in negotiations with a lender to extend the LOC facility before it expires

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt, excluding capital lease obligations, primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $1,223.8 million of fixed-rate debt and not on DPL’s financial position or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DP&L’s $100 million variable-rate long-term debt outstanding as of September 30, 2010.

DP&L’s interest rate risk with respect to DP&L’s long-term debt primarily relates to the potential impact a decrease in interest rates of one percentage point has on the fair value of DP&L’s $783.8 million of fixed-rate debt and not on DP&L’s financial position or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100 million variable-rate long-term debt outstanding as of September 30, 2010.

Credit Risk

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

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CRITICAL ACCOUNTING ESTIMATES

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; income taxes; valuation of regulatory assets and liabilities; the valuation of insurance and claims costs; the valuation of assets and liabilities related to employee benefits; and the valuation of contingent and other obligations. Actual results may differ from those estimates. Refer to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 for a complete listing of our critical accounting policies and estimates. As of September 30, 2010, there have been no material changes to these critical accounting policies and estimates.

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ELECTRIC SALES AND REVENUES

	DPL								DP&L (a)
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009		2010		2009		2010		2009
Electric sales (millions of kWh)
Residential	1,515		1,237		4,224		3,862		1,515		1,237		4,224		3,862
Commercial	1,121		961		2,931		2,799		1,086		961		2,875		2,799
Industrial	939		909		2,717		2,522		930		909		2,702		2,522
Other retail	399		353		1,096		1,049		397		353		1,093		1,049
Total retail (a)	3,974		3,460		10,968		10,232		3,928		3,460		10,894		10,232

Wholesale (a)	625		915		2,170		2,039		578		897		2,110		1,975

Total	4,599		4,375		13,138		12,271		4,506		4,357		13,004		12,207

Operating revenues ($ in thousands)
Residential	$	194,510	$	143,668	$	520,599	$	419,528	$	194,495	$	143,668	$	520,571	$	419,528
Commercial	107,503		86,491		289,925		249,133		80,122		85,420		240,130		247,143
Industrial	66,909		61,218		196,780		172,094		24,772		49,569		96,636		140,559
Other retail	30,832		25,324		85,622		74,290		17,314		20,943		50,184		62,181
Other miscellaneous revenues	2,854		2,135		6,949		6,248		3,089		2,168		7,650		6,346
Total retail (a)	402,608		318,836		1,099,875		921,293		319,792		301,768		915,171		875,757

Wholesale (a)	31,124		30,951		110,473		81,534		97,356		47,777		263,236		124,728

RTO revenues	80,384		54,547		194,307		171,578		69,817		48,668		170,501		153,248

Other revenues	2,769		3,025		8,901		9,118		—		—		—		—

Total	$	516,885	$	407,359	$	1,413,556	$	1,183,523	$	486,965	$	398,213	$	1,348,908	$	1,153,733

Electric customers at end of period
Residential	454,783		455,318		454,783		455,318		454,783		455,318		454,783		455,318
Commercial	50,504		50,026		50,504		50,026		50,110		50,026		50,110		50,026
Industrial	1,803		1,773		1,803		1,773		1,770		1,773		1,770		1,773
Other	6,686		6,560		6,686		6,560		6,683		6,560		6,683		6,560

Total	513,776		513,677		513,776		513,677		513,346		513,677		513,346		513,677

(a) DP&L sold 1,338 million kWh and 387 million kWh of power to DPLER (a subsidiary of DPL) during the three months ended September 30, 2010 and 2009, respectively. DP&L sold 3,091 million kWh and 1,099 million kWh of power to DPLER during the nine months ended September 30, 2010 and 2009, respectively. These kWh sales are not included in DP&L wholesale sales volumes in the chart above. These kWh sales also relate to DP&L retail customers within the DP&L service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on DP&L’s Condensed Financial Statements and retail revenues on DPL’s Condensed Consolidated Financial Statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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Item 4. Controls and Procedures

Our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for establishing and maintaining our disclosure controls and procedures. These controls and procedures were designed to ensure that material information relating to us and our subsidiaries are communicated to the CEO and CFO. We evaluated these disclosure controls and procedures as of the end of the period covered by this report with the participation of our CEO and CFO. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective: (i) to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms; and (ii) to ensure that information required to be disclosed by us in the reports that we submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the three months ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II

Item 1 - Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We believe the amounts provided in our Consolidated Financial Statements, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below) and to comply with applicable laws and regulations will not exceed the amounts reflected in our Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2010, cannot be reasonably determined.

Our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and Quarterly Reports on Form 10-Q for the three months ended March 31, 2010 and for the three months ended June 30, 2010, and the Notes to the Consolidated Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in this Item 1 is limited to certain recent developments concerning our legal proceedings, as well as certain new legal proceedings, and should be read in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and our Quarterly Reports on Form 10-Q for the three months ended March 31, 2010 and for the three months ended June 30, 2010.

The following information is incorporated by reference into this Item: (a) information concerning the legal proceedings discussed in Item 1 — Note 14 of Notes to Condensed Consolidated Financial Statements (Unaudited) under the subheading “Air Quality — Litigation Involving Co-Owned Plants” of Part 1 of this Quarterly Report on Form 10-Q and (b) information concerning the legal proceedings discussed in Item 2 of Part 1 of this Quarterly Report on Form 10-Q — under the heading OHIO REGULATORY MATTERS, the heading OTHER MATTERS, and the subheading “Land Use and Solid Waste Disposal” under the heading ENVIRONMENTAL MATTERS.

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Item 1A — Risk Factors

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in our stock is provided in our most recent Annual Report on Form 10-K. The Form 10-K may be obtained as discussed on Page 6 of this report. If any of these events occur, our business, financial position or results of operation could be materially affected.

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

None

Item 3 — Defaults Upon Senior Securities

None

Item 4 — Removed and Reserved

Item 5 — Other Information

None

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Item 6 — Exhibits

		Exhibit
DPL Inc.	DP&L	Number	Exhibit	Location
X	X	10(a)*	Separation Agreement dated as of September 17, 2010, by and between DPL Inc. and The Dayton Power and Light Company and Douglas C. Taylor	Filed herewith as Exhibit 10(a)

X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)

X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)

	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)

	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)

X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)

X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)

	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)

	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)

X	X	101.INS	XBRL Instance	Furnished herewith as Exhibit 101.INS

X	X	101.SCH	XBRL Taxonomy Extension Schema	Furnished herewith as Exhibit 101.SCH

X	X	101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Furnished herewith as Exhibit 101.CAL

X	X	101.DEF	XBRL Taxonomy Extension Definition Linkbase	Furnished herewith as Exhibit 101.DEF

X	X	101.LAB	XBRL Taxonomy Extension Label Linkbase	Furnished herewith as Exhibit 101.LAB

X	X	101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Furnished herewith as Exhibit 101.PRE

* Management contract or compensatory plan.

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SIGNATURES

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

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


Date:	October 28, 2010	/s/ Paul M. Barbas
		Paul M. Barbas President and Chief Executive Officer (principal executive officer)


	October 28, 2010	/s/ Frederick J. Boyle
		Frederick J. Boyle Senior Vice President, Chief Financial Officer, and Treasurer (principal financial officer)


	October 28, 2010	/s/ Joseph W. Mulpas
		Joseph W. Mulpas Vice President, Controller and Chief Accounting Officer
		(principal accounting officer)