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

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

For the quarterly period ended ~~March 31,~~June 30, 2012

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

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

For the transition period from to

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

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

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

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

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

(Registrants are voluntary filers that have filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 in the preceding 12 months.)

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

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

All of the outstanding common stock of DPL Inc. is indirectly owned by The AES Corporation. All of the common stock of The Dayton Power and Light Company is owned by DPL Inc.

As of ~~March 31,~~June 30, 2012, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, no par value	1

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

Documents incorporated by reference: None

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

Table of Contents

DPL Inc. and The Dayton Power and Light Company

Index

		Page No.

Glossary of Terms			4

Part I Financial Information


	Item 1	Financial Statements — DPL Inc. and The Dayton Power &and Light Company(Unaudited)

		DPL Inc.

		Condensed Consolidated Statements of Results of Operations	10

		Condensed Consolidated Statements of Comprehensive Income (Loss)	11

		Condensed Consolidated Statements of Cash Flows	12

		Condensed Consolidated Balance Sheets	13

		Notes to Condensed Consolidated Financial Statements	15

		The Dayton Power and Light Company

		Condensed Statements of Results of Operations	4753

		Condensed Statements of Comprehensive Income (Loss)	4854

		Condensed Statements of Cash Flows	4955

		Condensed Balance Sheets	5056

		Notes to Condensed Financial Statements	5258

	Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	7787

		Electric Sales and Revenues	~~107~~121

	Item 3	Quantitative and Qualitative Disclosures about Market Risk	~~107~~121

	Item 4	Controls and Procedures	~~108~~122

Part II Other Information


	Item 1	Legal Proceedings	~~108~~122

	Item 1A	Risk Factors	~~108~~122

	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	~~110~~124

	Item 3	Defaults Upon Senior Securities	~~110~~124

	Item 4	Mine Safety Disclosures	~~110~~124

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DPL Inc. and The Dayton Power and Light Company

Index (cont.)

	Item 5	Other Information	~~110~~124

	Item 6	Exhibits	~~111~~125

Other

Signatures		127

	~~Signatures~~		~~113~~

	Certifications		130

Table of Contents

GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition

AES		The AES Corporation, a global power company, the ultimate parent company of DPL

AMI		Advanced Metering Infrastructure

AOCI		Accumulated Other Comprehensive Income

ARO		Asset Retirement Obligation

ASU		Accounting Standards Update

CFTC		Commodity Futures Trading Commission

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CSAPR		Cross-State Air Pollution Rule

CSP		Columbus Southern Power Company, a subsidiary of American Electric Power Company, Inc. (“AEP”). Columbus Southern Power Company merged into the Ohio Power Company, another subsidiary of AEP, effective December 31, 2011

CO2		Carbon Dioxide

CCEM		Customer Conservation and Energy Management

CRES		Competitive Retail Electric Service

DPL		DPL Inc.

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 which sells competitive electric energy and other energy services

DP&L		The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility which sells electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio

Duke Energy		Duke Energy Ohio, Inc., formerly The Cincinnati Gas & Electric Company (CG&E)

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

ESP 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.

FASB		Financial Accounting Standards Board

FASC		FASB Accounting Standards Codification

FASC 805		FASB Accounting Standards Codification 805, “Business Combinations”

Table of Contents

GLOSSARY OF TERMS (cont.)

Abbreviation or Acronym		Definition

FERC		Federal Energy Regulatory Commission

FGD		Flue Gas Desulfurization

Form 10-K		DPL’s and DP&L’s combined Annual Report on Form 10-K/A for the fiscal year ending December 31, 2011, which was filed on March 28, 2012

FTRs		Financial Transmission Rights

~~Table of Contents~~

~~GLOSSARY OF TERMS (CONT.)~~

~~Abbreviation or Acronym~~		~~Definition~~

GAAP		Generally Accepted Accounting Principles in the United States of America

GHG		Greenhouse Gas

IFRS		International Financial Reporting Standards

kWh		Kilowatt hours

MC Squared		MC Squared Energy Services, LLC, a retail electricity supplier wholly owned by DPLER which was purchased on February 28, 2011

Merger		The merger of DPL and Dolphin Sub, Inc. (a wholly owned subsidiary of AES) in accordance with the terms of the Merger agreement. At the Merger date, Dolphin Sub, Inc. was merged into DPL, leaving DPL as the surviving company. As a result of the Merger, DPL became a wholly owned subsidiary of AES.

Merger agreement		The Agreement and Plan of Merger dated April 19, 2011 among DPL, The AES Corporation (“AES”), and Dolphin Sub, Inc., a wholly owned subsidiary of AES, whereby AES agreed to acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of existing debt. Upon closing, DPL became a wholly owned subsidiary of AES.

Merger date		November 28, 2011, the date of the closing of the merger of DPL and Dolphin Sub, Inc., a wholly owned subsidiary of AES.

MRO		Market Rate Option, a plan available to be filed with the PUCO pursuant to Ohio law

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 and, in some cases, insurance services to partner companies related to jointly owned facilities operated by DP&L

NERC		North American Electric Reliability Corporation

NOV		Notice of Violation

NOx		Nitrogen Oxide

NPDES		National Pollutant Discharge Elimination System

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

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GLOSSARY OF TERMS (cont.)

Abbreviation or Acronym		Definition

PJM		PJM Interconnection, LLC, a regional transmission organization

Predecessor		DPL prior to November 28, 2011, the date AES acquired DPL

PRP		Potentially Responsible Party

PUCO		Public Utilities Commission of Ohio

RSU		Restricted Stock Units

RTO		Regional Transmission Organization

~~Table of Contents~~

~~GLOSSARY OF TERMS (cont.)~~

~~Abbreviation or Acronym~~		~~Definition~~

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 ESP or MRO 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

SERP		Supplemental Executive Retirement Plan

SO2		Sulfur Dioxide

SO3		Sulfur Trioxide

SSO		Standard Service Offer which represents the regulated rates, authorized by the PUCO, charged to DP&L retail customers within DP&L’s service territory

Successor		DPL after its acquisition by AES

TCRR		Transmission Cost Recovery Rider

USEPA		U.S. Environmental Protection Agency

USF		Universal Service Fund

VRDN		Variable Rate Demand Note

Table of Contents

This report includes the combined filing of DPL and DP&L. On November 28, 2011, DPL became a wholly owned subsidiary of AES, a global power company. 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.

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. 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 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; costs related to the Merger and the effects of any disruption from the Merger that may make it more difficult to maintain relationships with employees, customers, other business partners or government entities; 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. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

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.

COMPANY WEBSITES

DPL’s public internet site is http://www.dplinc.com. DP&L’s public internet site is http://www.dpandl.com. The information on these websites is not incorporated by reference into this report.

Table of Contents

Part I — Financial Information

This report includes the combined filing of DPL and DP&L. 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.

Item 1 — Financial Statements

Table of Contents

FINANCIAL STATEMENTS

DPL INC.

Table of Contents

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
$ in millions except per share amounts	Successor			Predecessor			Successor			Predecessor			Successor			Predecessor

Revenues	$	434.0		$	480.6		$	382.0		$	433.3		$	816.0		$	913.9

Cost of revenues:
Fuel	97.4			99.7			71.6			92.1			169.0			191.9
Purchased power	94.8			120.8			80.3			113.6			175.1			234.4
Amortization of intangibles	27.8			—			28.6			—			56.4			—
Total cost of revenues	220.0			220.5			180.5			205.7			400.5			426.3

Gross margin	214.0			260.1			201.5			227.6			415.5			487.6

Operating expenses:
Operation and maintenance	101.7			99.3			103.8			106.8			205.5			206.2
Depreciation and amortization	31.4			35.1			29.7			35.1			61.1			70.2
General taxes	21.7			24.8			21.3			19.9			43.0			44.6
Total operating expenses	154.8			159.2			154.8			161.8			309.6			321.0

Operating income	59.2			100.9			46.7			65.8			105.9			166.6

Other income / (expense), net:
Investment income	0.1			0.1			0.2			0.1			0.3			0.2
Interest expense	(29.6		)	(16.9		)	(32.4		)	(17.6		)	(62.0		)	(34.5		)
Charge for early redemption of debt	—			(15.3		)	—			—			—			(15.3		)
Other income / (deductions)	(0.3		)	(0.5		)	(0.9		)	(0.3		)	(1.2		)	(0.7		)
Total other income / (expense), net	(29.8		)	(32.6		)	(33.1		)	(17.8		)	(62.9		)	(50.3		)

Earnings before income tax	29.4			68.3			13.6			48.0			43.0			116.3

Income tax expense	7.7			24.8			8.7			16.3			16.4			41.1

Net income	$	21.7		$	43.5		$	4.9		$	31.7		$	26.6		$	75.2

Average number of common shares outstanding (millions):
Basic	N/A			114.0			N/A			114.2			N/A			114.1
Diluted	N/A			114.5			N/A			114.9			N/A			114.7

Earnings per share of common stock:
Basic	N/A			$	0.38		N/A			$	0.28		N/A			$	0.66
Diluted	N/A			$	0.38		N/A			$	0.28		N/A			$	0.66

Dividends paid per share of common stock	N/A			$	0.3325		N/A			$	0.3325		N/A			$	0.6650

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
$ in millions	Successor			Predecessor			Successor			Predecessor			Successor			Predecessor

Net income (loss)	$	21.7		$	43.5		$	4.9		$	31.7		$	26.6		$	75.2

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax expense of $(0.2) and $0.0, respectively	0.4			—
Change in fair value of available-for-sale securities, net of income base benefit / (expense) of $0.1 and $0.0, respectively, for the three months and $(0.2) and $0.0, respectively for the six months							(0.1		)	—			0.3			—

Total change in fair value of available-for-sale securities	0.4			—			(0.1		)	—			0.3			—

Derivative activity:
Change in derivative fair value, net of income tax expense of $(4.2) and $(1.1), respectively	7.6			2.1
Reclassification of earnings, net of income tax (expense) / benefit of $0.6 and $0.2, respectively	(0.9		)	(0.9		)
Change in derivative fair value, net of income tax expense of $7.4 and $6.0, respectively, for the three months and $3.3 and $5.4, respectively, for the six months							(13.4		)	(11.3		)	(5.8		)	(10.1		)
Reclassification of earnings, net of income tax (expense) / benefit of $0.0 and $(1.0), respectively, for the three months and $0.7 and $(1.3), respectively, for the six months							0.1			1.3			(0.8		)	1.3

Total change in fair value of derivatives	6.7			1.2			(13.3		)	(10.0		)	(6.6		)	(8.8		)

Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $(0.0) and $0.4, respectively	—			1.2
Reclassification to earnings, net of income tax benefit / (expense) of $0.0 and $(0.3), respectively, for the three months and $0.0 and $(0.8), respectively for the six months							(0.1		)	0.4			(0.1		)	1.6

Total change in unfunded pension obligation	—			1.2			(0.1		)	0.4			(0.1		)	1.6

Other comprehensive income / (loss)	7.1			2.4			(13.5		)	(9.6		)	(6.4		)	(7.2		)

Net comprehensive income / (loss)	$	28.8		$	45.9		$	(8.6	)	$	22.1		$	20.2		$	68.0

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended						Six Months Ended
	March 31,						June 30,
	2012			2011			2012			2011
$ in millions	Successor			Predecessor			Successor			Predecessor
Cash flows from operating activities:
Net income	$	21.7		$	43.5		$	26.6		$	75.2
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	31.4			35.1			61.1			70.2
Amortization of other assets	27.8			—			56.4			—
Amortization of debt market value adjustments	(4.7		)				(9.5		)	—
Deferred income taxes	(9.2		)	33.7			(6.9		)	37.5
Charge for early redemption of debt	—			15.3			—			15.3
Changes in certain assets and liabilities:
Accounts receivable	(3.4		)	11.9			9.6			19.5
Inventories	(0.6		)	1.3			(1.2		)	1.2
Prepaid taxes							0.3			(20.7		)
Taxes applicable to subsequent years	22.9			15.9			40.7			31.8
Deferred regulatory costs, net	7.2			12.8			0.1			8.9
Accounts payable	(1.8		)	(5.1		)	7.9			(5.9		)
Accrued taxes payable	(21.6		)	(28.4		)	(50.6		)	(33.4		)
Accrued interest payable	29.1			(1.2		)	1.5			2.0
Pension, retiree and other benefits	2.1			(41.2		)	4.6			(42.7		)
Unamortized investment tax credit	—			(0.7		)	(0.1		)	(1.4		)
Insurance and claims costs	0.8			2.2			—			3.7
Other	(7.1		)	(3.1		)	2.6			23.9
Net cash provided by operating activities	94.6			92.0			143.1			185.1

Cash flows from investing activities:
Capital expenditures	(54.0		)	(43.0		)	(110.5		)	(91.4		)
Purchase of MC Squared	—			(8.2		)	—			(8.2		)
Purchases of short-term investments and securities	—			(1.7		)	—			(1.7		)
Sales of short-term investments and securities	—			60.8			—			70.9
Other investing activities, net	—			2.1			—			1.8
Net cash (used for) / provided by investing activities	(54.0		)	10.0			(110.5		)	(28.6		)

Cash flows from financing activities:
Dividends paid on common stock	(45.0		)	(37.8		)	(45.0		)	(76.4		)
Contributions to additional paid-in capital from parent	2.0			—			0.3			—
Payment to former warrant holders	(9.0		)	—			(9.0		)	—
Retirement of long-term debt							(0.1		)	—
Early redemption of Capital Trust II notes	—			(122.0		)	—			(122.0		)
Premium paid for early redemption of debt	—			(12.2		)	—			(12.2		)
Payment of MC Squared debt	—			(13.5		)	—			(13.5		)
Withdrawals from revolving credit facilities	—			50.0			—			50.0
Repayment of borrowing from revolving credit facilities	—			(20.0		)	—			(50.0		)
Exercise of stock options							—			1.4
Exercise of warrants							—			14.7
Tax impact related to exercise of stock options							—			0.3
Net cash (used for) / provided by financing activities	(52.0		)	(155.5		)	(53.8		)	(207.7		)

Cash and cash equivalents:
Net change	(11.4		)	(53.5		)	(21.2		)	(51.2		)
Balance at beginning of period	173.5			124.0			173.5			124.0
Cash and cash equivalents at end of period	$	162.1		$	70.5		$	152.3		$	72.8

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	5.7		$	18.1		$	66.7		$	30.3
Income taxes paid, net	$	7.0		$	—		$	21.6		$	24.7
Non-cash financing and investing activities:
Accruals for capital expenditures	$	24.1		$	18.3		$	25.3		$	22.6
Long-term liability incurred for purchase of plant assets	$	—		$	18.7		$	—		$	18.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At			At			At
	March 31,			December 31,			June 30,			December 31,
	2012			2011			2012			2011
$ in millions	Successor						Successor
ASSETS

Current assets:
Cash and cash equivalents	$	162.1		$	173.5		$	152.3		$	173.5
Accounts receivable, net (Note 3)	224.4			219.1			208.1			219.1
Inventories (Note 3)	126.4			125.8			127.0			125.8
Taxes applicable to subsequent years	53.6			76.5			35.8			76.5
Regulatory assets, current (Note 4)	15.2			20.2			22.3			20.8
Other prepayments and current assets	37.5			36.2			35.2			36.2
Total current assets	619.2			651.3			580.7			651.9

Property, plant and equipment:
Property, plant and equipment	2,482.3			2,431.0			2,481.6			2,316.9
Less: Accumulated depreciation and amortization	(41.1		)	(7.5		)	(120.3		)	(7.5		)
	2,441.2			2,423.5			2,361.3			2,309.4

Construction work in process	151.1			152.3			145.2			152.3
Total net property, plant and equipment	2,592.3			2,575.8			2,506.5			2,461.7

Other noncurrent assets:
Regulatory assets, non-current (Note 4)	172.9			177.8			170.9			177.8
Goodwill	2,489.3			2,489.3			2,559.1			2,559.1
Intangible assets, net of amortization	133.8			161.5			111.9			165.4
Other deferred assets	49.3			51.8			42.3			51.8
Total other noncurrent assets	2,845.3			2,880.4			2,884.2			2,954.1

Total Assets	$	6,056.8		$	6,107.5		$	5,971.4		$	6,067.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

March 31,

December 31,

June 30,

December 31,

2012

2011

2012

2011

$ in millions

Successor

$ in millions

Successor

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:

Current portion - long-term debt (Note 6)

0.4

0.4

Current portion - long-term debt (Note 6)

0.4

0.4

Accounts payable

103.3

111.1

Accounts payable

111.0

111.1

Accrued taxes

94.7

76.3

Accrued taxes

64.9

76.3

Accrued interest

59.5

30.2

Accrued interest

32.0

30.2

Customer security deposits

16.4

15.9

Customer security deposits

16.5

15.9

Regulatory liabilities, current (Note 4)

—

0.6

Regulatory liabilities, current (Note 4)

—

0.5

Dividends payable

25.0

—

Insurance and claims costs

15.0

14.2

Insurance and claims costs

14.2

14.2

Other current liabilities

48.7

56.1

Other current liabilities

55.0

56.1

Total current liabilities

338.0

304.8

Total current liabilities

319.0

304.7

Noncurrent liabilities:

Long-term debt (Note 6)

2,624.1

2,628.9

Long-term debt (Note 6)

2,619.2

2,628.9

Deferred taxes (Note 7)

543.1

549.4

Deferred taxes (Note 7)

499.0

510.5

Taxes payable

56.4

96.9

Regulatory liabilities, non-current (Note 4)

118.5

118.6

Regulatory liabilities, non-current (Note 4)

118.2

118.6

Pension, retiree and other benefits

47.7

47.5

Pension, retiree and other benefits

47.2

47.5

Derivative liability

42.2

36.9

Unamortized investment tax credit

3.7

3.6

Unamortized investment tax credit

3.5

3.6

Other deferred credits

146.8

205.6

Other deferred credits

68.0

71.0

Total noncurrent liabilities

3,483.9

3,553.6

Total noncurrent liabilities

3,453.7

3,513.9

Redeemable preferred stock of subsidiary

18.4

18.4

Redeemable preferred stock of subsidiary

18.4

18.4

Commitments and contingencies (Note 13)

Common shareholder’s equity:

Common stock:

Successor

No par value

Successor

March 31, 2012

December 31, 2011

No par value

June 30, 2012

December 31, 2011

Shares authorized

1,500

Shares issued

Shares outstanding

—

Other paid-in capital

2,239.3

2,237.3

Other paid-in capital

2,236.6

2,237.3

Accumulated other comprehensive income / (loss)

6.7

(0.4

)

Accumulated other comprehensive income / (loss)

(6.8

)

(0.4

)

Retained earnings / (deficit)

(29.5

)

(6.2

)

Retained earnings / (deficit)

(49.5

)

(6.2

)

Total common shareholder’s equity

2,216.5

2,230.7

Total common shareholder’s equity

2,180.3

2,230.7

Total Liabilities and Shareholder’s Equity

6,056.8

6,107.5

Total Liabilities and Shareholder’s Equity

5,971.4

6,067.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

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 two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared. Refer to Note 14 for more information relating to these reportable segments.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly owned subsidiary of AES. See Note 2.

DP&L is a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and 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.

DPLER sells competitive retail electric service, under contract, to residential, commercial and industrial customers. DPLER’s operations include those of its wholly owned subsidiary, MC Squared, which was acquired on February 28, 2011. DPLER has ~~more than 45,000~~approximately 70,000 customers currently located throughout Ohio and Illinois. DPLER does not own any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations. DPLER’s sales reflect the general economic conditions and seasonal weather patterns of the ~~area.~~areas it serves.

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity 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.

DP&L’s electric transmission and distribution businesses are subject to rate regulation by federal and state regulators while its generation business is deemed competitive under Ohio law. Accordingly, DP&L applies the accounting standards for regulated operations to its electric transmission and distribution businesses and records regulatory assets when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost recoveries in customer rates relate to expected future costs.

DPL and its subsidiaries employed ~~1,494~~1,493 people as of ~~March 31,~~June 30, 2012, of which ~~1,450~~1,446 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

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. DP&L’s undivided ownership interests in certain coal-fired generating plants are included in the financial statements at amortized cost, which was adjusted to fair value at the Merger ~~date.~~date for DPL Inc. Operating revenues and expenses are included on a pro-rata basis in the corresponding lines in the Condensed Consolidated Statement of Operations. See Note 5 for more information.

Certain excise taxes collected from customers have been reclassified out of operating expenses in the 2011 presentation to conform to AES’ presentation of these items. These taxes are presented net within revenue. Certain immaterial amounts from prior periods have been reclassified to conform to the current reporting presentation.

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All material intercompany accounts and transactions are eliminated in consolidation.

These financial statements have been prepared in accordance with GAAP for interim financial statements and with the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our Form 10-K for the fiscal year ended December 31, 2011.

In the opinion of our management, the Condensed Consolidated Financial Statements presented in this report contain all adjustments necessary to fairly state our financial condition as of ~~March 31,~~June 30, 2012; our results of operations for the three and six months ended ~~March 31,~~June 30, 2012 and our cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2012. 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 six months ended ~~March 31,~~June 30, 2012 may not be indicative of our results that will be realized for the full year ending December 31, 2012.

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; assets and liabilities related to employee benefits; goodwill; and intangibles.

On November 28, 2011, AES completed the Merger with DPL. As a result of the Merger, DPL is an indirectly wholly owned subsidiary of AES. DPL’s basis of accounting incorporates the application of FASC 805, “Business Combinations” (FASC 805) as of the date of the Merger. FASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the Merger date. DPL’s Condensed Consolidated Financial Statements and accompanying footnotes have been segregated to present pre-merger activity as the “Predecessor” Company and post-merger activity as the “Successor” Company. Purchase accounting impacts, including goodwill recognition, have been “pushed down” to DPL, resulting in the assets and liabilities of DPL being recorded at their respective fair values as of November 28, 2011. These adjustments are subject to change as AES finalizes its purchase price allocation during the applicable measurement period.

As a result of the push down accounting, DPL’s Condensed Consolidated Statements of Operations subsequent to the Merger include amortization expense relating to purchase accounting adjustments and depreciation of fixed assets based upon their fair value. Therefore, the DPL financial data prior to the Merger will not generally be comparable to its financial data subsequent to the Merger.

DPL remeasured the carrying amount of all of its assets and liabilities to fair value, which resulted in the recognition of approximately ~~$2,489.3~~$2,559.1 million of goodwill. FASC 350, “Intangibles — Goodwill and Other,” requires that goodwill be tested for impairment at the reporting unit level at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions; changes to our operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass its effect to customers; negative or declining cash flows; loss of a key contract or customer, particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.

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As part of the purchase accounting, values were assigned to various intangible assets, including customer relationships, customer contracts and the value of our ~~electric security plan.~~ESP.

Sale of Receivables

In the first quarter of 2012, DPLER began selling receivables from DPLER customers in Duke Energy’s territory to Duke Energy. These sales are at face value for cash at the billed amounts for DPLER customers’ use of energy. There is no recourse or any other continuing involvement associated with the sold receivables. Total receivables sold during the three and six months ended ~~March 31,~~June 30, 2012 ~~was $2.0 million.~~were $4.0 million and $5.2 million, respectively.

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. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was ~~$1.4~~$1.2 million and $1.1 million during the three months and $2.6 million and $2.2 million during the six months ended ~~March 31,~~June 30, 2012 and 2011, respectively.

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

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

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

Intangibles

Intangibles include emission allowances, renewable energy credits, customer relationships, customer contracts and the value of our ESP. Emission allowances are carried on a first-in, first-out (FIFO) basis for purchased emission allowances. In addition, we recorded emission allowances at their fair value as of the Merger date. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. During the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011, ~~DP&L~~DPL had no gains for the sale of emission allowances. Beginning in January 2010, part of the gains on emission allowances were used to reduce the overall fuel rider charged to our SSO retail customers.

Customer relationships recognized as part of the purchase accounting associated with the Merger are amortized over ~~nine~~ten to ~~fifteen~~seventeen years and customer contracts are amortized over the average length of the contracts. The ESP is amortized over one year on a straight-line basis. Emission allowances are amortized as they are used in our operations on a FIFO basis. Renewable energy credits are amortized as they are used or retired.

Prior to the Merger date, emission allowances and renewable energy credits were carried as inventory. Emission allowances and renewable energy credits are now carried as intangibles in accordance with AES’ policy. The amounts for 2011 have been reclassified to reflect this change in presentation.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

DPL collects certain excise taxes levied by state or local governments from its customers. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and recorded as a reduction in revenues for presentation in accordance with AES policy. The amounts for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~$13.2~~$11.9 million and ~~$14.0~~$11.6 million, respectively. The amounts for the six months ended June 30, 2012 and 2011 were $24.8 million and $25.7 million, respectively. The 2011 ~~amount was~~amounts were reclassified to conform to this presentation.

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Share-Based Compensation

We measure the cost of employee services received and paid with equity instruments based on the fair-value of such equity instrument on the grant date. This cost is recognized in results of operations over the period that employees are required to provide service. Liability awards are initially recorded based on the fair-value of equity instruments and are to be re-measured for the change in stock price at each subsequent reporting date until the liability is ultimately settled. The fair-value for employee share options and other similar instruments at the grant date are estimated using option-pricing models and any excess tax benefits are recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits is presented in the Condensed Consolidated Statements of Cash Flows within Cash flows from financing activities. As a result of the Merger (see Note 2), vesting of all DPL share-based awards was accelerated as of the Merger date, and none are in existence at ~~March 31,~~June 30, 2012.

Recently Issued Accounting Standards

Offsetting Assets and Liabilities

In December 2011, the FASB issued ASU 2011-11 “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) effective for interim and annual reporting periods beginning on or after January 1, 2013. We expect to adopt this ASU on January 1, 2013. This standard updates FASC ~~Topic~~ 210, “Balance Sheet.” ASU 2011-11 updates the disclosures for financial instruments and derivatives to provide more transparent information around the offsetting of assets and liabilities. Entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and/or subject to an agreement similar to a master netting agreement. We do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.

Recently Adopted Accounting Standards

Fair Value Disclosures

In May 2011, the FASB issued ASU 2011-04 “Fair Value Measurements” (ASU 2011-04) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 820, “Fair Value Measurements.” ASU 2011-04 essentially converges US GAAP guidance on fair value with the IFRS guidance. The ASU requires more disclosures around Level 3 inputs. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts. These new rules did not have a material effect on our overall results of operations, financial position or cash flows.

Comprehensive Income

In June 2011, the FASB issued ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 220, “Comprehensive Income.” ASU 2011-05 essentially converges US GAAP guidance on the presentation of comprehensive income with the IFRS guidance. The ASU requires the presentation of comprehensive income in one continuous financial statement or two separate but consecutive statements. Any reclassification adjustments from other comprehensive income to net income are required to be presented on the face of the Statement of Comprehensive Income. These new rules did not have a material effect on our overall results of operations, financial position or cash flows.

Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08 “Testing Goodwill for Impairment” (ASU 2011-08) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC 350, “Intangibles-Goodwill and Other.” ASU 2011-08 allows an entity to first test Goodwill using qualitative factors to determine if it is more likely than not that the fair value of a reporting unit has been impaired; if so, then the two-step impairment test is performed. We will incorporate these new requirements in our future goodwill impairment testing.

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2.Business Combination

On November 28, 2011, AES completed its acquisition of DPL. AES paid cash consideration of approximately $3,483.6 million. The allocation of the purchase price was based on the estimated fair value of assets acquired and liabilities assumed. In addition, Dolphin Subsidiary II, Inc. (a wholly owned subsidiary of AES) issued $1,250.0 million of debt, which, as a result of the merger of DPL and Dolphin Subsidiary II, Inc. was assumed by DPL. ~~As of March 31, 2012, there have been no changes to the preliminary valuations assigned to the~~

The assets acquired and liabilities assumed in the acquisition have been recorded at provisional amounts based on the ~~Merger date. It is likely~~preliminary purchase price allocation. We are in the process of obtaining the following additional information that could impact the purchase price allocation within the measurement period, which could be up to one year from the date of acquisition: discount rates; energy price curves, dispatching assumptions, and contractual arrangements associated with jointly owned plants, all of which could affect the value of the generation business property, plant and equipment; assumptions around customer switching and aggregation, which could affect the value of intangible assets; assumptions on the valuation of regulatory assets and liabilities; deferred income taxes; and the determination of reporting units. If materially different from the final amounts, such provisional amounts will be retrospectively adjusted to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Additionally, key input assumptions and their sensitivity to the valuation of assets acquired and liabilities assumed are continuing to be reviewed by management, which may result in requiring additional information related to these key input assumptions.

During the three months ended June 30, 2012, we recognized a decrease of $114.1 million in the provisional value of property, plant and equipment and a related decrease of $38.9 million in the ~~intangible asset related~~provisionally recognized deferred tax liabilities as a result of additional information associated with growth and ancillary revenue assumptions. Additionally, we recognized an increase of $3.9 million for certain customer contracts of DPLER and other intangibles due to ~~the ESP with its regulated customers and long-term coal contracts, the 4.9% equity ownership interest in OVEC, and deferred taxes could change as the valuation process is finalized. DPLER,~~ ~~DPL’s~~ ~~wholly owned CRES provider, will also likely have changes in its initial~~additional contractual information obtained during this quarter. These purchase price ~~allocation~~adjustments increased the provisionally recognized goodwill by $69.8 million and have been reflected retrospectively as of December 31, 2011 in the accompanying Condensed Consolidated Balance Sheets. The effect on net income for the ~~valuation of its intangible assets~~six months ended June 30, 2012 was $1.7 million. The effect on net income for the ~~trade name,~~period November 28, 2011 through December 31, 2011 was not material.

Estimated fair value of assets acquired and ~~customer relationships and contracts.~~liabilities assumed as of the Merger date are as follows:

$ in millions	Current purchase price allocation			Preliminary purchase price allocation
Cash	$	116.4		$	116.4
Accounts receivable	277.6			277.6
Inventory	123.7			123.7
Other current assets	41.0			41.0
Property, plant and equipment	2,434.4			2,548.5
Intangible assets subject to amortization	170.2			166.3
Intangible assets - indefinite-lived	5.0			5.0
Regulatory assets	201.7			201.1
Other non-current assets	58.3			58.3
Current liabilities	(400.1		)	(400.2		)
Debt	(1,255.1		)	(1,255.1		)
Deferred taxes	(519.3		)	(558.2		)
Regulatory liabilities	(117.0		)	(117.0		)
Other non-current liabilities	(193.9		)	(194.7		)
Redeemable preferred stock	(18.4		)	(18.4		)
Net identifiable assets acquired	924.5			994.3
Goodwill	2,559.1			2,489.3
Net assets acquired	$	3,483.6		$	3,483.6

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3.Supplemental Financial Information

	At			At			At			At
	March 31,			December 31,			June 30,			December 31,
	2012			2011			2012			2011
$ in millions	Successor						Successor
Accounts receivable, net:
Unbilled revenue	$	61.0		$	72.4		$	71.5		$	72.4
Customer receivables	115.8			113.2			108.2			113.2
Amounts due from partners in jointly-owned plants	31.2			29.2			20.4			29.2
Coal sales	9.2			1.0			3.1			1.0
Other	8.3			4.4			5.9			4.4
Provision for uncollectible accounts	(1.1		)	(1.1		)	(1.0		)	(1.1		)
Total accounts receivable, net	$	224.4		$	219.1		$	208.1		$	219.1

Inventories, at average cost:
Fuel and limestone	$	84.0		$	84.2		$	85.0		$	84.2
Plant materials and supplies	40.6			39.8			40.0			39.8
Other	1.8			1.8			2.0			1.8
Total inventories, at average cost	$	126.4		$	125.8		$	127.0		$	125.8

Accumulated Other Comprehensive Income (Loss)

AOCI is included on our balance sheets within the Common shareholder’s equity sections. The following table provides the components that constitute the balance sheet amounts in AOCI at ~~March 31,~~June 30, 2012 and December 31, 2011:

	At		At			At			At
	March 31,		December 31,			June 30,			December 31,
	2012		2011			2012			2011
$ in millions	Successor					Successor

Financial instruments, net of tax	$	0.4	$	—		$	0.3		$	—
Cash flow hedges, net of tax	6.2		(0.5		)	(7.1		)	(0.5		)
Pension and postretirement benefits, net of tax	0.1		0.1			—			0.1
Total	$	6.7	$	(0.4	)	$	(6.8	)	$	(0.4	)

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4. Regulatory Assets and Liabilities

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

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

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Regulatory assets and liabilities are classified as current or non-current based on the term in which recovery is expected.

The following table presents DPL’s regulatory assets and liabilities:

Type of

Amortization

March 31,

December 31,

Type of

Amortization

June 30,

December 31,

$ in millions

Recovery (a)

Through

2012

2011

Recovery (a)

Through

2012

2011

Current Regulatory Assets:

TCRR, transmission, ancillary and other PJM-related costs

Ongoing

2.8

4.7

Ongoing

5.4

4.7

Power plant emission fees

Ongoing

3.1

4.8

Ongoing

1.4

4.8

Fuel and purchased power recovery costs

Ongoing

9.3

10.7

Ongoing

15.5

11.3

Total current regulatory assets

15.2

20.2

22.3

20.8

Non-current Regulatory Assets:

Deferred recoverable income taxes

B/C

Ongoing

23.3

24.1

B/C

Ongoing

22.5

24.1

Pension benefits

Ongoing

90.5

92.1

Ongoing

88.9

92.1

Unamortized loss on reacquired debt

Ongoing

12.6

13.0

Ongoing

12.4

13.0

Regional transmission organization costs

2014

3.7

4.1

2014

3.3

4.1

Deferred storm costs - 2008

18.2

17.9

18.5

17.9

CCEM smart grid and advanced metering infrastructure costs

6.6

6.6

6.6

6.6

CCEM energy efficiency program costs

Ongoing

6.9

8.8

Ongoing

7.3

8.8

Consumer education campaign

3.0

3.0

3.0

3.0

Retail settlement system costs

3.1

3.1

3.1

3.1

Other costs

5.0

5.1

5.3

5.1

Total non-current regulatory assets

172.9

177.8

170.9

177.8

Current Regulatory Liabilities:

Other

Ongoing

—

0.6

Ongoing

—

0.5

Total current regulatory liabilities

—

0.6

—

0.5

Non-current Regulatory Liabilities:

Estimated costs of removal - regulated property

112.5

112.4

112.4

112.4

Postretirement benefits

6.0

6.2

5.8

6.2

Total non-current regulatory liabilities

118.5

118.6

118.2

118.6

(a) B — Balance has an offsetting liability resulting in no effect 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

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. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.

Power plant emission fees represent costs paid to the State of Ohio since 2002. As part of the fuel factor settlement agreement in November 2011, these costs are being recovered through the fuel factor.

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Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process. We received the audit report for 2011 on April 27, 2012. The auditor has recommended that the PUCO consider reducing DP&L’s recovery of fuel costs by approximately $3.3 million from certain transactions. We will have further discussions with interested parties concerning the audit report in the ~~second quarter~~last half of 2012.

~~Table of Contents~~

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as the result of tax benefits 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 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.

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.

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.

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. On October 19, 2010, DP&L elected to withdraw its case pertaining to the Smart Grid and AMI programs. The PUCO accepted the withdrawal in an order issued on January 5, 2011. The PUCO also indicated that it expects DP&L to continue to monitor other utilities’ Smart Grid and AMI programs and to explore the potential benefits of investing in Smart Grid and AMI programs and that DP&L will, when appropriate, file new Smart Grid and/or AMI business cases in the future. We plan to file to recover these deferred costs in a future regulatory rate proceeding. 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. These costs are being recovered through an energy efficiency rider that began July 1, 2009 and is subject to a two-year true-up for any over/under recovery of costs. The two-year true-up was approved by the PUCO and a new rate was set.

Consumer education campaign represents costs for consumer education advertising regarding electric ~~deregulation and its related rate case.~~deregulation.

Retail settlement system costs represent costs to implement a retail settlement system that reconciles the energy a CRES supplier delivers to its customers and what its customers actually use. Based on case precedent in other utilities’ cases, the costs are recoverable through a future DP&L rate proceeding.

Other costs primarily include RPM capacity, 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.

~~Table of Contents~~

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

5. Ownership of Coal-fired Facilities

DP&L and certain other Ohio utilities have undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of ~~March 31,~~June 30, 2012, DP&L had ~~$55.0~~$71.0 million of construction work in process at such jointly-owned facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Consolidated Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Consolidated Balance Sheets. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned plant.

DP&L’s undivided ownership interest in such facilities as well as our wholly owned ~~coal fired~~coal-fired Hutchings station at ~~March 31,~~June 30, 2012 is as follows:

			DP&L Investment									DP&L Investment
	DP&L Share		(adjusted to fair value at Merger date)							DP&L Share		(adjusted to fair value at Merger date)
									SCR and FGD									SCR and FGD
									Equipment									Equipment
		Summer					Construction		Installed		Summer					Construction		Installed
		Production	Gross Plant		Accumulated		Work in		and in		Production	Gross Plant		Accumulated		Work in		and in
	Ownership	Capacity	in Service		Depreciation		Process		Service	Ownership	Capacity	in Service		Depreciation		Process		Service
	(%)	(MW)	($ in millions)		($ in millions)		($ in millions)		(Yes/No)	(%)	(MW)	($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	207	$	—	$	—	$	—	No	50.0	207	$	1	$	1	$	—	No
Conesville Unit 4	16.5	129	—		—		3		Yes	16.5	129	1		1		7		Yes
East Bend Station	31.0	186	—		—		5		Yes	31.0	186	5		4		7		Yes
Killen Station	67.0	402	332		1		6		Yes	67.0	402	313		10		6		Yes
Miami Fort Units 7 and 8	36.0	368	238		2		2		Yes	36.0	368	219		7		2		Yes
Stuart Station	35.0	808	189		—		11		Yes	35.0	808	203		10		11		Yes
Zimmer Station	28.1	365	159		—		28		Yes	28.1	365	141		19		38		Yes
Transmission (at varying percentages)			34		1		—					35		2		—
Total		2,465	$	952	$	4	$	55			2,465	$	918	$	54	$	71

Wholly-owned production unit:
Hutchings Station	100.0	365	$	—	$	—	$	—	No	100.0	365	$	1	$	—	$	1	No

Currently, our coal-fired generation units at Hutchings and Beckjord do not have the SCR and FGD emission-control equipment installed. DP&L owns 100% of the Hutchings station and has a 50% interest in Beckjord Unit 6. On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. DP&L does not object to Duke’s decision. Beckjord Unit 6 was valued at zero at the Merger date.

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We are considering options for the Hutchings station, but have not yet made a final decision. ~~We do~~DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated and unavailable for service until at least June 1, 2014, if ever. In addition, DP&L has notified PJM that Hutchings Units 1 and 2 will be deactivated by June 1, 2015. The decision to deactivate Units 1 and 2 has been made because these two units are not ~~believe that any accruals are~~equipped with the advanced environmental control technologies needed ~~related~~ to comply with the MACT standard and the cost of compliance with the MACT standard or conversion to natural gas for these units would likely exceed the expected return. DP&L is still studying the option of converting two or more of Hutchings ~~station.~~Units 3-6 to natural gas in order to comply with environmental requirements.

DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.

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6.Debt Obligations

~~Long-term Debt~~

At

At

March 31,

December 31,

$ in millions

2012

2011

Successor

First mortgage bonds maturing in October 2013 - 5.125%

$
498.9

$
503.6

Pollution control series maturing in January 2028 - 4.70%

36.1

36.1

Pollution control series maturing in January 2034 - 4.80%

179.6

179.6

Pollution control series maturing in September 2036 - 4.80%

96.2

96.2

Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.20% and 0.06% - 0.32% (a)

100.0

100.0

U.S. Government note maturing in February 2061 - 4.20%

18.5

18.5

929.3

934.0

Obligation for capital lease

0.3

0.4

Unamortized debt discount

—

—

Total long-term debt at subsidiary

929.6

934.4

Bank Term Loan - variable rates: 2.25% - 2.30% and 1.48% - 4.25% (b)

425.0

425.0

Senior unsecured bonds maturing October 2016 - 6.50%

450.0

450.0

Senior unsecured bonds maturing October 2021 - 7.25%

800.0

800.0

Note to DPL Capital Trust II maturing in September 2031 - 8.125%

19.5

19.5

Total long-term debt

$
2,624.1

$
2,628.9

~~Current portion - Long-term Debt~~

At

At

March 31,

December 31,

2012

2011

$ in millions

Successor

U.S. Government note maturing in February 2061 - 4.20%

$
0.1

$
0.1

Obligation for capital lease

0.3

0.3

Total current portion - long-term debt at subsidiary

$
0.4

$
0.4

~~(a) Range of interest rates for the three months ended March 31, 2012 and the twelve months ended December 31, 2011, respectively.~~

~~(b) Range of interest rates for the three months ended March 31, 2012 and from the draw-down of the loan in August 2011 through December 31, 2011, respectively.~~

All debt outstanding at the Merger date was revalued at the estimated fair value.

Long-term debt

	At		At
	June 30,		December 31,
	2012		2011
$ in millions	Successor
First mortgage bonds maturing in October 2013 - 5.125%	$	494.0	$	503.6
Pollution control series maturing in January 2028 - 4.70%	36.1		36.1
Pollution control series maturing in January 2034 - 4.80%	179.6		179.6
Pollution control series maturing in September 2036 - 4.80%	96.2		96.2
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% (a)	100.0		100.0
U.S. Government note maturing in February 2061 - 4.20%	18.4		18.5
	924.3		934.0

Obligation for capital lease	0.2		0.4
Unamortized debt discount	—		—
Total long-term debt at subsidiary	924.5		934.4

Bank Term Loan - variable rates: 2.24% - 2.30% and 1.48% - 4.25% (b)	425.0		425.0
Senior unsecured bonds maturing October 2016 - 6.50%	450.0		450.0
Senior unsecured bonds maturing October 2021 - 7.25%	800.0		800.0
Note to DPL Capital Trust II maturing in September 2031 - 8.125%	19.7		19.5
Total long-term debt	$	2,619.2	$	2,628.9

Current portion - Long-term debt

	At		At
	June 30,		December 31,
	2012		2011
$ in millions	Successor
U.S. Government note maturing in February 2061 - 4.20%	$	0.1	$	0.1
Obligation for capital lease	0.3		0.3
Total current portion - long-term debt at subsidiary	$	0.4	$	0.4

(a)Range of interest rates for the six months ended June 30, 2012 and the twelve months ended December 31, 2011, respectively.

(b)Range of interest rates for the six months ended June 30, 2012 and from the draw-down of the loan in August 2011 through

December 31, 2011, respectively.

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At ~~March 31,~~June 30, 2012, maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions

DPL

Due within one year

$
0.4

Due within two years

470.4

Due within three years

425.2

Due within four years

0.1

Due within five years

450.1

Thereafter

1,252.9

2,599.1

Unamortized adjustments to market value from purchase accounting

25.4

Total long-term debt

$
2,624.5

~~Table of Contents~~

$ in millions	DPL
Due within one year	$	0.4
Due within two years	470.4
Due within three years	425.1
Due within four years	0.1
Due within five years	450.1
Thereafter	1,252.8
	2,598.9

Unamortized adjustments to market value from purchase accounting	20.7
Total long-term debt	$	2,619.6

Premiums or discounts recognized at the Merger date are amortized over the life of the debt using the effective interest method.

On December 4, 2008, the OAQDA issued $100.0 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 letter of credit issued by JPMorgan Chase Bank, N.A. This letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. Fees associated with this letter of credit facility were not material during the three and six months ended ~~March 31,~~June 30, 2012 and 2011.

On April 20, 2010, DP&L entered into a $200.0 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 $50.0 million. DP&L had no outstanding borrowings under this credit facility at ~~March 31,~~June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended ~~March 31,~~June 30, 2012 and 2011. This facility also contains a ~~$50~~$50.0 million letter of credit sublimit. As of ~~March 31,~~June 30, 2012, DP&L had no outstanding letters of credit against the facility.

On February 23, 2011, DPL purchased $122.0 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 $12.2 million, or 10%, premium. Debt issuance costs and unamortized debt discount totaling $3.1 million were also recognized in February 2011 associated with this transaction.

On March 1, 2011, DP&L completed the purchase of $18.7 million of electric transmission and distribution assets from the federal government that are located at the Wright-Patterson Air Force Base. DP&L financed the acquisition of these assets with a note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum.

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at ~~March 31,~~June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended ~~March 31,~~June 30, 2012. This facility also contains a ~~$50~~$50.0 million letter of credit sublimit. As of ~~March 31,~~June 30, 2012, DP&L had no outstanding letters of credit against the facility.

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On August 24, 2011, DPL entered into a $125.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL had no outstanding borrowings under this credit facility at ~~March 31,~~June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended ~~March 31,~~June 30, 2012. This facility may also be used to issue letters of credit up to the ~~$125~~$125.0 million limit. As of ~~March 31,~~June 30, 2012, DPL had no outstanding letters of credit against the facility.

On August 24, 2011, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group. This agreement is for a three year term expiring on August 24, 2014. DPL has borrowed the entire ~~$425~~$425.0 million available under the facility at ~~March 31,~~June 30, 2012. Fees associated with this term loan were not material during the three and six months ended ~~March 31,~~June 30, 2012.

In connection with the closing of the Merger (see Note 2), DPL assumed $1,250.0 million of debt that Dolphin Subsidiary II, Inc., a subsidiary of AES, issued on October 3, 2011 to partially finance the Merger. The $1,250.0 million was issued in two tranches. The first tranche was $450.0 million of five year senior unsecured notes issued with a 6.50% coupon maturing on October 15, 2016. The second tranche was $800.0 million of ten year senior unsecured notes issued with a 7.25% coupon maturing on October 15, 2021.

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.

~~Table of Contents~~

7.Income Taxes

The following table details the effective tax rates for the three and six months ended ~~March 31,~~June 30, 2012 and 2011.

Three Months Ended

March 31,

2012

2011

DPL

26.0
%
36.3
%

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
	Successor	Predecessor	Successor	Predecessor
DPL	64.0%	34.0%	38.1%	35.3%

Income tax ~~expense~~expenses for the three and six months ended ~~March 31,~~June 30, 2012 and 2011 were calculated using the estimated annual effective income tax rates for 2012 and 2011 and reflect estimated annual effective income tax rates of ~~25.6%~~29.0% and 33.7%, 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.

For the three months ended ~~March 31, 2011,~~June 30, 2012, DPL increased income tax expense by ~~$1.8~~$3.7 million ~~by increasing~~as a result of the following discrete tax adjustments: an increase to deferred state income taxes ~~by $2.0~~of $3.6 million and ~~decreasing~~an increase in other estimated tax liabilities of $0.1 million.

For the six months ended June 30, 2012, DPL increased income tax expense by ~~$0.2~~$3.9 million as a result of the following discrete tax adjustments: an increase to deferred state income taxes of $3.6 million and an increase in other estimated tax liabilities of $0.3 million.

For the three and six months ended ~~March 31,~~June 30, 2012, the ~~decrease~~increase in DPL’s effective tax rate compared to the same period in 2011 primarily reflects decreased pre-tax ~~earnings.~~earnings and an increase to deferred state income taxes.

Deferred tax liabilities for DPL decreased by approximately ~~$6.3~~$44.1 million and $11.5 million, respectively, during the three and six months ended ~~March 31,~~June 30, 2012. These decreases were primarily related to purchase accounting adjustments, amortization and depreciation.

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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~~effect on our financial statements.

8.Pension and Postretirement Benefits

DP&L sponsors a defined benefit pension plan for the vast majority of its employees.

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. There were no contributions made during the ~~three~~six months ended ~~March 31,~~June 30, 2012. DP&L made a discretionary contribution of $40.0 million to the defined benefit plan induring the ~~three~~six months ended ~~March 31,~~June 30, 2011.

The amounts presented in the following tables for pension include both the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP in the aggregate. The amounts presented for postretirement include both health and life insurance.

~~Table of Contents~~

The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the three months ended ~~March 31,~~June 30, 2012 and 2011 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement						Pension						Postretirement
	Successor			Predecessor			Successor			Predecessor			Successor			Predecessor			Successor			Predecessor
$ in millions	2012			2011			2012			2011			2012			2011			2012			2011
Service cost	$	1.5		$	1.4		$	0.1		$	—		$	1.6		$	1.5		$	—		$	0.1
Interest cost	4.3			4.3			0.3			0.3			4.3			4.3			0.1			0.2
Expected return on assets (a)	(5.7		)	(6.1		)	(0.1		)	(0.1		)	(5.6		)	(6.1		)	—			—
Amortization of unrecognized:
Actuarial (gain) / loss	1.2			2.3			(0.2		)	(0.2		)	1.2			2.2			(0.2		)	(0.2		)
Prior service cost	0.4			0.5			—			—			0.3			0.6			—			—
Net periodic benefit cost / (income) before adjustments	$	1.7		$	2.4		$	0.1		$	—		$	1.8		$	2.5		$	(0.1	)	$	0.1

(a) For purposes of calculating the expected return on pension plan assets, under GAAP, the market-related value of assets (MRVA) is used. GAAP requires that the difference between actual plan asset returns and estimated plan asset returns be included in the MRVA equally over a period not to exceed five years. We use a methodology under which we include the difference between actual and estimated asset returns in the MRVA equally over a three year period. The MRVA used in the calculation of expected return on pension plan assets for the 2012 and 2011 net periodic benefit cost was approximately $336 million and $316 million, respectively.

The net periodic benefit cost / (income) of the pension and postretirement benefit plans for the six months ended June 30, 2012 and 2011 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
	Successor			Predecessor			Successor			Predecessor
$ in millions	2012			2011			2012			2011
Service cost	$	3.1		$	2.9		$	0.1		$	0.1
Interest cost	8.6			8.6			0.4			0.5
Expected return on assets (a)	(11.3		)	(12.2		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Actuarial (gain) / loss	2.4			4.5			(0.4		)	(0.4		)
Prior service cost	0.7			1.1			—			—
Net periodic benefit cost / (income) before adjustments	$	3.5		$	4.9		$	—		$	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 calculation of expected return on pension plan assets for the 2012 and 2011 net periodic benefit cost was approximately $336 million and $316 million, respectively.

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Benefit payments, which reflect future service, are expected to be paid as follows:

Estimated Future Benefit Payments and Medicare Part D Reimbursements

$ in millions	Pension		Postretirement		Pension		Postretirement

2012	$	17.3	$	1.8	$	11.5	$	1.2
2013	$	22.7	$	2.3	22.7		2.3
2014	$	23.2	$	2.2	23.2		2.2
2015	$	23.8	$	2.0	23.8		2.0
2016	$	24.0	$	1.9	24.0		1.9
2017 - 2021	$	124.4	$	7.5	124.4		7.5

9. 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 our best estimates of ~~possible~~the fair value, ~~that~~which may not be the value realized in the future. The table below presents the fair value and cost of our non-derivative instruments at ~~March 31,~~June 30, 2012 and December 31, 2011. See also Note 10 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.

Successor

At March 31,

At December 31,

2012

2011

$ in millions

Cost

Fair Value

Cost

Fair Value

Assets

Money Market Funds

$
0.2

$
0.2

$
0.2

$
0.2

Equity Securities

3.9

5.0

3.9

4.4

Debt Securities

5.1

5.5

5.0

5.5

Multi-Strategy Fund

0.3

0.3

0.3

0.2

Total Assets

$
9.5

$
11.0

$
9.4

$
10.3

Liabilities

Debt

$
2,624.5

$
2,723.4

$
2,629.3

$
2,710.6

~~Table of Contents~~

	Successor
	At June 30,				At December 31,
	2012				2011
$ in millions	Cost		Fair Value		Cost		Fair Value
Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities	4.0		4.9		3.9		4.4
Debt Securities	5.0		5.5		5.0		5.5
Multi-Strategy Fund	0.3		0.2		0.3		0.2
Total Assets	$	9.5	$	10.8	$	9.4	$	10.3

Liabilities
Debt	$	2,619.6	$	2,744.4	$	2,629.3	$	2,710.6

Debt

The carrying value of DPL’s debt was adjusted to fair value at the Merger date. Unrealized gains or losses that are not recognized in the financial statements as debt isare presented at the carrying value established at the Merger ~~date, net of unamortized premium or discount in the financial statements.~~date. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2013 to 2061.

Master Trust Assets

DP&L established a Master Trust to hold assets that could be used for the benefit of employees participating in employee benefit plans. These assets are primarily comprised of open-ended mutual funds which are valued using the net asset value per unit. These investments are recorded at fair value within Other deferred assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DPL had ~~$0.6~~$0.5 million ($~~0.4~~0.3 million after tax) of unrealized gains and immaterial losses on the Master Trust assets in AOCI at ~~March 31,~~June 30, 2012 and immaterial unrealized gains and losses in AOCI at December 31, 2011.

Due to the liquidation of the DPL Inc. common stock held in the Master Trust, there is sufficient cash to cover the next twelve months of benefits payable to employees covered under the benefit plans. Therefore, no unrealized gains or losses are expected to be transferred to earnings since we will not need to sell any investments in 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 ~~March~~June 30, 2012 and December 31, ~~2012.~~2011. These assets are part of the Master Trust. 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 ~~March 31,~~June 30, 2012, 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 (Successor)

$ in millions	Fair Value at March 31, 2012		Fair Value at December 31, 2011		Unfunded Commitments		Fair Value at June 30, 2012		Fair Value at December 31, 2011		Unfunded Commitments
Money Market Fund (a)	$	0.2	$	0.2	$	—	$	0.2	$	0.2	$	—

Equity Securities (b)	5.0		4.4		—		4.9		4.4		—

Debt Securities (c)	5.5		5.5		—		5.5		5.5		—

Multi-Strategy Fund (d)	0.3		0.2		—		0.2		0.2		—

Total	$	11.0	$	10.3	$	—	$	10.8	$	10.3	$	—

(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~~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 a mix of actively managed funds holding 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.

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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.

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The fair value of assets and liabilities at ~~March 31,~~June 30, 2012 and December 31, 2011 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:

	Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)
				Level 1		Level 2			Level 3						Fair Value on
	Fair Value at			Based on Quoted		Other						Collateral and			Balance Sheet			Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)
	March 31,			Prices in Active		Observable			Unobservable			Counterparty			at March 31,						Level 1		Level 2			Level 3						Fair Value on
$ in millions	2012*			Markets		Inputs			Inputs			Netting			2012			Fair Value at June 30, 2012*			Based on Quoted Prices in Active Markets		Other Observable Inputs			Unobservable Inputs			Collateral and Counterparty Netting			Balance Sheet at June 30, 2012
Assets
Master Trust Assets
Money Market Funds	$	0.2		$	—	$	0.2		$	—		$	—		$	0.2		$	0.2		$	—	$	0.2		$	—		$	—		$	0.2
Equity Securities	5.0			—		5.0			—			—			5.0			4.9			—		4.9			—			—			4.9
Debt Securities	5.5			—		5.5			—			—			5.5			5.5			—		5.5			—			—			5.5
Multi-Strategy Fund	0.3			—		0.3			—			—			0.3			0.2			—		0.2			—			—			0.2
Total Master Trust Assets	11.0			—		11.0			—			—			11.0			10.8			—		10.8			—			—			10.8

Derivative Assets
FTRs	0.1			—		0.1			—			—			0.1
Heating Oil Futures	1.6			1.6		—			—			(1.6		)	—			0.3			0.3		—			—			(0.3		)	—
Forward Power Contracts	18.2			—		18.2			—			(0.7		)	17.5			18.3			—		18.3			—			(3.3		)	15.0
Total Derivative Assets	19.9			1.6		18.3			—			(2.3		)	17.6			18.6			0.3		18.3			—			(3.6		)	15.0

Total Assets	$	30.9		$	1.6	$	29.3		$	—		$	(2.3	)	$	28.6		$	29.4		$	0.3	$	29.1		$	—		$	(3.6	)	$	25.8

Liabilities
Derivative Liabilities
Interest Rate Hedge	$	(16.8	)	$	—	$	(16.8	)	$	—		$	—		$	(16.8	)	$	(39.5	)	$	—	$	(39.5	)	$	—		$	—		$	(39.5	)
FTRs																		(0.1		)	—		—			(0.1		)	—			(0.1		)
Forward NYMEX Coal Contracts	(22.3		)	—		(22.3		)	—			16.0			(6.3		)	(16.5		)	—		(16.5		)	—			11.4			(5.1		)
Forward Power Contracts	(16.0		)	—		(16.0		)	—			10.7			(5.3		)	(16.0		)	—		(16.0		)	—			11.5			(4.5		)
Total Derivative Liabilities	(55.1		)	—		(55.1		)	—			26.7			(28.4		)	(72.1		)	—		(72.0		)	(0.1		)	22.9			(49.2		)

Long-term Debt	(2,723.4		)	—		(2,704.2		)	(19.2		)	—			(2,723.4		)	(2,744.4		)	—		(2,725.2		)	(19.2		)	—			(2,744.4		)

Total Liabilities	$	(2,778.5	)	$	—	$	(2,759.3	)	$	(19.2	)	$	26.7		$	(2,751.8	)	$	(2,816.5	)	$	—	$	(2,797.2	)	$	(19.3	)	$	22.9		$	(2,793.6	)

*Includes credit valuation adjustments for counterparty risk and our own credit risk.

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	Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)
				Level 1		Level 2			Level 3					Fair Value on
	Fair Value at			Based on Quoted		Other					Collateral and			Balance Sheet at			Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)
	December 31,			Prices in Active		Observable			Unobservable		Counterparty			December 31,						Level 1		Level 2			Level 3					Fair Value on
$ in millions	2011*			Markets		Inputs			Inputs		Netting			2011			Fair Value at December 31, 2011*			Based on Quoted Prices in Active Markets		Other Observable Inputs			Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2011
Assets
Master Trust Assets
Money Market Funds	$	0.2		$	—	$	0.2		$	—	$	—		$	0.2		$	0.2		$	—	$	0.2		$	—	$	—		$	0.2
Equity Securities	4.4			—		4.4			—		—			4.4			4.4			—		4.4			—		—			4.4
Debt Securities	5.5			—		5.5			—		—			5.5			5.5			—		5.5			—		—			5.5
Multi-Strategy Fund	0.2			—		0.2			—		—			0.2			0.2			—		0.2			—		—			0.2
Total Master Trust Assets	10.3			—		10.3			—		—			10.3			10.3			—		10.3			—		—			10.3

Derivative Assets
FTRs	0.1			—		0.1			—		—			0.1			0.1			—		0.1			—		—			0.1
Heating Oil Futures	1.8			1.8		—			—		(1.8		)	—			1.8			1.8		—			—		(1.8		)	—
Forward Power Contracts	17.3			—		17.3			—		(1.0		)	16.3			17.3			—		17.3			—		(1.0		)	16.3
Total Derivative Assets	19.2			1.8		17.4			—		(2.8		)	16.4			19.2			1.8		17.4			—		(2.8		)	16.4

Total Assets	$	29.5		$	1.8	$	27.7		$	—	$	(2.8	)	$	26.7		$	29.5		$	1.8	$	27.7		$	—	$	(2.8	)	$	26.7

Liabilities
Derivative Liabilities
Interest Rate Hedge	$	(32.5	)	$	—	$	(32.5	)	$	—	$	—		$	(32.5	)	$	(32.5	)	$	—	$	(32.5	)	$	—	$	—		$	(32.5	)
Forward NYMEX Coal Contracts	(14.5		)	—		(14.5		)	—		10.8			(3.7		)	(14.5		)	—		(14.5		)	—		10.8			(3.7		)
Forward Power Contracts	(13.3		)	—		(13.3		)	—		5.6			(7.7		)	(13.3		)	—		(13.3		)	—		5.6			(7.7		)
Total Derivative Liabilities	(60.3		)	—		(60.3		)	—		16.4			(43.9		)	(60.3		)	—		(60.3		)	—		16.4			(43.9		)

Total Liabilities	$	(60.3	)	$	—	$	(60.3	)	$	—	$	16.4		$	(43.9	)	$	(60.3	)	$	—	$	(60.3	)	$	—	$	16.4		$	(43.9	)

*Includes credit valuation adjustments for counterparty risk and our own credit risk.

We use the market approach to value our financial instruments. Level 1 inputs are used for derivative contracts such as heating oil futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as ~~financial transmission rights (where the quoted prices are from a relatively inactive market),~~ forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). 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. Financial transmission rights are considered a Level 3 input, beginning April 1, 2012, because the monthly auctions are considered inactive.

Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

Our debt is fair valued for disclosure purposes only and most of the fair values are determined using quoted market prices in inactive markets. These fair value inputs are considered Level 2 in the fair value hierarchy. Our long-term leases and the WPAFB loan are not publicly traded. Fair value is assumed to equal carrying value. These fair value inputs are considered Level 3 in the fair value hierarchy as there are no observable inputs. Additional Level 3 disclosures were not presented since debt is not recorded at fair value.

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

Non-recurring ~~fair value measurements~~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. Additions to AROs were not material during the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011.

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Cash Equivalents

DPL had ~~$100.0~~$110.0 million and $125.0 million in money market funds classified as cash and cash equivalents in its Condensed Consolidated Balance Sheets at ~~March 31,~~June 30, 2012 and December 31, 2011, respectively. The money market funds have quoted prices that are generally equivalent to ~~par.~~par and are considered Level 2.

10. Derivative Instruments and Hedging Activities

In the normal course of business, DPL enters 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 asset and liability derivative positions with the same counterparty are netted on the balance sheets if we have a Master Netting Agreement with the counterparty. We also net any collateral posted or received against the corresponding derivative asset or liability position. 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 ~~March 31,~~June 30, 2012, DPL had the following outstanding derivative instruments:

	Accounting		Purchases		Sales			Net Purchases/ (Sales)			Accounting		Purchases		Sales			Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)		(in thousands)			(in thousands)			Treatment	Unit	(in thousands)		(in thousands)			(in thousands)
FTRs	Mark to Market	MWh	2.8		—			2.8			Mark to Market	MWh	15.2		—			15.2
Heating Oil Futures	Mark to Market	Gallons	1,680.0		—			1,680.0			Mark to Market	Gallons	630.0		—			630.0
Forward Power Contracts	Cash Flow Hedge	MWh	881.1		(107.2		)	773.9			Cash Flow Hedge	MWh	876.0		(1,595.2		)	(719.2		)
Forward Power Contracts	Mark to Market	MWh	1,195.4		(1,213.5		)	(18.1		)	Mark to Market	MWh	1,981.1		(4,003.1		)	(2,022.0		)
NYMEX-quality Coal Contracts*	Mark to Market	Tons	1,410.5		—			1,410.5			Mark to Market	Tons	860.3		—			860.3
Interest Rate Swaps	Cash Flow Hedge	USD	$	160,000.0	$	—		$	160,000.0		Cash Flow Hedge	USD	$	160,000.0	$	—		$	160,000.0

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

At December 31, 2011, DPL had the following outstanding derivative instruments:

	Accounting		Purchases		Sales			Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)		(in thousands)			(in thousands)
FTRs	Mark to Market	MWh	7.1		(0.7		)	6.4
Heating Oil Futures	Mark to Market	Gallons	2,772.0		—			2,772.0
Forward Power Contracts	Cash Flow Hedge	MWh	886.2		(341.6		)	544.6
Forward Power Contracts	Mark to Market	MWh	1,769.4		(1,739.5		)	29.9
NYMEX-quality Coal Contracts*	Mark to Market	Tons	2,015.0		—			2,015.0
Interest Rate Swaps	Cash Flow Hedge	USD	$	160,000.0	$	—		$	160,000.0

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

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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~~observable market prices available as of the balance sheet dates and 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.

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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. During 2011, interest rate hedging relationships with a notional amount of $200.0 million settled resulting in DPL making a cash payment of $48.1 million ($31.3 million net of tax). As part of the Merger discussed in Note 2, DPL entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL’s 6.875% debt that was due in September 2011. The remainder was drawn for other corporate purposes. This agreement is for a three year term expiring on August 24, 2014. As a result, some of the forecasted transactions originally being hedged are probable of not occurring and therefore approximately $5.1 million ($3.3 million net of tax) has been reclassified to earnings during the period January 1, 2011 through November 27, 2011. Because the interest rate swap had already cash settled as of the Merger date, this hedge had no future value and was not valued as a part of the purchase accounting (See Note 2 for more information). We reclassify gains and losses on interest rate derivative hedges related to debt financings from AOCI into earnings in those periods in which hedged interest payments occur.

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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 three months ended ~~March 31,~~June 30, 2012 and 2011:

	March 31,								March 31,
	2012								2011								June 30, 2012						June 30, 2011
	Successor								Predecessor								Successor						Predecessor
					Interest								Interest							Interest						Interest
$ in millions (net of tax)	Power				Rate Hedge				Power				Rate Hedge				Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	0.3			$	(0.8		)	$	(1.8		)	$	21.4			$	(2.3	)	$	8.5		$	(1.6	)	$	22.4

Net gains / (losses) associated with current period hedging transactions	(1.5			)	9.1				0.5				1.6				(0.2		)	(13.2		)	(0.5		)	(10.8		)

Net gains reclassified to earnings
Interest expense	—				0.2				—				(0.6			)
Interest Expense																	—			—			—			0.7
Revenues	(1.2			)	—				(0.1			)	—				—			—			0.3			—
Purchased power	0.1				—				(0.2			)	—
Purchased Power																	0.1			—			0.3			—

Ending accumulated derivative gain / (loss) in AOCI	$	(2.3		)	$	8.5			$	(1.6		)	$	22.4			$	(2.4	)	$	(4.7	)	$	(1.5	)	$	12.3

Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest expense	$		—		$		(1.6	)	$		—		$		—
Interest Expense																	$	—		$	2.3		$	—		$	(1.3	)
Revenues	$		—		$		—		$		—		$		—		$	—		$	—		$	—		$	—
Purchased power	$		—		$		—
Purchased Power																	$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(0.3		)	$	—											$	(1.1	)	$	—		—			—

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	33				18												30			14			—			—

*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 DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the six months ended June 30, 2012 and 2011:

	June 30, 2012						June 30, 2011
	Successor						Predecessor
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	0.3		$	(0.8	)	$	(1.8	)	$	21.4

Net gains / (losses) associated with current period hedging transactions	(1.6		)	(4.2		)	(0.9		)	(9.2		)

Net gains reclassified to earnings
Interest Expense	—			0.3			—			0.1
Revenues	(1.1		)	—			0.5			—
Purchased Power	—			—			0.7			—

Ending accumulated derivative gain / (loss) in AOCI	$	(2.4	)	$	(4.7	)	$	(1.5	)	$	12.3

Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest Expense	$	—		$	1.2		$	—		$	(1.3	)
Revenues	$	—		$	—		$	—		$	—
Purchased Power	$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(1.1	)	$	—		—			—

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	30			14			—			—

*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 tables show the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at ~~March 31,~~June 30, 2012 and December 31, 2011:

Fair Values of Derivative Instruments Designated as Hedging Instruments

at ~~March 31,~~June 30, 2012 (Successor)

								Fair Value on										Fair Value on
$ in millions	Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet			Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	1.0		$	(0.6	)	Other current assets	$	0.4		$	1.8		$	(1.5	)	Other current assets	$	0.3
Forward Power Contracts in a Liability Position	(1.5		)	1.1			Other current liabilities	(0.4		)	(2.9		)	2.4			Other current liabilities	(0.5		)

Total short-term cash flow hedges	(0.5		)	0.5				—
Total Short-term Cash Flow Hedges											(1.1		)	0.9				(0.2		)

Long-term Derivative Positions

Forward Power Contracts in a Asset Position											0.5			(0.5		)	Other deferred assets	—
Forward Power Contracts in a Liability Position	(4.7		)	3.0			Other deferred credits	(1.7		)	(4.6		)	3.1			Other deferred credits	(1.5		)
Interest Rate Hedges in a Liability Position	(16.8		)	—			Other deferred credits	(16.8		)	(39.5		)	—			Other deferred credits	(39.5		)

Total long-term cash flow hedges	(21.5		)	3.0				(18.5		)
Total Long-term Cash Flow Hedges											(43.6		)	2.6				(41.0		)

Total cash flow hedges	$	(22.0	)	$	3.5			$	(18.5	)
Total Cash Flow Hedges											$	(44.7	)	$	3.5			$	(41.2	)

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at December 31, 2011 (Successor)

								Fair Value on										Fair Value on
$ in millions	Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet			Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	1.5		$	(0.9	)	Other current assets	$	0.6		$	1.5		$	(0.9	)	Other current assets	$	0.6
Forward Power Contracts in a Liability Position	(0.2		)	—			Other current liabilities	(0.2		)	(0.2		)	—			Other current liabilities	(0.2		)

Total short-term cash flow hedges	1.3			(0.9		)		0.4
Total Short-term Cash Flow Hedges											1.3			(0.9		)		0.4

Long-term Derivative Positions

Forward Power Contracts in an Asset Position	0.1			(0.1		)	Other deferred assets	—			0.1			(0.1		)	Other deferred assets	—
Forward Power Contracts in a Liability Position	(2.6		)	1.7			Other deferred credits	(0.9		)	(2.6		)	1.7			Other deferred credits	(0.9		)
Interest Rate Hedges in a Liability Position	(32.5		)	—			Other deferred credits	(32.5		)	(32.5		)	—			Other deferred credits	(32.5		)

Total long-term cash flow hedges	(35.0		)	1.6				(33.4		)
Total Long-term Cash Flow Hedges											(35.0		)	1.6				(33.4		)

Total cash flow hedges	$	(33.7	)	$	0.7			$	(33.0	)
Total Cash Flow Hedges											$	(33.7	)	$	0.7			$	(33.0	)

(1) Includes credit valuation adjustment.

(2) 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 purchase 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 currently mark to market Financial Transmission Rights (FTRs), heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP 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

In accordance with regulatory accounting under GAAP, a cost that is probable of recovery in future rates should be deferred as a regulatory asset and a gain that is probable of being returned to customers 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 and purchased power recovery rider approved by the PUCO which began January 1, 2010. Therefore, the Ohio retail customers’ 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 Condensed Consolidated Balance Sheets of the gains and losses on DPL’s derivatives not designated as hedging instruments for the three and six months ended ~~March 31,~~June 30, 2012 and ~~2011:~~2011.

For the three months ended ~~March 31,~~June 30, 2012 (Successor)

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total			NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(7.8	)	$	(0.1	)	$	(0.1	)	$	1.4		$	(6.6	)	$	5.7		$	(1.3	)	$	(0.2	)	$	0.9		$	5.1
Realized gain / (loss)	(5.0		)	0.9			(0.2		)	(2.3		)	(6.6		)	(9.5		)	0.5			0.7			(2.1		)	(10.4		)
Total	$	(12.8	)	$	0.8		$	(0.3	)	$	(0.9	)	$	(13.2	)	$	(3.8	)	$	(0.8	)	$	0.5		$	(1.2	)	$	(5.3	)

Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(3.5	)	$	—		$	—		$	—		$	(3.5	)	$	2.3		$	—		$	—		$	—		$	2.3
Regulatory (asset) / liability	(1.1		)	0.1			—			—			(1.0		)	0.8			(0.6		)	—			—			0.2

Recorded in Income Statement: gain / (loss)
Revenue		—			—			—			3.4			3.4		—			—			—			(2.7		)	(2.7		)
Purchased power	—			—			(0.3		)	(4.3		)	(4.6		)	—			—			0.5			1.5			2.0
Fuel	(8.2		)	0.6			—			—			(7.6		)	(6.9		)	(0.3		)	—			—			(7.2		)
O&M	—			0.1			—			—			0.1			—			0.1			—			—			0.1
Total	$	(12.8	)	$	0.8		$	(0.3	)	$	(0.9	)	$	(13.2	)	$	(3.8	)	$	(0.8	)	$	0.5		$	(1.2	)	$	(5.3	)

For the three months ended ~~March 31,~~June 30, 2011 (Predecessor)

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total			NYMEX Coal			Heating Oil			FTRs		Power			Total
Change in unrealized gain / (loss)	$	(3.5	)	$	3.0	$	(0.1	)	$	0.6		$	—		$	(10.2	)	$	(1.4	)	$	0.1	$	(0.1	)	$	(11.6	)
Realized gain / (loss)	2.4			0.4		(0.8		)	(0.8		)	1.2			1.4			0.6			0.2		(1.3		)	0.9
Total	$	(1.1	)	$	3.4	$	(0.9	)	$	(0.2	)	$	1.2		$	(8.8	)	$	(0.8	)	$	0.3	$	(1.4	)	$	(10.7	)

Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(2.4	)	$	—	$	—		$	—		$	(2.4	)	$	(5.0	)	$	—		$	—	$	—		$	(5.0	)
Regulatory (asset) / liability	0.3			1.6		—			—			1.9			(2.3		)	(0.9		)	—		—			(3.2		)

Recorded in Income Statement: gain / (loss)
Revenue		—			—		—			(1.6	)		(1.6	)	—			—			—		(3.1		)	(3.1		)
Purchased power	—			—		(0.9		)	1.4			0.5			—			—			0.3		1.7			2.0
Fuel	1.0			1.7		—						2.7			(1.5		)	—			—		—			(1.5		)
O&M	—			0.1		—						0.1			—			0.1			—		—			0.1
Total	$	(1.1	)	$	3.4	$	(0.9	)	$	(0.2	)	$	1.2		$	(8.8	)	$	(0.8	)	$	0.3	$	(1.4	)	$	(10.7	)

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For the six months ended June 30, 2012 (Successor)

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

(2.0

)

(1.5

)

(0.2

)

2.3

(1.4

)

Realized gain / (loss)

(14.5

)

1.4

0.5

(4.4

)

(17.0

)

Total

(16.5

)

(0.1

)

0.3

(2.1

)

(18.4

)

Recorded on Balance Sheet:

Partners’ share of gain / (loss)

(1.2

)

—

(1.2

)

Regulatory (asset) / liability

(0.3

)

(0.6

)

—

(0.9

)

Recorded in Income Statement: gain / (loss)

Revenue

—

0.7

Purchased power

—

0.3

(2.8

)

(2.5

)

Fuel

(15.0

)

0.3

—

(14.7

)

O&M

—

0.2

—

0.2

Total

(16.5

)

(0.1

)

0.3

(2.1

)

(18.4

)

For the six months ended June 30, 2011 (Predecessor)

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(13.8	)	$	1.6	$	(0.1	)	$	0.5		$	(11.8	)
Realized gain / (loss)	3.8			0.9		(0.7		)	(2.1		)	1.9
Total	$	(10.0	)	$	2.5	$	(0.8	)	$	(1.6	)	$	(9.9	)

Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(7.4	)	$	—	$	—		$	—		$	(7.4	)
Regulatory (asset) / liability	(2.0		)	0.6		—			—			(1.4		)

Recorded in Income Statement: gain / (loss)
Revenue	—			—		—			(4.7		)	(4.7		)
Purchased power	—			—		(0.8		)	3.1			2.3
Fuel	(0.6		)	1.8		—			—			1.2
O&M	—			0.1		—			—			0.1
Total	$	(10.0	)	$	2.5	$	(0.8	)	$	(1.6	)	$	(9.9	)

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The following table shows the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at ~~March 31,~~June 30, 2012:

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at ~~March 31,~~June 30, 2012 (Successor)

$ in millions

Fair Value (1)

Netting (2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

13.3

—

Other prepayments and current assets

13.3

Forward Power Contracts in a Liability position

(7.7
)
5.7

Other current liabilities

(2.0
)
NYMEX-quality Coal Forwards in a Liability position

(16.7
)
10.3

Other prepayments and current assets

(6.4
)
Heating Oil Futures in an Asset position

1.6

(1.6
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

(9.4
)
14.4

5.0

Long-term Derivative Positions

Forward Power Contracts in an Asset position

4.0

—

Other deferred assets

4.0

Forward Power Contracts in a Liability position

(2.3
)
1.0

Other deferred credits

(1.3
)
NYMEX-quality Coal Forwards in a Liability position

(5.6
)
5.6

Other deferred assets

—

Total long-term derivative MTM positions

(3.9
)
6.6

2.7

Total MTM Position

$
(13.3
)
$
21.0

$
7.7

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in a Liability Position

(0.1

)

—

Other current liabilities

(0.1

)

Forward Power Contracts in an Asset Position

12.1

(1.2

)

Other prepayments and current assets

10.9

Forward Power Contracts in a Liability Position

(6.4

)

5.0

Other current liabilities

(1.4

)

NYMEX-quality Coal Forwards in a Liability Position

(12.9

)

7.8

Other prepayments and current assets

(5.1

)

Heating Oil Futures in an Asset Position

0.3

(0.3

)

Other prepayments and current assets

—

Total Short-term Derivative MTM Positions

(7.0

)

11.3

4.3

Long-term Derivative Positions

Forward Power Contracts in an Asset Position

3.9

(0.1

)

Other deferred assets

3.8

Forward Power Contracts in a Liability Position

(2.1

)

1.0

Other deferred credits

(1.1

)

NYMEX-quality Coal Forwards in a Liability Position

(3.6

)

3.6

Other deferred assets

—

Total Long-term Derivative MTM Positions

(1.8

)

4.5

2.7

Total MTM Position

(8.8

)

15.8

7.0

(1)Includes credit valuation adjustment.

(2)Includes counterparty and collateral netting.

The following table shows the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at December 31, 2011:

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at December 31, 2011 (Successor)

$ in millions

Fair Value (1)

Netting (2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

9.9

—

Other prepayments and current assets

9.9

Forward Power Contracts in a Liability position

(6.5
)
2.6

Other current liabilities

(3.9
)
NYMEX-quality Coal Forwards in a Liability position

(8.3
)
4.6

Other current liabilities

(3.7
)
Heating Oil Futures in an Asset position

1.8

(1.8
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

(3.0
)
5.4

2.4

Long-term Derivative Positions

Forward Power Contracts in an Asset position

5.8

—

Other deferred assets

5.8

Forward Power Contracts in a Liability position

(4.0
)
1.3

Other deferred credits

(2.7
)
NYMEX-quality Coal Forwards in a Liability position

(6.2
)
6.2

Other deferred credits

—

Total long-term derivative MTM positions

(4.4
)
7.5

3.1

Total MTM Position

$
(7.4
)
$
12.9

$
5.5

$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset Position	$	0.1		$	—		Other prepayments and current assets	$	0.1
Forward Power Contracts in an Asset Position	9.9			—			Other prepayments and current assets	9.9
Forward Power Contracts in a Liability Position	(6.5		)	2.6			Other current liabilities	(3.9		)
NYMEX-quality Coal Forwards in a Liability Position	(8.3		)	4.6			Other current liabilities	(3.7		)
Heating Oil Futures in an Asset Position	1.8			(1.8		)	Other prepayments and current assets	—

Total Short-term Derivative MTM Positions	(3.0		)	5.4				2.4

Long-term Derivative Positions
Forward Power Contracts in an Asset Position	5.8			—			Other deferred assets	5.8
Forward Power Contracts in a Liability Position	(4.0		)	1.3			Other deferred credits	(2.7		)
NYMEX-quality Coal Forwards in a Liability Position	(6.2		)	6.2			Other deferred credits	—

Total Long-term Derivative MTM Positions	(4.4		)	7.5				3.1

Total MTM Position	$	(7.4	)	$	12.9			$	5.5

(1)Includes credit valuation adjustment.

(2)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. Even though our debt has fallen below investment grade, our counterparties to the derivative instruments have not requested immediate payment or demanded immediate and ongoing full overnight collateralization of the MTM loss.

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The aggregate fair value of DPL’s commodity derivative instruments that are in a MTM loss position at ~~March 31,~~June 30, 2012 is ~~$38.6~~$32.8 million. This amount is offset by ~~$26.0~~$19.3 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of ~~$0.9~~$3.7 million. If our counterparties were to call for collateral, we could have to post collateral for the remaining ~~$11.7~~$9.8 million.

11. Common ~~Shareholders’~~Shareholder’s Equity

Effective on the Merger date, DPL adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which one share is outstanding at ~~March 31,~~June 30, 2012.

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program that permitted DPL to 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. This 2009 Stock Repurchase Program was scheduled to run through June 30, 2012, but was suspended in connection with the Merger with The AES Corporation, discussed in Note 2. In June 2011, 0.7 million warrants were exercised with proceeds of $14.7 million. Since the Stock Repurchase Program was suspended, the proceeds from the June 2011 exercise of warrants were not used to repurchase stock.

As a result of the Merger involving DPL and AES, the outstanding shares of DPL common stock were converted into the right to receive merger consideration of $30.00 per share. When the remaining warrants were exercised in March 2012, DPL paid the warrant holders an amount equal to $9.00 per warrant, which is the difference between the merger consideration of $30.00 per share of DPL common stock and the exercise price of $21.00 per share. This amount was recorded as a $9.0 million liability at the Merger date. At December 31, 2011, DPL had 1.0 million outstanding warrants which were exercised in March 2012. At ~~March 31,~~June 30, 2012, there are no remaining warrants outstanding.

ESOP

In October 1992, our Board of Directors approved the formation of a Company-sponsored ESOP to fund matching contributions to DP&L’s 401(k) retirement savings plan and certain other payments to eligible full-time employees. ESOP shares used to fund matching contributions to DP&L’s 401(k) vested after two, three or five years of service in accordance with the match formula effective for the respective plan match year; other compensation shares awarded vested immediately.

During December 2011, the ESOP Plan was terminated and participant balances were transferred to one of the two DP&L sponsored defined contribution 401(k) plans. On December 5, 2011, the ESOP Trust paid the total outstanding principal and interest of $68.2 million on the loan with DPL, using the merger proceeds from DPL common stock held within the ESOP suspense account.

12. Earnings per Share

Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations were 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 six months ended ~~March 31,~~June 30, 2011. Effective with the Merger with AES, DPL is wholly owned by AES and earnings per share information is no longer required.

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

Successor

Predecessor

Successor

Predecessor

Three Months Ended March 31,

Three Months Ended June 30,

2012

2011

2012

2011

$ and shares in millions except

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Income

Shares

Share

Income

Shares

Share

Basic EPS

N/A

43.5

114.0

0.38

N/A

31.7

114.2

0.28

Effect of Dilutive Securities:

Warrants

N/A

0.3

N/A

0.5

Stock options, performance and restricted shares

N/A

0.2

N/A

0.2

Diluted EPS

N/A

43.5

114.5

0.38

N/A

31.7

114.9

0.28

Successor

Predecessor

Six Months Ended June 30,

2012

2011

$ and shares in millions except

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

N/A

75.2

114.1

0.66

Effect of Dilutive Securities:

Warrants

N/A

0.4

Stock options, performance and restricted shares

N/A

0.2

Diluted EPS

N/A

75.2

114.7

0.66

13. Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. — Guarantees

In the normal course of business, DPL enters into various agreements with its wholly owned subsidiaries, DPLE and DPLER and its wholly owned subsidiary, MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes.

At ~~March 31,~~June 30, 2012, DPL had ~~$47.4~~$26.4 million of guarantees to third parties for future financial or performance assurance under such agreements, including ~~$47.1~~$26.1 million of guarantees, on behalf of DPLE and DPLER and $0.3 million of guarantees on behalf of MC Squared. The guarantee arrangements entered into by DPL with these third parties cover select present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable by DPL upon written notice within a certain time to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was ~~$0.4~~$1.0 million at ~~March 31,~~June 30, 2012.

To date, DPL has not incurred any losses related to the guarantees of DPLE’s, DPLER’s and MC Squared’s obligations and we believe it is remote that DPL would be required to perform or incur any losses in the future associated with any of the above guarantees of DPLE’s, DPLER’s and MC Squared’s obligations.

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Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of ~~March 31,~~June 30, 2012, DP&L could be responsible for the repayment of 4.9%, or ~~$64.9~~$69.2 million, of a ~~$1,324.7~~$1,411.4 million debt obligation that features maturities from 2013 to ~~2026.~~2040. This would only happen if this electric generation company defaulted on its debt payments. As of ~~March 31,~~June 30, 2012, we have no knowledge of such a default.

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 Form 10-K for the fiscal year ended December 31, 2011.

~~Table of Contents~~

Contingencies

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of ~~March 31,~~June 30, 2012, 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.~~environmental regulations and laws. 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 in accordance with the provisions of GAAP. We have estimated liabilities of approximately ~~$3.2~~$4.3 million for environmental matters. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

We have several pending environmental matters associated with our power plants. Some of these matters could have material adverse impacts on our business and 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 station and a 50% interest in Beckjord Unit 6.

On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. Beckjord Unit 6 was valued at zero at the Merger date. ~~The Hutchings station was also valued at zero at the Merger date.~~

We are considering options for the Hutchings station, but have not yet made a final decision. ~~We do not believe~~DP&L has informed PJM that ~~any accruals are needed related~~Hutchings Unit 4 has incurred damage to ~~the~~a rotor and will be deactivated and unavailable for service until at least June 1, 2014, if ever. In addition, DP&L has notified PJM that Hutchings ~~station.~~Units 1 and 2 will be deactivated by June 1, 2015.

DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.

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Environmental Matters Related to Air Quality

Clean Air Act Compliance

In 1990, the federal government amended the CAA to further regulate air pollution. Under the CAA, the USEPA sets limits on, among other things, how much of ~~a pollutant~~certain designated pollutants can be in the ambient air anywhere in the United States. The CAA allows individual states to have stronger pollution controls than those set under the CAA, 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.

Cross-State Air Pollution Rule

The Clean Air Interstate Rule (CAIR) final rules 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. Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit on July 11, 2008 to vacate CAIR and its associated Federal Implementation ~~Plan.~~Plan (FIP). 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 2008 decision.

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In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a ~~federal implementation plan (FIP)~~FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The USEPA Administrator signed the final rule, now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our operations and result in material compliance costs.

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. The final rule was published in the Federal Register on March 21, 2011. This regulation affects seven auxiliary boilers used for start-up purposes at DP&L’s generation facilities. The regulations contain emissions limitations, operating limitations and other requirements. In December 2011, the USEPA proposed additional changes to this rule and solicited comments. Compliance costs are not expected to be material to DP&L’s operations.

On May 3, 2010, the USEPA finalized the “National Emissions Standards for Hazardous Air Pollutants” 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. Compliance costs onfor DP&L’s operations are not expected to be material.

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Carbon ~~Emissions~~ and Other Greenhouse ~~Gases~~Gas Emissions

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~~CO2 and other GHGs “regulated air pollutants” under the CAA.

Under USEPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the USEPA began regulating GHG emissions from certain stationary sources in January 2011. The Tailoring Rule sets forth criteria for determining which facilities are required to obtain permits for their GHG emissions pursuant to the CAA Prevention of Significant Deterioration and Title V operating permit programs. Under the Tailoring Rule, permitting requirements are being phased in through successive steps that may expand the scope of covered sources over time. The USEPA has issued guidance on what the best available control technology entails for the control of GHGs and individual states are required to determine what controls are required for facilities on a case-by-case basis. The ultimate impact of the Tailoring Rule to DP&L cannot be determined at this time, but the cost of compliance could be material.

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On April 13, 2012, the USEPA published its proposed GHG standards for new electric generating units (EGUs) under CAA subsection 111(b), which would require certain new EGUs to meet a standard of 1,000 pounds of ~~carbon dioxide~~CO2 per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive ~~carbon dioxide~~CO2 emission control technology to meet the standard. Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d). These latter rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.

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. Further GHG legislation or regulation 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 condition. However, due to the uncertainty associated with such legislation or regulation, we cannot predict the final outcome or the financial impact that such legislation or regulation may 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,GHGs, including ~~electric generating units.~~EGUs. DP~~&L’s~~&L ~~first report~~has submitted to ~~the~~ USEPA ~~was submitted prior to the September 30, 2011 due date~~GHG emission reports for ~~2010 emissions. This~~2012 and 2011. While this reporting rule will guide development of policies and programs to reduce ~~emissions.~~emissions, DP&L does not anticipate that ~~this~~the reporting rule will itself result in any significant cost or other effect on current operations.

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Plants

On June 20, 2011, the U.S. Supreme Court ruled that the USEPA’s regulation of GHGs under the CAA displaced any right that plaintiffs may have had to seek similar regulation through federal common law litigation in the court system. 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 have been affected by the outcome of these lawsuits or similar suits that may have been filed against other electric power companies, including DP&L. Because the issue was not squarely before it, the U.S. Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under state law.

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As a result of a 2008 consent decree entered into with the Sierra Club and approved by the U.S. District Court for the Southern District of Ohio, DP&L and the other owners of the J.M. Stuart generating station are subject to certain specified emission targets related to NOx, SO2 and particulate matter. The consent decree also includes commitments for energy efficiency and renewable energy activities. An amendment to the consent decree was entered into and approved in 2010 to clarify how emissions would be computed during malfunctions. Continued compliance with the consent decree, as amended, is not expected to have a material effect on DP&L’s results of operations, financial condition or cash flows in the future.

Notices of Violation Involving Co-Owned Plants

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 Duke Energy (Beckjord Unit 6) and CSP (Conesville Unit 4) and co-owned by DP&L were referenced in these actions. 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 June 2000, the USEPA issued an NOV to the DP&L-operated J.M. Stuart generating station (co-owned by DP&L, Duke Energy, and CSP) for alleged violations of the CAA. The NOV contained allegations that Stuart station engaged in projects between 1978 and 2000 without New Source Review and ~~PSD~~Prevention of Significant Deterioration permits that resulted in significant increases in particulate matter, SO2, and NOx. These allegations are consistent with NOVs and complaints that the USEPA had 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. DP&L cannot predict the outcome of this matter.

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In December 2007, the Ohio EPA issued an NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The NOV 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.

On March 13, 2008, Duke Energy, the operator of the Zimmer generating station, received an NOV and a Finding of Violation (FOV) 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. A second NOV and FOV with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess emissions. DP&L is a co-owner of the Zimmer generating station and could be affected by the eventual resolution of these matters. Duke Energy is expected to act on behalf of itself and the co-owners with respect to these matters. DP&L is unable to predict the outcome of these matters.

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 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. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and the U.S. Department of Justice to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.

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Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act — Regulation of Water Intake

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. 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 released new proposed regulations on March 28, 2011, published in the Federal Register on April 20, 2011. We submitted comments to the proposed regulations on August 17, 2011. ~~The~~It is anticipated that the final rules ~~are expected to~~will be promulgated in ~~place by mid-2012.~~mid-2013. We do not yet know the ~~impact~~effect these proposed rules will have on our operations.

Clean Water Act — Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart station NPDES 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 a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement 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. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. On May 17, 2012, we met with Ohio EPA to discuss this matter. It is not known what additional actions the agency might take. Depending on the outcome of the process, the effects could be material on DP&L’s ~~operation.~~

~~Table of Contents~~operations.

In September 2009, the USEPA announced that it will be revising technology-based regulations governing water discharges from steam electric generating facilities. The rulemaking included the collection of information via an industry-wide questionnaire as well as targeted water sampling efforts at selected facilities. It is anticipated that the USEPA will release a proposed rule by November 2012 with a final regulation in place by early 2014. At present, DP&L is unable to predict the impact this rulemaking will have on its operations.

In April 2012, DP&Lreceived an NOV related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. USEPA has indicated that they may take additional enforcement action. DP&L~~will install~~ has installed sedimentation ponds as part of the runoff control measures to address this ~~issue. We expect~~issue and is working with the ~~impact~~various agencies to resolve their concerns. This may affect the landfill’s construction schedule and delay its operational date. DP&L has accrued an immaterial amount for anticipated penalties related to this issue.

Table of ~~this NOV to be immaterial.~~Contents

Regulation of 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 granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010. 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. On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. In June 2012, DP&L filed a motion for summary judgment on grounds that the remaining claims for contribution are barred by a statute of limitations. The plaintiffs opposed that motion and, additionally, have filed a motion seeking Court leave to amend their complaint to add more than 20 new defendants to the case and to recharacterize and re-allege claims against DP&L that the Court dismissed in its February 10, 2011 order. While DP&L is unable 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 its operations.

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 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 its operations.

On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCBs). While this reassessment is in the early stages and the USEPA is ~~seeking~~evaluating information from potentially affected parties on how it should proceed, the outcome may have a material adverse effect on DP&L. The USEPA has indicated that a proposed rule will be released in late 2012. At present, DP&L is unable to predict the impact this initiative will have on its operations.

Regulation of Ash Ponds

In 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 the Hutchings station.

In August 2010, the USEPA conducted an inspection of the Hutchings station ash ponds. In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the Hutchings station ash ponds. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.

In June 2011, the USEPA conducted an inspection of the Killen station ash ponds. In June 2012, the USEPA issued a draft report from the inspection that noted no significant issues with the ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.

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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 byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable to predict the financial effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse effect on operations.

Notice of Violation Involving Co-Owned Plants

On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act ~~National Pollutant Discharge Elimination System~~NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flow.

Legal and Other Matters

In February 2007, DP&L filed a lawsuit in the United States District Court for Southern District of Ohio against ~~a coal supplier~~Appalachian Fuels, LLC (“Appalachian”) seeking damages incurred due to ~~the supplier’s~~Appalachian’s failure to supply approximately 1.5 million tons of coal to two commonly 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~~Appalachian has denied liability, and is currently in federal bankruptcy proceedings in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

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. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. On July 5, 2012, a Stipulation was executed and filed with the FERC that resolves SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries) and Exelon Corporation (and its subsidiaries). If the Stipulation is approved, DP&L would receive approximately $14.6 million from BP. DP&L will record the settlement of the BP claims once FERC approval is received. With respect to ~~unsettled~~these claims, DP&L management has deferred $18.1 million and $17.8 million as of ~~March 31,~~June 30, 2012 and December 31, 2011, respectively, as Other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The amount at ~~March 31,~~June 30, 2012 and December 31, 2011 includes estimated earnings and interest of ~~$5.5~~$5.4 million and $5.2 million, respectively.

On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, but on appeal subject to ~~possible~~ appellate court review. These orders do not affect ~~prior~~ settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that ~~had~~have not yet previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.

Lawsuits were filed in connection with the Merger seeking, among other things, one or more of the following: to enjoin consummation of the Merger until certain conditions were met, to rescind the Merger or for rescissory damages, or to commence a sale process and/or obtain an alternative transaction or to recover an unspecified amount of other damages and costs, including attorneys’ fees and expenses, or a constructive trust or an accounting from the individual defendants for benefits they allegedly obtained as a result of their alleged breach of duty. All of these lawsuits, except one, were resolved and/or dismissed prior to the March 28, 2012 filing of our Form 10-K for the fiscal year ending December 31, 2011, and were discussed in that and previous reports we filed. The last of these lawsuits was dismissed on March 29, ~~2012 as noted below.~~2012.

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~~On April 28, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming~~ ~~DPL~~ ~~and each member of~~ ~~DPL’s~~ ~~board of directors as defendants. The lawsuit filed by Payne Family Trust was a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders. On March 29, 2012, the Court entered an order dismissing this lawsuit with prejudice pursuant to a stipulation filed by the parties. Plaintiff had alleged, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the Merger of~~ ~~DPL~~ ~~and AES.~~

14. Business Segments

DPL operates through two segments consisting of the operations of two of its wholly owned subsidiaries, DP&L (Utility segment) and DPLER, ~~(Competitive Retail segment) and~~including the results of DPLER’s wholly owned subsidiary, MC Squared (Competitive Retail segment). This is how we view our business and make decisions on how to allocate resources and evaluate performance.

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to ~~more than 45,000~~approximately 70,000 customers currently located throughout Ohio and in Illinois. In February 2011, DPLER purchased MC Squared, a Chicago-based retail electricity supplier, which serves more than ~~4,000~~5,900 customers in Northern Illinois. At the end of the second quarter of 2012, MC Squared added approximately 29,000 new customers in Illinois cities as a result of various governmental aggregation agreements. These new customers have not yet been billed and are not included in the customer counts above. Due to increased competition in Ohio, since 2010 we have increased the number of employees and resources assigned to manage the Competitive Retail segment and increased its marketing to customers. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Included within the “Other” column are other businesses that do not meet the GAAP requirements for disclosure as reportable segments as well as certain corporate costs which include interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin. The accounting policies of the reportable segments are the same as those described in Note 1 — Overview and Summary of Significant Accounting Policies. Intersegment sales and profits are eliminated in consolidation.

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The following table presents financial information for each of DPL’s reportable business segments:

Successor

$ in millions

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Quarter Ended March 31, 2012

Revenues from external customers

$
312.8

$
112.1

$
9.1

$
—

$
434.0

Intersegment revenues

86.8

—

0.9

(87.7
)
—

Total revenues

399.6

112.1

10.0

(87.7
)
434.0

Fuel

95.6

—

1.8

—

97.4

Purchased power

84.9

96.7

—

(86.8
)
94.8

Amortization of intangibles

—

—

27.8

—

27.8

Gross margin

$
219.1

$
15.4

$
(19.6
)
$
(0.9
)
$
214.0

Depreciation and amortization

$
34.7

$
0.2

$
(3.5
)
$
—

$
31.4

Interest expense

9.6

0.2

20.0

(0.2
)
29.6

Income tax expense (benefit)

17.3

3.4

(13.0
)
—

7.7

Net income (loss)

38.1

6.0

(22.4
)
—

21.7

Cash capital expenditures

53.2

0.4

0.4

—

54.0

Total assets

3,501.6

72.8

2,482.4

—

6,056.8

Predecessor

Quarter Ended March 31, 2011

Revenues from external customers

$
374.7

$
94.0

$
11.9

$
—

$
480.6

Intersegment revenues

75.1

—

1.0

(76.1
)
—

Total revenues

449.8

94.0

12.9

(76.1
)
480.6

Fuel

98.6

—

1.1

—

99.7

Purchased power

117.8

77.7

0.4

(75.1
)
120.8

Gross margin

$
233.4

$
16.3

$
11.4

$
(1.0
)
$
260.1

Depreciation and amortization

$
33.1

$
0.2

$
1.8

$
—

$
35.1

Interest expense

9.7

—

7.2

—

16.9

Income tax expense (benefit)

27.0

6.6

(8.8
)
—

24.8

Net income (loss)

52.7

6.1

(14.8
)
(0.5
)
43.5

Cash capital expenditures

42.4

—

0.6

—

43.0

Year ended December 31, 2011

Total assets

3,525.7

69.9

2,511.9

—

6,107.5

$ in millions	Utility		Competitive Retail			Other			Adjustments and Eliminations			DPL Consolidated

Three Months Ended June 30, 2012
Revenues from external customers	$	261.7	$	109.9		$	10.4		$	—		$	382.0
Intersegment revenues	84.9		—			0.8			(85.7		)	—
Total revenues	346.6		109.9			11.2			(85.7		)	382.0

Fuel	68.6		—			3.0			—			71.6
Purchased power	69.3		95.5			0.4			(84.9		)	80.3
Amortization of intangibles	—		—			28.6			—			28.6

Gross margin	$	208.7	$	14.4		$	(20.8	)	$	(0.8	)	$	201.5

Depreciation and amortization	$	36.1	$	(0.1	)	$	(6.3	)	$	—		$	29.7
Interest expense	9.4		0.1			23.1			(0.2		)	32.4
Income tax expense (benefit)	15.6		6.5			(13.4		)	—			8.7
Net income (loss)	31.3		1.5			(27.9		)	—			4.9

Cash capital expenditures	56.3		0.1			0.1			—			56.5
Total assets	3,488.5		76.5			2,406.4			—			5,971.4

Predecessor

Three Months Ended June 30, 2011
Revenues from external customers	$	315.9	$	102.0	$	15.4		$	—		$	433.3
Intersegment revenues	81.0		—		1.0			(82.0		)	—
Total revenues	396.9		102.0		16.4			(82.0		)	433.3

Fuel	89.1		—		3.0			—			92.1
Purchased power	104.4		89.5		0.7			(81.0		)	113.6

Gross margin	$	203.4	$	12.5	$	12.7		$	(1.0	)	$	227.6

Depreciation and amortization	$	33.4	$	—	$	1.7		$	—		$	35.1
Interest expense	9.7		0.1		7.9			(0.1		)	17.6
Income tax expense (benefit)	15.5		3.3		(2.5		)	—			16.3
Net income (loss)	30.8		5.7		(3.7		)	(1.1		)	31.7

Cash capital expenditures	48.4		—		—			—			48.4

Year Ended December 31, 2011
Total assets	3,525.7		69.9		2,472.1			—			6,067.7

4550

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Successor

$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated

Six Months Ended June 30, 2012
Revenues from external customers	$	574.5	$	222.0	$	19.5		$	—		$	816.0
Intersegment revenues	171.7		—		1.7			(173.4		)	—
Total revenues	746.2		222.0		21.2			(173.4		)	816.0

Fuel	164.2		—		4.8			—			169.0
Purchased power	154.2		192.2		0.4			(171.7		)	175.1
Amortization of intangibles	—		—		56.4			—			56.4

Gross margin	$	427.8	$	29.8	$	(40.4	)	$	(1.7	)	$	415.5

Depreciation and amortization	$	70.8	$	0.1	$	(9.8	)	$	—		$	61.1
Interest expense	19.0		0.3		43.1			(0.4		)	62.0
Income tax expense (benefit)	32.9		9.9		(26.4		)	—			16.4
Net income (loss)	69.4		7.5		(50.3		)	—			26.6

Cash capital expenditures	109.5		0.5		0.5			—			110.5
Total assets	3,488.5		76.5		2,406.4			—			5,971.4

Predecessor

Six Months Ended June 30, 2011
Revenues from external customers	$	690.6	$	196.0	$	27.3		$	—		$	913.9
Intersegment revenues	156.1		—		2.0			(158.1		)	—
Total revenues	846.7		196.0		29.3			(158.1		)	913.9

Fuel	187.7		—		4.2			—			191.9
Purchased power	222.2		167.2		1.1			(156.1		)	234.4

Gross margin	$	436.8	$	28.8	$	24.0		$	(2.0	)	$	487.6

Depreciation and amortization	$	66.5	$	0.1	$	3.6		$	—		$	70.2
Interest expense	19.4		0.1		15.1			(0.1		)	34.5
Income tax expense (benefit)	42.5		9.9		(11.3		)	—			41.1
Net income (loss)	83.5		11.8		(18.5		)	(1.6		)	75.2

Cash capital expenditures	90.8		—		0.6			—			91.4

Year Ended December 31, 2011
Total assets	3,525.7		69.9		2,472.1			—			6,067.7

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FINANCIAL STATEMENTS

The Dayton Power and Light Company

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

							Three Months Ended						Six Months Ended
	Three Months Ended March 31,						June 30,						June 30,
$ in millions	2012			2011			2012			2011			2012			2011

Revenues	$	399.6		$	449.8		$	346.6		$	396.9		$	746.2		$	846.7

Cost of revenues:
Fuel	95.6			98.6			68.6			89.1			164.2			187.7
Purchased power	84.9			117.8			69.3			104.4			154.2			222.2
Total cost of revenues	180.5			216.4			137.9			193.5			318.4			409.9

Gross margin	219.1			233.4			208.7			203.4			427.8			436.8

Operating expenses:
Operation and maintenance	99.2			91.4			96.0			95.1			195.2			186.5
Depreciation and amortization	34.7			33.1			36.1			33.4			70.8			66.5
General taxes	20.2			19.6			19.6			19.1			39.8			38.7
Total operating expenses	154.1			144.1			151.7			147.6			305.8			291.7

Operating income	65.0			89.3			57.0			55.8			122.0			145.1

Other income / (expense), net:
Investment income	0.1			0.6			0.1			0.5			0.2			1.1
Interest expense	(9.6		)	(9.7		)	(9.4		)	(9.7		)	(19.0		)	(19.4		)
Other income / (expense)	(0.1		)	(0.5		)	(0.8		)	(0.3		)	(0.9		)	(0.8		)
Total other income / (expense), net	(9.6		)	(9.6		)	(10.1		)	(9.5		)	(19.7		)	(19.1		)

Earnings before income tax	55.4			79.7			46.9			46.3			102.3			126.0

Income tax expense	17.3			27.0			15.6			15.5			32.9			42.5

Net income	38.1			52.7			31.3			30.8			69.4			83.5

Dividends on preferred stock	0.2			0.2			0.2			0.2			0.4			0.4

Earnings on common stock	$	37.9		$	52.5		$	31.1		$	30.6		$	69.0		$	83.1

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

Three Months Ended
March 31,

$ in millions

2012

2011

Net income / (loss)

$
38.1

$
52.7

Available-for-sale securities activity:

Change in fair value of available-for-sale securities, net of income tax expense of $(0.2) and $(0.5), respectively

0.4

0.9

Total change in fair value of available-for-sale securities

0.4

0.9

Derivative activity:

Change in derivative fair value, net of income tax benefit of $0.8 and $(0.3), respectively

(1.5
)
0.5

Reclassification of earnings, net of income tax (expense) of $0.6 and $0.2, respectively

(1.7
)
(0.9
)

Total change in fair value of derivatives

(3.2
)
(0.4
)

Pension and postretirement activity:

Reclassification to earnings, net of income tax expense of $(0.7) and $(0.4), respectively

1.1

1.2

Total change in unfunded pension obligation

1.1

1.2

Other comprehensive income / (loss)

(1.7
)
1.7

Net comprehensive income / (loss)

$
36.4

$
54.4

~~See Notes to Condensed Financial Statements.~~

~~These interim statements are unaudited.~~

	Three Months Ended						Six Months Ended
	June 30,						June 30,
$ in millions	2012			2011			2012			2011

Net income / (loss)	$	31.3		$	30.8		$	69.4		$	83.5

Available-for-sale securities activity:
Change in fair value of available-for-sale securities, net of income tax benefit / (expense) of $0.0 and $(0.9), respectively, for the three months and $(0.2) and $(1.4), respectively, for the six months	(0.1		)	1.8			0.3			2.7

Total change in fair value of available-for-sale securities	(0.1		)	1.8			0.3			2.7

Derivative activity:
Change in derivative fair value, net of income tax benefit / (expense) of $0.0 and $0.3, respectively, for the three months and $0.8 and $0.5, respectively, for the six months	(0.1		)	(0.7		)	(1.6		)	(0.9		)
Reclassification of earnings, net of income tax benefit / (expense) of $0.0 and $(0.3), respectively, for the three months and $(0.6) and $(0.6), respectively, for the six months	(0.5		)	—			(2.3		)	—

Total change in fair value of derivatives	(0.6		)	(0.7		)	(3.9		)	(0.9		)

Pension and postretirement activity:
Reclassification to earnings, net of income tax benefit / (expense) of $(0.4) and $(0.1), respectively, for the three months and $(1.1) and $(0.1), respectively, for the six months	0.8			0.4			2.0			1.4

Total change in unfunded pension obligation	0.8			0.4			2.0			1.4

Other comprehensive income / (loss)	0.1			1.5			(1.6		)	3.2

Net comprehensive income / (loss)	$	31.4		$	32.3		$	67.8		$	86.7

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

							Six Months Ended
	Three Months Ended March 31,						June 30,
$ in millions	2012			2011			2012			2011
Cash flows from operating activities:
Net income	$	38.1		$	52.7		$	69.4		$	83.5
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	34.7			33.1			70.8			66.5
Deferred income taxes	(2.4		)	33.3			3.3			37.2
Changes in certain assets and liabilities:
Accounts receivable	(0.6		)	11.9			19.5			25.5
Inventories	(2.0		)	1.3			(2.5		)	1.5
Prepaid taxes							0.4			(19.2		)
Taxes applicable to subsequent years	21.5			15.7			38.4			31.4
Deferred regulatory costs, net	7.1			12.8			(0.1		)	8.9
Accounts payable	(2.2		)	(4.0		)	6.5			(7.8		)
Accrued taxes payable	(15.0		)	(28.9		)	(46.8		)	(32.3		)
Accrued interest payable	7.5			7.6			5.2			5.3
Pension, retiree and other benefits	2.1			(41.2		)	4.6			(42.7		)
Unamortized investment tax credit	(0.6		)	(0.7		)	(1.3		)	(1.4		)
Other	1.4			(9.6		)	6.1			6.8
Net cash provided by operating activities	89.6			84.0			173.5			163.2

Cash flows from investing activities:
Capital expenditures	(53.2		)	(42.4		)	(109.5		)	(90.8		)
Other investing activities, net	—			2.0			—			1.7
Net cash used for investing activities	(53.2		)	(40.4		)	(109.5		)	(89.1		)

Cash flows from financing activities:
Dividends paid on common stock to parent	(45.0		)	(70.0		)	(70.0		)	(115.0		)
Dividends paid on preferred stock	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Retirement of long-term debt							(0.1		)	—
Withdrawals from revolving credit facilities	—			50.0			—			50.0
Repayment of borrowings from revolving credit facilities	—			(20.0		)	—			(50.0		)
Net cash used for financing activities	(45.2		)	(40.2		)	(70.5		)	(115.4		)

Cash and cash equivalents:
Net change	(8.8		)	3.4			(6.5		)	(41.3		)
Balance at beginning of period	32.2			54.0			32.2			54.0
Cash and cash equivalents at end of period	$	23.4		$	57.4		$	25.7		$	12.7

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	2.4		$	2.3		$	14.4		$	14.6
Income taxes paid, net	$	6.1		$	—		$	16.6		$	24.1
Non-cash financing and investing activities:
Accruals for capital expenditures	$	24.1		$	18.3		$	25.3		$	22.6
Long-term liability incurred for the purchase of assets	$	—		$	18.7		$	—		$	18.7

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

	At			At			At			At
	March 31,			December 31,			June 30,			December 31,
$ in millions	2012			2011			2012			2011

ASSETS

Current assets:
Cash and cash equivalents	$	23.4		$	32.2		$	25.7		$	32.2
Accounts receivable, net (Note 3)	181.1			178.5			157.0			178.5
Inventories (Note 3)	125.1			123.1			125.6			123.1
Taxes applicable to subsequent years	50.4			71.9			33.4			71.9
Regulatory assets, current (Note 4)	12.7			17.7			19.3			17.7
Other prepayments and current assets	24.6			25.0			23.1			25.0
Total current assets	417.3			448.4			384.1			448.4

Property, plant and equipment:
Property, plant and equipment	5,318.6			5,277.9			5,376.2			5,277.9
Less: Accumulated depreciation and amortization	(2,596.5		)	(2,568.9		)	(2,627.0		)	(2,568.9		)
	2,722.1			2,709.0			2,749.2			2,709.0

Construction work in process	149.4			150.7			144.2			150.7
Total net property, plant and equipment	2,871.5			2,859.7			2,893.4			2,859.7

Other noncurrent assets:
Regulatory assets, non-current (Note 4)	172.9			177.8			170.9			177.8
Intangible assets	7.3			6.5			10.0			6.5
Other deferred assets	32.6			33.3			30.1			33.3
Total other noncurrent assets	212.8			217.6			211.0			217.6

Total Assets	$	3,501.6		$	3,525.7		$	3,488.5		$	3,525.7

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

March 31,

December 31,

June 30,

December 31,

$ in millions

2012

2011

2012

2011

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:

Current portion - long-term debt (Note 6)

0.4

0.4

0.4

0.4

Accounts payable

97.8

106.0

104.5

106.0

Accrued taxes

95.6

72.8

63.9

72.8

Accrued interest

15.4

7.9

13.2

7.9

Customer security deposits

16.4

15.8

16.4

15.8

Other current liabilities

47.3

41.4

54.4

41.4

Total current liabilities

272.9

244.3

252.8

244.3

Noncurrent liabilities:

Long-term debt (Note 6)

902.9

903.0

902.8

903.0

Deferred taxes (Note 7)

634.0

637.7

639.2

637.7

Taxes payable

55.5

93.9

Regulatory liabilities, non-current (Note 4)

118.5

118.6

118.2

118.6

Pension, retiree and other benefits

47.7

47.5

47.2

47.5

Unamortized investment tax credit

29.3

29.9

28.6

29.9

Derivative liability

2.7

3.9

Other deferred credits

124.3

163.9

63.3

66.1

Total noncurrent liabilities

1,856.7

1,900.6

1,857.5

1,900.6

Redeemable preferred stock

22.9

22.9

22.9

22.9

Commitments and contingencies (Note 12)

Common shareholder’s equity:

Common stock, at par value of $0.01 per share

0.4

0.4

0.4

0.4

Other paid-in capital

803.1

803.1

803.1

803.1

Accumulated other comprehensive loss

(36.4

)

(34.7

)

(36.3

)

(34.7

)

Retained earnings

582.0

589.1

588.1

589.1

Total common shareholder’s equity

1,349.1

1,357.9

1,355.3

1,357.9

Total Liabilities and Shareholder’s Equity

3,501.6

3,525.7

3,488.5

3,525.7

See Notes to Condensed Financial Statements.

These interim statements are unaudited.

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Notes to Condensed Financial Statements (Unaudited)

1. Overview and Summary of Significant Accounting Policies

Description of Business

On November 28, 2011, DP&L’s parent company DPL was acquired by AES in the Merger and DPL became an indirectly wholly owned subsidiary of AES. See Note 2 for more information.

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

DP&L employed ~~1,450~~1,446 people as of ~~March 31,~~June 30, 2012. Approximately ~~53%~~54% of all employees are under a collective bargaining agreement which expires on October 31, 2014.

Financial Statement Presentation

DP&L does not have any subsidiaries. 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 excise taxes collected from customers have been reclassified out of operating expense and recorded as a reduction in revenues in the 2011 presentation to conform to AES’ presentation of these items. These taxes are presented net within revenue. Certain immaterial amounts from prior periods have been reclassified to conform to the current reporting presentation.

In the opinion of our management, the Condensed Financial Statements presented in this report contain all adjustments necessary to fairly state our financial condition as of ~~March 31, 2012;~~June 30, 2012, our results of operations for the three and six months ended ~~March 31,~~June 30, 2012 and our cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2012. 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 six months ended ~~March 31,~~June 30, 2012 may not be indicative of our results that will be realized for the full year ending December 31, 2012.

Table of Contents

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.

~~Table of Contents~~

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. For non-regulated property, cost also includes capitalized interest. Capitalization of AFUDC and interest ceases at either project completion or at the date specified by regulators. AFUDC and capitalized interest was ~~$1.4~~$1.2 million and $1.1 million for the three months and $2.6 million and $2.3 million for the six months ended ~~March 31,~~June 30, 2012 and 2011, respectively.

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

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

Intangibles

Intangibles consist of emission allowances and renewable energy credits. Emission allowances are carried on a first-in, ~~first out~~first-out (FIFO) basis for purchased emission allowances. Net gains or losses on the sale of excess emission allowances, representing the difference between the sales proceeds and the cost of emission allowances, are recorded as a component of our fuel costs and are reflected in Operating income when realized. Emission allowances are amortized as they are used in our operations. Renewable energy credits are amortized as they are used or retired.

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. Prior to the Merger date, certain excise and other taxes were recorded on a gross basis. Effective on the Merger date, these taxes are accounted for on a net basis and are recorded as a reduction in Revenues for presentation in accordance with AES policy. The amounts for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~$13.2~~$11.9 million and ~~$14.0~~$11.6 million, respectively. The amounts for the six months ended June 30, 2012 and 2011 were $24.8 million and $25.7 million, respectively. The 2011 ~~amount was~~amounts were reclassified to conform to this presentation.

Share-Based Compensation

We measured the cost of employee services received and paid with equity instruments based on the fair-value of such equity instrument on the grant date. This cost was recognized in results of operations over the period that employees were required to provide service. Liability awards were initially recorded based on the fair-value of equity instruments and were re-measured for the change in stock price at each subsequent reporting date until the liability was ultimately settled. The fair-value for employee share options and other similar instruments at the grant date were estimated using option-pricing models and any excess tax benefits were recognized as an addition to paid-in capital. The reduction in income taxes payable from the excess tax benefits was presented in the Condensed Statements of Cash Flows within Cash flows from financing activities. As a result of the Merger (see Note 2), vesting of all DPL share-based awards was accelerated as of the Merger date, and none are in existence at June 30, 2012.

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Related Party Transactions

In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. The following table provides a summary of these transactions:

							Three Months Ended						Six Months Ended
	Three Months Ended March 31,						June 30,						June 30,
$ in millions	2012			2011			2012			2011			2012			2011

DP&L Revenues:
Sales to DPLER (a)	$	83.0		$	75.1		$	86.7		$	81.0		$	169.7		$	156.1
Sales to MC Squared							$	0.3		$	—		$	0.3		$	—

DP&L Operation & Maintenance Expenses:
Premiums paid for insurance services provided by MVIC (b)	(0.6		)	(0.8		)	(0.6		)	(0.8		)	(1.3		)	(1.6		)
Expense recoveries for services provided to DPLER (c)	0.9			0.9			0.6			0.8			1.5			1.7

(a) DP&L sells power to DPLER to satisfy the electric requirements of DPLER’s retail customers. The revenue dollars associated with sales to DPLER are recorded as wholesale revenues in DP&L’s Financial Statements. The increase in DP&L’s sales to DPLER during the three and six months ended ~~March 31,~~June 30, 2012, compared to the three and six months ended ~~March 31,~~June 30, 2011, is primarily due to customers electing to switch their generation service from DP&L to DPLER.~~DP&L~~ ~~did not sell any physical power to MC Squared during either of these periods.~~

(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.

Recently Issued Accounting Standards

Offsetting Assets and Liabilities

Recently Adopted Accounting Standards

Fair Value Disclosures

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Comprehensive Income

~~Table of Contents~~

~~Goodwill Impairment~~

In September 2011, the FASB issued ASU 2011-08 “Testing Goodwill for Impairment” (ASU 2011-08) effective for interim and annual reporting periods beginning after December 15, 2011. We adopted this ASU on January 1, 2012. This standard updates FASC Topic 350, “Intangibles-Goodwill and Other.” ASU 2011-08 allows an entity to first test Goodwill using qualitative factors to determine if it is more likely than not that the fair value of a reporting unit has been impaired; if so, then the two-step impairment test is performed. We will incorporate these new requirements in our future goodwill impairment testing.

2. Business Combination

On November 28, 2011, all of the outstanding common stock of DP&L’s parent company, DPL, was acquired by AES. In accordance with FASC 805, the assets and liabilities of DPL were valued at their fair value at the Merger date. These adjustments were “pushed down” to DPL’s records. These adjustments were not pushed down to DP&L which will continue to use its historic costs for its assets and liabilities.

3. Supplemental Financial Information

	At			At			At			At
	March 31,			December 31,			June 30,			December 31,
$ in millions	2012			2011			2012			2011

Accounts receivable, net:
Unbilled revenue	$	39.3		$	49.5		$	48.0		$	49.5
Customer receivables	89.2			85.8			75.8			85.8
Amounts due from partners in jointly-owned plants	31.2			29.2			20.4			29.2
Coal sales	9.2			1.0			3.1			1.0
Other	13.2			13.9			10.6			13.9
Provision for uncollectible accounts	(1.0		)	(0.9		)	(0.9		)	(0.9		)
Total accounts receivable, net	$	181.1		$	178.5		$	157.0		$	178.5

Inventories, at average cost:
Fuel and limestone	$	83.9		$	82.8		$	84.9		$	82.8
Plant materials and supplies	39.4			38.6			38.8			38.6
Other	1.8			1.7			1.9			1.7
Total inventories, at average cost	$	125.1		$	123.1		$	125.6		$	123.1

Accumulated Other Comprehensive Income (Loss)

AOCI is included on our balance sheets within the Common shareholders’ equity sections. The following table provides the components that constitute the balance sheet amounts in AOCI at ~~March 31,~~June 30, 2012 and December 31, 2011:

	March 31,			December 31,			June 30,			December 31,
$ in millions	2012			2011			2012			2011

Financial instruments, net of tax	$	1.0		$	0.6		$	0.9		$	0.6
Cash flow hedges, net of tax	5.8			9.0			5.2			9.0
Pension and postretirement benefits, net of tax	(43.2		)	(44.3		)	(42.4		)	(44.3		)
Total	$	(36.4	)	$	(34.7	)	$	(36.3	)	$	(34.7	)

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4. Regulatory Assets and Liabilities

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

Regulatory assets and liabilities for DP&L are as follows:

Type of

Amortization

March 31,

December 31,

Type of

Amortization

June 30,

December 31,

$ in millions

Recovery (a)

Through

2012

2011

Recovery (a)

Through

2012

2011

Current Regulatory Assets:

TCRR, transmission, ancillary and other PJM-related costs

Ongoing

2.8

4.7

Ongoing

5.4

4.7

Power plant emission fees

Ongoing

3.1

4.8

Ongoing

1.4

4.8

Fuel and purchased power recovery costs

Ongoing

6.8

8.2

Ongoing

12.5

8.2

Total current regulatory assets

12.7

17.7

19.3

17.7

Non-current Regulatory Assets:

Deferred recoverable income taxes

B/C

Ongoing

23.3

24.1

B/C

Ongoing

22.5

24.1

Pension and postretirement benefits

Ongoing

90.5

92.1

Ongoing

88.9

92.1

Unamortized loss on reacquired debt

Ongoing

12.6

13.0

Ongoing

12.4

13.0

Regional transmission organization costs

2014

3.7

4.1

2014

3.3

4.1

Deferred storm costs - 2008

18.2

17.9

18.5

17.9

CCEM smart grid and advanced metering infrastructure costs

6.6

6.6

6.6

6.6

CCEM energy efficiency program costs

Ongoing

6.9

8.8

Ongoing

7.3

8.8

Consumer education campaign

3.0

3.0

3.0

3.0

Retail settlement system costs

3.1

3.1

3.1

3.1

Other costs

5.0

5.1

5.3

5.1

Total non-current regulatory assets

172.9

177.8

170.9

177.8

Non-current Regulatory Liabilities:

Estimated costs of removal - regulated property

112.5

112.4

112.4

112.4

Postretirement benefits

6.0

6.2

5.8

6.2

Total non-current regulatory liabilities

118.5

118.6

118.2

118.6

(a) B — Balance has an offsetting liability resulting in no effect 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.

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Regulatory Assets

Fuel and purchased power recovery costs represent prudently incurred fuel, purchased power, derivative, emission and other related costs which will be recovered from or returned to customers in the future through the operation of the fuel and purchased power recovery rider. The fuel and purchased power recovery rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter. DP&L implemented the fuel and purchased power recovery rider on January 1, 2010. As part of the PUCO approval process, an outside auditor is hired to review fuel costs and the fuel procurement process. ~~We received~~The auditor has recommended that the ~~audit report for 2011 on April 27, 2012.~~PUCO consider reducing DP&L’s recovery of fuel costs by approximately $3.3 million from certain transactions. We will have further discussions with interested parties concerning the audit report in the ~~second quarter~~last half of 2012.

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.

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.

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Consumer education campaign represents costs for consumer education advertising regarding electric deregulation and its related rate case.

Other costs primarily include RPM capacity, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.

Regulatory Liabilities

5. Ownership of Coal-fired Facilities

DP&L and certain other Ohio utilities have undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of ~~March 31,~~June 30, 2012, DP&L had ~~$55.0~~$71.0 million of construction work in process at such jointly-owned 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. Each joint owner provides their own financing for their share of the operations and capital expenditures of the jointly owned plant.

DP&L’s undivided ownership interest in such facilities as well as our wholly owned ~~coal fired~~coal-fired Hutchings station at ~~March 31,~~June 30, 2012, is as follows:

DP&L Share

DP&L Investment

SCR and FGD

Equipment

Summer

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

207

$
75

$
59

$
—

No

Conesville Unit 4

16.5

129

121

33

3

Yes

East Bend Station

31.0

186

202

134

5

Yes

Killen Station

67.0

402

617

302

6

Yes

Miami Fort Units 7 and 8

36.0

368

366

142

2

Yes

Stuart Station

35.0

808

731

281

11

Yes

Zimmer Station

28.1

365

1,059

630

28

Yes

Transmission (at varying percentages)

91

58

—

Total

2,465

$
3,262

$
1,639

$
55

Wholly-owned production unit:

Hutchings Station

100.0

365

$
123

$
115

$
—

No

~~Table of Contents~~

	DP&L Share		DP&L Investment
									SCR and FGD
									Equipment
		Summer					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	207	$	75	$	61	$	—	No
Conesville Unit 4	16.5	129	121		34		7		Yes
East Bend Station	31.0	186	202		134		7		Yes
Killen Station	67.0	402	624		305		6		Yes
Miami Fort Units 7 and 8	36.0	368	366		144		2		Yes
Stuart Station	35.0	808	737		286		11		Yes
Zimmer Station	28.1	365	1,059		634		38		Yes
Transmission (at varying percentages)			92		58		—
Total		2,465	$	3,276	$	1,656	$	71

Wholly-owned production unit:
Hutchings Station	100.0	365	$	123	$	115	$	1	No

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including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. DP&L does not object to Duke’s decision. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.

We are considering options for the Hutchings station, but have not yet made a final decision. DP&L has informed PJM that Hutchings Unit 4 has incurred damage to a rotor and will be deactivated and unavailable for service until at least June 1, 2014, if ever. In addition, DP&L has notified PJM that Hutchings Units 1 and 2 will be deactivated by June 1, 2015. The decision to deactivate Units 1 and 2 has been made because these two units are not equipped with the advanced environmental control technologies needed to comply with the MACT standard and the cost of compliance with the MACT standard or conversion to natural gas for these units would likely exceed the expected return. DP&L is still studying the option of converting two or more of Hutchings Units 3-6 to natural gas in order to comply with environmental requirements. We do not believe that any accruals ~~or impairment charges~~ are needed related to the Hutchings station.

~~As part of~~Due to changes in the provisional DPL purchase ~~accounting adjustments related to~~price allocation that were recognized in the ~~Merger with AES, four plants (Beckjord, Conesville, East Bend and Hutchings)~~second quarter of 2012, 18 generating facilities had ~~future expected cash flows that, when discounted, produced~~ a ~~zero~~combined decline in estimated fair market ~~value. Since~~value of approximately $114.1 million as of June 30, 2012. Because DP&L did not apply push down accounting to its respective assets and liabilities at the time of purchase, this ~~valuation~~change in purchase price allocation also did not affect the ~~book value~~respective carrying values for DP&L’s generating facilities as of ~~these plants’ valuation at~~ ~~DP&L~~.June 30, 2012. However, DP&L ~~performed~~did consider whether the reduction in allocated purchase price for certain generating facilities would constitute a potential impairment indicator as of June 30, 2012. Because DP&L routinely assesses the recoverability of carrying values for various generating facilities using an ~~impairment review of these plants, which is initially based on~~estimated undiscounted future cash flows analysis, and ~~exceed their net book value so~~because there were no significant changes to estimated future undiscounted cash flows by facility as a result of the purchase price allocation adjustments referenced above, no impairment ~~is required~~indicators were identified and no impairment charges were recognized as of ~~March 31, 2012.~~June 30, 2012 by DP&L. Significant changes in expected future revenues or costs for any of these ~~plants~~facilities could result in a future impairment ~~charge.~~indicator.

6. Debt Obligations

Long-term debt is as follows:

Long-term ~~Debt~~debt

	March 31,			December 31,			June 30,			December 31,
$ in millions	2012			2011			2012			2011

First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0		$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%	35.3			35.3			35.3			35.3
Pollution control series maturing in January 2034 - 4.80%	179.1			179.1			179.1			179.1
Pollution control series maturing in September 2036 - 4.80%	100.0			100.0			100.0			100.0
Pollution control series maturing in November 2040 - variable rates:
0.04% - 0.20% and 0.06% - 0.32% (a)	100.0			100.0
Pollution control series maturing in November 2040 - variable rates: 0.04% - 0.26% and 0.06% - 0.32% (a)							100.0			100.0
U.S. Government note maturing in February 2061 - 4.20%	18.5			18.5			18.4			18.5
	902.9			902.9			902.8			902.9

Obligation for capital lease	0.3			0.4			0.2			0.4
Unamortized debt discount	(0.3		)	(0.3		)	(0.2		)	(0.3		)
Total long-term debt	$	902.9		$	903.0		$	902.8		$	903.0

Current portion - Long-term ~~Debt~~debt

	March 31,		December 31,		June 30,		December 31,
$ in millions	2012		2011		2012		2011

U.S. Government note maturing in February 2061 - 4.20%	$	0.1	$	0.1	$	0.1	$	0.1
Obligation for capital lease	0.3		0.3		0.3		0.3
Total current portion - long-term debt	$	0.4	$	0.4	$	0.4	$	0.4

(a) Range of interest rates for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and the twelve months ended December 31, 2011, respectively.

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At ~~March 31,~~June 30, 2012, maturities of long-term debt, including capital lease obligations, are summarized as follows:

$ in millions

Amount

Due within one year

$
0.4

Due within two years

470.4

Due within three years

0.2

Due within four years

0.1

Due within five years

0.1

Thereafter

432.4

$
903.6

~~Table of Contents~~

$ in millions	Amount
Due within one year	$	0.4
Due within two years	470.4
Due within three years	0.1
Due within four years	0.1
Due within five years	0.1
Thereafter	432.1
	$	903.2

On August 24, 2011, DP&L entered into a $200.0 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a four year term expiring on August 24, 2015 and provides DP&L with the ability to increase the size of the facility by an additional $50.0 million. DP&L had no outstanding borrowings under this credit facility at ~~March 31,~~June 30, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three and six months ended ~~March 31,~~June 30, 2012 and 2011. This facility also contains a ~~$50~~$50.0 million letter of credit sublimit. As of ~~March 31,~~June 30, 2012, DP&L had no outstanding letters of credit against the facility.

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7. Income Taxes

The following table details the effective tax rates for the three and six months ended ~~March 31,~~June 30, 2012 and 2011.

Three Months Ended

March 31,

2012

2011

DP&L

31.3
%
34.0
%

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011

DP&L	33.3%	33.6%	32.2%	33.8%

Income tax expenses for the three and six months ended ~~March 31,~~June 30, 2012 and 2011 were calculated using the estimated annual effective income tax rates for 2012 and 2011 and reflect estimated annual effective income tax rates of ~~31.1%~~32.0% and ~~33.7%~~33.5%, 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.

For the three and six months ended ~~March 31,~~June 30, 2012, DP&L increased income tax expense by $0.2 million and $0.3 million, respectively, due to an increase in other estimated tax liabilities.

For the three and six months ended June 30, 2012, the decrease in DP&L’s effective tax rate compared to the same period in 2011 primarily reflects decreased pre-tax book income and increased Section 199 Domestic Production Deduction benefits.

Deferred tax liabilities for DP&L ~~decreased~~increased by approximately ~~$3.7~~$5.2 million and $1.5 million, respectively, during the three and six months ended ~~March 31,~~June 30, 2012. These ~~decreases~~increases were primarily related to depreciation.

~~Table of Contents~~

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

8. Pension and Postretirement Benefits

DP&L sponsors a defined benefit pension plan for the vast majority of its employees.

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. There were no contributions made during the ~~three~~six months ~~ending March 31,~~ended June 30, 2012. DP&L made a discretionary contribution of $40.0 million to the defined benefit plan induring the ~~three~~six months ended ~~March 31,~~June 30, 2011.

The amounts presented in the following tables for pension include the collective bargaining plan formula, the traditional management plan formula, the cash balance plan formula and the SERP in the aggregate. The amounts presented for postretirement include both health and life insurance.

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The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months ended ~~March 31,~~June 30, 2012 and 2011 was:

Net Periodic Benefit Cost / (Income)

Pension

Postretirement

$ in millions

2012

2011

2012

2011

Service cost

$
1.5

$
1.4

$
0.1

$
—

Interest cost

4.3

4.3

0.3

0.3

Expected return on assets (a)

(5.7
)
(6.1
)
(0.1
)
(0.1
)
Amortization of unrecognized:

Actuarial (gain) / loss

2.7

2.3

(0.2
)
(0.2
)
Prior service cost

0.8

0.5

—

—

Net periodic benefit cost / (income) before adjustments

$
3.6

$
2.4

$
0.1

$
—

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
$ in millions	2012			2011			2012			2011
Service cost	$	1.6		$	1.5		$	—		$	0.1
Interest cost	4.3			4.3			0.1			0.2
Expected return on assets (a)	(5.6		)	(6.1		)	—			—
Amortization of unrecognized:
Actuarial (gain) / loss	2.0			2.2			(0.3		)	(0.2		)
Prior service cost	0.7			0.6			—			—
Net periodic benefit cost / (income) before adjustments	$	3.0		$	2.5		$	(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 calculation of expected return on pension plan assets for the 2012 and 2011 net periodic benefit cost was approximately $335 million and $316 million, respectively.

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the six months ended June 30, 2012 and 2011 was:

Net Periodic Benefit Cost / (Income)

	Pension						Postretirement
$ in millions	2012			2011			2012			2011
Service cost	$	3.1		$	2.9		$	0.1		$	0.1
Interest cost	8.6			8.6			0.4			0.5
Expected return on assets (a)	(11.3		)	(12.2		)	(0.1		)	(0.1		)
Amortization of unrecognized:
Actuarial (gain) / loss	4.7			4.5			(0.5		)	(0.4		)
Prior service cost	1.5			1.1			—			—
Net periodic benefit cost / (income) before adjustments	$	6.6		$	4.9		$	(0.1	)	$	0.1

Benefit payments, which reflect future service, are expected to be paid as follows:

Estimated Future Benefit Payments and Medicare Part D Reimbursements

$ in millions	Pension		Postretirement		Pension		Postretirement

2012	$	17.3	$	1.8	$	11.5	$	1.2
2013	22.7		2.3		22.7		2.3
2014	23.2		2.2		23.2		2.2
2015	23.8		2.0		23.8		2.0
2016	24.0		1.9		24.0		1.9
2017 - 2021	124.4		7.5		124.4		7.5

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9. 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 method is available to us. The ~~fair~~ value of our financial instruments represents our best estimates of ~~possible~~fair value, ~~that may or~~which may not be the value realized in the future. The table below presents the fair value and cost of our non-derivative instruments at ~~March 31,~~June 30, 2012 and December 31, 2011. See also Note 10 for the fair values of our derivative instruments.

	At March 31,				At December 31,				At June 30,				At December 31,
	2012				2011				2012				2011
$ in millions	Cost		Fair Value		Cost		Fair Value		Cost		Fair Value		Cost		Fair Value

Assets
Money Market Funds	$	0.2	$	0.2	$	0.2	$	0.2	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities (a)	3.9		5.0		3.9		4.4		4.0		4.9		3.9		4.4
Debt Securities	5.1		5.5		5.0		5.5		5.0		5.5		5.0		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.2		0.3		0.2		0.3		0.2
	$	9.5	$	11.0	$	9.4	$	10.3	$	9.5	$	10.8	$	9.4	$	10.3

Liabilities
Debt	$	903.3	$	930.6	$	903.4	$	934.5	$	903.2	$	938.9	$	903.4	$	934.5

(a) DPL stock held in the DP&L Master Trust was cashed out at the $30/share merger consideration price. Approximately $26.9 million in gross proceeds was received and a gain of $14.6 million was recognized in earnings.

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 asbecause 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 2013 to 2061.

Master Trust Assets

DP&L established a Master Trust to hold assets that could be used 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 which are valued using the net asset value per unit. These investments are recorded at fair value within Other assets on the balance sheets and classified as available for sale. Any unrealized gains or losses are recorded in AOCI until the securities are sold.

DP&L had ~~$1.5~~$1.4 million ($~~1.0~~0.9 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at ~~March 31,~~June 30, 2012 and $1.0 million ($0.7 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2011.

Due to the liquidation of the DPL common stock held in the Master Trust, there is sufficient cash to cover the next twelve months of benefits payable to employees covered under the benefit plans. Therefore, no unrealized gains or losses are expected to be transferred to earnings since we will not need to sell any investments in the next twelve months.

Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of ~~March 31,~~June 30, 2012. These assets are part of the Master Trust. 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. At ~~March 31,~~June 30, 2012, DP&L did not have any investments for sale at a price different from the NAV per unit.

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Fair Value Estimated Using Net Asset Value per Unit

$ in millions	Fair Value at March 31, 2012		Fair Value at December 31, 2011		Unfunded Commitments		Redemption Frequency	Fair Value at June 30, 2012		Fair Value at December 31, 2011		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	0.2	$	—	Immediate	$	0.2	$	0.2	$	—	Immediate

Equity Securities (b)	5.0		4.4		—		Immediate	4.9		4.4		—		Immediate

Debt Securities (c)	5.5		5.5		—		Immediate	5.5		5.5		—		Immediate

Multi-Strategy Fund (d)	0.3		0.2		—		Immediate	0.2		0.2		—		Immediate

Total	$	11.0	$	10.3	$	—		$	10.8	$	10.3	$	—

(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.

Fair Value Hierarchy

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

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

$ in millions

Fair Value at
March 31,
2012*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Fair Value on
Balance Sheet at
March 31, 2012

Assets

Master Trust Assets

Money Market Funds

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Equity Securities (a)

5.0

—

5.0

—

—

5.0

Debt Securities

5.5

—

5.5

—

—

5.5

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

Total Master Trust Assets

11.0

—

11.0

—

—

11.0

Derivative Assets

FTRs

0.1

—

0.1

—

—

0.1

Heating Oil Futures

1.6

1.6

—

—

(1.6
)
—

Forward Power Contracts

4.7

—

4.7

—

(0.7
)
4.0

Total Derivative Assets

6.4

1.6

4.8

—

(2.3
)
4.1

Total Assets

$
17.4

$
1.6

$
15.8

$
—

$
(2.3
)
$
15.1

Liabilities

Derivative Liabilities

Forward Power Contracts

$
(9.6
)
$
—

$
(9.6
)
$
—

$
4.1

$
(5.5
)
Forward NYMEX Coal Contracts

(22.3
)
—

(22.3
)
—

16.0

(6.3
)
Total Derivative Liabilities

(31.9
)
—

(31.9
)
—

20.1

(11.8
)

Long-term Debt

(930.6
)
—

(911.4
)
(19.2
)
—

(930.6
)

Total Liabilities

$
(962.5
)
$
—

$
(943.3
)
$
(19.2
)
$
20.1

$
(942.4
)

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	Assets and Liabilities Measured at Fair Value on a Recurring Basis
				Level 1		Level 2			Level 3
$ in millions	Fair Value at June 30, 2012*			Based on Quoted Prices in Active Markets		Other Observable Inputs			Unobservable Inputs			Collateral and Counterparty Netting			Fair Value on Balance Sheet at June 30, 2012
Assets
Master Trust Assets
Money Market Funds	$	0.2		$	—	$	0.2		$	—		$	—		$	0.2
Equity Securities (a)	4.9			—		4.9			—			—			4.9
Debt Securities	5.5			—		5.5			—			—			5.5
Multi-Strategy Fund	0.2			—		0.2			—			—			0.2
Total Master Trust Assets	10.8			—		10.8			—			—			10.8

Derivative Assets
Heating Oil Futures	0.3			0.3		—			—			(0.3		)	—
Forward Power Contracts	7.8			—		7.8			—			(3.4		)	4.4
Total Derivative Assets	8.1			0.3		7.8			—			(3.7		)	4.4

Total Assets	$	18.9		$	0.3	$	18.6		$	—		$	(3.7	)	$	15.2

Liabilities
Derivative Liabilities
FTRs	$	(0.1	)	$	—	$	—		$	(0.1	)	$	—		$	(0.1	)
Forward Power Contracts	(12.0		)	—		(11.9		)	—			7.2			(4.8		)
Forward NYMEX Coal Contracts	(16.5		)	—		(16.5		)	—			11.4			(5.1		)
Total Derivative Liabilities	(28.6		)	—		(28.4		)	(0.1		)	18.6			(10.0		)

Long-term Debt	(938.9		)	—		(919.7		)	(19.2		)	—			(938.9		)

Total Liabilities	$	(967.5	)	$	—	$	(948.1	)	$	(19.3	)	$	18.6		$	(948.9	)

*Includes credit valuation adjustments for counterparty risk and our own credit risk.

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,
2011*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Balance Sheet at
December 31,
2011

Assets

Master Trust Assets

��
Money Market Funds

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Equity Securities (a)

4.4

—

4.4

—

—

4.4

Debt Securities

5.5

—

5.5

—

—

5.5

Multi-Strategy Fund

0.2

—

0.2

—

—

0.2

Total Master Trust Assets

10.3

—

10.3

—

—

10.3

Derivative Assets

FTRs

0.1

—

0.1

—

—

0.1

Heating Oil Futures

1.8

1.8

—

—

(1.8
)
—

Forward Power Contracts

4.1

—

4.1

—

(1.0
)
3.1

Total Derivative Assets

6.0

1.8

4.2

—

(2.8
)
3.2

Total Assets

$
16.3

$
1.8

$
14.5

$
—

$
(2.8
)
$
13.5

Liabilities

Derivative Liabilities

Forward Power Contracts

$
(5.0
)
$
—

$
(5.0
)
$
—

$
1.7

$
(3.3
)
Forward NYMEX Coal Contracts

(14.5
)
—

(14.5
)
—

10.8

(3.7
)
Total Derivative Liabilities

(19.5
)
—

(19.5
)
—

12.5

(7.0
)

Total Liabilities

$
(19.5
)
$
—

$
(19.5
)
$
—

$
12.5

$
(7.0
)

(a) DPL stock in the Master Trust was cashed out at the $30/share merger consideration price.

	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, 2011*			Based on Quoted Prices in Active Markets		Other Observable Inputs			Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2011
Assets
Master Trust Assets
Money Market Funds	$	0.2		$	—	$	0.2		$	—	$	—		$	0.2
Equity Securities (a)	4.4			—		4.4			—		—			4.4
Debt Securities	5.5			—		5.5			—		—			5.5
Multi-Strategy Fund	0.2			—		0.2			—		—			0.2
Total Master Trust Assets	10.3			—		10.3			—		—			10.3

Derivative Assets
FTRs	0.1			—		0.1			—		—			0.1
Heating Oil Futures	1.8			1.8		—			—		(1.8		)	—
Forward Power Contracts	4.1			—		4.1			—		(1.0		)	3.1
Total Derivative Assets	6.0			1.8		4.2			—		(2.8		)	3.2

Total Assets	$	16.3		$	1.8	$	14.5		$	—	$	(2.8	)	$	13.5

Liabilities
Derivative Liabilities
Forward Power Contracts	$	(5.0	)	$	—	$	(5.0	)	$	—	$	1.7		$	(3.3	)
Forward NYMEX Coal Contracts	(14.5		)	—		(14.5		)	—		10.8			(3.7		)
Total Derivative Liabilities	(19.5		)	—		(19.5		)	—		12.5			(7.0		)

Total Liabilities	$	(19.5	)	$	—	$	(19.5	)	$	—	$	12.5		$	(7.0	)

*Includes credit valuation adjustments for counterparty risk and our own credit risk.

(a) DPL stock in the Master Trust was cashed out at the $30/share merger consideration price.

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We use the market approach to value our financial instruments. Level 1 inputs are used for derivative contracts such as heating oil futures. The fair value is determined by reference to quoted market prices and other relevant information generated by market transactions. Level 2 inputs are used to value derivatives such as ~~financial transmission rights (where the quoted prices are from a relatively inactive market),~~ forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). 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.~~unit; and interest rate hedges, which use observable inputs to populate a pricing model. Financial transmission rights are considered a Level 3 input beginning April 1, 2012 because the monthly auctions are considered inactive.

Our Level 3 inputs are immaterial to our derivative balances as a whole and as such no further disclosures are presented.

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

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. Additions to ~~AROS~~AROs were not material during the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011.

10. Derivative Instruments and Hedging Activities

In the normal course of business, DP&L enters 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 asset and liability derivative positions with the same counterparty are netted on the balance sheets if we have a Master Netting Agreement with the counterparty. We also net any collateral posted or received against the corresponding derivative asset or liability position. 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.

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At ~~March 31,~~June 30, 2012, DP&L had the following outstanding derivative instruments:

	Accounting		Purchases	Sales		Net Purchases/ (Sales)	Accounting		Purchases	Sales		Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs	Mark to Market	MWh	2.8	—		2.8	Mark to Market	MWh	15.2	—		15.2
Heating Oil Futures	Mark to Market	Gallons	1,680.0	—		1,680.0	Mark to Market	Gallons	630.0	—		630.0
Forward Power Contracts	Cash Flow Hedge	MWh	881.0	(107.2	)	773.8	Cash Flow Hedge	MWh	876.0	(1,595.2	)	(719.2	)
Forward Power Contracts	Mark to Market	MWh	618.7	(618.7	)	—	Mark to Market	MWh	1,530.2	(2,566.6	)	(1,036.4	)
NYMEX-quality Coal Contracts*	Mark to Market	Tons	1,410.5	—		1,410.5	Mark to Market	Tons	860.3	—		860.3

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

~~Table of Contents~~

At December 31, 2011, DP&L had the following outstanding derivative instruments:

	Accounting		Purchases	Sales		Net Purchases/ (Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs	Mark to Market	MWh	7.1	(0.7	)	6.4
Heating Oil Futures	Mark to Market	Gallons	2,772.0	—		2,772.0
Forward Power Contracts	Cash Flow Hedge	MWh	886.2	(341.6	)	544.6
Forward Power Contracts	Mark to Market	MWh	525.1	(525.1	)	—
NYMEX-quality Coal Contracts*	Mark to Market	Tons	2,015.0	—		2,015.0

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

Cash Flow Hedges

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The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow ~~hedges:~~hedges for the three months ended June 30, 2012 and 2011:

	March 31,						March 31,
	2012						2011						June 30, 2012						June 30, 2011
				Interest						Interest						Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(0.8	)	$	9.8		$	(1.8	)	$	12.2		$	(3.4	)	$	9.2		$	(1.6	)	$	11.6

Net gains / (losses) associated with current period hedging transactions	(1.5		)	—			0.5			—			(0.1		)	—			(0.5		)	—

Net (gains) / losses reclassified to earnings
Interest Expense	—			(0.6		)	—			(0.6		)	—			(0.6		)	—			(0.6		)
Revenues	(1.2		)	—			(0.1		)	—			—			—			0.3			—
Purchased Power	0.1			—			(0.2		)	—			0.1			—			0.3			—
Ending accumulated derivative gain / (loss) in AOCI	$	(3.4	)	$	9.2		$	(1.6	)	$	11.6		$	(3.4	)	$	8.6		$	(1.5	)	$	11.0

Net gains / (losses) associated with the ineffective portion of the hedging transaction:
Interest expense	$	—		$	—		$	—		$	—
Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest Expense													$	—		$	—		$	—		$	—
Revenues	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Purchased Power													$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(0.5	)	$	(2.4	)							$	(0.7	)	$	(1.6	)	—			—

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	33			—									30			—			—			—

*The*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 six months ended June 30, 2012 and 2011:

	June 30, 2012						June 30, 2011
				Interest						Interest
$ in millions (net of tax)	Power			Rate Hedge			Power			Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI	$	(0.7	)	$	9.8		$	(1.8	)	$	12.2

Net gains / (losses) associated with current period hedging transactions	(1.6		)	—			(0.9		)	—

Net (gains) / losses reclassified to earnings
Interest Expense	—			(1.2		)	—			(1.2		)
Revenues	0.1			—			0.5			—
Purchased Power	(1.2		)	—			0.7			—
Ending accumulated derivative gain / (loss) in AOCI	$	(3.4	)	$	8.6		$	(1.5	)	$	11.0

Net gains / (losses) associated with the ineffective portion of the hedging transaction
Interest Expense	$	—		$	—		$	—		$	—
Revenues	$	—		$	—		$	—		$	—
Purchased Power	$	—		$	—		$	—		$	—

Portion expected to be reclassified to earnings in the next twelve months*	$	(0.7	)	$	(1.6	)	—			—

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	30			—			—			—

*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 tables show the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments at ~~March 31,~~June 30, 2012 and December 31, 2011.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at ~~March 31,~~June 30, 2012

								Fair Value on										Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet			Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	1.0		$	(0.6	)	Other prepayments and current assets	$	0.4		$	1.8		$	(1.5	)	Other prepayments and current assets	$	0.3
Forward Power Contracts in a Liability Position	(1.5		)	1.1			Other current liabilities	(0.4		)	(2.9		)	2.4			Other current liabilities	(0.5		)

Total short-term cash flow hedges	(0.5		)	0.5				—
Total Short-term Cash Flow Hedges											(1.1		)	0.9				(0.2		)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position											0.5			(0.5		)	Other deferred assets	—
Forward Power Contracts in a Liability Position	(4.7		)	3.0			Other deferred credits	(1.7		)	(4.6		)	3.1			Other deferred credits	(1.5		)

Total long-term cash flow hedges	(4.7		)	3.0				(1.7		)
Total Long-term Cash Flow Hedges											(4.1		)	2.6				(1.5		)

Total cash flow hedges	$	(5.2	)	$	3.5			$	(1.7	)
Total Cash Flow Hedges											$	(5.2	)	$	3.5			$	(1.7	)

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at December 31, 2011

								Fair Value on										Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet			Fair Value (1)			Netting (2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions

Forward Power Contracts in an Asset Position	$	1.5		$	(0.9	)	Other deferred assets	$	0.6		$	1.5		$	(0.9	)	Other prepayments and current assets	$	0.6
Forward Power Contracts in a Liability Position	(0.2		)	—			Other current liabilities	(0.2		)	(0.2		)	—			Other current liabilities	(0.2		)

Total short-term cash flow hedges	1.3			(0.9		)		0.4
Total Short-term Cash Flow Hedges											1.3			(0.9		)		0.4

Long-term Derivative Positions

Forward Power Contracts in an Asset Position	0.1			(0.1		)	Other deferred assets	—			0.1			(0.1		)	Other deferred assets	—
Forward Power Contracts in a Liability Position	(2.6		)	1.7			Other deferred credits	(0.9		)	(2.6		)	1.7			Other deferred credits	(0.9		)

Total long-term cash flow hedges	(2.5		)	1.6				(0.9		)
Total Long-term Cash Flow Hedges											(2.5		)	1.6				(0.9		)

Total cash flow hedges	$	(1.2	)	$	0.7			$	(0.5	)
Total Cash Flow Hedges											$	(1.2	)	$	0.7			$	(0.5	)

(1) Includes credit valuation adjustment.

(2) 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 815. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the statements of results of operations in the period in which the change occurred. This is commonly referred to as “MTM accounting.” Contracts we enter into as part of our risk management program may be settled financially, by physical delivery or net settled with the counterparty. We mark to market FTRs, heating oil futures, forward NYMEX-quality coal contracts and certain forward power contracts.

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

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Regulatory Assets and Liabilities

The following table shows the amount and classification within the statements of results of operations or balance sheets of the gains and losses on DP&L’s derivatives not designated as hedging instruments for the three and six months ended ~~March 31,~~June 30, 2012 and 2011.

For the Three Months Ended ~~March 31,~~June 30, 2012

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total			NYMEX Coal			Heating Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(7.8	)	$	(0.1	)	$	(0.1	)	$	—		$	(8.0	)	$	5.7		$	(1.3	)	$	(0.2	)	$	0.9	$	5.1
Realized gain / (loss)	(5.0		)	0.9			(0.2		)	—			(4.3		)	(9.5		)	0.5			0.7			—		(8.3		)
Total	$	(12.8	)	$	0.8		$	(0.3	)	$	—		$	(12.3	)	$	(3.8	)	$	(0.8	)	$	0.5		$	0.9	$	(3.2	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(3.5	)	$	—		$	—		$	—		$	(3.5	)	$	2.3		$	—		$	—		$	—	$	2.3
Regulatory (asset) / liability	(1.1		)	0.1			—			—			(1.0		)	0.8			(0.6		)	—			—		0.2

Recorded in Income Statement: gain / (loss)
Purchased power	—			—			(0.3		)	(1.6		)	(1.9		)	—			—			0.5			0.9		1.4
Revenue	—			—			—			1.6			1.6			—			—			—			—		—
Fuel	(8.2		)	0.6			—			—			(7.6		)	(6.9		)	(0.3		)	—			—		(7.2		)
O&M	—			0.1			—			—			0.1			—			0.1			—			—		0.1
Total	$	(12.8	)	$	0.8		$	(0.3	)	$	—		$	(12.3	)	$	(3.8	)	$	(0.8	)	$	0.5		$	0.9	$	(3.2	)

For the Three Months Ended ~~March 31,~~June 30, 2011

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total			NYMEX Coal			Heating Oil			FTRs		Power			Total
Change in unrealized gain / (loss)	$	(3.5	)	$	3.0	$	(0.1	)	$	(0.1	)	$	(0.7	)	$	(10.2	)	$	(1.4	)	$	0.1	$	0.3		$	(11.2	)
Realized gain / (loss)	2.4			0.4		(0.8		)	(0.3		)	1.7			1.4			0.6			0.2		(0.3		)	1.9
Total	$	(1.1	)	$	3.4	$	(0.9	)	$	(0.4	)	$	1.0		$	(8.8	)	$	(0.8	)	$	0.3	$	—		$	(9.3	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(2.4	)	$	—	$	—		$	—		$	(2.4	)	$	(5.0	)	$	—		$	—	$	—		$	(5.0	)
Regulatory (asset) / liability	0.3			1.6		—			—			1.9			(2.3		)	(0.9		)	—		—			(3.2		)

Recorded in Income Statement: gain / (loss)
Purchased power	—			—		(0.9		)	(0.4		)	(1.3		)	—			—			0.3		—			0.3
Revenue	—			—		—			—			—			—			—			—		—			—
Fuel	1.0			1.7		—			—			2.7			(1.5		)	—			—		—			(1.5		)
O&M	—			0.1		—			—			0.1			—			0.1			—		—			0.1
Total	$	(1.1	)	$	3.4	$	(0.9	)	$	(0.4	)	$	1.0		$	(8.8	)	$	(0.8	)	$	0.3	$	—		$	(9.3	)

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For the Six Months Ended June 30, 2012

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(2.0	)	$	(1.5	)	$	(0.2	)	$	0.9		$	(2.8	)
Realized gain / (loss)	(14.5		)	1.4			0.5			0.1			(12.5		)
Total	$	(16.5	)	$	(0.1	)	$	0.3		$	1.0		$	(15.3	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(1.2	)	$	—		$	—		$	—		$	(1.2	)
Regulatory (asset) / liability	(0.3		)	(0.6		)	—			—			(0.9		)

Recorded in Income Statement: gain / (loss)
Purchased power	—			—			0.3			(0.8		)	(0.5		)
Revenue	—			—			—			1.8			1.8
Fuel	(15.0		)	0.3			—			—			(14.7		)
O&M	—			0.2			—			—			0.2
Total	$	(16.5	)	$	(0.1	)	$	0.3		$	1.0		$	(15.3	)

For the Six Months Ended June 30, 2011

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(13.8	)	$	1.6	$	(0.1	)	$	0.1		$	(12.2	)
Realized gain / (loss)	3.8			0.9		(0.7		)	(0.5		)	3.5
Total	$	(10.0	)	$	2.5	$	(0.8	)	$	(0.4	)	$	(8.7	)
Recorded on Balance Sheet:
Partners’ share of gain / (loss)	$	(7.4	)	$	—	$	—		$	—		$	(7.4	)
Regulatory (asset) / liability	(2.0		)	0.6		—			—			(1.4		)

Recorded in Income Statement: gain / (loss)
Purchased power	—			—		(0.8		)	(0.4		)	(1.2		)
Revenue	—			—		—			—			—
Fuel	(0.6		)	1.8		—			—			1.2
O&M	—			0.1		—			—			0.1
Total	$	(10.0	)	$	2.5	$	(0.8	)	$	(0.4	)	$	(8.7	)

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The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments not designated as hedging instruments at ~~March 31,~~June 30, 2012.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at ~~March 31,~~June 30, 2012

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

2.3

—

Other prepayments and current assets

2.3

Forward Power Contracts in a Liability position

(2.2
)
—

Other current liabilities

(2.2
)
NYMEX-Quality Coal Forwards in a Liability position

(16.7
)
10.3

Other current liabilities

(6.4
)
Heating Oil Futures in an Asset position

1.6

(1.6
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

(14.9
)
8.7

(6.2
)

Long-term Derivative Positions

Forward Power Contracts in an Asset position

1.4

—

Other deferred assets

1.4

Forward Power Contracts in a Liability position

(1.3
)
—

Other deferred credits

(1.3
)
NYMEX-Quality Coal Forwards in a Liability position

(5.6
)
5.6

Other deferred credits

—

Total long-term derivative MTM positions

(5.5
)
5.6

0.1

Total MTM Position

$
(20.4
)
$
14.3

$
(6.1
)

$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in a Liability Position	$	(0.1	)	$	—		Other current liabilities	$	(0.1	)
Forward Power Contracts in an Asset Position	3.2			(1.3		)	Other prepayments and current assets	1.9
Forward Power Contracts in a Liability Position	(2.9		)	1.2			Other current liabilities	(1.7		)
NYMEX-Quality Coal Forwards in a Liability Position	(12.9		)	7.8			Other current liabilities	(5.1		)
Heating Oil Futures in an Asset Position	0.3			(0.3		)	Other prepayments and current assets	—

Total Short-term Derivative MTM Positions	(12.4		)	7.4				(5.0		)

Long-term Derivative Positions
Forward Power Contracts in an Asset Position	2.3			(0.1		)	Other deferred assets	2.2
Forward Power Contracts in a Liability Position	(1.6		)	0.5			Other deferred credits	(1.1		)
NYMEX-Quality Coal Forwards in a Liability Position	(3.6		)	3.6			Other deferred credits	—

Total Long-term Derivative MTM Positions	(2.9		)	4.0				1.1

Total MTM Position	$	(15.3	)	$	11.4			$	(3.9	)

(1)Includes credit valuation adjustment.

(2)Includes counterparty and collateral netting.

The following table shows the fair value and balance sheet classification of DP&L’s derivative instruments not designated as hedging instruments at December 31, 2011.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at December 31, 2011

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

1.0

—

Other prepayments and current assets

1.0

Forward Power Contracts in a Liability position

(0.9
)
—

Other current liabilities

(0.9
)
NYMEX-Quality Coal Forwards in a Liability position

(8.3
)
4.6

Other current liabilities

(3.7
)
Heating Oil Futures in an Asset position

1.8

(1.8
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

(6.3
)
2.8

(3.5
)

Long-term Derivative Positions

Forward Power Contracts in an Asset position

1.5

—

Other deferred assets

1.5

Forward Power Contracts in a Liability position

(1.3
)
—

Other deferred credits

(1.3
)
NYMEX-Quality Coal Forwards in a Liability position

(6.2
)
6.2

Other deferred credits

—

Total long-term derivative MTM positions

(6.0
)
6.2

0.2

Total MTM Position

$
(12.3
)
$
9.0

$
(3.3
)

$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Fair Value on Balance Sheet
Short-term Derivative Positions
FTRs in an Asset Position	$	0.1		$	—		Other prepayments and current assets	$	0.1
Forward Power Contracts in an Asset Position	1.0			—			Other prepayments and current assets	1.0
Forward Power Contracts in a Liability Position	(0.9		)	—			Other current liabilities	(0.9		)
NYMEX-Quality Coal Forwards in a Liability Position	(8.3		)	4.6			Other current liabilities	(3.7		)
Heating Oil Futures in an Asset Position	1.8			(1.8		)	Other prepayments and current assets	—

Total Short-term Derivative MTM Positions	(6.3		)	2.8				(3.5		)

Long-term Derivative Positions
Forward Power Contracts in an Asset Position	1.5			—			Other deferred assets	1.5
Forward Power Contracts in a Liability Position	(1.3		)	—			Other deferred credits	(1.3		)
NYMEX-Quality Coal Forwards in a Liability Position	(6.2		)	6.2			Other deferred credits	—

Total Long-term Derivative MTM Positions	(6.0		)	6.2				0.2

Total MTM Position	$	(12.3	)	$	9.0			$	(3.3	)

(1)Includes credit valuation adjustment.

(2)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 changes in our credit ratings in April 2011 have not triggered the provisions discussed above; however, there is a possibility of further downgrades related to the Merger with AES that could trigger such provisions.

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The aggregate fair value of DP&L’s commodity derivative instruments that are in a MTM loss position at ~~March 31,~~June 30, 2012 is ~~$32.0~~$28.5 million. This amount is offset by ~~$19.4~~$15.0 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of ~~$0.9~~$3.7 million. If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining ~~$11.7~~$9.8 million.

11. Common Shareholder’s Equity

DP&L has 250,000,000 authorized common shares, of which 41,172,173 are outstanding at ~~March 31,~~June 30, 2012. All common shares are held by DP&L’s parent, DPL.

As part of the PUCO’s approval of the Merger, DP&L agreed to maintain a capital structure that includes an equity ratio of at least 50 percent and not to have a negative retained earnings balance.

12. Contractual Obligations, Commercial Commitments and Contingencies

DP&L — Equity Ownership Interest

Commercial Commitments and Contractual Obligations

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 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 Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of ~~March 31,~~June 30, 2012, cannot be reasonably determined.

Environmental Matters

DP&L’s facilities and operations are subject to a wide range of federal, state and local environmental regulations and laws. 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 in accordance with the provisions of GAAP. We have estimated liabilities of approximately ~~$3.2~~$4.3 million for environmental matters. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial condition or cash flows.

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On July 15, 2011, Duke Energy, co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO. The plan indicated that Duke Energy plans to cease production at the Beckjord station, including our jointly owned Unit 6, in December 2014. This was followed by a notification by Duke Energy to PJM, dated February 1, 2012, of a planned April 1, 2015 deactivation of this unit. We are depreciating Unit 6 through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.

Environmental Matters Related to Air Quality

Clean Air Act Compliance

Cross-State Air Pollution Rule

In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). ~~CAIR~~CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. We do not believe the rule will have a material effect on our operations in 2012. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, USEPA is expected to institute a ~~federal implementation plan (FIP)~~FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. DP&L is unable to estimate the effect of the new requirements; however, CSAPR could have a material adverse effect on our operations.

Mercury and Other Hazardous Air Pollutants

On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating units. The standards include new requirements for emissions of mercury and a number of other heavy metals. The ~~EPA~~USEPA Administrator signed the final rule, now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the rule was published in the Federal Register on February 16, 2012. Affected electric generating units (EGUs) will have to come into compliance with the new requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is evaluating the costs that may be incurred to comply with the new requirement; however, MATS could have a material adverse effect on our operations and result in material compliance costs.

Table of Contents

~~Table of Contents~~

Carbon ~~Emissions~~ and Other Greenhouse ~~Gases~~Gas Emissions

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 CO2and other GHGs “regulated air pollutants” under the CAA.

On April 13, 2012, the USEPA published its GHG standards for new electric generating units (EGUs) under CAA subsection 111(b), which would require certain new EGUs to meet a standard of 1,000 pounds of CO2per megawatt-hour, a standard based on the emissions limitations achievable through natural gas combined cycle generation. The proposal anticipates that affected coal-fired units would need to install carbon capture and storage or other expensive CO2 emission control technology to meet the standard. Furthermore, the USEPA may propose and promulgate guidelines for states to address GHG standards for existing EGUs under CAA subsection 111(d). These latter rules may focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.

Table of Contents

Litigation, Notices of Violation and Other Matters Related to Air Quality

Litigation Involving Co-Owned Plants

~~Table of Contents~~

Notices of Violation Involving Co-Owned Plants

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 Hutchings station. The NOVs’ alleged deficiencies related to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. On November 18, 2009, the USEPA issued an NOV to DP&L for alleged NSR violations of the CAA at the Hutchings station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the projects described in the NOV were modifications subject to NSR. DP&L is engaged in discussions with the USEPA and the U.S. Department of Justice to resolve these matters, but DP&L is unable to determine the timing, costs or method by which these issues may be resolved. The Ohio EPA is kept apprised of these discussions.

Table of Contents

Environmental Matters Related to Water Quality, Waste Disposal and Ash Ponds

Clean Water Act — Regulation of Water Intake

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. 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 released new proposed regulations on March 28, 2011, published in the Federal Register on April 20, 2011. It is anticipated that the final rules will be promulgated in mid-2013. We submitted comments to the proposed regulations on August 17, 2011. ~~The final rules are expected to be in place by mid-2012.~~ We do not yet know the impact these proposed rules will have on our operations.

~~Table of Contents~~

Clean Water Act — Regulation of Water Discharge

In December 2006, we submitted an application for the renewal of the Stuart station NPDES 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 a thermal discharge study completed during the previous permit term. Subsequently, DP&L and the Ohio EPA reached an agreement 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. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. The Ohio EPA issued another draft permit in December 2011 and a public hearing was held on February 2, 2012. The draft permit would require DP&L, over the 54 months following issuance of a final permit, to take undefined actions to lower the temperature of its discharged water to a level unachievable by the station under its current design or alternatively make other significant modifications to the cooling water system. DP&L submitted comments to the draft permit and is considering legal options. On May 17, 2012 we met with Ohio EPA to discuss this matter. It is not known what additional actions the agency might take. Depending on the outcome of the process, the effects could be material on DP&L’s operation.

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. USEPA has indicated that they may take additional enforcement action. DP&L ~~will install~~has installed sedimentation ponds as part of the runoff control measures to address this ~~issue. We expect~~issue and is working with the ~~impact of~~various agencies to resolve their concerns. This may affect the landfill’s construction schedule and delay its operational date. DP&L has accrued an immaterial amount for anticipated penalties related to this ~~NOV to be immaterial.~~issue.

Table of Contents

Regulation of Waste Disposal

On February 10, 2011, the Court dismissed claims against DP&L that related to allegations that chemicals used by DP&L at its service center contributed to the landfill site’s contamination. The Court, however, did not dismiss claims alleging financial responsibility for remediation costs based on hazardous substances from DP&L that were allegedly directly delivered by truck to the landfill. Discovery, including depositions of past and present DP&L employees, is ongoing. In June 2012, DP&L filed a motion for summary judgment on grounds that the remaining claims for contribution are barred by a statute of limitations. The plaintiffs oppose that motion and, additionally, have filed a motion seeking Court leave to amend their complaint to add more than 20 new defendants to the case and to recharacterize and re-allege claims against DP&L that the Court dismissed in its February 10, 2011 order. While DP&L is unable 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.

~~Table of Contents~~

Regulation of Ash Ponds

Table of Contents

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 byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. The USEPA anticipates issuing a final rule on this topic in late 2012. DP&L is unable 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 effect on DP&L’s operations.

Notice of Violation involving Co-Owned Plants

On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleged non-compliance by DP&L with certain provisions of the RCRA, the Clean Water Act ~~National Pollutant Discharge Elimination System~~NPDES permit program and the station’s storm water pollution prevention plan. The notice requested that DP&L respond with the actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its review of the findings, although there can be no assurance, we believe that the notice will not result in any material effect on DP&L’s results of operations, financial condition or cash flow.

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 commonly 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 in which DP&L is participating as an unsecured creditor. DP&L is unable to determine the ultimate resolution of this matter. DP&L has not recorded any assets relating to possible recovery of costs in this lawsuit.

~~Table of Contents~~

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. Prior to this final order being issued, DP&L entered into a significant number of bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. On July 5, 2012, a Stipulation was executed and filed with the FERC that resolves SECA claims against BP Energy Company (“BP”) and DP&L, AEP (and its subsidiaries) and Exelon Corporation (and its subsidiaries.). If the Stipulation is approved, DP&L would receive approximately $14.6 million from BP. DP&L will record the settlement of the BP claims once FERC approval is received. With respect to ~~unsettled~~these claims, DP&L management has deferred $18.1 million and $17.8 million as of ~~December 31, 2011~~June 30, 2012 and December 31, ~~2010,~~2011, respectively, as Other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The ~~amounts~~amount at ~~March 31,~~June 30, 2012 and December 31, 2011 includes estimated earnings and interest of ~~$5.5~~$5.4 million and $5.2 million, respectively.

On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed. These orders are now final, but appealed and subject to ~~possible~~ appellate court review. These orders do not affect ~~prior~~ settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L. For other parties that ~~had~~have not yet previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.

~~On April 28, 2011, a lawsuit was filed in the Court~~86

Table of ~~Common Pleas of Montgomery County, Ohio, naming~~ ~~DPL~~ ~~and each member of~~ ~~DPL’s~~ ~~board of directors as defendants. The lawsuit filed by Payne Family Trust was a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders. On March 29, 2012, the Court entered an order dismissing this lawsuit with prejudice pursuant to a stipulation filed by the parties. Plaintiff had alleged, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the Merger of~~ ~~DPL~~ ~~and AES.~~Contents

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

The following discussion contains forward-looking statements and should be read in conjunction with the accompanying Condensed Consolidated Financial Statements and related footnotes of DPL and the Condensed Financial Statements and related footnotes of DP&L included in Part I — Financial Information, the risk factors in Item 1A to Part I of our Form 10-K for the fiscal year ending December 31, 2011 and in Item 1A to Part II of this Quarterly Report on Form 10-Q, and our “Forward-Looking Statements” section on page 8 of this Form 10-Q. For a list of certain abbreviations or acronyms in this discussion, see Glossary at the beginning of this Form 10-Q.

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DESCRIPTION OF BUSINESS

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER subsidiary. Refer to Note 14 of Notes to DPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments.

On November 28, 2011, DPL was acquired by AES in the Merger and DPL became a wholly owned subsidiary of AES. See Note 2 of Notes to DPL’s Condensed Consolidated Financial Statements.

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

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BUSINESS COMBINATION

Acquisition by The AES Corporation

On November 28, 2011, DPL merged with Dolphin Sub, Inc., a wholly owned subsidiary of The AES Corporation, a Delaware corporation (“AES”) pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) whereby AES acquired DPL for $30.00 per share in a cash transaction valued at approximately $3.5 billion. At closing, DPL became a wholly owned subsidiary of AES.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1,250.0 million in long-term Senior Notes on October 3, 2011, to partially finance the Merger (see Note 2 of Notes to DPL’s Condensed Consolidated Financial Statements). Upon the consummation of the Merger, Dolphin Subsidiary II, Inc. was merged into DPL and these notes became long-term debt obligations of DPL. This debt has and will have a material effect on DPL’s cash requirements.

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As a result of the Merger, including the assumption of merger-related debt, DPL and DP&L were downgraded by all three major credit rating agencies. We do not anticipate that these reduced ratings will have a significant effect on our liquidity; however, we expect that our cost of capital will increase. See Note 6 of Notes to DPL’s Condensed Consolidated Financial Statements for more information.

DPL incurred merger transaction costs consisting primarily of banker’s fees, legal fees and change of control costs of approximately $53.6 million pre-tax during 2011 and an additional $1.0 million pre-tax during 2012. Other than these costs, interest on the additional debt and other items noted above, DPL and DP&L do not expect the Merger to have a significant effect on their financial position, results of operations or sources of liquidity during 2012.

The Merger also resulted in DPL recording ~~$2,489.3~~$2,559.1 million in goodwill due to the push down of purchase accounting in accordance with FASC 805. Utilities in Ohio continue to face downward pressure on operating margins due to the evolving regulatory environment, which is moving towards a market-based competitive pricing mechanism. At the same time, declining energy prices are also reducing operating margins across the utility industry. These competitive forces could adversely impact the future operating performance of DPL and may result in impairment of its goodwill.

Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present. In evaluating the potential impairment of goodwill, we make estimates and assumptions about revenue, operating cash flows, capital expenditures, growth rates and discount rates based on our budgets and long term forecasts, macroeconomic projections, and current market expectations of returns on similar assets. There are inherent uncertainties related to these factors and management’s judgment in applying these factors. Generally, the fair value of a reporting unit is determined using a discounted cash flow valuation model. We could be required to evaluate the potential impairment of goodwill outside of the required annual assessment process if we experience situations, including but not limited to: deterioration in general economic conditions, operating or regulatory environment; increased competitive environment; increase in fuel costs particularly when we are unable to pass along such costs to customers; negative or declining cash flows; loss of a key contract or customer particularly when we are unable to replace it on equally favorable terms; or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods.

DPL will perform its annual goodwill impairment evaluation in the fourth quarter of 2012.

Predecessor and Successor Financial Presentation

DPL’s financial statements and related financial and operating data include the periods before and after the Merger with AES on November 28, 2011, and are labeled as Predecessor and Successor, respectively. In accordance with GAAP, DPL applied push-down accounting to account for the merger. For accounting purposes only, push-down accounting created a new cost basis assigned to assets, liabilities and equity as of the Merger date. Such adjustments are subject to change as AES finalizes its purchase price allocation during the applicable measurement period.

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REGULATORY ENVIRONMENT

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.

· Carbon ~~Emissions~~ and Other Greenhouse ~~Gases~~Gas Emissions

There is an on-going concern nationally and internationally about global climate change and the contribution of emissions of GHGs, including most significantly CO2. This concern has led to regulation and 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 GHG emissions under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the CAA. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This endangerment finding became effective in January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision.

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As a result of this endangerment finding and other USEPA regulations, emissions of CO2 and other GHGs from certain electric generating units and other stationary sources are subject to regulation. Increased pressure for GHG emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on GHG 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 GHGemissions at generating stations we own and co-own is approximately 16 million tons annually. If we are required to implement control of CO2 and other GHGs at generation facilities, the cost to DPL and DP&L of such reductions could be material.

·Clean Water Act

In April 2012, DP&L received an NOV related to the construction of the Carter Hollow landfill at the J.M. Stuart station. The NOV indicated that construction activities caused sediment to flow into downstream creeks. In addition, the U.S. Army Corps of Engineers issued a Cease and Desist order followed by a notice suspending the previously issued Corps permit authorizing work associated with the landfill. USEPA has indicated that they may take additional enforcement action. DP&L ~~will install~~has installed sedimentation ponds as part of the runoff control measures to address this ~~issue. We expect~~issue and is working with the ~~impact of~~various agencies to resolve their concerns. This may affect the landfill’s construction schedule and delay its operational date. DP&L has accrued an immaterial amount for anticipated penalties related to this ~~NOV to be immaterial.~~issue.

· 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 increased percentage requirements each year thereafter. The annual targets for energy efficiency and peak demand reductions began in 2009 with annual increases. Energy efficiency programs are expected 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. The PUCO issued general rules for calculating the earnings and comparing them to a comparable group to determine whether there were significantly excessive earnings. Pursuant to the ESP Stipulation, DP&L becomes subject to the SEET in 2013 based on 2012 earnings results and the SEET may have a material effect on our results of operations, financial condition and cash flows.

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SB 221 also requires that all Ohio distribution utilities file either an ESP or MRO. Under the MRO, a periodic competitive bid process will set the retail generation price after the utility demonstrates that it can meet certain market criteria and bid requirements. Also, under this option, utilities that still own generation in the state are required to phase-in the MRO over a period of not less than five years. An ESP may allow for adjustments to the SSO for costs associated with environmental compliance; fuel and purchased power; construction of new or investment in specified generating facilities; and the provision of standby and default service, operating, maintenance, or other costs including taxes. As part of its ESP, a utility is permitted to file an infrastructure improvement plan that will specify the initiatives the utility will take to rebuild, upgrade,

or replace its electric distribution system, including cost recovery mechanisms. Both MRO and ESP options involve a “significantly excessive earnings test” based on the earnings of comparable companies with similar business and financial risks. On March 30, 2012, DP&Lfiled with the PUCO for approval of its next SSO to replace the existing ESP that expires on December 31, 2012. The initial filing indicated that the proposed MRO rates, if approved by the PUCO, would reduce DP&L’s revenues by about $30 million in the first year after they are applied, based on the level of SSO sales contained in the filing. The filing requested approval of athe five-year and five month MRO, which will be effective January 1, 2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing and no decision has been made. The outcome of the proceeding is uncertain and could have a material impact on our results.

· NOx and SO2 Emissions — CSAPR

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In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CATR was finalized as the Cross-State Air Pollution Rule (CSAPR) on July 6, 2011, but subsequent litigation has resulted in CSAPR’s implementation being delayed indefinitely. CSAPR creates four separate trading programs: two SO2 areas (Group 1 and Group 2); and two NOx reduction requirements (annual and ozone season). Group 1 states (16 states including Ohio) will have to meet a 2012 cap and additional reductions in 2014. Group 2 states (7 states) will only have to meet the 2012 cap. The Ohio EPA has a State Implementation Plan (SIP) that incorporates the CAIR program requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA is expected to institute a ~~Federal Implementation Plan (FIP)~~FIP in lieu of state SIPs and allow for the states to develop SIPs for approval as early as 2013. We do not believe the rule will have a material effect on our operations in 2012, but until the CSAPR becomes effective, DP&L is unable to estimate the impact of the new requirements in future years.

COMPETITION AND PJM PRICING

· RPM Capacity Auction Price

The PJM RPM capacity base residual auction for the ~~2014/2015~~2015/2016 period cleared at a per megawatt price of ~~$126/~~$136/day for our RTO area. The per megawatt prices for the periods 2014/2015, 2013/2014, 2012/2013, and 2011/2012 were $126/day, $28/day, $16/day, and $110/day, respectively, 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. The SSO retail costs and revenues are included in the RPM rider. Therefore 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 based on actual results attained in 2011, we estimate that a hypothetical increase or decrease of $10 in the capacity auction price would result in an annual impact to net income of approximately ~~$5.2~~$5.1 million and ~~$3.9~~$3.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

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· Ohio Competitive Considerations and Proceedings

Since January 2001, DP&L’s electric customers have been permitted to choose their retail electric generation supplier. DP&L continues to have the exclusive right to provide delivery service in its state certified territory and the obligation to supply retail generation service to customers that do not choose an alternative supplier. The PUCO maintains jurisdiction over DP&L’s delivery of electricity, SSO and other retail electric services.

Lower market prices for power have resulted in increased levels of competition to provide transmission and generation services. This in turn has led approximately ~~53%~~56% of DP&L’s retail volume to be switched to CRES providers. DPLER, an affiliated company and one of the registered CRES providers, has been marketing transmission and generation services to DP&L customers. The following table provides a summary of the number of electric customers and volumes provided by all CRES providers in our service territory during the three and six months ended ~~March 31,~~June 30, 2012 and 2011:

	Three months ended		Three months ended
	June 30, 2012		June 30, 2011
	Electric Customers	Sales (in Millions of kWh)	Electric Customers	Sales (in Millions of kWh)

Supplied by DPLER	50,157	1,540	12,033	1,419

Supplied by non-affiliated CRES providers	49,901	465	4,996	164

Total supplied in our service territory by DPLER and other CRES providers	100,058	2,005	17,029	1,583

Distribution sales by DP&L in our service territory (a)	512,675	3,375	513,107	3,268

~~Table of Contents~~(a) The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers.

Three months ended

Three months ended

March 31, 2012

March 31, 2011

Electric
Customers

Sales (in Millions
of kWh)

Electric
Customers

Sales (in Millions
of kWh)

Supplied by DPLER

Residential

26,336

110

32

—

Commercial

10,868

435

7,699

412

Industrial

630

723

553

695

Other

3,249

189

1,500

238

Supplied by DPLER

41,083

1,457

9,784

1,345

Supplied by non-affiliated CRES providers

Residential

24,958

81

291

1

Commercial

6,766

180

2,266

65

Industrial

371

123

137

46

Other

561

16

84

6

Supplied by non-affiliated CRES providers

32,656

400

2,778

118

Total supplied in our service territory by DPLER and other CRES providers

Residential

51,294

191

323

1

Commercial

17,634

615

9,965

477

Industrial

1,001

846

690

741

Other

3,810

205

1,584

244

Total supplied in our service territory by DPLER and other CRES providers

73,739

1,857

12,562

1,463

Distribution sales by DP&L in our service territory (a)

Residential

455,243

1,403

456,074

1,544

Commercial

50,169

879

50,124

891

Industrial

1,749

903

1,762

850

Other

6,795

339

6,728

345

Distribution sales by DP&L in our service territory (a)

513,956

3,524

514,688

3,630

	Six months ended		Six months ended
	June 30, 2012		June 30, 2011
	Electric Customers	Sales (in Millions of kWh)	Electric Customers	Sales (in Millions of kWh)

Supplied by DPLER	50,157	2,997	12,033	2,764

Supplied by non-affiliated CRES providers	49,901	866	4,996	282

Total supplied in our service territory by DPLER and other CRES providers	100,058	3,863	17,029	3,046

Distribution sales by DP&L in our service territory (a)	512,675	6,899	513,107	6,898

(a) The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers.

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The volumes supplied by DPLER represent approximately ~~41%~~46% and ~~37%~~43% of DP&L’s total distribution volumes during the three months ended ~~March 31,~~June 30, 2012 and 2011, respectively, and 43% and 40% during the six months ended June 30, 2012 and 2011, respectively. We cannot determine the extent to which customer switching to CRES providers will occur in the future and the effect this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.

As of ~~March 31,~~June 30, 2012, approximately ~~53%~~56% of DP&L’s load has switched to CRES providers with DPLER acquiring 78% of the switched load. For the ~~three~~six months ended ~~March 31,~~June 30, 2012, customer switching negatively affected DPL’s gross margin by approximately ~~$27.0~~$59.0 million compared to the 2011 effect of approximately ~~$9.0~~$20.0 million. For the ~~three~~six months ended ~~March 31,~~June 30, 2012, customer switching negatively affected DP&L’s gross margin by approximately ~~$53.0~~$110.0 million compared to the 2011 effect of approximately ~~$19.0~~$36.0 million.

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Several communities in DP&L’s service area have passed ordinances allowing the communities to become government aggregators for the purpose of offering alternative electric generation supplies to their citizens. To date, a number of organizations have filed with the PUCO to initiate aggregation programs. If a number of the larger organizations move forward with aggregation, it could have a material effect on our earnings.

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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, 2012, 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. 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 and purchased power recovery rider, our results of operations, financial condition or cash flows could be materially affected.

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RESULTS OF OPERATIONS — DPL

DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. 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								Three Months Ended						Six Months Ended
	March 31,								June 30,						June 30,
	2012			2011					2012			2011			2012			2011
$ in millions	Successor			Predecessor					Successor			Predecessor			Successor			Predecessor

Revenues:
Retail	$	349.3		$			369.5		$	324.2		$	336.5		$	673.5		$	705.9
Wholesale	22.4			32.4					12.3			28.7			34.7			61.1
RTO revenues	18.2			21.4					19.7			19.5			37.9			40.9
RTO capacity revenues	36.9			55.3					26.6			49.7			63.5			105.0
Other revenues	3.2			2.7					2.5			2.9			5.7			5.7
Mark-to-market gains / (losses)	4.0			(0.7				)
Mark-to-market (losses) / gains									(3.3		)	(4.0		)	0.7			(4.7		)
Total revenues	$	434.0		$			480.6		$	382.0		$	433.3		$	816.0		$	913.9

Cost of revenues:
Fuel costs	$	90.6		$			100.9		$	71.7		$	90.0		$	162.3		$	190.9
Losses / (gains) from sale of coal	3.4			(1.8				)	1.9			(1.2		)	5.3			(2.9		)
Mark-to-market losses	3.4			0.6
Mark-to-market (gains) / losses									(2.0		)	3.3			1.4			3.9
Net fuel	97.4			99.7					71.6			92.1			169.0			191.9

Purchased power	34.6			37.3					39.3			43.3			73.9			80.6
RTO charges	24.5			29.3					21.6			27.1			46.1			56.4
RTO capacity charges	33.7			55.5					22.7			47.0			56.4			102.5
Mark-to-market losses / (gains)	2.0			(1.3				)
Mark-to-market (gains) / losses									(3.3		)	(3.8		)	(1.3		)	(5.1		)
Net purchased power	94.8			120.8					80.3			113.6			175.1			234.4

Amortization of intangibles	27.8			—					28.6			—			56.4			—

Total cost of revenues	$	220.0		$			220.5		$	180.5		$	205.7		$	400.5		$	426.3

Gross margins (a)	$	214.0		$		260.1			$	201.5		$	227.6		$	415.5		$	487.6

Gross margin as a percentage of revenues	49		%	54				%	53		%	53		%	51		%	53		%

Operating income	$	59.2		$	100.9				$	46.7		$	65.8		$	105.9		$	166.6

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

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DPL — Revenues

Retail customers, especially residential and commercial customers, consume more electricity on warmer and colder days. Therefore, 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

Six Months Ended

March 31,

June 30,

2012

2011

2012

2011

2012

2011

Number of days

Successor

Predecessor

Successor

Predecessor

Successor

Predecessor

Heating degree days (a)

2,263

2,967

455

513

2,718

3,480

Cooling degree days (a)

—

400

319

430

319

(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; our plants’ and other utility 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.

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

	Three Months Ended					Three Months Ended			Six Months Ended
	March 31,					June 30,			June 30,
$ in millions	2012 vs. 2011					2012 vs. 2011			2012 vs. 2011

Retail
Rate	$			3.1		$	(1.5	)	$	1.5
Volume	(23.5				)	(10.4		)	(33.8		)
Other miscellaneous	0.7
Other retail						(0.4		)	(0.1		)
Total retail change	$		(19.7		)	$	(12.3	)	$	(32.4	)

Wholesale
Rate	$	4.0				$	(1.7	)	$	2.2
Volume	(14.0				)	(14.7		)	(28.6		)
Total wholesale change	$			(10.0	)	$	(16.4	)	$	(26.4	)

RTO capacity & other
RTO capacity and other RTO revenues	$	(21.6			)	$	(22.9	)	$	(44.5	)

Other
Unrealized MTM	$	4.7				$	0.7		$	5.4
Miscellaneous						(0.4		)	—
Total other revenue						$	0.3		$	5.4

Total revenues change	$	(46.6			)	$	(51.3	)	$	(97.9	)

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For the three months ended ~~March 31,~~June 30, 2012, Revenues decreased ~~$46.6~~$51.3 million to ~~$434.0~~$382.0 million from ~~$480.6~~$433.3 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale sales volume, a decrease in retail and wholesale average rates and a decrease in RTO capacity and other RTO revenues.

·Retail revenues decreased $12.3 million resulting primarily from a 3% decrease in retail sales volume compared to the prior year period largely as a result of customer switching due to increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions as well as a slight increase in average rates. Weather during the three months was slightly favorable with a 25% increase in the number of cooling degree days to 400 days from 319 days in 2011 slightly offset by an 11% decrease in the number of heating degree days to 455 days from 513 days in 2011. The above resulted in an unfavorable $10.4 million retail sales volume variance and an unfavorable $1.5 million retail price variance.

·Wholesale revenues decreased $16.4 million primarily as a result of a 51% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, as well as a 12% decrease in wholesale average prices. This resulted in an unfavorable $14.7 million wholesale sales volume variance and an unfavorable wholesale price variance of $1.7 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, decreased $22.9 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was the result of a $23.1 million decrease in revenues realized from the PJM capacity auction offset by a slight increase in transmission and congestion revenues.

For the six months ended June 30, 2012, Revenues decreased $97.9 million to $816.0 million from $913.9 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale sales volume and a decrease in RTO capacity and other RTO revenues, partially offset by an increase in retail and wholesale average rates.

· Retail revenues decreased ~~$19.7~~$32.4 million resulting primarily from a 6%5% decrease in retail sales volume compared to the prior year period largely due to unfavorable weather. The unfavorable weather conditions resulted in a ~~23%~~22% decrease in the number of heating degree days to ~~2,263~~2,718 days from ~~2,967~~3,480 days in 2011 offset slightly by a 35% increase in the number of cooling degree days to 430 days from 319 days in 2011. The decrease in sales volume is also due to the effect of lower revenues due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions as well as a slight increase in average ~~retail rates of 1%, and by improved economic conditions.~~rates. The above resulted in an unfavorable ~~$23.5~~$33.8 million retail sales volume variance and a favorable ~~$3.1~~$1.5 million retail price variance.

· Wholesale revenues decreased ~~$10.0~~$26.4 million primarily as a result of a ~~43%~~47% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset by a ~~13%~~7% increase in wholesale average prices. This resulted in an unfavorable ~~$14.0~~$28.6 million wholesale sales volume variance and a favorable wholesale price variance of ~~$4.0~~$2.2 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, decreased ~~$21.6~~$44.5 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of ~~an $18.4~~a $41.5 million decrease in revenues realized from the PJM capacity auction.

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DPL — Cost of Revenues

For the three months ended ~~March 31,~~June 30, 2012:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased ~~$2.3~~$20.5 million, or 2%22%, ~~compared to 2011. During~~during the quarter ended ~~March 31,~~June 30, 2012 compared to the same period in 2011. This decrease was largely due to an $18.3 million decrease in fuel costs ~~decreased by $10.3 million~~ driven by a ~~14%~~21% decrease in the volume of generation at our plants. ~~This~~Also contributing to this decrease ~~was partially offset by increased~~were unrealized MTM gains of $2.0 million for the three months ended June 30, 2012 versus $3.3 million MTM losses ~~on the sale of coal and MTM.~~ ~~DP&L~~ ~~realized $3.4 million in losses from the sale of coal, compared to $1.8 million of realized gains~~ during the same period in 2011. ~~In addition, unrealized MTM~~Partially offsetting the decreases were $1.9 million in realized losses ~~were $3.4 million for the three months ended March 31, 2012~~from DP&L’s sale of coal, compared to ~~$0.6~~$1.2 million ~~for~~of realized gains during the same period in 2011.

· Net purchased power decreased ~~$26.0~~$33.3 million, or ~~22%~~29%, compared to the same period in 2011 due largely to a ~~$26.6~~$29.8 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased ~~less than 1% and~~41% while purchased power prices decreased approximately 8%36% resulting in a decrease of $4.0 million compared to the same period in 2011. 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.

· Amortization of intangibles increased ~~$27.8~~$28.6 million, or 100%, compared to the same period in 2011 due to the application of purchase accounting at the Merger date.

For the six months ended June 30, 2012:

86·Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $22.9 million, or 12%, during the six months ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to a $28.6 million decrease in fuel costs driven by a 17% decrease in the volume of generation at our plants. Also contributing to this decrease were unrealized MTM losses of only $1.4 million for the six months ended June 30, 2012 versus $3.9 million MTM losses during the same period in 2011. Partially offsetting the decreases were $5.3 million in realized losses from DP&L’s sale of coal, compared to $2.9 million of realized gains during the same period in 2011.

·Net purchased power decreased $59.3 million, or 25%, compared to the same period in 2011 due largely to a $56.4 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased 21% while purchased power prices decreased approximately 24% resulting in a decrease of $6.7 million compared to the same period in 2011. 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.

·Amortization of intangibles increased $56.4 million, or 100%, compared to the same period in 2011 due to the application of purchase accounting at the Merger date.

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DPL — Operation and Maintenance

Three Months Ended

March 31,

$ in millions

2012 vs. 2011

Low-income payment program (1)

$
5.2

Competitive retail operations

2.2

Generating facilities operating and maintenance expenses

1.3

Maintenance of overhead transmission and distribution lines

(5.7
)
Pension expense

(0.9
)
Other, net

0.3

Total operation and maintenance expense

$
2.4

The following table provides a summary of changes in operation and maintenance expense from the prior period.

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2012 vs. 2011			2012 vs. 2011
Low-income payment program (1)	$	5.2		$	10.4
Competitive retail operations	2.6			4.8
Generating facilities operating and maintenance expenses	(0.1		)	1.3
Maintenance of overhead transmission and distribution lines	(0.6		)	(6.3		)
Merger related costs	(5.4		)	(6.0		)
Deferred compensation	(1.8		)	(2.0		)
Pension related expense	(0.7		)	(1.4		)
Other, net	(2.2		)	(1.5		)
Total operation and maintenance expense	$	(3.0	)	$	(0.7	)

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

During the three months ended ~~March 31,~~June 30, 2012, Operation and maintenance expense ~~increased $2.4~~decreased $3.0 million, or 2%3%, compared to the same period in 2011. This variance was primarily the result of:

·a slight decrease in expenses related to the maintenance of overhead transmission and distribution lines,

·higher costs in the prior year related to the Merger,

·decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current period, and

·lower pension expenses primarily related to the elimination of certain unrecognized actuarial losses and prior service costs as a result of purchase accounting due to the Merger. These amounts were previously recorded in Accumulated Other Comprehensive Income and recognized in pension expense over the remaining service life of plan participants. These decreases were partially offset by:

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

·increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers.

During the six months ended June 30, 2012, Operation and maintenance expense decreased $0.7 million compared to the same period in 2011. This variance was primarily the result of:

·decreased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011,

·higher costs in the prior year related to the Merger,

·decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods, and

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These decreases were partially offset by:

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

· increased marketing, customer maintenance and labor costs associated with the competitive retail business as a result of increased sales volume and number of customers, and

· increased expenses for generating facilities largely due to the length and timing of planned outages at jointly owned production units relative to the same period in 2011.

~~These increases were partially offset by:~~

·~~decreased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February 2011, and~~

DPL — Depreciation and Amortization

For the three and six months ended ~~March 31,~~June 30, 2012, Depreciation and amortization expense decreased ~~$3.7~~$5.4 million, or ~~11%~~15%, and $9.1 million, or 13%, respectively, as compared to 2011. The ~~decrease~~decreases primarily ~~reflects~~reflect the effect of the purchase accounting ~~resulting~~which resulted in estimated fair values of our plants below the carrying ~~value~~values at the Merger date. This was partially offset by increased amortization expense primarily due to amortization resulting from the ~~amortization~~increase in the estimated value of certain intangibles acquired in the ~~merger.~~Merger.

DPL — General Taxes

For the three and six months ended ~~March 31,~~June 30, 2012, General taxes ~~decreased $3.1~~increased $1.4 million, or ~~13%~~7%, and decreased $1.6 million, or 4%, respectively, as compared to 2011. The increase was primarily the result of higher property tax accruals in 2012. This decrease was primarily the result of an unfavorable 2011 determination from the Ohio gross receipts tax audit partially offset by higher property tax accruals in 2012 compared to 2011. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and are recorded as a reduction in revenues for presentation in accordance with AES policy. The 2011 amount was reclassified to conform to this presentation.

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DPL — Interest Expense

For the three months ended ~~March 31,~~June 30, 2012, Interest expense increased ~~$12.7~~$14.8 million, or ~~75%~~84%, as compared to 2011 due primarily to higher interest cost subsequent to the Merger as a result of the $1,250.0 million of debt that was assumed by DPL in connection with the AES Merger.

For the six months ended June 30, 2012, Interest expense increased $27.5 million, or 80%, as compared to 2011 due primarily to higher interest cost subsequent to the Merger as a result of the $1,250.0 million of debt that was assumed by DPL in connection with the AES Merger.

DPL — Charge for Early Redemption of Debt

The Charge for early redemption of debt reflects the purchase, in February 2011, of $122.0 million principal of the DPL Capital Trust II 8.125% capital securities in a privately negotiated transaction. As part of this transaction, DPL paid a $12.2 million, or 10% premium, and wrote-off $3.1 million of unamortized discount and issuance costs.

DPL — Income Tax Expense

For the three and six months ended ~~March 31,~~June 30, 2012, Income tax expense decreased ~~$17.1~~$7.6 million, or ~~69%~~47%, and $24.7 million, or 60%, respectively, as compared to 2011 primarily due to decreased pre-tax ~~income.~~income, partially offset by increased state income taxes.

RESULTS OF OPERATIONS BY SEGMENT — DPL

DPL’s two segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its competitive retail electric service subsidiaries. These segments are discussed further below:

Utility Segment

The Utility segment is comprised of DP&L’s electric generation, transmission and distribution businesses which generate and sell electricity to residential, commercial, industrial and governmental customers. Electricity for the segment’s 24-county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers who are located in a 6,000 square mile area of West Central Ohio. DP&L also sells electricity to DPLER and any excess energy and capacity is sold into the wholesale market. DP&L’s transmission and distribution businesses are subject to rate regulation by federal and state regulators while rates for its generation business are deemed competitive under Ohio law.

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Competitive Retail Segment

The Competitive Retail segment is comprised of the DPLER and MC Squared competitive retail electric service businesses which sell retail electric energy under contract to residential, commercial, industrial and governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to ~~more than 45,000~~approximately 70,000 customers currently located throughout Ohio and Illinois. MC Squared, a Chicago-based retail electricity supplier, serves more than ~~4,000~~5,900 customers in Northern Illinois. At the end of the second quarter of 2012, MC Squared added approximately 29,000 new customers in Illinois cities as a result of various governmental aggregation agreements. These new customers have not yet been billed and are not included in the customer counts above. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. DP&L sells power to DPLER and MC Squared under a wholesale ~~agreement.~~agreements. Under ~~this agreement,~~these agreements, intercompany sales from DP&L to DPLER and MC Squared are based on fixed-price contracts for each DPLER ~~customer; the~~or MC Squared customer. The price approximates market prices for wholesale power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

Other

Included within Other are other businesses that do not meet the GAAP requirements for separate disclosure as reportable segments as well as certain corporate costs which include amortization of intangibles recognized in conjunction with the Merger and interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin.

See Note 14 of Notes to DPL’s Condensed Consolidated Financial Statements for further discussion of DPL’s reportable segments.

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The following table presents DPL’s gross margin by business segment:

	Three months ended									Three months ended
	March 31,						Increase (Decrease)			June 30,
	2012			2011			2012 vs. 2011			2012			2011			Increase (Decrease)
$ in millions	Successor			Predecessor						Successor			Predecessor			2012 vs. 2011

Utility	$	219.1		$	233.4		$	(14.3	)	$	208.7		$	203.4		$	5.3
Competitive Retail	15.4			16.3			(0.9		)	14.4			12.5			1.9
Other	(19.6		)	11.4			(31.0		)	(20.8		)	12.7			(33.5		)
Adjustments and Eliminations	(0.9		)	(1.0		)	0.1			(0.8		)	(1.0		)	0.2
Total consolidated	$	214.0		$	260.1		$	(46.1	)	$	201.5		$	227.6		$	(26.1	)

	Six months ended
	June 30,
	2012			2011			Increase (Decrease)
$ in millions	Successor			Predecessor			2012 vs. 2011

Utility	$	427.8		$	436.8		$	(9.0	)
Competitive Retail	29.8			28.8			1.0
Other	(40.4		)	24.0			(64.4		)
Adjustments and Eliminations	(1.7		)	(2.0		)	0.3
Total consolidated	$	415.5		$	487.6		$	(72.1	)

The financial condition, results of operations and cash flows of the Utility segment are identical in all material respects and for both periods presented, to those of DP&L which are included in this Form 10-Q. We do not believe that additional discussions of the financial condition and results of operations of the Utility segment would enhance an understanding of this business since these discussions are already included under the DP&L discussions below.

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Income Statement Highlights — Competitive Retail Segment

	Three months ended										Three months ended
	March 31,						Increase (Decrease)				June 30,
	2012			2011			2012 vs. 2011				2012			2011			Increase (Decrease)
$ in millions	Successor			Predecessor							Successor			Predecessor			2012 vs. 2011
Revenues:
Retail	$	107.6		$	94.3			$	13.3		$	112.6		$	105.3		$	7.3
RTO and other	4.5			(0.3		)	4.8				(2.7		)	(3.3		)	0.6
	112.1			94.0			18.1				109.9			102.0			7.9

Cost of revenues:
Purchased power	96.7			77.7			19.0				95.5			89.5			6.0

Gross margins (a)	15.4			16.3			(0.9			)	14.4			12.5			1.9

Operation and maintenance expense	5.2			3.0			2.2				5.8			3.1			2.7
Other expenses (income), net	0.8			0.6			0.2				0.6			0.4			0.2
Total expenses, net	6.0			3.6			2.4				6.4			3.5			2.9

Earnings (Loss) from continuing operations before income tax	9.4			12.7			(3.3			)	8.0			9.0			(1.0		)
Income tax expense (benefit)	3.4			6.6			(3.2			)	6.5			3.3			3.2
Net income (Loss)	$	6.0		$	6.1			$	(0.1	)	$	1.5		$	5.7		$	(4.2	)

Gross margin as a percentage of
revenues	14		%	17		%

Gross margin as a percentage of revenues											13		%	12		%

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	Six months ended
	June 30,
	2012			2011			Increase (Decrease)
$ in millions	Successor			Predecessor			2012 vs. 2011
Revenues:
Retail	$	220.2		$	199.6		$	20.6
RTO and other	1.8			(3.6		)	5.4
	222.0			196.0			26.0

Cost of revenues:
Purchased power	192.2			167.2			25.0

Gross margins (a)	29.8			28.8			1.0

Operation and maintenance expense	11.0			6.1			4.9
Other expenses (income), net	1.4			1.0			0.4
Total expenses, net	12.4			7.1			5.3

Earnings (Loss) from continuing operations before income tax	17.4			21.7			(4.3		)
Income tax expense (benefit)	9.9			9.9			—
Net income (Loss)	$	7.5		$	11.8		$	(4.3	)

Gross margin as a percentage of revenues	13		%	15		%

(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.

Competitive Retail Segment — Revenue

For the three months ended ~~March 31,~~June 30, 2012, the segment’s retail revenues increased ~~$13.3~~$7.3 million, or ~~14%~~7%, as compared to 2011. The increase was primarily due to increased retail sales volume from DP&L’s retail customers switching their electric service to DPLER. Increased competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER or other CRES suppliers. The increased sales volume from switching was partially offset by unfavorable weather conditions resulting in a 12% decrease in the number of heating degree days during the period in 2012 compared to 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 1,900 million kWh of power to approximately 70,000 customers for the three months ending June 30, 2012 compared to approximately 1,700 million kWh of power to more than 15,000 customers during the same period of 2011.

For the six months ended June 30, 2012, the segment’s retail revenues increased $20.6 million, or 10%, as compared to 2011. The increase was primarily due to an $8.3 million increase in retail revenue from MC Squared which was purchased on February 28, 2011 combined with increased retail sales volume from DP&L’s retail customers switching their ~~retail~~ electric service to DPLER. Increased ~~levels of~~ competition in the competitive retail electric service business in the state of Ohio has resulted in many of DP&L’s retail customers switching their retail electric service to DPLER or other CRES suppliers. The increased sales volume from switching and ~~the purchase of~~from MC Squared was partially offset by unfavorable weather conditions resulting in a ~~23%~~22% decrease in the number of heating degree days during the period in 2012 compared to 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately ~~1,700~~3,600 million kWh of power to approximately 70,000 customers for the six months ending June 30, 2012 compared to approximately 3,100 million kWh of power to more than ~~46,000 customers for the three months ending March 31, 2012 compared to approximately 1,500 million kWh of power to more than 12,000~~15,000 customers during the same period of 2011.

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Competitive Retail Segment — Purchased Power

For the three months ended ~~March 31,~~June 30, 2012, the Competitive Retail segment purchased power increased ~~$19.0~~$6.0 million, or ~~24%~~7%, as compared to 2011 due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.

For the six months ended June 30, 2012, the Competitive Retail segment purchased power increased $25.0 million, or 15%, as compared to 2011 due to higher purchased power volumes required to satisfy an increase in customer base resulting from customer switching and ~~$11.1 million relating to~~ power purchased for MC Squared ~~customers.~~customers for all six months in 2012 versus four months in 2011. The Competitive Retail segment’s electric energy used to meet its sales obligations was purchased from DP&L and PJM. Intercompany sales from DP&L to DPLER are based on fixed-price contracts for each DPLER customer; the price approximates market prices for wholesale power at the inception of each customer’s contract.

Competitive Retail Segment — Operation and Maintenance

For the three months ended ~~March 31,~~June 30, 2012, DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2012 as compared to 2011 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

For the six months ended June 30, 2012, DPLER’s operation and maintenance expenses include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses. The higher operation and maintenance expense in 2012 as compared to 2011 is reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers and the purchase of MC Squared.

Competitive Retail Segment — Income Tax Expense

For the three months ended ~~March 31,~~June 30, 2012, the segment’s income tax expense ~~decreased~~increased $3.2 million compared to the same period in 2011 ~~primarily~~ due to ~~decreased pre-tax income and decreased~~increased state income tax expenses. ~~State~~

For the six months ended June 30, 2012, the segment’s income ~~taxes were higher in 2011 due to a $2.0 million charge for state deferred taxes due~~tax expense did not change compared to the ~~Illinois Unitary Tax rules~~same period in 2011 as a result of the ~~purchase of MC Squared.~~increased state income taxes noted above offset by decreased pre-tax income.

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RESULTS OF OPERATIONS — DP&L

Income Statement Highlights — DP&L

	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
$ in millions	2012			2011			2012			2011			2012			2011

Revenues:
Retail	$	242.7		$	276.3		$	212.7		$	232.1		$	455.4		$	508.4
Wholesale	104.5			106.2			95.8			104.7			200.3			210.9
RTO revenues	17.3			20.4			18.4			18.1			35.7			38.5
RTO capacity revenues	31.4			46.8			22.6			42.1			54.0			88.9
Mark-to-market gains	3.7			0.1
Mark-to-market (losses) / gains							(2.9		)	(0.1		)	0.8			—
Total revenues	$	399.6		$	449.8		$	346.6		$	396.9		$	746.2		$	846.7

Cost of revenues:
Fuel costs	$	88.8		$	99.8		$	68.6		$	86.9		$	157.4		$	186.7
Losses / (gains) from sale of coal	3.4			(1.8		)	1.9			(1.1		)	5.3			(2.9		)
Mark-to-market losses	3.4			0.6
Mark-to-market (gains) / losses							(1.9		)	3.3			1.5			3.9
Net fuel	95.6			98.6			68.6			89.1			164.2			187.7

Purchased power	25.5			33.9			31.1			32.8			56.6			66.7
RTO charges	24.1			29.1			20.7			27.6			44.8			56.7
RTO capacity charges	31.5			54.5			21.1			44.4			52.6			98.9
Mark-to-market losses	3.8			0.3
Mark-to-market (gains) / losses							(3.6		)	(0.4		)	0.2			(0.1		)
Total purchased power	84.9			117.8			69.3			104.4			154.2			222.2

Total cost of revenues	$	180.5		$	216.4		$	137.9		$	193.5		$	318.4		$	409.9

Gross margins (a)	$	219.1		$	233.4		$	208.7		$	203.4		$	427.8		$	436.8

Gross margin as a percentage of revenues	55		%	52		%	60		%	51		%	57		%	52		%

Operating Income	$	65.0		$	89.3		$	57.0		$	55.8		$	122.0		$	145.1

DP&L — Revenues

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

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

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

	Three Months Ended			Three Months Ended			Six Months Ended
	March 31,			June 30,			June 30,
$ in millions	2012 vs. 2011			2012 vs. 2011			2012 vs. 2011

Retail
Rate	$	(3.0	)	$	(5.4	)	$	(8.8	)
Volume	(30.8		)	(13.7		)	(44.1		)
Other miscellaneous	0.2			(0.3		)	(0.1		)
Total retail change	(33.6		)	(19.4		)	(53.0		)

Wholesale
Rate	5.7			(2.0		)	3.8
Volume	(7.4		)	(6.9		)	(14.4		)
Total wholesale change	(1.7		)	(8.9		)	(10.6		)

RTO capacity and other
RTO capacity and other RTO revenues	(18.5		)	(19.2		)	(37.7		)

Other
Unrealized MTM	$	3.6		$	(2.8	)	$	0.8

Total revenues change	$	(50.2	)	$	(50.3	)	$	(100.5	)

For the three months ended ~~March 31,~~June 30, 2012, Revenues decreased ~~$50.2~~$50.3 million, or ~~11%~~13%, to ~~$399.6~~$346.6 million from ~~$449.8~~$396.9 million in the prior year. This decrease was primarily the result of lower average retail and wholesale rates, lower retail and wholesale sales volumes and decreased RTO capacity and other ~~revenues, partially offset by higher average wholesale prices.~~revenues. The revenue components for the three months ended ~~March 31,~~June 30, 2012 are further discussed below:

·Retail revenues decreased ~~$33.6~~$19.4 million primarily due to ~~an 11%~~a 6% decrease in retail sales volumes compared to ~~those in~~ the prior year largely as a result of customer switching due to ~~unfavorable weather~~increased levels of competition to provide transmission and generation services in our service territory. This decrease in sales volume was partially offset by improved economic conditions. ~~The unfavorable weather conditions resulted~~Weather during the three months was slightly favorable with a 25% increase in ~~a 23%~~the number of cooling degree days to 400 days from 319 days in 2011 slightly offset by an 11% decrease in the number of heating degree days to ~~2,263~~455 days from ~~2,967~~513 days in 2011. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 1%3% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were 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 riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable ~~$30.8~~$13.7 million retail sales volume variance and an unfavorable ~~$3.0~~$5.4 million retail price variance.

· Wholesale revenues decreased ~~$1.7~~$8.9 million primarily as a result of a 7% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, as well as a 2% decrease in wholesale average prices partially offset by the effect of 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 an unfavorable $6.9 million wholesale volume variance and a $2.0 million unfavorable wholesale price variance.

·RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased $19.2 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of a $19.5 million decrease in revenues realized from the PJM capacity auction, offset by a slight increase of $0.3 million in transmission and congestion revenues.

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For the six months ended June 30, 2012, Revenues decreased $100.5 million, or 12%, to $746.2 million from $846.7 million in the prior year. This decrease was primarily the result of lower average retail rates, lower retail and wholesale sales volumes and decreased RTO capacity and other revenues, partially offset by higher average wholesale prices. The revenue components for the six months ended June 30, 2012 are further discussed below:

·Retail revenues decreased $53.0 million primarily due to a 9% decrease in retail sales volumes compared to those in the prior year largely due to unfavorable weather conditions. The unfavorable weather conditions resulted in a 22% decrease in the number of heating degree days to 2,718 days from 3,480 days in 2011 offset slightly by a 35% increase in the number of cooling degree days to 430 days from 319 days in 2011. Although DP&L had a number of customers that switched their retail electric service from DP&L to DPLER, an affiliated CRES provider, DP&L continued to provide distribution services to those customers within its service territory. The average retail rates decreased 2% overall primarily as a result of customers switching from DP&L to DPLER. The remaining distribution services provided by DP&L were 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 riders, and the incremental effect of the recovery of costs under the EIR. The above resulted in an unfavorable $44.1 million retail sales volume variance and an unfavorable $8.8 million retail price variance.

·Wholesale revenues decreased $10.6 million primarily as a result of a 7% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset by the effect of 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 decrease was partially offset by a 6%2% increase in average wholesale sales prices. This resulted in an unfavorable ~~$7.4~~$14.4 million wholesale volume variance offset partially by a ~~$5.7~~$3.8 million favorable wholesale price variance.

· RTO capacity and other revenues, consisting primarily of compensation for use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, decreased ~~$18.5~~$37.7 million compared to the same period in 2011. This decrease in RTO capacity and other revenues was primarily the result of a ~~$15.4~~$34.9 million decrease in revenues realized from the PJM capacity auction and a decrease of ~~$3.1~~$2.8 million in transmission and congestion revenues.

~~Table of Contents~~

DP&L — Cost of Revenues

For the three months ended ~~March 31,~~June 30, 2012:

· Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased ~~$3.0~~$20.5 million, or 3%23%, ~~compared to 2011. During~~during the quarter ended ~~March 31,~~June 30, 2012 compared to the same period in 2011. This decrease was largely due to an $18.3 million decrease in fuel costs ~~decreased by $11.0 million~~ driven by a ~~14%~~22% decrease in the volume of generation at our plants. ~~This~~Also contributing to this decrease ~~was partially offset by increased~~were unrealized MTM gains of $1.9 million for the three months ended June 30, 2012 versus $3.3 million MTM losses ~~on the sale of coal and MTM.~~ ~~DP&L~~ ~~realized $3.4 million in losses from the sale of coal, compared to $1.8 million of realized gains~~ during the same period in 2011. ~~In addition, unrealized MTM~~Partially offsetting the decreases were $1.9 million in realized losses ~~were $3.4 million for the three months ended March 31, 2012~~from DP&L’s sale of coal, compared to ~~$0.6~~$1.1 million ~~for~~of realized gains during the same period in 2011.

· Net purchased power decreased ~~$32.9~~$35.1 million, or ~~28%~~34%, compared to the same period in 2011 due largely to a ~~$28.0~~$30.2 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This ~~increase~~decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes ~~decreased 23% and~~increased 56% while purchased power prices decreased approximately 2%39% resulting in a decrease of $1.7 million compared to the same period in 2011. 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 six months ended June 30, 2012:

·Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $23.5 million, or 13%, during the six months ended June 30, 2012 compared to the same period in 2011. This decrease was largely due to a $29.3 million decrease in fuel costs driven by an 18% decrease in the volume of generation at our plants. Also contributing to the decrease were unrealized MTM losses of $1.5 million for the six months ended June 30, 2012 versus $3.9 million MTM losses during the same period in 2011. Partially offsetting the decreases were $5.3 million in realized losses from DP&L’s sale of coal, compared to $2.9 million of realized gains during the same period in 2011.

·Net purchased power decreased $68.0 million, or 31%, compared to the same period in 2011 due largely to a $58.2 million decrease in RTO capacity and other charges which were incurred as a member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Purchased power volumes increased 13% while purchased power prices decreased approximately 25% resulting in a decrease of $10.1 million compared to the same period in 2011. We purchase power to satisfy retail sales volume when generating facilities are not available due to planned and unplanned outages or when market prices are below the marginal costs associated with our generating facilities.

DP&L — Operation and Maintenance

Three Months Ended

March 31,

$ in millions

2012 vs 2011

Low-income payment program (1)

$
5.2

Generating facilities operating and maintenance expenses

1.4

Pension expenses

1.1

Maintenance of overhead transmission and distribution lines

(5.7
)
Other, net

5.8

Total operation and maintenance expense

$
7.8

The following table provides a summary of changes in operation and maintenance expense from the prior period.

	Three Months Ended			Six Months Ended
	June 30,			June 30,
$ in millions	2012 vs. 2011			2012 vs. 2011
Low-income payment program (1)	$	5.2		$	10.4
Generating facilities operating and maintenance expenses	—			1.4
Pension expenses	0.6			1.7
Maintenance of overhead transmission and distribution lines	(0.6		)	(6.3		)
Deferred compensation	(1.8		)	(2.0		)
Other, net	(2.5		)	3.5
Total operation and maintenance expense	$	0.9		$	8.7

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

For the three months ended ~~March 31,~~June 30, 2012, Operation and maintenance expense increased ~~$7.8~~$0.9 million, or 9%1%, compared to the same period in 2011. This variance was primarily the result of increased assistance for low-income retail customers which is funded by the USF revenue rate rider. These increases were partially offset by decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods.

For the six months ended June 30, 2012, Operation and maintenance expense increased $8.7 million, or 5%, compared to the same period in 2011. This variance was primarily the result of:

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

· increased expenses for generating facilities largely due to the length and timing of planned outages at jointly owned production units relative to the same period in 2011, and

· increased pension expenses primarily related to changes in plan assumptions, specifically a lower discount rate and lower expected rate of return on plan assets.

These increases were partially offset by by:

·decreased expenses related to the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in February ~~2011.~~2011, and

·decreased expenses related to deferred compensation arrangements primarily related to fewer equity awards in the current periods.

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DP&L — Depreciation and Amortization

For the three and six months ended ~~March 31,~~June 30, 2012, Depreciation and amortization expense increased ~~$1.6~~$2.7 million and $4.3 million, respectively, as compared to 2011. The increase primarily reflected the impact of investments in plant and equipment during the ~~three~~six months ended ~~March 31,~~June 30, 2012.

DP&L — General Taxes

For the three and six months ended ~~March 31,~~June 30, 2012, General taxes increased ~~$0.6~~$0.5 million, or 3%, and $1.1 million, or 3%, respectively, as compared to 2011. This increase was primarily the result of higher property tax accruals in 2012. Prior to the Merger date, certain excise and other taxes were recorded gross. Effective on the Merger date, these taxes are accounted for on a net basis and are recorded as a reduction in Revenues for presentation in accordance with AES policy. The 2011 ~~amount was~~amounts were reclassified to conform to this presentation.

~~Table of Contents~~

DP&L — Interest Expense

Interest expense recorded during the three and six months ended ~~March 31,~~June 30, 2012 did not fluctuate significantly from that recorded during the three and six months ended ~~March 31,~~June 30, 2011.

DP&L — Income Tax Expense

For the three and six months ended ~~March 31,~~June 30, 2012, Income tax expense ~~decreased $9.7~~increased $0.1 million, or ~~36%~~1%, and decreased $9.6 million, or 23%, respectively, as compared to 2011 primarily due to decreased pre-tax ~~income.~~income during the six month period.

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

Three months ended

March 31,

2012

2011

$ in millions

Successor

Predecessor

Net cash provided by operating activities

$
94.6

$
92.0

Net cash provided by / (used for) investing activities

(54.0
)

10.0

Net cash used for financing activities

(52.0
)

(155.5
)

Net change

(11.4
)

(53.5
)
Cash and cash equivalents at beginning of period

173.5

124.0

Cash and cash equivalents at end of period

$
162.1

$
70.5

DPL

	Six months ended
	June 30,
	2012			2011
$ in millions	Successor			Predecessor

Net cash provided by operating activities	$	143.1		$	185.1
Net cash used for investing activities	(110.5		)	(28.6		)
Net cash used for financing activities	(53.8		)	(207.7		)

Net change	(21.2		)	(51.2		)
Cash and cash equivalents at beginning of period	173.5			124.0
Cash and cash equivalents at end of period	$	152.3		$	72.8

DP&L

For the Three Months

Ended March 31,

$ in millions

2012

2011

Net cash provided by operating activities

$
89.6

$
84.0

Net cash used for investing activities

(53.2
)

(40.4
)
Net cash used for financing activities

(45.2
)

(40.2
)

Net change

(8.8
)

3.4

Cash and cash equivalents at beginning of period

32.2

54.0

Cash and cash equivalents at end of period

$
23.4

$
57.4

DP&L

	Six months ended
	June 30,
$ in millions	2012			2011

Net cash provided by operating activities	$	173.5		$	163.2
Net cash used for investing activities	(109.5		)	(89.1		)
Net cash used for financing activities	(70.5		)	(115.4		)

Net change	(6.5		)	(41.3		)
Cash and cash equivalents at beginning of period	32.2			54.0
Cash and cash equivalents at end of period	$	25.7		$	12.7

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

Net ~~Cash Provided~~cash provided by ~~Operating Activities~~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.

~~Table of Contents~~

DPL — Net cash provided by operating activities

DPL’s Net cash provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

	Successor			Predecessor			Successor			Predecessor
	Three months			Three months			Six months			Six months
	ended			ended			ended			ended
	March 31,			March 31,			June 30,			June 30,
$ in millions	2012			2011			2012			2011

Net income	$	21.7		$	43.5		$	26.6		$	75.2
Depreciation and amortization	54.5			35.1			108.0			70.2
Deferred income taxes	(9.2		)	33.7			(6.9		)	37.5
Charge for early redemption of debt	—			15.3			—			15.3
Contribution to pension plan	—			(40.0		)	—			(40.0		)
Accrued interest	29.1			(1.2		)	1.5			2.0
Deferred regulatory costs, net	7.2			12.8			0.1			8.9
Other	(8.7		)	(7.2		)	13.8			16.0
Net cash provided by operating activities	$	94.6		$	92.0		$	143.1		$	185.1

For the ~~three~~six months ended ~~March 31,~~June 30, 2012, Net cash provided by operating activities was primarily a result of Net income adjusted for noncash depreciation and amortization. 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, taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances. Accrued interest relates primarily to the $1,250.0 million of debt and the timing of payments.

For the ~~three~~six months ended ~~March 31,~~June 30, 2011, 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:

· A ~~$33.7~~$37.5 million increase to Deferred income taxes primarily as a result of depreciation as well as pension contributions.

· A $15.3 million charge for the early redemption of DPL Capital Trust II securities.

· A DP&L contribution of $40.0 million to the defined benefit pension plan in February 2011.

·109

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 timingTable 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.Contents

DP&L — Net cash provided by operating activities

DP&L’s Net cash provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

Three Months Ended

March 31,

$ in millions

2012

2011

Net income

$
38.1

$
52.7

Depreciation and amortization

34.7

33.1

Deferred income taxes

(2.4
)

33.3

Contribution to pension plan

—

(40.0
)
Deferred regulatory costs, net

7.1

12.8

Other

12.1

(7.9
)
Net cash provided by operating activities

$
89.6

$
84.0

~~Table of Contents~~

	Six Months Ended
	June 30,
$ in millions	2012			2011

Net income	$	69.4		$	83.5
Depreciation and amortization	70.8			66.5
Deferred income taxes	3.3			37.2
Contribution to pension plan	—			(40.0		)
Accrued interest	5.2			5.3
Deferred regulatory costs, net	(0.1		)	8.9
Other	24.9			1.8
Net cash provided by operating activities	$	173.5		$	163.2

For the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011, 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 — Net cash (used for) / provided by investing activities

DPL’s Net cash used for investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

Successor

Predecessor

Three months

Three months

ended

ended

March 31,

March 31,

$ in millions

2012

2011

Other plant-related asset acquisitions, net

$
(51.7
)

$
(41.4
)
Environmental and renewable energy capital expenditures

(2.3
)

(1.6
)
Purchase of MC Squared

—

(8.2
)
Sales / (purchases) of short-term investments, net

—

59.1

Other

—

2.1

Net cash (used for) / provided by investing activities

$
(54.0
)

$
10.0

	Successor			Predecessor
	Six months			Six months
	ended			ended
	June 30,			June 30,
$ in millions	2012			2011

Other plant-related asset acquisitions, net	$	(104.9	)	$	(85.5	)
Environmental and renewable energy capital expenditures	(5.6		)	(5.9		)
Purchase of MC Squared	—			(8.2		)
Sales / (purchases) of short-term investments, net	—			69.2
Other	—			1.8
Net cash (used for) / provided by investing activities	$	(110.5	)	$	(28.6	)

For the ~~three~~six months ended ~~March 31,~~June 30, 2012, DPL’s cash used for investing activities reflects assets acquired at our generation plants.

For the ~~three~~six months ended ~~March 31,~~June 30, 2011, DPL cash used for investing activities was primarily for assets acquired at our generation plants. Additionally, DPL, on behalf of DPLER, made a cash payment of approximately $8.2 million to acquire MC Squared. Also during the ~~three~~six months ended ~~March 31,~~June 30, 2011, DPL redeemed ~~$60.8~~$70.9 million of short-term investments mostly comprised of VRDN securities as well as purchased an additional $1.7 million of short-term investments during the same period. 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.

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Table of Contents

DP&L — Net cash used for investing activities

DP&L’s Net cash used for investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

	Three Months Ended						Six Months Ended
	March 31,						June 30,
$ in millions	2012			2011			2012			2011

Other plant-related asset acquisitions, net	$	(50.9	)	$	(40.8	)	$	(103.9	)	$	(85.0	)
Environmental and renewable energy capital expenditures	(2.3		)	(1.6		)
Environmental and renewable energy
capital expenditures							(5.6		)	(5.8		)
Other	—			2.0			—			1.7
Net cash used for investing activities	$	(53.2	)	$	(40.4	)	$	(109.5	)	$	(89.1	)

For the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011, the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’s Net cash used for investing activities above with the exception of the short-term investing activity.

~~Table of Contents~~

DPL — Net cash used for financing activities

DPL’s Net cash used for financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

	Successor			Predecessor			Successor			Predecessor
	Three months			Three months			Six months			Six months
	ended			ended			ended			ended
	March 31,			March 31,			June 30,			June 30,
$ in millions	2012			2011			2012			2011

Dividends paid on common stock	$	(45.0	)	$	(37.8	)	$	(45.0	)	$	(76.4	)
Contributions to additional paid-in capital from parent	2.0			—			0.3			—
Payment to former warrant holders	(9.0		)	—			(9.0		)	—
Retirement of long-term debt							(0.1		)	—
Early redemption of long-term debt, including premium	—			(134.2		)	—			(134.2		)
Payment of MC Squared debt	—			(13.5		)	—			(13.5		)
Withdrawals from revolving credit facility, net	—			30.0
Exercise of warrants							—			14.7
Exercise of stock options including tax impact							—			1.7
Net cash used for financing activities	$	(52.0	)	$	(155.5	)	$	(53.8	)	$	(207.7	)

For the ~~three~~six months ended ~~March 31,~~June 30, 2012, DPL paid common stock dividends of $45.0 million to its parent, partially offset by contributions to additional paid-in capital from its parent, AES. DPL also paid $9.0 million to former warrant holders which represents the difference between the exercise price of $21.00 per share and the $30.00 per share paid by AES in the Merger.

For the ~~three~~six months ended ~~March 31,~~June 30, 2011, DPL paid common stock dividends of ~~$37.8~~$76.4 million and paid $134.2 million for the purchase of the DPL Capital Trust II capital securities, of which $122.0 million related to the capital securities and an additional $12.2 million related to the premium paid on the purchase. DPL also paid down the debt of MC Squared which was acquired in February 2011. ~~In addition,~~ ~~DP&L~~ ~~initiated net draws~~

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Table of ~~$30.0 million on one of its revolving credit facilities.~~Contents

DP&L —– Net cash used for financing activities

DP&L’s Net cash used for financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 can be summarized as follows:

	Three Months Ended						Six Months Ended
	March 31,						June 30,
$ in millions	2012			2011			2012			2011

Dividends paid on common stock to parent	$	(45.0	)	$	(70.0	)	$	(70.0	)	$	(115.0	)
Withdrawals from revolving credit facility, net	—			30.0
Other	(0.2		)	(0.2		)	(0.5		)	(0.4		)
Net cash used for financing activities	$	(45.2	)	$	(40.2	)	$	(70.5	)	$	(115.4	)

For the ~~three~~six months ended ~~March 31,~~June 30, 2012, ~~DP&L’s~~ ~~Net cash used for financing activities primarily relates to $45.0 million in dividends.~~

~~For the three months ended March 31, 2011,~~DP&L’s Net cash used for financing activities primarily relates to $70.0 million in dividends ~~partially offset by a net withdrawal of $30.0~~paid to DPL.

For the six months ended June 30, 2011, DP&L’s Net cash used for financing activities primarily relates to $115.0 million ~~on one of its revolving credit facilities.~~in dividends paid to DPL.

Liquidity

We expect our existing sources of liquidity to remain sufficient to meet our anticipated ~~obligations.~~operating needs. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements for retail operations, and dividend payments. For 2012, 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 bank credit facilities will continue to be available to manage working capital requirements during those periods.

~~Table of Contents~~

At the filing date of this quarterly report on Form 10-Q, DP&L has access to $400.0 million of short-term financing under two revolving credit facilities. The first facility, established in August 2011, is for $200.0 million, ~~and~~ expires in August 2015 and has eight participating banks, with no bank having more than 22% of the total commitment. DP&L also has the option to increase the potential borrowing amount under the first facility by $50.0 million. The second facility, established in April 2010, is for $200.0 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. DP&L also has the option to increase the potential borrowing amount under the second facility by $50.0 million.

At the filing date of this quarterly report on Form 10-Q, DPL has access to $125.0 million of short-term financing under a revolving credit facility established in August 2011. This facility expires in August 2014 and has seven participating banks with no bank having more than 32% of the total commitment.

					Amounts						Amounts
					available as of						available as of
$ in millions	Type	Maturity	Commitment		March 31, 2012		Type	Maturity	Commitment		June 30, 2012

DP&L	Revolving	August 2015	$	200.0	$	200.0	Revolving	August 2015	$	200.0	$	200.0

DP&L	Revolving	April 2013	200.0		200.0		Revolving	April 2013	200.0		200.0

DPL Inc.	Revolving	August 2014	125.0		125.0		Revolving	August 2014	125.0		125.0

			$	525.0	$	525.0			$	525.0	$	525.0

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Table of Contents

Each DP&L revolving credit facility has a $50.0 million letter of credit sublimit. The entire DPL revolving credit facility amount is available for letter of credit issuances. As of ~~March 31,~~June 30, 2012 and through the date of filing this quarterly report on Form 10-Q, there were no letters of credit issued and outstanding on the revolving credit facilities.

Cash and cash equivalents for DPL and DP&L amounted to ~~$162.1~~$152.3 million and ~~$23.4~~$25.7 million, respectively, at ~~March 31,~~June 30, 2012. At that date, neither DPL nor DP&L had any short-term ~~investments.~~investments that were not included in cash and cash equivalents.

On February 23, 2011, DPL purchased and retired $122.0 million principal amount of DPL Capital Trust II 8.125% trust preferred securities. As part of this transaction, DPL paid a $12.2 million, or 10%, premium. Debt issuance costs and unamortized debt discount associated with this transaction, totaling $3.1 million, were also recognized in February 2011.

Capital Requirements

Planned construction additions for 2012 relate primarily to new investments in and upgrades to DP&L’s power plant equipment and 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 ~~$700.0~~$585.0 million in capital projects for the period 2012 through 2014. Approximately $15.0 million of this projected amount is to enable DP&L to meet the recently revised reliability standards of NERC. DP&L is subject to the mandatory reliability standards of NERC and Reliability First 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 $72.0 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.

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Debt Covenants

As mentioned above, DPL has access to $125.0 million of short-term financing under its revolving credit facility and has borrowed $425.0 million under its term loan facility. Each of these facilities has two financial covenants. The first financial covenant requires DPL’s total debt to total capitalization ratio to not exceed 0.70 to 1.00. The second financial covenant requires DPL’s consolidated earnings before interest, taxes, depreciation and amortization (EBITDA) to consolidated interest charge ratio to be not less than 2.50 to 1.00. As of ~~March 31,~~June 30, 2012 the first covenant was met with a ratio of 0.55 to 1.00, and the second covenant was met with a ratio of ~~5.82~~5.20 to 1.00. The debt to capitalization ratio is calculated as the sum of DPL’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DPL’s ~~shareholders’~~shareholder’s equity and total debt including guarantee obligations. The consolidated interest rate coverage ratio is calculated, at the end of each fiscal quarter, by dividing consolidated EBITDA for the four prior fiscal quarters by the consolidated interest charges for the same period.

Also mentioned above, DP&L has access to $400.0 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 ~~March 31, 2011,~~June 30, 2012, this covenant was met with a ratio of 0.41 to 1.00. The above ratio is calculated as the sum of DP&L’s current and long-term portion of debt, including its guarantee obligations, divided by the total of DP&L’s ~~shareholders’~~shareholder’s equity and total debt including guarantee obligations.

There have been no material changes to our debt covenants as disclosed in our Form 10-K for the fiscal year ended December 31, 2011.

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Debt Ratings

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

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

Fitch Ratings	BB+	BBB+	Stable	November 2011
Moody’s Investors Service	Ba1	A3	Stable	November 2011
Standard & Poor’s Corp.	BB+	BBB+	CreditWatch Negative	April 2012

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

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

Credit Ratings

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

	DPL	DP&L	Outlook	Effective

Fitch Ratings	BB+	BBB-	Stable	November 2011
Moody’s Investors Service	Ba1	Baa2	Stable	November 2011
Standard & Poor’s Corp.	BBB-	BBB-	CreditWatch Negative	April 2012

Standard & Poor’s recently put both DPL and DP&L on CreditWatch Negative reflecting the potential to lower the credit ratings of both entities in the near term pending greater clarity on the timing and transition to full market rates for DP&L. They have also revised their assessment of DPL and DP&L’s business risk profiles to “strong” from “excellent” to reflect the increased competition in Ohio, the expected growth of the unregulated retail business and the increasing competitive pressure due to lower wholesale electric prices stressing profit margins.

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If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

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, and its wholly owned subsidiary MC Squared, providing financial or performance assurance to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish these subsidiaries’ intended commercial purposes. During the ~~three~~six months ended ~~March 31,~~June 30, 2012, DPL did not incur any losses related to the guarantees of these 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.

At ~~March 31,~~June 30, 2012, DPL had ~~$47.4~~$26.4 million of guarantees to third parties, for future financial or performance assurance under such agreements, on behalf of DPLE, DPLER and MC Squared. The guarantee arrangements entered into by DPL with these third parties cover present and future obligations of DPLE, DPLER and MC Squared to such beneficiaries and are terminable at any time by DPL upon written notice to the beneficiaries. The carrying amount of obligations for commercial transactions covered by these guarantees and recorded in our Condensed Consolidated Balance Sheets was ~~$0.4~~$1.0 million at ~~March 31,~~June 30, 2012.

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DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of ~~March 31,~~June 30, 2012, DP&L could be responsible for the repayment of 4.9%, or ~~$64.9~~$69.2 million, of a ~~$1,324.7~~$1,411.4 million debt obligation that features maturities ranging from 2013 to ~~2026.~~2040. This would only happen if this electric generation company defaulted on its debt payments. As of ~~March 31,~~June 30, 2012, we have no knowledge of such a default.

Commercial Commitments and Contractual Obligations

Also see Note 13 of Notes to DPL’s 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, changes in capacity prices and fluctuations in interest rates. We use various market risk sensitive instruments, including derivative contracts, primarily to limit our exposure to fluctuations in commodity pricing. Our Commodity Risk Management Committee (CRMC), ~~comprising~~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 instruments are used principally for economic hedging purposes and none are held for trading purposes. 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 cash flow hedge accounting. MTM gains and losses on derivative instruments that qualify for cash flow hedge accounting are deferred in AOCI until the forecasted transactions occur.

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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.

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 2012 under contract, sales requirements may change. The majority of the contracted coal is purchased at fixed prices. Some contracts provide for periodic ~~adjustments and some are priced based on market indices.~~adjustments. Fuel costs are affected by changes in volume and price and are driven by a number of variables including weather, the wholesale market price of power, certain provisions in coal contracts related to government imposed costs, counterparty performance and credit, scheduled outages and generation plant mix. To the extent we are not able to hedge against price volatility or recover increases through our fuel and purchased power recovery rider that began in January ~~2010;~~2010, our results of operations, financial condition or cash flows could be materially affected.

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.

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Commodity Derivatives

To minimize the risk of fluctuations in the market price of commodities, such as coal, power and heating oil, we may enter into commodity-forward and futures contracts to effectively hedge the cost/revenues of the commodity. Maturity dates of the contracts are scheduled to coincide with market purchases/sales of the commodity. Cash proceeds or payments between us and the counter-party at maturity of the contracts are recognized as an adjustment to the cost of the commodity purchased or sold. We generally do not enter into forward contracts beyond thirty-six months.

A 10% increase or decrease in the market price of our heating oil forwards, NYMEX coal forwards and power forward ~~power~~ contracts at ~~March 31,~~June 30, 2012 would not have a significant effect on Net income.

The following table provides information regarding the volume and average market price of our NYMEX coal forward derivative contracts at March 31, 2012 and the effect to Net income if the market price were to increase or decrease by 10%:

NYMEX Coal Forwards

Contract
Volume
(in millions of
Tons)

Weighted
Average
Market
Price
(per Ton)

Increase /
Decrease in
Net Income
(in millions) (a)

2012-Purchase

0.9

$
61.02

$
1.9

2013-Purchase

0.5

$
69.94

$
1.1

2014-Purchase

—

$
—

$
—

~~(a)The Net Income effect of a 10% change in the market price of NYMEX Coal has been partially off-set by our partners’ share of the gain or loss and by the retail jurisdicational share of the~~ ~~DPL~~ ~~portion that is deferred on the balance sheet in conjunction with the fuel and purchased power recovery rider.~~

Wholesale Revenues

Approximately ~~14%~~10% of DPL’s and 34% of DP&L’s electric revenues for the three months ended ~~March 31,~~June 30, 2012 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.

Approximately 18% of DPL’s and ~~34%~~37% of DP&L’s electric revenues for the three months ended ~~March 31,~~June 30, 2011 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.

~~101~~Approximately 12% of DPL’s and 34% of DP&L’s electric revenues for the six months ended June 30, 2012 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.

~~Table~~Approximately 18% of ~~Contents~~DPL’s and 35% of DP&L’s electric revenues for the six months ended June 30, 2011 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 ~~March 31,~~June 30, 2012, 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), including the impact of a corresponding 10% change in the portion of purchased power used as part of the sale (note the share of the internal generation used to meet the DPLER wholesale sale would not be affected by the 10% change in wholesale prices):

$ in millions	DPL		DP&L		DPL		DP&L

Effect of 10% change in price per mWh	$	7.0	$	5.8	$	6.0	$	6.0

RPM Capacity Revenues and Costs

As a member of PJM, DP&L receives revenues from the RTO related to its transmission and generation assets and incurs costs associated with its load obligations for retail customers. PJM, which has a delivery year which runs from June 1 to May 31, has conducted auctions for capacity through the ~~2014/15~~2015/16 delivery year. The clearing prices for capacity during the PJM delivery periods from ~~2010/11~~2011/12 through ~~2014/15~~2015/16 are as follows:

PJM Delivery Year

2010/11

2011/12

2012/13

2013/14

2014/15

Capacity clearing price ($/MW-day)

$
174

$
110

$
16

$
28

$
126

	PJM Delivery Year
	2011/12		2012/13		2013/14		2014/15		2015/16

Capacity clearing price ($/MW-day)	$	110	$	16	$	28	$	126	$	136

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Our computed average capacity prices by calendar year are reflected in the table below:

Calendar Year

2010

2011

2012

2013

2014

Computed average capacity price ($/MW-day)

$
144

$
137

$
55

$
23

$
85

	Calendar Year
	2011		2012		2013		2014		2015

Computed average capacity price ($/MW-day)	$	137	$	55	$	23	$	85	$	132

Future RPM auction results are dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and PJM’s RPM business rules. The volatility in the RPM capacity auction pricing has had and will continue to have a significant impact on DPL’s capacity revenues and costs. Although DP&L currently has an approved RPM rider in place to recover or repay any excess capacity costs or revenues, the RPM rider only applies to customers supplied under our SSO. Customer switching reduces the number of customers supplied under our SSO, causing more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.

The table below provides estimates of the effect on annual net income as of ~~March 31,~~June 30, 2012 of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes. We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO. These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through ~~March 31,~~June 30, 2012. As of ~~March 31,~~June 30, 2012, approximately ~~47%~~48% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions	DPL		DP&L		DPL		DP&L

Effect of a $10/MW-day change in capacity auction pricing	$	5.3	$	4.0	$	5.1	$	3.8

Capacity revenues and costs are also impacted by, among other factors, the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.

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Fuel and Purchased Power Costs

DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs in the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 were 34% and ~~37%~~36%, respectively. We have a significant portion of projected 2012 fuel needs under contract. The majority of our contracted coal is purchased at fixed prices although some contracts provide for periodic pricing adjustments. We may purchase SO2 allowances for 2012; 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 2012 depending on NOx emissions. Fuel costs are affected 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 was allowed to recover its SSO retail customers’ share of fuel and purchased power costs as part of the fuel rider approved by the PUCO. Since there has been an increase in customer switching, SSO customers currently represent approximately ~~49%~~48% of DP&L’s total fuel costs. The table below provides the effect on annual net income as of ~~March 31,~~June 30, 2012, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate ~~49%~~48% recovery:

$ in millions	DPL		DP&L		DPL		DP&L

Effect of 10% change in fuel and purchased power	$	17.4	$	15.7	$	17.0	$	15.3

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Interest Rate Risk

As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL and DP&L have both fixed-rate and ~~variable rate~~variable-rate long-term debt. DPL’s variable-rate debt consists of a $425.0 million unsecured term loan with a syndicated bank group. The term loan interest rate fluctuates with changes in an underlying interest rate index, typically LIBOR. DP&L’s variable-rate debt is comprised of publicly held pollution control bonds. The variable-rate bonds bear interest based on a prevailing rate that is reset weekly based on a comparable market index. Market indexes can be affected by market demand, supply, market interest rates and other economic conditions. See Note 7 of Notes to DPL’s Condensed Consolidated Financial Statements and Note 6 to DP&L’s Condensed Financial Statements.

We partially hedge against interest rate fluctuations by entering into interest rate swap agreements to limit the interest rate exposure on the underlying financing. As of ~~March 31,~~June 30, 2012, we have entered into interest rate hedging relationships with an aggregate notional amount of $160.0 million related to planned future borrowing activities in calendar year 2013. The average interest rate associated with the $160.0 million aggregate notional amount interest rate hedging relationships is 3.8%. We are limiting 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. Any additional credit rating downgrades could affect our liquidity and further increase our cost of capital.

The carrying value of DPL’s debt was ~~$2,624.5~~$2,619.6 million at ~~March 31,~~June 30, 2012, consisting of DPL’s unsecured notes and unsecured term loan, along with DP&L’s first mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base debt facility. All of DPL’s debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at ~~March 31,~~June 30, 2012 was ~~$2,723.4~~$2,744.4 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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Carrying Value and Interest Rate Detail by Contractual Maturity Date

DPL

																			Carrying value at		Fair value at																				Carrying value at		Fair value at
																			March 31,		March 31,		Twelve Months Ending June 30,																		June 30,		June 30,
$ in millions	2013			2014			2015			2016			2017			Thereafter			2012 (a)		2012 (a)		2013			2014			2015			2016			2017			Thereafter			2012 (a)		2012 (a)
Long-term debt

Variable-rate debt	$	—		$	—		$	425.0		$	—		$	—		$	100.0		$	525.0	$	525.0	$	—		$	—		$	425.0		$	—		$	—		$	100.0		$	525.0	$	525.0
Average interest rate	0.0		%	0.0		%	2.3		%	0.0		%	0.0		%	0.1		%					0.0		%	0.0		%	2.2		%	0.0		%	0.0		%	0.2		%

Fixed-rate debt	$	0.4		$	499.3		$	0.2		$	0.1		$	450.1		$	1,149.4		$	2,099.5	$	2,198.4	$	0.4		$	494.4		$	0.1		$	0.1		$	450.1		$	1,149.5		$	2,094.6	$	2,219.4
Average interest rate	4.9		%	5.1		%	4.8		%	4.2		%	6.5		%	6.6		%					4.8		%	5.1		%	4.2		%	4.2		%	6.5		%	6.6		%

Total																			$	2,624.5	$	2,723.4																			$	2,619.6	$	2,744.4

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

The carrying value of DP&L’s debt was ~~$903.3~~$903.2 million at ~~March 31,~~June 30, 2012, consisting of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and the Wright-Patterson Air Force Base debt facility. The fair value of this debt was ~~$930.6~~$938.9 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. Note that the DP&L debt was not revalued using push-down accounting as a result of the Merger.

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Principal Payments and Interest Rate Detail by Contractual Maturity Date

DP&L

																			Carrying value at		Fair value at																				Carrying value at		Fair value at
				��															March 31,		March 31,		Twelve Months Ending June 30,																		June 30,		June 30,
$ in millions	2013			2014			2015			2016			2017			Thereafter			2012 (a)		2012 (a)		2013			2014			2015			2016			2017			Thereafter			2012 (a)		2012 (a)
Long-term debt

Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0	$	100.0	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0	$	100.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.1		%					0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.2		%

Fixed-rate debt	$	0.4		$	470.4		$	0.2		$	0.1		$	0.1		$	332.1		$	803.3	$	830.6	$	0.4		$	470.4		$	0.1		$	0.1		$	0.1		$	332.1		$	803.2	$	838.9
Average interest rate	4.9		%	5.1		%	4.8		%	4.2		%	4.2		%	4.8		%					4.8		%	5.1		%	4.2		%	4.2		%	4.2		%	4.8		%

Total																			$	903.3	$	930.6																			$	903.2	$	938.9

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

Debt maturities occurring in 2012 are discussed under FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS.

Long-term Debt Interest Rate Risk Sensitivity Analysis

Our estimate of market risk exposure is presented for our fixed-rate and variable-rate debt at ~~March 31,~~June 30, 2012 for which an immediate adverse market movement causes a potential material impact on our financial position, results of operations, or the fair value of the debt. We believe that the adverse market movement represents the hypothetical loss to future earnings and does not represent the maximum possible loss nor any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. As of ~~March 31,~~June 30, 2012, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

~~104~~DPL

	Carrying value at		Fair value at		One percent
	June 30,		June 30,		interest rate
$ in millions	2012		2012		risk
Long-term debt

Variable-rate debt	$	525.0	$	525.0	$	5.3

Fixed-rate debt	2,094.6		2,219.4		22.2

Total	$	2,619.6	$	2,744.4	$	27.5

DP&L

	Carrying value at		Fair value at		One percent
	June 30,		June 30,		interest rate
$ in millions	2012		2012		risk
Long-term debt

Variable-rate debt	$	100.0	$	100.0	$	1.0

Fixed-rate debt	803.2		838.9		8.4

Total	$	903.2	$	938.9	$	9.4

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~~DPL~~

Carrying value at

Fair value at

One percent

March 31,

March 31,

interest rate

$ in millions

2012

2012

risk

Long-term debt

Variable-rate debt

$
525.0

$
525.0

$
5.3

Fixed-rate debt

2,099.5

2,198.4

22.0

Total

$
2,624.5

$
2,723.4

$
27.3

~~DP&L~~

Carrying value at

Fair value at

One percent

March 31,

March 31,

interest rate

$ in millions

2012

2012

risk

Long-term debt

Variable-rate debt

$
100.0

$
100.0

$
1.0

Fixed-rate debt

803.3

830.6

8.3

Total

$
903.3

$
930.6

$
9.3

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 primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $~~2,099.5~~2,094.6 million of fixed-rate debt and not on DPL’s financial condition 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 DPL’s $525.0 million variable-rate long-term debt outstanding as of ~~March 31,~~June 30, 2012.

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 ~~$803.3~~$803.2 million of fixed-rate debt and not on DP&L’s financial condition 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 $100.0 million variable-rate long-term debt outstanding as of ~~March 31,~~June 30, 2012.

Equity Price Risk

As of ~~March 31,~~June 30, 2012, approximately ~~37%~~26% of the defined benefit pension plan assets were comprised of investments in equity securities and ~~63%~~74% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. We use an investment adviser to assist in managing our investment portfolio. The market value of the equity securities was approximately ~~$128.3~~$91.1 million at ~~March 31,~~June 30, 2012. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$12.8~~$9.1 million reduction in fair value as of ~~March 31,~~June 30, 2012.

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; the valuation of derivative instruments; the valuation of insurance and claims liabilities; the valuation of allowances for receivables and deferred income taxes; regulatory assets and liabilities; reserves recorded for income tax exposures; litigation; contingencies; the valuation of AROs; and assets and liabilities related to employee benefits. Refer to our Form 10-K for the fiscal year ended December 31, 2011 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

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ELECTRIC SALES AND REVENUES

DPL

DP&L (a)

DPLER (b)

Three Months Ended

Three Months Ended

Three Months Ended

March 31,

March 31,

March 31,

2012

2011

2012

2011

2012

2011

Successor

Predecessor

Electric sales (millions of kWh)

Residential

1,324

1,544

1,322

1,544

112

—

Commercial

931

932

699

831

640

513

Industrial

828

829

780

807

799

717

Other retail

330

342

323

339

195

241

Total retail

3,413

3,647

3,124

3,521

1,746

1,471

Wholesale

344

606

401

654

—

—

Total

3,757

4,253

3,525

4,175

1,746

1,471

Operating revenues ($ in thousands)

Residential

$
171,162

$
185,515

$
163,431

$
185,501

$
7,732

$
14

Commercial

87,373

92,014

45,424

56,932

41,949

35,082

Industrial

61,550

61,850

16,130

17,942

45,420

43,907

Other retail

26,398

27,512

14,876

13,245

12,428

15,233

Other miscellaneous revenues

2,775

2,572

2,853

2,690

85

32

Total retail

349,258

369,463

242,714

276,310

107,614

94,268

Wholesale

22,379

32,429

104,455

106,166

1

(739
)

RTO revenues

55,093

76,680

48,715

67,246

498

488

Other revenues

7,294

2,022

3,678

39

3,987

6

Total

$
434,024

$
480,594

$
399,562

$
449,761

$
112,100

$
94,023

Electric customers at end of period

Residential

455,977

456,074

455,243

456,074

27,070

32

Commercial

54,342

52,727

50,169

50,124

15,659

10,275

Industrial

1,905

1,928

1,749

1,762

786

719

Other

6,943

6,865

6,811

6,744

2,763

1,621

Total

519,167

517,594

513,972

514,704

46,278

12,647

DPL

DP&L (a)

DPLER (b)(c)

Three Months Ended

June 30,

2012

2011

2012

2011

2012

2011

Successor

Predecessor

Electric sales (millions of kWh)

3,494

3,861

3,202

3,638

1,871

1,669

Billed electric customers (end of period)

532,502

516,290

512,691

513,123

69,968

15,200

DPL

DP&L (a)

DPLER (b)(c)

Six Months Ended

June 30,

2012

2011

2012

2011

2012

2011

Successor

Predecessor

Electric sales (millions of kWh)

7,251

8,114

6,727

7,812

3,617

3,141

Billed electric customers (end of period)

532,502

516,290

512,691

513,123

69,968

15,200

(a) This chart contains electric sales from DP&L’s generation and purchased power. DP&L sold ~~1,457~~1,540 million kWh and ~~1,344~~1,419 million kWh of power to DPLER ~~(a subsidiary of~~ ~~DPL~~) during the three months ~~ending March 31,~~ended June 30, 2012 and 2011, respectively ~~which are not included in~~ ~~DP&L~~ ~~wholesale sales volumes in the chart above. These~~and 2,997 million 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~~2,763 million kWh 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~~~~. DP&L~~ ~~did not sell any~~ power to ~~MC Squared~~DPLER during ~~either of these periods.~~the six months ended June 30, 2012 and 2011, respectively.

(b) This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.

(c) Does not include approximately 29,000 customers recently enrolled by MC Squared under various governmental aggregation agreements at June 30, 2012 that have not yet been physically billed.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

See the “MARKET RISK” section in Item 2 of this Part I.I, which is incorporated by reference into this item.

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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 quarter ended ~~March 31,~~June 30, 2012 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 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 Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements, cannot be reasonably determined.

Our Form 10-K for the fiscal year ended December 31, 2011, and the Notes to the Condensed Consolidated Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Form 10-K, and should be read in conjunction with the Form 10-K.

The following information is incorporated by reference into this Item: (i) information about DP&L’s March 30, 2012 MRO filing with the PUCO in Item 2 to Part I of this Quarterly Report on Form ~~10-Q~~10-Q; and (ii) information about the legal proceedings contained in Part I, Item 1 — Note 13 of Notes to DPL’s Condensed Consolidated Financial Statements of this Quarterly Report on Form 10-Q.

Item 1A — Risk Factors

A listing of the risk factors that we consider to be the most significant to a decision to invest in our securities is provided in our Form 10-K for the fiscal year ended December 31, 2011. The information in this Item 1A to Part II of our Quarterly Report on Form 10-Q updates and restates one of the risk factors included in the Form 10-K. Otherwise, there have been no material changes with respect to the risk factors disclosed in our form 10-K. If any of the events described in our risk factors occur, it could have a material effect on our results of operations, financial condition and cash flows.

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The risks and uncertainties described in our risk factors are not the only ones we face. In addition, new risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. Our risk factors should be read in conjunction with the other detailed information concerning DPL and DP&L set forth in the Notes to DPL’s and DP&L’s Financial Statements and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections included in our filings.

The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Ohio and the rules, policies and procedures of the PUCO. On May 1, 2008, SB 221, an Ohio electric energy bill, was signed by the Governor of Ohio and became effective July 31, 2008. This law, among other things, requires all Ohio distribution utilities at certain times to file an SSO either in the form of an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the utility’s earnings to the earnings of other companies with similar business and financial risks. The PUCO approved DP&L’s initial ESP on June 24, 2009. DP&L’s ESP provides, among other things, that DP&L’s existing rate plan structure will continue through the end of 2012; that DP&L may seek recovery for adjustments to its existing rate plan structure for costs associated with storm damage, regulatory and tax changes, new climate change or carbon regulations, fuel and purchased power and certain other costs; and that SB 221’s significantly excessive earnings test will apply in 2013 based upon DP&L’s 2012 earnings. On March 30, 2012, DP&L filed an MRO to establish a new rate plan and recovery structure that will phase in market-based rates over the time period January 2013 through May 2018. As filed, DP&L’s proposed MRO is expected to provide an initial rate decrease for customers and result in decreases to DP&L’s revenues that could adversely affect our results of operations, financial condition and cash flows. DP&L faces regulatory uncertainty from this MRO filing. The PUCO could accept, reject or seek to modify DP&L’s proposed MRO and/or require DP&L to propose another SSO. A new or revised SSO could result in changes to DP&L’s rate plan and recovery structure that could further adversely affect our results of operations, cash flows and financial condition. DP&L’s proposed MRO and current ESP and certain filings made by us in connection with this plan are further discussed in our periodic reports. In addition, as the local distribution utility, DP&L has an obligation to serve customers within its certified territory and under the terms of its current ESP, as it is the provider of last resort (POLR) for standard offer service. DP&L’s current rate structure provides for a nonbypassable charge to compensate DP&L for this ~~POLR~~ obligation. The PUCO may decrease or discontinue this rate charge in connection with DP&L’s SSO filing or at some other time in the future.

While rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCO will agree that all of our costs have been prudently incurred or are recoverable or that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and permitted rates of return. Certain of our cost recovery riders are also bypassable by some of our customers who switched to a CRES provider. Accordingly, the revenue DP&L receives may or may not match its expenses at any given time. Therefore, DP&L could be subject to prevailing market prices for electricity and would not necessarily be able to charge rates that produce timely or full recovery of its expenses. Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return and POLR service; changes in DP&L’s rate structure and its ability to recover amounts for environmental compliance, POLR obligations, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), customer switching, capital expenditures and investments and other costs on a full or timely basis through rates; and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

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

None

Item 3 — Defaults Upon Senior Securities

None

Item 4 — Mine Safety Disclosures

Not applicable.

Item 5 — Other Information

None

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Item 6 — Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location

X		31(a)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(a)
X		31(b)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(b)
	X	31(c)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(c)
	X	31(d)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 31(d)
X		32(a)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(a)
X		32(b)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(b)
	X	32(c)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(c)
	X	32(d)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith as Exhibit 32(d)

~~111~~125

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DPL Inc.	DP&L	Exhibit Number	Exhibit	Location

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

Exhibits referencing File No. 1-9052 have been filed by DPL Inc. and those referencing File No. 1-2385 have been filed by The Dayton Power and Light Company.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, we have not filed as an exhibit to this form

10-Q certain instruments with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of us and our subsidiaries on a consolidated basis, but we hereby agree to furnish to the SEC on request any such instruments.

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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:	~~May~~August 3, 2012	/s/ Philip Herrington
		Philip Herrington President and Chief Executive Officer (principal executive officer)


	~~May~~August 3, 2012	/s/ ~~Joseph W. Mulpas~~Craig Jackson
		~~Joseph W. Mulpas~~Craig Jackson Senior Vice President ~~Controller, Chief Accounting Officer~~ and ~~Interim~~ Chief Financial Officer ~~(principal accounting officer and~~ (principal financial officer)


	August 3, 2012	/s/ Gregory S. Campbell
		Gregory S. Campbell Vice President and Controller (principal accounting officer)

~~113~~127

DP&L

	For the Three Months
	Ended March 31,
$ in millions	2012			2011

Net cash provided by operating activities	$	89.6		$	84.0
Net cash used for investing activities	(53.2		)	(40.4		)
Net cash used for financing activities	(45.2		)	(40.2		)

Net change	(8.8		)	3.4
Cash and cash equivalents at beginning of period	32.2			54.0
Cash and cash equivalents at end of period	$	23.4		$	57.4

NYMEX Coal Forwards	Contract Volume (in millions of Tons)	Weighted Average Market Price (per Ton)		Increase / Decrease in Net Income (in millions) (a)
2012-Purchase	0.9	$	61.02	$	1.9
2013-Purchase	0.5	$	69.94	$	1.1
2014-Purchase	—	$	—	$	—

	PJM Delivery Year
	2010/11		2011/12		2012/13		2013/14		2014/15

Capacity clearing price ($/MW-day)	$	174	$	110	$	16	$	28	$	126

	Calendar Year
	2010		2011		2012		2013		2014

Computed average capacity price ($/MW-day)	$	144	$	137	$	55	$	23	$	85

	DPL				DP&L (a)				DPLER (b)
	Three Months Ended				Three Months Ended				Three Months Ended
	March 31,				March 31,				March 31,
	2012		2011		2012		2011		2012		2011
	Successor		Predecessor
Electric sales (millions of kWh)
Residential	1,324		1,544		1,322		1,544		112		—
Commercial	931		932		699		831		640		513
Industrial	828		829		780		807		799		717
Other retail	330		342		323		339		195		241
Total retail	3,413		3,647		3,124		3,521		1,746		1,471

Wholesale	344		606		401		654		—		—

Total	3,757		4,253		3,525		4,175		1,746		1,471

Operating revenues ($ in thousands)
Residential	$	171,162	$	185,515	$	163,431	$	185,501	$	7,732	$	14
Commercial	87,373		92,014		45,424		56,932		41,949		35,082
Industrial	61,550		61,850		16,130		17,942		45,420		43,907
Other retail	26,398		27,512		14,876		13,245		12,428		15,233
Other miscellaneous revenues	2,775		2,572		2,853		2,690		85		32
Total retail	349,258		369,463		242,714		276,310		107,614		94,268

Wholesale	22,379		32,429		104,455		106,166		1		(739		)

RTO revenues	55,093		76,680		48,715		67,246		498		488

Other revenues	7,294		2,022		3,678		39		3,987		6

Total	$	434,024	$	480,594	$	399,562	$	449,761	$	112,100	$	94,023

Electric customers at end of period
Residential	455,977		456,074		455,243		456,074		27,070		32
Commercial	54,342		52,727		50,169		50,124		15,659		10,275
Industrial	1,905		1,928		1,749		1,762		786		719
Other	6,943		6,865		6,811		6,744		2,763		1,621

Total	519,167		517,594		513,972		514,704		46,278		12,647