UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

~~For the quarterly period ended~~ ~~June 30, 2011~~

OR

For the quarterly period ended March 31, 2012

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

For the transition period from to

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

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

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

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

DPL Inc.		Yes xo		No ox
The Dayton Power and Light Company		Yes xo		No ox

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.	x	o	o	ox	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 ~~July 25, 2011,~~March 31, 2012, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, ~~$0.01~~no par value	~~117,712,910~~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			34

Part I Financial Information

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

~~Item 1~~	~~Financial Statements —~~ ~~DPL~~ ~~and~~ ~~DP&L~~ ~~(Unaudited)~~	DPL Inc.

		Condensed Consolidated Statements of Results of Operations — ~~DPL~~		710

		Condensed Consolidated Statements of ~~Cash Flows —~~ ~~DPL~~Comprehensive Income (Loss)		8

	~~Condensed Consolidated Balance Sheets —~~ ~~DPL~~		9

	~~Condensed Statements of Results of Operations —~~ ~~DP&L~~		11

		Condensed Consolidated Statements of Cash Flows — ~~DP&L~~		12

		Condensed Consolidated Balance Sheets — ~~DP&L~~		13

		Notes to Condensed Consolidated Financial Statements		15

		The Dayton Power and Light Company

		Condensed Statements of Results of Operations	47

		Condensed Statements of Comprehensive Income (Loss)	48

		Condensed Statements of Cash Flows	49

		Condensed Balance Sheets	50

		Notes to Condensed Financial Statements	52

	Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	77
	65
		Electric Sales and Revenues	107

	~~Electric Sales and Revenues~~		98

Item 3	Quantitative and Qualitative Disclosures about Market Risk		99107

	Item 4	Controls and Procedures		~~100~~108

Part II Other Information

	Item 1	Legal Proceedings	108

	Item 11A	~~Legal Proceedings~~Risk Factors		~~100~~108

~~Item 1a~~	~~Risk Factors~~		~~101~~

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		~~103~~110

	Item 3	Defaults Upon Senior Securities		~~103~~110

	Item 4	~~Removed and Reserved~~Mine Safety Disclosures	110

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DPL Inc. and The Dayton Power and Light Company

Index (cont.)

	~~103~~Item 5	Other Information	110

~~Item 5~~	~~Other Information~~		~~103~~

Item 6	Exhibits		~~104~~111

Other

	Signatures			~~106~~113

	Certifications		~~108~~

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

~~BTU~~		~~British Thermal Units~~

CFTC		Commodity Futures Trading Commission

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CSAPR		~~Cross State~~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.~~, the parent company~~

DPLE		DPL Energy, LLC, a ~~wholly-owned~~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~~wholly owned subsidiary of DPL ~~that~~ which sells ~~retail~~competitive electric energy and other energy services

DP&L		The Dayton Power and Light Company, the principal subsidiary of DPL and a public utility ~~that~~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~~2009.

~~ESOP~~		~~Employee Stock Ownership Plan~~

~~ESP~~		~~Electric Security Plans, filed with the PUCO pursuant to Ohio law~~

FASB		Financial Accounting Standards Board

FASC		FASB Accounting Standards Codification

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

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

~~LOC~~		~~Letter of Credit~~

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

~~Table of Contents~~

~~GLOSSARY OF TERMS (cont.)~~

~~Abbreviation or Acronym~~
Merger		The merger of ~~Definition~~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~~agreement		The Agreement and Plan of Merger dated April 19, 2011 among DPL ~~and,~~, The AES Corporation ~~a Delaware corporation~~ (“AES”), and Dolphin ~~sub,~~Sub, Inc., a wholly owned subsidiary of AES, whereby AES ~~will~~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 ~~will become~~became a ~~wholly-owned~~wholly owned subsidiary of ~~AES~~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~~wholly owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries

~~MWh~~		~~Megawatt hours~~ 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

~~OCC~~		~~Ohio Consumers’ Counsel~~

~~ODT~~		~~Ohio Department of Taxation~~

Ohio EPA		Ohio Environmental Protection Agency

OTC		Over-The-Counter

OVEC		Ohio Valley Electric Corporation, an electric generating company in which DP&L holds a 4.9% equity interest

PJM		PJM Interconnection, ~~L.L.C.,~~LLC, a regional transmission organization

~~Proposed Merger~~Predecessor		~~The proposed merger involving~~DPL prior to November 28, 2011, the date AES acquired DPL ~~and AES as contemplated by the Merger Agreement~~

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 ~~electric security plan~~ESP or ~~a market rate option~~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~~standards.

SCR		Selective Catalytic Reduction

SEC		Securities and Exchange Commission

SECA		Seams Elimination Charge Adjustment

SERP		Supplemental Executive Retirement Plan

~~SFAS~~SO2		~~Statement of Financial Accounting Standards~~Sulfur Dioxide

SO23		Sulfur ~~Dioxide~~

~~Table of Contents~~

~~GLOSSARY OF TERMS (cont.)~~

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

SSO		Standard Service Offer which represents the regulated rates, authorized by the PUCO, charged to DP&Lretail 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 ~~file current, annual and quarterly reports, proxy statements (~~.On November 28, 2011, DPL ~~only)~~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 ~~required~~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 ~~Securities Exchange Act~~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 ~~1934, as amended,~~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.

~~Our~~COMPANY WEBSITES

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

~~In addition, our~~DP&L’s public internet site includes other items related to corporate governance matters, including, among other things, our governance guidelines, charters of various committees of the Board of Directors and our code of business conduct and ethics applicable to all employees, officers and directors. You may obtain copies ofis http://www.dpandl.com. The information on these ~~documents, free of charge,~~websites is not incorporated by ~~sending a request, in writing, to DPL Investor Relations, 1065 Woodman Drive, Dayton, Ohio 45432.~~

~~Forward-looking Statements:~~ Certain statements contained in this report are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Please see Item 2 of Part I, Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information about forward-looking statements contained inreference into this report.

Table of Contents

Part 1I — Financial Information

This report includes the combined filing of DPL and DP&L. ~~DP&L~~ ~~is the principal subsidiary of~~ ~~DPL~~ ~~providing approximately 90% of~~ ~~DPL’s~~ ~~total consolidated gross margin and approximately 93% of~~ ~~DPL’s~~ ~~total consolidated asset base.~~ Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both DPL and DP&L, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to DPL or DP&L will clearly be noted in the section.

6Item 1 — Financial Statements

Table of Contents

~~Item 1 — Financial Statements~~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
$ in millions except per share amounts	2011			2010			2011			2010			Successor			Predecessor

Revenues	$	444.9		$	445.5		$	939.6		$	896.7		$	434.0		$	480.6

Cost of revenues:
Fuel	92.1			90.9			191.9			192.8			97.4			99.7
Purchased power	113.6			90.9			234.4			163.7			94.8			120.8
Amortization of intangibles													27.8			—
Total cost of revenues	205.7			181.8			426.3			356.5			220.0			220.5

Gross margin	239.2			263.7			513.3			540.2			214.0			260.1

Operating expenses:
Operation and maintenance	106.8			87.5			206.2			168.1			101.7			99.3
Depreciation and amortization	35.1			35.7			70.2			73.1			31.4			35.1
General taxes	31.5			31.2			70.3			63.7			21.7			24.8
Total operating expenses	173.4			154.4			346.7			304.9			154.8			159.2

Operating income	65.8			109.3			166.6			235.3			59.2			100.9

Other income / (expense), net:
Investment income	0.1			0.2			0.2			0.3			0.1			0.1
Interest expense	(17.6		)	(17.5		)	(34.5		)	(35.4		)	(29.6		)	(16.9		)
Charge for early redemption of debt	—			—			(15.3		)	—			—			(15.3		)
Other expense	(0.3		)	(0.5		)	(0.7		)	(1.3		)
Other income / (deductions)													(0.3		)	(0.5		)
Total other income / (expense), net	(17.8		)	(17.8		)	(50.3		)	(36.4		)	(29.8		)	(32.6		)

Earnings before income tax	48.0			91.5			116.3			198.9			29.4			68.3

Income tax expense	16.3			30.1			41.1			66.5			7.7			24.8
Net income	$	31.7		$	61.4		$	75.2		$	132.4		$	21.7		$	43.5

Average number of common shares outstanding (millions):
Basic	114.2			115.7			114.1			115.6			N/A			114.0
Diluted	114.9			116.2			114.7			116.2			N/A			114.5

Earnings per share of common stock:
Basic	$	0.28		$	0.53		$	0.66		$	1.15		N/A			$	0.38
Diluted	$	0.28		$	0.53		$	0.66		$	1.14		N/A			$	0.38

Dividends paid per share of common stock	$	0.3325		$	0.3025		$	0.6650		$	0.6050		N/A			$	0.3325

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

710

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DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

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

Net income (loss)	$	21.7		$	43.5

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			—

Total change in fair value of available-for-sale securities	0.4			—

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		)

Total change in fair value of derivatives	6.7			1.2

Pension and postretirement activity:
Reclassification to earnings, net of income tax expense of $(0.0) and $0.4, respectively	—			1.2

Total change in unfunded pension obligation	—			1.2

Other comprehensive income / (loss)	7.1			2.4

Net comprehensive income / (loss)	$	28.8		$	45.9

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
$ in millions	2011			2010			Successor			Predecessor
Cash flows from operating activities:
Net income	$	75.2		$	132.4		$	21.7		$	43.5
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	70.2			73.1			31.4			35.1
Amortization of other assets							27.8			—
Amortization of debt market value adjustments							(4.7		)
Deferred income taxes	37.5			6.4			(9.2		)	33.7
Unamortized investment tax credit	(1.4		)	(1.4		)
Charge for early redemption of debt	15.3			—			—			15.3
Changes in certain assets and liabilities:
Accounts receivable	19.5			4.7			(3.4		)	11.9
Inventories	(0.3		)	(1.8		)	(0.6		)	1.3
Prepaid taxes	(20.7		)	(1.0		)
Taxes applicable to subsequent years	31.8			29.5			22.9			15.9
Deferred regulatory costs, net	8.9			4.1			7.2			12.8
Accounts payable	(5.9		)	8.7			(1.8		)	(5.1		)
Accrued taxes payable	(33.4		)	(36.4		)	(21.6		)	(28.4		)
Accrued interest payable	2.0			0.2			29.1			(1.2		)
Pension, retiree and other benefits	(42.7		)	(23.0		)	2.1			(41.2		)
Unamortized investment tax credit							—			(0.7		)
Insurance and claims costs	3.7			(1.5		)	0.8			2.2
Other	25.4			10.9			(7.1		)	(3.1		)
Net cash provided by operating activities	185.1			204.9			94.6			92.0

Cash flows from investing activities:
Capital expenditures	(91.4		)	(75.1		)	(54.0		)	(43.0		)
Purchase of MC Squared	(8.2		)	—			—			(8.2		)
Purchases of short-term investments and securities	(1.7		)	(61.2		)	—			(1.7		)
Sales of short-term investments and securities	70.9			14.2			—			60.8
Other	1.8			1.9
Net cash used for investing activities	(28.6		)	(120.2		)
Other investing activities, net							—			2.1
Net cash (used for) / provided by investing activities							(54.0		)	10.0

Cash flows from financing activities:
Dividends paid on common stock	(76.4		)	(69.9		)	(45.0		)	(37.8		)
Early redemption of Capital Trust II debt	(122.0		)	—
Contributions to additional paid-in capital from parent							2.0			—
Payment to former warrant holders							(9.0		)	—
Early redemption of Capital Trust II notes							—			(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
Repayments of borrowings from revolving credit facilities	(50.0		)	—
Repurchase of DPL common stock	—			(3.9		)
Exercise of stock options	1.4			1.4
Exercise of warrants	14.7			—
Tax impact related to exercise of stock options	0.3			0.2
Net cash used for financing activities	(207.7		)	(72.2		)
Repayment of borrowing from revolving credit facilities							—			(20.0		)
Net cash (used for) / provided by financing activities							(52.0		)	(155.5		)

Cash and cash equivalents:
Net change	(51.2		)	12.5			(11.4		)	(53.5		)
Balance at beginning of period	124.0			74.9			173.5			124.0
Cash and cash equivalents at end of period	$	72.8		$	87.4		$	162.1		$	70.5

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	30.3		$	35.7		$	5.7		$	18.1
Income taxes paid, net	$	24.7		$	53.2		$	7.0		$	—
Non-cash financing and investing activities:
Accruals for capital expenditures	$	22.6		$	11.3		$	24.1		$	18.3
Long-term liability incurred for purchase of assets	$	18.7		$	—
Long-term liability incurred for purchase of plant assets							$	—		$	18.7

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

812

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DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

March 31,

December 31,

June 30,

December 31,

2012

2011

$ in millions

2011

2010

Successor

ASSETS

Current assets:

Cash and cash equivalents

72.8

124.0

162.1

173.5

Short-term investments

—

69.3

Accounts receivable, net (Note 2)

201.8

215.5

Inventories (Note 2)

115.6

115.3

Accounts receivable, net (Note 3)

224.4

219.1

Inventories (Note 3)

126.4

125.8

Taxes applicable to subsequent years

31.8

63.7

53.6

76.5

Regulatory assets, current (Note 4)

15.2

20.2

Other prepayments and current assets

69.4

40.6

37.5

36.2

Total current assets

491.4

628.4

619.2

651.3

Property, plant and equipment:

Property, plant and equipment

5,482.6

5,353.6

2,482.3

2,431.0

Less: Accumulated depreciation and amortization

(2,629.3

)

(2,555.2

)

(41.1

)

(7.5

)

2,853.3

2,798.4

2,441.2

2,423.5

Construction work in process

112.3

119.7

151.1

152.3

Total net property, plant and equipment

2,965.6

2,918.1

2,592.3

2,575.8

Other noncurrent assets:

Regulatory assets (Note 3)

178.8

189.0

Regulatory assets, non-current (Note 4)

172.9

177.8

Goodwill

2,489.3

2,489.3

Intangible assets, net of amortization

133.8

161.5

Other deferred assets

75.8

77.8

49.3

51.8

Total other noncurrent assets

254.6

266.8

2,845.3

2,880.4

Total Assets

3,711.6

3,813.3

6,056.8

6,107.5

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

913

Table of Contents

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

At

At

June 30,

December 31,

$ in millions

2011

2010

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:

Current portion - long-term debt (Note 5)

$
297.8

$
297.5

Accounts payable

94.6

98.7

Accrued taxes

70.9

68.1

Accrued interest

20.6

18.4

Customer security deposits

17.9

18.7

Other current liabilities

55.6

40.9

Total current liabilities

557.4

542.3

Noncurrent liabilities:

Long-term debt (Note 5)

923.6

1,026.6

Deferred taxes (Note 6)

660.6

625.4

Regulatory liabilities (Note 3)

129.4

124.0

Pension, retiree and other benefits

27.6

64.9

Unamortized investment tax credit

31.0

32.4

Insurance and claims costs

13.7

10.1

Other deferred credits

110.9

146.2

Total noncurrent liabilities

1,896.8

2,029.6

Redeemable preferred stock of subsidiary

22.9

22.9

Commitments and contingencies (Note 14)

Common shareholders’ equity:

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

June 2011

December 2010

Shares authorized

250,000,000

250,000,000

Shares issued

163,724,211

163,724,211

Shares outstanding

117,712,910

116,924,844

1.2

1.2

Warrants

1.6

2.7

Common stock held by employee plans

(8.1
)
(12.5
)
Accumulated other comprehensive loss

(26.1
)
(18.9
)
Retained earnings

1,265.9

1,246.0

Total common shareholders’ equity

1,234.5

1,218.5

Total Liabilities and Shareholders’ Equity

$
3,711.6

$
3,813.3

~~See Notes to Condensed Consolidated Financial Statements.~~

~~These interim statements are unaudited.~~

~~Table of Contents~~

~~THE DAYTON POWER AND LIGHT COMPANY~~

~~CONDENSED STATEMENTS OF RESULTS OF OPERATIONS~~

Three Months Ended

Six Months Ended

June 30,

June 30,

$ in millions

2011

2010

2011

2010

Revenues

$
408.6

$
423.9

$
872.4

$
861.9

Cost of revenues:

Fuel

89.1

88.5

187.7

189.1

Purchased power

104.4

90.3

222.2

162.9

Total cost of revenues

193.5

178.8

409.9

352.0

Gross margin

215.1

245.1

462.5

509.9

Operating expenses:

Operation and maintenance

95.1

85.4

186.5

164.7

Depreciation and amortization

33.4

33.2

66.5

68.0

General taxes

30.8

29.5

64.4

61.8

Total operating expenses

159.3

148.1

317.4

294.5

Operating income

55.8

97.0

145.1

215.4

Other income / (expense), net:

Investment income

0.5

0.4

1.1

0.9

Interest expense

(9.7
)
(9.1
)
(19.4
)
(18.5
)
Other expense

(0.3
)
(0.5
)
(0.8
)
(1.1
)
Total other income / (expense), net

(9.5
)
(9.2
)
(19.1
)
(18.7
)

Earnings before income tax

46.3

87.8

126.0

196.7

Income tax expense

15.5

28.4

42.5

65.2

Net income

30.8

59.4

83.5

131.5

Dividends on preferred stock

0.2

0.2

0.4

0.4

Earnings on common stock

$
30.6

$
59.2

$
83.1

$
131.1

~~See Notes to Condensed Consolidated Financial Statements.~~

~~These interim statements are unaudited.~~

~~Table of Contents~~

~~THE DAYTON POWER AND LIGHT COMPANY~~

~~CONDENSED STATEMENTS OF CASH FLOWS~~

Six Months Ended

June 30,

$ in millions

2011

2010

Cash flows from operating activities:

Net income

$
83.5

$
131.5

Adjustments to reconcile Net income to Net cash provided by operating activities:

Depreciation and amortization

66.5

68.0

Deferred income taxes

37.2

5.8

Unamortized investment tax credit

(1.4
)
(1.4
)
Changes in certain assets and liabilities:

Accounts receivable

25.5

19.9

Inventories

—

(2.0
)
Prepaid taxes

(19.2
)
(1.0
)
Taxes applicable to subsequent years

31.4

29.4

Deferred regulatory costs, net

8.9

4.1

Accounts payable

(7.8
)
7.4

Accrued taxes payable

(32.3
)
(37.6
)
Accrued interest payable

5.3

(0.1
)
Pension, retiree and other benefits

(42.7
)
(23.0
)
Other

8.3

4.1

Net cash provided by operating activities

163.2

205.1

Cash flows from investing activities:

Capital expenditures

(90.8
)
(73.5
)
Other

1.7

1.9

Net cash used for investing activities

(89.1
)
(71.6
)

Cash flows from financing activities:

Dividends paid on common stock to parent

(115.0
)
(150.0
)
Dividends paid on preferred stock

(0.4
)
(0.4
)
Withdrawals from revolving credit facilities

50.0

—

Repayments of borrowings from revolving credit facilities

(50.0
)
—

Net cash used for financing activities

(115.4
)
(150.4
)

Cash and cash equivalents:

Net change

(41.3
)
(16.9
)
Balance at beginning of period

54.0

57.1

Cash and cash equivalents at end of period

$
12.7

$
40.2

Supplemental cash flow information:

Interest paid, net of amounts capitalized

$
14.6

$
19.7

Income taxes paid, net

$
24.1

$
53.1

Non-cash financing and investing activities:

Accruals for capital expenditures

$
22.6

$
11.3

Long-term liability incurred for the purchase of assets

$
18.7

$
—

~~See Notes to Condensed Consolidated Financial Statements.~~

~~These interim statements are unaudited.~~

~~Table of Contents~~

~~THE DAYTON POWER AND LIGHT COMPANY~~

~~CONDENSED BALANCE SHEETS~~

At

At

June 30,

December 31,

$ in millions

2011

2010

ASSETS

Current assets:

Cash and cash equivalents

$
12.7

$
54.0

Accounts receivable, net (Note 2)

150.4

178.0

Inventories (Note 2)

114.1

114.2

Taxes applicable to subsequent years

31.4

62.8

Other prepayments and current assets

60.6

42.7

Total current assets

369.2

451.7

Property, plant and equipment:

Property, plant and equipment

5,218.0

5,093.7

Less: Accumulated depreciation and amortization

(2,523.7
)
(2,453.1
)

2,694.3

2,640.6

Construction work in process

112.7

119.6

Total net property, plant and equipment

2,807.0

2,760.2

Other noncurrent assets:

Regulatory assets (Note 3)

178.8

189.0

Other assets

80.0

74.5

Total other noncurrent assets

258.8

263.5

Total Assets

$
3,435.0

$
3,475.4

~~See Notes to Condensed Consolidated Financial Statements.~~

~~These interim statements are unaudited.~~

~~Table of Contents~~

~~THE DAYTON POWER AND LIGHT COMPANY~~

~~CONDENSED BALANCE SHEETS~~

At

At

June 30,

December 31,

$ in millions

2011

2010

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:

Current portion - long-term debt (Note 5)

$
0.4

$
0.1

Accounts payable

87.0

95.7

Accrued taxes

70.3

66.6

Accrued interest

13.3

7.7

Customer security deposits

17.8

18.7

Other current liabilities

33.8

33.6

Total current liabilities

222.6

222.4

Noncurrent liabilities:

Long-term debt (Note 5)

903.0

884.0

Deferred taxes (Note 6)

636.5

598.0

Regulatory liabilities (Note 3)

129.4

124.0

Pension, retiree and other benefits

27.6

64.9

Unamortized investment tax credit

31.0

32.4

Other deferred credits

111.0

147.3

Total noncurrent liabilities

1,838.5

1,850.6

Redeemable preferred stock

22.9

22.9

Commitments and contingencies (Note 14)

Common shareholder’s equity:

Common stock, at par value of $0.01 per share

0.4

0.4

Other paid-in capital

782.6

782.4

Accumulated other comprehensive loss

(17.0
)
(20.2
)
Retained earnings

585.0

616.9

Total common shareholder’s equity

1,351.0

1,379.5

Total Liabilities and Shareholder’s Equity

$
3,435.0

$
3,475.4

~~See Notes to Condensed Consolidated Financial Statements.~~

~~These interim statements are unaudited.~~

			At			At
			March 31,			December 31,
			2012			2011
$ in millions			Successor
LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:
Current portion - long-term debt (Note 6)			$	0.4		$	0.4
Accounts payable			103.3			111.1
Accrued taxes			94.7			76.3
Accrued interest			59.5			30.2
Customer security deposits			16.4			15.9
Regulatory liabilities, current (Note 4)			—			0.6
Insurance and claims costs			15.0			14.2
Other current liabilities			48.7			56.1
Total current liabilities			338.0			304.8

Noncurrent liabilities:
Long-term debt (Note 6)			2,624.1			2,628.9
Deferred taxes (Note 7)			543.1			549.4
Regulatory liabilities, non-current (Note 4)			118.5			118.6
Pension, retiree and other benefits			47.7			47.5
Unamortized investment tax credit			3.7			3.6
Other deferred credits			146.8			205.6
Total noncurrent liabilities			3,483.9			3,553.6

Redeemable preferred stock of subsidiary			18.4			18.4

Commitments and contingencies (Note 13)

Common shareholder’s equity:
Common stock:	Successor
	No par value
	March 31, 2012	December 31, 2011
Shares authorized	1,500	1,500
Shares issued	1	1
Shares outstanding	1	1	—			—
Other paid-in capital			2,239.3			2,237.3
Accumulated other comprehensive income / (loss)			6.7			(0.4		)
Retained earnings / (deficit)			(29.5		)	(6.2		)
Total common shareholder’s equity			2,216.5			2,230.7
Total Liabilities and Shareholder’s Equity			$	6,056.8		$	6,107.5

See Notes to Condensed Consolidated Financial Statements.
These interim statements are unaudited.

Table of Contents

Notes to Condensed Consolidated Financial Statements (Unaudited)

~~This report includes the combined filing of~~ ~~DPL~~ ~~and~~ ~~DP&L~~. ~~DP&L~~ ~~is the principal subsidiary of~~ ~~DPL~~ ~~providing approximately 90% of~~ ~~DPL’s~~ ~~total consolidated gross margin and approximately 93% of~~ ~~DPL’s~~ ~~total consolidated asset base. Throughout this report, the terms “we,” “us,” “our” and “ours” are used to refer to both~~ ~~DPL~~ ~~and~~ ~~DP&L~~~~, respectively and altogether, unless the context indicates otherwise. Discussions or areas of this report that apply only to~~ ~~DPL~~ or ~~DP&L~~ ~~will clearly be noted in the section.~~

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

1. Overview and Summary of Significant Accounting Policies

Description of Business

DPL is a diversified regional energy company organized in 1985 under the laws of Ohio. DPL’s two reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER ~~subsidiary.~~operations, which include the operations of DPLER’s wholly owned subsidiary MC Squared. Refer to Note ~~15 of Notes to Condensed Consolidated Financial Statements~~14 for more information relating to these reportable segments.

On November 28, 2011, ~~DP&L~~DPL was acquired by AES in the Merger and DPL ~~does not have any reportable segments.~~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 ~~the~~ sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for DP&L’s 24 county service area is primarily generated at eight coal-fired power plants and is distributed to more than 500,000 retail customers. Principal industries served include automotive, food processing, paper, plastic manufacturing and defense.

DP&L’s sales reflect the general economic conditions ~~customers switching to other retail electric suppliers~~ 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~~wholly owned subsidiary, MC Squared, which was ~~purchased~~acquired on February 28, 2011. DPLER has ~~approximately 15,000~~more than 45,000 customers currently located throughout Ohio and Illinois. DPLER does not ~~have~~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.

DPL’s other significant subsidiaries include DPLE, which owns and operates peaking generating facilities from which it makes wholesale sales of electricity and MVIC, ~~DPL’s~~our captive insurance company that provides insurance services to us and our subsidiaries. All of DPL’s ~~subsidiaries.~~subsidiaries are wholly owned.

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

~~All of~~ ~~DPL’s~~ ~~subsidiaries are wholly-owned.~~ ~~DP&L~~ ~~does not have any subsidiaries.~~

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 ~~1,535~~1,494 people as of ~~June 30, 2011,~~March 31, 2012, of which ~~1,503~~1,450 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires inon October ~~2011.~~31, 2014.

Financial Statement Presentation

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

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

~~Table~~Certain excise taxes collected from customers have been reclassified out of ~~Contents~~

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.

~~Deferred SECA revenue~~15

Table of $15.4 million at December 31, 2010 was reclassified from Regulatory liabilities to Other deferred credits. The balance of deferred SECA revenue at June 30, 2011 and December 31, 2010 was $14.1 million and $15.4 million, respectively. The FERC-approved SECA billings are unearned revenue where the earnings process is not complete and do not represent a potential overpayment by retail ratepayers or potential refunds of costs that had been previously charged to retail ratepayers through rates. Therefore, any amounts that are ultimately collected related to these charges would not be a reduction to future rates charged to retail ratepayers and therefore do not meet the criteria for recording as a regulatory liability under GAAP. Refer to Note 14 of Notes to Condensed Consolidated Financial Statements for more information relating to SECA.Contents

All material intercompany accounts and transactions are eliminated in consolidation.

These financial statements have been prepared in accordance with GAAP for interim financial statements and with the instructions of Form 10-Q and Regulation S-X. Accordingly, certain information and footnote disclosures normally included in the annual financial statements prepared in accordance with GAAP have been omitted from this interim report. Therefore, our interim financial statements in this report should be read along with the annual financial statements included in our ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, ~~2010.~~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 ~~June 30, 2011;~~March 31, 2012; our results of operations for the three ~~and six~~ months ended ~~June 30, 2011;~~March 31, 2012 and our cash flows for the ~~six~~three months ended ~~June 30, 2011.~~March 31, 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 ~~June 30, 2011~~March 31, 2012 may not be indicative of our results that will be realized for the full year ending December 31, ~~2011.~~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; ~~and~~ assets and liabilities related to employee ~~benefits.~~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 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.

Table of Contents

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.

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 months ended March 31, 2012 was $2.0 million.

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 million and $1.1 million during the three months ended March 31, 2012 and ~~six month periods ended June 30,~~ 2011, ~~and 2010 was not material.~~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.

At Intangibles

~~June 30~~,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 months ended March 31, 2012 and 2011, ~~neither~~ ~~DPL~~ ~~nor~~ DP&L had ~~any material plant acquisition adjustments or other plant-related adjustments.~~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.

~~Table of Contents~~

~~Depreciation Study — Change in Estimate~~

~~Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For~~ ~~DPL’s~~ ~~generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010,~~ ~~DPL~~ completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation study concluded that many of ~~DPL’s~~ ~~composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated.~~ ~~DPL~~ adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the three and six months ended June 30, 2011, the net reduction in depreciation expense amounted to $2.4 million ($1.6 million net of tax) and $4.8 million ($3.1 million, net of tax), respectively, and increased diluted EPS by approximately $0.01 and $0.02 per share, respectively. The net reduction in depreciation expense for the twelve months ended June 30, 2011 was $9.6 million ($6.3 million net of tax) or $0.04 per diluted share.

~~Short-Term Investments~~

~~DPL~~ ~~utilizes VRDNs~~Customer relationships recognized as part of ~~its short-term investment strategy.~~the purchase accounting are amortized over nine to fifteen years and customer contracts are amortized over the average length of the contracts. The ~~VRDNs are of high credit quality and are~~ secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale back to the financial institution upon notice. Although ~~DPL’s~~ ~~VRDN investments have original maturities~~ESP is amortized over one year on a straight-line basis. Emission allowances are amortized as they are ~~frequently re-priced and trade at par.~~ ~~We account for these VRDNs~~used in our operations on a FIFO basis. Renewable energy credits are amortized as ~~available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since~~ they are ~~highly liquid and are~~ ~~readily available to support~~ ~~DPL’s~~ ~~current operating needs.~~used or retired.

~~DPL~~ ~~also utilizes investment-grade fixed income corporate securities~~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 ~~its short-term investment portfolio. These securities are accounted~~accordance with AES’ policy. The amounts for ~~as held-to-maturity investments.~~2011 have been reclassified to reflect this change in presentation.

Accounting for Taxes Collected from Customers and Remitted to Governmental Authorities

~~DP&L~~DPL collects certain excise taxes levied by state or local governments from its customers. ~~DP&L’s~~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 ~~gross~~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, 2012 and ~~general taxes in the accompanying Condensed Statements of Results of Operations as follows:~~2011 were $13.2 million and $14.0 million, respectively. The 2011 amount was reclassified to conform to this presentation.

Three Months Ended

Six Months Ended

June 30,

June 30,

$ in millions

2011

2010

2011

2010

State/Local excise taxes

$
11.6

$
11.4

$
25.7

$
25.5

Table of Contents

~~Related Party Transactions~~Share-Based Compensation

InWe measure the ~~normal course~~cost of ~~business,~~ ~~DP&L~~ ~~enters into transactions~~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 ~~subsidiaries of~~ ~~DPL~~~~. All material intercompany accounts~~similar instruments at the grant date are estimated using option-pricing models and ~~transactions~~any excess tax benefits are ~~eliminated~~recognized as an addition to paid-in capital. The reduction in ~~DPL’s~~income taxes payable from the excess tax benefits is presented in the Condensed Consolidated ~~Financial Statements. The following table provides~~Statements of Cash Flows within Cash flows from financing activities. As a ~~summary~~result of ~~these transactions:~~

Three Months Ended

Six Months Ended

June 30,

June 30,

$ in millions

2011

2010

2011

2010

DP&L Revenues:

Sales to DPLER (a)

$
81.0

$
52.8

$
156.1

$
90.0

DP&L Operation & Maintenance Expenses:

Premiums paid for insurance services provided by MVIC (b)

$
(0.8
)
$
(0.8
)
$
(1.6
)
$
(1.7
)
Expense recoveries for services provided to DPLER (c)

$
0.8

$
1.5

$
1.7

$
2.4

~~(a)~~the Merger (see Note 2), vesting of all ~~DP&L~~ DPL~~sells power to DPLER~~ share-based awards was accelerated as of the Merger date, and none are in ~~Ohio to satisfy the electric requirements of its retail customers. The revenues associated with sales to DPLER are recorded as wholesale sales in~~ ~~DP&L’s~~ ~~Condensed Financial Statements. The increase in~~ ~~DP&L’s~~ sales to DPLER in Ohio during the three and six months ended June 30, 2011 compared to the similar periods in 2010 is primarily due to an increase in 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 (including MC Squared). 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~~existence at ~~DP&L’s~~ ~~cost and credits the expense in which they were initially recorded.~~March 31, 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 ~~expect to adopt~~adopted this ASU on January 1, 2012. This standard updates FASC ~~Topic~~ 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 and~~inputs. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair ~~value;~~value and provides clarification of blockage factors and other premiums and discounts. ~~We do not expect these~~These new rules todid not have a material ~~impact~~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 ~~expect to adopt~~adopted this ASU on January 1, 2012. This standard updates FASC ~~Topic~~ 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. ~~We do not expect these~~These new rules todid not have a material ~~impact~~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.

Table of Contents

2. ~~Supplemental Financial Information and Comprehensive Income~~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

At

At

June 30,

December 31,

$ in millions

2011

2010

Accounts receivable, net:

Unbilled revenue

$
70.6

$
84.5

Customer receivables

116.7

113.9

Amounts due from partners in jointly-owned plants

8.7

7.0

Coal sales

1.2

4.0

Other

5.8

7.0

Provision for uncollectible accounts

(1.2
)
(0.9
)
Total accounts receivable, net

$
201.8

$
215.5

Inventories, at average cost:

Fuel, limestone and emission allowances

$
70.9

$
73.2

Plant materials and supplies

39.4

38.8

Other

5.3

3.3

Total inventories, at average cost

$
115.6

$
115.3

~~DP&L~~

At

At

June 30,

December 31,

$ in millions

2011

2010

Accounts receivable, net:

Unbilled revenue

$
46.0

$
64.3

Customer receivables

90.8

95.6

Amounts due from partners in jointly-owned plants

8.7

7.0

Coal sales

1.2

4.0

Other

4.7

7.9

Provision for uncollectible accounts

(1.0
)
(0.8
)
Total accounts receivable, net

$
150.4

$
178.0

Inventories, at average cost:

Fuel, limestone and emission allowances

$
70.6

$
73.2

Plant materials and supplies

38.2

37.7

Other

5.3

3.3

Total inventories, at average cost

$
114.1

$
114.2

~~Table~~. As of ~~Contents~~

~~Supplemental Financial Information~~March 31, 2012, there have been no changes to the preliminary valuations assigned to the assets acquired and ~~Comprehensive Income (continued)~~liabilities assumed at the Merger date. It is likely that the value of the generation business related property, plant and equipment, the intangible asset related 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

~~Comprehensive income~~ wholly owned CRES provider, will also likely have changes in its initial purchase price allocation for the ~~three months ended June 30, 2011 and 2010 was as follows:~~

~~DPL Inc.~~

Three Months Ended June 30,

2011

2010

Comprehensive income:

Net income

$
31.7

$
61.4

Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.1 million

—

(0.2
)
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $5.0 million and $5.0 million, respectively

(10.0
)
(10.0
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.4 million and $0.4 million, respectively

0.4

0.8

Comprehensive income

$
22.1

$
52.0

~~DP&L~~

Three Months Ended June 30,

2011

2010

Comprehensive income:

Net income

$
30.8

$
59.4

Net change in unrealized gains (losses) on financial instruments, net of income tax expenses of $0.9 million and income tax benefits of $1.3 million, respectively

1.8

(2.4
)
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense of $0.1 million and income tax benefit of $1.9 million, respectively

(0.7
)
(4.2
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.4 million and $0.4 million, respectively

0.4

0.8

Comprehensive income

$
32.3

$
53.6

~~Comprehensive income~~valuation of its intangible assets for the ~~six months ended June 30, 2011~~trade name, and ~~2010 was as follows:~~
~~DPL Inc.~~

Six Months Ended June 30,

2011

2010

Comprehensive income:

Net income

$
75.2

$
132.4

Net change in unrealized gains (losses) on financial instruments, net of income tax expense of zero

—

(0.1
)
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $4.1 million and $2.4 million, respectively

(8.8
)
(5.6
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.8 million and income tax benefits of $0.2 million, respectively

1.6

2.6

Comprehensive income

$
68.0

$
129.3

~~DP&L~~

Six Months Ended June 30,

2011

2010

Comprehensive income:

Net income

$
83.5

$
131.5

Net change in unrealized gains (losses) on financial instruments, net of income tax expenses of $1.4 million and income tax benefits of $1.5 million, respectively

2.7

(2.7
)
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense of $0.2 million and $0.7 million, respectively

(1.1
)
0.2

Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.8 million and income tax benefits of $0.2 million, respectively

1.6

2.6

Comprehensive income

$
86.7

$
131.6

20

~~Table of Contents~~customer relationships and contracts.

3.     Supplemental Financial Information

At

At

March 31,

December 31,

2012

2011

$ in millions

Successor

Accounts receivable, net:

Unbilled revenue

$
61.0

$
72.4

Customer receivables

115.8

113.2

Amounts due from partners in jointly-owned plants

31.2

29.2

Coal sales

9.2

1.0

Other

8.3

4.4

Provision for uncollectible accounts

(1.1
)
(1.1
)
Total accounts receivable, net

$
224.4

$
219.1

Inventories, at average cost:

Fuel and limestone

$
84.0

$
84.2

Plant materials and supplies

40.6

39.8

Other

1.8

1.8

Total inventories, at average cost

$
126.4

$
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, 2012 and December 31, 2011:

At

At

March 31,

December 31,

2012

2011

$ in millions

Successor

Financial instruments, net of tax

$
0.4

$
—

Cash flow hedges, net of tax

6.2

(0.5
)
Pension and postretirement benefits, net of tax

0.1

0.1

Total

$
6.7

$
(0.4
)
4. Regulatory ~~Matters~~Assets and Liabilities

In accordance with GAAP, regulatory assets and liabilities are recorded in the ~~condensed consolidated balance sheets~~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.

~~Economic Development Contract~~19

~~On March 4, 2011,~~ ~~DP&L~~ ~~applied for approval from the PUCO~~Table of ~~an arrangement entered into with~~ ~~DPL’s~~ ~~largest customer. Under the terms of this arrangement, all of the retail electric energy services of this customer will be provided by~~ ~~DP&L~~ through December 31, 2011. Subject to certain terms and conditions, this arrangement may be extended beyond December 31, 2011; however, its total duration is not to exceed 42 months. This arrangement was approved by the PUCO on June 8, 2011 and effective in July 2011. Under Ohio law, the electric discount provided to this customer may be recovered from all customers through an Economic Development Rider.Contents

Regulatory assets and liabilities are classified as current or non-current based on the ~~condensed consolidated balance sheets include:~~term in which recovery is expected.

At

At

Type of

Amortization

June 30,

December 31,

$ in millions

Recovery (a)

Through

2011

2010

Regulatory Assets:

Deferred recoverable income taxes

B/C

Ongoing

$
29.1

$
29.9

Pension benefits

C

Ongoing

77.8

81.1

Unamortized loss on reacquired debt

C

Ongoing

13.6

14.3

Regional transmission organization costs

D

2014

4.8

5.5

TCRR, transmission, ancillary and other PJM-related costs

F

Ongoing

8.7

11.8

Deferred storm costs - 2008

D

17.4

16.9

Power plant emission fees

C

Ongoing

6.5

6.6

CCEM smart grid and advanced metering infrastructure costs

D

6.6

6.6

CCEM energy efficiency program costs

F

Ongoing

5.7

4.8

Other costs

8.6

11.5

Total regulatory assets

$
178.8

$
189.0

Regulatory Liabilities:

Estimated costs of removal - regulated property

$
110.2

$
107.9

Postretirement benefits

5.7

6.1

Fuel and purchased power recovery costs

C

Ongoing

13.5

10.0

Total regulatory liabilities

$
129.4

$
124.0

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

At

At

Type of

Amortization

March 31,

December 31,

$ in millions

Recovery (a)

Through

2012

2011

Current Regulatory Assets:

TCRR, transmission, ancillary and other PJM-related costs

F

Ongoing

$
2.8

$
4.7

Power plant emission fees

C

Ongoing

3.1

4.8

Fuel and purchased power recovery costs

C

Ongoing

9.3

10.7

Total current regulatory assets

$
15.2

$
20.2

Non-current Regulatory Assets:

Deferred recoverable income taxes

B/C

Ongoing

$
23.3

$
24.1

Pension benefits

C

Ongoing

90.5

92.1

Unamortized loss on reacquired debt

C

Ongoing

12.6

13.0

Regional transmission organization costs

D

2014

3.7

4.1

Deferred storm costs - 2008

D

18.2

17.9

CCEM smart grid and advanced metering infrastructure costs

D

6.6

6.6

CCEM energy efficiency program costs

F

Ongoing

6.9

8.8

Consumer education campaign

D

3.0

3.0

Retail settlement system costs

D

3.1

3.1

Other costs

5.0

5.1

Total non-current regulatory assets

$
172.9

$
177.8

Current Regulatory Liabilities:

Other

C

Ongoing

—

0.6

Total current regulatory liabilities

$
—

$
0.6

Non-current Regulatory Liabilities:

Estimated costs of removal - regulated property

$
112.5

$
112.4

Postretirement benefits

6.0

6.2

Total non-current regulatory liabilities

$
118.5

$
118.6

(a)       B — Balance has an offsetting liability resulting in no ~~impact~~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.
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. We will have further discussions with interested parties concerning the audit report in the second quarter of 2012.
20

Table of Contents
Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as athe result of ~~amounts~~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 ~~Topic~~ 715 “Compensation — Retirement Benefits” costs of our regulated operations that for ratemaking purposes are deferred for future recovery. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income (OCI), the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. This regulatory asset represents the regulated portion that would otherwise be charged as a loss to OCI.

21

~~Table of Contents~~
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 ~~precedent,~~precedence, we are amortizing these costs over a 10-year period that began in 2004 when we joined the PJM RTO.
~~TCRR, transmission, ancillary and other PJM-related costs~~ represent the costs related to transmission, ancillary service and other PJM-related charges that have been incurred as a member of PJM. On an annual basis, retail rates are adjusted to true-up costs with recovery in rates.

Deferred storm costs — 2008 relate to costs incurred to repair the damage caused by hurricane force winds in September 2008, as well as other major 2008 storms. On January 14, 2009, the PUCO granted DP&L the authority to defer these costs with a return until such time that DP&L seeks recovery in a future rate proceeding.
~~Power plant emission fees~~ represent costs paid to the State of Ohio since 2002. An application is pending before the PUCO to amend an approved rate rider that had been in effect to collect fees that were paid and deferred in years prior to 2002. The deferred costs incurred prior to 2002 have been fully recovered. As the previously approved rate rider continues to be in effect, we believe these costs are probable of future rate recovery.

CCEM smart grid and AMI costs represent costs incurred as a result of studying and developing distribution system upgrades and implementation of AMI. 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.
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 ~~consumer education advertising costs regarding electric deregulation, settlement system costs, electric choice system,~~ RPM capacity, other PJM and rate case costs and alternative energy costs that are or will be recovered over various periods.

Regulatory Liabilities

Estimated costs of removal — regulated property ~~reflects~~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.

21

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

~~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.~~ ~~DP&L~~ recently underwent an audit of its fuel and purchased power recovery rider and, as a result, there is some uncertainty as to the costs that will be approved for recovery. Independent third parties conducted the fuel audit in accordance with PUCO standards. The audit was completed in the second quarter of 2011 and a hearing has been set by the PUCO for August 30, 2011. Once the PUCO audit approval process is complete, ~~DP&L~~ ~~may record a favorable or~~
22

~~Table of Contents~~
~~unfavorable adjustment to earnings. Based on past PUCO precedent, we believe these deferred fuel and purchased power costs are probable of future recovery or repayment in the case of over recovery.~~
4.5. Ownership of Coal-fired Facilities

DP&L ~~with~~and certain other Ohio utilities ~~has~~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 ~~June 30, 2011, we~~March 31, 2012, DP&L had ~~$49~~$55.0 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed 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~~wholly owned coal fired Hutchings ~~plant~~station at ~~June 30, 2011,~~March 31, 2012, is as follows:

DP&L Investment

DP&L Share

DP&L Investment

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

$
75

$
55

$
1

No

50.0

207

$
—

$
—

$
—

No

Conesville Unit 4

16.5

129

119

30

4

Yes

16.5

129

—

—

3

Yes

East Bend Station

31.0

186

201

132

—

Yes

31.0

186

—

—

5

Yes

Killen Station

67.0

402

617

294

2

Yes

67.0

402

332

1

6

Yes

Miami Fort Units 7 and 8

36.0

368

354

134

10

Yes

36.0

368

238

2

2

Yes

Stuart Station

35.0

808

719

274

17

Yes

35.0

808

189

—

11

Yes

Zimmer Station

28.1

365

1,060

620

15

Yes

28.1

365

159

—

28

Yes

Transmission (at varying percentages)

—

91

57

—

34

1

—

Total

2,465

$
3,236

$
1,596

$
49

2,465

$
952

$
4

$
55

Wholly-owned production unit:

Hutchings Station

100.0

390

$
124

$
113

$
1

No

100.0

365

$
—

$
—

$
—

No

Currently, our coal-fired generation units at Hutchings and Beckjord do not have the SCR and FGD emission-control equipment installed. DP~~&L’s~~&L ~~share~~owns 100% of ~~operating costs associated with~~ the ~~jointly-owned generating facilities are included within the corresponding line~~Hutchings station and has a 50% interest in ~~the Condensed Statements of Results of Operations.~~
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,~~station, including our ~~jointly-owned~~jointly owned Unit 6, in December 2014. ~~We are depreciating~~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 ~~through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.~~
was valued at zero at the Merger date. We are considering options for the Hutchings ~~Station,~~station, but have not yet made a final decision. We do not believe that any accruals are needed related to the Hutchings station.
DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.
22

Table of Contents
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. At March 31, 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

23

Table of Contents

~~5. Debt Obligations~~
~~Long-term Debt~~

At

At

June 30,

December 31,

$ in millions

2011

2010

DP&L

First mortgage bonds maturing in October 2013 - 5.125%

$
470.0

$
470.0

Pollution control series maturing in January 2028 - 4.70%

35.3

35.3

Pollution control series maturing in January 2034 - 4.80%

179.1

179.1

Pollution control series maturing in September 2036 - 4.80%

100.0

100.0

Pollution control series maturing in November 2040 - variable rates: 0.23% - 0.29% and 0.16% - 0.36% (a)

100.0

100.0

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

18.5

—

902.9

884.4

Obligation for capital lease

0.5

0.1

Unamortized debt discount

(0.4
)
(0.5
)
Total long-term debt - DP&L

$
903.0

$
884.0

DPL

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

20.6

142.6

Total long-term debt - DPL

$
923.6

$
1,026.6

~~Current portion - Long-term Debt~~

At

At

June 30,

December 31,

$ in millions

2011

2010

DP&L

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

$
0.1

$
—

Obligation for capital lease

0.3

0.1

Total current portion - long-term debt - DP&L

$
0.4

$
0.1

DPL

Senior notes maturing in September 2011 - 6.875%

297.4

297.4

Total current portion - long-term debt - DPL

$
297.8

$
297.5

~~(a)    Range of interest rates for~~Premiums or discounts recognized at the ~~six months ended June 30, 2011 and~~Merger date are amortized over the ~~twelve months ended December 31, 2010, respectively.~~
~~At June 30, 2011, maturities of long-term debt, including capital lease obligations and excluding the unamortized debt discount, are summarized as follows:~~
$ in millions

DPL

DP&L

Due within one year

$
297.8

$
0.4

Due within two years

0.4

0.4

Due within three years

470.4

470.4

Due within four years

0.1

0.1

Due within five years

0.1

0.1

Thereafter

453.0

432.4

$
1,221.8

$
903.8

24

~~Table of Contents~~
~~In connection with the closing~~life of the ~~Proposed Merger (see Note 16 of Notes to Condensed Consolidated Financial Statements),~~ ~~DPL~~ ~~expects to assume $1.25 billion of~~ debt ~~that we believe AES will issue to finance~~using the ~~acquisition. As a result of this expected additional indebtedness, in April 2011,~~ ~~DPL~~ ~~and~~ ~~DP&L~~ ~~were downgraded by one of the major credit rating agencies. All three of the major credit rating agencies reduced their outlook from stable to negative and indicated they would reduce~~ ~~DPL’s~~ ~~ratings to below investment grade upon assumption by~~ ~~DPL~~ ~~of the additional debt as a result of the Proposed Merger discussed in Note 16 of Notes to Condensed Consolidated Financial Statements.~~
~~On November 21, 2006,~~ ~~DP&L~~ ~~entered into a $220 million unsecured revolving credit agreement. This agreement has a five-year term that expires on November 21, 2011 and provides~~ ~~DP&L~~ ~~with the ability to increase the size of the facility by an additional $50 million at any time.~~ ~~DP&L~~ had no outstanding borrowings under this credit facility at June 30, 2011. Fees associated with this credit facility were not material during the three months and six months ended June 30, 2011, respectively. The fees andeffective interest rate associated with this facility have not changed as a result of the changes to our credit ratings that occurred in April 2011. This revolving credit agreement contains a $50 million letter of credit sublimit. As of June 30, 2011, ~~DP&L~~ ~~had no outstanding letters of credit against the facility.~~method.

On December 4, 2008, the OAQDA issued ~~$100~~$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 ~~LOC~~letter of credit issued by JPMorgan Chase Bank, N.A. This ~~LOC~~letter of credit facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. ~~The fees~~Fees associated with this ~~facility have increased as a result~~letter of ~~the changes to our credit ratings that occurred in April 2011. ��Fees associated with this~~ credit facility were not material during the three ~~and six~~ months ended ~~June 30, 2011, respectively.~~ ~~DP&L~~March 31, 2012 and ~~JPMorgan have entered into a Limited Consent and Waiver which provides for a waiver of any event of default under the LOC Agreement that would otherwise result from the closing of the Proposed Merger.~~
~~On April 21, 2009,~~ ~~DP&L~~ ~~entered into a $100 million unsecured revolving credit agreement with a syndicated bank group. The agreement was for a 364-day term and expired on April 20, 2010.~~2011.

On April 20, 2010, DP&L entered into a ~~$200~~$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~~$50.0 million. DP&L had no outstanding borrowings under this credit facility at ~~June 30,~~March 31, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three ~~and six~~ months ended ~~June 30, 2011. The fees~~March 31, 2012 and ~~interest rate associated with this facility will increase as a result of the changes to our credit ratings that occurred in April~~ 2011. This facility also contains a $50 million letter of credit sublimit. As of ~~June 30, 2011,~~March 31, 2012, DP&L had no outstanding letters of credit against the facility.~~DP&L~~, Bank of America and the Lenders have entered into a Limited Consent and Waiver which provides for a waiver of any event of default under the Credit Agreement that would otherwise result from the closing of the Proposed Merger.
~~Refer to Note 16 of the Condensed Consolidated Financial Statements for additional information on the Proposed Merger with AES and refinancing related to~~ ~~DPL’s~~ ~~existing credit facilities.~~

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 ~~February 28, 2011, DPLER purchased MC Squared. As part of the purchase price,~~ ~~DPL~~ ~~acquired restricted cash for repayment of MC Squared debt. On the day of the purchase,~~ ~~DPL~~ ~~issued a guarantee to a third party for the MC Squared debt. By issuing the guarantee, all restrictions on the cash were released and~~ ~~DPL~~ ~~used the cash to redeem most of the MC Squared debt owed to a third party totaling $13.5 million.~~
On March 1, 2011, DP&L ~~purchased~~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, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three months ended March 31, 2012. This facility also contains a $50 million letter of credit sublimit. As of March 31, 2012, DP&L had no outstanding letters of credit against the facility.
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, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three months ended March 31, 2012. This facility may also be used to issue letters of credit up to the $125 million limit. As of March 31, 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 million available under the facility at March 31, 2012. Fees associated with this term loan were not material during the three months ended March 31, 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.

2524

Table of Contents

6.7.   Income Taxes

The following table details the effective tax rates for the three ~~and six~~ months ended ~~June 30, 2011~~March 31, 2012 and ~~2010.~~2011.

Three Months Ended

Six Months Ended

June 30,

June 30,

2011

2010

2011

2010

DPL

34.0
%
32.9
%
35.3
%
33.4
%

DP&L

33.6
%
32.3
%
33.8
%
33.1
%

Three Months Ended

March 31,

2012

2011

DPL

26.0
%
36.3
%

Income tax ~~expenses~~expense for the three ~~and six~~ months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ were calculated using the estimated annual effective income tax rates for ~~2011~~2012 and ~~2010~~2011 and reflect estimated annual effective income tax rates of ~~33.7%~~25.6% and ~~33.5%~~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 recognized.~~rates.

For the three months ended ~~June 30,~~March 31, 2011, DPL increased income tax expense by ~~$0.1 million for an increase in other estimated tax liabilities. For the six months ended June 30, 2011,~~ ~~DPL~~ ~~increased income tax expense by $1.9~~$1.8 million by increasing deferred state income taxes by $2.0 million and decreasing other estimated tax liabilities by ~~$0.1~~$0.2 million.

For the three ~~and six~~ months ended ~~June 30, 2011,~~ ~~DP&L~~ ~~increased income tax expense by $0.1 million and $0.2 million, respectively, for an increase in other estimated tax liabilities.~~
~~For~~March 31, 2012, the ~~six months ended June 30, 2011, the increase~~decrease in DPL’s effective tax rate compared to the same period in ~~2010~~2011 primarily reflects ~~the~~ decreased ~~benefits from the Section 199 Domestic Production Deduction due to the election of bonus depreciation and increased state income tax expense due to the acquisition of MC Squared. The increase in~~ ~~DP&L’s~~ ~~effective tax rate primarily reflects the decreased benefits from the Section 199 Domestic Production Deduction.~~pre-tax earnings.

Deferred tax liabilities for ~~both~~ DPL ~~and~~ ~~DP&L~~ ~~increased~~decreased by approximately ~~$32.4~~$6.3 million ~~and $37.8 million, respectively,~~ during the ~~six~~three months ended ~~June 30, 2011.~~March 31, 2012. These ~~increases~~decreases were primarily related to ~~depreciation, a pension contribution~~amortization and ~~other temporary differences arising from routine changes in balance sheet accounts giving rise to deferred taxes.~~depreciation.

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. WeAt this time, we do not expect the results of this examination to have a material impact on our financial statements.

~~As of June 30, 2011,~~ ~~DPL~~ has incurred approximately $5.2 million in certain costs that are directly associated with the Proposed Merger, which will be deemed as non-deductible, resulting in approximately $1.8 million of additional tax expense for the period in which the transaction would occur.
7.8.     Pension and Postretirement Benefits

~~DPL~~DP&L sponsors a defined benefit pension plan for the vast majority of its employees. For collective bargaining employees, the defined benefits are based on a specific dollar amount per year of service. For all other employees (management employees), the defined benefit pension plan is based primarily on compensation and years of service. As of December 31, 2010, this existing pension plan was closed to new management employees. A participant is 100% vested in all amounts credited to his or her account upon the completion of five vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan, or upon a change of control or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination.
26

~~Table of Contents~~
Almost all management employees beginning employment on or after January 1, 2011 will be enrolled in a cash balance defined benefit plan. Similar to the predecessor pension plan for management employees, the cash balance benefits are based on compensation and years of service. A participant shall become 100% vested in all amounts credited to his or her account upon the completion of three vesting years, as defined in The Dayton Power and Light Company Retirement Income Plan or upon a change of control or the participant’s death or disability. If a participant’s employment is terminated, other than by death or disability, prior to such participant becoming 100% vested in his or her account, the account shall be forfeited as of the date of termination. Vested benefits in the cash balance plan are fully portable upon termination of employment.

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 ~~discretionary~~voluntary contributions from time to time. There were no contributions made during the three months ended March 31, 2012. DP&L made a discretionary ~~contributions~~contribution of $40.0 ~~million and $20.0~~ million to the defined benefit plan in ~~February 2011 and 2010, respectively.~~
Qualified employees who retired prior to 1987 and their dependents are eligible for health care and life insurance benefits until their death, while qualified employees who retired after 1987 are eligible for life insurance benefits and partially subsidized health care. The partially subsidized health care is at the election of the employee, who pays the majority of the cost, and is available only from retirement until Medicare coverage begins at age 65. We have funded a portion of the union-eligible benefits using a Voluntary Employee Beneficiary Association Trust.three months ended March 31, 2011.

The amounts presented in the following tables for pension include both the ~~defined benefit pension/~~collective bargaining plan formula, the traditional management plan formula, the cash balance ~~plans~~plan formula and the SERP in the ~~aggregate, and the~~aggregate. The amounts presented for postretirement include both health and life insurance.
25

Table of Contents

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ was:

Net Periodic Benefit Cost / (Income)

Pension

Postretirement

$ in millions

2011

2010

2011

2010

Service cost

$
1.5

$
1.1

$
0.1

$
—

Interest cost

4.3

4.5

0.2

0.3

Expected return on assets (a)

(6.1
)
(5.6
)
—

(0.1
)
Amortization of unrecognized:

Actuarial (gain) / loss

2.2

1.8

(0.2
)
(0.1
)
Prior service cost

0.6

0.9

—

—

Net periodic benefit cost / (income) before adjustments

$
2.5

$
2.7

$
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 2011 net periodic benefit cost was approximately $316 million.Net Periodic Benefit Cost / (Income)

~~The net periodic benefit cost (income) of the pension and postretirement benefit plans for the six months ended June 30, 2011 and 2010 was:~~
Net Periodic Benefit Cost / (Income)

Pension

Postretirement

Pension

Postretirement

Successor

Predecessor

Successor

Predecessor

$ in millions

2011

2010

2011

2010

2012

2011

2012

2011

Service cost

$
2.9

$
2.2

$
0.1

$
—

$
1.5

$
1.4

$
0.1

$
—

Interest cost

8.6

9.0

0.5

0.7

4.3

4.3

0.3

0.3

Expected return on assets (a)

(12.2
)
(11.2
)
(0.1
)
(0.2
)

(5.7
)

(6.1
)
(0.1
)

(0.1
)
Amortization of unrecognized:

Actuarial (gain) / loss

4.5

3.6

(0.4
)
(0.4
)

1.2

2.3

(0.2
)

(0.2
)
Prior service cost

1.1

1.9

—

0.1

0.4

0.5

—

—

Net periodic benefit cost / (income) before adjustments

$
4.9

$
5.5

$
0.1

$
0.2

$
1.7

$
2.4

$
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.~~million, respectively.
27

~~Table of Contents~~

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

2011

$
10.7

$
1.3

2012

$
23.1

$
2.4

$
17.3

$
1.8

2013

$
23.1

$
2.4

$
22.7

$
2.3

2014

$
23.6

$
2.3

$
23.2

$
2.2

2015

$
24.0

$
2.1

$
23.8

$
2.0

2016 - 2020

$
122.9

$
8.8

2016

$
24.0

$
1.9

2017 - 2021

$
124.4

$
7.5

8.9. 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 estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at ~~June 30, 2011~~March 31, 2012 and December 31, ~~2010.~~2011. See also Note 910 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.

Successor

At June 30,

At December 31,

At March 31,

At December 31,

2011

2010

2012

2011

$ in millions

Cost

Fair Value

Cost

Fair Value

Cost

Fair Value

Cost

Fair Value

DPL

Assets

Money Market Funds

$
0.2

$
0.2

$
1.6

$
1.6

$
0.2

$
0.2

$
0.2

$
0.2

Equity Securities

3.5

4.2

3.8

4.4

3.9

5.0

3.9

4.4

Debt Securities

5.2

5.5

5.2

5.5

5.1

5.5

5.0

5.5

Multi-Strategy Fund

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.2

Total Master Trust Assets

$
9.2

$
10.2

$
10.9

$
11.8

Short-term Investments - VRDNs

$
—

$
—

$
54.2

$
54.2

Short-term Investments - Bonds

—

—

15.1

15.1

Total Short-term Investments

$
—

$
—

$
69.3

$
69.3

Total Assets

$
9.2

$
10.2

$
80.2

$
81.1

$
9.5

$
11.0

$
9.4

$
10.3

Liabilities

Debt

$
1,221.4

$
1,198.7

$
1,324.1

$
1,307.5

$
2,624.5

$
2,723.4

$
2,629.3

$
2,710.6

DP&L

Assets

Money Market Funds

$
0.2

$
0.2

$
1.6

$
1.6

Equity Securities (a)

16.9

33.7

17.5

30.2

Debt Securities

5.2

5.5

5.2

5.5

Multi-Strategy Fund

0.3

0.3

0.3

0.3

Total Master Trust Assets

$
22.6

$
39.7

$
24.6

$
37.6

Liabilities

Debt

$
903.4

$
877.3

$
884.1

$
850.6

26

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

Debt
~~Debt is shown as~~
The carrying value of DPL’s debt was adjusted to fair value ~~based on current public market prices for disclosure purposes only.~~at the Merger date. Unrealized gains or losses are not recognized in the ~~condensed consolidated~~ financial statements as debt is presented at ~~amortized cost~~the carrying value established at the Merger date, net of unamortized premium or discount in the ~~condensed consolidated~~ financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from ~~2011~~2013 to 2061.
28

~~Table of Contents~~

Master Trust Assets
DP&L established a Master Trust to hold assets that could be used for the benefit of ~~directors and~~ employees participating in employee benefit plans. These assets are ~~not used for general operating purposes and are~~ primarily comprised of open-ended mutual funds ~~and~~ ~~DPL~~ ~~common stock. The~~ ~~DPL~~ ~~common stock held by the~~ ~~DP&L~~ ~~Master Trust is eliminated in consolidation and is not reflected in~~ ~~DPL’s~~ ~~Condensed Consolidated Balance Sheets. The~~ ~~DPL~~ ~~common stock is valued using current public market prices, while the open-ended mutual funds~~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 ~~$1.0~~$0.6 million ($~~0.7~~0.4 million after tax) inof unrealized gains and immaterial ~~unrealized~~ losses on the Master Trust assets in AOCI at ~~June 30, 2011~~March 31, 2012 and ~~$0.9 million ($0.6 million after tax) in~~immaterial unrealized gains and ~~immaterial unrealized~~ losses in AOCI at December 31, ~~2010.~~2011.

Due to the liquidation of the ~~DP&L~~DPL Inc. ~~had $17.0 million ($11.0 million after tax)~~common stock held in ~~unrealized gains and immaterial unrealized losses on~~ the Master Trust, ~~assets in AOCI at June 30, 2011 and $13.0 million ($8.5 million after tax) in~~there is sufficient cash to cover the next twelve months of benefits payable to employees covered under the benefit plans. Therefore, no unrealized gains ~~and immaterial unrealized~~or losses ~~in AOCI at December 31, 2010.~~
~~Approximately $0.4 million in unrealized gains~~ are expected to be transferred to earnings since we will not need to sell any investments in the next twelve months.
~~Short-Term Investments~~
~~DPL~~ ~~utilizes VRDNs as part of its short-term investment strategy. The VRDNs are of high credit quality and are~~ secured by irrevocable letters of credit from major financial institutions. VRDN investments have variable rates tied to short-term interest rates. Interest rates are reset every seven days and these VRDNs can be tendered for sale back to the financial institution upon notice. Although ~~DPL’s~~ ~~VRDN investments have original maturities over one year, they are frequently re-priced and trade at par.~~ ~~We account for these VRDNs as available-for-sale securities and record them as short-term investments at fair value, which approximates cost, since they are highly liquid and are~~ ~~readily available to support~~ ~~DPL’s~~ ~~current operating needs.~~
~~DPL~~ ~~also utilizes investment-grade fixed income corporate securities in its short-term investment portfolio. These securities are accounted for as held-to-maturity investments.~~
29

~~Table of Contents~~

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 ~~June 30, 2011 and December~~March 31, ~~2010.~~2012. These assets are part of the Master ~~Trust and exclude~~ ~~DPL~~ ~~common stock which is valued using quoted market prices and not the NAV.~~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 ~~June 30, 2011,~~March 31, 2012, DPL did not have any investments for sale at a price different ~~than~~from the NAV per unit.

Fair Value Estimated using Net Asset Value per Unit

$ in millions

Fair Value at
June 30, 2011

Fair Value at
December 31, 2010

Unfunded
Commitments

Redemption
Frequency

Money Market Fund (a)

$
0.2

$
1.6

$
—

Immediate

Equity Securities (b)

4.2

4.4

—

Immediate

Debt Securities (c)

5.5

5.5

—

Immediate

Multi-Strategy Fund (d)

0.3

0.3

—

Immediate

Total

$
10.2

$
11.8

$
—

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

Money Market Fund (a)

$
0.2

$
0.2

$
—

Equity Securities (b)

5.0

4.4

—

Debt Securities (c)

5.5

5.5

—

Multi-Strategy Fund (d)

0.3

0.2

—

Total

$
11.0

$
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.

(c)     This category includes ~~funds holding~~ 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.

27

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

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

We did not have any transfers of the fair values of our financial instruments between Level 1 and Level 2 of the fair value ~~hierarchy during the three and six months ended June 30, 2011.~~
30

~~Table of Contents~~hierarchy.

The fair value of assets and liabilities at ~~June 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011 measured on a recurring basis and the respective category within the fair value hierarchy for DPL was determined as follows:

~~DPL~~

Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)

Level 1

Level 2

Level 3

Fair Value on

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Fair Value at

Based on Quoted

Other

Collateral and

Balance Sheet

Level 1

Level 2

Level 3

March 31,

Prices in Active

Observable

Unobservable

Counterparty

at March 31,

$ in millions

Fair Value at
June 30,
2011*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Fair Value on
Balance Sheet at
June 30, 2011

2012*

Markets

Inputs

Inputs

Netting

2012

Assets

Master Trust Assets

Money Market Funds

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Equity Securities

4.2

—

4.2

—

—

4.2

5.0

—

5.0

—

—

5.0

Debt Securities

5.5

—

5.5

—

—

5.5

5.5

—

5.5

—

—

5.5

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

0.3

—

0.3

—

—

0.3

Total Master Trust Assets

$
10.2

$
—

$
10.2

$
—

$
—

$
10.2

11.0

—

11.0

—

—

11.0

Derivative Assets

FTRs

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

0.1

—

0.1

—

—

0.1

Heating Oil Futures

3.3

3.3

—

—

(3.3
)
—

1.6

1.6

—

—

(1.6
)
—

Interest Rate Hedge

18.6

—

18.6

—

—

18.6

Forward NYMEX Coal Contracts

24.4

—

24.4

—

(13.6
)
10.8

Forward Power Contracts

12.9

—

12.9

—

(0.8
)
12.1

18.2

—

18.2

—

(0.7
)
17.5

Total Derivative Assets

$
59.4

$
3.3

$
56.1

$
—

$
(17.7
)
$
41.7

19.9

1.6

18.3

—

(2.3
)
17.6

Short-term Investments - Bonds

—

—

—

—

—

—

Total Short-term investments

$
—

$
—

$
—

$
—

$
—

$
—

Total Assets

$
69.6

$
3.3

$
66.3

$
—

$
(17.7
)
$
51.9

$
30.9

$
1.6

$
29.3

$
—

$
(2.3
)
$
28.6

Liabilities

Derivative Liabilities

Interest Rate Hedge

$
(18.7
)
$
—

$
(18.7
)
$
—

$
—

$
(18.7
)

$
(16.8
)
$
—

$
(16.8
)
$
—

$
—

$
(16.8
)
Forward NYMEX Coal Contracts

(0.5
)
—

(0.5
)
—

0.5

—

(22.3
)
—

(22.3
)
—

16.0

(6.3
)
Forward Power Contracts

(9.7
)
—

(9.7
)
—

3.5

(6.2
)

(16.0
)
—

(16.0
)
—

10.7

(5.3
)
Total Derivative Liabilities

$
(28.9
)
$
—

$
(28.9
)
$
—

$
4.0

$
(24.9
)

(55.1
)
—

(55.1
)
—

26.7

(28.4
)

Long-term Debt

(2,723.4
)
—

(2,704.2
)
(19.2
)
—

(2,723.4
)

Total Liabilities

$
(28.9
)
$
—

$
(28.9
)
$
—

$
4.0

$
(24.9
)

$
(2,778.5
)
$
—

$
(2,759.3
)
$
(19.2
)
$
26.7

$
(2,751.8
)

*Includes credit valuation adjustments for counterparty risk.

3128

Table of Contents

~~DPL~~

Assets and Liabilities Measured at Fair Value on a Recurring Basis (Successor)

Level 1

Level 2

Level 3

Fair Value on

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Fair Value at

Based on Quoted

Other

Collateral and

Balance Sheet at

Level 1

Level 2

Level 3

Fair Value on

December 31,

Prices in Active

Observable

Unobservable

Counterparty

December 31,

$ in millions

Fair Value at
December 31,
2010*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Balance Sheet at
December 31,
2010

2011*

Markets

Inputs

Inputs

Netting

2011

Assets

��

Master Trust Assets

Money Market Funds

$
1.6

$
—

$
1.6

$
—

$
—

$
1.6

$
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

0.3

—

0.3

—

—

0.3

0.2

—

0.2

—

—

0.2

Total Master Trust Assets

$
11.8

$
—

$
11.8

$
—

$
—

$
11.8

10.3

—

10.3

—

—

10.3

Derivative Assets

FTRs

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

0.1

—

0.1

—

—

0.1

Heating Oil Futures

1.6

1.6

—

—

(1.6
)
—

1.8

1.8

—

—

(1.8
)
—

Interest Rate Hedge

20.7

—

20.7

—

—

20.7

Forward NYMEX Coal Contracts

37.5

—

37.5

—

(21.9
)
15.6

Forward Power Contracts

0.2

—

0.2

—

(0.2
)
—

17.3

—

17.3

—

(1.0
)
16.3

Total Derivative Assets

$
60.3

$
1.6

$
58.7

$
—

$
(23.7
)
$
36.6

19.2

1.8

17.4

—

(2.8
)
16.4

Short-term Investments - VRDNs

$
54.2

$
—

$
54.2

$
—

$
—

$
54.2

Short-term Investments - Bonds

15.1

—

15.1

—

—

15.1

Total Short-term investments

$
69.3

$
—

$
69.3

$
—

$
—

$
69.3

Total Assets

$
141.4

$
1.6

$
139.8

$
—

$
(23.7
)
$
117.7

$
29.5

$
1.8

$
27.7

$
—

$
(2.8
)
$
26.7

Liabilities

Derivative Liabilities

Interest Rate Hedge

$
6.6

$
—

$
6.6

$
—

$
—

$
6.6

$
(32.5
)
$
—

$
(32.5
)
$
—

$
—

$
(32.5
)
Forward NYMEX Coal Contracts

(14.5
)
—

(14.5
)
—

10.8

(3.7
)
Forward Power Contracts

3.1

—

3.1

—

(1.1
)
2.0

(13.3
)
—

(13.3
)
—

5.6

(7.7
)
Total Derivative Liabilities

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

(60.3
)
—

(60.3
)
—

16.4

(43.9
)

Total Liabilities

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

$
(60.3
)
$
—

$
(60.3
)
$
—

$
16.4

$
(43.9
)

*Includes credit valuation adjustments for counterparty risk.

32

~~Table of Contents~~
~~The fair value of assets and liabilities at June 30, 2011 and December 31, 2010 measured on a recurring basis and the respective category within the fair value hierarchy for~~ ~~DP&L~~ ~~was determined as follows:~~
~~DP&L~~

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

$ in millions

Fair Value at
June 30,
2011*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Fair Value on
Balance Sheet at
June 30, 2011

Assets

Master Trust Assets

Money Market Funds

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Equity Securities (a)

33.7

29.5

4.2

—

—

33.7

Debt Securities

5.5

—

5.5

—

—

5.5

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

Total Master Trust Assets

$
39.7

$
29.5

$
10.2

$
—

$
—

$
39.7

Derivative Assets

FTRs

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Heating Oil Futures

3.3

3.3

—

—

(3.3
)
—

Forward NYMEX Coal Contracts

24.4

—

24.4

—

(13.6
)
10.8

Forward Power Contracts

1.3

—

1.3

—

(0.8
)
0.5

Total Derivative Assets

$
29.2

$
3.3

$
25.9

$
—

$
(17.7
)
$
11.5

Total Assets

$
68.9

$
32.8

$
36.1

$
—

$
(17.7
)
$
51.2

Liabilities

Derivative Liabilities

Forward NYMEX Coal Contracts

$
(0.5
)
$
—

$
(0.5
)
$
—

$
0.5

$
—

Forward Power Contracts

(3.6
)
—

(3.6
)
—

1.5

(2.1
)
Total Derivative Liabilities

$
(4.1
)
$
—

$
(4.1
)
$
—

$
2.0

$
(2.1
)

Total Liabilities

$
(4.1
)
$
—

$
(4.1
)
$
—

$
2.0

$
(2.1
)
*Includes credit valuation adjustments for counterparty risk.
~~(a)~~ ~~DPL~~ ~~stock in the Master Trust is eliminated in consolidation.~~
~~DP&L~~

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Fair Value on

$ in millions

Fair Value at
December 31,
2010*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Balance Sheet at
December 31,
2010

Assets

Master Trust Assets

Money Market Funds

$
1.6

$
—

$
1.6

$
—

$
—

$
1.6

Equity Securities (a)

30.2

25.8

4.4

—

—

30.2

Debt Securities

5.5

—

5.5

—

—

5.5

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

Total Master Trust Assets

$
37.6

$
25.8

$
11.8

$
—

$
—

$
37.6

Derivative Assets

FTRs

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

Heating Oil Futures

1.6

1.6

—

—

(1.6
)
—

Forward NYMEX Coal Contracts

37.5

—

37.5

—

(21.9
)
15.6

Forward Power Contracts

0.2

—

0.2

—

(0.2
)
—

Total Derivative Assets

$
39.6

$
1.6

$
38.0

$
—

$
(23.7
)
$
15.9

Total Assets

$
77.2

$
27.4

$
49.8

$
—

$
(23.7
)
$
53.5

Liabilities

Derivative Liabilities

Forward Power Contracts

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

Total Derivative Liabilities

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

Total Liabilities

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

*Includes credit valuation adjustments for counterparty risk.
~~(a)~~ ~~DPL~~ ~~stock in the Master Trust is eliminated in consolidation.~~
33

~~Table of Contents~~
We use the market approach to value our financial instruments. Level 1 inputs are used ~~for~~ ~~DPL~~ ~~common stock held by the Master Trust and~~ for derivative contracts such as heating oil futures. 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) ~~and~~, forward power contracts and forward NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). ~~VRDNs and bonds are considered Level 2 because they are priced using recent transactions for similar assets.~~ Other Level 2 assets ~~include~~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.
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.

Approximately ~~97%~~99% of the inputs to the fair value of our derivative instruments are from quoted market prices.

Non-recurring fair value measurements
We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. ~~There~~Additions to AROs were ~~no additions to our existing AROs~~not material during the three ~~or six~~ months ended ~~June 30,~~March 31, 2012 and 2011.

29

Table of Contents
Cash Equivalents
DPL had ~~$25.0~~$100.0 million and ~~$29.9~~$125.0 million in money market funds ~~at June 30, 2011 and December 31, 2010, respectively,~~ classified as cash and cash equivalents in its Condensed Consolidated Balance ~~Sheets.~~Sheets at March 31, 2012 and December 31, 2011, respectively. The money market funds have quoted prices that are generally equivalent to par.

9.10. Derivative Instruments and Hedging Activities

In the normal course of business, DPL ~~and~~ ~~DP&L~~ ~~enter~~enters into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for ~~commodities.~~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 ~~generally~~ to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as a cash flow ~~hedge~~hedges or marked to market each reporting period.

At ~~June 30, 2011,~~March 31, 2012, DPL ~~and~~ ~~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 ~~(1)~~

Mark to Market

MWh

17.0

—

17.0

Mark to Market

MWh

2.8

—

2.8

Heating Oil Futures ~~(1)~~

Mark to Market

Gallons

4,578.0

—

4,578.0

Mark to Market

Gallons

1,680.0

—

1,680.0

Forward Power Contracts ~~(1)~~

Cash Flow Hedge

MWh

927.2

(965.7
)
(38.5
)

Cash Flow Hedge

MWh

881.1

(107.2
)
773.9

Forward Power Contracts ~~(1)~~

Mark to Market

MWh

446.9

(423.2
)
23.7

Mark to Market

MWh

1,195.4

(1,213.5
)
(18.1
)
Forward Power Contracts (2)

Mark to Market

MWh

1,311.3

(1,338.7
)
(27.4
)
NYMEX-quality Coal Contracts* (1)

Mark to Market

Tons

3,588.3

—

3,588.3

Interest Rate Swaps (2)

Cash Flow Hedge

USD

460,000.0

—

460,000.0

NYMEX-quality Coal Contracts*

Mark to Market

Tons

1,410.5

—

1,410.5

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.

~~(1)Reflected in both~~ ~~DPL’s~~ ~~and~~ ~~DP&L’s~~ ~~Condensed Consolidated Financial Statements.~~
~~(2)Reflected in only~~ ~~DPL’s~~ ~~Condensed Consolidated Financial Statements.~~
34

~~Table of Contents~~
At December 31, ~~2010,~~2011, DPL ~~and~~ ~~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 ~~(1)~~

Mark to Market

MWh

9.0

—

9.0

Mark to Market

MWh

7.1

(0.7
)
6.4

Heating Oil Futures ~~(1)~~

Mark to Market

Gallons

6,216.0

—

6,216.0

Mark to Market

Gallons

2,772.0

—

2,772.0

Forward Power Contracts ~~(1)~~

Cash Flow Hedge

MWh

580.8

(572.9
)
7.9

Cash Flow Hedge

MWh

886.2

(341.6
)
544.6

Forward Power Contracts ~~(1)~~

Mark to Market

MWh

195.6

(108.5
)
87.1

Mark to Market

MWh

1,769.4

(1,739.5
)
29.9

NYMEX-quality Coal Contracts* ~~(1)~~

Mark to Market

Tons

4,006.8

—

4,006.8

Mark to Market

Tons

2,015.0

—

2,015.0

Interest Rate Swaps ~~(2)~~

Cash Flow Hedge

USD

360,000.0

—

360,000.0

Cash Flow Hedge

USD

$
160,000.0

$
—

$
160,000.0

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

~~(1)Reflected in both~~ ~~DPL’s~~ ~~and~~ ~~DP&L’s~~ ~~Condensed Consolidated Financial Statements.~~30

~~(2)Reflected in only~~ ~~DPL’s~~ ~~Condensed Consolidated Financial Statements.~~Table of Contents

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

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

We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt.  We do not hedge all interest rate exposure. As of June 30, 2011, we have entered into interest rate hedging relationships with aggregate notional amounts of $300 million and $160 million related to planned future borrowing activities in calendar years 2011 and 2013, respectively. As part of the Proposed Merger discussed in Note 16, ~~DPL~~ ~~agreed to use commercially reasonable efforts to enter into a $425 million term loan of at least three years, in part, to refinance the approximately $297.4 million principal amount of~~ ~~DPL’s~~ 6.875% debt that is due in September 2011. As a result, some of the forecasted transactions originally being hedged are probable of not occurring and therefore approximately $2.0 million ($1.3 million net of tax) of the fair value of the derivative instrument associated with those forecasted transactions has been reclassified out of AOCI and reflected in earnings during the second quarter. Our ~~2013~~ 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 ~~our~~ debt financings from AOCI into earnings in those periods in which hedged interest payments ~~occur~~.occur.

3531

Table of Contents

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended ~~June 30, 2011~~March 31, 2012 and ~~2010:~~2011:

March 31,

March 31,

June 30,

June 30,

2012

2011

2011

2010

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

$
(1.6
)
$
22.4

$
3.6

$
14.1

$
0.3

$
(0.8
)

$
(1.8
)
$
21.4

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

(0.5
)
(10.8
)
(2.1
)
(5.8
)

(1.5
)
9.1

0.5

1.6

Net gains reclassified to earnings

Interest expense

—

0.7

—

(0.6
)

—

0.2

—

(0.6
)
Revenues

0.3

—

(1.5
)
—

(1.2
)
—

(0.1
)
—

Purchased power

0.3

—

—

—

0.1

—

(0.2
)
—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
12.3

$
—

$
7.7

$
(2.3
)
$
8.5

$
(1.6
)
$
22.4

Net gains / (losses) associated with the ineffective portion of the hedging transaction

Interest expense

—

(1.3
)
—

—

$
—

$
(1.6
)

$
—

$
—

Revenues

—

—

—

—

$
—

$
—

$
—

$
—

Purchased power

$
—

$
—

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

$
(1.9
)
$
(2.4
)

$
(0.3
)
$
—

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

42

27

33

18

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

36

~~Table of Contents~~
~~The following table provides information for~~ ~~DP&L~~ ~~concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended June 30, 2011 and 2010:~~

June 30,

June 30,

2011

2010

Interest

Interest

$ in millions (net of tax)

Power

Rate Hedge

Power

Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI

$
(1.6
)
$
11.6

$
3.6

$
14.1

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

(0.5
)
—

(2.1
)
—

Net gains reclassified to earnings

Interest expense

—

(0.6
)
—

(0.6
)
Revenues

0.3

—

(1.5
)
—

Purchased power

0.3

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
11.0

$
—

$
13.5

Net gains / (losses) associated with the ineffective portion of the hedging transaction

Interest expense

—

—

—

—

Revenues

—

—

—

—

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

$
(1.9
)
$
(2.4
)

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

42

—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
37

~~Table of Contents~~
~~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, 2011 and 2010:~~

June 30,

June 30,

2011

2010

Interest

Interest

$ in millions (net of tax)

Power

Rate Hedge

Power

Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI

$
(1.8
)
$
21.4

$
(1.4
)
$
14.7

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

(0.9
)
(9.2
)
(2.3
)
(5.8
)

Net gains reclassified to earnings

Interest expense

—

0.1

—

(1.2
)
Revenues

0.5

—

3.7

—

Purchased power

0.7

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
12.3

$
0.0

$
7.7

Net gains / (losses) associated with the ineffective portion of the hedging transaction

Interest expense

—

(1.3
)
—

—

Revenues

—

—

—

—

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

$
(1.9
)
$
(2.4
)

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

42

27

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
38

~~Table of Contents~~
~~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, 2011 and 2010:~~

June 30,

June 30,

2011

2010

Interest

Interest

$ in millions (net of tax)

Power

Rate Hedge

Power

Rate Hedge

Beginning accumulated derivative gain / (loss) in AOCI

$
(1.8
)
$
12.2

$
(1.4
)
$
14.7

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

(0.9
)
—

(2.3
)
—

Net gains reclassified to earnings

Interest expense

—

(1.2
)
—

(1.2
)
Revenues

0.5

—

3.7

—

Purchased power

0.7

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
11.0

$
0.0

$
13.5

Net gains / (losses) associated with the ineffective portion of the hedging transaction

Interest expense

—

—

—

—

Revenues

—

—

—

—

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

$
(1.9
)
$
(2.4
)

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

42

—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
3932

Table of Contents

The following tables show the fair value and balance sheet classification of DPL’s derivative instruments designated as hedging instruments at ~~June 30, 2011~~March 31, 2012 and December 31, ~~2010.~~2011:

Fair Values of Derivative Instruments Designated as Hedging Instruments
at ~~June 30, 2011~~March 31, 2012 (Successor)

~~DPL~~

Fair Value on

$ in millions

Fair Value(1)

Netting (2)

Balance Sheet Location

Balance Sheet

Short-term Derivative Positions

Forward Power Contracts in an Asset position

$
0.3

$
(0.3
)
Other prepayments and current assets

$
—

Forward Power Contracts in a Liability position

(2.2
)
1.0

Other current liabilities

(1.2
)
Interest Rate Hedges in a Liability position

(18.7
)
—

Other current liabilities

(18.7
)

Total short-term cash flow hedges

$
(20.6
)
$
0.7

$
(19.9
)

Long-term derivative positions

Forward Power Contracts in an Asset position

$
0.2

$
(0.1
)
Other deferred assets

$
0.1

Forward Power Contracts in a Liability position

(0.6
)
0.1

Other deferred credits

(0.5
)
Interest Rate Hedges in an Asset position

18.6

—

Other deferred assets

18.6

Total long-term cash flow hedges

$
18.2

$
—

$
18.2

Total cash flow hedges

$
(2.4
)
$
0.7

$
(1.7
)

Fair Value on

$ in millions

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

Forward Power Contracts in a Liability Position

(1.5
)
1.1

Other current liabilities

(0.4
)

Total short-term cash flow hedges

(0.5
)
0.5

—

Long-term Derivative Positions

Forward Power Contracts in a Liability Position

(4.7
)
3.0

Other deferred credits

(1.7
)
Interest Rate Hedges in a Liability Position

(16.8
)
—

Other deferred credits

(16.8
)

Total long-term cash flow hedges

(21.5
)
3.0

(18.5
)

Total cash flow hedges

$
(22.0
)
$
3.5

$
(18.5
)

(1)Includes credit valuation adjustment.
(2)Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at December 31, ~~2010~~2011 (Successor)

~~DPL~~

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

Forward Power Contracts in a Liability Position

$
(2.8
)
$
1.0

Other current liabilities

$
(1.8
)

(0.2
)
—

Other current liabilities

(0.2
)
Interest Rate Hedges in a Liability Position

(6.6
)
—

Other current liabilities

(6.6
)

Total short-term cash flow hedges

$
(9.4
)
$
1.0

$
(8.4
)

1.3

(0.9
)

0.4

Long-term Derivative Positions

Forward Power Contracts in an Asset Position

$
0.2

$
(0.2
)
Other deferred assets

$
—

0.1

(0.1
)
Other deferred assets

—

Forward Power Contracts in a Liability Position

(0.2
)
0.1

Other deferred credits

(0.1
)

(2.6
)
1.7

Other deferred credits

(0.9
)
Interest Rate Hedges in an Asset Position

20.7

—

Other deferred credits

20.7

Interest Rate Hedges in a Liability Position

(32.5
)
—

Other deferred credits

(32.5
)

Total long-term cash flow hedges

$
20.7

$
(0.1
)

$
20.6

(35.0
)
1.6

(33.4
)

Total cash flow hedges

$
11.3

$
0.9

$
12.2

$
(33.7
)
$
0.7

$
(33.0
)

(1)Includes credit valuation adjustment.
(2)Includes counterparty and collateral netting.
40

~~Table of Contents~~
~~The following tables show the fair value and balance sheet classification of~~ ~~DP&L’s~~ ~~derivative instruments designated as hedging instruments at June 30, 2011 and December 31, 2010.~~
~~Fair Values of Derivative Instruments Designated as Hedging Instruments~~
~~at June 30, 2011~~
~~DP&L~~

Fair Value on

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Balance Sheet

Short-term Derivative Positions

Forward Power Contracts in an Asset position

$
0.3

$
(0.3
)
Other prepayments and current assets

$
—

Forward Power Contracts in a Liability position

(2.2
)
1.0

Other current liabilities

(1.2
)

Total short-term cash flow hedges

$
(1.9
)
$
0.7

$
(1.2
)

Long-term derivative positions

Forward Power Contracts in an Asset position

$
0.2

$
(0.1
)
Other deferred assets

$
0.1

Forward Power Contracts in a Liability position

(0.6
)
0.1

Other deferred credits

(0.5
)

Total long-term cash flow hedges

$
(0.4
)
$
—

$
(0.4
)

Total cash flow hedges

$
(2.3
)
$
0.7

$
(1.6
)
~~(1)Includes credit valuation adjustment.~~
~~(2)Includes counterparty and collateral netting.~~
~~Fair Values of Derivative Instruments Designated as Hedging Instruments~~
~~at December 31, 2010~~
~~DP&L~~

Fair Value on

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Balance Sheet

Short-term Derivative Positions

Forward Power Contracts in a Liability Position

$
(2.8
)
$
1.0

Other current liabilities

$
(1.8
)

Total short-term cash flow hedges

$
(2.8
)
$
1.0

$
(1.8
)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position

$
0.2

$
(0.2
)
Other deferred assets

$
—

Forward Power Contracts in a Liability Position

(0.2
)
0.1

Other deferred credits

(0.1
)

Total long-term cash flow hedges

$
—

$
(0.1
)

$
(0.1
)

Total cash flow hedges

$
(2.8
)
$
0.9

$
(1.9
)
~~(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.

4133

Table of Contents

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 ~~revenue~~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 ~~June 30, 2011~~March 31, 2012 and ~~2010.~~2011:

For the three months ended ~~June 30, 2011~~March 31, 2012 (Successor)

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
(10.2
)
$
(1.4
)
$
0.1

$
(0.1
)
$
(11.6
)

$
(7.8
)
$
(0.1
)
$
(0.1
)
$
1.4

$
(6.6
)
Realized gain / (loss)

1.4

0.6

0.2

(1.3
)
0.9

(5.0
)
0.9

(0.2
)
(2.3
)
(6.6
)
Total

$
(8.8
)
$
(0.8
)
$
0.3

$
(1.4
)
$
(10.7
)

$
(12.8
)
$
0.8

$
(0.3
)
$
(0.9
)
$
(13.2
)

Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(5.0
)
$
—

$
—

$
—

$
(5.0
)
Partners’ share of gain / (loss)

$
(3.5
)
$
—

$
—

$
—

$
(3.5
)
Regulatory (asset) / liability

(2.3
)
(0.9
)
—

—

(3.2
)

(1.1
)
0.1

—

—

(1.0
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
(3.1
)
$
(3.1
)
Revenue

—

—

—

3.4

3.4

Purchased power

—

—

0.3

1.7

2.0

—

—

(0.3
)
(4.3
)
(4.6
)
Fuel

(1.5
)
—

—

—

(1.5
)

(8.2
)
0.6

—

—

(7.6
)
O&M

—

0.1

—

—

0.1

—

0.1

—

—

0.1

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
(1.4
)
$
(10.7
)

$
(12.8
)
$
0.8

$
(0.3
)
$
(0.9
)
$
(13.2
)

For the three months ended ~~June 30, 2010~~March 31, 2011 (Predecessor)

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
14.1

$
(0.6
)
$
0.2

$
(0.9
)
$
1.0

$
13.8

$
(3.5
)
$
3.0

$
(0.1
)
$
0.6

$
—

Realized gain / (loss)

0.7

(0.5
)
(0.3
)
(0.2
)
—

(0.3
)

2.4

0.4

(0.8
)
(0.8
)
1.2

Total

$
14.8

$
(1.1
)
$
(0.1
)
$
(1.1
)
$
1.0

$
13.5

$
(1.1
)
$
3.4

$
(0.9
)
$
(0.2
)
$
1.2

Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
7.8

$
—

$
—

$
—

$
—

$
7.8

Partners’ share of gain / (loss)

$
(2.4
)
$
—

$
—

$
—

$
(2.4
)
Regulatory (asset) / liability

4.1

(0.3
)
—

—

—

3.8

0.3

1.6

—

—

1.9

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
(1.1
)
$
—

$
(1.1
)
Revenue

—

—

—

(1.6
)

(1.6
)
Purchased power

—

—

(0.1
)
—

—

(0.1
)

—

—

(0.9
)
1.4

0.5

Fuel

2.9

(0.6
)
—

—

1.0

3.3

1.0

1.7

—

2.7

O&M

—

(0.2
)
—

—

—

(0.2
)

—

0.1

—

0.1

Total

$
14.8

$
(1.1
)
$
(0.1
)
$
(1.1
)
$
1.0

$
13.5

$
(1.1
)
$
3.4

$
(0.9
)
$
(0.2
)
$
1.2

42

~~Table of Contents~~
~~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
)
$
0.5

$
(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:

Partner’s share of gain / (loss)

$
(7.4
)
$
—

$
—

$
—

$
(7.4
)
Regulatory (asset) / liability

(2.0
)
0.6

—

—

(1.4
)

Recorded in Income Statement: gain / (loss)

Retail 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
)
~~For the six months ended June 30, 2010~~
$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

Change in unrealized gain / (loss)

$
2.7

$
0.2

$
(0.3
)
$
0.2

$
—

$
2.8

Realized gain / (loss)

1.1

(1.1
)
(1.0
)
(0.1
)
—

(1.1
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
1.8

$
—

$
—

$
—

$
—

$
1.8

Regulatory (asset) / liability

0.4

—

—

—

—

0.4

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
0.1

$
—

$
0.1

Purchased power

—

—

(1.3
)
—

—

(1.3
)
Fuel

1.6

(0.9
)
—

—

—

0.7

O&M

—

—

—

—

—

—

Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

4334

Table of Contents

The following ~~tables show the amount and classification within the Condensed Statements of Results of Operations or Condensed Balance Sheets of the gains and losses on~~ ~~DP&L’s~~ ~~derivatives not designated as hedging instruments for the three and six months ended June 30, 2011 and 2010.~~
~~For the three months ended June 30, 2011~~
$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
(10.2
)
$
(1.4
)
$
0.1

$
0.3

$
(11.2
)
Realized gain / (loss)

1.4

0.6

0.2

(0.3
)
1.9

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
—

$
(9.3
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(5.0
)
$
—

$
—

$
—

$
(5.0
)
Regulatory (asset) / liability

(2.3
)
(0.9
)
—

—

(3.2
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
—

$
—

Purchased power

—

—

0.3

—

0.3

Fuel

(1.5
)
—

—

—

(1.5
)
O&M

—

0.1

—

—

0.1

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
—

$
(9.3
)
~~For the three months ended June 30, 2010~~
$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

Change in unrealized gain / (loss)

$
14.1

$
(0.6
)
$
0.2

$
(0.9
)
$
1.0

$
13.8

Realized gain / (loss)

0.7

(0.5
)
(0.3
)
(0.2
)
—

(0.3
)
Total

$
14.8

$
(1.1
)
$
(0.1
)
$
(1.1
)
$
1.0

$
13.5

Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
7.8

$
—

$
—

$
—

$
—

$
7.8

Regulatory (asset) / liability

4.1

(0.3
)
—

—

—

3.8

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
(1.1
)
$
—

$
(1.1
)
Purchased power

—

—

(0.1
)
—

—

(0.1
)
Fuel

2.9

(0.6
)
—

—

1.0

3.3

O&M

—

(0.2
)
—

—

—

(0.2
)
Total

$
14.8

$
(1.1
)
$
(0.1
)
$
(1.1
)
$
1.0

$
13.5

44

~~Table of Contents~~
~~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:

Partner’s share of gain / (loss)

$
(7.4
)
$
—

$
—

$
—

$
(7.4
)
Regulatory (asset) / liability

(2.0
)
0.6

—

—

(1.4
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
—

$
—

Purchased power

—

—

(0.8
)
(0.4
)
(1.2
)
Fuel

(0.6
)
1.8

—

—

1.2

O&M

—

0.1

—

—

0.1

Total

$
(10.0
)
$
2.5

$
(0.8
)
$
(0.4
)
$
(8.7
)
~~For the six months ended June 30, 2010~~
$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

Change in unrealized gain / (loss)

$
2.7

$
0.2

$
(0.3
)
$
0.2

$
—

$
2.8

Realized gain / (loss)

1.1

(1.1
)
(1.0
)
(0.1
)
—

(1.1
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
1.8

$
—

$
—

$
—

$
—

$
1.8

Regulatory (asset) / liability

0.4

—

—

—

—

0.4

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
0.1

$
—

$
0.1

Purchased power

—

—

(1.3
)
—

—

(1.3
)
Fuel

1.6

(0.9
)
—

—

—

0.7

O&M

—

—

—

—

—

—

Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

~~The following tables show~~table shows the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at ~~June 30, 2011.~~March 31, 2012:

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at ~~June 30, 2011~~March 31, 2012 (Successor)

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Fair Value (1)

Netting (2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.2

$
—

Other prepayments and current assets

$
0.2

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

6.1

(0.3
)
Other prepayments and current assets

5.8

13.3

—

Other prepayments and current assets

13.3

Forward Power Contracts in a Liability position

(4.5
)
1.3

Other current liabilities

(3.2
)

(7.7
)
5.7

Other current liabilities

(2.0
)
NYMEX-Quality Coal Forwards in an Asset position

12.6

(6.8
)
Other prepayments and current assets

5.8

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

2.6

(2.6
)
Other prepayments and current assets

—

1.6

(1.6
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

$
17.0

$
(8.4
)

$
8.6

(9.4
)
14.4

5.0

Long-term Derivative Positions

Forward Power Contracts in an Asset position

$
6.2

$
(0.1
)
Other deferred assets

$
6.1

4.0

—

Other deferred assets

4.0

Forward Power Contracts in a Liability position

(2.2
)
1.1

Other deferred credits

(1.1
)

(2.3
)
1.0

Other deferred credits

(1.3
)
NYMEX-Quality Coal Forwards in an Asset position

11.5

(6.8
)
Other deferred assets

4.7

NYMEX-Quality Coal Forwards in a Liability position

(0.5
)
0.5

Other deferred credits

—

Heating Oil Futures in an Asset position

0.7

(0.7
)
Other deferred assets

—

NYMEX-quality Coal Forwards in a Liability position

(5.6
)
5.6

Other deferred assets

—

Total long-term derivative MTM positions

$
15.7

$
(6.0
)

$
9.7

(3.9
)
6.6

2.7

Total MTM Position

$
32.7

$
(14.4
)

$
18.3

$
(13.3
)
$
21.0

$
7.7

(1)Includes credit valuation adjustment.
(2)Includes counterparty and collateral netting.
45

~~Table of Contents~~

The following ~~tables show~~table shows the fair value and balance sheet classification of ~~DP&L’s~~ ~~derivative instruments not designated as hedging instruments at June 30, 2011.~~
~~Fair Values of Derivative Instruments Not Designated as Hedging Instruments~~
~~at June 30, 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

$
0.2

$
—

Other prepayments and current assets

$
0.2

Forward Power Contracts in an Asset position

0.4

(0.3
)
Other prepayments and current assets

0.1

Forward Power Contracts in a Liability position

(0.5
)
0.3

Other current liabilities

(0.2
)
NYMEX-Quality Coal Forwards in an Asset position

12.6

(6.8
)
Other prepayments and current assets

5.8

Heating Oil Futures in an Asset position

2.6

(2.6
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

$
15.3

$
(9.4
)

$
5.9

Long-term Derivative Positions

Forward Power Contracts in an Asset position

$
0.4

$
(0.1
)
Other deferred assets

$
0.3

Forward Power Contracts in a Liability position

(0.3
)
0.1

Other deferred credits

(0.2
)
NYMEX-Quality Coal Forwards in an Asset position

11.5

(6.8
)
Other deferred assets

4.7

NYMEX-Quality Coal Forwards in a Liability position

(0.5
)
0.5

Other deferred credits

—

Heating Oil Futures in an Asset position

0.7

(0.7
)
Other deferred assets

—

Total long-term derivative MTM positions

$
11.8

$
(7.0
)

$
4.8

Total MTM Position

$
27.1

$
(16.4
)

$
10.7

~~The following tables show the fair value and balance sheet classification of~~ DPL’s ~~and~~ ~~DP&L’s~~ derivative instruments not designated as hedging instruments at December 31, ~~2010.~~2011:

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, ~~2010~~2011 (Successor)

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Fair Value (1)

Netting (2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.3

$
—

Other prepayments and current assets

$
0.3

$
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

(0.1
)
—

Other current liabilities

(0.1
)

(6.5
)
2.6

Other current liabilities

(3.9
)
NYMEX-Quality Coal Forwards in an Asset position

14.0

(7.4
)
Other prepayments and current assets

6.6

NYMEX-quality Coal Forwards in a Liability position

(8.3
)
4.6

Other current liabilities

(3.7
)
Heating Oil Futures in an Asset position

0.5

(0.5
)
Other current liabllities

—

1.8

(1.8
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

$
14.7

$
(7.9
)

$
6.8

(3.0
)
5.4

2.4

Long-term Derivative Positions

NYMEX-Quality Coal Forwards in an Asset position

$
23.5

$
(14.5
)
Other deferred assets

$
9.0

Heating Oil Futures in an Asset position

1.1

(1.1
)
Other deferred assets

—

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

$
24.6

$
(15.6
)

$
9.0

(4.4
)
7.5

3.1

Total MTM Position

$
39.3

$
(23.5
)

$
15.8

$
(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. IfEven though our debt ~~were to fall~~has fallen below investment grade, ~~we would be in violation of these provisions, and the~~our counterparties to the derivative instruments ~~could request~~have not requested immediate payment or ~~demand~~demanded 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~~
35

Table of ~~further downgrades related to the Proposed Merger with AES that could trigger such provisions. See Note 16 of Notes to Condensed Consolidated Financial Statements.~~Contents

The aggregate fair value of DPL’s commodity derivative instruments that are in a MTM loss position at ~~June 30, 2011~~March 31, 2012 is ~~$9.9~~$38.6 million. This amount is offset by ~~$2.9~~$26.0 million of collateral posted directly with third parties and in a broker margin account which offsets our loss positions on the forward ~~power~~ contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of ~~$1.1~~$0.9 million. If our ~~debt~~counterparties were to ~~fall below investment grade,~~call for collateral, we ~~would~~could have to post collateral for the remaining ~~$5.9~~$11.7 million.
46

~~Table of Contents~~
~~The aggregate fair value of~~ ~~DP&L’s~~ derivative instruments that are in a MTM loss position at June 30, 2011 is $4.1 million. This amount is offset by $0.9 million in a broker margin account which offsets our loss positions on the forward power contracts. This liability position is further offset by the asset position of counterparties with master netting agreements of $1.1 million. If ~~DP&L~~ ~~debt were to fall below investment grade,~~ ~~DP&L~~ ~~would have to post collateral for the remaining $2.1 million.~~
~~10.~~~~Share-Based Compensation~~
Share-based compensation expense was $1.3 million ($0.9 million net of tax) and $1.3 million ($0.9 million net of tax) for the three months ended June 30, 2011 and 2010, respectively, and $2.7 million ($1.8 million net of tax) and $2.6 million ($1.7 million net of tax) for the six months ended June 30, 2011 and 2010, respectively.
~~Share-based awards issued in~~ ~~DPL’s~~ ~~common stock will be distributed from treasury stock.~~ ~~DPL~~ ~~has sufficient treasury stock to satisfy all outstanding share-based awards.~~
~~Summarized share-based compensation activity for the three months ended June 30, 2011 and 2010 was as follows:~~

Options

RSUs

Performance Shares

2011

2010

2011

2010

2011

2010

Outstanding at beginning of period

100,500

351,500

—

3,311

296,591

307,985

Granted

—

—

—

—

—

—

Dividends

—

—

—

—

—

—

Exercised

(75,000
)
—

—

—

—

—

Expired

(25,000
)
—

—

—

—

—

Forfeited

—

—

—

—

—

—

Outstanding at period end

500

351,500

—

3,311

296,591

307,985

Exercisable at period end

500

351,500

—

—

—

—

Management Performance

Restricted Shares

Shares

2011

2010

2011

2010

Outstanding at beginning of period

286,737

219,782

111,298

110,706

Granted

—

29,591

—

—

Dividends

—

—

—

—

Exercised

(2,500
)
—

—

—

Expired

—

—

—

—

Forfeited

—

(272
)
—

—

Outstanding at period end

284,237

249,101

111,298

110,706

Exercisable at period end

—

—

—

—

Director RSUs

2011

2010

Outstanding at beginning of period

16,528

20,944

Granted

—

15,752

Dividends accrued

624

683

Exercised and issued

(2,066
)
(2,618
)
Exercised and deferred

(15,086
)
(18,817
)
Forfeited

—

—

Outstanding at period end

—

15,944

Exercisable at period end

—

—

47

~~Table of Contents~~
~~Summarized share-based compensation activity for the six months ended June 30, 2011 and 2010 was as follows:~~

Options

RSUs

Performance Shares

2011

2010

2011

2010

2011

2010

Outstanding at beginning of year

351,500

417,500

—

3,311

278,334

237,704

Granted

—

—

—

—

85,093

161,534

Dividends

—

—

—

—

—

—

Exercised

(75,000
)
(66,000
)
—

—

—

(91,253
)
Expired

(276,000
)
—

—

—

(66,836
)
—

Forfeited

—

—

—

—

—

—

Outstanding at period end

500

351,500

—

3,311

296,591

307,985

Exercisable at period end

500

351,500

—

—

—

—

Management Performance

Restricted Shares

Shares

2011

2010

2011

2010

Outstanding at beginning of year

219,391

218,197

104,124

84,241

Granted

67,346

34,176

49,510

37,480

Dividends

—

—

—

—

Exercised

(2,500
)
(3,000
)
(7,911
)
—

Expired

—

—

(31,081
)
—

Forfeited

—

(272
)
(3,344
)
(11,015
)
Outstanding at period end

284,237

249,101

111,298

110,706

Exercisable at period end

—

—

—

—

Director RSUs

2011

2010

Outstanding at beginning of year

16,320

20,712

Granted

—

15,752

Dividends accrued

1,362

1,154

Exercised and issued

(2,066
)
(2,618
)
Exercised and deferred

(15,616
)
(19,056
)
Forfeited

—

—

Outstanding at period end

—

15,944

Exercisable at period end

—

—

11. Common Shareholders’ Equity

Effective on the Merger date, DPL ~~has 250,000,000~~ adopted Amended Articles of Incorporation providing for 1,500 authorized common shares, of which ~~117,712,910 are~~one share is outstanding at ~~June 30, 2011.~~
~~On October 27, 2010, the~~ ~~DPL~~ ~~Board of Directors approved a new Stock Repurchase Program under which~~ ~~DPL~~ may repurchase up to $200 million of its common stock from time to time in the open market, through private transactions or otherwise. This 2010 Stock Repurchase Program is scheduled to run through DecemberMarch 31, ~~2013 but may be modified or terminated at any time without notice. Under this 2010 Stock Repurchase Program,~~ ~~DPL~~ repurchased 2.04 million shares at an average per share price of $25.75 during the fourth quarter of 2010. No share repurchases were made during the six months ended June 30, 2011. At June 30, 2011, the amount still available that could be used to repurchase stock under this program is approximately $147.5 million. As a result of the Proposed Merger with The AES Corporation, discussed further in Note 16 of Notes to Condensed Consolidated Financial Statements, the 2010 Stock Repurchase Program has been suspended.2012.

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program ~~under which~~that permitted DPL ~~may~~to use proceeds from the exercise of DPL warrants ~~held~~ 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 iswas scheduled to run through June 30, 2012, ~~which is three months after~~but was suspended in connection with the ~~end of the warrant exercise period. Under this 2009 Stock Repurchase Program,~~ ~~DPL~~ repurchased a total of 145,915 shares during the three months ended March 31, 2010 at an average per share price of $26.71, effectively utilizing the entire $3.9 million that was available to repurchase stock at December 31, 2009. As a result of the Proposed Merger with The AES Corporation, discussed ~~further~~ in Note ~~16 of Notes to Condensed Consolidated Financial Statements, the 2009 Stock Repurchase Program has been suspended.~~2. In June 2011, 0.7 million warrants were exercised with proceeds of $14.7 million. Since the Stock Repurchase Program ~~has been~~was suspended, the proceeds from the June 2011 exercise of warrants ~~and proceeds received from any future exercise of warrants will~~were not be used to repurchase stock.

48

~~Table~~As a result of ~~Contents~~
~~Pursuant~~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 ~~agreement,~~holders an amount equal to $9.00 per warrant, which is the difference between the merger consideration of $30.00 per share of DPL ~~has authorized~~ common ~~shares sufficient to provide for~~stock and the exercise ~~in full~~price of ~~all outstanding warrants.~~$21.00 per share. This amount was recorded as a $9.0 million liability at the Merger date. At ~~June 30,~~December 31, 2011, DPL had 1.0 million outstanding warrants which were exercised in March 2012. At March 31, 2012, there are ~~exercisable in the future.~~no remaining warrants outstanding.

~~Rights Agreement~~ESOP
~~DPL~~ ~~has~~In October 1992, our Board of Directors approved the formation of a ~~Rights Agreement, dated as~~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 ~~September 25, 2001,~~service in accordance with ~~Computershare Trust Company, N.A. (the “Rights Agreement”). The Rights Agreement attached one right to each common share outstanding at~~ the ~~close of business on December 31, 2001. The rights separate from~~match formula effective for the ~~common~~respective plan match year; other compensation shares ~~and become exercisable at the exercise price of $130 per right in the event of certain attempted business combinations.~~awarded vested immediately.

~~The Rights Agreement~~During December 2011, the ESOP Plan was ~~amended as of April 19, 2011,~~terminated and participant balances were transferred to ~~provide that neither the execution~~one of the ~~Merger Agreement nor~~two DP&L sponsored defined contribution 401(k) plans. On December 5, 2011, the ~~consummation~~ESOP Trust paid the total outstanding principal and interest of $68.2 million on the ~~transactions contemplated by~~loan with DPL, using the ~~Merger Agreement will trigger the provisions of the Rights Agreement. As amended,~~merger proceeds from DPL ~~plans to keep~~common stock held within the ~~Rights Agreement in place until just prior to the effective time of the Proposed Merger.~~ESOP suspense account.

12. ~~EPS~~Earnings per Share

Basic EPS is based on the weighted-average number of DPL common shares outstanding during the year. Diluted EPS is based on the weighted-average number of DPL common and common-equivalent shares outstanding during the year, except in periods where the inclusion of such common-equivalent shares is anti-dilutive. Excluded from outstanding shares for these weighted-average computations ~~are~~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 ~~June 30, 2011~~March 31, 2011. Effective with the Merger with AES, DPL is wholly owned by AES and ~~2010. These shares may be dilutive in the future.~~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

Three Months Ended June 30,

Three Months Ended March 31,

Three Months Ended March 31,

2011

2010

2012

2011

$ and shares in millions except

Per

Per

Per

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Income

Shares

Share

Income

Shares

Share

Basic EPS

$
31.7

114.2

$
0.28

$
61.4

115.7

$
0.53

N/A

N/A

N/A

$
43.5

114.0

$
0.38

Effect of Dilutive Securities:

Warrants

0.5

0.4

N/A

0.3

Stock options, performance and restricted shares

0.2

0.1

N/A

0.2

Diluted EPS

$
31.7

114.9

$
0.28

$
61.4

116.2

$
0.53

N/A

N/A

N/A

$
43.5

114.5

$
0.38

Six Months Ended June 30,

2011

2010

$ and shares in millions except

Per

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

$
75.2

114.1

$
0.66

$
132.4

115.6

$
1.15

Effect of Dilutive Securities:

Warrants

0.4

0.4

Stock options, performance and restricted shares

0.2

0.2

Diluted EPS

$
75.2

114.7

$
0.66

$
132.4

116.2

$
1.14

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13. ~~Insurance Recovery~~
~~On May 16, 2007,~~ ~~DPL~~ filed a claim with Energy Insurance Mutual (EIM) to recoup legal costs associated with our litigation against certain former executives. On February 15, 2010, after having engaged in both mediation and arbitration, ~~DPL~~ and EIM entered into a settlement agreement resolving all coverage issues and finalizing all obligations in connection with the claim. The proceeds from the settlement amounted to $3.4 million, net of associated expenses, and were recorded as a reduction to operation and maintenance expense during the six months ended June 30, 2010.
~~14.~~ Contractual Obligations, Commercial Commitments and Contingencies

DPL Inc. — Guarantees
In the normal course of business, DPL enters into various agreements with its ~~wholly-owned~~wholly owned subsidiaries, DPLE and DPLER and its ~~indirect wholly-owned~~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. ~~Certain of~~ ~~DPL’s~~ financial or performance assurance agreements 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 the provisions, and the counterparties to the assurance agreements could demand alternative credit assurance or, in some instances, early termination. The changes in our credit ratings in April 2011 have not triggered these provisions. ~~DPL’s~~ ~~and~~ ~~DP&L’s~~ credit rating may have additional downgrades as a result of the Proposed Merger discussed in Note 16 of Notes to Condensed Consolidated Financial Statements. This may cause the need for additional credit assurance to satisfy various creditors.

At ~~June 30, 2011,~~March 31, 2012, DPL had ~~$90.2~~$47.4 million of guarantees to third parties for future financial or performance assurance under such agreements, including ~~$73.2~~$47.1 million of guarantees, on behalf of DPLE and DPLER and ~~$17.0~~$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 ~~$2.6 million and $1.0~~$0.4 million at ~~June 30, 2011 and 2010, respectively.~~March 31, 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~~obligations.

~~DP&L —~~ Equity Ownership Interest
DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of ~~June 30, 2011,~~March 31, 2012, DP&L could be responsible for the repayment of 4.9%, or ~~$61.4~~$64.9 million, of a ~~$1,252.5~~$1,324.7 million debt obligation that ~~matures in~~features maturities from 2013 to 2026. This would only happen if this electric generation company defaulted on its debt payments. As of ~~June 30, 2011,~~March 31, 2012, we have no knowledge of such a default.
~~Other than the guarantees discussed in our Annual Report on Form 10-K and the guarantees discussed above,~~ ~~DPL~~ ~~and~~ ~~DP&L~~ do not have any other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commercial Commitments and Contractual Obligations
There have been no material changes, outside the ordinary course of business, to our commercial commitments and to the information disclosed in the contractual obligations table in our ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, 2010 except for the note payable to the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum discussed further in Note 5 of Notes to Condensed Consolidated Financial Statements.2011.

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Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of ~~June 30, 2011,~~March 31, 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. 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.~~ estimated in accordance with the provisions of GAAP.We have ~~reserves~~estimated liabilities of approximately ~~$2.2~~$3.2 million for environmental matters. We evaluate the potential liability related to probable losses quarterly and may revise our estimates. Such revisions in the estimates of the potential liabilities could have a material adverse effect on our results of operations, financial ~~position~~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 ~~plant~~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~~jointly owned Unit 6, in December 2014. ~~We are depreciating~~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 ~~through December 2014 and do not believe that any additional accruals or impairment charges are needed as a result of this decision.~~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,~~station, but have not yet made a final decision. We do not believe that any accruals are needed related to the Hutchings station.

~~Regulation~~DPL revalued DP&L’s investment in the above plants at the estimated fair value for each plant at the Merger date.
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 ~~law,~~CAA, the USEPA sets limits on how much of a pollutant 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.

On October 27, 2003, the USEPA published final rules regarding the equipment replacement provision (ERP) of the routine maintenance, repair and replacement (RMRR) exclusion of the CAA. Activities at power plants that fall within the scope of the RMRR exclusion do not trigger new source review (NSR) requirements, including the imposition of stricter emission limits. On December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. On June 6, 2005, the USEPA issued its final response on the reconsideration of the ERP exclusion. The USEPA clarified its position, but did not change any aspect of the 2003 final rules. This decision was appealed and the D.C. Circuit vacated the final rules on March 17, 2006. The scope of the RMRR exclusion remains uncertain due to this action by the D.C. Circuit, as well as multiple litigations not directly involving us where courts are defining the scope of the exception with respect to the specific facts and circumstances of the particular power plants and activities before the courts. While we believe that we have not engaged in any activities with respect to our existing power plants that would trigger the NSR requirements, if NSR requirements were imposed on any of ~~DP&L’s~~ ~~existing power plants, the results could have a material adverse impact on us.~~
The USEPA issued a proposed rule on October 20, 2005, concerning the test for measuring whether modifications to electric generating units should trigger application of NSR standards under the CAA. A supplemental rule was also proposed on May 8, 2007, to include additional options for determining if there is an emissions increase when an existing electric generating unit makes a physical or operational change. The rule was challenged by environmental organizations and has not been finalized. While we cannot predict the outcome of this rulemaking, any finalized rules could materially affect our operations.
~~Interstate~~Cross-State Air ~~Quality~~Pollution Rule
~~On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap SO~~2 ~~and NOx emissions from electric utilities.~~ The ~~proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and~~
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~~Table of Contents~~
~~ozone pollution in other downwind states in the eastern United States. On June 10, 2004, the USEPA issued a supplemental proposal to the IAQR, then renamed the~~ Clean Air Interstate Rule (CAIR)~~. The~~ final rules ~~were signed on March 10, 2005, and~~ were published on May 12, 2005. CAIR created an interstate trading program for annual NOx emission allowances and made modifications to an existing trading program for SO2. ~~On August 24, 2005, the USEPA proposed additional revisions to the CAIR. On July 11, 2008,~~Appeals brought by various parties resulted in a decision by the U.S. Court of Appeals for the District of Columbia Circuit ~~issued a decision~~on July 11, 2008 to vacate ~~the USEPA’s~~ CAIR and its associated Federal Implementation Plan and remanded to the USEPA with instructions to issue new regulations that conformed with the procedural and substantive requirements of the CAA. The Court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 ~~emission trading program established by the March 10, 2005 rules, and created uncertainty regarding future NOx and SO~~2 ~~emission reduction requirements and their timing. The USEPA and a group representing utilities filed a request on September 24, 2008, for a rehearing before the entire Court.~~Plan. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July ~~11,~~ 2008 decision.

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Table of Contents
In ~~the fourth quarter of 2007,~~ ~~DP&L~~ ~~began a program for selling excess emission allowances, including annual NOxemission allowances and SO~~2 ~~emission allowances that were the subject of CAIR trading programs. In subsequent quarters,~~ ~~DP&L~~ ~~recognized gains from the sale of excess emission allowances~~an attempt to ~~third parties. The Court’s CAIR decision affected the trading market for excess allowances and impacted~~ ~~DP&L’s~~ ~~program for selling additional excess allowances in 2008. In January 2009, we resumed selling excess allowances due~~conform to the ~~revival of the emissions trading market. On~~Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) ~~to replace CAIR. We reviewed this proposal and submitted comments to the USEPA on September 30, 2010. These rules were~~. CATR was finalized as the ~~Cross State~~Cross-State Air Pollution Rule (CSAPR) on July 6, ~~2011. CSAPR responds to the court ruling remanding the 2005 CAIR.~~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 rule is effective January 1, 2012, and allowances will be distributed in the third quarter of 2012.~~ We ~~are in the process of reviewing the regulation, but~~ do not ~~expect~~believe the ~~ruling to~~rule will have a ~~significant impact~~material effect on our operations in ~~2012, but it may impact operation of uncontrolled units in future years.~~
~~In 2007, the~~2012. The Ohio EPA ~~revised their~~has a State Implementation Plan (SIP) ~~to incorporate a~~that incorporates the CAIR program ~~consistent with the IAQR. The Ohio EPA had received partial approval from~~requirements, which remain in effect pending judicial review of CSAPR. If CSAPR becomes effective, the USEPA and had been awaiting full program approval from the USEPA when the U.S. Court of Appeals issued its July 11, 2008 decision. As a result of the December 23, 2008 order, the Ohio EPA proposed revised rules on May 11, 2009, which were finalized on July 15, 2009. On September 25, 2009, the USEPA issued a full SIP approval for the Ohio CAIR program. CSAPR, finalized on July 6, 2011, institutesis expected to institute a federal implementation plan (FIP) in lieu of state SIPs ~~for 2012~~ and ~~allows~~allow for the states to develop SIPs for approval as early as 2013. ~~We do not expect~~DP&L is unable to estimate the ~~FIP will~~effect of the new requirements; however, CSAPR could have a ~~significant impact~~material adverse effect on our operations.

Mercury and Other Hazardous Air Pollutants
On January 30, 2004, the USEPA published its proposal to restrict mercury and other air toxins from coal-fired and oil-fired utility plants. The USEPA “de-listed” mercury as a hazardous air pollutant from coal-fired and oil-fired utility plants and, instead, proposed a cap-and-trade approach to regulate the total amount of mercury emissions allowed from such sources. The final Clean Air Mercury Rule (CAMR) was signed March 15, 2005, and was published on May 18, 2005. On March 29, 2005, nine states sued the USEPA, opposing the cap-and-trade regulatory approach taken by the USEPA. In 2007, the Ohio EPA adopted rules implementing the CAMR program. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit struck down the USEPA regulations, finding that the USEPA had not complied with statutory requirements applicable to “de-listing” a hazardous air pollutant and that a cap-and-trade approach was not authorized by law for “listed” hazardous air pollutants. A request for rehearing before the entire Court of Appeals was denied and a petition for review before the U.S. Supreme Court was filed on October 17, 2008. On February 23, 2009, the U.S. Supreme Court denied the petition. On May 3, 2011, the USEPA published proposed Maximum Achievable Control Technology (MACT) standards for coal- and oil-fired electric generating ~~units~~units. The standards include new requirements for emissions of mercury and ~~is expected to finalize this~~a number of other heavy metals. The USEPA Administrator signed the final rule, ~~during~~now called MATS (Mercury and Air Toxics Standards), on December 16, 2011, and the ~~quarter ending December 31, 2011. Upon publication~~rule was published in the Federal Register ~~following finalization, affected~~on February 16, 2012. Affected electric generating units (EGUs) will have ~~three years~~ to come into compliance with the new ~~requirements.~~requirements by April 16, 2015, but may be granted an additional year contingent on Ohio EPA approval. DP&L is ~~unable to determine the impact on its financial condition or results of operations or~~evaluating the costs that may be incurred to comply with ~~any~~the new requirement; however, ~~a MACT standard~~MATS could have a material adverse effect on our operations and result in material compliance costs.
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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. ~~The compliance date is March 21, 2014.~~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” ~~(NESHAP)~~ for compression ignition (CI) reciprocating internal combustion engines (RICE). The units affected at DP&L are 18 diesel electric generating engines and eight emergency “black start” engines. The existing CI RICE units must comply by May 3, 2013. The regulations contain emissions limitations, operating limitations and other requirements. Compliance costs on DP&L’s operations are not expected to be ~~material to~~ ~~DP&L’s~~ ~~operations.~~material.

~~National Ambient Air Quality Standards~~
On January 5, 2005, the USEPA published its final non-attainment designations for the National Ambient Air Quality Standard (NAAQS) for Fine Particulate Matter 2.5 (PM 2.5). These designations included countiesCarbon Emissions and ~~partial counties in which~~ ~~DP&L~~ ~~operates and/or owns generating facilities. On March 4, 2005,~~ ~~DP&L~~ and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered the USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, the USEPA denied the petitions for reconsideration. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting ~~DP&L’s~~ ~~generation plants. As of June 30, 2011,~~ ~~DP&L’s~~ ~~Stuart, Killen and Hutchings Stations were located in non-attainment areas for the 24-hour PM 2.5 standard.~~ ~~DP&L~~ ~~anticipates that these areas will be re-designated as attainment for PM 2.5 during the second half of 2011. We cannot predict the impact the revisions to the PM 2.5 standard will have on~~ ~~DP&L’s~~ ~~financial condition or results of operations.~~
On May 5, 2004, the USEPA issued its proposed regional haze rule, which addresses how states should determine the Best Available Retrofit Technology (BART) for sources covered under the regional haze rule. Final rules were published July 6, 2005, providing states with several options for determining whether sources in the state should be subject to BART. In the final rule, the USEPA made the determination that CAIR achieves greater progress than BART and may be used by states as a BART substitute. Numerous units owned and operated by us will be impacted by BART. We cannot determine the extent of the impact until Ohio determines how BART will be implemented.
On September 16, 2009, the USEPA announced that it would reconsider the 2008 national ground level ozone standard. This may lead to additional ozone non-attainment areas in 2012, followed by tighter NOx emission standards. ~~DP&L~~ ~~cannot determine the effect of this potential change, if any, on its operations.~~
Effective April 12, 2010, the USEPA implemented revisions to its primary NAAQS for nitrogen dioxide. This change may affect certain emission sources in heavy traffic areas like the I-75 corridor between Cincinnati and Dayton after 2016. Several of our facilities or co-owned facilities are within this area. ~~DP&L~~ ~~cannot determine the effect of this potential change, if any, on its operations.~~
~~Effective August 23, 2010, the USEPA implemented revisions to its primary NAAQS for SO~~2 ~~replacing the current 24-hour standard and annual standard with a one hour standard.~~ ~~DP&L~~ ~~cannot determine the effect of this potential change, if any, on its operations. No effects are anticipated before 2014.~~
~~Climate Change~~Other Greenhouse Gases
In response to a U.S. Supreme Court decision that the USEPA has the authority to regulate CO2 emissions from motor vehicles, the USEPA made a finding that CO2 and certain other GHGs are pollutants under the CAA. Subsequently, under the CAA, USEPA determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. This finding became effective in January 2010. Numerous affected parties have petitioned the USEPA Administrator to reconsider this decision. On April 1, 2010, USEPA signed the “Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards” rule. Under USEPA’s view, this is the final action that renders carbon dioxide and other GHGs “regulated air pollutants” under the CAA.

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 ~~EPA plans~~Tailoring Rule sets forth criteria for determining which facilities are required to ~~propose~~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 GHG standards for new ~~and modified~~ 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 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 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) ~~— later in 2011, and such final standards by May 2012.~~. These latter rules may
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focus on energy efficiency improvements at power plants. We cannot predict the effect of these standards, if any, on DP&L’s operations.

~~Legislation proposed in 2009 to target a reduction in the emission of GHGs from large sources was not enacted.~~ Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 emissions at generating stations we own and co-own is approximately 16 million tons annually. ~~Proposed~~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 ~~will~~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, including electric generating units. ~~The~~DP&L’s first report isto the USEPA was submitted prior to the September 30, 2011 due ~~in the fall of 2011~~date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other ~~impact~~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 Supreme Court rejected federal common law nuisance claims brought initially in 2004 by eight states, the City of New York and three land trusts, who had sought injunctive relief and limitations on GHGs emitted by American Electric Power Company, Inc. (AEP), one of AEP’s subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. TheU.S. Supreme Court ruled that the ~~Clean Air Act and~~USEPA’s regulation of GHGs under the ~~authority given to EPA under that Act to regulate GHGs~~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~~state law. ~~However, such claims appear likely to be dismissed by a lower court on similar pre-emption grounds.~~

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 ~~owner~~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 aan 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 permits that resulted in significant increases in particulate matter, SO2, and NOx. These allegations are consistent with NOVs and complaints that the USEPA had ~~recently~~ brought against numerous other coal-fired utilities in the Midwest. The NOV indicated the USEPA may: (1) issue an order requiring compliance with the requirements of the Ohio SIP; or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. To date, neither action has been taken. DP&L cannot predict the outcome of this matter.

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In December 2007, the Ohio EPA issued aan NOV to the DP&L-operated Killen generating station (co-owned by DP&L and Duke Energy) for alleged violations of the CAA. The ~~NOVs~~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 aan 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
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with similar allegations was issued on November 4, 2010. Also in 2010, USEPA issued an NOV to Zimmer for excess ~~emissions, which may have been resolved through resubmission of monitoring reports.~~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.

~~Other Issues Involving Co-Owned Plants~~
~~In 2006,~~ ~~DP&L~~ ~~detected a malfunction with its emission monitoring system at the~~ ~~DP&L~~~~-operated Killen generating station (co-owned by~~ ~~DP&L~~ ~~and Duke Energy) and ultimately determined its SO~~2 ~~and NOx emissions data were under reported.~~ ~~DP&L~~ ~~has petitioned the USEPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter of 2006.~~ ~~DP&L~~ has sufficient allowances in its general account to cover the understatement. Management does not believe the ultimate resolution of this matter will have a material impact on results of operations, financial condition or cash flows.
Notices of Violation Involving ~~Wholly-Owned~~Wholly Owned Plants
In 2007, the Ohio EPA and the USEPA issued NOVs to DP&L for alleged violations of the CAA at the ~~O.H.~~ Hutchings ~~Station.~~station. The NOVs’ alleged deficiencies relate to stack opacity and particulate emissions. Discussions are under way with the USEPA, the U.S. Department of Justice and Ohio EPA. ~~DP&L~~ ~~has provided data to those agencies regarding its maintenance expenses and operating results. On December 15, 2008,~~ ~~DP&L~~ received a request from the USEPA for additional documentation with respect to those issues and other CAA issues including issues relating to capital expenses and any changes in capacity or output of the units at the O.H. Hutchings Station. During 2009, ~~DP&L~~ ~~continued to submit various other operational and performance data to the USEPA in compliance with its request.~~ ~~DP&L~~ ~~is currently unable to determine the timing, costs or method by which the issues may be resolved and continues to work with the USEPA on this issue.~~
On November 18, 2009, the USEPA issued aan NOV to DP&L for alleged NSR violations of the CAA at the ~~O.H.~~ Hutchings ~~Station~~station relating to capital projects performed in 2001 involving Unit 3 and Unit 6. DP&L does not believe that the ~~two~~ projects described in the NOV were modifications subject to NSR.DP&L is 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 and continues to work with the USEPA on~~resolved. The Ohio EPA is kept apprised of these ~~issues.~~discussions.

~~Regulation~~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 to the Federal Court of Appeals for the Second Circuit in New York and the Court issued an opinion on January 25, 2007, remanding several aspects of the rule to the USEPA for reconsideration. Several parties petitioned the U.S. Supreme Court for review of the lower court decision. On April 14, 2008, the Supreme Court elected to review the lower court decision on the issue of whether the USEPA can compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Briefs were submitted to the Court in the summer of 2008 and oral arguments were held in December 2008.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 and~~2011. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012. ~~We are reviewing the proposed regulation and will be submitting comments.~~ We do not yet know the impact these proposed rules will have on our operations.

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Clean Water Act — Regulation of Water Discharge
On May 4, 2004, the Ohio EPA issued a final National Pollutant Discharge Elimination System permit (the Permit) for J.M. Stuart Station that continued our authority to discharge water from the station into the Ohio River. During the three-year term of the Permit, we conducted a thermal discharge study to evaluate the technical feasibility and economic reasonableness of water cooling methods other than cooling towers. In December 2006, we submitted an application for the renewal of the 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 ~~the~~a thermal discharge ~~study.~~study completed during the previous permit term. Subsequently, ~~representatives from~~ DP&L and the Ohio EPA ~~agreed~~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~~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. ~~We continue attempts~~In a letter to ~~resolve this issue with both~~the Ohio EPA dated September 28, 2011, the USEPA ~~and~~reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA ~~but~~does not re-draft the ~~timing~~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 ~~uncertain.~~considering legal options. Depending on the outcome of the process, the effects could be material on DP&L’s operation.
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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. ~~Subsequent to the information collection effort, it~~It is anticipated that the USEPA will release a proposed rule by ~~mid-2012~~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, ~~Regulation Matters Related~~DP&L received an NOV related to ~~Land Use and Solid Waste Disposal~~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. DP&L will install sedimentation ponds as part of the runoff control measures to address this issue. We expect the impact of this NOV to be immaterial.

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 ~~has~~ granted such access and drilling of soil borings and installation of monitoring wells occurred in late 2009 and early 2010.~~DP&L~~ ~~believes the chemicals used at its service center building site were appropriately disposed of and have not contributed to the contamination at the South Dayton Dump landfill site.~~ On May 24, 2010, three members of the existing PRP group, Hobart Corporation, Kelsey-Hayes Company and NCR Corporation, filed a civil complaint in the United States District Court for the Southern District of Ohio against DP&L and numerous other defendants alleging that DP&L and the other defendants contributed to the contamination at the South Dayton Dump landfill site and seeking reimbursement of the PRP group’s costs associated with the investigation and remediation of the site. ~~DP&L~~ ~~filed a motion to dismiss the complaint and intends to vigorously defend against any claim that it has any financial responsibility to remediate conditions at the landfill site.~~ 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. 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.~~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 ~~us.~~

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

During 2008, a major spill occurred at an ash pond owned by the Tennessee Valley Authority (TVA) as a result of a dike failure. The spill generated a significant amount of national news coverage, and support for tighter regulations for the storage and handling of coal combustion products. ~~DP&L~~ ~~has ash ponds at the Killen, O.H. Hutchings and J.M. Stuart Stations which it operates, and also at generating stations operated by others but in which~~ ~~DP&L~~ ~~has an ownership interest.~~

~~During~~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.~~stations. Subsequently, the USEPA collected similar information for ~~O.H.~~the Hutchings Station. In October 2009, the USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, the USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds. In May 2010, ~~DP&L~~ ~~responded to the USEPA final inspection report with our plans to address the recommendations.~~station.

~~Similarly, in~~In August 2010, the USEPA conducted an inspection of the ~~O.H.~~ Hutchings ~~Station~~station ash ponds. ~~The draft report relating to the inspection was received in November 2010 and~~ ~~DP&L~~ ~~provided comments on the draft report in December 2010.~~ In June 2011, the USEPA issued a final report from the inspection including recommendations relative to the ~~O.H.~~ Hutchings ~~Station~~station ash ponds. DP&L ~~is reviewing the final report and intends to respond to the USEPA with plans to address the recommendations.~~ ~~DP&L~~is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the ~~outcome this inspection will have~~effect on ~~its operations.~~operations that might arise under a different plan.

In June 2011, the USEPA conducted an inspection of the Killen ~~Station~~station ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.

~~In addition, as a result~~42

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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 ~~impact~~effect of this regulation, but if coal combustion byproducts are regulated as hazardous waste, it is expected to have a material adverse ~~impact~~effect on operations.

~~Ohio Regulation~~Notice of Violation Involving Co-Owned Plants

~~SB 221~~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 permit program and the implementation rules contain targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards. If any targets are not met, compliance penalties will apply unless the PUCO makes certain findings that would excuse performance. ~~DP&L~~station’s storm water pollution prevention plan. The notice requested ~~the PUCO’s consent~~ that DP&L ~~had met~~respond with the ~~2009 requirements for energy efficiency~~actions it has subsequently taken or plans to take to remedy the USEPA’s findings and ~~for demand reduction based~~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 ~~interpretation~~results of ~~how those requirements should be applied. These filings also requested that if the PUCO disagreed with~~ ~~DP&L’s~~ ~~interpretation, the PUCO grant alternative relief and find that~~ ~~DP&L~~ was unable to meet the targets due to reasons beyond its reasonable control, i.e., uncertainty throughout 2009 caused by delays in finalizing the rules and the lack of timely PUCO action on several of ~~DP&L’s~~ ~~special contracts relating to demand response efforts which remain pending before the PUCO.~~ ~~DP&L~~ ~~made a filing on April 29, 2011 seeking PUCO authorization to increase the energy efficiency rider to recover costs associated with energy efficiency and peak demand reduction compliance.~~

~~In addition, the implementation rules required that on January 1, 2010,~~ ~~DP&L~~ ~~file an extensive energy efficiency portfolio plan, outlining how~~ ~~DP&L~~ ~~plans to comply with the energy efficiency and demand reduction benchmarks.~~ ~~DP&L~~ ~~filed a separate request for a finding that it had already complied with this requirement in the form of~~ ~~DP&L’s~~ ~~portfolio plan that had been filed in 2008 as part of its CCEM plan, which had been approved by the PUCO and is being implemented. On May 19, 2010 the PUCO approved in part and denied in part~~ ~~DP&L’s~~ ~~request that the PUCO find that it met the 2009 energy efficiency portfolio requirements and directed~~ ~~DP&L~~ to file a measurement and verification plan as well as a market potential study within 60 days of the date of the order. The Company made this filing on July 15, 2010. A settlement was reached in this case and approved by the PUCO in April 2011. On June 1, 2011 ~~DP&L~~ ~~filed an amendment to~~

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~~its Alternative Energy Rider case that is pending before the PUCO. This request will increase the rider to recover additional compliance costs.~~

~~As the energy efficiency and alternative energy targets get increasingly larger over time, the costs of complying with SB 221 and the PUCO’s implementing rules could have a material impact on~~ ~~DP&L’s~~operations, financial ~~condition.~~

~~DP&L~~ established a fuel and purchased power recovery rider beginning January 1, 2010. The fuel rider fluctuates based on actual costs and recoveries and is modified at the start of each seasonal quarter: March 1, June 1, September 1 and December 1 each year. In early 2011, an audit was performed on ~~DP&L’s~~ fuel rider which was conducted by an independent third party in accordance with PUCO standards. As a result there is some uncertainty as to the costs that will be approved for recovery. The audit was completed in the second quarter of 2011 and a hearing has been set by the PUCO for August 30, 2011. Once the PUCO audit approval process is complete, ~~DP&L~~ ~~may record a favorable~~condition or ~~unfavorable adjustment to earnings. Based on past PUCO precedent, we believe these deferred fuel and purchased power costs are probable of future recovery or repayment in the case of over recovery.~~

~~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. SB 221 included a provision that would allow Ohio electric utilities to seek and obtain a reconcilable rider to recover RTO-related costs and credits. ~~DP&L’s~~ TCRR and PJM RPM riders were initially approved in November 2009 to recover these costs. Both the TCRR and the RPM riders assign costs and revenues from PJM monthly bills to retail ratepayers based on the percentage of SSO retail customers’ load and sales volumes to total retail load and total retail and wholesale volumes. Customer switching to CRES providers decreases ~~DP&L’s~~ ~~SSO retail customers’ load and sales volumes. Therefore, increases in customer switching cause more of the RPM capacity costs and revenues to be excluded from the RPM rider calculation.~~ ~~DP&L’s~~ ~~annual true-up of these two riders was approved by the PUCO by an order dated April 27, 2011.~~

~~DP&L~~ entered into an economic development arrangement with its single largest electricity consumer. This arrangement was approved by the PUCO on June 8, 2011 and is effective in July 2011. Under Ohio law, ~~DP&L~~ ~~is permitted to seek recovery of costs associated with economic development programs including foregone revenues from all customers. On June 3, 2011~~ ~~DP&L~~ ~~made a filing seeking PUCO authorization to defer costs associated with any current and future economic development arrangements. This filing is pending.~~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 ~~jointly~~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.

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

~~As a member of PJM,~~ ~~DP&L~~ is also subject to charges and costs associated with PJM operations as approved by the FERC. FERC orders issued in 2007 and thereafter regarding the allocation of costs of large transmission facilities within PJM could result in additional costs being allocated to ~~DP&L~~ ~~of approximately $12 million or more annually by 2012. Although we continue to maintain that these costs should be borne by the beneficiaries of these projects and that~~ ~~DP&L~~ ~~is not one of these beneficiaries, any credits or costs resulting from these proceedings would be reflected in~~ ~~DP&L’s~~ ~~retail transmission rider.~~

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

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into a significant number of ~~bi-lateral~~bilateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. With respect to unsettled claims, DP&L management has deferred ~~$14.1~~$18.1 million and ~~$15.4~~$17.8 million as of ~~June 30, 2011~~March 31, 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 ~~results~~amount at March 31, 2012 and December 31, 2011 includes estimated earnings and interest of ~~this proceeding~~$5.5 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, subject to possible appellate court review. These orders do not ~~expected~~affect prior settlements that had been reached with other parties that owed SECA revenues to ~~have a material adverse effect on~~ DP~~&L’s~~&L ~~results~~or were recipients of ~~operations.~~amounts paid by DP&L. For other parties that had not 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.

~~Refer~~Lawsuits were filed in connection with the Merger seeking, among other things, one or more of the following: to ~~Note 16~~enjoin consummation of ~~Notes~~the Merger until certain conditions were met, to ~~Condensed Consolidated Financial Statements~~rescind the Merger or for ~~additional information surrounding~~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 ~~Proposed~~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.

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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 ~~any related legal matters.~~AES.

~~15.~~14. Business Segments

DPL operates through two segments consisting of the operations of two of its ~~wholly-owned~~wholly owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment) and 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~~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 ~~DPLER’s~~the DPLER and MC Squared competitive retail electric service ~~business~~businesses which ~~sells~~sell retail electric energy under contract to residential, commercial, industrial and ~~industrial~~governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to ~~approximately 15,000~~more than 45,000 customers currently located throughout Ohio and in Illinois. ~~Beginning~~In February ~~28,~~ 2011, ~~the Competitive Retail segment includes the results of~~DPLER purchased MC Squared, a Chicago-based retail electricity ~~supplier. MC Squared was purchased by DPLER on February 28, 2011 and~~supplier, which serves ~~approximately 3,000~~more than 4,000 customers in ~~northern~~Northern Illinois. 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 ~~Ohio~~ sales obligations was purchased from DP&Lat 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. The electric energy used to meet its Illinois sales obligations was purchased from PJM.~~power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of ~~DPLER~~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:

$ in millions

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Three Months Ended June 30, 2011

Revenues from external customers

$
327.6

$
102.0

$
15.3

$
—

$
444.9

Intersegment revenues

81.0

—

1.0

(82.0
)
—

Total revenues

$
408.6

$
102.0

$
16.3

$
(82.0
)
$
444.9

Fuel

89.1

—

3.0

—

92.1

Purchased power

104.4

89.5

0.7

(81.0
)
113.6

Gross margin

$
215.1

$
12.5

$
12.6

$
(1.0
)
$
239.2

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

Three Months Ended June 30, 2010

Revenues from external customers

$
371.2

$
62.8

$
11.5

$
—

$
445.5

Intersegment revenues

52.7

—

1.1

(53.8
)
—

Total revenues

$
423.9

$
62.8

$
12.6

$
(53.8
)
$
445.5

Fuel

88.5

—

2.4

—

90.9

Purchased power

90.3

52.7

0.6

(52.7
)
90.9

Gross margin

$
245.1

$
10.1

$
9.6

$
(1.1
)
$
263.7

Depreciation and amortization

$
33.2

$
0.1

$
2.4

$
—

$
35.7

Interest expense

9.1

—

8.4

—

17.5

Income tax expense (benefit)

28.4

3.1

(1.4
)
—

30.1

Net income (loss)

59.4

5.0

(1.4
)
(1.6
)
61.4

Cash capital expenditures

34.1

—

1.2

—

35.3

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

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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 March 31,
$ in millions	2012			2011

Revenues	$	399.6		$	449.8

Cost of revenues:
Fuel	95.6			98.6
Purchased power	84.9			117.8
Total cost of revenues	180.5			216.4

Gross margin	219.1			233.4

Operating expenses:
Operation and maintenance	99.2			91.4
Depreciation and amortization	34.7			33.1
General taxes	20.2			19.6
Total operating expenses	154.1			144.1

Operating income	65.0			89.3

Other income / (expense), net:
Investment income	0.1			0.6
Interest expense	(9.6		)	(9.7		)
Other income / (expense)	(0.1		)	(0.5		)
Total other income / (expense), net	(9.6		)	(9.6		)

Earnings before income tax	55.4			79.7

Income tax expense	17.3			27.0

Net income	38.1			52.7

Dividends on preferred stock	0.2			0.2

Earnings on common stock	$	37.9		$	52.5

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.

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THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
$ in millions	2012			2011
Cash flows from operating activities:
Net income	$	38.1		$	52.7
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	34.7			33.1
Deferred income taxes	(2.4		)	33.3
Changes in certain assets and liabilities:
Accounts receivable	(0.6		)	11.9
Inventories	(2.0		)	1.3
Taxes applicable to subsequent years	21.5			15.7
Deferred regulatory costs, net	7.1			12.8
Accounts payable	(2.2		)	(4.0		)
Accrued taxes payable	(15.0		)	(28.9		)
Accrued interest payable	7.5			7.6
Pension, retiree and other benefits	2.1			(41.2		)
Unamortized investment tax credit	(0.6		)	(0.7		)
Other	1.4			(9.6		)
Net cash provided by operating activities	89.6			84.0

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

Cash flows from financing activities:
Dividends paid on common stock to parent	(45.0		)	(70.0		)
Dividends paid on preferred stock	(0.2		)	(0.2		)
Withdrawals from revolving credit facilities	—			50.0
Repayment of borrowings from revolving credit facilities	—			(20.0		)
Net cash used for financing activities	(45.2		)	(40.2		)

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

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	2.4		$	2.3
Income taxes paid, net	$	6.1		$	—
Non-cash financing and investing activities:
Accruals for capital expenditures	$	24.1		$	18.3
Long-term liability incurred for the purchase of assets	$	—		$	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
	March 31,			December 31,
$ in millions	2012			2011

ASSETS

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

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

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

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

Total Assets	$	3,501.6		$	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

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

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:
Current portion - long-term debt (Note 6)	$	0.4		$	0.4
Accounts payable	97.8			106.0
Accrued taxes	95.6			72.8
Accrued interest	15.4			7.9
Customer security deposits	16.4			15.8
Other current liabilities	47.3			41.4
Total current liabilities	272.9			244.3

Noncurrent liabilities:
Long-term debt (Note 6)	902.9			903.0
Deferred taxes (Note 7)	634.0			637.7
Regulatory liabilities, non-current (Note 4)	118.5			118.6
Pension, retiree and other benefits	47.7			47.5
Unamortized investment tax credit	29.3			29.9
Other deferred credits	124.3			163.9
Total noncurrent liabilities	1,856.7			1,900.6

Redeemable preferred stock	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
Other paid-in capital	803.1			803.1
Accumulated other comprehensive loss	(36.4		)	(34.7		)
Retained earnings	582.0			589.1
Total common shareholder’s equity	1,349.1			1,357.9

Total Liabilities and Shareholder’s Equity	$	3,501.6		$	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

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 is a wholly owned subsidiary of DPL.

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 people as of March 31, 2012. Approximately 53% 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.

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 Financial Statements presented in this report contain all adjustments necessary to fairly state our financial condition as of March 31, 2012; our results of operations for the three months ended March 31, 2012 and our cash flows for the three months ended March 31, 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 months ended March 31, 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; and assets and liabilities related to employee benefits.

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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 million and $1.1 million for the three months ended March 31, 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 (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.

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

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, 2012 and 2011 were $13.2 million and $14.0 million, respectively. The 2011 amount was 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.

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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 March 31,
$ in millions	2012			2011

DP&L Revenues:
Sales to DPLER (a)	$	83.0		$	75.1

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

(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 months ended March 31, 2012, compared to the three months ended March 31, 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

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.

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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
	March 31,			December 31,
$ in millions	2012			2011

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

Inventories, at average cost:
Fuel and limestone	$	83.9		$	82.8
Plant materials and supplies	39.4			38.6
Other	1.8			1.7
Total inventories, at average cost	$	125.1		$	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, 2012 and December 31, 2011:

	March 31,			December 31,
$ in millions	2012			2011

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

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

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

			At		At
	Type of	Amortization	March 31,		December 31,
$ in millions	Recovery (a)	Through	2012		2011
Current Regulatory Assets:
TCRR, transmission, ancillary and other PJM-related costs	F	Ongoing	$	2.8	$	4.7
Power plant emission fees	C	Ongoing	3.1		4.8
Fuel and purchased power recovery costs	C	Ongoing	6.8		8.2
Total current regulatory assets			$	12.7	$	17.7

Non-current Regulatory Assets:
Deferred recoverable income taxes	B/C	Ongoing	$	23.3	$	24.1
Pension and postretirement benefits	C	Ongoing	90.5		92.1
Unamortized loss on reacquired debt	C	Ongoing	12.6		13.0
Regional transmission organization costs	D	2014	3.7		4.1
Deferred storm costs - 2008	D		18.2		17.9
CCEM smart grid and advanced metering infrastructure costs	D		6.6		6.6
CCEM energy efficiency program costs	F	Ongoing	6.9		8.8
Consumer education campaign	D		3.0		3.0
Retail settlement system costs	D		3.1		3.1
Other costs			5.0		5.1
Total non-current regulatory assets			$	172.9	$	177.8

Non-current Regulatory Liabilities:
Estimated costs of removal - regulated property			$	112.5	$	112.4
Postretirement benefits			6.0		6.2
Total non-current regulatory liabilities			$	118.5	$	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

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.

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. We will have further discussions with interested parties concerning the audit report in the second quarter 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.

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.

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.

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

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.

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.

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, 2012, DP&L had $55.0 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets. 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 Hutchings station at March 31, 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

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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. 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. We do not believe that any accruals or impairment charges are needed related to the Hutchings station.

As part of the provisional DPL purchase accounting adjustments related to the Merger with AES, four plants (Beckjord, Conesville, East Bend and Hutchings) had future expected cash flows that, when discounted, produced a zero fair market value. Since DP&L did not apply push down accounting, this valuation did not affect the book value of these plants’ valuation at DP&L. However, DP&L performed an impairment review of these plants, which is initially based on undiscounted future cash flows and exceed their net book value so no impairment is required as of March 31, 2012. Significant changes in expected future revenues or costs for any of these plants could result in a future impairment charge.

6. Debt Obligations

Long-term debt is as follows:

Long-term Debt

	March 31,			December 31,
$ in millions	2012			2011

First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%	35.3			35.3
Pollution control series maturing in January 2034 - 4.80%	179.1			179.1
Pollution control series maturing in September 2036 - 4.80%	100.0			100.0
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
	902.9			902.9

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

Current portion - Long-term Debt

	March 31,		December 31,
$ in millions	2012		2011

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	$	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.

At March 31, 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

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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 months ended March 31, 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, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three months ended March 31, 2012 and 2011. This facility also contains a $50 million letter of credit sublimit. As of March 31, 2012, DP&L had no outstanding letters of credit against the facility.

On March 1, 2011, DP&L completed the purchase of $18.7 million 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, 2012 and December 31, 2011. Fees associated with this revolving credit facility were not material during the three months ended March 31, 2012 and 2011. This facility also contains a $50 million letter of credit sublimit. As of March 31, 2012, DP&L had no outstanding letters of credit against the facility.

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

7. Income Taxes

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

	Three Months Ended
	March 31,
	2012		2011

DP&L	31.3	%	34.0	%

Income tax expenses for the three months ended March 31, 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% 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, 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 by approximately $3.7 million during the three months ended March 31, 2012. These decreases were primarily related to depreciation.

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$ in millions

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Six Months Ended June 30, 2011

Revenues from external customers

$
716.3

$
196.0

$
27.3

$
—

$
939.6

Intersegment revenues

156.1

—

2.0

(158.1
)
—

Total revenues

$
872.4

$
196.0

$
29.3

$
(158.1
)
$
939.6

Fuel

187.7

—

4.2

—

191.9

Purchased power

222.2

167.2

1.1

(156.1
)
234.4

Gross margin

$
462.5

$
28.8

$
24.0

$
(2.0
)
$
513.3

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

Six Months Ended June 30, 2010

Revenues from external customers

$
771.9

$
104.6

$
20.2

$
—

$
896.7

Intersegment revenues

90.0

—

2.2

(92.2
)
—

Total revenues

$
861.9

$
104.6

$
22.4

$
(92.2
)
$
896.7

Fuel

189.1

—

3.7

—

192.8

Purchased power

162.9

90.0

0.8

(90.0
)
163.7

Gross margin

$
509.9

$
14.6

$
17.9

$
(2.2
)
$
540.2

Depreciation and amortization

$
68.0

$
0.1

$
5.0

$
—

$
73.1

Interest expense

18.5

—

16.9

—

35.4

Income tax expense (benefit)

65.2

4.3

(3.0
)
—

66.5

Net income (loss)

131.5

7.1

(3.4
)
(2.8
)
132.4

Cash capital expenditures

73.5

—

1.6

—

75.1

Total Assets

June 30, 2011

$
3,435.0

$
59.5

$
1,698.2

$
(1,481.1
)
$
3,711.6

December 31, 2010

$
3,475.4

$
35.7

$
1,828.8

$
(1,526.6
)
$
3,813.3

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

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 months ending March 31, 2012. DP&L made a discretionary contribution of $40.0 million to the defined benefit plan in the three months ended March 31, 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.

The net periodic benefit cost (income) of the pension and postretirement benefit plans for the three months ended March 31, 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		$	—

(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.

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

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

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~~16. Proposed Merger with~~ 9. Fair Value Measurements

The ~~AES Corporation~~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 estimates of possible value that may or may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at March 31, 2012 and December 31, 2011. See also Note 10 for the fair values of our derivative instruments.

	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 (a)	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
	$	9.5	$	11.0	$	9.4	$	10.3

Liabilities
Debt	$	903.3	$	930.6	$	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 as debt is presented at amortized cost in the financial statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 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 million ($1.0 million after tax) in unrealized gains and immaterial unrealized losses on the Master Trust assets in AOCI at March 31, 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

~~On April 19, 2011,~~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, 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, 2012, ~~DPL~~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
Money Market Fund (a)	$	0.2	$	0.2	$	—	Immediate

Equity Securities (b)	5.0		4.4		—		Immediate

Debt Securities (c)	5.5		5.5		—		Immediate

Multi-Strategy Fund (d)	0.3		0.2		—		Immediate

Total	$	11.0	$	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 AES Corporation,~~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 ~~Delaware corporation (“AES”), entered into an Agreement~~mix of actively managed funds holding investments in stocks, bonds and ~~Plan of Merger (the “Merger Agreement”) whereby AES will acquire~~ ~~DPL~~ ~~for $30.00 per share~~short-term investments in a ~~cash~~mix of actively managed funds. Investments in this category can be redeemed immediately at the current net asset value per unit.

Fair Value Hierarchy

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction ~~valued at approximately $3.5 billion plus~~between market participants on the ~~assumption~~measurement date. The fair value hierarchy requires an entity to maximize the use of ~~$1.2 billion~~observable inputs and minimize the use of ~~debt. Upon closing,~~ ~~DPL~~ ~~will become~~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 ~~wholly-owned subsidiary~~large rating agency.

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

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The ~~transaction has been unanimously approved~~fair value of assets and liabilities at March 31, 2012 and December 31, 2011 measured on a recurring basis and the respective category within the fair value hierarchy for DP&L was determined as follows:

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
				Level 1		Level 2			Level 3
$ 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	)

*Includes credit valuation adjustments for counterparty 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	)

*Includes credit valuation adjustments for counterparty 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 ~~each~~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 ~~DPL’s~~day NAV per unit.

Our debt is fair valued for disclosure purposes only and ~~AES’ board of directors, but is subject to certain conditions, including receipt~~most of the ~~approval of~~ ~~DPL~~ ~~shareholders~~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 ~~receipt~~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.

Approximately 99% of ~~all required regulatory approvals~~the inputs to the fair value of our derivative instruments are from ~~among others,~~quoted market prices for DP&L.

Non-recurring Fair Value Measurements

We use the ~~FERC~~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 months ended March 31, 2012 and 2011.

10. Derivative Instruments and Hedging Activities

In the ~~PUCO. On May 18, 2011,~~normal course of business, ~~DPL~~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 ~~AES filed merger applications~~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 ~~FERC and~~same counterparty are netted on the ~~PUCO.~~balance sheets if we have a Master Netting Agreement with the counterparty. We ~~expect a two~~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 ~~three month review~~determine whether new or offsetting transactions are required. The objective of the ~~FERC application~~hedging program is to mitigate financial risks while ensuring that we have adequate resources to meet our requirements. We monitor and a six to nine month review of the PUCO application. The FERC application will be deemed approved after 180 days, unless the FERC tolls for good cause the completed application for further consideration, which may or may not occurvalue derivative positions monthly as part of ~~the FERC’s review. Also on May 18, 2011,~~ ~~DPL~~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 ~~AES~~are designated as cash flow hedges or marked to market each filed their respective Premerger Notification and Report Forms with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Those filings initiated a statutory 30-day waiting period, which expired on June 14, 2011, when early termination of the waiting period was granted. The Vermont Department of Banking, Insurance, Securities and Health Care Administration also issued a formal approval with respect to the Proposed Merger on May 18, 2011. The parties anticipate receiving additional approvals and then closing the transaction during the fourth quarter of 2011 or first quarter of 2012.

The Merger Agreement includes customary representations, warranties and restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the Proposed Merger or termination of the Merger Agreement. Among other restrictions, without the consent of AES, the Merger Agreement limits our total capital expenditures, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior consent of AES, increase our quarterly common stock dividend of $0.3325 per share.

~~DPL~~ ~~expects to continue its policy of paying regular quarterly cash dividends until closing. Dividends are expected to be paid on a prorated basis during the quarter in which the transaction closes.~~reporting period.

At March 31, 2012, 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	2.8	—		2.8
Heating Oil Futures	Mark to Market	Gallons	1,680.0	—		1,680.0
Forward Power Contracts	Cash Flow Hedge	MWh	881.0	(107.2	)	773.8
Forward Power Contracts	Mark to Market	MWh	618.7	(618.7	)	—
NYMEX-quality Coal Contracts*	Mark to Market	Tons	1,410.5	—		1,410.5

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

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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

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 ~~Merger Agreement also includes certain provisions whereby we have agreed~~fair value of cash flow hedges as determined by current public market prices will continue to ~~use commercially reasonable efforts~~fluctuate with changes in market prices up to ~~replace~~ ~~DP&L’s~~ ~~existing $220.0 million revolving credit facility. We have agreed~~contract expiration. The effective portion of the hedging transaction is recognized in AOCI and transferred to ~~replace this facility with a new revolving credit facility~~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 ~~an amount equal~~earnings in the current period. All risk components were taken into account to ~~or greater than $200.0 million with a term~~determine the hedge effectiveness of ~~at least three years.~~ ~~DPL~~ has also agreed to use commercially reasonable efforts to enter into a revolving credit facility in an amount equal to or greater than $125.0 million with a term of at least three years and to enter into a $425.0 million term loan with a term of at least three years, in part, to refinance the ~~approximately $297.4 million principal amount of~~ ~~DPL’s~~ ~~6.875% debt that is due in September 2011.~~cash flow hedges.

We ~~believe that Dolphin Subsidiary II, Inc., a subsidiary~~enter into forward power contracts to manage commodity price risk exposure related to our generation of ~~AES, is planning to issue $1.25 billion~~electricity. We do not hedge all commodity price risk. We reclassify gains and losses on forward power contracts from AOCI into earnings in ~~long-term Senior Notes prior to~~those periods in which the consummation of the Proposed Merger and that the proceeds from these notes will be used to partially finance the Proposed Merger. Upon the consummation of the Proposed Merger, these notes are expected to become long-term debt obligations of ~~DPL~~. ~~DPL~~ ~~will not have any obligation associated with these notes if the Proposed Merger is not consummated.~~contracts settle.

~~The Merger Agreement restricts~~ ~~DPL~~ ~~from soliciting or initiating discussions with third parties regarding other proposals to acquire~~ ~~DPL~~, subject to certain exceptions for responding to unsolicited third party acquisition proposals and engaging in discussions and negotiations regarding unsolicited third party acquisition proposals. The Merger Agreement also contains certain termination rights for both ~~DPL~~ ~~and AES. Upon termination under specified circumstances,~~ ~~DPL~~ ~~will be required to pay AES a termination fee~~66

Table of ~~$106 million.~~Contents

The following ~~lawsuits~~table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges:

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

Beginning accumulated derivative gain / (loss) in AOCI	$	(0.8	)	$	9.8		$	(1.8	)	$	12.2

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

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

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

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

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

*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, 2012 and December 31, 2011.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at March 31, 2012

								Fair Value on
$ in millions	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
Forward Power Contracts in a Liability Position	(1.5		)	1.1			Other current liabilities	(0.4		)

Total short-term cash flow hedges	(0.5		)	0.5				—

Long-term Derivative Positions

Forward Power Contracts in a Liability Position	(4.7		)	3.0			Other deferred credits	(1.7		)

Total long-term cash flow hedges	(4.7		)	3.0				(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
$ in millions	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
Forward Power Contracts in a Liability Position	(0.2		)	—			Other current liabilities	(0.2		)

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

Total long-term cash flow hedges	(2.5		)	1.6				(0.9		)

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

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 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 months ended March 31, 2012 and 2011.

For the Three Months Ended March 31, 2012

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

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

For the Three Months Ended March 31, 2011

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

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

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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, 2012.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments

at March 31, 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	)

(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	)

(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, 2012 is $32.0 million. This amount is offset by $19.4 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 million. If our counterparties were to call for collateral, DP&L could be required to post collateral for the remaining $11.7 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, 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

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, 2012, DP&L could be responsible for the repayment of 4.9%, or $64.9 million, of a $1,324.7 million debt obligation that features maturities from 2013 to 2026. This would only happen if this electric generation company defaulted on its debt payments. As of March 31, 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.

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, 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 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.

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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. We are considering options for the Hutchings station, but have not yet made a final decision. We do not believe that any accruals or impairment charges are needed related to the Hutchings station.

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 how much of a pollutant 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. 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.

In an attempt to conform to the Court’s decision, on July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR). CAIR 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) 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 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.

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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 on DP&L’s operations are not expected to be material.

Carbon Emissions and Other Greenhouse Gases

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 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.

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 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 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, including electric generating units. DP&L’s first report to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other 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 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.

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 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.

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 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.

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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. 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. DP&L will install sedimentation ponds as part of the runoff control measures to address this issue. We expect the impact of this NOV to be immaterial.

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.

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. 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.

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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 information from potentially affected parties on how it should proceed, the outcome may have a material 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. DP&L is unable to predict the outcome this inspection will have on its operations.

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 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.

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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. With respect to unsettled claims, DP&L management has deferred $18.1 million and $17.8 million as of December 31, 2011 and December 31, 2010, respectively, as Other deferred credits representing the amount of unearned income and interest where the earnings process is not complete. The amounts at March 31, 2012 and December 31, 2011 includes estimated interest of $5.5 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, 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 not 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 ~~Proposed~~ Merger ~~(See Item 1a, “Risk Factors,” for additional risks related to the Proposed Merger). Each of these lawsuits seeks,~~seeking, among other things, one or more of the following: to enjoin consummation of the ~~defendants from consummating the Proposed~~ Merger until certain conditions ~~are~~were met, or to rescind the ~~Proposed~~ Merger or for rescissory damages, ~~or to recover damages if the Proposed Merger is consummated~~ or to commence a sale process and/or obtain an alternative transaction ~~or to promptly notice an annual shareholder meeting~~ 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~~ duty. All of these lawsuits, except one, were resolved and/or ~~an injunction specifically preventing~~ ~~DPL~~ ~~from paying a termination fee.~~

~~Table~~dismissed prior to the March 28, 2012 filing of ~~Contents~~

~~On April 21, 2011, a lawsuit was filed in~~our Form 10-K for the ~~Court of Common Pleas of Montgomery County, Ohio, naming~~ ~~DPL~~ ~~and each member of~~ ~~DPL’s~~ ~~board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit is a purported class action filed by Patricia A. Heinmullter on behalf of herself and an alleged class of~~ ~~DPL~~ ~~shareholders. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.~~

~~On April 25, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of~~ ~~DPL’s~~ ~~board of directors and AES as defendants and naming~~ ~~DPL~~ ~~as a nominal defendant. The lawsuit filed by The Austen Trust is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES aided and abetted such breach.~~

~~On April 26, 2011, a lawsuit was filed in the United States District Court, Southern District, Western Division, naming each member of~~ ~~DPL’s~~ ~~board of directors, AES and Dolphin Sub, Inc. as defendants and naming~~ ~~DPL~~ ~~as a nominal defendant. The lawsuit filed by Stephen Kubiak is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and that AES and Dolphin Sub, Inc. aided and abetted such breach.~~

~~On April 26, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of~~ ~~DPL’s~~ ~~board of directors, AES and Dolphin Sub, Inc. as defendants and naming~~ ~~DPL~~ ~~as a nominal defendant. The lawsuit filed by Sandra Meyr is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach. On May~~fiscal year ending December 31, 2011, ~~the Court granted the plaintiff’s voluntary motion to dismiss the lawsuit without prejudice.~~

~~On April 27, 2011, a lawsuit~~and were discussed in that and previous reports we filed. The last of these lawsuits was ~~filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of~~ ~~DPL’s~~ ~~board of directors and AES~~dismissed on March 29, 2012, as ~~defendants and naming~~ ~~DPL~~ ~~as a nominal defendant. The lawsuit filed by Thomas Strobhar is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES aided and abetted such breach.~~

~~On April 27, 2011, another lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming~~ ~~DPL~~~~, each member of~~ ~~DPL’s~~ ~~board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Laurence D. Paskowitz is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that~~ ~~DPL~~~~, AES and Dolphin Sub, Inc. aided and abetted such breach.~~noted below.

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 iswas 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 ~~alleges,~~had alleged, among other things, that DPL’s directors breached their fiduciary duties in approving the ~~proposed~~ Merger of DPL and AES.

~~On May 4, 2011, a lawsuit was filed in the United States District Court for the Southern District of Ohio, Western Division, naming~~ ~~DPL~~~~, each member of~~ ~~DPL’s~~ ~~board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Patrick Nichting is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that~~ ~~DPL~~~~, AES and Dolphin Sub, Inc. aided and abetted such breach.~~

~~On May 6, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming~~ ~~DPL~~~~, each member of~~ ~~DPL’s~~ board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Robin Mahaffey, Jerome R. Baxter, and Donald and Patricia Aydelott is a purported class action on behalf of plaintiffs and an alleged class of ~~DPL~~ ~~shareholders. Plaintiffs allege, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that~~ ~~DPL~~ ~~and AES aided and abetted such breach. On June 24, 2011, the plaintiffs voluntarily dismissed without prejudice this lawsuit.~~

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~~On May 10, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of~~ ~~DPL’s~~ ~~board of directors and AES as defendants and naming~~ ~~DPL~~ as a nominal defendant. The lawsuit filed by Glenda E. Hime, Donald D. Foreman, Donald Moberly, James Sciarrotta, Barbara H. Sciarrotta, Robert Krebs and Frances Krebs is a purported class action on behalf of plaintiffs and an alleged class of ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiffs allege, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES aided and abetted such breach.~~

~~On May 20, 2011, a lawsuit was filed in the United States District Court for the Southern District of Ohio, Western Division, naming~~ ~~DPL~~~~, each member of~~ ~~DPL’s~~ board of directors, AES and Dolphin Sub, Inc. as defendants. The lawsuit filed by Ralph B. Holtmann and Catherine P. Holtmann is a purported class action on behalf of plaintiffs and an alleged class of ~~DPL~~ ~~shareholders. Plaintiffs allege, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that~~ ~~DPL~~~~, AES and Dolphin Sub, Inc. aided and abetted such breach.~~

~~On May 24, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of~~ ~~DPL’s~~ ~~board of directors and AES as defendants and naming~~ ~~DPL~~ ~~as a nominal defendant. The lawsuit filed by Maxine Levy is a purported class action on behalf of plaintiff and an alleged class of~~ ~~DPL~~ ~~shareholders and a purported derivative action on behalf of~~ ~~DPL~~~~. Plaintiff alleges, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the proposed Merger of~~ ~~DPL~~ ~~and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.~~

On June 13, 2011, the three actions pending in the United States District Court for the Southern District of Ohio were consolidated. On June 14, 2011, the United States District Court of the Southern District of Ohio granted Plaintiff Nichting’s motion to appoint lead and liaison counsel.~~On June 30, 2011, Plaintiffs in the consolidated federal action filed an amended complaint that adds claims based on alleged omissions in the preliminary proxy statement that~~ ~~DPL~~ ~~filed on June 22, 2011 (the “Preliminary Proxy Statement”). Plaintiffs , in their individual capacity only, assert a claim against~~ ~~DPL~~ ~~and its directors under Section 14(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) for purported omissions in the Preliminary Proxy Statement and a claim against~~ ~~DPL’s~~ ~~directors for control person liability under Section 20(a) of the Exchange Act. In addition, Plaintiffs purport to assert state law claims directly on behalf of Plaintiffs and an alleged class of~~ ~~DPL~~ ~~shareholders and derivatively on behalf of~~ ~~DPL~~~~. Plaintiffs allege, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties in approving the Merger Agreement for the Proposed Merger of~~ ~~DPL~~ ~~and AES and that~~ ~~DPL~~ ~~AES and Dolphin Sub, Inc. aided and abetted such breach.~~

~~A number of other similar putative class action lawsuits by purported shareholders of~~ ~~DPL~~ ~~on behalf of themselves and other shareholders of~~ ~~DPL~~ ~~and/or derivative lawsuits by purported shareholders of~~ ~~DPL~~ ~~on behalf of~~ ~~DPL~~ ~~may be filed in federal or state court in Ohio. Such complaints may name as defendants~~ ~~DPL~~ ~~and its directors and, in certain cases, AES and Dolphin Sub, Inc.~~

~~The complaints may allege, among other things, that~~ ~~DPL’s~~ ~~directors breached their fiduciary duties to shareholders of~~ ~~DPL~~ ~~in connection with~~ ~~DPL’s~~ ~~entry into the proposed Merger with AES and that~~ ~~DPL~~~~, AES and Dolphin Sub, Inc. aided and abetted the directors’ purported breaches of fiduciary duties and that~~ ~~DPL’s~~ proxy statement related to the approval of the proposed Merger contains misrepresentations and omissions. The complaints may seek, among other things, class action status, an order enjoining the proposed transaction, compensatory damages and attorneys’ fees and expenses.

~~DPL~~ ~~is vigorously defending against all of the claims referred to above.~~

~~DPL~~ ~~expects to record transaction fees relating to the Proposed Merger consisting primarily of bankers’ fees, legal fees, and change of control costs of approximately $45 million pre-tax during 2011.~~

~~Further information concerning the Proposed Merger, including a copy of the Merger Agreement, is included in~~ ~~DPL’s~~ ~~Current Report on Form 8-K relating to the Proposed Merger, filed with the SEC on April 20, 2011 and~~ ~~DPL’s~~ Preliminary Proxy Statement filed with the SEC on June 22, 2011. We expect to file with the SEC and send to shareholders a definitive proxy statement in connection with the Proposed Merger and other matters. A definitive proxy statement will be sent shortly to shareholders in connection with the Proposed Merger and the Company’s Annual Meeting of shareholders scheduled to occur September 23, 2011.

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

This report includes the combined filing of DPL and DP&L. ~~DP&L~~ ~~is the principal~~On November 28, 2011, DPL became a wholly owned subsidiary of ~~DPL~~ ~~providing approximately 90% of~~ ~~DPL’s~~ ~~total consolidated gross margin and approximately 93% of~~ ~~DPL’s~~ ~~total consolidated asset base.~~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.

~~Certain statements contained in this report, including this~~The following discussion are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Matters discussed in this report that relate to events or developments that are expected to occur in the future, including: the Proposed Merger transaction between ~~DPL~~ and The AES Corporation (AES) and the expected timing and completion of the transaction; 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. Suchcontains forward-looking statements ~~are subject to risks~~ and uncertainties, and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to: abnormal or severe weather and catastrophic weather-related damage; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, natural gas, oil and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; performance of our suppliers and other counterparties; increased competition and deregulation in the electric utility industry; increased competition in the retail generation market; a material deterioration in ~~DPL~~’s retail and/or wholesale businesses and assets; changes in interest rates; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, emission levels and regulations, rate structures or tax laws; changes in federal or state environmental laws and regulations to which ~~DPL~~ ~~and its subsidiaries are subject; the development and operation of RTOs, including PJM to which~~ ~~DPL’s~~ ~~operating subsidiary (~~~~DP&L~~) has given control of its transmission functions; changes in our purchasing processes, pricing, delays, employee, contractor and supplier performance and availability; significant delays associated with large construction projects; growth in our service territory and changes in demand and demographic patterns; changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; financial market conditions; the outcomes of litigation and regulatory investigations, proceedings or inquiries; general economic conditions; an otherwise material adverse change in the business, assets, financial condition or results of operations of ~~DPL~~~~; and the risks and other factors discussed in this report and other~~ ~~DPL~~ ~~and~~ ~~DP&L~~ filings with the SEC. Regarding the Proposed Merger transaction with AES, there can be no assurance as to the timing of the closing of the transaction, or whether the transaction will close at all. The following factors, among others, could also cause or contribute to causing our actual results to differ materially from the results anticipated in our forward-looking statements: the ability to obtain the approval of the transaction by ~~DPL’s~~ shareholders; the ability to obtain required regulatory approvals of the transaction or to satisfy other conditions to the transaction on the terms and expected timeframe or at all; transaction costs; and the effects of disruption from the transaction making it more difficult to maintain relationships with employees, customers, other business partners or government entities.

~~The following discussion~~ 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

DPLis a diversified regional ~~electric~~ energy ~~and utility company.~~company organized in 1985 under the laws of Ohio. DPL’s two ~~reporting~~reportable segments are the Utility segment, comprised of its DP&L subsidiary, and the Competitive Retail segment, comprised of its DPLER ~~subsidiary and DPLER’s subsidiary, MC Squared.~~subsidiary. Refer to Note 1514 of Notes toDPL’s Condensed Consolidated Financial Statements for more information relating to these reportable segments.

On November 28, 2011, ~~DP&L~~DPL was acquired by AES in the Merger and DPL ~~does not have any reportable segments.~~became a wholly owned subsidiary of AES. See Note 2 of Notes to DPL’s Condensed Consolidated Financial Statements.

DP&L is ~~primarily~~a public utility incorporated in 1911 under the laws of Ohio. DP&L is engaged in the generation, transmission, distribution and ~~distribution~~sale of electricity to residential, commercial, industrial and governmental customers in a 6,000 square mile area of West Central Ohio. Electricity for ~~DPL~~ 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 strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, ~~DPL’s~~ ~~and~~ ~~DP&L’s~~ ~~strategy is to match energy supply with load, or customer demand, to maximize profits while effectively managing exposure to movements in~~sells any excess energy and ~~fuel prices~~capacity into the wholesale market.

DPLER sells competitive retail electric service, under contract, to residential, commercial and ~~utilizing~~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 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.

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 ~~that transfer electricity at the most efficient~~when incurred costs are expected to be recovered in future customer rates, and regulatory liabilities when current cost ~~and~~recoveries in customer rates relate to ~~maintain the highest level of customer service and reliability.~~expected future costs.

~~We operate~~DPL and ~~manage generation assets and~~its subsidiaries employed 1,494 people as of March 31, 2012, of which 1,450 employees were employed by DP&L. Approximately 53% of all employees are ~~exposed to~~under a number of risks. These risks include, but are not limited to, electricity wholesale price risk, PJM capacity price risk, regulatory risk, environmental risk, fuel supply and price risk, customer switching risk and the risk associated with power plant performance. We attempt to manage these risks through various means. For instance, we operate a portfolio of wholly-owned and jointly-owned generation assets that is diversified as to coal source, cost structure and operating characteristics. We are focusedcollective bargaining agreement which expires on ~~the operating efficiency of these power plants and maintaining their availability.~~

We~~operate and manage~~transmission and distribution assets in a rate-regulated environment. Accordingly, this subjects us to regulatory risk in terms of the costs that we may recover and the investment returns that we may collect in customer rates. We are focused on delivering electricity and maintaining high standards of customer service and reliability in a cost-effective manner.October 31, 2014.

~~RECENT DEVELOPMENTS~~BUSINESS COMBINATION

~~Merger Agreement with~~Acquisition by The AES Corporation

On ~~April 19,~~November 28, 2011, DPL ~~and~~merged with Dolphin Sub, Inc., a wholly owned subsidiary of The AES Corporation, a Delaware corporation (“AES”)~~, entered into an~~ pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) whereby AES ~~will acquire~~acquired DPL for ~~$30~~$30.00 per share in a cash transaction valued at approximately $3.5 ~~billion plus the assumption of $1.2 billion of debt. Upon~~billion. At closing, DPL ~~will become~~became a ~~wholly-owned~~wholly owned subsidiary of AES.

~~The transaction has been unanimously approved by each~~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 ~~and AES’ board of directors, but is subject to certain conditions, including receipt~~Condensed Consolidated Financial Statements). Upon the consummation of the ~~approval of~~ ~~DPL~~ ~~shareholders and the receipt of all required regulatory approvals from, among others, the FERC and the PUCO. On May 18, 2011,~~Merger, Dolphin Subsidiary II, Inc. was merged into DPL and ~~AES filed merger applications with the FERC~~these notes became long-term debt obligations of DPL. This debt has and ~~the PUCO. We expect~~will have a two to three month review of the FERC application and a six to nine month review of the PUCO application. The FERC application will be deemed approved after 180 days, unless the FERC tolls for good cause the completed application for further consideration, which may or may not occur as part of the FERC’s review. Alsomaterial effect on ~~May 18, 2011,~~ ~~DPL~~DPL’s and AES each filed their respective Premerger Notification and Report Forms with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Those filings initiated a statutory 30-day waiting period, which expired on June 14, 2011, when early termination of the waiting period was granted. The Vermont Department of Banking, Insurance, Securities and Health Care Administration also issued a formal approval with respect to the Proposed Merger on May 18, 2011. The parties anticipate receiving additional approvals and then closing the transaction during the fourth quarter of 2011 or first quarter of 2012.cash requirements.

~~See Item 1a, “Risk Factors,” and Note 16 of Notes to Condensed Consolidated Financial Statements for additional risks and information related to the Proposed Merger.~~

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~~The Merger Agreement also includes certain provisions whereby we have agreed to use commercially reasonable efforts to replace~~ ~~DP&L’s~~ existing $220.0 million revolving credit facility. We have agreed to replace this facility with a new revolving credit facility in an amount equal to or greater than $200.0 million with a term of at least three years. ~~DPL~~ has also agreed to use commercially reasonable efforts to enter into a revolving credit facility in an amount equal to or greater than $125.0 million with a term of at least three years and to enter into a $425.0 million term loan with a term of at least three years, in part, to refinance the approximately $297.4 million principal amount of ~~DPL’s~~ ~~6.875% debt that is due in September 2011.~~

We believe that Dolphin Subsidiary II, Inc., a subsidiary of AES, is planning to issue $1.25 billion in long-term Senior Notes prior to the consummation of the Proposed Merger and that the proceeds from these notes will be used to partially finance the Proposed Merger. Upon the consummation of the Proposed Merger, these notes are expected to become long-term debt obligations of ~~DPL~~. ~~DPL~~ ~~will not have any obligation associated with these notes if the Proposed Merger is not consummated. This debt will have a material effect on~~ ~~DPL’s~~ ~~cash requirements post-closing.~~

As a result of the ~~Proposed~~ Merger, including the ~~expected incurrence~~assumption of ~~additional~~ ~~DPL~~merger-related debt, DPL and DP&L were ~~recently~~ downgraded by ~~one of the major credit rating agencies and~~ all three major credit rating ~~agencies reduced their outlook from stable to negative.~~agencies. We do not anticipate that these reduced ratings will have a significant ~~impact~~effect on our liquidity; however, we expect that our cost of capital will increase. See Note 56 of Notes toDPL’s Condensed Consolidated Financial Statements for more information. It is important for us to maintain our credit ratings and have access to the capital markets in order to reliably serve our customers, invest in capital improvements and prepare for our customer’s future energy needs. As discussed in Note 9 of Notes to Condensed Consolidated Financial Statements, further credit rating downgrades could also require us to post additional credit assurances for commodity derivatives as certain derivative instruments require us to post collateral or provide other credit assurances based on our credit ratings.

DPL ~~expects to incur~~incurred merger transaction ~~fees~~costs consisting primarily of banker’s fees, legal fees and change of control costs of approximately ~~$45~~$53.6 million pre-tax during ~~2011.~~2011 and an additional $1.0 million pre-tax during 2012. Other than these ~~transaction fees~~costs, interest on the additional debt and other ~~than as~~items noted above, DPL and DP&L do not expect the ~~Proposed~~ Merger to have a significant ~~impact~~effect on their ~~cash requirements and~~financial position, results of operations or sources of liquidity during 2011 and do not anticipate materially modifying their business or operating strategies prior to the closing of the Proposed Merger, but we cannot predict the long-term impact consummation of the Proposed Merger will have on us.2012.

~~Additional information concerning~~The Merger also resulted in DPL recording $2,489.3 million in goodwill due to the ~~Proposed Merger, including~~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 ~~copy~~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 ~~Merger Agreement, is included~~required annual assessment process if we experience situations, including but not limited to: deterioration in ~~DPL’s~~ ~~current report~~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 ~~Form 8-K relating to the Proposed Merger, filed with the SEC on April 20, 2011 and~~ ~~DPL’s~~ ~~Preliminary Proxy Statement filed with the SEC on June 22, 2011. We expect to file with the SEC and send to shareholders~~equally favorable terms; or adverse actions or assessments by a ~~definitive proxy statement in connection with the Proposed Merger and other matters. On July 1, 2011,~~ ~~DPL~~ ~~learned that the SEC would not review the preliminary proxy statement. A definitive proxy statement will be sent shortly to shareholders in connection with the Proposed Merger~~regulator. These types of events and the ~~Company’s Annual Meeting~~resulting analyses could result in goodwill impairment expense, which could substantially affect our results of ~~shareholders scheduled to occur September 23, 2011.~~operations for those periods.

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

~~Purchase of a Retail Electricity Supplier~~Predecessor and Successor Financial Presentation

On February 28, 2011, DPLER purchased MC Squared, a Chicago-based retail electricity supplier, for approximately $8.2 million. MC Squared serves approximately 3,000 customers in Northern Illinois at June 30, 2011. For the year ended December 31, 2010, it sold approximately 648 million kWh of power, generating revenues of approximately $46 million. The purchase of MC Squared is expected to complement DPLER’s existing Ohio retail market activity and to provide a platform for expansion into other attractive markets.

~~Redemption of DPL Capital Trust II Securities~~DPL’s

~~On February 23,~~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 ~~acquired $122.0 million of outstanding DPL Capital Trust II 8.125% trust preferred securities from~~applied push-down accounting to account for the merger. For accounting purposes only, push-down accounting created a ~~third party. As a result of this transaction,~~ ~~DPL~~ ~~recorded a net loss on the reacquisition~~new cost basis assigned to assets, liabilities and equity as of the ~~securities in~~Merger date. Such adjustments are subject to change as AES finalizes its purchase price allocation during the amount of approximately $15.3 million ($10.1 million net of tax) in the first quarter of 2011. Interest savings from the redemption of these securities are expected to be approximately $8.4 million ($5.6 million net of tax) for the remainder of 2011. ~~DPL~~ ~~financed this transaction using a combination of cash on hand, drawings from its revolving credit facilities as well as proceeds from the sale of some of its short-term investments.~~

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

~~Table of Contents~~applicable measurement period.

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 ~~— Climate Change Legislation~~and Other Greenhouse Gases

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 CO2GHG emissions ~~from motor vehicles~~ under the CAA. In April 2009, the USEPA issued a proposed endangerment finding under the ~~CAA, which was finalized and published on December 15, 2009.~~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. ~~In December 2009, the USEPA finalized this~~This endangerment finding ~~with a regulatory~~became effective ~~date of~~in January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision. ~~This~~

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As a result of this endangerment finding ~~if not changed, is expected to lead to the regulation~~and other USEPA regulations, emissions of CO2 and other GHGs from certain electric generating units and other stationary sources ~~of these emissions.~~are subject to regulation. Increased pressure for CO2GHG emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on CO2GHG emissions from power generation facilities and their potential role in climate change. ~~Legislation proposed in 2009 to target a reduction in the emission of GHGs from large sources was not enacted.~~ Approximately 99% of the energy we produce is generated by coal. DP&L’s share of CO2 GHG emissions at generating stations we own and co-own is approximately 16 million tons annually. If ~~legislation or regulations~~we are ~~passed at the federal or state levels that impose mandatory reductions~~required to implement control of CO2 and other GHGs onat generation facilities, the cost to DPL and DP&L of such reductions could be material.

·Clean Water Act

· 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 ~~also~~ 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 ~~impact~~effect on our results of operations, financial condition and cash flows.

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&L ~~faces regulatory uncertainty from~~ filed with the PUCO for approval of its next SSO to replace the existing ESP orthat expires on December 31, 2012. The filing requested approval of a five-year and five month MRO, ~~filing~~ which ~~is scheduled to be filed in the first quarter of 2012 to~~will be effective January 1, ~~2013.~~2013, and would phase in market rates over this period. The PUCO is currently reviewing the filing ~~may result in changes to~~and no decision has been made. The outcome of the ~~current rate structure~~proceeding is uncertain and ~~riders.~~could have a material impact on our results.

· NOx and SO2 Emissions — ~~CAIR~~CSAPR

The ~~USEPA issued CAIR~~Clean Air Interstate Rule (CAIR) final rules were published on ~~March 10, 2005 to regulate certain upwind states with respect to fine particulate matter and ozone.~~May 12, 2005. CAIR created an interstate trading ~~programs~~program for annual NOx emission allowances and made modifications to an existing trading program for SO2 ~~that were to take effect~~. Appeals brought by various parties resulted in ~~2010. On July 11, 2008,~~a decision by the ~~United States~~U.S. Court of Appeals for the District of Columbia Circuit ~~issued a decision that vacated the USEPA~~on July 11, 2008 to vacate CAIR and its associated Federal Implementation Plan. ~~This decision remanded these issues back to the USEPA. The court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO~~2 ~~emission trading program, and created uncertainty regarding future NOx and SO~~2 ~~emission reduction requirements and their timing.~~ On December 23, 2008, the ~~court reversed part~~U.S. Court of ~~its decision~~Appeals issued an order on reconsideration that ~~vacated CAIR. Thus,~~permits CAIR ~~currently remains~~to remain in effect ~~but~~until the USEPA ~~remains subject~~issues new regulations that would conform to the ~~court’s order to revise~~CAA requirements and the ~~program. On~~Court’s July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) to replace CAIR. We reviewed this proposal and submitted comments to the USEPA on September 30, 2010. These rules were finalized as the Cross State Air Pollution Rule (CSAPR) on July 6, 2011. CSAPR responds to the court ruling remanding the 2005 CAIR.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~~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 ~~rule~~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 ~~effective January 1, 2012,~~expected to institute a Federal Implementation Plan (FIP) in lieu of state SIPs and ~~allowances will be distributed in 3Q 2012.~~allow for the states to develop SIPs for approval as early as 2013. We ~~are in the process of reviewing the regulation, but~~ do not ~~expect~~believe the ~~ruling to~~rule will have a ~~significant impact~~material effect on our operations in 2012, ~~however, it may~~but until the CSAPR becomes effective, DP&L is unable to estimate the impact ~~operation~~ of ~~uncontrolled units~~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 period cleared at a per megawatt price of $126/day for our RTO area. The per megawatt prices for the periods 2013/2014, 2012/2013, and 2011/2012 ~~and 2010/2011~~ were $28/day, $16/day, ~~$110/day~~ and ~~$174/~~$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~~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 ~~2010,~~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 ~~$5.0~~$5.2 million and ~~$3.7~~$3.9 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.

· 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 ~~overall power~~ market prices for power have resulted in increased levels of competition to provide transmission and generation services. This in turn has led ~~to a significant number~~approximately 53% of DP&L’s ~~customers~~retail volume to ~~switch their retail electric services~~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 ~~month periods~~months ended ~~June 30, 2011~~March 31, 2012 and ~~2010 and the six month periods ended June 30, 2011 and 2010:~~2011:

Three Months Ended

Three Months Ended

June 30, 2011

June 30, 2010

Electric
Customers

Sales (in Millions
of kWh)

Electric
Customers

Sales (in Millions
of kWh)

Supplied by DPLER

12,033

1,420

2,661

1,033

Supplied by non-affiliated CRES providers

4,996

164

168

14

Total supplied in our service territory

17,029

1,584

2,829

1,047

Supplied by DP&L in our service territory(a)

513,123

3,260

514,142

3,350

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	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

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

The volumes supplied by DPLER represent approximately ~~44%~~41% and ~~31%~~37% of DP&L’s total distribution volumes during the three ~~month periods ended June 30, 2011 and 2010, respectively. The reduction to gross margin during the three~~ months ended ~~June 30,~~March 31, 2012 and 2011, ~~as a result of customers switching to DPLER and other CRES providers was approximately $11.0 million and $17.0 million, for~~ ~~DPL~~ ~~and~~ ~~DP&L~~, respectively. We ~~currently~~ cannot determine the extent to which customer switching to CRES providers will occur in the future and the ~~impact~~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.

69As of March 31, 2012, approximately 53% of DP&L’s load has switched to CRES providers with DPLER acquiring 78% of the switched load. For the three months ended March 31, 2012, customer switching negatively affected DPL’s gross margin by approximately $27.0 million compared to the 2011 effect of approximately $9.0 million. For the three months ended March 31, 2012, customer switching negatively affected DP&L’s gross margin by approximately $53.0 million compared to the 2011 effect of approximately $19.0 million.

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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Six Months Ended

Six Months Ended

June 30, 2011

June 30, 2010

Electric
Customers

Sales (in Millions
of kWh)

Electric
Customers

Sales (in Millions
of kWh)

Supplied by DPLER

12,033

2,764

2,661

1,753

Supplied by non-affiliated CRES providers

4,966

282

168

16

Total supplied in our service territory

16,999

3,046

2,829

1,769

Supplied by DP&L in our service territory(a)

513,123

6,898

514,142

6,966

~~(a)~~~~The kWh sales include all distribution sales, including those whose power is supplied by non-affiliated CRES providers.~~
~~The volumes supplied by DPLER represent approximately 40% and 25% of~~ ~~DP&L’s~~ total distribution volumes during the six month periods ended June 30, 2011 and 2010, respectively. The reduction to gross margin during the six months ended June 30, 2011 as a result of customers switching to DPLER and other CRES providers was approximately $20.0 million and $36.0 million, for ~~DPL~~ ~~and~~ ~~DP&L~~, respectively. We currently cannot determine the extent to which customer switching to CRES providers will occur in the future and the impact this will have on our operations, but any additional switching could have a significant adverse effect on our future results of operations, financial condition and cash flows.
~~During the second quarter, we have seen a significant increase in retail competition for our residential retail customers. Approximately 6% of~~ ~~DP&L’s~~ annualized residential load switched to CRES providers during the past two months with DPLER acquiring 54% of the switched load. For the calendar year 2011, based on current trends, we project customer shopping will negatively impact gross margin by approximately $40.0 to $45.0 million compared to the 2010 impact of approximately $17.0 million.

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, ~~2011,~~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.

Effective January 2010, the SSO retail customers’ portion of fuel price changes, including coal requirements and purchased power costs, was reflected in the implementation of the fuel and purchased power recovery rider, subject to PUCO review. ~~DP&L~~ had an audit of its fuel and purchased power recovery rider, but there is some uncertainty as to the costs that will be approved for recovery. Independent third parties conducted the fuel audit in accordance with PUCO standards. The audit was completed in the second quarter of 2011 and a hearing has been set by the PUCO for August 30, 2011. Once the PUCO audit approval process is complete, ~~DP&L~~ may record a favorable or unfavorable adjustment to earnings. Based on past PUCO precedent, we believe these deferred fuel and purchased power costs are probable of future recovery or repayment in the case of over recovery.
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~~Table of Contents~~
~~FINANCIAL OVERVIEW~~
~~The following financial overview relates to~~ ~~DPL~~~~, which includes its principal subsidiary~~ ~~DP&L~~~~. The results of operations for both~~ ~~DPL~~ ~~and~~ ~~DP&L~~ ~~are separately discussed in more detail following this financial overview.~~
~~For the three months ended June 30, 2011, Net income for~~ ~~DPL~~ ~~was $31.7 million, or $0.28 per share, compared to Net income of $61.4 million, or $0.53 per share, for the same period in 2010. All EPS amounts are on a diluted share basis.~~ ~~As discussed more fully below, the key drivers of the results during the three month period ended June 30, 2011 compared to the similar period of the prior year are comprised of the following:~~
·~~a decrease in retail revenue due to pricing associated with competitively supplied customers,~~
·~~an overall decline in generating plant performance which resulted in a decrease in wholesale sales volume and an increase in purchased power volume,~~
·~~an increase in operation and maintenance expenses resulting from repair and damage caused by storms and planned outages at jointly-owned production facilities, and~~
·~~transaction costs related to the Proposed Merger.~~
~~Partially offsetting these items were:~~
·~~an increase in retail rates primarily as a result of an increase in the Fuel and Purchased Power Recovery Rider and an increase in the capacity clearing price of the PJM capacity auction,~~
·~~a decrease in purchased power prices,~~
·~~an increase in retail sales volumes due to improved economic conditions, and~~
·~~a decrease in the volume of fuel consumed due to decreased generation by our power plants.~~
~~For the six months ended June 30, 2011, Net income for~~ ~~DPL~~ ~~was $75.2 million, or $0.66 per share, compared to Net income of $132.4 million, or $1.14 per share, for the same period in 2010. All EPS amounts are on a diluted share basis.~~ ~~As discussed more fully below, the key drivers of the results during the six month period ended June 30, 2011 compared to the similar period of the prior year are comprised of the following:~~
·~~a decrease in retail revenue due to pricing associated with competitively supplied customers,~~
·~~an overall decline in generating plant performance which resulted in a decrease in wholesale sales volume and an increase in purchased power volume,~~
·~~an increase in operation and maintenance expenses resulting from repair and damage caused by an ice storm experienced during February 2011 and planned outages at jointly-owned production facilities,~~
·~~a loss on the repurchase of DPL Capital Trust II securities,~~
·~~an increase in tax related expenses due to deferred taxes recorded as a result of the MC Squared acquisition and an unfavorable determination from the Ohio gross receipts tax audit,~~
·~~an insurance settlement received during the six months ended June 30, 2010, and~~
·~~transaction costs related to the Proposed Merger.~~
~~Partially offsetting these items were:~~
·~~an increase in retail rates primarily as a result of an increase in the Fuel and Purchased Power Recovery Rider and an increase in the capacity clearing price of the PJM capacity auction,~~
·~~a decrease in purchased power prices,~~
·~~an increase in retail sales volumes due to improved economic conditions, and~~
·~~a decrease in the volume of fuel consumed due to decreased generation by our power plants.~~
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RESULTS OF OPERATIONS — DPL

DPL’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary DP&L. ~~DP&L~~ ~~provides~~ ~~approximately 90% of~~ ~~DPL’s~~ ~~total consolidated gross margin.~~ All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for DP&L is presented elsewhere in this report.

Income Statement Highlights — DPL

Three Months Ended

March 31,

Three Months Ended
June 30,

Six Months Ended
June 30,

2012

2011

$ in millions

2011

2010

2011

2010

Successor

Predecessor

Revenues:

Retail

$
348.1

$
342.7

$
731.6

$
697.3

$
349.3

$
369.5

Wholesale

28.7

39.1

61.1

79.3

22.4

32.4

RTO revenues

19.5

20.1

40.9

41.2

18.2

21.4

RTO capacity revenues

49.7

40.4

105.0

72.7

36.9

55.3

Other revenues

2.9

3.2

5.7

6.2

3.2

2.7

Other mark to market losses

(4.0
)
—

(4.7
)
—

Mark-to-market gains / (losses)

4.0

(0.7
)
Total revenues

$
444.9

$
445.5

$
939.6

$
896.7

$
434.0

$
480.6

Cost of revenues:

Fuel costs

$
93.3

$
92.4

$
194.8

$
194.7

$
90.6

$
100.9

Gains from sale of coal

(1.2
)
(1.1
)
(2.9
)
(1.3
)
Gains from sale of emission allowances

—

(0.4
)
—

(0.6
)
Losses / (gains) from sale of coal

3.4

(1.8
)
Mark-to-market losses

3.4

0.6

Net fuel

92.1

90.9

191.9

192.8

97.4

99.7

Purchased power

39.5

21.3

75.5

35.0

34.6

37.3

RTO charges

27.1

26.7

56.4

51.4

24.5

29.3

RTO capacity charges

47.0

42.9

102.5

77.3

33.7

55.5

Mark-to-market losses / (gains)

2.0

(1.3
)
Net purchased power

113.6

90.9

234.4

163.7

94.8

120.8

Amortization of intangibles

27.8

—

Total cost of revenues

$
205.7

$
181.8

$
426.3

$
356.5

$
220.0

$
220.5

Gross margins (a)

$
239.2

$
263.7

$
513.3

$
540.2

$
214.0

$
260.1

Gross margin as a percentage of revenues

53.8
%
59.2
%
54.6
%
60.2
%

49
%

54
%

Operating income

$
65.8

$
109.3

$
166.6

$
235.3

$
59.2

$
100.9

Earnings per share of common stock:

Basic EPS from operations

$
0.28

$
0.53

$
0.66

$
1.15

Diluted EPS from operations

$
0.28

$
0.53

$
0.66

$
1.14

(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

Three Months Ended

Six Months Ended

March 31,

June 30,

June 30,

2012

2011

Number of days

2011

2010

2011

2010

Successor

Predecessor

Heating degree days (a)

513

365

3,480

3,423

2,263

2,967

Cooling degree days (a)

319

376

319

376

30

—

(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

Six Months Ended

Three Months Ended

June 30,

June 30,

March 31,

$ in millions

2011 vs. 2010

2011 vs. 2010

2012 vs. 2011

Retail

Rate

$
6.7

$
31.7

$
3.1

Volume

(3.0
)
(0.2
)

(23.5
)
Other miscellaneous

1.7

2.8

0.7

Total retail change

$
5.4

$
34.3

$
(19.7
)

Wholesale

Rate

$
3.0

$
3.5

$
4.0

Volume

(13.4
)
(21.7
)

(14.0
)
Total wholesale change

$
(10.4
)
$
(18.2
)

$
(10.0
)

RTO capacity & other

RTO capacity and other revenues

$
8.7

$
32.0

RTO capacity and other RTO revenues

$
(21.6
)

Other

Unrealized MTM

$
(4.0
)
$
(4.7
)

$
4.7

Other

(0.3
)
(0.5
)
Total revenue change

$
(4.3
)
$
(5.2
)

Total revenues change

$
(0.6
)
$
42.9

$
(46.6
)

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For the three months ended ~~June 30, 2011,~~March 31, 2012, Revenues decreased ~~$0.6~~$46.6 million to ~~$444.9~~$434.0 million from ~~$445.5~~$480.6 million in the same period of the prior year. This decrease was primarily the result of lower retail and wholesale sales ~~volumes partially offset by higher retail~~volume and ~~wholesale average rates and an increase~~a decrease in RTO capacity and other RTO ~~revenues.~~revenues, partially offset by an increase in retail and wholesale average rates.

·                  Retail revenues ~~increased $5.4~~decreased $19.7 million resulting primarily from a ~~2% increase~~6% decrease in ~~average~~ retail ~~rates~~sales volume compared to prior year period largely due ~~largely~~ to ~~an increase~~unfavorable weather. The unfavorable weather conditions resulted in a 23% decrease in the ~~Fuel Rider and an increase~~number of heating degree days to 2,263 days from 2,967 days in ~~the Universal Service Fund Rider. This increase~~2011. The decrease in ~~the average retail rates was partially offset by~~sales volume is also due to the effect of lower ~~rates~~revenues due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. ~~Retail~~This decrease in sales volume ~~decreased slightly compared to the prior year period largely due to warmer weather. Cooling degree days were 15% less than the prior year.~~was partially offset by a slight increase in average retail rates of 1%, and by improved economic conditions. The above resulted in ~~a favorable $6.7 million retail price variance and~~ an unfavorable ~~$3.0~~$23.5 million retail sales volume variance and a favorable $3.1 million retail price variance.

·                  Wholesale revenues decreased ~~$10.4~~$10.0 million primarily as a result of a ~~34%~~43% decrease in wholesale sales volume which was largely a result of lower generation by our power plants, partially offset ~~partially~~ by ~~an 11%~~a 13% increase in wholesale ~~sales~~average prices. This resulted in an unfavorable ~~$13.4~~$14.0 million wholesale sales volume variance ~~partially offset by~~and a favorable wholesale price variance of ~~$3.0~~$4.0 million. Wholesale sales volume decreased primarily as a result of an increase in outages at our generating plants during the three months ended June 30, 2011 compared to the three months ended June 30, 2010.

·                  RTO capacity and other revenues, consisting primarily of compensation for ~~the~~ use of DP&L’s transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, ~~increased $8.7~~decreased $21.6 million compared to the same period in ~~2010.~~2011. This ~~increase~~decrease in RTO capacity and other revenues was primarily the result of ~~a $9.3~~an $18.4 million ~~increase~~decrease in revenues realized from the PJM capacity ~~auction, partially offset by a slight decrease in transmission, congestion and other revenues.~~
·Other Unrealized MTM, consisting of retail sales contracts accounted for as derivatives, decreased $4.0 million as a result of increases in market prices for power. The majority of these contracts were acquired on February 28, 2011 when DPLER, a wholly-owned subsidiary of ~~DPL~~~~, acquired MC Squared Energy Services. However, this decrease is largely offset by a corresponding increase in unrealized MTM on purchased power contracts also accounted for as derivatives.~~
For the six months ended June 30, 2011, Revenues increased $42.9 million to $939.6 million from $896.7 million in the same period of the prior year. This increase was primarily the result of higher retail and wholesale average rates and an increase in RTO capacity and other RTO revenues, partially offset by lower wholesale and retail sales volumes.
·Retail revenues increased $34.3 million resulting primarily from a 5% increase in average retail rates due largely to an increase in the Fuel Rider and an increase in the Universal Service Fund Rider. This increase in the average retail rates was partially offset by the effect of lower rates due to customer switching which has resulted from increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume remained relatively even compared to the prior year period largely due to continued improvement in economic conditions offset slightly by the warmer weather. Cooling degree days were 15% less than the prior year. The above resulted in a favorable $31.7 million retail price variance offset by an unfavorable $0.2 million retail sales volume variance.
·Wholesale revenues decreased $18.2 million primarily as a result of a 27% decrease in wholesale sales volume, offset partially by a 6% increase in wholesale sales prices. This resulted in an unfavorable $21.7 million wholesale sales volume variance, offset partially by a favorable wholesale price variance of $3.5 million. Wholesale sales volume decreased primarily as a result of an increase in outages at our generating plants during the six months ended June 30, 2011 compared to the six months ended June 30, 2010.
·~~RTO capacity and other revenues, consisting primarily of compensation for the use of~~ ~~DP&L’s~~ transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $32.0 million compared to the same period in 2010. This increase in RTO capacity and other revenues was primarily the result of a $32.3 million increase in revenues realized from the PJM capacity auction, partially offset by a slight decrease in transmission, congestion and other revenues.
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·Other Unrealized MTM, consisting of retail sales contracts accounted for as derivatives, decreased $4.7 million as a result of increases in market prices for power. The majority of these contracts were acquired on February 28, 2011 when DPLER, a wholly-owned subsidiary of ~~DPL~~~~, acquired MC Squared Energy Services. However, this decrease is largely offset by a corresponding increase in unrealized MTM on purchased power contracts also accounted for as derivatives.~~auction.

DPL — Cost of Revenues
For the three months ended ~~June 30, 2011:~~March 31, 2012:

·                  Net fuel costs, which include coal, gas, oil and emission allowance costs, ~~increased $1.2~~decreased $2.3 million, or 1%2%, compared to 2011. During the ~~same period in 2010, primarily due to the impact of~~quarter ended March 31, 2012, fuel costs decreased by $10.3 million driven by a ~~17.3%~~14% decrease in the volume of generation at our plants. This decrease was partially offset by increased losses on the sale of coal and ~~a 13.3% increase~~MTM. DP&L realized $3.4 million in losses from the ~~price~~sale of ~~generation by our plants resulting from an increase~~coal, compared to $1.8 million of realized gains during the same period in ~~and the timing of unit outages during~~2011. In addition, unrealized MTM losses were $3.4 million for the three months ended ~~June 30, 2011 when~~March 31, 2012 compared to $0.6 million for the same period in ~~2010.~~2011.

·                  Net purchased power ~~increased $22.7~~decreased $26.0 million, or ~~25%~~22%, compared to the same period in ~~2010~~2011 due largely to ~~an increase of $4.5~~a $26.6 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. ~~Also contributing~~Purchased power volumes increased less than 1% and purchased power prices decreased approximately 8% compared to the ~~increase~~same period in ~~net purchased power was a $34.5 million increase associated with higher purchased power volumes partially offset by a $10.1 million decrease related to lower average market prices for purchased power.~~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 ~~operating~~ our generating facilities.

~~For the six months ended June 30, 2011:~~
·                  ~~Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $0.9~~Amortization of intangibles increased $27.8 million, or ~~0.5%~~100%, compared to the same period in ~~2010, primarily~~2011 due to the ~~impact~~application of ~~a 15.8% decrease in~~purchase accounting at the volume of generation and a 15.9% increase in the price of generation by our plants resulting from an increase in and the timing of unit outages during the six months ended June 30, 2011 when compared to the same period in 2010.Merger date.

·Net purchased power increased $70.7 million, or 43%, compared to the same period in 2010 due to an increase of $30.2 million 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 included the net impact of the deferral and recovery of~~ ~~DP&L’s~~ transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $68.0 million increase associated with higher purchased power volumes partially offset by $21.2 million related to lower average market prices for purchased power. 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 operating our generating facilities.
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DPL — Operation and Maintenance

Three Months Ended

Six Months Ended

Three Months Ended

June 30,

June 30,

March 31,

$ in millions

2011 vs. 2010

2011 vs. 2010

2012 vs. 2011

Low-income payment program (1)

$
5.2

Competitive retail operations

2.2

Generating facilities operating and maintenance expenses

$
8.7

$
16.2

1.3

Maintenance of overhead transmission and distribution lines

2.2

9.5

(5.7
)
Low-income payment program (1)

3.2

7.7

Merger related costs

5.8

6.6

Insurance settlement, net

—

3.4

Energy efficiency programs (1)

0.3

(1.6
)
Group insurance / long-term disability

(4.4
)
(4.1
)
Pension expense

(0.9
)
Other, net

3.5

0.4

0.3

Total operation and maintenance expense

$
19.3

$
38.1

$
2.4

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

During the three months ended ~~June 30, 2011,~~March 31, 2012, Operation and maintenance expense increased ~~$19.3~~$2.4 million, or ~~22%~~2%, compared to the same period in ~~2010.~~2011. This variance was primarily the result of:
·~~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 2010,~~
·~~increased expenses related to the maintenance of overhead transmission and distribution lines largely related to storms occurring during the second quarter of 2011,~~
·~~increased assistance for low-income retail customers which is funded by the USF revenue rate rider, and~~
·~~increased cost related to the Proposed Merger with AES.~~
These increases were partially offset by lower health insurance and disability costs primarily due to fewer employees going onto long-term disability during the current quarter as compared to the same period in 2010.
~~During the six months ended June 30, 2011, Operation and maintenance expense increased $38.1 million, or 23%, compared to the same period in 2010. This variance was primarily the result of:~~
·~~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 2010,~~
·~~increased expenses related to the maintenance of overhead transmission and distribution lines largely related to a significant ice storm in February 2011,~~

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

·                  increased ~~cost related to~~marketing, customer maintenance and labor costs associated with the ~~Proposed Merger with AES,~~competitive retail business as a result of increased sales volume and number of customers, and

·                  ~~a prior year insurance settlement that reimbursed us~~increased expenses for ~~legal costs associated with our litigation against certain former executives.~~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:

·                  ~~lower~~decreased expenses ~~relating~~related to ~~energy efficiency programs that were put~~the maintenance of overhead transmission and distribution lines primarily as a result of storms, including a significant ice storm in ~~place for our customers,~~February 2011, and

·                  lower ~~health insurance~~pension expenses primarily related to the elimination of certain unrecognized actuarial losses and ~~disability~~prior service costs ~~primarily~~as a result of purchase accounting due to ~~fewer employees going onto long-term disability during~~ the ~~current year as compared to~~Merger. These amounts were previously recorded in Accumulated Other Comprehensive Income and recognized in pension expense over the ~~same period in 2010.~~remaining service life of plan participants.

DPL — Depreciation and Amortization
For the three ~~and six~~ months ended ~~June 30, 2011~~March 31, 2012, Depreciation and amortization expense decreased ~~$0.6~~$3.7 million, or 2%11%, ~~and $2.9 million, or 4%, respectively,~~ as compared to ~~the three and six months ended June 30, 2010.~~2011. The decrease primarily reflects the ~~impact~~effect of the purchase accounting resulting in estimated fair values below the carrying value at the Merger date. This was partially offset by increased amortization expense primarily due to the amortization of certain intangibles acquired in the merger.
DPL — General Taxes
For the three months ended March 31, 2012, General taxes decreased $3.1 million, or 13%, as compared to 2011. 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 ~~depreciation study which resulted~~net basis and are recorded as a reduction in ~~lower depreciation rates on generation property which were implemented on July 1, 2010.~~revenues for presentation in accordance with AES policy. The 2011 amount was reclassified to conform to this presentation.

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DPL — ~~General Taxes~~ Interest Expense
For the three months ended ~~June 30, 2011, General taxes increased $0.3 million, or 1.0% as compared to the same period in 2010. This increase was primarily the result of higher property tax accruals in 2011 compared to 2010~~
~~For the six months ended June 30, 2011~~, General taxes increased $6.6 million, or 10.4% as compared to the same period in 2010. This increase was primarily the result of higher property tax accruals in 2011 compared to 2010 and an unfavorable determination from the Ohio gross receipts tax audit.
~~DPL~~ — ~~Investment Income~~
~~Investment income recorded during the three and six months ended June 30, 2011 did not fluctuate significantly from that recorded during the three and six months ended June 30, 2010.~~
~~DPL~~ — ~~Interest Expense~~
~~For the three months ended June 30, 2011~~March 31, 2012, Interest expense ~~did not fluctuate significantly from that recorded during the same period in 2010. For the six months ended June 30, 2011, Interest expense decreased $0.9~~increased $12.7 million, or 3%75%, as compared to ~~the same period in 2010~~2011 due primarily ~~due~~to higher interest cost subsequent to the ~~early redemption~~Merger as a result of the $1,250.0 million of debt that was assumed by DPL ~~Capital Trust II 8.125% capital securities discussed below.~~ 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 ~~June 30, 2011~~March 31, 2012, Income tax expense decreased ~~$13.8~~$17.1 million, or ~~46.0%~~69%, ~~and $25.4 million, or 38.0%, respectively,~~ as compared to ~~the same periods in 2010~~2011 primarily due to decreased pre-tax income.

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 ~~DPLER and DPLER’s subsidiary MC Squared.~~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 ~~in Ohio~~ 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.

Competitive Retail Segment
The Competitive Retail segment is comprised of ~~DPLER’s~~the DPLER and MC Squared competitive retail electric service ~~business~~businesses which ~~sells~~sell retail electric energy under contract to residential, commercial, industrial and ~~industrial~~governmental customers who have selected DPLER or MC Squared as their alternative electric supplier. The Competitive Retail segment sells electricity to ~~approximately 15,000~~more than 45,000 customers currently located throughout Ohio and Illinois. ~~Beginning February 28, 2011, the Competitive Retail segment includes the results of~~ MC Squared, a Chicago-based retail electricity ~~supplier. MC Squared was purchased by DPLER on February 28, 2011 and~~supplier, serves ~~approximately 3,000~~more than 4,000 customers in ~~northern~~Northern Illinois. The Competitive Retail segment’s electric energy used to meet its ~~Ohio~~ sales obligations was purchased from DP&Lat and PJM. DP&L sells power to DPLER under a wholesale agreement. Under this agreement, 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. The electric energy used to meet its Illinois sales obligation was purchased from PJM.~~power at the inception of each customer’s contract. The Competitive Retail segment has no transmission or generation assets. The operations of ~~DPLER~~the Competitive Retail segment are not subject to cost-of-service rate regulation by federal or state regulators.

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~~Table of Contents~~

~~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 interest expense on DPL’s debt.

Management evaluates segment performance based on gross margin.

See Note 1514 of Notes toDPL’s Condensed Consolidated Financial Statements for further discussion of DPL’s reportable segments.
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Table of Contents

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

Three months ended June 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

Utility

$
215.1

$
245.1

$
(30.0
)
Competitive Retail

12.5

10.1

2.4

Other

12.6

9.6

3.0

Adjustments and Eliminations

(1.0
)
(1.1
)
0.1

Total consolidated

$
239.2

$
263.7

$
(24.5
)
~~The following table presents~~ ~~DPL’s~~ ~~gross margin by business segment:~~

Three months ended

March 31,

Increase (Decrease)

Six months ended June 30,

Increase (Decrease)

2012

2011

2012 vs. 2011

$ in millions

2011

2010

2011 vs. 2010

Successor

Predecessor

Utility

$
462.5

$
509.9

$
(47.4
)

$
219.1

$
233.4

$
(14.3
)
Competitive Retail

28.8

14.6

14.2

15.4

16.3

(0.9
)
Other

24.0

17.9

6.1

(19.6
)

11.4

(31.0
)
Adjustments and Eliminations

(2.0
)
(2.2
)
0.2

(0.9
)

(1.0
)
0.1

Total consolidated

$
513.3

$
540.2

$
(26.9
)

$
214.0

$
260.1

$
(46.1
)

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.

78

~~Table of Contents~~
Income Statement Highlights — Competitive Retail Segment

Three months ended June 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

Revenues:

Retail

$
106.1

$
62.5

$
43.6

RTO and other

(4.1
)
0.3

(4.4
)

$
102.0

$
62.8

$
39.2

Cost of revenues:

Purchased power

$
89.5

$
52.7

$
36.8

Gross margins (a)

$
12.5

$
10.1

$
2.4

Operation and maintenance expense

3.1

1.6

1.5

Other expenses (income), net

0.4

0.4

—

Total expenses, net

$
3.5

$
2.0

$
1.5

Earnings (Loss) from continuing operations before income tax

9.0

8.1

0.9

Income tax expense (benefit)

3.3

3.1

0.2

Net income (Loss)

$
5.7

$
5.0

$
0.7

Gross margin as a percentage of revenues

12.3
%
16.2
%

~~(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.

Three months ended

March 31,

Increase (Decrease)

Six months ended June 30,

Increase (Decrease)

2012

2011

2012 vs. 2011

$ in millions

2011

2010

2011 vs. 2010

Successor

Predecessor

Revenues:

Retail

$
199.6

$
104.0

$
95.6

$
107.6

$
94.3

$
13.3

RTO and other

(3.6
)
0.6

(4.2
)

4.5

(0.3
)
4.8

$
196.0

$
104.6

$
91.4

112.1

94.0

18.1

Cost of revenues:

Purchased power

$
167.2

$
90.0

$
77.2

96.7

77.7

19.0

Gross margins (a)

$
28.8

$
14.6

$
14.2

15.4

16.3

(0.9
)

Operation and maintenance expense

6.1

2.8

3.3

5.2

3.0

2.2

Other expenses (income), net

1.0

0.4

0.6

0.8

0.6

0.2

Total expenses, net

$
7.1

$
3.2

$
3.9

6.0

3.6

2.4

Earnings (Loss) from continuing operations before income tax

21.7

11.4

10.3

9.4

12.7

(3.3
)
Income tax expense (benefit)

9.9

4.3

5.6

3.4

6.6

(3.2
)
Net income (Loss)

$
11.8

$
7.1

$
4.7

$
6.0

$
6.1

$
(0.1
)

Gross margin as a percentage of revenues

14.7
%
14.0
%

Gross margin as a percentage of

revenues

14
%

17
%

(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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Competitive Retail Segment — Revenue
For the three months ended ~~June 30, 2011,~~March 31, 2012, the segment’s retail revenues increased ~~$43.6~~$13.3 million, or ~~70%~~14%, as compared to ~~the same period in 2010.~~2011. The increase was primarily ~~driven by the high~~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 ~~which~~ has ~~continued to result~~resulted in ~~a significant number~~many of DP&L’s retail customers switching their retail electric service to ~~DPLER. Also contributing to this increase was~~DPLER or other CRES suppliers. The increased sales volume from switching and the purchase of MC Squared ~~on February 28, 2011,~~was partially offset by unfavorable weather conditions resulting in ~~additional retail revenues~~a 23% decrease in the number of ~~$12.2 million recorded~~heating degree days during the ~~three months ended June 30,~~period in 2012 compared to 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately ~~1,420~~1,700 million kWh of power to ~~12,033~~more than 46,000 customers ~~in Ohio during~~for the three months ~~ended June 30, 2011~~ending March 31, 2012 compared to ~~1,033~~approximately 1,500 million kWh ~~sold~~of power to ~~2,661 Ohio~~more than 12,000 customers during the same period ~~in 2010.~~
~~For the six months ended June 30, 2011, the segment’s retail revenues increased $95.6 million, or 92%,~~ ~~compared to the same period in 2010. The increase was primarily driven by the high levels~~ of ~~competition in the competitive retail electric service business in the state of Ohio which has continued to result in a significant number of~~ ~~DP&L’s~~ retail customers switching their retail electric service to DPLER. Also contributing to this increase was the purchase of MC Squared on February 28, 2011, resulting in additional retail revenues of $16.3 million recorded since this purchase date. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 2,764 million kWh of power to 12,033 customers in Ohio during the six months ended June 30, 2011 compared to 1,753 million kWh sold to 2,661 Ohio customers during the same period in 2010.2011.

Competitive Retail Segment — Purchased Power
For the three months ended ~~June 30, 2011,~~March 31, 2012, ~~Purchased~~the Competitive Retail segment purchased power ~~for the segment~~ increased ~~$36.8~~$19.0 million, or ~~70%~~24%, as compared to ~~the same period in 2010 primarily~~2011 due to higher purchased power volumes required to satisfy an ~~increasing~~increase in customer base ~~as a result of~~resulting from customer switching and ~~the purchase of~~$11.1 million relating to power purchased for MC ~~Squared.~~Squared customers. The Competitive Retail segment’s electric energy used to meet its ~~Ohio~~ sales obligations was purchased from DP&L atand 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. This increase was partially offset by lower average prices paid for purchased~~ power ~~in 2011 compared to 2010. The electric energy used to meet~~at the ~~segment’s Illinois sales obligation was purchased from PJM.~~
~~For the six months ended June 30, 2011,~~ Purchased power for the segment increased $77.2 million, or 86%, as compared to the same period in 2010 primarily due to higher purchased power volumes required to satisfy an increasing customer base as a resultinception of ~~customer switching and the purchase of MC Squared. The Competitive Retail segment’s electric energy used to meet its Ohio sales obligations was purchased from~~ ~~DP&L~~ at market prices for wholesale power. This increase was partially offset by lower average prices paid for purchased power in 2011 compared to 2010. The electric energy used to meet the segment’s Illinois sales obligation was purchased from PJM.each customer’s contract.

Competitive Retail Segment — Operation and Maintenance
For the three months ended ~~June 30, 2011,~~March 31, 2012, ~~the segment’s Operation~~DPLER’s operation and maintenance expenses ~~which~~ include employee-related expenses, accounting, information technology, payroll, legal and other administration ~~expenses, increased $1.5 million, or 94%, compared to the same period in 2010.~~expenses. The higher operation and maintenance expense in ~~2011~~2012 as compared to ~~2010~~2011 is ~~primarily~~ reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of ~~customers.~~
~~For~~customers and the ~~six months ended June 30, 2011,~~ the segment’s Operation and maintenance expenses which include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses, increased $3.3 million, or 118%, compared to the same period in 2010. The higher operation and maintenance expense in 2011 as compared to 2010 is primarily reflectivepurchase of ~~increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.~~
80

~~Table of Contents~~MC Squared.

Competitive Retail Segment — Income Tax Expense
For the three months ended ~~June 30, 2011,~~March 31, 2012, the segment’s income tax expense ~~increased $0.2 million.~~
~~For the six months ended June 30, 2011,~~ ~~the segment’s income tax expense increased $5.6~~decreased $3.2 million compared to the same period in ~~2010~~2011 primarily due to ~~increased~~decreased pre-tax ~~income. In addition, as a result of the purchase of MC Squared we recorded~~income and decreased state income tax expenses. State income taxes were higher in 2011 due to a $2.0 million charge for state deferred taxes due to the Illinois Unitary Tax ~~rules.~~rules as a result of the purchase of MC Squared.
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Table of Contents

RESULTS OF OPERATIONS — DP&L
Income Statement Highlights — DP&L

Three Months Ended

Six Months Ended

Three Months Ended

June 30,

June 30,

March 31,

$ in millions

2011

2010

2011

2010

2012

2011

Revenues:

Retail

$
243.7

$
281.3

$
534.1

$
595.4

$
242.7

$
276.3

Wholesale

104.7

89.6

210.9

165.9

104.5

106.2

RTO revenues

18.1

19.0

38.5

39.2

17.3

20.4

RTO capacity revenues

42.1

34.0

88.9

61.4

31.4

46.8

Mark-to-market gains

3.7

0.1

Total revenues

$
408.6

$
423.9

$
872.4

$
861.9

$
399.6

$
449.8

Cost of revenues:

Fuel costs

$
90.2

$
90.0

$
190.6

$
191.0

$
88.8

$
99.8

Gains from sale of coal

(1.1
)
(1.1
)
(2.9
)
(1.3
)
Gains from sale of emission allowances

—

(0.4
)
—

(0.6
)
Losses / (gains) from sale of coal

3.4

(1.8
)
Mark-to-market losses

3.4

0.6

Net fuel

89.1

88.5

187.7

189.1

95.6

98.6

Purchased power

32.4

21.4

66.6

35.0

25.5

33.9

RTO charges

27.6

26.1

56.7

50.6

24.1

29.1

RTO capacity charges

44.4

42.8

98.9

77.3

31.5

54.5

Mark-to-market losses

3.8

0.3

Total purchased power

104.4

90.3

222.2

162.9

84.9

117.8

Total cost of revenues

$
193.5

$
178.8

$
409.9

$
352.0

$
180.5

$
216.4

Gross margins (a)

$
215.1

$
245.1

$
462.5

$
509.9

$
219.1

$
233.4

Gross margin as a percentage of revenues

52.6
%
57.8
%
53.0
%
59.2
%

55
%
52
%

Operating Income

$
55.8

$
97.0

$
145.1

$
215.4

$
65.0

$
89.3

(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.

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’s retail 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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Table of Contents

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

Three Months Ended

Six Months Ended

Three Months Ended

June 30,

June 30,

March 31,

$ in millions

2011 vs. 2010

2011 vs. 2010

2012 vs. 2011

Retail

Rate

$
(17.9
)
$
(34.1
)

$
(3.0
)
Volume

(21.2
)
(29.7
)

(30.8
)
Other miscellaneous

1.5

2.5

0.2

Total retail change

$
(37.6
)
$
(61.3
)

(33.6
)

Wholesale

Rate

$
8.0

$
11.0

5.7

Volume

7.1

34.0

(7.4
)
Total wholesale change

$
15.1

$
45.0

(1.7
)

RTO capacity and other

RTO capacity and other revenues

$
7.2

$
26.8

RTO capacity and other RTO revenues

(18.5
)

Other

Unrealized MTM

$
3.6

Total revenues change

$
(15.3
)
$
10.5

$
(50.2
)

For the three months ended ~~June 30, 2011,~~March 31, 2012, Revenues decreased ~~$15.3~~$50.2 million, or 4%11%, to ~~$408.6~~$399.6 million from ~~$423.9~~$449.8 million in the prior year. This decrease was primarily the result of lower average retail rates, ~~and~~ lower retail ~~sales volumes, partially offset by~~and wholesale sales volumes ~~higher average wholesale prices as well as increased~~and decreased RTO capacity and other ~~revenues.~~revenues, partially offset by higher average wholesale prices. The revenue components for the three months ended ~~June 30, 2011~~March 31, 2012 are further discussed below:

·                  Retail revenues decreased ~~$37.6~~$33.6 million primarily ~~as a result of a 7%~~due to an 11% decrease in ~~average~~ retail ~~rates~~sales volumes compared to those in the prior year largely due to ~~customers switching~~unfavorable weather conditions. The unfavorable weather conditions resulted in a 23% decrease in the number of heating degree days to 2,263 days from ~~DP&L~~.2,967 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% 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 ~~average~~ rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by ~~an increase in~~ the ~~Fuel~~implementation of the fuel and ~~Purchased Power Recovery Rider~~energy efficiency riders, increased TCRR and ~~an increase in~~RPM riders, and the ~~Universal Service Fund Rider. Also contributing to~~incremental effect of the ~~decline in revenues was an 8% decrease in retail sales volumes largely due to an unfavorable 15% decrease in cooling degree days from~~recovery of costs under the ~~prior year.~~EIR. The above resulted in an unfavorable ~~$17.9~~$30.8 million retail ~~price~~sales volume variance and an unfavorable ~~$21.2~~$3.0 million retail ~~sales volume~~price variance.

·                  Wholesale revenues ~~increased $15.1~~decreased $1.7 million primarily as a result of ~~an 8% increase in average wholesale prices combined with an 8% increase~~a 7% decrease in wholesale sales volume ~~due in large part to~~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% increase in average wholesale sales prices. This resulted in ~~a favorable $8.0~~an unfavorable $7.4 million wholesale ~~price~~volume variance ~~and~~offset partially by a $5.7 million favorable wholesale ~~sales volume variance of $7.1 million.~~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, ~~increased $7.2~~decreased $18.5 million compared to the same period in ~~2010.~~2011. This ~~increase~~decrease in RTO capacity and other revenues was primarily the result of a ~~$7.9~~$15.4 million ~~increase~~decrease in revenues realized from the PJM capacity auction, ~~offset slightly by~~and a decrease of $3.1 million in transmission and congestion revenues.

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For the six months ended June 30, 2011, Revenues increased $10.5 million, or 1%, to $872.4 million from $861.9 million in the prior year. This increase was primarily the result of higher wholesale sales volumes, higher average wholesale prices as well as increased RTO capacity and other revenues, partially offset by lower average retail rates and lower retail sales volumes. The revenue components for the six months ended June 30, 2011 are further discussed below:
·~~Retail revenues decreased $61.3 million primarily as a result of a 6% decrease in average retail rates due to customers switching from~~ ~~DP&L~~~~. 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 remaining distribution services provided by~~ ~~DP&L~~ were billed at a lower average rate resulting in a reduction of total average retail rates. The decrease in average retail rates resulting from customers switching was partially offset by increases in the Fuel and Purchased Power Recovery Rider and the Universal Service Fund Rider. Also contributing to the decline in revenues was a 5% decrease in retail sales volumes largely due to an unfavorable 15% decrease in cooling degree days from the prior year. The above resulted in an unfavorable $34.1 million retail price variance and an unfavorable $29.7 million retail sales volume variance.
·Wholesale revenues increased $45.0 million primarily as a result of a 6% increase in average wholesale prices combined with a 21% increase in wholesale sales volume due in large part to 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 a favorable $34.0 million wholesale sales volume variance and a favorable wholesale price variance of $11.0 million.
·~~RTO capacity and other revenues, consisting primarily of compensation for use of~~ ~~DP&L’s~~ transmission assets, regulation services, reactive supply and operating reserves, and capacity payments under the RPM construct, increased $26.8 million compared to the same period in 2010. This increase in RTO capacity and other revenues was primarily the result of a $27.4 million increase in revenues realized from the PJM capacity auction offset slightly be a decrease in transmission and congestion revenues.
DP&L — Cost of Revenues
For the three months ended ~~June 30, 2011:~~March 31, 2012:

·                  Net fuel costs, which include coal, gas, oil and emission allowance costs, ~~increased $0.6~~decreased $3.0 million, or 1%3%, compared to ~~2010, primarily due to~~2011. During the ~~impact of~~quarter ended March 31, 2012, fuel costs decreased by $11.0 million driven by a ~~17.8%~~14% decrease in the volume of generation at our plants. This decrease was partially offset by increased losses on the sale of coal and ~~a 12.7% increase~~MTM. DP&L realized $3.4 million in losses from the ~~price~~sale of ~~generation by our plants resulting from an increase~~coal, compared to $1.8 million of realized gains during the same period in ~~and the timing of, unit outages during~~2011. In addition, unrealized MTM losses were $3.4 million for the three months ended ~~June 30, 2011, when~~March 31, 2012 compared to $0.6 million for the same period in ~~2010.~~2011.

·                  Net purchased power ~~increased $14.1~~decreased $32.9 million, or ~~16%~~28%, compared to the same period in ~~2010,~~2011 due largely to ~~an increase of $3.1~~a $28.0 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 included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. ~~Also contributing~~Purchased power volumes decreased 23% and purchased power prices decreased approximately 2% compared to the ~~increase~~same period in ~~net purchased power was a $19.7 million increase associated with higher purchased power volumes partially offset by $5.8 million related to lower average market prices for purchased power.~~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.

~~For the six months ended June 30, 2011:~~
·Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $1.4 million, or 1%, compared to 2010, primarily due to the impact of a 16.0% decrease in the volume of generation and a 15.8% increase in the price of generation by our plants resulting from an increase in, and the timing of, unit outages during the six months ended June 30, 2011, when compared to the same period in 2010.
·Net purchased power increased $59.3 million, or 36%, compared to the same period in 2010, due largely to an increase of $27.7 million 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 included the net impact of the deferral and recovery of~~ ~~DP&L’s~~ transmission, capacity and other PJM-related charges. Also contributing to the increase in net purchased power was a $48.8 million increase associated with higher purchased power volumes partially offset by $15.9 million related to lower average market prices for purchased power. 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.
83

~~Table of Contents~~
DP&L — Operation and Maintenance

Three Months Ended

Six Months Ended

Three Months Ended

June 30,

June 30,

March 31,

$ in millions

2011 vs. 2010

2011 vs. 2010

2012 vs 2011

Low-income payment program (1)

$
5.2

Generating facilities operating and maintenance expenses

$
8.7

$
16.0

1.4

Pension expenses

1.1

Maintenance of overhead transmission and distribution lines

2.2

9.5

(5.7
)
Low-income payment program (1)

3.2

7.7

Energy efficiency programs (1)

0.3

(1.6
)
Group insurance / long-term disability

(4.3
)
(4.1
)
Other, net

(0.4
)
(5.7
)

5.8

Total operation and maintenance expense

$
9.7

$
21.8

$
7.8

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

For the three months ended ~~June 30, 2011,~~March 31, 2012, Operation and maintenance expense increased ~~$9.7~~$7.8 million, or ~~11%~~9%, compared to the same period in ~~2010.~~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~~jointly owned production units relative to the same period in ~~2010,~~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 decreased expenses related to the maintenance of overhead transmission and distribution lines ~~and~~
·~~increased assistance for low-income retail customers which is funded by the USF revenue rate rider.~~
~~These increases were partially offset by lower health insurance and disability costs~~ primarily ~~due to fewer employees filing for long-term disability during the current quarter~~ as ~~compared to the same period in 2010.~~
~~For the six months ended June 30, 2011, Operation and maintenance expense increased $21.8 million, or 13%, compared to the same period in 2010. This variance was primarily the~~a result ~~of:~~
·~~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 2010,~~
·~~increased expenses related to the maintenance of overhead transmission and distribution lines largely related to~~storms, including a significant ice storm in February ~~2011, and~~
·~~increased assistance for low-income retail customers which is funded by the USF revenue rate rider.~~
~~These increases were partially offset by:~~
·~~lower expenses relating to energy efficiency programs that were put in place for our customers, and~~
·~~lower health insurance and disability costs primarily due to fewer employees filing for long-term disability during the current quarter as compared to the same period in 2010.~~2011.

DP&L — Depreciation and Amortization
For the three months ended ~~June 30, 2011~~March 31, 2012, Depreciation and amortization expense increased ~~$0.2~~$1.6 million ~~or 1%,~~ as compared to 2011. The increase primarily reflected the impact of investments in plant and equipment during the three months ended June 30, 2010. The increase is primarily the result of a net increase in depreciable property partially offset by a decrease due to a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010.March 31, 2012.
DP&L — General Taxes

For the ~~six~~three months ended ~~June 30, 2011~~March 31, 2012, ~~Depreciation and amortization expense decreased $1.5~~General taxes increased $0.6 million, or 2%3%, as compared to 2011. This increase was primarily the ~~six months ended June 30, 2010.~~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 ~~decrease primarily reflected the impact of a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010.~~2011 amount was reclassified to conform to this presentation.

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Table of Contents

DP&L — ~~General Taxes~~
~~For the three and six months ended June 30, 2011~~, General taxes increased $1.3 million, or 4.4%, and $2.6 million, or 4.2%, respectively, as compared to the same periods in 2010. These increases were primarily the result of higher property tax accruals in 2011 compared to 2010.
~~DP&L — Investment Income~~
~~Investment income recorded during the three and six months ended June 30, 2011 did not fluctuate significantly from that recorded during the three and six months ended June 30, 2010.~~
~~DP&L —~~ Interest Expense
Interest expense recorded during the three ~~and six~~ months ended ~~June 30, 2011~~March 31, 2012 did not fluctuate significantly from that recorded during the three ~~and six~~ months ended ~~June 30, 2010.~~March 31, 2011.

DP&L — Income Tax Expense
For the three ~~and six~~ months ended ~~June 30, 2011,~~March 31, 2012, Income tax expense decreased ~~$12.9~~$9.7 million, or ~~45%~~36%, ~~and $22.7 million, or 35%, respectively,~~as compared to ~~the same period in 2010,~~2011 primarily due to decreased pre-tax income.

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~~
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

For the Six Months

Ended June 30,

$ in millions

2011

2010

Net cash provided by operating activities

$
185.1

$
204.9

Net cash used for investing activities

(28.6
)
(120.2
)
Net cash used for financing activities

(207.7
)
(72.2
)

Net change

$
(51.2
)
$
12.5

Cash and cash equivalents at beginning of period

124.0

74.9

Cash and cash equivalents at end of period

$
72.8

$
87.4

~~DP&L~~
DP&L

For the Six Months

For the Three Months

Ended June 30,

Ended March 31,

$ in millions

2011

2010

2012

2011

Net cash provided by operating activities

$
163.2

$
205.1

$
89.6

$
84.0

Net cash used for investing activities

(89.1
)
(71.6
)

(53.2
)

(40.4
)
Net cash used for financing activities

(115.4
)
(150.4
)

(45.2
)

(40.2
)

Net change

$
(41.3
)
$
(16.9
)

(8.8
)

3.4

Cash and cash equivalents at beginning of period

54.0

57.1

32.2

54.0

Cash and cash equivalents at end of period

$
12.7

$
40.2

$
23.4

$
57.4

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

85

~~Table of Contents~~
Net Cash Provided by Operating Activities
The revenue from our energy business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes.

94

Table of Contents
DPL — Net ~~Cash~~cash provided by ~~Operating Activities~~operating activities
DPL’s Net cash provided by operating activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Successor

Predecessor

Three months

Three months

Six Months Ended

ended

ended

June 30,

March 31,

March 31,

$ in millions

2011

2010

2012

2011

Net income

$
75.2

$
132.4

$
21.7

$
43.5

Depreciation and amortization

70.2

73.1

54.5

35.1

Deferred income taxes

37.5

6.4

(9.2
)

33.7

Charge for early redemption of debt

—

15.3

Contribution to pension plan

(40.0
)
(20.0
)

—

(40.0
)
Charge for early redemption of debt

15.3

—

Accrued interest

29.1

(1.2
)
Deferred regulatory costs, net

7.2

12.8

Other

26.9

13.0

(8.7
)

(7.2
)
Net cash provided by operating activities

$
185.1

$
204.9

$
94.6

$
92.0

For the ~~six~~three months ended ~~June 30,~~March 31, 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 months ended March 31, 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 ~~$37.5~~$33.7 million increase to Deferred income taxes primarily as a result of depreciation as well as pension contributions.
·~~DP&L~~ ~~made a discretionary contribution of $40.0 million to the defined benefit pension plan in February 2011.~~
·                  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.
·                  Other ~~which~~ represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances.

~~For the six months ended June 30, 2010,~~DP&L — Net cash provided by operating activities ~~was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:~~
·The $6.4 million increase to Deferred income taxes primarily results from a $7.0 million temporary difference due to a pension contribution and other temporary differences arising from routine changes in balance sheet accounts.
·~~DP&L~~ ~~made a discretionary contribution of $20.0 million to the defined benefit pension plan in February 2010.~~
·Other, which represents items that had a current period cash flow impact and includes changes in working capital and other future rights or obligations to receive or to pay cash. These items are primarily impacted by, among other factors, the timing of when cash payments are made for fuel, purchased power, operating costs, interest and taxes, and when cash is received from our utility customers and from the sales of coal and excess emission allowances.
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~~DP&L — Net Cash provided by Operating Activities~~
DP&L’s Net cash provided by operating activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Six Months Ended

Three Months Ended

June 30,

March 31,

$ in millions

2011

2010

2012

2011

Net income

$
83.5

$
131.5

$
38.1

$
52.7

Depreciation and amortization

66.5

68.0

34.7

33.1

Deferred income taxes

37.2

5.8

(2.4
)

33.3

Contribution to pension plan

(40.0
)
(20.0
)

—

(40.0
)
Deferred regulatory costs, net

7.1

12.8

Other

16.0

19.8

12.1

(7.9
)
Net cash provided by operating activities

$
163.2

$
205.1

$
89.6

$
84.0

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Table of Contents

For the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011, ~~and 2010,~~ 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 Investing Activities~~cash (used for) / provided by investing activities
DPL’s Net cash used for investing activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Successor

Predecessor

Three months

Three months

Six Months Ended

ended

ended

June 30,

March 31,

March 31,

$ in millions

2011

2010

2012

2011

Other plant-related asset acquisitions, net

$
(51.7
)

$
(41.4
)
Environmental and renewable energy capital expenditures

$
(5.9
)
$
(7.2
)

(2.3
)

(1.6
)
Other asset acquisitions, net

(85.5
)
(67.9
)
Purchase of MC Squared

(8.2
)
—

—

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

69.2

(47.0
)

—

59.1

Other

1.8

1.9

—

2.1

Net cash used for investing activities

$
(28.6
)
$
(120.2
)
Net cash (used for) / provided by investing activities

$
(54.0
)

$
10.0

For the ~~six~~three months ended ~~June 30,~~March 31, 2012, DPL’s cash used for investing activities reflects assets acquired at our generation plants.
For the three months ended March 31, 2011, ~~DP&L~~DPL ~~continued to see reductions in its environmental and renewable energy capital expenditures due to the completion of the solar energy facility~~cash used for investing activities was primarily for assets acquired at ~~Yankee Station during 2010.~~our generation plants. Additionally, DPL, on behalf of DPLER, made a cash payment of approximately $8.2 million to acquire MC ~~Squared (see Note 15 of Notes to Condensed Consolidated Financial Statements).~~Squared. Also during the ~~six~~three months ended ~~June 30,~~March 31, 2011, DPL redeemed ~~$70.9~~$60.8 million of short-term investments mostly comprised of VRDN securities as well as ~~purchasing~~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.

~~For the six months ended June 30, 2010,~~ ~~DP&L~~ ~~incurred environmental and renewable energy capital expenditures primarily related to the construction of a solar energy facility at Yankee Station.~~ ~~DP&L~~ ~~also continued to make upgrades and other investments in other generation, transmission and distribution equipment. During this period,~~ ~~DPL~~ also purchased a net $32 million of VRDN securities from various institutional securities brokers as well as $15 million of investment-grade fixed income corporate bonds. The VRDN securities are backed by irrevocable letters of credit. These securities have variable coupon rates that are typically re-set weekly relative to various short-term rate indices. ~~DPL~~ ~~can tender these VRDN securities for sale upon notice to the broker and receive payment for the tendered securities within seven days.~~
87

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DP&L — Net ~~Cash~~cash used for ~~Investing Activities~~investing activities
DP&L’s Net cash used for investing activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Six Months Ended

Three Months Ended

June 30,

March 31,

$ in millions

2011

2010

2012

2011

Other plant-related asset acquisitions, net

$
(50.9
)
$
(40.8
)
Environmental and renewable energy capital expenditures

$
(5.8
)
$
(7.2
)

(2.3
)
(1.6
)
Other asset acquisitions, net

(85.0
)
(66.3
)
Other

1.7

1.9

—

2.0

Net cash used for investing activities

$
(89.1
)
$
(71.6
)

$
(53.2
)
$
(40.4
)

For the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011, ~~and 2010,~~ the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’sNet cash ~~provided by /~~ used for investing activities ~~above.~~above with the exception of the short-term investing activity.

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Table of Contents
DPL — Net ~~Cash~~cash used for ~~Financing Activities~~financing activities
DPL’s Net cash used for financing activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Successor

Predecessor

Three months

Three months

Six Months Ended

ended

ended

June 30,

March 31,

March 31,

$ in millions

2011

2010

2012

2011

Dividends paid on common stock

$
(76.4
)
$
(69.9
)

$
(45.0
)

$
(37.8
)
Repurchase of DPL common stock

—

(3.9
)
Contributions to additional paid-in capital from parent

2.0

—

Payment to former warrant holders

(9.0
)

—

Early redemption of long-term debt, including premium

(134.2
)
—

—

(134.2
)
Payment of MC Squared debt

(13.5
)
—

—

(13.5
)
Exercise of warrants

14.7

—

Other

1.7

1.6

Withdrawals from revolving credit facility, net

—

30.0

Net cash used for financing activities

$
(207.7
)
$
(72.2
)

$
(52.0
)

$
(155.5
)

For the ~~six~~three months ended ~~June 30,~~March 31, 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 months ended March 31, 2011, DPL paid common stock dividends of ~~$76.4~~$37.8 million and paid $134.2 million for the purchase of the DPL Capital Trust II capital securities, of which ~~$122~~$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 (see Note 15 of Notes to Condensed Consolidated Financial Statements), and~~2011. In addition, DP&L ~~received $14.7~~initiated net draws of $30.0 million ~~from the exercise~~on one of ~~700,000 warrants.~~
~~For the six months ended June 30, 2010,~~ ~~DPL~~ paid common stock dividends of $69.9 million. In addition, under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 11 of Notes to Condensed Consolidated Financial Statements), ~~DPL~~ ~~repurchased approximately 145,915~~ ~~DPL~~ ~~common shares for $3.9 million.~~its revolving credit facilities.

DP&L — Net ~~Cash~~cash used for ~~Financing Activities~~financing activities
DP&L’s Net cash used for financing activities for the ~~six~~three months ended ~~June 30,~~March 31, 2012 and 2011 ~~and 2010~~ can be summarized as follows:

Six Months Ended

Three Months Ended

June 30,

March 31,

$ in millions

2011

2010

2012

2011

Dividends paid on common stock to parent

$
(115.0
)
$
(150.0
)

$
(45.0
)

$
(70.0
)
Withdrawals from revolving credit facility, net

—

30.0

Other

(0.4
)
(0.4
)

(0.2
)

(0.2
)
Net cash used for financing activities

$
(115.4
)
$
(150.4
)

$
(45.2
)

$
(40.2
)

88

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

For the ~~six~~three months ended ~~June 30,~~March 31, 2011, DP&L’s Net cash used for financing activities primarily relates to ~~$115.0~~$70.0 million in dividends ~~paid to~~ ~~DPL~~.
~~For the six months ended June 30, 2010,~~ ~~DP&L’s~~ ~~Net cash used for financing activities primarily relates to $150.0~~partially offset by a net withdrawal of $30.0 million ~~in dividends paid to~~ ~~DPL~~.on one of its revolving credit facilities.

Liquidity
We expect our existing sources of liquidity to remain sufficient to meet our anticipated obligations. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements for retail operations, ~~interest~~ and dividend payments. For ~~2011,~~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.
97

Table of Contents

At the filing date of this quarterly report on Form 10-Q, DP&L has access to ~~$420~~$400.0 million of short-term financing under two revolving credit facilities. The first facility, established in August 2011, is for ~~$220~~$200.0 million and expires in ~~November 2011~~August 2015 and has ~~three~~eight participating ~~banks;~~banks, with no bank having more than 22% of the ~~lead bank~~total commitment. DP&L also has ~~a total commitment of 36% while~~ the ~~other two have commitments of 32% each.~~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~~$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.

Amounts

available as of

$ in millions

Type

Maturity

Commitment

June 30, 2011

DP&L

Revolving

November 2011

$
220.0

$
220.0

DP&L

Revolving

April 2013

$
200.0

$
200.0

$
420.0

$
420.0

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

available as of

$ in millions

Type

Maturity

Commitment

March 31, 2012

DP&L

Revolving

August 2015

$
200.0

$
200.0

DP&L

Revolving

April 2013

200.0

200.0

DPL Inc.

Revolving

August 2014

125.0

125.0

$
525.0

$
525.0

EachDP&L revolving credit facility has a ~~$50~~$50.0 million ~~Letter~~letter of ~~Credit (LOC)~~credit sublimit. The entire DPL revolving credit facility amount is available for letter of credit issuances. As of ~~June 30, 2011~~March 31, 2012 and through the date of filing this quarterly report on Form 10-Q, there were no letters of credit issued and outstanding ~~LOCs~~ on ~~either facility.~~
~~DPL’s~~ ~~$297.4 million 6.875% senior notes due September 2011 have been reflected as a current liability. Management will continue to monitor and evaluate market conditions over~~ the ~~next several months and make a determination to either seek to refinance the senior notes or explore alternative financing arrangements.~~
The Merger Agreement discussed in Note 16 of Notes to Condensed Consolidated Financial Statements also includes certain provisions whereby we have agreed to use commercially reasonable efforts to replace ~~DP&L’s~~ ~~existing $220.0 million~~ revolving credit ~~facility. We have agreed to replace this facility with a new revolving credit facility in an amount equal to or greater than $200.0 million with a term of at least three years.~~ ~~DPL~~ has also agreed to use commercially reasonable efforts to enter into a revolving credit facility in an amount equal to or greater than $125.0 million with a term of at least three years and to enter into a $425.0 million term loan with a term of at least three years, in part, to refinance the approximately $297.4 million principal amount of ~~DPL’s~~ ~~6.875% debt that is due in September 2011.~~facilities.

Cash and cash equivalents for DPL and DP&L amounted to ~~$72.8~~$162.1 million and ~~$12.7~~$23.4 million, respectively, at ~~June 30,~~March 31, 2012. At that date, neither DPL nor DP&L had short-term investments.
On February 23, 2011, DPL purchased $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.

89Capital 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 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.
98

Table of Contents

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, 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 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’ 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 ~~$420~~$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 ~~June 30,~~March 31, 2011, 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 ~~guaranty~~guarantee obligations, divided by the total of DP&L’s shareholders’ equity and total debt including ~~guaranty~~guarantee obligations.

There have been no material changes to our debt covenants as disclosed in our ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, ~~2010. We are in compliance with all of our debt covenants.~~2011.

~~Capital Requirements~~Debt Ratings
~~Planned construction additions for 2011 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 $770 million in capital projects for the period 2011 through 2013. Approximately $15 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. Additionally, ~~DP&L~~ anticipates spending approximately $70 million within the next five years as part of its identified obligations under the PJM RTEP (Regional Transmission Expansion Plan) within its zone, as well as a cost-allocation of approximately $160 million for RTEP projects in other PJM zones. The latter is subject to change pending the revised PJM cost-allocation methodology, as a result of the Court of Appeals decision to remand the case to the FERC. 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.
~~DPL’s~~ ~~construction additions were $86.8 million and $62.4 million during the six month periods ended June 30, 2011 and 2010, respectively.~~ ~~DPL~~ ~~expects to spend approximately $310 million in 2011 on construction additions. Planned construction additions for 2011 relate to~~ ~~DP&L’s~~ ~~environmental compliance program, power plant equipment, and its transmission and distribution system.~~
~~DP&L’s~~ ~~construction additions were $86.3 million and $60.8 million during the six month periods ended June 30, 2011 and 2010, respectively.~~ ~~DP&L~~ ~~expects to spend approximately $300 million in 2011 on construction additions. Planned construction additions for 2011 relate to~~ ~~DP&L’s~~ ~~environmental compliance program, power plant equipment, and its transmission and distribution system.~~
~~Credit Ratings~~
The following table outlines the debt ~~credit~~ ratings and outlook offor 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+

AStable

~~Negative~~
~~April~~November 2011
Moody’s Investors Service

~~Baa1~~Ba1

~~Aa3~~A3

~~Negative~~Stable

~~April~~November 2011
Standard & Poor’s Corp.

BB+
BBB+

A
CreditWatch Negative

April ~~2011~~2012

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

~~In connection~~Credit Ratings
The following table outlines the credit ratings (issuer/corporate rating) and outlook for each company, along with the ~~closing~~effective dates of ~~the Proposed Merger (see Note 16 of Notes to Condensed Consolidated Financial Statements),~~each rating and outlook for DPL is expected to assume upon closing of the Proposed Merger, $1.25 billion of debt that an AES affiliate will issue to finance the acquisition. As a result of this proposed additional indebtedness, in April 2011 ~~DPL~~and DP&L ~~were downgraded by one~~.
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 ~~major credit rating agencies above~~unregulated retail business and ~~all three major credit rating agencies reduced their outlook from stable~~the increasing competitive pressure due to ~~negative.~~ ~~DPL’s~~ ~~and~~ ~~DP&L’s~~ ~~credit rating may have additional downgrades as a result of the Proposed Merger discussed in Note 16 of Notes to Condensed~~lower wholesale electric prices stressing profit margins.

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~~Consolidated Financial Statements. This~~If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may ~~cause~~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 ~~need for additional credit assurance to satisfy various creditors.~~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~~wholly owned subsidiaries, DPLE and DPLER, and its ~~indirect wholly-owned~~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. ~~Certain~~During the three months ended March 31, 2012, DPL did not incur any losses related to the guarantees of ~~DPL’s~~ ~~financial or performance assurance agreements contain provisions~~these obligations and we believe it is unlikely 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~~DPL would be required to perform or incur any losses in ~~violation~~the future associated with any of the provisions, and the counterparties to the assurance agreements could demand alternative credit assurance. The changes in our credit ratings in April 2011 have not triggered these provisions. There may be further changes to our credit ratings which may trigger these provisions.above guarantees.

At ~~June 30, 2011,~~March 31, 2012, DPL had ~~$90.2~~$47.4 million of guarantees to third parties for future financial or performance assurance under such agreements, ~~including $73.2 million of guarantees~~ on behalf of DPLE, ~~and~~ DPLER and ~~$17.0 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 at any time 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 ~~$2.6 million and $1.0~~$0.4 million at ~~June 30, 2011 and 2010, respectively.~~March 31, 2012.

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 ~~June 30, 2011,~~March 31, 2012, DP&L could be responsible for the repayment of 4.9%, or ~~$61.4~~$64.9 million, of a ~~$1,252.5~~$1,324.7 million debt obligation that ~~matures in~~features maturities ranging from 2013 to 2026. This would only happen if this electric generation company defaulted on its debt payments. As of ~~June 30, 2011,~~March 31, 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 ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, ~~2010 except for the note payable~~2011.
Also see Note 13 of Notes to ~~the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum discussed further in Note 5 of~~ ~~Notes to~~DPL’s Condensed Consolidated Financial Statements.

~~See Note 14 of Notes to Condensed Consolidated Financial Statements.~~
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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), ~~comprised~~comprising 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 ~~2011~~2012 under contract, sales requirements may ~~change, particularly for retail load.~~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. 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; 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.

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 and forward power contracts at ~~June 30, 2011~~March 31, 2012 would not have a significant effect on Net income.
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The following table provides information regarding the volume and average market price of our NYMEX coal forward derivative contracts at ~~June 30, 2011~~March 31, 2012 and the effect to Net income if the market price were to increase or decrease by 10%:

Weighted

Increase /

Average

Decrease in

Contract

Market

Net Income

Commodity

Volume

Units

Price / Unit

(in millions)

NYMEX Coal Forwards - Non-Hedged

2011 - Purchase

149,188

tons

$
77.89

$
0.4
(a)
2012 - Purchase

1,246,200

tons

$
82.26

$
3.8
(a)
2013 - Purchase

372,000

tons

$
86.72

$
2.1
(a)
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 impact~~Income effect of a 10% change in the market price of NYMEX ~~coal is~~Coal has been partially ~~offset~~off-set by our partners’ share of the gain or loss and by the retail ~~jurisdictional~~jurisdicational share of the DPLportion that is deferred on the balance sheet in conjunction with the fuel ~~cost~~ and purchased power recovery rider.

Wholesale Revenues
Approximately ~~18%~~14% of DPL’s and ~~16%~~34% of DP&L’s electric revenues for the three months ended ~~June 30,~~March 31, 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% of DP&L’s electric revenues for the three months ended March 31, 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.

~~Approximately 17%~~101

Table of ~~DPL’s~~ ~~and 17% of~~ ~~DP&L’s~~ electric revenues for the three months ended June 30, 2010 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.
~~Approximately 18% of~~ ~~DPL’s~~ ~~and 16% 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. 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 17% of~~ ~~DPL’s~~ ~~and 16% of~~ ~~DP&L’s~~ electric revenues for the six months ended June 30, 2010 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.Contents

The table below provides the effect on annual Net income as of ~~June 30, 2011,~~March 31, 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

$
8.5

$
7.0

Effect of 10% change in price per mWh

$
7.0

$
5.8

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 delivery year. The clearing prices for capacity during the PJM delivery periods from 2010/11 through 2014/15 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

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PJM Delivery Year

2010/11

2011/12

2012/13

2013/14

2014/15

Capacity clearing price ($/MW-day)

$
174

$
110

$
16

$
28

$
126

Our computed average capacity prices by calendar year are reflected in the table below:

Calendar Year

2010

2011

2012

2013

Computed average capacity price ($/MW-day)

144

137

55

23

Calendar Year

2010

2011

2012

2013

2014

Computed average capacity price ($/MW-day)

$
144

$
137

$
55

$
23

$
85

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 ~~June 30, 2011,~~March 31, 2012 of a hypothetical increase or decrease of ~~$10~~$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 ~~June 30, 2011.~~March 31, 2012. As of ~~June 30, 2011,~~March 31, 2012, approximately ~~55%~~47% 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 change in capacity auction pricing

$
5.0

$
3.7

Effect of a $10/MW-day change in capacity auction pricing

$
5.3

$
4.0

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’sfuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs ~~for~~in the three months ~~and six months~~ ended ~~June 30,~~March 31, 2012 and 2011 were ~~35%~~34% and ~~35%~~37%, respectively. We have ~~substantially all~~a significant portion of ~~the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2011~~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 ~~2011;~~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 ~~2011~~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 ~~55%~~49% of DP&L’s total fuel costs. The table below provides the effect on annual net income as of ~~June 30, 2011,~~March 31, 2012, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate ~~55%:~~49% recovery:

$ in millions

DPL

DP&L

DPL

DP&L

Effect of 10% change in fuel and purchased power

$
18.7

$
18.1

$
17.4

$
15.7

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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 ~~has fixed-rate long-term debt~~ and DP&L ~~has~~have both ~~fixed~~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 ~~associated with tax-exempt~~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. ~~As a result of the Proposed Merger with AES,~~ ~~DPL~~ ~~and~~ ~~DP&L~~ were recently downgraded by one of the major credit rating agencies and all three major credit rating agencies reduced their outlook from stable to negative. We do not anticipate these reduced ratings having a significant impact on our liquidity; however, our cost of capital will increase. See Note ~~5 and Note 16~~7 of Notes to DPL’sCondensed 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 ~~June 30, 2011,~~March 31, 2012, we have entered into interest rate hedging relationships with an aggregate notional amount of ~~$300 million and $160~~$160.0 million related to planned future borrowing activities in calendar year ~~2011 and calendar year 2013, respectively.~~2013. The average interest rate associated with the ~~$300 million and $160~~$160.0 million aggregate notional amount interest rate hedging relationships is ~~4.04% and 3.80%, respectively.~~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 ~~$1,221.4~~$2,624.5 million at ~~June 30, 2011,~~March 31, 2012, consisting of~~DP&L’s~~ ~~first mortgage bonds,~~ ~~DP&L’s~~ ~~debt associated with tax-exempt pollution control bonds,~~ DPL’s unsecured notes and unsecured term loan, along with DP&L’sfirst mortgage bonds, tax-exempt pollution control bonds, capital leases, and the Wright-Patterson Air Force Base debt facility. All of DPL’s ~~capital lease.~~debt was adjusted to fair value at the Merger date according to FASC 805. The fair value of this debt at March 31, 2012 was ~~$1,198.7~~$2,723.4 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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Table of Contents
~~Principal Payments~~Carrying Value and Interest Rate Detail by Contractual Maturity Date
DPL

Carrying value at

Fair value at

Carrying value at

Fair value at

For the years ending June 30,

June 30,

June 30,

March 31,

March 31,

$ in millions

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (a)

2013

2014

2015

2016

2017

Thereafter

2012 (a)

2012 (a)

Long-term debt

Variable-rate debt

$
—

$
—

$
—

$
—

$
—

$
100.0

$
100.0

$
100.0

$
—

$
—

$
425.0

$
—

$
—

$
100.0

$
525.0

$
525.0

Average interest rate

0.0
%
0.0
%
0.0
%
0.0
%
0.0
%
0.1
%
0.1
%

0.0
%
0.0
%
2.3
%
0.0
%
0.0
%
0.1
%

Fixed-rate debt

$
297.8

$
0.4

$
470.4

$
0.1

$
0.1

$
352.6

$
1,121.4

$
1,098.7

$
0.4

$
499.3

$
0.2

$
0.1

$
450.1

$
1,149.4

$
2,099.5

$
2,198.4

Average interest rate

6.9
%
4.9
%
5.1
%
4.2
%
4.2
%
5.0
%
5.5
%

4.9
%
5.1
%
4.8
%
4.2
%
6.5
%
6.6
%

Total

$
1,221.4

$
1,198.7

$
2,624.5

$
2,723.4

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

The carrying value of DP&L’s debt was ~~$903.4~~$903.3 million at ~~June 30, 2011,~~March 31, 2012, consisting of its first mortgage bonds, tax-exempt pollution control bonds, capital leases and ~~a capital lease.~~the Wright-Patterson Air Force Base debt facility. The fair value of this debt was ~~$877.3~~$930.6 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:~~
95

~~Table~~changes. Note that the DP&L debt was not revalued using push-down accounting as a result of ~~Contents~~the Merger.

Principal Payments and Interest Rate Detail by Contractual Maturity Date
DP&L

Carrying value at

Fair value at

Carrying value at

Fair value at

For the years ending June 30,

June 30,

June 30,

��

March 31,

March 31,

$ in millions

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (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
%
0.1
%

0.0
%
0.0
%
0.0
%
0.0
%
0.0
%
0.1
%

Fixed-rate debt

$
0.4

$
0.4

$
470.4

$
0.1

$
0.1

$
332.0

$
803.4

$
777.3

$
0.4

$
470.4

$
0.2

$
0.1

$
0.1

$
332.1

$
803.3

$
830.6

Average interest rate

4.9
%
4.9
%
5.1
%
4.2
%
4.2
%
4.8
%
5.0
%

4.9
%
5.1
%
4.8
%
4.2
%
4.2
%
4.8
%

Total

$
903.4

$
877.3

$
903.3

$
930.6

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

Debt maturities occurring in ~~2011~~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 ~~June 30, 2011~~March 31, 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 ~~June 30, 2011,~~March 31, 2012, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

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DPL

Carrying value at

Fair value at

One percent

Carrying value at

Fair value at

One percent

June 30,

June 30,

interest rate

March 31,

March 31,

interest rate

$ in millions

2011

2011

risk

2012

2012

risk

Long-term debt

Variable-rate debt

$
100.0

$
100.0

$
1.0

$
525.0

$
525.0

$
5.3

Fixed-rate debt

1,121.4

1,098.7

11.0

2,099.5

2,198.4

22.0

Total

$
1,221.4

$
1,198.7

$
12.0

$
2,624.5

$
2,723.4

$
27.3

DP&L

Carrying value at

Fair value at

One percent

Carrying value at

Fair value at

One percent

June 30,

June 30,

interest rate

March 31,

March 31,

interest rate

$ in millions

2011

2011

risk

2012

2012

risk

Long-term debt

Variable-rate debt

$
100.0

$
100.0

$
1.0

$
100.0

$
100.0

$
1.0

Fixed-rate debt

803.4

777.3

7.8

803.3

830.6

8.3

Total

$
903.4

$
877.3

$
8.8

$
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~~fixed rate debt, the interest rate risk with respect to DPL’s long-term debt ~~excluding capital lease obligations,~~ primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $~~1,098.7~~2,099.5 million of fixed-rate debt and not on DPL’s financial ~~position~~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 ~~DP&L’s~~DPL’s ~~$100.0~~$525.0 million variable-rate long-term debt outstanding as of ~~June 30, 2011.~~
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~~Table of Contents~~March 31, 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 ~~$777.3~~$803.3 million of fixed-rate debt and not on DP&L’s financial ~~position~~condition or DP&L’sresults 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~~ $100.0 million variable-rate long-term debt outstanding as of ~~June 30, 2011.~~March 31, 2012.

Equity Price Risk
As of ~~June 30, 2011,~~March 31, 2012, approximately ~~38%~~37% of the defined benefit pension plan assets were comprised of investments in equity securities and ~~62%~~63% 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 ~~equity securities are carried at their~~ market value of the equity securities was approximately ~~$127.7~~$128.3 million at ~~June 30, 2011.~~March 31, 2012. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12.8 million reduction in fair value as of ~~June 30, 2011.~~March 31, 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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Table of Contents
CRITICAL ACCOUNTING ESTIMATES

DPL’s Condensed Consolidated Financial Statements and DP&L’s ~~condensed consolidated financial statements~~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 ~~believed~~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 ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, ~~2010~~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)

DPL

DP&L (a)

DPLER (b)

Three Months Ended

Three Months Ended

Three Months Ended

Three Months Ended

Three Months Ended

Three Months Ended

March 31,

March 31,

March 31,

June 30,

June 30,

June 30,

2012

2011

2012

2011

2012

2011

2011

2010

2011

2010

2011

2010

Successor

Predecessor

Electric sales (millions of kWh)

Residential

1,144

1,114

1,144

1,114

1

—

1,324

1,544

1,322

1,544

112

—

Commercial

985

924

791

906

638

190

931

932

699

831

640

513

Industrial

867

977

818

972

773

666

828

829

780

807

799

717

Other retail

349

360

343

358

257

202

330

342

323

339

195

241

Total retail

3,345

3,375

3,096

3,350

1,669

1,058

3,413

3,647

3,124

3,521

1,746

1,471

Wholesale

516

786

542

783

—

—

344

606

401

654

—

—

Total

3,861

4,161

3,638

4,133

1,669

1,058

3,757

4,253

3,525

4,175

1,746

1,471

Operating revenues ($ in thousands)

Residential

$
153,998

$
146,003

$
153,917

$
145,995

$
81

$
10

$
171,162

$
185,515

$
163,431

$
185,501

$
7,732

$
14

Commercial

96,905

93,422

54,304

80,673

42,601

16,269

87,373

92,014

45,424

56,932

41,949

35,082

Industrial

65,530

72,270

18,809

34,624

46,721

35,229

61,550

61,850

16,130

17,942

45,420

43,907

Other retail

27,304

28,363

12,315

17,069

15,890

11,054

26,398

27,512

14,876

13,245

12,428

15,233

Other miscellaneous revenues

4,337

2,609

4,416

2,878

56

6

2,775

2,572

2,853

2,690

85

32

Total retail

348,074

342,667

243,761

281,239

105,349

62,568

349,258

369,463

242,714

276,310

107,614

94,268

Wholesale

28,659

39,116

104,705

89,538

739

—

22,379

32,429

104,455

106,166

1

(739
)

RTO revenues

69,221

60,495

60,142

53,195

615

311

55,093

76,680

48,715

67,246

498

488

Other revenues

(981
)
3,195

—

—

(4,668
)
6

7,294

2,022

3,678

39

3,987

6

Total

$
444,973

$
445,473

$
408,608

$
423,972

$
102,035

$
62,885

$
434,024

$
480,594

$
399,562

$
449,761

$
112,100

$
94,023

Electric customers at end of period

Residential

454,552

455,594

454,552

455,594

137

27

455,977

456,074

455,243

456,074

27,070

32

Commercial

52,970

50,429

50,056

50,128

12,224

1,878

54,342

52,727

50,169

50,124

15,659

10,275

Industrial

1,891

1,801

1,755

1,764

726

321

1,905

1,928

1,749

1,762

786

719

Other

6,877

6,659

6,760

6,656

2,113

776

6,943

6,865

6,811

6,744

2,763

1,621

Total

516,290

514,483

513,123

514,142

15,200

3,002

519,167

517,594

513,972

514,704

46,278

12,647

(a)This chart contains electric sales from DP&L’s generation and purchased power. DP&L sold ~~1,420~~1,457 million kWh and ~~1,033~~1,344 million kWh of power to DPLER (a subsidiary of DPL) during the three months ending ~~June 30,~~March 31, 2012 and 2011, ~~and 2010,~~ respectively, which are not included in DP&L wholesale sales volumes in the chart above. These kWh sales also relate to DP&L retail customers within the DP&L service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on DP&L’s Condensed Financial Statements and retail revenues on DPL’s Condensed Consolidated Financial Statements. DP&L did not sell any power to MC Squared during either of these periods.
(b)~~This chart includes all sales of DPLER and MC Squared, both within and outside of the~~ ~~DP&L~~ ~~service territory.~~
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~~ELECTRIC SALES AND REVENUES~~

DPL

DP&L (a)

DPLER (b)

Six Months Ended

Six Months Ended

Six Months Ended

June 30,

June 30,

June 30,

2011

2010

2011

2010

2011

2010

Electric sales (millions of kWh)

Residential

2,688

2,709

2,688

2,709

1

1

Commercial

1,917

1,810

1,622

1,789

1,152

341

Industrial

1,696

1,778

1,625

1,772

1,489

1,046

Other retail

691

697

681

696

498

394

Total retail

6,992

6,994

6,616

6,966

3,140

1,782

Wholesale

1,122

1,545

1,196

1,534

—

—

Total

8,114

8,539

7,812

8,500

3,140

1,782

Operating revenues ($ in thousands)

Residential

$
347,138

$
326,089

$
347,043

$
326,076

$
95

$
13

Commercial

192,472

182,422

114,789

160,008

77,683

22,413

Industrial

129,399

129,871

38,771

71,864

90,628

58,007

Other retail

55,675

54,790

26,418

32,870

31,123

23,614

Other miscellaneous revenues

6,909

4,095

7,106

4,561

88

9

Total retail

731,593

697,267

534,127

595,379

199,617

104,056

Wholesale

61,088

79,349

210,911

165,880

—

—

RTO revenues

145,903

113,923

127,387

100,684

1,104

565

Other revenues

1,041

6,132

—

—

(4,669
)
16

Total

$
939,625

$
896,671

$
872,425

$
861,943

$
196,052

$
104,637

Electric customers at end of period

Residential

454,552

455,594

454,552

455,594

137

27

Commercial

52,970

50,429

50,056

50,128

12,224

1,878

Industrial

1,891

1,801

1,755

1,764

726

321

Other

6,877

6,659

6,760

6,656

2,113

776

Total

516,290

514,483

513,123

514,142

15,200

3,002

~~(a)~~~~This chart contains electric sales from~~ ~~DP&L’s~~ ~~generation and purchased power.~~ ~~DP&L~~ ~~sold 2,764 million kWh and 1,753 million kWh of power to DPLER (a subsidiary of~~ ~~DPL~~~~) during the six months ending June 30, 2011 and 2010, respectively, which are not included in~~ ~~DP&L~~ ~~wholesale sales volumes in the chart above. These kWh sales also relate to~~ ~~DP&L~~ ~~retail customers within the~~ ~~DP&L~~ service territory for distribution services and their inclusion in wholesale sales would result in a double counting of kWh volume. The dollars of operating revenues associated with these sales are classified as wholesale revenues on ~~DP&L’s~~ ~~Financial Statements and retail revenues on~~ ~~DPL’s~~ ~~Condensed Consolidated Financial Statements~~~~. DP&L~~ ~~did not sell any power to MC Squared during either of these periods.~~
~~(b)~~This chart includes all sales of DPLER and MC Squared, both within and outside of the DP&L service territory.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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Item 4. Controls and Procedures

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

There was no change in our internal control over financial reporting during the ~~six months~~quarter ended ~~June 30, 2011~~March 31, 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 ~~Annual Report on~~ Form 10-K for the fiscal year ended December 31, ~~2010 and Quarterly Report on Form 10-Q for the three months ended March 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 this Item 1 of our Quarterly Report on Form 10-Q is limited to certain recent developments concerning our legal proceedings and ~~certain~~ new legal proceedings, since the filing of ~~our Annual Report on~~such Form 10-K, ~~for the fiscal year ended December 31, 2010 and Quarterly Report on form 10-Q for the three months ended March 31, 2011,~~ and should be read in conjunction with ~~these prior reports.~~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 ~~legal proceedings related to the Proposed Merger involving~~ ~~DPL~~ ~~and AES contained~~PUCO in Item ~~1 - Note 16 of Notes~~2 to ~~Condensed Consolidated Financial Statements~~Part I of this ~~report~~Quarterly Report on Form 10-Q and (ii) information about the legal proceedings contained under the section entitled “Ohio Regulation” and the first legal proceeding contained under the subsection entitled “Litigation Involving Co-Owned Plants” under the section entitled “Litigation, Notices of Violation and Other Matters Related to Air Quality” in Part I, Item 1 — Note 1413 of Notes to DPL’s Condensed Consolidated Financial Statements of this ~~report.~~
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~~Table of Contents~~Quarterly Report on Form 10-Q.

Item 1a1A — Risk Factors

A ~~comprehensive~~ listing of the risk factors that we consider to be the most significant to ~~your~~a decision to invest in our ~~stock~~securities is provided in our ~~most recent Annual Report on~~ Form 10-K ~~and supplemented in our Quarterly Report on Form 10-Q~~ for the ~~three months~~fiscal year ended ~~March~~December 31, 2011. ~~These reports may be obtained as discussed on Page 6 of this report.~~ The information in this Item 1a1A to Part II of our Quarterly Report on Form 10-Q updates and restates ~~and provides updates on certain~~one of the risk factors included in ~~these prior reports and also contains an additional risk factor.~~the Form 10-K. If any of ~~these~~the events described in our risk factors occur, ~~our business, financial position or results of operation could be materially affected.~~
~~DPL~~ ~~may be unable to obtain the approvals required to complete~~ ~~its~~ Proposed Merger with The AES Corporation or, obtaining required governmental and regulatory approvals may require the combined company to comply with restrictions or conditions that may materially impact the anticipated benefits of the Proposed Merger.
~~On April 20, 2011,~~ ~~DPL~~ ~~announced the execution of a definitive merger agreement with The AES Corporation (the Merger Agreement), pursuant to which each outstanding share of~~ ~~DPL~~ ~~common stock will be converted into the right to receive cash in the amount of $30.00 per share. Before the Proposed Merger may be completed, approval by~~ ~~DPL~~ ~~shareholders must be obtained. In addition~~, ~~the transaction is subject to the satisfaction or waiver of certain conditions and the receipt of all required regulatory approvals from, among others, the FERC and the PUCO~~. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the Proposed Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following consummation that may materially impact the anticipated benefits of the Proposed Merger. These conditions or changes could have the effect of delaying completion of the Proposed Merger or imposing additional costs on or limiting the revenues of the combined company following the Proposed Merger. A delay in the completion of the Proposed Merger beyond the termination date specified in the Merger Agreement due to, among other things, restrictions or conditions sought by governmental authorities could provide either party the right to terminate the Merger Agreement.
We are also subject to the risk that a required condition to the Proposed Merger may not be satisfied. Both companies are targeting to complete the Proposed Merger in the fourth quarter of 2011 or first quarter of 2012, but are subject to uncertainties related to the timing needed to consummate the Proposed Merger.
~~In the event that the Merger Agreement is terminated prior to the completion of the Proposed~~~~Merger,~~ DPL could incur significant transaction costs that could materially impact its financial performance and results. Failure to complete the Proposed Merger could also negatively impact DPL’s stock price and its future business and financial results.
~~DPL~~ will incur significant merger transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the Proposed Merger. If the Proposed Merger is not completed for certain reasons~~including, among others, if the Merger Agreement is terminated under certain specified circumstances,~~ ~~DPL~~ ~~will be required to pay The AES Corporation a termination fee of $106 million. The occurrence of either of these events individually or in combination~~it could have a material ~~adverse affect on~~ ~~DPL’s~~ ~~financial results.~~
~~We will be subject to business uncertainties and contractual restrictions while the Proposed~~~~Merger with The AES Corporation is pending that could adversely affect our financial results.~~
~~Uncertainty about the effect of the Proposed Merger on employees or suppliers may have an adverse~~ effect on ~~us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair~~ our ~~ability to attract, retain~~results of operations, financial condition and motivate key personnel until the Proposed Merger is completed and for a period of time thereafter, and could cause suppliers and others that deal with us to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the Proposed Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our business operations and financial results could be adversely affected.cash flows.

~~101~~108

Table of Contents

~~We expect that matters relating~~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 ~~the~~ ~~Proposed Merger and integration-related issues will place a significant burden on management, employees and internal resources,~~ which ~~could otherwise have been devoted to other business opportunities. The diversion of management time on merger-related issues could~~they may affect our business or financial ~~results.~~
~~In addition,~~performance. Our risk factors should be read in conjunction with the ~~Merger Agreement restricts us, without The AES Corporation’s consent, from making certain acquisitions~~ other detailed information concerning DPL and ~~taking other specified actions,~~DP&L~~including limiting~~ 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 total capital spending, limiting the extent that we can obtain financing through long-term debt and equity and prohibiting our ability to increase the dividend rates on our stock until the Proposed Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to consummation of the Proposed Merger or termination of the Merger Agreement.filings.

~~Lawsuits have been filed~~The costs we can recover and ~~several other lawsuits may be filed against DPL, its directors, AES and Dolphin Sub, Inc. challenging~~ the ~~Merger Agreement, and an adverse judgment in such lawsuits may prevent the Proposed Merger from becoming effective or from becoming effective within the expected timeframe.~~
~~DPL~~ ~~and its directors have been named and AES and Dolphin Sub, Inc. have also been named, as defendants in purported class action and derivative action lawsuits filed by~~return on capital we are permitted to earn for certain aspects of our ~~shareholders challenging~~business are regulated and governed by the ~~Proposed Merger~~laws of Ohio and ~~seeking,~~the rules, policies and procedure of the PUCO.
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 ~~enjoin~~file an SSO either in the ~~defendants from consummating~~form of an ESP or MRO, and established a significantly excessive earnings test for Ohio public utilities that compares the ~~Merger on the agreed-upon terms. We could also be subject to additional litigation related~~utility’s earnings to the ~~Proposed Merger, whether~~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 ~~not it~~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 ~~consummated. If any plaintiff is successful~~expected to provide an initial rate decrease for customers and result in obtaining an injunction prohibiting the parties from completing the Proposed Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Proposed Merger in the expected timeframe or altogether. While we are currently vigorously defending against any such litigation, these matters create additional uncertainty relatingdecreases to ~~the consummation of the proposed transaction and defending such matters is costly and distracting to management.~~
~~Push-down accounting adjustments in connection with the Proposed Merger may have a material effect on DPL’s future financial results.~~
Under U.S. GAAP, pursuant to FASC No. 805 and Staff Accounting Bulletin Topic 5.J “New Basis of Accounting Required in Certain Circumstances”, when an acquisition results in an entity becoming substantially wholly owned, push-down accounting is applied in the acquired entity’s separate financial statements. Push-down accounting requires that the fair value adjustments and goodwill or negative goodwill identified by the acquiring entity be pushed down and reflected in the financial statements of the acquired entity. As a result, following the consummation of the Proposed Merger and the completion by AES of its purchase price allocation, the cost basis of certain of ~~DPL’s~~DP&L’s ~~assets and liabilities may be adjusted and any resulting goodwill or negative goodwill may be allocated and pushed down to~~ ~~DPL~~~~. Although we believe~~revenues that ~~AES is still in the preliminary stages of determining the adjustments, which will be based on preliminary purchase price allocations and preliminary valuations of~~ ~~DPL’s~~ ~~assets and liabilities (which will be subject to change within the applicable measurement period), these adjustments could have a material effect on~~ ~~DPL’s~~ ~~future financial condition and results of operations, including but not limited to increased depreciation, amortization, impairment and other non-cash charges. As a result,~~ ~~DPL’s~~ ~~actual future results may not be comparable with results in prior periods.~~
~~Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties~~ could adversely affect our results of operations, financial condition and cash flows.DP&L
~~From time~~ faces regulatory uncertainty from this MRO filing. The PUCO could accept, reject or seek to ~~time we rely on access~~modify DP&L’s proposed MRO and/or require DP&L to ~~the credit~~propose another SSO. A new or revised SSO could result in changes to DP&L’s rate plan and capital markets to fund certain of our operational and capital costs. These capital and credit markets have experienced extreme volatility and disruption and the ability of corporations to obtain funds through the issuance of debt or equity has been negatively impacted. Disruptions in the credit and capital markets make it harder and more expensive to obtain funding for our business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterpartiesrecovery structure that could further adversely affect our results of operations, cash flows and financial ~~condition~~condition. DP&L’s proposed MRO and ~~cash flows. If~~current ESP and certain filings made by us in connection with this plan are further discussed in our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which could reduce our profitability.periodic reports. In addition, as the local distribution utility, DP&L has ~~variable~~an obligation to serve customers within its certified territory and under the terms of its ESP, as it is the provider of last resort (POLR) for standard offer service. DP&L’s current rate ~~debt that bears interest based on~~structure provides for a prevailing rate that is reset weekly based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also currently maintain both cash on deposit and investments in cash equivalents that could be adversely affected by interest rate fluctuations. In addition, select debt of ~~DPL~~ ~~and~~nonbypassable charge to compensate DP&L ~~is currently rated investment grade by various rating agencies.~~for this POLR obligation. The PUCO may decrease or discontinue this rate charge in connection with ~~DPL~~DP&L’s ~~expects to assume additional significant debt upon consummation of~~SSO filing or at some other time in the ~~Proposed Merger involving The AES Corporation. In light of this expected assumption of~~future.

~~102~~

~~Table~~While rate regulation is premised on full recovery of ~~Contents~~
~~debt, one~~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 ~~major rating agencies has downgraded our debt. In addition, all three major credit rating agencies have reduced their outlook from stable~~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 ~~negative~~recover amounts for environmental compliance, POLR obligations, reliability initiatives, fuel and ~~have indicated that they will downgrade~~ ~~DPL’s~~ ~~debt to below investment grade upon the expected assumption of additional debt by~~ ~~DPL~~ ~~in connection with the consummation of the Proposed Merger. If the credit rating agencies were to rate~~ ~~DPL~~ ~~and~~ ~~DP&L~~ ~~below investment grade, we would likely be required to pay~~purchased power (which account for a higher interest rate under certain existing and future financings and our potential pool of investors and funding sources would likely decrease. Our credit ratings also govern the collateral provisions of certainsubstantial portion of our ~~contracts,~~operating costs), customer switching, capital expenditures and investments and other costs on a ~~below investment grade credit rating could require us~~full or timely basis through rates; and changes to ~~provide other credit assurances under these contracts. These events would likely reduce our liquidity~~the frequency and ~~profitability 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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Table of Contents
Item 2 — Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 — Defaults Upon Senior Securities

None

Item 4 — ~~Removed and Reserved~~Mine Safety Disclosures
Not applicable.

Item 5 — Other Information

None

~~103~~110

Table of Contents

Item 6 — Exhibits
DPL Inc.

DP&L

Exhibit
Number

Exhibit

Location

X

~~2(a)~~
~~Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc.~~
~~Exhibit 2.1 to Report on Form 8-K filed April 20, 2011 (File No. 1-9052)~~
X
X
~~10(a)~~
Limited Consent and Waiver, dated as of May 24, 2011, to the Credit Agreement, dated as of April 20, 2010, among The Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, and the lender parties
~~Exhibit 10.1 to Report on Form 8-K filed May 31, 2011~~
~~(File No. 1-2385)~~
X
X
10(b)*
~~Retention Agreement, dated May 25, 2011, by and between DPL Inc. and The Dayton Power and Light Company and Craig L. Jackson~~
~~Filed herewith as~~
~~Exhibit 10(b)~~
X
31(a)

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 31(a)
X

31(b)

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 31(b)

X

31(c)

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 31(c)

X

31(d)

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 31(d)
X

32(a)

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 32(a)
X

32(b)

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 32(b)

X

32(c)

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 32(c)

X

32(d)

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith as
Exhibit 32(d)
111

Table of Contents
DPL Inc.
DP&L
Exhibit
Number
Exhibit
Location

X

X

101.INS

XBRL Instance

Furnished herewith as Exhibit 101.INS
~~104~~

~~Table of Contents~~
~~DPL Inc.~~
~~DP&L~~
~~Exhibit~~
~~Number~~
~~Exhibit~~
~~Location~~
X

X

101.SCH

XBRL Taxonomy Extension Schema

Furnished herewith as Exhibit 101.SCH
X

X

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

Furnished herewith as Exhibit 101.CAL
X

X

101.DEF

XBRL Taxonomy Extension Definition Linkbase

Furnished herewith as Exhibit 101.DEF
X

X

101.LAB

XBRL Taxonomy Extension Label Linkbase

Furnished herewith as Exhibit 101.LAB
X

X

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

Furnished herewith as Exhibit 101.PRE

*Management contract or compensatory plan.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) ~~(v)~~(iii)(A) of Item 601 of Regulation S-K, we have not filed as ~~exhibits~~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.

~~105~~112

Table of Contents
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:
~~July 28, 2011~~May 3, 2012
/s/ ~~Paul M. Barbas~~Philip Herrington

~~Paul M. Barbas~~
Philip Herrington
President and Chief Executive Officer

(principal executive officer)

~~July 28, 2011~~
~~/s/ Frederick J. Boyle~~
~~Frederick J. Boyle~~
~~Senior Vice President, and Chief Financial Officer~~
~~(principal financial officer)~~

~~July28, 2011~~May 3, 2012
/s/ Joseph W. Mulpas

Joseph W. Mulpas
Vice President, Controller, Chief Accounting Officer
and Interim Chief Financial Officer (principal accounting officer and principal financial officer)

~~Vice President, Controller and Chief Accounting Officer~~

~~(principal accounting officer)~~

~~106~~113

	Three Months Ended June 30,
	2011			2010
Comprehensive income:
Net income	$	31.7		$	61.4
Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.1 million	—			(0.2		)
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $5.0 million and $5.0 million, respectively	(10.0		)	(10.0		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.4 million and $0.4 million, respectively	0.4			0.8
Comprehensive income	$	22.1		$	52.0

	Six Months Ended June 30,
	2011			2010
Comprehensive income:
Net income	$	75.2		$	132.4
Net change in unrealized gains (losses) on financial instruments, net of income tax expense of zero	—			(0.1		)
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $4.1 million and $2.4 million, respectively	(8.8		)	(5.6		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expenses of $0.8 million and income tax benefits of $0.2 million, respectively	1.6			2.6
Comprehensive income	$	68.0		$	129.3

									Successor
	At June 30,				At December 31,				At March 31,				At December 31,
	2011				2010				2012				2011
$ in millions	Cost		Fair Value		Cost		Fair Value		Cost		Fair Value		Cost		Fair Value
DPL
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6	$	0.2	$	0.2	$	0.2	$	0.2
Equity Securities	3.5		4.2		3.8		4.4		3.9		5.0		3.9		4.4
Debt Securities	5.2		5.5		5.2		5.5		5.1		5.5		5.0		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.3		0.3		0.3		0.3		0.2
Total Master Trust Assets	$	9.2	$	10.2	$	10.9	$	11.8

Short-term Investments - VRDNs	$	—	$	—	$	54.2	$	54.2
Short-term Investments - Bonds	—		—		15.1		15.1
Total Short-term Investments	$	—	$	—	$	69.3	$	69.3

Total Assets	$	9.2	$	10.2	$	80.2	$	81.1	$	9.5	$	11.0	$	9.4	$	10.3

Liabilities
Debt	$	1,221.4	$	1,198.7	$	1,324.1	$	1,307.5	$	2,624.5	$	2,723.4	$	2,629.3	$	2,710.6


DP&L
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities (a)	16.9		33.7		17.5		30.2
Debt Securities	5.2		5.5		5.2		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.3
Total Master Trust Assets	$	22.6	$	39.7	$	24.6	$	37.6

Liabilities
Debt	$	903.4	$	877.3	$	884.1	$	850.6

	Fair Value Estimated using Net Asset Value per Unit
$ in millions	Fair Value at June 30, 2011		Fair Value at December 31, 2010		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	1.6	$	—	Immediate

Equity Securities (b)	4.2		4.4		—		Immediate

Debt Securities (c)	5.5		5.5		—		Immediate

Multi-Strategy Fund (d)	0.3		0.3		—		Immediate

Total	$	10.2	$	11.8	$	—

								Fair Value on
$ in millions	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
Forward Power Contracts in a Liability Position	(1.5		)	1.1			Other current liabilities	(0.4		)

Total short-term cash flow hedges	(0.5		)	0.5				—

Long-term Derivative Positions

Forward Power Contracts in a Liability Position	(4.7		)	3.0			Other deferred credits	(1.7		)
Interest Rate Hedges in a Liability Position	(16.8		)	—			Other deferred credits	(16.8		)

Total long-term cash flow hedges	(21.5		)	3.0				(18.5		)

Total cash flow hedges	$	(22.0	)	$	3.5			$	(18.5	)

	Options			RSUs		Performance Shares
	2011		2010	2011	2010	2011	2010
Outstanding at beginning of period	100,500		351,500	—	3,311	296,591	307,985
Granted	—		—	—	—	—	—
Dividends	—		—	—	—	—	—
Exercised	(75,000	)	—	—	—	—	—
Expired	(25,000	)	—	—	—	—	—
Forfeited	—		—	—	—	—	—
Outstanding at period end	500		351,500	—	3,311	296,591	307,985
Exercisable at period end	500		351,500	—	—	—	—

					Management Performance
	Restricted Shares				Shares
	2011		2010		2011	2010
Outstanding at beginning of period	286,737		219,782		111,298	110,706
Granted	—		29,591		—	—
Dividends	—		—		—	—
Exercised	(2,500	)	—		—	—
Expired	—		—		—	—
Forfeited	—		(272	)	—	—
Outstanding at period end	284,237		249,101		111,298	110,706
Exercisable at period end	—		—		—	—

	Director RSUs
	2011		2010
Outstanding at beginning of period	16,528		20,944
Granted	—		15,752
Dividends accrued	624		683
Exercised and issued	(2,066	)	(2,618	)
Exercised and deferred	(15,086	)	(18,817	)
Forfeited	—		—
Outstanding at period end	—		15,944
Exercisable at period end	—		—

	Three Months Ended		Three Months Ended
	June 30, 2011		June 30, 2010
	Electric Customers	Sales (in Millions of kWh)	Electric Customers	Sales (in Millions of kWh)

Supplied by DPLER	12,033	1,420	2,661	1,033
Supplied by non-affiliated CRES providers	4,996	164	168	14
Total supplied in our service territory	17,029	1,584	2,829	1,047

Supplied by DP&L in our service territory(a)	513,123	3,260	514,142	3,350

													Three Months Ended
													March 31,
	Three Months Ended June 30,						Six Months Ended June 30,						2012			2011
$ in millions	2011			2010			2011			2010			Successor			Predecessor

Revenues:
Retail	$	348.1		$	342.7		$	731.6		$	697.3		$	349.3		$			369.5
Wholesale	28.7			39.1			61.1			79.3			22.4			32.4
RTO revenues	19.5			20.1			40.9			41.2			18.2			21.4
RTO capacity revenues	49.7			40.4			105.0			72.7			36.9			55.3
Other revenues	2.9			3.2			5.7			6.2			3.2			2.7
Other mark to market losses	(4.0		)	—			(4.7		)	—
Mark-to-market gains / (losses)													4.0			(0.7				)
Total revenues	$	444.9		$	445.5		$	939.6		$	896.7		$	434.0		$			480.6

Cost of revenues:
Fuel costs	$	93.3		$	92.4		$	194.8		$	194.7		$	90.6		$			100.9
Gains from sale of coal	(1.2		)	(1.1		)	(2.9		)	(1.3		)
Gains from sale of emission allowances	—			(0.4		)	—			(0.6		)
Losses / (gains) from sale of coal													3.4			(1.8				)
Mark-to-market losses													3.4			0.6
Net fuel	92.1			90.9			191.9			192.8			97.4			99.7

Purchased power	39.5			21.3			75.5			35.0			34.6			37.3
RTO charges	27.1			26.7			56.4			51.4			24.5			29.3
RTO capacity charges	47.0			42.9			102.5			77.3			33.7			55.5
Mark-to-market losses / (gains)													2.0			(1.3				)
Net purchased power	113.6			90.9			234.4			163.7			94.8			120.8

Amortization of intangibles													27.8			—

Total cost of revenues	$	205.7		$	181.8		$	426.3		$	356.5		$	220.0		$			220.5

Gross margins (a)	$	239.2		$	263.7		$	513.3		$	540.2		$	214.0		$		260.1

Gross margin as a percentage of revenues	53.8		%	59.2		%	54.6		%	60.2		%	49		%	54				%

Operating income	$	65.8		$	109.3		$	166.6		$	235.3		$	59.2		$	100.9

Earnings per share of common stock:
Basic EPS from operations	$	0.28		$	0.53		$	0.66		$	1.15
Diluted EPS from operations	$	0.28		$	0.53		$	0.66		$	1.14

	Three months ended June 30,						Increase (Decrease)
$ in millions	2011			2010			2011 vs. 2010

Utility	$	215.1		$	245.1		$	(30.0	)
Competitive Retail	12.5			10.1			2.4
Other	12.6			9.6			3.0
Adjustments and Eliminations	(1.0		)	(1.1		)	0.1
Total consolidated	$	239.2		$	263.7		$	(24.5	)

	For the Six Months
	Ended June 30,
$ in millions	2011			2010

Net cash provided by operating activities	$	185.1		$	204.9
Net cash used for investing activities	(28.6		)	(120.2		)
Net cash used for financing activities	(207.7		)	(72.2		)

Net change	$	(51.2	)	$	12.5
Cash and cash equivalents at beginning of period	124.0			74.9
Cash and cash equivalents at end of period	$	72.8		$	87.4

DP&L

	For the Six Months						For the Three Months
	Ended June 30,						Ended March 31,
$ in millions	2011			2010			2012			2011

Net cash provided by operating activities	$	163.2		$	205.1		$	89.6		$	84.0
Net cash used for investing activities	(89.1		)	(71.6		)	(53.2		)	(40.4		)
Net cash used for financing activities	(115.4		)	(150.4		)	(45.2		)	(40.2		)

Net change	$	(41.3	)	$	(16.9	)	(8.8		)	3.4
Cash and cash equivalents at beginning of period	54.0			57.1			32.2			54.0
Cash and cash equivalents at end of period	$	12.7		$	40.2		$	23.4		$	57.4

							Successor			Predecessor
							Three months			Three months
	Six Months Ended						ended			ended
	June 30,						March 31,			March 31,
$ in millions	2011			2010			2012			2011

Net income	$	75.2		$	132.4		$	21.7		$	43.5
Depreciation and amortization	70.2			73.1			54.5			35.1
Deferred income taxes	37.5			6.4			(9.2		)	33.7
Charge for early redemption of debt							—			15.3
Contribution to pension plan	(40.0		)	(20.0		)	—			(40.0		)
Charge for early redemption of debt	15.3			—
Accrued interest							29.1			(1.2		)
Deferred regulatory costs, net							7.2			12.8
Other	26.9			13.0			(8.7		)	(7.2		)
Net cash provided by operating activities	$	185.1		$	204.9		$	94.6		$	92.0

					Amounts
					available as of
$ in millions	Type	Maturity	Commitment		June 30, 2011

DP&L	Revolving	November 2011	$	220.0	$	220.0

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

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

Fitch Ratings	BB+	BBB+	AStable	~~Negative~~	~~April~~November 2011
Moody’s Investors Service	~~Baa1~~Ba1	~~Aa3~~A3	~~Negative~~Stable	~~April~~November 2011
Standard & Poor’s Corp.	BB+	BBB+	A	CreditWatch Negative	April ~~2011~~2012

			Weighted		Increase /
			Average		Decrease in
	Contract		Market		Net Income
Commodity	Volume	Units	Price / Unit		(in millions)

NYMEX Coal Forwards - Non-Hedged
2011 - Purchase	149,188	tons	$	77.89	$	0.4	(a)
2012 - Purchase	1,246,200	tons	$	82.26	$	3.8	(a)
2013 - Purchase	372,000	tons	$	86.72	$	2.1	(a)

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

Computed average capacity price ($/MW-day)	144	137	55	23

																			Carrying value at			Fair value at																				Carrying value at		Fair value at
	For the years ending June 30,																		June 30,			June 30,																				March 31,		March 31,
$ in millions	2012			2013			2014			2015			2016			Thereafter			2011 (a)			2011 (a)		2013			2014			2015			2016			2017			Thereafter			2012 (a)		2012 (a)
Long-term debt

Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0		$	100.0	$	—		$	—		$	425.0		$	—		$	—		$	100.0		$	525.0	$	525.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.1		%	0.1		%			0.0		%	0.0		%	2.3		%	0.0		%	0.0		%	0.1		%

Fixed-rate debt	$	297.8		$	0.4		$	470.4		$	0.1		$	0.1		$	352.6		$	1,121.4		$	1,098.7	$	0.4		$	499.3		$	0.2		$	0.1		$	450.1		$	1,149.4		$	2,099.5	$	2,198.4
Average interest rate	6.9		%	4.9		%	5.1		%	4.2		%	4.2		%	5.0		%	5.5		%			4.9		%	5.1		%	4.8		%	4.2		%	6.5		%	6.6		%

Total																			$	1,221.4		$	1,198.7																			$	2,624.5	$	2,723.4

	Carrying value at		Fair value at		One percent		Carrying value at		Fair value at		One percent
	June 30,		June 30,		interest rate		March 31,		March 31,		interest rate
$ in millions	2011		2011		risk		2012		2012		risk
Long-term debt

Variable-rate debt	$	100.0	$	100.0	$	1.0	$	525.0	$	525.0	$	5.3

Fixed-rate debt	1,121.4		1,098.7		11.0		2,099.5		2,198.4		22.0

Total	$	1,221.4	$	1,198.7	$	12.0	$	2,624.5	$	2,723.4	$	27.3

															DPL				DP&L (a)				DPLER (b)
	DPL					DP&L (a)				DPLER (b)					Three Months Ended				Three Months Ended				Three Months Ended
	Three Months Ended					Three Months Ended				Three Months Ended					March 31,				March 31,				March 31,
	June 30,					June 30,				June 30,					2012		2011		2012		2011		2012		2011
	2011			2010		2011		2010		2011			2010		Successor		Predecessor
Electric sales (millions of kWh)
Residential	1,144			1,114		1,144		1,114		1			—		1,324		1,544		1,322		1,544		112		—
Commercial	985			924		791		906		638			190		931		932		699		831		640		513
Industrial	867			977		818		972		773			666		828		829		780		807		799		717
Other retail	349			360		343		358		257			202		330		342		323		339		195		241
Total retail	3,345			3,375		3,096		3,350		1,669			1,058		3,413		3,647		3,124		3,521		1,746		1,471

Wholesale	516			786		542		783		—			—		344		606		401		654		—		—

Total	3,861			4,161		3,638		4,133		1,669			1,058		3,757		4,253		3,525		4,175		1,746		1,471

Operating revenues ($ in thousands)
Residential	$	153,998		$	146,003	$	153,917	$	145,995	$	81		$	10	$	171,162	$	185,515	$	163,431	$	185,501	$	7,732	$	14
Commercial	96,905			93,422		54,304		80,673		42,601			16,269		87,373		92,014		45,424		56,932		41,949		35,082
Industrial	65,530			72,270		18,809		34,624		46,721			35,229		61,550		61,850		16,130		17,942		45,420		43,907
Other retail	27,304			28,363		12,315		17,069		15,890			11,054		26,398		27,512		14,876		13,245		12,428		15,233
Other miscellaneous revenues	4,337			2,609		4,416		2,878		56			6		2,775		2,572		2,853		2,690		85		32
Total retail	348,074			342,667		243,761		281,239		105,349			62,568		349,258		369,463		242,714		276,310		107,614		94,268

Wholesale	28,659			39,116		104,705		89,538		739			—		22,379		32,429		104,455		106,166		1		(739		)

RTO revenues	69,221			60,495		60,142		53,195		615			311		55,093		76,680		48,715		67,246		498		488

Other revenues	(981		)	3,195		—		—		(4,668		)	6		7,294		2,022		3,678		39		3,987		6

Total	$	444,973		$	445,473	$	408,608	$	423,972	$	102,035		$	62,885	$	434,024	$	480,594	$	399,562	$	449,761	$	112,100	$	94,023

Electric customers at end of period
Residential	454,552			455,594		454,552		455,594		137			27		455,977		456,074		455,243		456,074		27,070		32
Commercial	52,970			50,429		50,056		50,128		12,224			1,878		54,342		52,727		50,169		50,124		15,659		10,275
Industrial	1,891			1,801		1,755		1,764		726			321		1,905		1,928		1,749		1,762		786		719
Other	6,877			6,659		6,760		6,656		2,113			776		6,943		6,865		6,811		6,744		2,763		1,621

Total	516,290			514,483		513,123		514,142		15,200			3,002		519,167		517,594		513,972		514,704		46,278		12,647

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location

X		~~2(a)~~	~~Agreement and Plan of Merger, dated as of April 19, 2011, by and among DPL Inc., The AES Corporation and Dolphin Sub, Inc.~~	~~Exhibit 2.1 to Report on Form 8-K filed April 20, 2011 (File No. 1-9052)~~

X	X	~~10(a)~~	Limited Consent and Waiver, dated as of May 24, 2011, to the Credit Agreement, dated as of April 20, 2010, among The Dayton Power and Light Company, Bank of America, N.A., as Administrative Agent and an L/C Issuer, and the lender parties	~~Exhibit 10.1 to Report on Form 8-K filed May 31, 2011~~ ~~(File No. 1-2385)~~

X	X	10(b)*	~~Retention Agreement, dated May 25, 2011, by and between DPL Inc. and The Dayton Power and Light Company and Craig L. Jackson~~	~~Filed herewith as~~ ~~Exhibit 10(b)~~

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

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

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

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

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

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

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

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

~~DPL Inc.~~	~~DP&L~~	~~Exhibit~~ ~~Number~~	~~Exhibit~~	~~Location~~
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

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


Date:	~~July 28, 2011~~May 3, 2012	/s/ ~~Paul M. Barbas~~Philip Herrington
		~~Paul M. Barbas~~
		Philip Herrington President and Chief Executive Officer
		(principal executive officer)


	~~July 28, 2011~~	~~/s/ Frederick J. Boyle~~
		~~Frederick J. Boyle~~
		~~Senior Vice President, and Chief Financial Officer~~
		~~(principal financial officer)~~


	~~July28, 2011~~May 3, 2012	/s/ Joseph W. Mulpas
		Joseph W. Mulpas Vice President, Controller, Chief Accounting Officer and Interim Chief Financial Officer (principal accounting officer and principal financial officer)
			~~Vice President, Controller and Chief Accounting Officer~~
			~~(principal accounting officer)~~