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 endedSeptember 30, 2011

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

For the transition period from to

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

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

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

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

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

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

DPL Inc.		Yes 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	o
The Dayton Power and Light Company	o	o	x	o

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

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

As of ~~July 25,~~October 24, 2011, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares Outstanding

DPL Inc.	Common Stock, $0.01 par value	~~117,712,910~~117,729,995

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

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

Table of Contents

DPL Inc. and The Dayton Power and Light Company

Index

					Page No.
Glossary of Terms				3

Part I Financial Information

	Item 1	Financial Statements —– DPL and DP&L (Unaudited)

		Condensed Consolidated Statements of Results of Operations —– DPL		7

		Condensed Consolidated Statements of Cash Flows —– DPL		8

		Condensed Consolidated Balance Sheets —– DPL		9

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

		Condensed Statements of Cash Flows —– DP&L		12

		Condensed Balance Sheets —– DP&L		13

		Notes to Condensed Consolidated Financial Statements		15

	Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	70
	65
		Electric Sales and Revenues	106

	~~Electric Sales and Revenues~~		98

Item 3	Quantitative and Qualitative Disclosures about Market Risk		99107

	Item 4	Controls and Procedures	108

Part II Other Information			~~100~~

	Item 1	Legal Proceedings	108

~~Part II Other Information~~	Item 1a	Risk Factors	109

~~Item 1~~	~~Legal Proceedings~~		~~100~~

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

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		~~103~~111

	Item 3	Defaults Upon Senior Securities		~~103~~111

	Item 4	Removed and Reserved		~~103~~111

	Item 5	Other Information		~~103~~112

	Item 6	Exhibits		~~104~~112

Other


Signatures		~~106~~114


Certifications	~~108~~115

Table of Contents

GLOSSARY OF TERMS

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

Abbreviation or Acronym

Definition

AMI

Advanced Metering Infrastructure

AOCI

Accumulated Other Comprehensive Income

ARO

Asset Retirement Obligation

ASU
��
Accounting Standards Update

BTU

British Thermal Units

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, a subsidiary of AEP

CO2

Carbon Dioxide

CCEM

Customer Conservation and Energy Management

CRES

Competitive Retail Electric Service

DPL

DPL Inc., the parent company

DPLE

DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales

DPLER

DPL Energy Resources, Inc., a wholly-owned subsidiary of DPL that sells retail electric energy and other energy services

DP&L

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

Duke Energy

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

EIR

Environmental Investment Rider

EPS

Earnings Per Share

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

ESOP

Employee Stock Ownership Plan

ESP

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

FASB

Financial Accounting Standards Board

FASC

FASB Accounting Standards Codification

FERC

Federal Energy Regulatory Commission

FGD

Flue Gas Desulfurization

GAAP

Generally Accepted Accounting Principles in the United States

GHG

Greenhouse Gas

IFRS

International Financial Reporting Standards

kWh

Kilowatt hours
3

Table of Contents
GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym
Definition

LOC

Letter of Credit

MC Squared

MC Squared Energy Services, LLC, a wholly-owned retail electricity supplier of DPLER that was purchased on February 28, 2011
3

~~Table of Contents~~
~~GLOSSARY OF TERMS (cont.)~~
~~Abbreviation or Acronym~~
~~Definition~~

Merger 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 acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of debt. Upon closing, DPL will become a wholly-owned subsidiary of AES

MRO

Market Rate Option

MTM

~~Mark to Market~~Mark-to-Market

MVIC

Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries

MWh

Megawatt hours

NERC

North American Electric Reliability Corporation

NOV

Notice of Violation

NOx

Nitrogen Oxide

NYMEX

New York Mercantile Exchange

OAQDA

Ohio Air Quality Development Authority

OCC

Office of the 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., a regional transmission organization

Proposed Merger

The proposed merger involving 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

RPM

Reliability Pricing Model

SB 221

Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an electric security plan or a market rate option to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards

SCR

Selective Catalytic Reduction
4

Table of Contents
GLOSSARY OF TERMS (cont.)
Abbreviation or Acronym
Definition

SEC

Securities and Exchange Commission

SECA

Seams Elimination Charge Adjustment

SERP

Supplemental Executive Retirement Plan

SFAS

Statement of Financial Accounting Standards

SO2

Sulfur Dioxide
4

~~Table of Contents~~
~~GLOSSARY OF TERMS (cont.)~~
~~Abbreviation or Acronym~~
~~Definition~~

SSO

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

TCRR

Transmission Cost Recovery Rider

USEPA

U.S. Environmental Protection Agency

USF

Universal Service Fund

VRDN

Variable Rate Demand Note

5

Table of Contents

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

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

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

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

Part 1 —– Financial Information

This report includes the combined filing of DPL and DP&L. DP&L is the principal subsidiary of DPL providing approximately 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 be clearly be noted in the section.

6

Table of Contents

Item 1 —– Financial Statements

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions except per share amounts

2011

2010

2011

2010

2011

2010

2011

2010

Revenues

$
444.9

$
445.5

$
939.6

$
896.7

$
511.8

$
516.9

$
1,451.4

$
1,413.6

Cost of revenues:

Fuel

92.1

90.9

191.9

192.8

129.0

104.3

320.9

297.1

Purchased power

113.6

90.9

234.4

163.7

108.3

119.0

342.7

282.7

Total cost of revenues

205.7

181.8

426.3

356.5

237.3

223.3

663.6

579.8

Gross margin

239.2

263.7

513.3

540.2

274.5

293.6

787.8

833.8

Operating expenses:

Operation and maintenance

106.8

87.5

206.2

168.1

92.0

84.2

298.2

252.3

Depreciation and amortization

35.1

35.7

70.2

73.1

35.8

32.2

106.0

105.3

General taxes

31.5

31.2

70.3

63.7

33.8

32.6

104.1

96.3

Total operating expenses

173.4

154.4

346.7

304.9

161.6

149.0

508.3

453.9

Operating income

65.8

109.3

166.6

235.3

112.9

144.6

279.5

379.9

Other income / (expense), net:

Investment income

0.1

0.2

0.2

0.3

0.1

0.3

0.3

0.6

Interest expense

(17.6
)
(17.5
)
(34.5
)
(35.4
)

(16.8
)
(17.6
)
(51.3
)
(53.0
)
Charge for early redemption of debt

—

—

(15.3
)
—

—

—

(15.3
)
—

Other expense

(0.3
)
(0.5
)
(0.7
)
(1.3
)

(0.5
)
(0.5
)
(1.2
)
(1.8
)
Total other income / (expense), net

(17.8
)
(17.8
)
(50.3
)
(36.4
)

(17.2
)
(17.8
)
(67.5
)
(54.2
)

Earnings before income tax

48.0

91.5

116.3

198.9

95.7

126.8

212.0

325.7

Income tax expense

16.3

30.1

41.1

66.5

28.6

40.4

69.7

106.9

Net income

$
31.7

$
61.4

$
75.2

$
132.4

$
67.1

$
86.4

$
142.3

$
218.8

Average number of common shares outstanding (millions):

Basic

114.2

115.7

114.1

115.6

115.0

115.8

114.4

115.7

Diluted

114.9

116.2

114.7

116.2

115.5

116.3

115.0

116.2

Earnings per share of common stock:

Basic

$
0.28

$
0.53

$
0.66

$
1.15

$
0.58

$
0.75

$
1.24

$
1.89

Diluted

$
0.28

$
0.53

$
0.66

$
1.14

$
0.58

$
0.74

$
1.24

$
1.88

Dividends paid per share of common stock

$
0.3325

$
0.3025

$
0.6650

$
0.6050

$
0.3325

$
0.3025

$
0.9975

$
0.9075

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

7

Table of Contents

DPL INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Cash flows from operating activities:

Net income

$
75.2

$
132.4

$
142.3

$
218.8

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

Depreciation and amortization

70.2

73.1

106.0

105.3

Deferred income taxes

37.5

6.4

70.5

38.7

Unamortized investment tax credit

(1.4
)
(1.4
)

(2.1
)
(2.1
)
Charge for early redemption of debt

15.3

—

15.3

—

Changes in certain assets and liabilities:

Accounts receivable

19.5

4.7

21.1

7.9

Inventories

(0.3
)
(1.8
)

(11.5
)
10.6

Prepaid taxes

(20.7
)
(1.0
)

(27.0
)
(0.9
)
Taxes applicable to subsequent years

31.8

29.5

47.7

44.2

Deferred regulatory costs, net

8.9

4.1

7.9

7.0

Accounts payable

(5.9
)
8.7

(13.4
)
(4.7
)
Accrued taxes payable

(33.4
)
(36.4
)

(58.2
)
(58.1
)
Accrued interest payable

2.0

0.2

(3.1
)
(5.6
)
Pension, retiree and other benefits

(42.7
)
(23.0
)

(31.7
)
(54.6
)
Insurance and claims costs

3.7

(1.5
)

4.1

(0.3
)
Other

25.4

10.9

(3.1
)
25.4

Net cash provided by operating activities

185.1

204.9

264.8

331.6

Cash flows from investing activities:

Capital expenditures

(91.4
)
(75.1
)

(141.3
)
(113.7
)
Purchase of MC Squared

(8.2
)
—

(8.3
)
—

Purchases of short-term investments and securities

(1.7
)
(61.2
)

(1.7
)
(62.7
)
Sales of short-term investments and securities

70.9

14.2

70.9

14.4

Other

1.8

1.9

1.5

1.7

Net cash used for investing activities

(28.6
)
(120.2
)

(78.9
)
(160.3
)

Cash flows from financing activities:

Dividends paid on common stock

(76.4
)
(69.9
)

(113.8
)
(104.8
)
Early redemption of Capital Trust II debt

(122.0
)
—

(122.0
)
—

Premium paid for early redemption of debt

(12.2
)
—

(12.2
)
—

Payment of MC Squared debt

(13.5
)
—

(13.5
)
—

Payment of long-term debt

(297.4
)
—

Issuance of long-term debt

300.0

—

Withdrawals from revolving credit facilities

50.0

—

50.0

—

Repayments of borrowings from revolving credit facilities

(50.0
)
—

(50.0
)
—

Repurchase of DPL common stock

—

(3.9
)

—

(3.9
)
Exercise of stock options

1.4

1.4

1.6

1.4

Exercise of warrants

14.7

—

14.7

—

Tax impact related to exercise of stock options

0.3

0.2

0.3

0.2

Net cash used for financing activities

(207.7
)
(72.2
)

(242.3
)
(107.1
)

Cash and cash equivalents:

Net change

(51.2
)
12.5

(56.4
)
64.2

Balance at beginning of period

124.0

74.9

124.0

74.9

Cash and cash equivalents at end of period

$
72.8

$
87.4

$
67.6

$
139.1

Supplemental cash flow information:

Interest paid, net of amounts capitalized

$
30.3

$
35.7

$
49.4

$
59.6

Income taxes paid, net

$
24.7

$
53.2

$
25.5

$
60.8

Non-cash financing and investing activities:

Accruals for capital expenditures

$
22.6

$
11.3

$
14.8

$
14.1

Long-term liability incurred for purchase of assets

$
18.7

$
—

$
18.7

$
—

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

8

Table of Contents

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

ASSETS

Current assets:

Cash and cash equivalents

$
72.8

$
124.0

$
67.6

$
124.0

Short-term investments

—

69.3

—

69.3

Accounts receivable, net (Note 2)

201.8

215.5

203.2

215.5

Inventories (Note 2)

115.6

115.3

126.8

115.3

Taxes applicable to subsequent years

31.8

63.7

15.9

63.7

Other prepayments and current assets

69.4

40.6

68.6

40.6

Total current assets

491.4

628.4

482.1

628.4

Property, plant and equipment:

Property, plant and equipment

5,482.6

5,353.6

5,508.3

5,353.6

Less: Accumulated depreciation and amortization

(2,629.3
)
(2,555.2
)

(2,652.7
)
(2,555.2
)

2,853.3

2,798.4

2,855.6

2,798.4

Construction work in process

112.3

119.7

118.6

119.7

Total net property, plant and equipment

2,965.6

2,918.1

2,974.2

2,918.1

Other noncurrent assets:

Regulatory assets (Note 3)

178.8

189.0

178.2

189.0

Other deferred assets

75.8

77.8

42.0

77.8

Total other noncurrent assets

254.6

266.8

220.2

266.8

Total Assets

$
3,711.6

$
3,813.3

$
3,676.5

$
3,813.3

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

9

Table of Contents

DPL INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:

Current portion - long-term debt (Note 5)

$
297.8

$
297.5

$
0.4

$
297.5

Accounts payable

94.6

98.7

82.2

98.7

Accrued taxes

70.9

68.1

72.4

68.1

Accrued interest

20.6

18.4

15.6

18.4

Customer security deposits

17.9

18.7

16.9

18.7

Other current liabilities

55.6

40.9

37.0

40.9

Total current liabilities

557.4

542.3

224.5

542.3

Noncurrent liabilities:

Long-term debt (Note 5)

923.6

1,026.6

1,223.6

1,026.6

Deferred taxes (Note 6)

660.6

625.4

670.0

625.4

Regulatory liabilities (Note 3)

129.4

124.0

133.1

124.0

Pension, retiree and other benefits

27.6

64.9

25.9

64.9

Unamortized investment tax credit

31.0

32.4

30.3

32.4

Insurance and claims costs

13.7

10.1

14.1

10.1

Other deferred credits

110.9

146.2

112.6

146.2

Total noncurrent liabilities

1,896.8

2,029.6

2,209.6

2,029.6

Redeemable preferred stock of subsidiary

22.9

22.9

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

September 2011

December 2010

Shares authorized

250,000,000

250,000,000

250,000,000

250,000,000

Shares issued

163,724,211

163,724,211

163,724,211

163,724,211

Shares outstanding

117,712,910

116,924,844

1.2

1.2

117,724,111

116,924,844

1.2

1.2

Warrants

1.6

2.7

1.6

2.7

Common stock held by employee plans

(8.1
)
(12.5
)

(7.1
)
(12.5
)
Accumulated other comprehensive loss

(26.1
)
(18.9
)

(72.1
)
(18.9
)
Retained earnings

1,265.9

1,246.0

1,295.9

1,246.0

Total common shareholders’ equity

1,234.5

1,218.5

1,219.5

1,218.5

Total Liabilities and Shareholders’ Equity

$
3,711.6

$
3,813.3

$
3,676.5

$
3,813.3

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

10

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

Revenues

$
408.6

$
423.9

$
872.4

$
861.9

$
466.8

$
487.0

$
1,339.2

$
1,348.9

Cost of revenues:

Fuel

89.1

88.5

187.7

189.1

124.0

97.4

311.7

286.5

Purchased power

104.4

90.3

222.2

162.9

95.6

116.4

317.8

279.3

Total cost of revenues

193.5

178.8

409.9

352.0

219.6

213.8

629.5

565.8

Gross margin

215.1

245.1

462.5

509.9

247.2

273.2

709.7

783.1

Operating expenses:

Operation and maintenance

95.1

85.4

186.5

164.7

80.2

78.7

266.7

243.4

Depreciation and amortization

33.4

33.2

66.5

68.0

33.8

30.4

100.3

98.4

General taxes

30.8

29.5

64.4

61.8

33.2

32.2

97.6

94.0

Total operating expenses

159.3

148.1

317.4

294.5

147.2

141.3

464.6

435.8

Operating income

55.8

97.0

145.1

215.4

100.0

131.9

245.1

347.3

Other income / (expense), net:

Investment income

0.5

0.4

1.1

0.9

0.4

0.4

1.5

1.3

Interest expense

(9.7
)
(9.1
)
(19.4
)
(18.5
)

(9.3
)
(9.4
)
(28.7
)
(27.9
)
Other expense

(0.3
)
(0.5
)
(0.8
)
(1.1
)

(0.4
)
(0.3
)
(1.2
)
(1.4
)
Total other income / (expense), net

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

(9.3
)
(9.3
)
(28.4
)
(28.0
)

Earnings before income tax

46.3

87.8

126.0

196.7

90.7

122.6

216.7

319.3

Income tax expense

15.5

28.4

42.5

65.2

26.8

39.4

69.3

104.6

Net income

30.8

59.4

83.5

131.5

63.9

83.2

147.4

214.7

Dividends on preferred stock

0.2

0.2

0.4

0.4

0.2

0.2

0.6

0.6

Earnings on common stock

$
30.6

$
59.2

$
83.1

$
131.1

$
63.7

$
83.0

$
146.8

$
214.1

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

11

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED STATEMENTS OF CASH FLOWS

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Cash flows from operating activities:

Net income

$
83.5

$
131.5

$
147.4

$
214.7

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

Depreciation and amortization

66.5

68.0

100.3

98.4

Deferred income taxes

37.2

5.8

56.1

36.9

Unamortized investment tax credit

(1.4
)
(1.4
)

(2.1
)
(2.1
)
Changes in certain assets and liabilities:

Accounts receivable

25.5

19.9

26.4

27.5

Inventories

—

(2.0
)

(11.5
)
10.3

Prepaid taxes

(19.2
)
(1.0
)

(11.5
)
(0.9
)
Taxes applicable to subsequent years

31.4

29.4

47.1

44.0

Deferred regulatory costs, net

8.9

4.1

7.9

7.0

Accounts payable

(7.8
)
7.4

(14.9
)
(6.1
)
Accrued taxes payable

(32.3
)
(37.6
)

(58.5
)
(55.6
)
Accrued interest payable

5.3

(0.1
)

7.4

2.2

Pension, retiree and other benefits

(42.7
)
(23.0
)

(31.7
)
(54.6
)
Other

8.3

4.1

24.4

16.3

Net cash provided by operating activities

163.2

205.1

286.8

338.0

Cash flows from investing activities:

Capital expenditures

(90.8
)
(73.5
)

(139.9
)
(112.3
)
Other

1.7

1.9

1.4

1.7

Net cash used for investing activities

(89.1
)
(71.6
)

(138.5
)
(110.6
)

Cash flows from financing activities:

Dividends paid on common stock to parent

(115.0
)
(150.0
)

(180.0
)
(150.0
)
Dividends paid on preferred stock

(0.4
)
(0.4
)

(0.6
)
(0.6
)
Withdrawals from revolving credit facilities

50.0

—

50.0

—

Repayments of borrowings from revolving credit facilities

(50.0
)
—

(50.0
)
—

Net cash used for financing activities

(115.4
)
(150.4
)

(180.6
)
(150.6
)

Cash and cash equivalents:

Net change

(41.3
)
(16.9
)

(32.3
)
76.8

Balance at beginning of period

54.0

57.1

54.0

57.1

Cash and cash equivalents at end of period

$
12.7

$
40.2

$
21.7

$
133.9

Supplemental cash flow information:

Interest paid, net of amounts capitalized

$
14.6

$
19.7

$
22.2

$
27.6

Income taxes paid, net

$
24.1

$
53.1

$
13.9

$
60.7

Non-cash financing and investing activities:

Accruals for capital expenditures

$
22.6

$
11.3

$
14.8

$
14.1

Long-term liability incurred for the purchase of assets

$
18.7

$
—

$
18.7

$
—

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

12

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

ASSETS

Current assets:

Cash and cash equivalents

$
12.7

$
54.0

$
21.7

$
54.0

Accounts receivable, net (Note 2)

150.4

178.0

152.5

178.0

Inventories (Note 2)

114.1

114.2

125.6

114.2

Taxes applicable to subsequent years

31.4

62.8

15.7

62.8

Other prepayments and current assets

60.6

42.7

45.2

42.7

Total current assets

369.2

451.7

360.7

451.7

Property, plant and equipment:

Property, plant and equipment

5,218.0

5,093.7

5,243.8

5,093.7

Less: Accumulated depreciation and amortization

(2,523.7
)
(2,453.1
)

(2,545.2
)
(2,453.1
)

2,694.3

2,640.6

2,698.6

2,640.6

Construction work in process

112.7

119.6

118.0

119.6

Total net property, plant and equipment

2,807.0

2,760.2

2,816.6

2,760.2

Other noncurrent assets:

Regulatory assets (Note 3)

178.8

189.0

178.2

189.0

Other assets

80.0

74.5

Other deferred assets

64.2

74.5

Total other noncurrent assets

258.8

263.5

242.4

263.5

Total Assets

$
3,435.0

$
3,475.4

$
3,419.7

$
3,475.4

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

13

Table of Contents

THE DAYTON POWER AND LIGHT COMPANY
CONDENSED BALANCE SHEETS

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

LIABILITIES AND SHAREHOLDER’S EQUITY

Current liabilities:

Current portion - long-term debt (Note 5)

$
0.4

$
0.1

$
0.4

$
0.1

Accounts payable

87.0

95.7

75.1

95.7

Accrued taxes

70.3

66.6

70.3

66.6

Accrued interest

13.3

7.7

15.5

7.7

Customer security deposits

17.8

18.7

16.9

18.7

Other current liabilities

33.8

33.6

33.8

33.6

Total current liabilities

222.6

222.4

212.0

222.4

Noncurrent liabilities:

Long-term debt (Note 5)

903.0

884.0

903.0

884.0

Deferred taxes (Note 6)

636.5

598.0

656.4

598.0

Regulatory liabilities (Note 3)

129.4

124.0

133.1

124.0

Pension, retiree and other benefits

27.6

64.9

25.9

64.9

Unamortized investment tax credit

31.0

32.4

30.3

32.4

Other deferred credits

111.0

147.3

84.4

147.3

Total noncurrent liabilities

1,838.5

1,850.6

1,833.1

1,850.6

Redeemable preferred stock

22.9

22.9

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

0.4

0.4

Other paid-in capital

782.6

782.4

782.8

782.4

Accumulated other comprehensive loss

(17.0
)
(20.2
)

(15.1
)
(20.2
)
Retained earnings

585.0

616.9

583.6

616.9

Total common shareholder’s equity

1,351.0

1,379.5

1,351.7

1,379.5

Total Liabilities and Shareholder’s Equity

$
3,435.0

$
3,475.4

$
3,419.7

$
3,475.4

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

14

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. Refer to Note 15 of Notes to Condensed Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.

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

DP&L’s sales reflect 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 subsidiary, MC Squared, which was purchased on February 28, 2011. DPLER has approximately ~~15,000~~25,000 customers currently located throughout Ohio and Illinois. DPLER does not have any transmission or generation assets, and all of DPLER’s electric energy was purchased from DP&L or PJM to meet its sales obligations.

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 captive insurance company that provides insurance services to us and DPL’s subsidiaries.

DPL also has a 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~~1,528 people as of ~~June~~September 30, 2011, of which ~~1,503~~1,497 employees were employed by DP&L. Approximately 53% of all employees are under a collective bargaining agreement which expires inon October 31, 2011. We began negotiations with employees covered under our collective bargaining agreement during the three months ended September 30, 2011 and reached a tentative agreement on October 17, 2011. See Note 14 of Notes to Condensed Consolidated Financial Statements for more information relating to the collective bargaining agreement.
15

Table of Contents

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

We prepare Condensed Financial Statements for DP&L. 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.
15

~~Table of Contents~~

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

Deferred SECA revenue 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~~September 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.

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.

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~~September 30, 2011; our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2011; and our cash flows for the ~~six~~nine months ended ~~June~~September 30, 2011. 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~~nine months ended ~~June~~September 30, 2011 may not be indicative of our results that will be realized for the full year ending December 31, 2011.

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

Property, Plant and Equipment
We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. Capitalization of AFUDC ceases at either project completion or at the date specified by regulators. AFUDC capitalized during the three and ~~six month periods~~nine months ended ~~June~~September 30, 2011 and 2010 was not material.
16

Table of Contents

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 ~~June~~September 30, 2011, neither DPL nor DP&L had any material plant acquisition adjustments or other plant-related adjustments.
16

~~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~~nine months ended ~~June~~September 30, 2011, the ~~net~~ reduction ~~in depreciation expense amounted to $2.4 million ($1.6 million net of tax) and~~was $4.8 million ($3.1 million, net of tax)~~, respectively,~~ and increased diluted EPS by approximately ~~$0.01 and $0.02~~$0.03 per ~~share, respectively.~~share. The net reduction in depreciation expense for the twelve months ended ~~June~~September 30, 2011 was ~~$9.6~~$7.2 million ($~~6.3~~4.7 million net of tax) or $0.04 per diluted share.

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.

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

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

State/Local excise taxes

$
11.6

$
11.4

$
25.7

$
25.5

$
14.3

$
14.6

$
39.9

$
40.1

17

Table of Contents

Related Party Transactions
In the normal course of business, DP&L enters into transactions with other subsidiaries of DPL. All material intercompany accounts and transactions are eliminated in DPL’s Condensed Consolidated Financial Statements. The following table provides a summary of these transactions:

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

DP&L Revenues:

Sales to DPLER (a)

$
81.0

$
52.8

$
156.1

$
90.0

$
90.2

$
75.9

$
246.3

$
165.9

DP&L Operation & Maintenance Expenses:

Premiums paid for insurance services provided by MVIC (b)

$
(0.8
)
$
(0.8
)
$
(1.6
)
$
(1.7
)

$
(0.8
)
$
(0.8
)
$
(2.4
)
$
(2.5
)
Expense recoveries for services provided to DPLER (c)

$
0.8

$
1.5

$
1.7

$
2.4

$
1.1

$
1.6

$
2.8

$
4.0

(a)       DP&L sells power to DPLER 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~~nine months ended ~~June~~September 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 at DP&L’s cost and credits the expense in which they were initially recorded.

Recently Issued 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 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 new rules to have a material impact 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 this ASU on January 1, 2012. This standard updates FASC Topic 220, “Comprehensive Income.” ASU 2011-05 and 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 new rules to have a material impact 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 expect to adopt 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, then the two-step impairment test is not performed. We do not expect these new rules to have a material impact on our overall results of operations, financial position or cash flows.
18

Table of Contents

2.     Supplemental Financial Information and Comprehensive Income

DPL Inc.

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

Accounts receivable, net:

Unbilled revenue

$
70.6

$
84.5

$
60.0

$
84.5

Customer receivables

116.7

113.9

124.7

113.9

Amounts due from partners in jointly-owned plants

8.7

7.0

10.8

7.0

Coal sales

1.2

4.0

3.8

4.0

Other

5.8

7.0

5.2

7.0

Provision for uncollectible accounts

(1.2
)
(0.9
)

(1.3
)
(0.9
)
Total accounts receivable, net

$
201.8

$
215.5

$
203.2

$
215.5

Inventories, at average cost:

Fuel, limestone and emission allowances

$
70.9

$
73.2

$
80.4

$
73.2

Plant materials and supplies

39.4

38.8

39.7

38.8

Other

5.3

3.3

6.7

3.3

Total inventories, at average cost

$
115.6

$
115.3

$
126.8

$
115.3

DP&L

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

Accounts receivable, net:

Unbilled revenue

$
46.0

$
64.3

$
38.0

$
64.3

Customer receivables

90.8

95.6

97.4

95.6

Amounts due from partners in jointly-owned plants

8.7

7.0

10.8

7.0

Coal sales

1.2

4.0

3.8

4.0

Other

4.7

7.9

3.5

7.9

Provision for uncollectible accounts

(1.0
)
(0.8
)

(1.0
)
(0.8
)
Total accounts receivable, net

$
150.4

$
178.0

$
152.5

$
178.0

Inventories, at average cost:

Fuel, limestone and emission allowances

$
70.6

$
73.2

$
80.4

$
73.2

Plant materials and supplies

38.2

37.7

38.5

37.7

Other

5.3

3.3

6.7

3.3

Total inventories, at average cost

$
114.1

$
114.2

$
125.6

$
114.2

19

Table of Contents

Supplemental Financial Information and Comprehensive Income (continued)

Comprehensive income for the three months ended ~~June~~September 30, 2011 and 2010 was as follows:

DPL Inc.

Three Months Ended June 30,

Three Months Ended September 30,

2011

2010

$ in millions

2011

2010

Comprehensive income:

Net income

$
31.7

$
61.4

$
67.1

$
86.4

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

Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.2 million and income tax expense of $0.1 million, respectively

(0.3
)
0.3

Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $24.9 million and $3.6 million, respectively

(46.6
)
(9.1
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax benefit of $0.1 million and income tax expense of $0.4 million, respectively

0.9

0.8

Comprehensive income

$
22.1

$
52.0

$
21.1

$
78.4

DP&L

Three Months Ended June 30,

Three Months Ended September 30,

2011

2010

$ in millions

2011

2010

Comprehensive income:

Net income

$
30.8

$
59.4

$
63.9

$
83.2

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

Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.1 million and income tax expense of $1.0 million, respectively

(0.4
)
1.8

Net change in deferred gains (losses) on cash flow hedges, net of income tax expense of $0.9 million and $0.2 million, respectively

1.3

(0.2
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax benefit of $0.1 million and income tax expense of $0.4 million, respectively

1.0

0.8

Comprehensive income

$
32.3

$
53.6

$
65.8

$
85.6

Comprehensive income for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 was as follows:

DPL Inc.

Six Months Ended June 30,

Nine Months Ended September 30,

2011

2010

$ in millions

2011

2010

Comprehensive income:

Net income

$
75.2

$
132.4

$
142.3

$
218.8

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

Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.2 million and income tax expense of $0.1 million, respectively

(0.3
)
0.2

Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $28.9 million and $6.0 million, respectively

(55.4
)
(14.7
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.7 million and $0.3 million, respectively

2.5

3.4

Comprehensive income

$
68.0

$
129.3

$
89.1

$
207.7

DP&L

Six Months Ended June 30,

Nine Months Ended September 30,

2011

2010

$ in millions

2011

2010

Comprehensive income:

Net income

$
83.5

$
131.5

$
147.4

$
214.7

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

Net change in unrealized gains (losses) on financial instruments, net of income tax expense of $1.3 million and income tax benefit of $0.5 million, respectively

2.3

(0.9
)
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense of $1.1 million and $1.0 million, respectively

0.2

(0.1
)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.7 million and $0.3 million, respectively

2.6

3.4

Comprehensive income

$
86.7

$
131.6

$
152.5

$
217.1

20

Table of Contents

3. Regulatory Matters

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
On March 4, 2011, DP&L applied for approval from the PUCO 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 became effective in July 2011. ~~Under Ohio law,~~On October 26, 2011, the ~~electric discount provided to this customer may be recovered from all customers through an~~PUCO approved our Economic Development ~~Rider.~~Rider, as filed, which is designed to recover costs associated with this and other economic development contracts and programs.

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

At

At

Type of

Amortization

June 30,

December 31,

$ in millions

Recovery (a)

Through

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

REGULATORY MATTERS

At

At

Type of

Amortization

September 30,

December 31,

$ in millions

Recovery (a)

Through

2011

2010

Regulatory Assets:

Deferred recoverable income taxes

B/C

Ongoing

$
26.6

$
29.9

Pension benefits

C

Ongoing

76.6

81.1

Unamortized loss on reacquired debt

C

Ongoing

13.3

14.3

Regional transmission organization costs

D

2014

4.4

5.5

TCRR, transmission, ancillary and other PJM-related costs

F

Ongoing

7.7

11.8

Deferred storm costs - 2008

D

17.7

16.9

Power plant emission fees

C

Ongoing

7.1

6.6

CCEM smart grid and advanced metering infrastructure costs

D

6.6

6.6

CCEM energy efficiency program costs

F

Ongoing

8.0

4.8

Other costs

10.2

11.5

Total regulatory assets

$
178.2

$
189.0

Regulatory Liabilities:

Estimated costs of removal - regulated property

$
111.7

$
107.9

Postretirement benefits

5.4

6.1

Fuel and purchased power recovery costs

C

Ongoing

16.0

10.0

Total regulatory liabilities

$
133.1

$
124.0

(a)       B — Balance has an offsetting liability resulting in no impact on rate base.
C — Recovery of incurred costs without a rate of return.
D — Recovery not yet determined, but is probable of occurring in future rate proceedings.
F — Recovery of incurred costs plus rate of return.

Regulatory Assets

Deferred recoverable income taxes represent deferred income tax assets recognized from the normalization of flow through items as a 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.
21

Table of Contents

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, 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.

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 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.

22

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,~~but there is some uncertainty as to the costs that will be ~~approved for recovery.~~recovered from or returned to customers. Independent third parties conducted the fuel audit in accordance with PUCO standards. ~~The audit was completed~~On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the ~~second quarter~~majority of the issues raised by the auditor. On October 19, 2011, ~~and~~we had a hearing ~~has been set by~~on this case. Although the Stipulation and Recommendation was uncontested, the PUCO ~~for August 30, 2011. Once~~may approve, disapprove, or modify the ~~PUCO audit approval process is complete,~~stipulation. DP&L ~~may~~expects to 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~~earnings after the ~~case of over recovery.~~final order is received.

4. Ownership of Coal-fired Facilities

DP&L with certain other Ohio utilities has undivided ownership interests in seven coal-fired electric generating facilities and numerous transmission facilities. Certain expenses, primarily fuel costs for the generating units, are allocated to the owners based on their energy usage. The remaining expenses, investments in fuel inventory, plant materials and operating supplies, and capital additions are allocated to the owners in accordance with their respective ownership interests. As of ~~June~~September 30, 2011, we had ~~$49~~$42 million of construction work in process at such facilities. DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

DP&L’s undivided ownership interest in such facilities as well as our wholly-owned coal fired Hutchings plant at ~~June~~September 30, 2011, is as follows:

DP&L Share

DP&L Investment

DP&L Share

DP&L Investment

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

$
76

$
57

$
—

No

Conesville Unit 4

16.5

129

119

30

4

Yes

16.5

129

119

31

5

Yes

East Bend Station

31.0

186

201

132

—

Yes

31.0

186

201

132

—

Yes

Killen Station

67.0

402

617

294

2

Yes

67.0

402

617

298

2

Yes

Miami Fort Units 7 and 8

36.0

368

354

134

10

Yes

36.0

368

366

137

2

Yes

Stuart Station

35.0

808

719

274

17

Yes

35.0

808

719

275

15

Yes

Zimmer Station

28.1

365

1,060

620

15

Yes

28.1

365

1,060

624

18

Yes

Transmission (at varying percentages)

—

91

57

—

—

91

57

—

Total

2,465

$
3,236

$
1,596

$
49

2,465

$
3,249

$
1,611

$
42

Wholly-owned production unit:

Hutchings Station

100.0

390

$
124

$
113

$
1

No

100.0

390

$
124

$
114

$
1

No

~~DP&L’s~~23

~~share~~Table of ~~operating costs associated with the jointly-owned generating facilities are included within the corresponding line in the Condensed Statements of Results of Operations.~~Contents

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. 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 Hutchings Station, but have not yet made a final decision.
23

~~Table of Contents~~ We do not believe that any accruals or impairment charges are needed related to the Hutchings Station.

5.   Debt Obligations
Long-term Debt

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

DP&L

First mortgage bonds maturing in October 2013 - 5.125%

$
470.0

$
470.0

$
470.0

$
470.0

Pollution control series maturing in January 2028 - 4.70%

35.3

35.3

35.3

35.3

Pollution control series maturing in January 2034 - 4.80%

179.1

179.1

179.1

179.1

Pollution control series maturing in September 2036 - 4.80%

100.0

100.0

100.0

100.0

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

100.0

100.0

Pollution control series maturing in November 2040 - variable rates: 0.06% - 0.29% and 0.16% - 0.36% (a)

100.0

100.0

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

18.5

—

18.5

—

902.9

884.4

902.9

884.4

Obligation for capital lease

0.5

0.1

0.5

0.1

Unamortized debt discount

(0.4
)
(0.5
)

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

$
903.0

$
884.0

$
903.0

$
884.0

DPL

Bank Term Loan - variable rates: 1.48% - 1.49% (b)

300.0

—

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

20.6

142.6

20.6

142.6

Total long-term debt - DPL

$
923.6

$
1,026.6

$
1,223.6

$
1,026.6

Current portion - Long-term Debt

At

At

At

At

June 30,

December 31,

September 30,

December 31,

$ in millions

2011

2010

2011

2010

DP&L

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

$
0.1

$
—

$
0.1

$
—

Obligation for capital lease

0.3

0.1

0.3

0.1

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

$
0.4

$
0.1

$
0.4

$
0.1

DPL

Senior notes maturing in September 2011 - 6.875%

297.4

297.4

—

297.4

Total current portion - long-term debt - DPL

$
297.8

$
297.5

$
0.4

$
297.5

~~(a)    Range of interest rates for the six months ended June~~
(a)
Range of interest rates for the nine months ended September 30, 2011 and the twelve months ended December 31, 2010, respectively.
(b)
Range of interest rates since the loan was drawn in August 2011.
24

Table of Contents

At ~~June~~September 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 millions

DPL

DP&L

Due within one year

$
0.4

$
0.4

Due within two years

0.4

0.4

Due within three years

770.3

470.3

Due within four years

0.1

0.1

Due within five years

0.1

0.1

Thereafter

453.1

432.5

$
1,224.4

$
903.8

In connection with the closing 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~~Dolphin Subsidiary II, Inc., a subsidiary of AES, ~~will issue~~issued on October 3, 2011 to finance a portion of the acquisition. The $1.25 billion was issued in two tranches. The first tranche was $450 million of five year senior unsecured notes issued at 6.50% maturing on October 15, 2016. The second tranche was $800 million of ten year senior unsecured notes issued at 7.25% maturing on October 15, 2021. 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~~may reduce DPL’s ratings to below investment grade upon assumption by DPL of the additional debt ~~as a result of~~in connection with 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~~was terminated 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 and 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.~~on August 29, 2011.

On December 4, 2008, the OAQDA issued $100 million of collateralized, variable rate Revenue Refunding Bonds Series A and B due November 1, 2040. In turn, DP&L borrowed these funds from the OAQDA and issued corresponding First Mortgage Bonds to support repayment of the funds. The payment of principal and interest on each series of the bonds when due is backed by a standby LOC issued by JPMorgan Chase Bank, N.A. This LOC facility, which expires in December 2013, is irrevocable and has no subjective acceleration clauses. The fees associated with this facility have increased as a result 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~~nine months ended ~~June~~September 30, 2011, respectively. DP&L 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.

On April 20, 2010, DP&L entered into a $200 million unsecured revolving credit agreement with a syndicated bank group. This agreement is for a three year term expiring on April 20, 2013 and provides DP&L with the ability to increase the size of the facility by an additional $50 million. DP&L had no outstanding borrowings under this credit facility at ~~June~~September 30, 2011. Fees associated with this credit facility were not material during the three and ~~six~~nine months ended ~~June~~September 30, 2011. The fees and interest rate associated with this facility ~~will increase~~have increased 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~~September 30, 2011, 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.
25

Table of Contents

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 $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 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 million.DP&L had no outstanding borrowings under this credit facility at September 30, 2011. Fees associated with this credit facility were not material during the three and nine months ended September 30, 2011. This facility also contains a $50 million letter of credit sublimit. As of September 30, 2011, DP&L had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $125 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 September 30, 2011. Fees associated with this credit facility were not material during the three and nine months ended September 30, 2011. This facility may also be used to issue letters of credit up to the $125 million limit. As of September 30, 2011, DPL had no outstanding letters of credit against the facility.
On August 24, 2011, DPL entered into a $425 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 $300 million of the $425 million available under the facility at September 30, 2011. Fees associated with this term loan were not material during the three and nine months ended September 30, 2011.
On September 1, 2011 DPL retired $297.4 million of 6.875% senior unsecured notes. DPL used the proceeds from a $300 million drawdown of the $425 million unsecured term loan to redeem these maturing bonds.
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.
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.

2526

Table of Contents

6.   Income Taxes

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

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

2011

2010

2011

2010

2011

2010

2011

2010

DPL

34.0
%
32.9
%
35.3
%
33.4
%

29.8
%
31.9
%
32.9
%
32.8
%

DP&L

33.6
%
32.3
%
33.8
%
33.1
%

29.6
%
32.1
%
32.0
%
32.8
%

Income tax expenses for the three and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 were calculated using the estimated annual effective income tax rates for 2011 and 2010 and reflect estimated annual effective income tax rates of ~~33.7%~~33.2% and ~~33.5%~~32.6%, respectively. Management estimates the annual effective tax rate based upon its forecast of annual pre-tax income. To the extent that actual pre-tax results for the year differ from the forecasts applied to the most recent interim period, the rates estimated could be materially different from the actual effective tax rates recognized.

For the three and nine months ended ~~June~~September 30, 2011, ~~DPL~~DPL’s current period effective tax rate is less than the estimated annual effective tax rate due to certain current period tax adjustments including a revision to the estimated annual effective tax rate. These current period adjustments resulted in DPL’s tax expense being reduced by $2.6 million and $0.7 million for the three and nine months ended September 30, 2011, respectively. The current period adjustments are primarily due to the effect of estimate-to-actual income tax provision adjustments related to the Internal Revenue Code Section 199 Domestic Production Deduction, ESOP related deductions and flow-through related deductions. For the nine months ended September 30, 2011, the reductions to the current period effective tax rate are partially offset by increased state 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 million by increasing deferred state income taxes by~~of $2.0 million ~~and decreasing other estimated tax liabilities by $0.1 million.~~recorded as a result of the acquisition of MC Suared.

For the three and ~~six~~nine months ended ~~June~~September 30, 2011, DP&L&L’s current period effective tax rate is less than the estimated annual effective tax rate due to certain current period tax adjustments including a revision to the estimated annual effective tax rate. These current period adjustments resulted in DP&L’s ~~increased~~tax expense being reduced by $2.6 million and $2.2 million for the three and nine months ended September 30, 2011, respectively. The current period adjustments are primarily due to the effect of estimate-to-actual income tax ~~expense by $0.1 million~~provision adjustments related to the Section 199 Domestic Production Deduction, ESOP related deductions and ~~$0.2 million, respectively, for an increase in other estimated tax liabilities.~~flow-through related deductions.

For the ~~six~~nine months ended ~~June~~September 30, 2011, the increase in DPL’s current period effective tax rate compared to the same period in 2010 ~~primarily~~ reflects the estimate-to-actual income tax provision adjustments which are more than offset by 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~~decrease in DP&L’s current period effective tax rate primarily reflects the estimate-to-actual income tax provision adjustments offset by decreased benefits from the Section 199 Domestic Production Deduction.

Deferred tax liabilities for both DPL and DP&L increased by approximately ~~$32.4~~$38.8 million and ~~$37.8~~$56.0 million, respectively, during the ~~six~~nine months ended ~~June~~September 30, 2011. These increases were related to depreciation, a pension contribution, financial transaction losses and other temporary differences arising from routine changes in balance sheet accounts giving rise to deferred taxes.

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

As of ~~June~~September 30, 2011, DPL has incurred approximately ~~$5.2~~$8.9 million in certain costs that are directly associated with the Proposed Merger, which ~~will~~may be deemed as non-deductible, resulting in approximately ~~$1.8~~$3.1 million of additional tax expense for the period in which the transaction ~~would occur.~~occurs.
27

Table of Contents

7.     Pension and Postretirement Benefits

DPL 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 contributions from time to time. DP&L made discretionary contributions of $40.0 million and ~~$20.0~~$40.0 million to the defined benefit plan ~~in February~~during the nine months ended September 30, 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.

DP&L sponsors a SERP providing supplemental pension benefits to a limited number of participants. Benefits under this SERP have been frozen and no additional benefits can be earned.
The amounts presented in the following tables for pension include both the defined benefit pension/cash balance plans and the SERP in the aggregate, and 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 ~~June~~September 30, 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.
~~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

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

Service cost

$
2.9

$
2.2

$
0.1

$
—

$
0.8

$
1.0

$
—

$
0.1

Interest cost

8.6

9.0

0.5

0.7

4.1

4.5

0.2

0.3

Expected return on assets (a)

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

(6.2
)
(5.6
)
(0.1
)
—

Amortization of unrecognized:

Actuarial (gain) / loss

4.5

3.6

(0.4
)
(0.4
)

1.7

2.0

(0.5
)
(0.2
)
Prior service cost

1.1

1.9

—

0.1

0.5

0.9

0.1

—

Net periodic benefit cost / (income) before adjustments

$
4.9

$
5.5

$
0.1

$
0.2

$
0.9

$
2.8

$
(0.3
)
$
0.2

(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~~$317 million.

2728

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

Pension

Postretirement

$ in millions

2011

2010

2011

2010

Service cost

$
3.7

$
3.2

$
0.1

$
0.1

Interest cost

12.7

13.5

0.7

1.0

Expected return on assets (a)

(18.4
)
(16.8
)
(0.2
)
(0.2
)
Amortization of unrecognized:

Actuarial (gain) / loss

6.2

5.6

(0.9
)
(0.6
)
Prior service cost

1.6

2.8

0.1

0.1

Net periodic benefit cost / (income) before adjustments

$
5.8

$
8.3

$
(0.2
)
$
0.4

(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 $317 million.

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

Estimated Future Benefit Payments, ~~and~~Net of Medicare Part D Reimbursements

$ in millions

Pension

Postretirement

Pension

Postretirement

2011

$
10.7

$
1.3

$
5.3

$
0.6

2012

$
23.1

$
2.4

$
23.1

$
2.4

2013

$
23.1

$
2.4

$
23.1

$
2.4

2014

$
23.6

$
2.3

$
23.6

$
2.3

2015

$
24.0

$
2.1

$
24.0

$
2.1

2016 - 2020

$
122.9

$
8.8

$
122.9

$
8.8

29

Table of Contents

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The fair value of our financial instruments represents estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at ~~June~~September 30, 2011 and December 31, 2010. See also Note 9 of Notes to Condensed Consolidated Financial Statements for the fair values of our derivative instruments.

At June 30,

At December 31,

At September 30,

At December 31,

2011

2010

2011

2010

$ 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

$
1.6

$
1.6

Equity Securities

3.5

4.2

3.8

4.4

3.9

4.0

3.8

4.4

Debt Securities

5.2

5.5

5.2

5.5

5.1

5.6

5.2

5.5

Multi-Strategy Fund

0.3

0.3

0.3

0.3

0.3

0.2

0.3

0.3

Total Master Trust Assets

$
9.2

$
10.2

$
10.9

$
11.8

$
9.5

$
10.0

$
10.9

$
11.8

Short-term Investments - VRDNs

$
—

$
—

$
54.2

$
54.2

$
—

$
—

$
54.2

$
54.2

Short-term Investments - Bonds

—

—

15.1

15.1

—

—

15.1

15.1

Total Short-term Investments

$
—

$
—

$
69.3

$
69.3

$
—

$
—

$
69.3

$
69.3

Total Assets

$
9.2

$
10.2

$
80.2

$
81.1

$
9.5

$
10.0

$
80.2

$
81.1

Liabilities

Debt

$
1,221.4

$
1,198.7

$
1,324.1

$
1,307.5

$
1,224.0

$
1,204.6

$
1,324.1

$
1,307.5

DP&L

Assets

Money Market Funds

$
0.2

$
0.2

$
1.6

$
1.6

$
0.2

$
0.2

$
1.6

$
1.6

Equity Securities (a)

16.9

33.7

17.5

30.2

17.3

33.5

17.5

30.2

Debt Securities

5.2

5.5

5.2

5.5

5.1

5.6

5.2

5.5

Multi-Strategy Fund

0.3

0.3

0.3

0.3

0.3

0.2

0.3

0.3

Total Master Trust Assets

$
22.6

$
39.7

$
24.6

$
37.6

$
22.9

$
39.5

$
24.6

$
37.6

Liabilities

Debt

$
903.4

$
877.3

$
884.1

$
850.6

$
903.4

$
884.2

$
884.1

$
850.6

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

Debt
Debt is shown asat fair value based on current public market prices for disclosure purposes only. Unrealized gains or losses are not recognized in the ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements as debt is presented at amortized cost in the ~~condensed consolidated financial statements.~~Condensed Consolidated Financial Statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2061.

28

~~Table of Contents~~
Master Trust Assets
DP&L established a Master Trust to hold assets 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 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.

30

Table of Contents
DPL had ~~$1.0~~$0.5 million ($~~0.7~~0.3 million after tax) in unrealized gains and ~~immaterial~~$0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at ~~June~~September 30, 2011 and $0.9 million ($0.6 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2010.

DP&L had ~~$17.0~~$16.6 million ($~~11.0~~10.8 million after tax) in unrealized gains and ~~immaterial~~$0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at ~~June~~September 30, 2011 and $13.0 million ($8.5 million after tax) in unrealized gains and immaterial unrealized losses in AOCI at December 31, 2010.

Approximately $0.4 million in unrealized gains are expected to be transferred to earnings in the next twelve months.

Short-Term Investments
DPL from time to time 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 from time to time utilizes investment-grade fixed income corporate securities in its short-term investment portfolio. These securities are accounted for as held-to-maturity investments.

2931

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~~September 30, 2011 and December 31, 2010. These assets are part of the Master Trust and exclude DPL common stock which is valued using quoted market prices and not the NAV. 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 on the reporting date. Investments that have restrictions on the redemption of the investments are Level 3 inputs. As of ~~June~~September 30, 2011, DPL did not have any investments for sale at a price different than 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
$ in millions

Fair Value at
September 30, 2011

Fair Value at
December 31, 2010

Unfunded
Commitments

Redemption
Frequency

Money Market Fund (a)

$
0.2

$
1.6

$
—

Immediate

Equity Securities (b)

4.0

4.4

—

Immediate

Debt Securities (c)

5.6

5.5

—

Immediate

Multi-Strategy Fund (d)

0.2

0.3

—

Immediate

Total

$
10.0

$
11.8

$
—

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

(c)        This category includes 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.

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~~nine months ended ~~June~~September 30, 2011.

3032

Table of Contents

The fair value of assets and liabilities at ~~June~~September 30, 2011 and December 31, 2010 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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Level 1

Level 2

Level 3

Fair Valueon

$ 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

Fair Value at
September 30,
2011*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Balance Sheet at
September 30,
2011

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

4.0

—

4.0

—

—

4.0

Debt Securities

5.5

—

5.5

—

—

5.5

5.6

—

5.6

—

—

5.6

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

0.2

—

0.2

—

—

0.2

Total Master Trust Assets

$
10.2

$
—

$
10.2

$
—

$
—

$
10.2

$
10.0

$
—

$
10.0

$
—

$
—

$
10.0

Derivative Assets

FTRs

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

$
0.1

$
—

$
0.1

$
—

$
—

$
0.1

Heating Oil Futures

3.3

3.3

—

—

(3.3
)
—

1.7

1.7

—

—

(1.7
)
—

Interest Rate Hedge

18.6

—

18.6

—

—

18.6

Forward NYMEX Coal Contracts

24.4

—

24.4

—

(13.6
)
10.8

2.3

—

2.3

—

(1.2
)
1.1

Forward Power Contracts

12.9

—

12.9

—

(0.8
)
12.1

12.8

—

12.8

—

(2.0
)
10.8

Total Derivative Assets

$
59.4

$
3.3

$
56.1

$
—

$
(17.7
)
$
41.7

$
16.9

$
1.7

$
15.2

$
—

$
(4.9
)
$
12.0

Short-term Investments - Bonds

—

—

—

—

—

—

—

—

—

—

—

—

Total Short-term investments

$
—

$
—

$
—

$
—

$
—

$
—

Total Short-term Investments

$
—

$
—

$
—

$
—

$
—

$
—

Total Assets

$
69.6

$
3.3

$
66.3

$
—

$
(17.7
)
$
51.9

$
26.9

$
1.7

$
25.2

$
—

$
(4.9
)
$
22.0

Liabilities

Derivative Liabilities

Interest Rate Hedge

$
(18.7
)
$
—

$
(18.7
)
$
—

$
—

$
(18.7
)
Interest Rate Hedges

$
28.5

$
—

$
28.5

$
—

$
—

$
28.5

Forward NYMEX Coal Contracts

(0.5
)
—

(0.5
)
—

0.5

—

6.3

—

6.3

—

(6.3
)
—

Forward Power Contracts

(9.7
)
—

(9.7
)
—

3.5

(6.2
)

6.6

—

6.6

—

(2.6
)
4.0

Total Derivative Liabilities

$
(28.9
)
$
—

$
(28.9
)
$
—

$
4.0

$
(24.9
)

$
41.4

$
—

$
41.4

$
—

$
(8.9
)
$
32.5

Total Liabilities

$
(28.9
)
$
—

$
(28.9
)
$
—

$
4.0

$
(24.9
)

$
41.4

$
—

$
41.4

$
—

$
(8.9
)
$
32.5

*Includes credit valuation adjustments for counterparty risk.

3133

Table of Contents

DPL

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Fair Value on

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

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

$
1.6

$
—

$
1.6

$
—

$
—

$
1.6

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

0.3

—

0.3

—

—

0.3

Total Master Trust Assets

$
11.8

$
—

$
11.8

$
—

$
—

$
11.8

$
11.8

$
—

$
11.8

$
—

$
—

$
11.8

Derivative Assets

FTRs

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

Heating Oil Futures

1.6

1.6

—

—

(1.6
)
—

1.6

1.6

—

—

(1.6
)
—

Interest Rate Hedge

20.7

—

20.7

—

—

20.7

20.7

—

20.7

—

—

20.7

Forward NYMEX Coal Contracts

37.5

—

37.5

—

(21.9
)
15.6

37.5

—

37.5

—

(21.9
)
15.6

Forward Power Contracts

0.2

—

0.2

—

(0.2
)
—

0.2

—

0.2

—

(0.2
)
—

Total Derivative Assets

$
60.3

$
1.6

$
58.7

$
—

$
(23.7
)
$
36.6

$
60.3

$
1.6

$
58.7

$
—

$
(23.7
)
$
36.6

Short-term Investments - VRDNs

$
54.2

$
—

$
54.2

$
—

$
—

$
54.2

$
54.2

$
—

$
54.2

$
—

$
—

$
54.2

Short-term Investments - Bonds

15.1

—

15.1

—

—

15.1

15.1

—

15.1

—

—

15.1

Total Short-term investments

$
69.3

$
—

$
69.3

$
—

$
—

$
69.3

Total Short-term Investments

$
69.3

$
—

$
69.3

$
—

$
—

$
69.3

Total Assets

$
141.4

$
1.6

$
139.8

$
—

$
(23.7
)
$
117.7

$
141.4

$
1.6

$
139.8

$
—

$
(23.7
)
$
117.7

Liabilities

Derivative Liabilities

Interest Rate Hedge

$
6.6

$
—

$
6.6

$
—

$
—

$
6.6

Interest Rate Hedges

$
6.6

$
—

$
6.6

$
—

$
—

$
6.6

Forward Power Contracts

3.1

—

3.1

—

(1.1
)
2.0

3.1

—

3.1

—

(1.1
)
2.0

Total Derivative Liabilities

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

Total Liabilities

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

$
9.7

$
—

$
9.7

$
—

$
(1.1
)
$
8.6

*Includes credit valuation adjustments for counterparty risk.

3234

Table of Contents

The fair value of assets and liabilities at ~~June~~September 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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Level 1

Level 2

Level 3

Fair Value on

$ 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

Fair Value at
September 30,
2011*

Based on Quoted
Prices in Active
Markets

Other
Observable
Inputs

Unobservable
Inputs

Collateral and
Counterparty
Netting

Balance Sheet at
September 30,
2011

Assets

Master Trust Assets

Money Market Funds

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

Equity Securities (a)

33.7

29.5

4.2

—

—

33.7

33.5

29.5

4.0

—

—

33.5

Debt Securities

5.5

—

5.5

—

—

5.5

5.6

—

5.6

—

—

5.6

Multi-Strategy Fund

0.3

—

0.3

—

—

0.3

0.2

—

0.2

—

—

0.2

Total Master Trust Assets

$
39.7

$
29.5

$
10.2

$
—

$
—

$
39.7

$
39.5

$
29.5

$
10.0

$
—

$
—

$
39.5

Derivative Assets

FTRs

$
0.2

$
—

$
0.2

$
—

$
—

$
0.2

$
0.1

$
—

$
0.1

$
—

$
—

$
0.1

Heating Oil Futures

3.3

3.3

—

—

(3.3
)
—

1.7

1.7

—

—

(1.7
)
—

Forward NYMEX Coal Contracts

24.4

—

24.4

—

(13.6
)
10.8

2.3

—

2.3

—

(1.2
)
1.1

Forward Power Contracts

1.3

—

1.3

—

(0.8
)
0.5

3.2

—

3.2

—

(2.4
)
0.8

Total Derivative Assets

$
29.2

$
3.3

$
25.9

$
—

$
(17.7
)
$
11.5

$
7.3

$
1.7

$
5.6

$
—

$
(5.3
)
$
2.0

Total Assets

$
68.9

$
32.8

$
36.1

$
—

$
(17.7
)
$
51.2

$
46.8

$
31.2

$
15.6

$
—

$
(5.3
)
$
41.5

Liabilities

Derivative Liabilities

Forward NYMEX Coal Contracts

$
(0.5
)
$
—

$
(0.5
)
$
—

$
0.5

$
—

$
6.3

$
—

$
6.3

$
—

$
(6.3
)
$
—

Forward Power Contracts

(3.6
)
—

(3.6
)
—

1.5

(2.1
)

2.8

—

2.8

—

(1.4
)
1.4

Total Derivative Liabilities

$
(4.1
)
$
—

$
(4.1
)
$
—

$
2.0

$
(2.1
)

$
9.1

$
—

$
9.1

$
—

$
(7.7
)
$
1.4

Total Liabilities

$
(4.1
)
$
—

$
(4.1
)
$
—

$
2.0

$
(2.1
)

$
9.1

$
—

$
9.1

$
—

$
(7.7
)
$
1.4

*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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Level 1

Level 2

Level 3

Fair Value on

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

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

$
1.6

$
—

$
1.6

$
—

$
—

$
1.6

Equity Securities (a)

30.2

25.8

4.4

—

—

30.2

30.2

25.8

4.4

—

—

30.2

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

$
37.6

$
25.8

$
11.8

$
—

$
—

$
37.6

$
37.6

$
25.8

$
11.8

$
—

$
—

$
37.6

Derivative Assets

FTRs

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

$
0.3

$
—

$
0.3

$
—

$
—

$
0.3

Heating Oil Futures

1.6

1.6

—

—

(1.6
)
—

1.6

1.6

—

—

(1.6
)
—

Forward NYMEX Coal Contracts

37.5

—

37.5

—

(21.9
)
15.6

37.5

—

37.5

—

(21.9
)
15.6

Forward Power Contracts

0.2

—

0.2

—

(0.2
)
—

0.2

—

0.2

—

(0.2
)
—

Total Derivative Assets

$
39.6

$
1.6

$
38.0

$
—

$
(23.7
)
$
15.9

$
39.6

$
1.6

$
38.0

$
—

$
(23.7
)
$
15.9

Total Assets

$
77.2

$
27.4

$
49.8

$
—

$
(23.7
)
$
53.5

$
77.2

$
27.4

$
49.8

$
—

$
(23.7
)
$
53.5

Liabilities

Derivative Liabilities

Forward Power Contracts

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

Total Derivative Liabilities

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

Total Liabilities

$
3.1

$
—

$
3.1

$
—

$
(1.1
)
$
2.0

$
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.

3335

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 NYMEX-quality coal contracts (which are traded on the OTC market but which are valued using prices on the NYMEX for similar contracts on the OTC market). VRDNs and bonds are considered Level 2 because they are priced using recent transactions for similar assets. Other Level 2 assets include open-ended mutual funds that are in the Master Trust, which are valued using the end of day NAV per unit and interest rate hedges, which use observable inputs to populate a pricing model.

Approximately ~~97%~~98% and 87% of the inputs to the fair value of our derivative instruments are from quoted market ~~prices.~~prices for DPL and DP&L, respectively.

Non-recurring fair value measurements
We use the cost approach to determine the fair value of our AROs which are estimated by discounting expected cash outflows to their present value at the initial recording of the liability. Cash outflows are based on the approximate future disposal cost as determined by market information, historical information or other management estimates. These inputs to the fair value of the AROs would be considered Level 3 inputs under the fair value hierarchy. There were no additions to our existing AROs during the three or ~~six~~nine months ended ~~June~~September 30, 2011.

Cash Equivalents
DPL had ~~$25.0 million~~no money in money market funds at September 30, 2011 and $29.9 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. The money market funds have quoted prices that are generally equivalent to par.

9. Derivative Instruments and Hedging Activities

In the normal course of business, DPL and DP&L enter into various financial instruments, including derivative financial instruments. We use derivatives principally to manage the risk of changes in market prices for commodities. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The objective of the hedging program is 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 or marked to market each reporting period.

At ~~June~~September 30, 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

17.0

—

17.0

Mark to Market

MWh

11.3

1.0

12.3

Heating Oil Futures (1)

Mark to Market

Gallons

4,578.0

—

4,578.0

Mark to Market

Gallons

3,654.0

—

3,654.0

Forward Power Contracts (1)

Cash Flow Hedge

MWh

927.2

(965.7
)
(38.5
)

Cash Flow Hedge

MWh

974.9

(746.5
)
228.4

Forward Power Contracts (1)

Mark to Market

MWh

446.9

(423.2
)
23.7

Mark to Market

MWh

587.0

(570.7
)
16.3

Forward Power Contracts (2)

Mark to Market

MWh

1,311.3

(1,338.7
)
(27.4
)

Mark to Market

MWh

1,365.2

(1,350.1
)
15.1

NYMEX-quality Coal Contracts* (1)

Mark to Market

Tons

3,588.3

—

3,588.3

Mark to Market

Tons

2,658.3

—

2,658.3

Interest Rate Swaps (2)

Cash Flow Hedge

USD

460,000.0

—

460,000.0

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.
(2)Reflected in only DPL’s Condensed Consolidated Financial Statements.

3436

Table of Contents

At December 31, 2010, DPL and DP&L had the following outstanding derivative instruments:

Accounting

Purchases

Sales

Net Purchases/
(Sales)

Commodity

Treatment

Unit

(in thousands)

(in thousands)

(in thousands)

FTRs (1)

Mark to Market

MWh

9.0

—

9.0

Heating Oil Futures (1)

Mark to Market

Gallons

6,216.0

—

6,216.0

Forward Power Contracts (1)

Cash Flow Hedge

MWh

580.8

(572.9
)
7.9

Forward Power Contracts (1)

Mark to Market

MWh

195.6

(108.5
)
87.1

NYMEX-quality Coal Contracts* (1)

Mark to Market

Tons

4,006.8

—

4,006.8

Interest Rate Swaps (2)

Cash Flow Hedge

USD

360,000.0

—

360,000.0

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

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

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~~September 30, 2011, we have ~~entered into~~outstanding interest rate hedging relationships with aggregate notional amounts of ~~$300 million and~~ $160 million related to planned future borrowing activities in calendar ~~years~~year 2013. During the three months ended September 30, 2011, ~~and 2013, respectively.~~interest rate hedging relationships with a notional amount of $200 million settled resulting in DPL making a cash payment of $48.1 million ($31.3 million net of tax) during the period. As part of the Proposed Merger discussed in Note 16, DPL ~~agreed to use commercially reasonable efforts to enter~~entered into a ~~$425~~$425.0 million unsecured term loan ~~of at least three years,~~agreement with a syndicated bank group on August 24, 2011, in part, to ~~refinance~~pay the approximately $297.4 million principal amount of DPL’s 6.875% debt that iswas due in September 2011. The remainder will be used for other corporate purposes. This agreement is for a three year term expiring on August 24, 2014. See Note 5 for further information. As a result, some of the forecasted transactions originally being hedged are probable of not occurring and therefore approximately ~~$2.0~~$3.1 million ($~~1.3~~2.0 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~~quarter ended September 30, 2011 and approximately $5.1 million ($3.3 million net of tax) has been reclassified during the nine months ended September 30, 2011. The remaining forecasted transactions associated with 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 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.

3537

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~~September 30, 2011 and 2010:

June 30,

June 30,

September 30,

September 30,

2011

2010

2011

2010

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

$
(1.5
)
$
12.3

$
—

$
7.7

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

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

1.8

(49.8
)
(0.4
)
(8.9
)

Net gains reclassified to earnings

Net (gains) / losses reclassified to earnings

Interest expense

—

0.7

—

(0.6
)

—

1.4

—

(0.6
)
Revenues

0.3

—

(1.5
)
—

0.1

—

0.8

—

Purchased power

0.3

—

—

—

—

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
12.3

$
—

$
7.7

$
0.4

$
(36.1
)
$
0.4

$
(1.8
)

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

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

Interest expense

—

(1.3
)
—

—

—

3.1

Revenues

—

—

—

—

—

—

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

$
(1.9
)
$
(2.4
)

$
0.8

$
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

39

24

*
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

36The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the nine months ended September 30, 2011 and 2010:

September 30,

September 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

0.8

(59.0
)
3.3

(14.7
)

Net (gains) / losses reclassified to earnings

Interest expense

—

1.5

—

(1.8
)
Revenues

0.8

—

(1.5
)
—

Purchased power

0.6

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
0.4

$
(36.1
)
$
0.4

$
(1.8
)

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

Interest expense

—

5.1

Revenues

—

—

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

$
0.8

$
2.4

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

39

24

*
The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate above due to market price changes.
39

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~~September 30, 2011 and 2010:

June 30,

June 30,

September 30,

September 30,

2011

2010

2011

2010

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
)
$
11.6

$
3.6

$
14.1

$
(1.5
)
$
11.0

$
—

$
13.5

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

(0.5
)
—

(2.1
)
—

1.8

—

(0.4
)
—

Net gains reclassified to earnings

Net (gains) / losses reclassified to earnings

Interest expense

—

(0.6
)
—

(0.6
)

—

(0.6
)
—

(0.6
)
Revenues

0.3

—

(1.5
)
—

0.1

—

0.8

—

Purchased power

0.3

—

—

—

—

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
11.0

$
—

$
13.5

$
0.4

$
10.4

$
0.4

$
12.9

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

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
)

$
0.8

$
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

—

39

—

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

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.
3840

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~~nine months ended ~~June~~September 30, 2011 and 2010:

June 30,

June 30,

September 30,

September 30,

2011

2010

2011

2010

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

$
(1.8
)
$
12.2

$
(1.4
)
$
14.7

$
(1.8
)
$
12.3

$
(1.4
)
$
14.7

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

(0.9
)
—

(2.3
)
—

0.8

—

3.3

—

Net gains reclassified to earnings

Net (gains) / losses reclassified to earnings

Interest expense

—

(1.2
)
—

(1.2
)

—

(1.9
)
—

(1.8
)
Revenues

0.5

—

3.7

—

0.8

—

(1.5
)
—

Purchased power

0.7

—

—

—

0.6

—

—

—

Ending accumulated derivative gain / (loss) in AOCI

$
(1.5
)
$
11.0

$
0.0

$
13.5

$
0.4

$
10.4

$
0.4

$
12.9

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

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
)

$
0.8

$
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

—

39

—

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

3941

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~~September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at ~~June~~September 30, 2011
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

$
0.3

$
(0.3
)
Other prepayments and current assets

$
—

Forward Power Contracts in a Liability Position

(1.1
)
0.2

Other current liabilities

(0.9
)

Total short-term cash flow hedges

$
(0.8
)
$
(0.1
)

$
(0.9
)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position

$
1.4

$
(1.0
)
Other deferred assets

$
0.4

Forward Power Contracts in a Liability Position

(0.2
)
0.1

Other deferred credits

(0.1
)
Interest Rate Hedges in a Liability Position

(28.5
)
—

Other deferred credits

(28.5
)

Total long-term cash flow hedges

$
(27.3
)
$
(0.9
)

$
(28.2
)

Total cash flow hedges

$
(28.1
)
$
(1.0
)

$
(29.1
)

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

Fair Values of Derivative Instruments Designated as Hedging Instruments
at December 31, 2010
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 a Liability Position

$
(2.8
)
$
1.0

Other current liabilities

$
(1.8
)

$
(2.8
)
$
1.0

Other current liabilities

$
(1.8
)
Interest Rate Hedges in a Liability Position

(6.6
)
—

Other current liabilities

(6.6
)

(6.6
)
—

Other current liabilities

(6.6
)

Total short-term cash flow hedges

$
(9.4
)
$
1.0

$
(8.4
)

$
(9.4
)
$
1.0

$
(8.4
)

Long-term Derivative Positions

Forward Power Contracts in an Asset Position

$
0.2

$
(0.2
)
Other deferred assets

$
—

$
0.2

$
(0.2
)
Other deferred assets

$
—

Forward Power Contracts in a Liability Position

(0.2
)
0.1

Other deferred credits

(0.1
)

(0.2
)
0.1

Other deferred credits

(0.1
)
Interest Rate Hedges in an Asset Position

20.7

—

Other deferred credits

20.7

20.7

—

Other deferred assets

20.7

Total long-term cash flow hedges

$
20.7

$
(0.1
)

$
20.6

$
20.7

$
(0.1
)

$
20.6

Total cash flow hedges

$
11.3

$
0.9

$
12.2

$
11.3

$
0.9

$
12.2

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

4042

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~~September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at ~~June~~September 30, 2011
DP&L

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

$
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
)
Forward Power Contracts in an Asset Position

$
0.3

$
(0.3
)
Other prepayments and current assets

$
—

Forward Power Contracts in a Liability Position

(1.1
)
0.2

Other current liabilities

(0.9
)

Total short-term cash flow hedges

$
(1.9
)
$
0.7

$
(1.2
)

$
(0.8
)
$
(0.1
)

$
(0.9
)

Long-term derivative positions

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
)
Forward Power Contracts in an Asset Position

$
1.4

$
(1.0
)
Other deferred assets

$
0.4

Forward Power Contracts in a Liability Position

(0.1
)
0.1

Other deferred credits

—

Total long-term cash flow hedges

$
(0.4
)
$
—

$
(0.4
)

$
1.3

$
(0.9
)

$
0.4

Total cash flow hedges

$
(2.3
)
$
0.7

$
(1.6
)

$
0.5

$
(1.0
)

$
(0.5
)

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

4143

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 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~~nine months ended ~~June~~September 30, 2011 and 2010.

For the three months ended ~~June~~September 30, 2011

$ 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
)

$
(27.9
)
$
(1.6
)
$
(0.1
)
$
(0.3
)
$
(29.9
)
Realized gain / (loss)

1.4

0.6

0.2

(1.3
)
0.9

4.3

0.5

—

1.2

6.0

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
(1.4
)
$
(10.7
)

$
(23.6
)
$
(1.1
)
$
(0.1
)
$
0.9

$
(23.9
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(5.0
)
$
—

$
—

$
—

$
(5.0
)

$
(13.8
)
$
—

$
—

$
—

$
(13.8
)
Regulatory (asset) / liability

(2.3
)
(0.9
)
—

—

(3.2
)

(4.0
)
(0.6
)
—

—

(4.6
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
(3.1
)
$
(3.1
)

$
—

$
—

$
—

$
(1.6
)
$
(1.6
)
Purchased power

—

—

0.3

1.7

2.0

—

—

(0.1
)
2.5

2.4

Fuel

(1.5
)
—

—

—

(1.5
)

(5.8
)
(0.5
)
—

—

(6.3
)
O&M

—

0.1

—

—

0.1

—

—

—

—

—

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
(1.4
)
$
(10.7
)

$
(23.6
)
$
(1.1
)
$
(0.1
)
$
0.9

$
(23.9
)
For the three months ended ~~June~~September 30, 2010

$ 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

$
(3.8
)
$
1.3

$
(0.1
)
$
0.5

$
(2.1
)
Realized gain / (loss)

0.7

(0.5
)
(0.3
)
(0.2
)
—

(0.3
)

0.6

(0.4
)
(0.4
)
—

(0.2
)
Total

$
14.8

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

$
13.5

$
(3.2
)
$
0.9

$
(0.5
)
$
0.5

$
(2.3
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
7.8

$
—

$
—

$
—

$
—

$
7.8

$
(1.6
)
$
—

$
—

$
—

$
(1.6
)
Regulatory (asset) / liability

4.1

(0.3
)
—

—

—

3.8

(1.0
)
0.7

—

—

(0.3
)

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
(1.1
)
$
—

$
(1.1
)

Purchased power

—

—

(0.1
)
—

—

(0.1
)

$
—

$
—

$
(0.5
)
$
0.5

$
—

Fuel

2.9

(0.6
)
—

—

1.0

3.3

(0.6
)
0.2

—

—

(0.4
)
O&M

—

(0.2
)
—

—

—

(0.2
)

—

—

—

—

—

Total

$
14.8

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

$
13.5

$
(3.2
)
$
0.9

$
(0.5
)
$
0.5

$
(2.3
)

4244

Table of Contents

For the ~~six~~nine months ended ~~June~~September 30, 2011

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
(13.8
)
$
1.6

$
(0.1
)
$
0.5

$
(11.8
)

$
(41.6
)
$
—

$
(0.1
)
$
0.6

$
(41.1
)
Realized gain / (loss)

3.8

0.9

(0.7
)
(2.1
)
1.9

8.1

1.5

(0.6
)
(0.8
)
8.2

Total

$
(10.0
)
$
2.5

$
(0.8
)
$
(1.6
)
$
(9.9
)

$
(33.5
)
$
1.5

$
(0.7
)
$
(0.2
)
$
(32.9
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(7.4
)
$
—

$
—

$
—

$
(7.4
)

$
(21.2
)
$
—

$
—

$
—

$
(21.2
)
Regulatory (asset) / liability

(2.0
)
0.6

—

—

(1.4
)

(5.9
)
0.1

—

—

(5.8
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
(4.7
)
$
(4.7
)

$
—

$
—

$
—

$
(6.3
)
$
(6.3
)
Purchased power

—

—

(0.8
)
3.1

2.3

—

—

(0.7
)
6.1

5.4

Fuel

(0.6
)
1.8

—

—

1.2

(6.4
)
1.3

—

—

(5.1
)
O&M

—

0.1

—

—

0.1

—

0.1

—

—

0.1

Total

$
(10.0
)
$
2.5

$
(0.8
)
$
(1.6
)
$
(9.9
)

$
(33.5
)
$
1.5

$
(0.7
)
$
(0.2
)
$
(32.9
)
For the ~~six~~nine months ended ~~June~~September 30, 2010

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
2.7

$
0.2

$
(0.3
)
$
0.2

$
—

$
2.8

$
(1.0
)
$
1.5

$
(0.4
)
$
0.7

$
0.8

Realized gain / (loss)

1.1

(1.1
)
(1.0
)
(0.1
)
—

(1.1
)

1.6

(1.5
)
(1.4
)
(0.1
)
(1.4
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

$
0.6

$
—

$
(1.8
)
$
0.6

$
(0.6
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
1.8

$
—

$
—

$
—

$
—

$
1.8

$
0.2

$
—

$
—

$
—

$
0.2

Regulatory (asset) / liability

0.4

—

—

—

—

0.4

(0.6
)
0.6

—

—

—

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
0.1

$
—

$
0.1

$
—

$
—

$
—

$
(0.1
)
$
(0.1
)
Purchased power

—

—

(1.3
)
—

—

(1.3
)

—

—

(1.8
)
0.7

(1.1
)
Fuel

1.6

(0.9
)
—

—

—

0.7

1.0

(0.5
)
—

—

0.5

O&M

—

—

—

—

—

—

—

(0.1
)
—

—

(0.1
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

$
0.6

$
—

$
(1.8
)
$
0.6

$
(0.6
)

4345

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~~nine months ended ~~June~~September 30, 2011 and 2010.

For the three months ended ~~June~~September 30, 2011

$ 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

$
0.3

$
(11.2
)

$
(27.9
)
$
(1.6
)
$
(0.1
)
$
0.3

$
(29.3
)
Realized gain / (loss)

1.4

0.6

0.2

(0.3
)
1.9

4.3

0.5

—

(0.3
)
4.5

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
—

$
(9.3
)

$
(23.6
)
$
(1.1
)
$
(0.1
)
$
—

$
(24.8
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(5.0
)
$
—

$
—

$
—

$
(5.0
)

$
(13.8
)
$
—

$
—

$
—

$
(13.8
)
Regulatory (asset) / liability

(2.3
)
(0.9
)
—

—

(3.2
)

(4.0
)
(0.6
)
—

—

(4.6
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
—

$
—

$
—

$
—

$
—

$
(0.1
)
$
(0.1
)
Purchased power

—

—

0.3

—

0.3

—

—

(0.1
)
0.1

—

Fuel

(1.5
)
—

—

—

(1.5
)

(5.8
)
(0.5
)
—

—

(6.3
)
O&M

—

0.1

—

—

0.1

—

—

—

—

—

Total

$
(8.8
)
$
(0.8
)
$
0.3

$
—

$
(9.3
)

$
(23.6
)
$
(1.1
)
$
(0.1
)
$
—

$
(24.8
)
For the three months ended ~~June~~September 30, 2010

$ 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

$
(3.8
)
$
1.3

$
(0.1
)
$
0.5

$
(2.1
)
Realized gain / (loss)

0.7

(0.5
)
(0.3
)
(0.2
)
—

(0.3
)

0.6

(0.4
)
(0.4
)
—

(0.2
)
Total

$
14.8

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

$
13.5

$
(3.2
)
$
0.9

$
(0.5
)
$
0.5

$
(2.3
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
7.8

$
—

$
—

$
—

$
—

$
7.8

$
(1.6
)
$
—

$
—

$
—

$
(1.6
)
Regulatory (asset) / liability

4.1

(0.3
)
—

—

—

3.8

(1.0
)
0.7

—

—

(0.3
)

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
(1.1
)
$
—

$
(1.1
)
Purchased power

—

—

(0.1
)
—

—

(0.1
)

$
—

$
—

$
(0.5
)
$
0.5

$
—

Fuel

2.9

(0.6
)
—

—

1.0

3.3

(0.6
)
0.2

—

—

(0.4
)
O&M

—

(0.2
)
—

—

—

(0.2
)

—

—

—

—

—

Total

$
14.8

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

$
13.5

$
(3.2
)
$
0.9

$
(0.5
)
$
0.5

$
(2.3
)

4446

Table of Contents

For the ~~six~~nine months ended ~~June~~September 30, 2011

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
(13.8
)
$
1.6

$
(0.1
)
$
0.1

$
(12.2
)

$
(41.6
)
$
—

$
(0.1
)
$
—

$
(41.7
)
Realized gain / (loss)

3.8

0.9

(0.7
)
(0.5
)
3.5

8.1

1.5

(0.6
)
(0.8
)
8.2

Total

$
(10.0
)
$
2.5

$
(0.8
)
$
(0.4
)
$
(8.7
)

$
(33.5
)
$
1.5

$
(0.7
)
$
(0.8
)
$
(33.5
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
(7.4
)
$
—

$
—

$
—

$
(7.4
)

$
(21.2
)
$
—

$
—

$
—

$
(21.2
)
Regulatory (asset) / liability

(2.0
)
0.6

—

—

(1.4
)

(5.9
)
0.1

—

—

(5.8
)

Recorded in Income Statement: gain / (loss)

Retail revenue

$
—

$
—

$
—

$
—

$
—

$
—

$
—

$
—

$
(0.2
)
$
(0.2
)
Purchased power

—

—

(0.8
)
(0.4
)
(1.2
)

—

—

(0.7
)
(0.6
)
(1.3
)
Fuel

(0.6
)
1.8

—

—

1.2

(6.4
)
1.3

—

—

(5.1
)
O&M

—

0.1

—

—

0.1

—

0.1

—

—

0.1

Total

$
(10.0
)
$
2.5

$
(0.8
)
$
(0.4
)
$
(8.7
)

$
(33.5
)
$
1.5

$
(0.7
)
$
(0.8
)
$
(33.5
)
For the ~~six~~nine months ended ~~June~~September 30, 2010

$ in millions

NYMEX
Coal

Heating
Oil

FTRs

Power

Natural
Gas

Total

NYMEX
Coal

Heating
Oil

FTRs

Power

Total

Change in unrealized gain / (loss)

$
2.7

$
0.2

$
(0.3
)
$
0.2

$
—

$
2.8

$
(1.0
)
$
1.5

$
(0.4
)
$
0.7

$
0.8

Realized gain / (loss)

1.1

(1.1
)
(1.0
)
(0.1
)
—

(1.1
)

1.6

(1.5
)
(1.4
)
(0.1
)
(1.4
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

$
0.6

$
—

$
(1.8
)
$
0.6

$
(0.6
)
Recorded on Balance Sheet:

Partner’s share of gain / (loss)

$
1.8

$
—

$
—

$
—

$
—

$
1.8

$
0.2

$
—

$
—

$
—

$
0.2

Regulatory (asset) / liability

0.4

—

—

—

—

0.4

(0.6
)
0.6

—

—

—

Recorded in Income Statement: gain / (loss)

Wholesale revenue

$
—

$
—

$
—

$
0.1

$
—

$
0.1

$
—

$
—

$
—

$
(0.1
)
$
(0.1
)
Purchased power

—

—

(1.3
)
—

—

(1.3
)

—

—

(1.8
)
0.7

(1.1
)
Fuel

1.6

(0.9
)
—

—

—

0.7

1.0

(0.5
)
—

—

0.5

O&M

—

—

—

—

—

—

—

(0.1
)
—

—

(0.1
)
Total

$
3.8

$
(0.9
)
$
(1.3
)
$
0.1

$
—

$
1.7

$
0.6

$
—

$
(1.8
)
$
0.6

$
(0.6
)

~~The following tables show the fair value and balance sheet classification of~~ ~~DPL’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

6.1

(0.3
)
Other prepayments and current assets

5.8

Forward Power Contracts in a Liability position

(4.5
)
1.3

Other current liabilities

(3.2
)
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

$
17.0

$
(8.4
)

$
8.6

Long-term Derivative Positions

Forward Power Contracts in an Asset position

$
6.2

$
(0.1
)
Other deferred assets

$
6.1

Forward Power Contracts in a Liability position

(2.2
)
1.1

Other deferred credits

(1.1
)
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

$
15.7

$
(6.0
)

$
9.7

Total MTM Position

$
32.7

$
(14.4
)

$
18.3

~~(1)Includes credit valuation adjustment.~~
~~(2)Includes counterparty and collateral netting.~~
4547

Table of Contents

The following tables show the fair value and balance sheet classification of DPL’s derivative instruments not designated as hedging instruments at September 30, 2011.
Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at September 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

$
0.1

$
—

Other prepayments and current assets

$
0.1

Forward Power Contracts in an Asset position

6.4

(0.4
)
Other prepayments and current assets

6.0

Forward Power Contracts in a Liability position

(3.8
)
1.4

Other current liabilities

(2.4
)

NYMEX-Quality Coal Forwards in an Asset position

1.6

(1.0
)
Other prepayments and current assets

0.6

NYMEX-Quality Coal Forwards in a Liability position

(1.8
)
1.8

Other current liabilities

—

Heating Oil Futures in an Asset position

1.7

(1.7
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

$
4.2

$
0.1

$
4.3

Long-term Derivative Positions

Forward Power Contracts in an Asset position

$
4.7

$
(0.3
)
Other deferred assets

$
4.4

Forward Power Contracts in a Liability position

(1.5
)
0.9

Other deferred credits

(0.6
)

NYMEX-Quality Coal Forwards in an Asset position

0.7

(0.2
)
Other deferred assets

0.5

NYMEX-Quality Coal Forwards in a Liability position

(4.5
)
4.5

Other deferred credits

—

Total long-term derivative MTM positions

$
(0.6
)
$
4.9

$
4.3

Total MTM Position

$
3.6

$
5.0

$
8.6

(1) Includes credit valuation adjustment.
(2) Includes counterparty and collateral netting.
The following tables show the fair value and balance sheet classification of DP&L’s derivative instruments not designated as hedging instruments at ~~June~~September 30, 2011.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at ~~June~~September 30, 2011

$ 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

0.4

(0.3
)
Other prepayments and current assets

0.1

0.7

(0.6
)
Other prepayments and current assets

0.1

Forward Power Contracts in a Liability position

(0.5
)
0.3

Other current liabilities

(0.2
)

(0.7
)
0.6

Other current liabilities

(0.1
)

NYMEX-Quality Coal Forwards in an Asset position

12.6

(6.8
)
Other prepayments and current assets

5.8

1.6

(0.9
)
Other prepayments and current assets

0.7

NYMEX-Quality Coal Forwards in a Liability position

(1.8
)
1.8

Other current liabilities

—

Heating Oil Futures in an Asset position

2.6

(2.6
)
Other prepayments and current assets

—

1.7

(1.7
)
Other prepayments and current assets

—

Total short-term derivative MTM positions

$
15.3

$
(9.4
)

$
5.9

$
1.6

$
(0.8
)

$
0.8

Long-term Derivative Positions

Forward Power Contracts in an Asset position

$
0.4

$
(0.1
)
Other deferred assets

$
0.3

$
0.8

$
(0.5
)
Other deferred assets

$
0.3

Forward Power Contracts in a Liability position

(0.3
)
0.1

Other deferred credits

(0.2
)

(0.9
)
0.5

Other deferred credits

(0.4
)

NYMEX-Quality Coal Forwards in an Asset position

11.5

(6.8
)
Other deferred assets

4.7

0.7

(0.3
)
Other deferred assets

0.4

NYMEX-Quality Coal Forwards in a Liability position

(0.5
)
0.5

Other deferred credits

—

(4.5
)
4.5

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

$
(3.9
)
$
4.2

$
0.3

Total MTM Position

$
27.1

$
(16.4
)

$
10.7

$
(2.3
)
$
3.4

$
1.1

(1) Includes credit valuation adjustment.
(2) Includes counterparty and collateral netting.
48

Table of Contents

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.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, 2010

$ in millions

Fair Value(1)

Netting(2)

Balance Sheet Location

Fair Value on
Balance Sheet

Short-term Derivative Positions

FTRs in an Asset position

$
0.3

$
—

Other prepayments and current assets

$
0.3

Forward Power Contracts in a Liability position

(0.1
)
—

Other current liabilities

(0.1
)
NYMEX-Quality Coal Forwards in an Asset position

14.0

(7.4
)
Other prepayments and current assets

6.6

Heating Oil Futures in an Asset position

0.5

(0.5
)
Other current liabllities

—

Total short-term derivative MTM positions

$
14.7

$
(7.9
)

$
6.8

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

—

Total long-term derivative MTM positions

$
24.6

$
(15.6
)

$
9.0

Total MTM Position

$
39.3

$
(23.5
)

$
15.8

(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 Proposed Merger with AES that could trigger such provisions. See Note 16 of Notes to Condensed Consolidated Financial Statements.

The aggregate fair value of DPL’s derivative instruments that are in a MTM loss position at ~~June~~September 30, 2011 is ~~$9.9~~$13.1 million. This amount is offset by ~~$2.9~~$6.9 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~~$2.1 million. If our debt were to fall below investment grade, we would have to post collateral for the remaining ~~$5.9~~$4.1 million.
46

~~Table of Contents~~

The aggregate fair value of DP&L’s derivative instruments that are in a MTM loss position at ~~June~~September 30, 2011 is ~~$4.1~~$8.5 million. This amount is offset by ~~$0.9~~$5.2 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~~$2.1 million. If DP&L debt were to fall below investment grade, DP&L would have to post collateral for the remaining ~~$2.1~~$1.2 million.

10.Share-Based Compensation

Share-based compensation expense was $1.3 million ($~~0.9~~0.8 million net of tax) and ~~$1.3~~$1.2 million ($~~0.9~~0.8 million net of tax) for the three months ended ~~June~~September 30, 2011 and 2010, respectively, and ~~$2.7~~$4.0 million ($~~1.8~~2.6 million net of tax) and ~~$2.6~~$3.8 million ($~~1.7~~2.5 million net of tax) for the ~~six~~nine months ended ~~June~~September 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

—

—

4749

Table of Contents

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

Options

RSUs

Performance Shares

Options

RSUs

Performance Shares

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

Outstanding at beginning of year

351,500

417,500

—

3,311

278,334

237,704

Outstanding at beginning of period

500

351,500

—

3,311

296,591

307,985

Granted

—

—

—

—

85,093

161,534

—

—

—

—

—

—

Dividends

—

—

—

—

—

—

—

—

—

—

—

—

Exercised

(75,000
)
(66,000
)
—

—

—

(91,253
)

(500
)
—

—

(3,311
)
—

—

Expired

(276,000
)
—

—

—

(66,836
)
—

—

—

—

—

—

—

Forfeited

—

—

—

—

—

—

—

—

—

—

—

—

Outstanding at period end

500

351,500

—

3,311

296,591

307,985

—

351,500

—

—

296,591

307,985

Exercisable at period end

500

351,500

—

—

—

—

—

351,500

—

—

—

—

Management Performance

Management Performance

Restricted Shares

Shares

Restricted Shares

Shares

2011

2010

2011

2010

2011

2010

2011

2010

Outstanding at beginning of year

219,391

218,197

104,124

84,241

Outstanding at beginning of period

284,237

249,101

111,298

110,706

Granted

67,346

34,176

49,510

37,480

—

2,617

—

—

Dividends

—

—

—

—

—

—

—

—

Exercised

(2,500
)
(3,000
)
(7,911
)
—

(25,585
)
(1,800
)
—

—

Expired

—

—

(31,081
)
—

—

—

—

—

Forfeited

—

(272
)
(3,344
)
(11,015
)

—

(7,635
)
(2,340
)
(1,494
)
Outstanding at period end

284,237

249,101

111,298

110,706

258,652

242,283

108,958

109,212

Exercisable at period end

—

—

—

—

—

—

—

—

Director RSUs

Director RSUs

2011

2010

2011

2010

Outstanding at beginning of year

16,320

20,712

Outstanding at beginning of period

—

15,944

Granted

—

15,752

14,392

—

Dividends accrued

1,362

1,154

634

655

Exercised and issued

(2,066
)
(2,618
)

—

—

Exercised and deferred

(15,616
)
(19,056
)

(634
)
(471
)
Forfeited

—

—

—

—

Outstanding at period end

—

15,944

14,392

16,128

Exercisable at period end

—

—

—

—

50

Table of Contents
Summarized share-based compensation activity for the nine months ended September 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

(75,500
)
(66,000
)
—

(3,311
)
—

(91,253
)
Expired

(276,000
)
—

—

—

(66,836
)
—

Forfeited

—

—

—

—

—

—

Outstanding at period end

—

351,500

—

—

296,591

307,985

Exercisable at period end

—

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

42,796

49,510

37,480

Dividends

—

—

—

—

Exercised

(28,085
)
(10,803
)
(7,911
)
—

Expired

—

—

(31,081
)
—

Forfeited

—

(7,907
)
(5,684
)
(12,509
)
Outstanding at period end

258,652

242,283

108,958

109,212

Exercisable at period end

—

—

—

—

Director RSUs

2011

2010

Outstanding at beginning of year

16,320

20,712

Granted

14,392

15,752

Dividends accrued

1,996

1,809

Exercised and issued

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

(16,250
)
(19,527
)
Forfeited

—

—

Outstanding at period end

14,392

16,128

Exercisable at period end

—

—

As a result of the Proposed Merger, all outstanding share-based awards are subject to accelerated vesting either in their entirety or on a pro rata basis. Share-based compensation expense is expected to increase upon merger close to reflect this accelerated vesting. See Note 16 of Notes to Condensed Consolidated Financial Statements.

11. Common Shareholders’ Equity

DPL has 250,000,000 authorized common shares, of which ~~117,712,910~~117,724,111 are outstanding at ~~June~~September 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 December 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~~nine months ended ~~June~~September 30, 2011. At ~~June~~September 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.

On October 28, 2009, the DPL Board of Directors approved a Stock Repurchase Program under which DPL may use proceeds from the exercise of DPL warrants 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 is scheduled to run through June 30, 2012, which is three months after 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.
51

Table of Contents
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. In June 2011, 0.7 million warrants were exercised with proceeds of $14.7 million. Since the Stock Repurchase Program has been suspended, the proceeds from the June 2011 exercise of warrants and proceeds received from any future exercise of warrants will not be used to repurchase stock.
48

~~Table of Contents~~

Pursuant to the warrant agreement, DPL has authorized common shares sufficient to provide for the exercise in full of all outstanding warrants. At ~~June~~September 30, 2011, DPL had 1.0 million outstanding warrants which are exercisable in the future.

Rights Agreement
DPL has a Rights Agreement, dated as of September 25, 2001, 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 the common shares and become exercisable at the exercise price of $130 per right in the event of certain attempted business combinations.

The Rights Agreement was amended as of April 19, 2011, to provide that neither the execution of the Merger Agreement nor the consummation of the transactions contemplated by the Merger Agreement will trigger the provisions of the Rights Agreement. As amended, DPL plans to keep the Rights Agreement in place until just prior to the effective time of the Proposed Merger.

12. EPS

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

The common-equivalent shares excluded from the calculation of diluted EPS, because they were anti-dilutive, were not material for the three and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010. These shares may be dilutive in the future.

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

Three Months Ended June 30,

2011

2010

$ and shares in millions except

Per

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

$
31.7

114.2

$
0.28

$
61.4

115.7

$
0.53

Effect of Dilutive Securities:

Warrants

0.5

0.4

Stock options, performance and restricted shares

0.2

0.1

Diluted EPS

$
31.7

114.9

$
0.28

$
61.4

116.2

$
0.53

Six Months Ended June 30,

Three Months Ended September 30,

2011

2010

2011

2010

$ 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

$
75.2

114.1

$
0.66

$
132.4

115.6

$
1.15

$
67.1

115.0

$
0.58

$
86.4

115.8

$
0.75

Effect of Dilutive Securities:

Warrants

0.4

0.4

0.3

0.3

Stock options, performance and restricted shares

0.2

0.2

0.2

0.2

Diluted EPS

$
75.2

114.7

$
0.66

$
132.4

116.2

$
1.14

$
67.1

115.5

$
0.58

$
86.4

116.3

$
0.74

4952

Table of Contents

Nine Months Ended September 30,

2011

2010

$ and shares in millions except

Per

Per

per share amounts

Income

Shares

Share

Income

Shares

Share

Basic EPS

$
142.3

114.4

$
1.24

$
218.8

115.7

$
1.89

Effect of Dilutive Securities:

Warrants

0.4

0.3

Stock options, performance and restricted shares

0.2

0.2

Diluted EPS

$
142.3

115.0

$
1.24

$
218.8

116.2

$
1.88

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~~nine months ended ~~June~~September 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 subsidiaries, DPLE and DPLER and its indirect 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~~ratings 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~~September 30, 2011, DPL had ~~$90.2~~$86.7 million of guarantees to third parties for future financial or performance assurance under such agreements including ~~$73.2~~$69.7 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 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~~$0.5 million and ~~$1.0~~$1.7 million at ~~June~~September 30, 2011 and December 31, 2010, respectively.

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.
53

Table of Contents

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~~September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or ~~$61.4~~$61.0 million, of a ~~$1,252.5~~$1,244.5 million debt obligation that matures in 2026. This would only happen if this electric generation company defaulted on its debt payments. As of ~~June~~September 30, 2011, 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~~changes in our debt as discussed ~~further~~ in Note 5 of Notes to Condensed Consolidated Financial Statements.
50

~~Table of Contents~~

Contingencies
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in our Condensed Consolidated Financial Statements, as prescribed by GAAP, are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims, tax examinations and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our Condensed Consolidated Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of ~~June~~September 30, 2011, 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. We have reserves of approximately $2.2 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 effect on our results of operations, financial position or cash flows.

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

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. 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 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.
54

Table of Contents

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

On October 27, 2003, the USEPA published final rules regarding the equipment replacement provision (ERP) of the routine maintenance, repair and replacement (RMRR) exclusion of the CAA. Activities at power plants that fall within the scope of the RMRR exclusion do not trigger new source review (NSR) requirements, including the imposition of stricter emission limits. On December 24, 2003, the United States Court of Appeals for the D.C. Circuit stayed the effective date of the rule pending its decision on the merits of the lawsuits filed by numerous states and environmental organizations challenging the final rules. On June 6, 2005, the USEPA issued its final response on the reconsideration of the ERP exclusion. The USEPA clarified its position, but did not change any aspect of the 2003 final rules. This decision was appealed and the D.C. Circuit vacated the final rules on March 17, 2006. The scope of the RMRR exclusion remains uncertain due to this action by the D.C. Circuit, as well as multiple litigations not directly involving us where courts are defining the scope of the exception with respect to the specific facts and circumstances of the particular power plants and activities before the courts. While we believe that we have not engaged in any activities with respect to our existing power plants that would trigger the NSR requirements, if NSR requirements were imposed on any of DP&L’s existing power plants, the results could 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 Air Quality Rule
On December 17, 2003, the USEPA proposed the Interstate Air Quality Rule (IAQR) designed to reduce and permanently cap SO2 and NOx emissions from electric utilities. The proposed IAQR focused on states, including Ohio, whose power plant emissions are believed to be significantly contributing to fine particle and
51

~~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, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision to vacate the USEPA’s CAIR and its associated Federal Implementation Plan and remanded to the USEPA with instructions to issue new regulations that conformed with the procedural and substantive requirements of the CAA. The Court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program established by the March 10, 2005 rules, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. The USEPA and a group representing utilities filed a request on September 24, 2008, for a rehearing before the entire Court. On December 23, 2008, the U.S. Court of Appeals issued an order on reconsideration that permits CAIR to remain in effect until the USEPA issues new regulations that would conform to the CAA requirements and the Court’s July 11, 2008 decision.

~~In the fourth quarter of 2007,~~ ~~DP&L~~ ~~began a program for selling excess emission allowances, including annual 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 to third parties. The Court’s CAIR decision affected the trading market for excess allowances and impacted~~ ~~DP&L’s~~ ~~program for selling additional excess allowances in 2008. In January 2009, we resumed selling excess allowances due to the revival of the emissions trading market.~~ On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) 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~~Cross-State Air Pollution Rule (CSAPR) on July 6, 2011. CSAPR responds to the court ruling remanding the 2005 CAIR. 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~~were distributed in the ~~third~~fourth quarter of ~~2012.~~ 2011.
55

Table of Contents
We are in the process of reviewing the ~~regulation, but~~rule, and are currently unable to predict the ultimate financial effect. We do not ~~expect~~believe the ~~ruling to~~rule will have a ~~significant~~material impact on our operations in ~~2012, but it may impact operation of uncontrolled units in future years.~~2012.

In 2007, the Ohio EPA revised their State Implementation Plan (SIP) to incorporate a CAIR program consistent with the IAQR. The Ohio EPA had received partial approval from the USEPA and had been awaiting full program approval from the USEPA when the U.S. Court of Appeals issued its July 11, 2008 decision. As a result of the December 23, 2008 order, the Ohio EPA proposed revised rules on May 11, 2009, which were finalized on July 15, 2009. On September 25, 2009, the USEPA issued a full SIP approval for the Ohio CAIR program. CSAPR, finalized on July 6, 2011, institutes a federal implementation plan (FIP) in lieu of state SIPs for 2012 and allows for the states to develop SIPs for approval as early as 2013. We do not expect the FIP will have a significant impact on 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 and is expected to finalize this rule during the quarter ending December 31, 2011. Upon publication in the Federal Register following finalization, affected electric generating units (EGUs) will have three years to come into compliance with the new requirements. DP&L is unable to determine the impact on its financial condition or results of operations or the costs that may be incurred to comply with any new requirement; however, a MACT standard could have a material adverse effect on our operations and result in material compliance costs.

52

~~Table of Contents~~
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 iswas originally March 21, 2014. However, the USEPA has announced that the compliance date for existing boilers will be delayed until a judicial review is no longer pending or until the EPA completes its reconsideration of the rule. 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 are not expected to be material to DP&L’s operations.

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 counties and partial counties in which DP&L operates and/or owns generating facilities. On March 4, 2005, DP&L and other Ohio electric utilities and electric generators filed a petition for review in the D.C. Circuit Court of Appeals, challenging the final rule creating these designations. On November 30, 2005, the court ordered the USEPA to decide on all petitions for reconsideration by January 20, 2006. On January 20, 2006, the USEPA denied the petitions for reconsideration. On July 7, 2009, the D.C. Circuit Court of Appeals upheld the USEPA non-attainment designations for the areas impacting DP&L’s generation plants. As of ~~June~~September 30, 2011, DP&L’s Stuart, Killen and Hutchings Stations were located in non-attainment areas for the 24-hour PM 2.5 standard.
56

Table of Contents
There is a possibility~~DP&L~~ ~~anticipates~~ that these areas will be re-designated as ~~attainment~~“attainment” for PM 2.5 ~~during~~within the ~~second half of 2011.~~next few quarters. 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~~On September 2, 2011, the USEPA decided to ~~additional ozone non-attainment areas in 2012, followed by tighter NOx emission standards.~~postpone their revisiting of this standard until 2013. 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 SO2 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~~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 carbon dioxide and other GHGs “regulated air pollutants” under the CAA.

The ~~EPA~~USEPA plans to propose GHG standards for new and modified electric generating units (EGUs) under CAA subsection 111(b) — and 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 rules may
53

~~Table of Contents~~
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 GHG legislation finalized at a future date could have a significant effect on DP&L’s operations and costs, which could adversely affect our net income, cash flows and financial condition. However, due to the uncertainty associated with such legislation, we cannot predict the final outcome or the financial impact that such legislation will have on DP&L.

On September 22, 2009, the USEPA issued a final rule for mandatory reporting of GHGs from large sources that emit 25,000 metric tons per year or more of CO2, including electric generating units. The first report 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 on current operations.
57

Table of Contents

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. The Supreme Court ruled that the Clean Air Act and the authority given to EPA under that Act to regulate GHGs 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 Supreme Court did not rule against the portion of plaintiffs’ original suits that sought relief under 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 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 a 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 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.

In December 2007, the Ohio EPA issued a 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 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 a 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
54

~~Table of Contents~~
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. 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.

58

Table of Contents
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 SO2 and NOx emissions data were under reported. DP&L has petitioned the USEPA to accept an alternative methodology for calculating actual emissions for 2005 and the first quarter of 2006. ~~DP&L~~ ~~has sufficient allowances in its general account to cover~~More than five years have passed since the ~~understatement. Management~~malfunction was reported and management does not believe ~~the ultimate~~that there will be a resolution of this matter ~~will~~that would have a material impact on results of operations, financial condition or cash flows.

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

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

~~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. 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.
55

~~Table of Contents~~

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 Permit that was due to expire on June 30, 2007. In July 2007, we received a draft permit proposing to continue our authority to discharge water from the station into the Ohio River. On February 5, 2008, we received a letter from the Ohio EPA indicating that they intended to impose a compliance schedule as part of the final Permit, that requires us to implement one of two diffuser options for the discharge of water from the station into the Ohio River as identified in the thermal discharge study. Subsequently, representatives from DP&L and the Ohio EPA agreed to allow DP&L to restrict public access to the water discharge area as an alternative to installing one of the diffuser options. Ohio EPA issued a revised draft permit that was received on November 12, 2008.
59

Table of Contents
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. ~~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 permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA. DP&L is unable to predict the timing for issuance of a final ~~permit is uncertain.~~permit.

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 is anticipated that the USEPA will release a proposed rule by mid-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 Matters Related to Land Use and Solid Waste Disposal~~

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 are 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. 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.

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.

5660

Table of Contents

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

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 March 2009, the USEPA, through a formal Information Collection Request, collected information on ash pond facilities across the country, including those at Killen and J.M. Stuart Stations. Subsequently, the USEPA collected similar information for O.H. Hutchings Station.
In October 2009, the USEPA conducted an inspection of the J.M. Stuart Station ash ponds. In March 2010, the USEPA issued a final report from the inspection including recommendations relative to the J.M. Stuart Station ash ponds. In May 2010, DP&L responded to the USEPA final inspection report with our plans to address the recommendations.

Similarly, in August 2010, the USEPA conducted an inspection of the O.H. Hutchings 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 ash ponds. On July 27, 2011, DP&L ~~is reviewing the final report and intends to respond~~responded to the USEPA final inspection report with plans to address the recommendations. DP&Lis 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 ash ponds. DP&L is unable to predict the outcome this inspection will have on its operations.

In addition, as a result of the TVA ash pond spill, there has been increasing advocacy to regulate coal combustion byproducts under the Resource Conservation Recovery Act (RCRA). On June 21, 2010, the USEPA published a proposed rule seeking comments on two options under consideration for the regulation of coal combustion byproducts including regulating the material as a hazardous waste under RCRA Subtitle C or as a solid waste under RCRA Subtitle D. DP&Lsubmitted comments regarding the proposed regulation on November 19, 2010. 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 impact on operations.

Notice of Violation involving Co-Owned Plants
On September 9, 2011, DP&L received a notice of violation from the USEPA with respect to its co-owned J.M. Stuart generating station based on a compliance evaluation inspection conducted by the USEPA and Ohio EPA in 2009. The notice alleges 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 requests that DP&L respond with the actions it has taken or plans to take to remedy the USEPA’s findings and ensure that further violations will not occur. Based on its initial review of the findings, although there can be no assurance, we believe that the notice will not result in any material impact on its results of operations, financial condition or cash flow.
61

Table of Contents
Ohio Regulation

SB 221 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~~ ~~requested the PUCO’s consent that~~ ~~DP&L~~ ~~had met the 2009 requirements for energy efficiency and for demand reduction based on~~ ~~DP&L’s~~ ~~interpretation of how those requirements should be applied. These filings also requested that if the PUCO disagreed with~~ ~~DP&L’s~~ ~~interpretation, the PUCO grant alternative relief and find that~~ ~~DP&L~~ was unable to meet the targets due to reasons beyond its reasonable control, i.e., uncertainty throughout 2009 caused by delays in finalizing the rules and the lack of timely PUCO action on several of ~~DP&L’s~~ ~~special contracts relating to demand response efforts which remain pending before the PUCO.~~ ~~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~~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. 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. On October 18, 2011, the PUCO approved this filing.
In compliance with the PUCO rules implementing SB 221, DP&L and DPLER made compliance filings on April 15, 2010 and again on April 15, 2011 demonstrating how each entity met the renewable and solar benchmarks for 2009 and 2010. The PUCO issued an order on July 27, 2011 finding that DP&L was in compliance with its 2009 renewable energy resource compliance obligation. Further the PUCO issued an order on October 3, 2011 finding that DPLER met its 2009 renewable energy resource compliance obligations. The proceedings initiated to demonstrate 2010 compliance with renewable and solar benchmarks are still pending. On June 1, 2011 DP&L filed an amendment to
57

~~Table of Contents~~
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 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,~~DP&L recently underwent an audit ~~was performed on~~ ~~DP&L’s~~of its fuel and purchased power recovery rider ~~which was conducted by an independent third party in accordance with PUCO standards. As a result~~but there is some uncertainty as to the costs that will be ~~approved for recovery. The audit was completed~~recovered from or returned to customers. On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the ~~second quarter~~majority of the issues raised by the auditor. On October 19, 2011, ~~and~~we had a hearing ~~has been set by~~on this case. Although the Stipulation and Recommendation was uncontested, the PUCO ~~for August 30, 2011. Once~~may approve, disapprove, or modify the ~~PUCO audit approval process is complete,~~stipulation. DP&L ~~may~~expects to 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~~earnings after the ~~case of over recovery.~~final order is received.

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 isbecame 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,~~October 26, 2011, ~~DP&L~~ ~~made a filing seeking~~the PUCO ~~authorization~~approved our Economic Development Rider, as filed, which is designed to ~~defer~~recover costs associated with ~~any current~~this and ~~future~~other economic development ~~arrangements. This filing is pending.~~contracts and programs.
62

Table of Contents

Legal and Other Matters

In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two jointly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share. DP&L obtained replacement coal to meet its needs. The supplier has denied liability, and is currently in federal bankruptcy proceedings 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
58

~~Table of Contents~~
into a significant number of bi-lateral settlement agreements with certain parties to resolve the matter, which by design will be unaffected by the final decision. With respect to unsettled claims, DP&L management has deferred $14.1 million and $15.4 million as of ~~June~~September 30, 2011 and December 31, 2010, respectively, as Other deferred credits representing the amount of unearned income where the earnings process is not complete. ~~The results~~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 ~~this proceeding~~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 to Note 16 of Notes to Condensed Consolidated Financial Statements for additional information surrounding the Proposed Merger and any related legal matters.
63

Table of Contents
Collective Bargaining Agreement
During the three months ended September 30, 2011, we began negotiations with employees covered under our collective bargaining agreement which is set to expire on October 31, 2011. On October 17, 2011, we reached a tentative agreement with these employees on a new three year labor agreement. Though we expect the tentative agreement to be ratified and that our employees will continue to work during the ratification process, it is possible that this tentative agreement will not be ratified, which could result in labor disruptions affecting some or all of our operations. We have contingency plans in place to mitigate the impact that any labor stoppages could have on our customers. A lengthy strike by our employees could have an adverse effect on our operations and financial condition.

15. Business Segments

DPL operates through two segments consisting of the operations of two of its wholly-owned subsidiaries, DP&L (Utility segment) and DPLER (Competitive Retail segment). 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 competitive retail electric service business which sells retail electric energy under contract to residential, commercial and industrial customers who have selected DPLER as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately ~~15,000~~25,000 customers 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 serves approximately 3,000 customers in ~~northern~~Northern Illinois. 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. The electric energy used to meet its Illinois sales obligations was purchased from PJM. The Competitive Retail segment has no transmission or generation assets. The operations of DPLER are not subject to 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.

5964

Table of Contents

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

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Three Months Ended June 30, 2011

Three Months Ended September 30, 2011

Revenues from external customers

$
327.6

$
102.0

$
15.3

$
—

$
444.9

$
376.6

$
118.6

$
16.6

$
—

$
511.8

Intersegment revenues

81.0

—

1.0

(82.0
)
—

90.2

—

1.1

(91.3
)
—

Total revenues

$
408.6

$
102.0

$
16.3

$
(82.0
)
$
444.9

$
466.8

$
118.6

$
17.7

$
(91.3
)
$
511.8

Fuel

89.1

—

3.0

—

92.1

124.0

—

5.0

—

129.0

Purchased power

104.4

89.5

0.7

(81.0
)
113.6

95.6

101.4

1.5

(90.2
)
108.3

Gross margin

$
215.1

$
12.5

$
12.6

$
(1.0
)
$
239.2

$
247.2

$
17.2

$
11.2

$
(1.1
)
$
274.5

Depreciation and amortization

$
33.4

$
—

$
1.7

$
—

$
35.1

$
33.8

$
0.1

$
1.9

$
—

$
35.8

Interest expense

9.7

0.1

7.9

(0.1
)
17.6

9.3

0.1

7.6

(0.2
)
16.8

Income tax expense (benefit)

15.5

3.3

(2.5
)
—

16.3

26.8

4.2

(2.4
)
—

28.6

Net income (loss)

30.8

5.7

(3.7
)
(1.1
)
31.7

63.9

7.8

(6.2
)
1.6

67.1

Cash capital expenditures

48.4

—

—

—

48.4

49.1

—

0.8

—

49.9

Three Months Ended June 30, 2010

Three Months Ended September 30, 2010

Revenues from external customers

$
371.2

$
62.8

$
11.5

$
—

$
445.5

$
411.1

$
84.5

$
21.3

$
—

$
516.9

Intersegment revenues

52.7

—

1.1

(53.8
)
—

75.9

—

1.1

(77.0
)
—

Total revenues

$
423.9

$
62.8

$
12.6

$
(53.8
)
$
445.5

$
487.0

$
84.5

$
22.4

$
(77.0
)
$
516.9

Fuel

88.5

—

2.4

—

90.9

97.4

—

6.9

—

104.3

Purchased power

90.3

52.7

0.6

(52.7
)
90.9

116.4

75.9

2.6

(75.9
)
119.0

Gross margin

$
245.1

$
10.1

$
9.6

$
(1.1
)
$
263.7

$
273.2

$
8.6

$
12.9

$
(1.1
)
$
293.6

Depreciation and amortization

$
33.2

$
0.1

$
2.4

$
—

$
35.7

$
30.4

$
—

$
1.8

$
—

$
32.2

Interest expense

9.1

—

8.4

—

17.5

9.4

—

8.3

(0.1
)
17.6

Income tax expense (benefit)

28.4

3.1

(1.4
)
—

30.1

39.4

1.4

(0.4
)
—

40.4

Net income (loss)

59.4

5.0

(1.4
)
(1.6
)
61.4

83.2

4.7

(4.2
)
2.7

86.4

Cash capital expenditures

34.1

—

1.2

—

35.3

38.8

—

(0.2
)
—

38.6

6065

Table of Contents

$ in millions

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Utility

Competitive
Retail

Other

Adjustments
and
Eliminations

DPL
Consolidated

Six Months Ended June 30, 2011

Nine Months Ended September 30, 2011

Revenues from external customers

$
716.3

$
196.0

$
27.3

$
—

$
939.6

$
1,092.9

$
314.6

$
43.9

$
—

$
1,451.4

Intersegment revenues

156.1

—

2.0

(158.1
)
—

246.3

—

3.1

(249.4
)
—

Total revenues

$
872.4

$
196.0

$
29.3

$
(158.1
)
$
939.6

$
1,339.2

$
314.6

$
47.0

$
(249.4
)
$
1,451.4

Fuel

187.7

—

4.2

—

191.9

311.7

—

9.2

—

320.9

Purchased power

222.2

167.2

1.1

(156.1
)
234.4

317.8

268.6

2.6

(246.3
)
342.7

Gross margin

$
462.5

$
28.8

$
24.0

$
(2.0
)
$
513.3

$
709.7

$
46.0

$
35.2

$
(3.1
)
$
787.8

Depreciation and amortization

$
66.5

$
0.1

$
3.6

$
—

$
70.2

$
100.3

$
0.2

$
5.5

$
—

$
106.0

Interest expense

19.4

0.1

15.1

(0.1
)
34.5

28.7

0.2

22.7

(0.3
)
51.3

Income tax expense (benefit)

42.5

9.9

(11.3
)
—

41.1

69.3

14.1

(13.7
)
—

69.7

Net income (loss)

83.5

11.8

(18.5
)
(1.6
)
75.2

147.4

19.6

(24.7
)
—

142.3

Cash capital expenditures

90.8

—

0.6

—

91.4

139.9

—

1.4

—

141.3

Six Months Ended June 30, 2010

Nine Months Ended September 30, 2010

Revenues from external customers

$
771.9

$
104.6

$
20.2

$
—

$
896.7

$
1,183.0

$
189.1

$
41.5

$
—

$
1,413.6

Intersegment revenues

90.0

—

2.2

(92.2
)
—

165.9

—

3.3

(169.2
)
—

Total revenues

$
861.9

$
104.6

$
22.4

$
(92.2
)
$
896.7

$
1,348.9

$
189.1

$
44.8

$
(169.2
)
$
1,413.6

Fuel

189.1

—

3.7

—

192.8

286.5

—

10.6

—

297.1

Purchased power

162.9

90.0

0.8

(90.0
)
163.7

279.3

165.9

3.4

(165.9
)
282.7

Gross margin

$
509.9

$
14.6

$
17.9

$
(2.2
)
$
540.2

$
783.1

$
23.2

$
30.8

$
(3.3
)
$
833.8

Depreciation and amortization

$
68.0

$
0.1

$
5.0

$
—

$
73.1

$
98.4

$
0.1

$
6.8

$
—

$
105.3

Interest expense

18.5

—

16.9

—

35.4

27.9

—

25.2

(0.1
)
53.0

Income tax expense (benefit)

65.2

4.3

(3.0
)
—

66.5

104.6

5.7

(3.4
)
—

106.9

Net income (loss)

131.5

7.1

(3.4
)
(2.8
)
132.4

214.7

11.8

(7.6
)
(0.1
)
218.8

Cash capital expenditures

73.5

—

1.6

—

75.1

112.3

—

1.4

—

113.7

Total Assets

June 30, 2011

$
3,435.0

$
59.5

$
1,698.2

$
(1,481.1
)
$
3,711.6

September 30, 2011

$
3,419.7

$
62.1

$
1,702.2

$
(1,507.5
)
$
3,676.5

December 31, 2010

$
3,475.4

$
35.7

$
1,828.8

$
(1,526.6
)
$
3,813.3

$
3,475.4

$
35.7

$
1,828.8

$
(1,526.6
)
$
3,813.3

6166

Table of Contents

16. Proposed Merger with The AES Corporation

On April 19, 2011, DPL and The AES Corporation, a Delaware corporation (“AES”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) whereby AES will acquire DPL for $30.00 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of debt. Upon closing, DPL will become a wholly-owned subsidiary of AES.

The transaction has been unanimously approved by each of DPL’s and AES’ board of directors ~~but~~and was approved by DPL’s shareholders on September 23, 2011. Consummation of the transaction is subject to certain conditions, including ~~receipt 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, DPL and AES filed merger applications with the FERC and the PUCO. ~~We expect 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. On October 26, 2011, DP&L reached a stipulation and recommendation with the PUCO staff and other parties in the AES/DP&L joint application for approval of the Proposed Merger. The Stipulation and Recommendation was filed with the PUCO on October 26, 2011 and is pending PUCO approval.
Also on May 18, 2011, DPL 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.

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.

~~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~~issued $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~~on October 3, 2011, 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.

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 of $106 million.

The following lawsuits have been 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, among other things, one or more of the following: to enjoin the defendants from consummating the Proposed Merger until certain conditions are 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 or an injunction specifically preventing DPL from paying a termination fee.

62

~~Table of Contents~~
On April 21, 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, 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~~Proposed Merger of DPL and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach.
67

Table of Contents

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~~the Austren 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~~Proposed Merger of DPL and AES and that AES aided and abetted such breach. On September 29, 2011 the Court entered an order dismissing the Austren Trust action without prejudice pursuant to a stipulation of dismissal filed by the parties.

On April 26, 2011, a lawsuit was filed in the United States District Court for the Southern District of Ohio, Western Division (the “District Court”), 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~~Proposed Merger of DPL and AES 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~~Proposed Merger of DPL and AES and that AES and Dolphin Sub, Inc. aided and abetted such breach. On May 31, 2011, the Court granted the plaintiff’s voluntary motion to dismiss the lawsuit without prejudice.

On April 27, 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 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~~Proposed Merger of DPL and AES and that AES aided and abetted such breach. On September 28, 2011, the Court entered an order dismissing the Strobhar action without prejudice pursuant to a stipulation of dismissal filed by the parties.

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~~Proposed Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.

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 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~~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~~Proposed Merger of DPL and AES and that DPL, AES and Dolphin Sub, Inc. aided and abetted such breach.
68

Table of Contents

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~~Proposed Merger of DPL and AES and that DPL and AES aided and abetted such breach. On June 24, 2011, the plaintiffs ~~voluntarily dismissed~~filed a notice of voluntary dismissal of this action without ~~prejudice this lawsuit.~~
63

~~Table of Contents~~prejudice.

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~~Proposed Merger of DPL and AES and that AES aided and abetted such breach. On September 28, 2011, the Court entered an order dismissing the Hime actions without prejudice pursuant to a stipulation of dismissal filed by the parties.

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~~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~~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~~plaintiffs purport to assert state law claims directly on behalf of ~~Plaintiffs~~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 DPLand 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~~On July 29, 2011, DPL ~~on behalf of themselves and other shareholders of~~, ~~DPL~~DPL’s ~~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. entered into a Memorandum of Understanding (the “MOU”) with the plaintiffs in the consolidated federal action reflecting their agreement in principle to settle the claims asserted in the consolidated federal action, subject to, among other things, the execution of a stipulation of settlement, completion of confirmatory discovery, provision of notice of the settlement to DPL’s shareholders, approval of the settlement by the District Court, and consummation of the Proposed Merger. If approved by the District Court, the settlement will resolve all pending federal court litigation related to the Proposed Merger, including the Kubiak, Holtmann and Nichting actions, and would result in the release by the plaintiffs and the proposed settlement class, which consists of all record and beneficial holders of DPL’s common stock during the period beginning April 19, 2011 through and including the consummation of the Merger (other than the defendants), of all claims that were or could have been brought challenging any aspect of the Merger Agreement, the Proposed Merger and any disclosures made in connection therewith (including the claims asserted in the lawsuits filed in Ohio state court described above, among other claims, but excluding any properly perfected claims for statutory appraisal in connection with the Proposed Merger). The MOU provides, among other things, for DPL to make certain supplemental disclosures concerning the Proposed Merger, which are contained in the definitive proxy statement DPL filed on August 5, 2011.

69

Table of Contents
In addition, the MOU provides that the plaintiffs intend to apply to the District Court for an award of reasonable attorneys’ fees and expenses. DPL reserves all rights to object to any such application for a fee or expense award, but agreed to pay any fee or expense award in an amount ordered by the District Court. Notice of the proposed settlement will be sent to members of the proposed class and to DPL shareholders as of the date of the District Court’s order preliminarily approving the settlement. The ~~complaints may allege,~~District Court will schedule a hearing regarding, 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~~settlement and ~~omissions. The complaints may seek, among other things, class action status,~~any application by plaintiffs’ counsel for an ~~order enjoining the proposed transaction, compensatory damages and~~award of attorneys’ fees and expenses.

There can be no assurance that the Proposed Merger will be consummated, that the parties will ultimately enter into a stipulation of settlement or that the District Court will approve the settlement even if the parties enter into such stipulation. In such event, the proposed settlement as contemplated by the MOU may be terminated. The settlement will not affect the amount of the merger consideration that DPL’s shareholders are entitled to receive in the Proposed Merger. DPL and its board of directors believe that these lawsuits are without merit and are seeking to settle them to eliminate the burden and expense of litigation and to provide additional information to DPL’s shareholders at a time and in a manner that would not have caused any further delay in DPL’s 2011 Annual Meeting of Shareholders or cause any delay in the consummation of the Proposed Merger.
Absent such settlement, DPL is intends to vigorously ~~defending~~defend 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~~Definitive Proxy Statement filed with the SEC on ~~June 22, 2011. We expect~~August 5, 2011, as modified by a correction to ~~file~~the Definitive Proxy Statement filed 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,on August 24, 2011.
64

~~Table of Contents~~

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 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.

Certain statements contained in this report, including this 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. Such forward-looking statements are subject to risks and uncertainties, and investors are cautioned that outcomes and results may vary materially from those projected due to various factors beyond our control, including but not limited to: abnormal or severe weather and catastrophic weather-related damage; unusual maintenance or repair requirements; changes in fuel costs and purchased power, coal, environmental emissions, natural gas, oil and other commodity prices; volatility and changes in markets for electricity and other energy-related commodities; performance of our suppliers and other counterparties; increased competition and deregulation in the electric utility industry; increased competition in the retail generation market; 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 and/or state environmental laws and regulations to which DPL and its subsidiaries are subject; the development and operation of RTOs, including PJM to which DPL’s operating subsidiary (DP&L) has given control of its transmission functions; changes in our purchasing processes, pricing, delays, employee, contractor and supplier performance and availability; significant delays associated with large construction projects; growth in our service territory and changes in demand and demographic patterns; changes in accounting rules and the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; financial market conditions; 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.
70

Table of Contents
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.

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

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

65

~~Table of Contents~~
DESCRIPTION OF BUSINESS

DPL is a regional electric energy and utility company. DPL’s two reporting 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. Refer to Note 15 of Notes to Condensed Consolidated Financial Statements for more information relating to these reportable segments. DP&L does not have any reportable segments.

DP&L is primarily engaged in the generation, transmission and distribution of electricity in West Central Ohio. DPL and DP&L strive to achieve disciplined growth in energy margins while limiting volatility in both cash flows and earnings and to achieve stable, long-term growth through efficient operations and strong customer and regulatory relations. More specifically, DPL’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 energy and fuel prices and utilizing the transmission and distribution assets that transfer electricity at the most efficient cost, and to maintain the highest level of customer service and reliability.

We operate and manage generation assets and are exposed to a number of risks. These risks include, but are not limited to, electricity wholesale price risk, 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 focused on the operating efficiency of these power plants and maintaining their availability.

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

71

Table of Contents
RECENT DEVELOPMENTS

Merger Agreement with The AES Corporation
On April 19, 2011, DPL and The AES Corporation, a Delaware corporation (“AES”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) whereby AES will acquire 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 closing, DPL will become a wholly-owned subsidiary of AES.

The transaction has been unanimously approved by each of DPL’s and AES’ board of directors ~~but~~and was approved by DPL’s shareholders on September 23, 2011. Consummation of the transaction is subject to certain conditions, including ~~receipt 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, DPL and AES filed merger applications with the FERC and the PUCO. ~~We expect 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. On October 26, 2011, DP&L reached a stipulation and recommendation with the PUCO staff and other parties in the AES/DP&L joint application for approval of the Proposed Merger. The Stipulation and Recommendation was filed with the PUCO on October 26, 2011 and is pending PUCO approval.
Also on May 18, 2011, DPL 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.

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.

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.

66

~~Table of Contents~~
~~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~~issued $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~~on October 3, 2011, 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 of additional DPL 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. We do not anticipate that these reduced ratings will have a significant impact on our liquidity; however, we expect that our cost of capital will increase. See Note 5 of Notes to 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 merger transaction fees consisting primarily of banker’s fees, legal fees, and change of control costs of approximately $45 million pre-tax during 2011. Other than these transaction fees and other than as noted above, DPL and DP&L do not expect the Proposed Merger to have a significant impact on their cash requirements and 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.

72

Table of Contents
Additional 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~~Definitive Proxy Statement filed with the SEC on ~~June 22, 2011. We expect~~August 5, 2011, as modified by a correction to ~~file~~the Definitive Proxy Statement filed with the SEC ~~and send to shareholders 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 and the Company’s Annual Meeting of shareholders scheduled to occur September 23,on August 24, 2011.

Purchase of a Retail Electricity Supplier
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~~September 30, 2011. For the year ended December 31, 2010, it sold approximately 648 million kWh of power, generating revenues of approximately $46 million. ~~The~~We believe that the purchase of MC Squared ~~is expected to complement~~complements DPLER’s existing Ohio retail market activity and ~~to provide~~provides a platform for expansion into other attractive markets.

Redemption of DPL Capital Trust II Securities
On February 23, 2011, DPL acquired $122.0 million of outstanding DPL Capital Trust II 8.125% trust preferred securities from a third party. As a result of this transaction, DPL recorded a net loss on the reacquisition of the securities in 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:

67

~~Table of Contents~~
REGULATORY ENVIRONMENT

·      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 interest in legislation at the federal level, actions at the state level as well as litigation relating to GHG emissions.  In 2007, a U.S. Supreme Court decision upheld that the USEPA has the authority to regulate CO2 emissions from motor vehicles under the CAA.  In April 2009, the USEPA issued a proposed endangerment finding under the CAA, which was finalized and published on December 15, 2009. The proposed finding determined that CO2 and other GHGs from motor vehicles threaten the health and welfare of future generations by contributing to climate change. In December 2009, the USEPA finalized this endangerment finding with a regulatory effective date of January 2010. Numerous affected parties have asked the USEPA Administrator to reconsider this decision. This endangerment finding, if not changed, is expected to lead to the regulation of CO2 and other GHGs from electric generating units and other stationary sources of these emissions. Increased pressure for CO2 emissions reduction is also coming from investor organizations and the international community. Environmental advocacy groups are also focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. 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. If legislation or regulations are passed at the federal or state levels that impose mandatory reductions of CO2 and other GHGs on generation facilities, the cost to DPL and DP&L of such reductions could be material.

·      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.
73

Table of Contents
The annual targets for energy efficiency and peak demand reductions also began in 2009 with annual increases. Energy efficiency programs are to save 22.3% by 2025 and peak demand reductions are expected to reach 7.75% by 2018 compared to a baseline energy usage. If any targets are not met, compliance penalties will apply, unless the PUCO makes certain findings that would excuse performance.

SB 221 also contains provisions for determining whether an electric utility has significantly excessive earnings. 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 on our results of operations, financial condition and cash flows.

DP&L faces regulatory uncertainty from its next ESP or MRO filing which is scheduled to be filed in the first quarter of 2012 to be effective January 1, 2013. The filing may result in changes to the current rate structure and riders. We are monitoring other utilities in Ohio and their ESP and MRO filings.

·      NOx and SO2 Emissions — CAIR
The USEPA issued CAIR on March 10, 2005 to regulate certain upwind states with respect to fine particulate matter and ozone. CAIR created interstate trading programs for annual NOx emission allowances and made modifications to an existing trading program for SO2 that were to take effect in 2010. On July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit issued a decision that vacated the USEPA CAIR and its associated Federal Implementation Plan. This decision remanded these issues back to the USEPA. The court’s decision, in part, invalidated the new NOx annual emission allowance trading program and the modifications to the SO2 emission trading program, and created uncertainty regarding future NOx and SO2 emission reduction requirements and their timing. On December 23, 2008, the court reversed part of its decision that vacated CAIR. Thus, CAIR currently remains in effect, but the USEPA remains subject to the court’s order to revise the program. On July 6, 2010, the USEPA proposed the Clean Air Transport Rule (CATR) 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~~Cross-State Air Pollution Rule (CSAPR) on July 6, 2011. CSAPR responds to the court ruling remanding the 2005 CAIR.
68

~~Table of Contents~~
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 is effective January 1, 2012, and allowances ~~will be~~were distributed in ~~3Q 2012.~~the fourth quarter of 2011. We are in the process of reviewing the ~~regulation, but~~rule and are currently unable to predict the ultimate financial effect. We do not ~~expect~~believe the ~~ruling to~~rule will have a ~~significant~~material impact on our operations in ~~2012, however, it may impact operation of uncontrolled units in future years.~~2012.

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, 2011/2012 and 2010/2011 were $28/day, $16/day, $110/day and $174/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, we estimate that a hypothetical increase or decrease of ~~$10~~$10/day in the capacity auction price would result in an annual impact to net income of approximately ~~$5.0~~$5.2 million and ~~$3.7~~$3.8 million for DPL and DP&L, respectively. These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.
74

Table of Contents

·      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 have resulted in increased levels of competition to provide transmission and generation services. This in turn has led to a significant number of DP&L’s customers to switch their retail electric services 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~~September 30, 2011 and 2010 and the ~~six month periods~~nine months ended ~~June~~September 30, 2011 and 2010:

Three Months Ended

Three Months Ended

Three Months Ended

Three Months Ended

June 30, 2011

June 30, 2010

September 30, 2011

September 30, 2010

Electric
Customers

Sales (in Millions
of kWh)

Electric
Customers

Sales (in Millions
of kWh)

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

21,990

1,567

4,396

1,338

Supplied by non-affiliated CRES providers

4,996

164

168

14

19,285

283

426

59

Total supplied in our service territory

17,029

1,584

2,829

1,047

41,275

1,850

4,822

1,397

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

513,123

3,260

514,142

3,350

512,439

3,874

513,332

3,928

(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%~~40% and ~~31%~~34% of DP&L’s total distribution volumes during the three ~~month periods~~months ended ~~June~~September 30, 2011 and 2010, respectively. The reduction to gross margin during the three months ended ~~June~~September 30, 2011 as a result of customers switching to DPLER and other CRES providers was approximately ~~$11.0~~$19.8 million and ~~$17.0~~$28.8 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.

Nine Months Ended

Nine Months Ended

September 30, 2011

September 30, 2010

Electric
Customers

Sales (in Millions
of kWh)

Electric
Customers

Sales (in Millions
of kWh)

Supplied by DPLER

21,990

4,330

4,396

3,091

Supplied by non-affiliated CRES providers

19,285

566

426

75

Total supplied in our service territory

41,275

4,896

4,822

3,166

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

512,439

10,772

513,332

10,894

(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 28% of DP&L’s total distribution volumes during the nine months ended September 30, 2011 and 2010, respectively. The reduction to gross margin during the nine months ended September 30, 2011 as a result of customers switching to DPLER and other CRES providers was approximately $39.4 million and $65.7 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.

6975

Table of Contents

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,~~and third quarters of 2011, we have seen a significant increase in retail competition for our residential retail customers. Approximately 6%12% of DP&L’sannualized residential load switched to CRES providers during ~~the past two months~~those quarters with DPLER acquiring ~~54%~~57% of the switched load. For the calendar year 2011, based on current trends, we project customer ~~shopping~~switching will negatively impact DPL’s gross margin by approximately ~~$40.0 to $45.0~~$55-$60 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, 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~~recently underwent 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~~recovered from or returned to customers. On October 6, 2011, DP&L and all of the ~~fuel audit~~active participants in ~~accordance with PUCO standards. The audit was completed in~~this proceeding reached a Stipulation and Recommendation that resolves the ~~second quarter~~majority of the issues raised by the auditor. On October 19, 2011, ~~and~~we had a hearing ~~has been set by~~on this case. Although the Stipulation and Recommendation was uncontested, the PUCO ~~for August 30, 2011. Once~~may approve, disapprove, or modify the ~~PUCO audit approval process is complete,~~stipulation. DP&L ~~may~~expects to 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~~earnings after the ~~case of over recovery.~~final order is received.

7076

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~~September 30, 2011, Net income for DPL was ~~$31.7~~$67.1 million, or ~~$0.28~~$0.58 per share, compared to Net income of ~~$61.4~~$86.4 million, or ~~$0.53~~$0.74 per share, for the same period in 2010. All EPS amounts are based on a diluted ~~share basis.~~shares outstanding. As discussed more fully below, the key drivers of the results during the three ~~month period~~months ended ~~June~~September 30, 2011 compared to the ~~similar~~same period of the prior year are comprised of the following:

·      a decrease in retail revenue due to pricing associated with competitively supplied customers and a slight decrease in sales volumes due to cooler weather,
·an increase in the price of fuel, combined with an increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal.
·an overall decline in generating plant performance which resulted in an increase in purchased power volume, 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 Universal Service Fund Riders,
·a decrease in purchased power prices, and
·a decrease in the volume of fuel consumed due to decreased generation by our power plants.
For the nine months ended September 30, 2011, Net income for DPL was $142.3 million, or $1.24 per share, compared to Net income of $218.8 million, or $1.88 per share, for the same period in 2010. All EPS amounts are based on diluted shares outstanding. As discussed more fully below, the key drivers of the results during the nine months ended September 30, 2011 compared to the same period of the prior year are comprised of the following:
·a decrease in retail revenue due to pricing associated with competitively supplied customers,
·an increase in the price of fuel, combined with an increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal.

·      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 several 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~~nine months ended ~~June~~September 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 Universal Service Fund Riders 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.

7177

Table of Contents

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

Nine Months Ended

Three Months Ended
June 30,

Six Months Ended
June 30,

September 30,

September 30,

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

Revenues:

Retail

$
348.1

$
342.7

$
731.6

$
697.3

$
410.3

$
402.6

$
1,141.9

$
1,099.9

Wholesale

28.7

39.1

61.1

79.3

40.7

31.2

101.8

110.3

RTO revenues

19.5

20.1

40.9

41.2

22.3

23.4

63.2

64.6

RTO capacity revenues

49.7

40.4

105.0

72.7

37.3

57.0

142.3

129.7

Other revenues

2.9

3.2

5.7

6.2

2.8

2.7

8.5

8.9

Other mark to market losses

(4.0
)
—

(4.7
)
—

Other mark-to-market gains / (losses)

(1.6
)
—

(6.3
)
0.2

Total revenues

$
444.9

$
445.5

$
939.6

$
896.7

$
511.8

$
516.9

$
1,451.4

$
1,413.6

Cost of revenues:

Fuel costs

$
93.3

$
92.4

$
194.8

$
194.7

$
121.8

$
104.8

$
312.7

$
300.5

Gains from sale of coal

(1.2
)
(1.1
)
(2.9
)
(1.3
)

(3.9
)
(1.1
)
(6.8
)
(2.4
)
Gains from sale of emission allowances

—

(0.4
)
—

(0.6
)

—

(0.1
)
—

(0.7
)
Mark-to-market (gains) / losses

11.1

0.7

15.0

(0.3
)
Net fuel

92.1

90.9

191.9

192.8

129.0

104.3

320.9

297.1

Purchased power

39.5

21.3

75.5

35.0

39.7

26.5

120.3

61.2

RTO charges

27.1

26.7

56.4

51.4

34.5

33.3

90.9

84.6

RTO capacity charges

47.0

42.9

102.5

77.3

35.5

59.6

138.0

137.0

Mark-to-market (gains) / losses

(1.4
)
(0.4
)
(6.5
)
(0.1
)
Net purchased power

113.6

90.9

234.4

163.7

108.3

119.0

342.7

282.7

Total cost of revenues

$
205.7

$
181.8

$
426.3

$
356.5

$
237.3

$
223.3

$
663.6

$
579.8

Gross margins (a)

$
239.2

$
263.7

$
513.3

$
540.2

$
274.5

$
293.6

$
787.8

$
833.8

Gross margin as a percentage of revenues

53.8
%
59.2
%
54.6
%
60.2
%

54
%
57
%
54
%
59
%

Operating income

$
65.8

$
109.3

$
166.6

$
235.3

$
112.9

$
144.6

$
279.5

$
379.9

Earnings per share of common stock:

Basic EPS from operations

$
0.28

$
0.53

$
0.66

$
1.15

$
0.58

$
0.75

$
1.24

$
1.89

Diluted EPS from operations

$
0.28

$
0.53

$
0.66

$
1.14

$
0.58

$
0.74

$
1.24

$
1.88

(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.

7278

Table of Contents

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

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

Number of days

2011

2010

2011

2010

2011

2010

2011

2010

Heating degree days (a)

513

365

3,480

3,423

124

52

3,604

3,475

Cooling degree days (a)

319

376

319

376

839

849

1,158

1,225

(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

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

Retail

Rate

$
6.7

$
31.7

$
12.7

$
44.3

Volume

(3.0
)
(0.2
)

(7.9
)
(8.0
)
Other miscellaneous

1.7

2.8

2.9

5.7

Total retail change

$
5.4

$
34.3

$
7.7

$
42.0

Wholesale

Rate

$
3.0

$
3.5

$
5.7

$
9.0

Volume

(13.4
)
(21.7
)

3.8

(17.5
)
Total wholesale change

$
(10.4
)
$
(18.2
)

$
9.5

$
(8.5
)

RTO capacity & other

RTO capacity and other revenues

$
8.7

$
32.0

RTO capacity & other RTO

RTO capacity and other RTO revenues

$
(20.8
)
$
11.2

Other

Unrealized MTM

$
(4.0
)
$
(4.7
)

$
(1.6
)
$
(6.5
)
Other

(0.3
)
(0.5
)

0.1

(0.4
)
Total revenue change

$
(4.3
)
$
(5.2
)
Total other revenue change

$
(1.5
)
$
(6.9
)

Total revenues change

$
(0.6
)
$
42.9

$
(5.1
)
$
37.8

7379

Table of Contents

For the three months ended ~~June~~September 30, 2011, Revenues decreased ~~$0.6~~$5.1 million to ~~$444.9~~$511.8 million from ~~$445.5~~$516.9 million in the same period of the prior year. This decrease was primarily the result of lower retail ~~and wholesale~~ sales volumes and a decrease in RTO capacity and other RTO revenues, partially offset by higher retail and wholesale average rates and ~~an increase in RTO capacity and other RTO revenues.~~higher wholesale sales volume.

·      Retail revenues increased ~~$5.4~~$7.7 million resulting primarily from a 2%3% 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~~is a result of increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume decreased ~~slightly~~2% compared to the prior year period largely due to ~~warmer~~cooler weather. ~~Cooling degree days were 15% less than the prior year.~~ The above resulted in a favorable ~~$6.7~~$12.7 million retail price variance and an unfavorable ~~$3.0~~$7.9 million retail sales volume variance.

·      Wholesale revenues ~~decreased $10.4~~increased $9.5 million primarily as a result of a ~~34%~~16% increase in wholesale sales prices and a 12% increase in wholesale sales volume. This resulted in a favorable $5.7 million wholesale price variance as well as a favorable wholesale sales variance of $3.8 million. Wholesale sales volume increased primarily as a result of energy being available for wholesale sales because of customers that have switched to other third-party CRES suppliers during the three months ended September 30, 2011 compared to the three months ended September 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, decreased $20.8 million compared to the same period in 2010. This decrease in RTO capacity and other revenues was primarily the result of a $19.7 million decrease in revenues realized from the PJM capacity auction, including a slight decrease in transmission, congestion and other revenues.
·Other Unrealized MTM revenues, consisting of retail sales contracts accounted for as derivatives, decreased $1.6 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 decrease in Unrealized MTM on purchased power contracts also accounted for as derivatives.
For the nine months ended September 30, 2011, Revenues increased $37.8 million to $1,451.4 million from $1,413.6 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 retail and wholesale sales volumes.
·Retail revenues increased $42.0 million resulting primarily from a 4% 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 average retail rates was partially offset by the effect of lower rates due to customer switching, which is a result of increased levels of competition to provide transmission and generation services in our service territory. Retail sales volume decreased compared to the prior year period due to cooler weather slightly offset by continued improvement in economic conditions. Cooling degree days were 5% less than the prior year. The above resulted in a favorable $44.3 million retail price variance offset by an unfavorable $8.0 million retail sales volume variance. The increase was also attributable to $3.5 million of other miscellaneous retail revenues which includes revenues associated with the operation of a recently acquired distribution system.
·Wholesale revenues decreased $8.5 million primarily as a result of a 16% decrease in wholesale sales volume, offset partially by ~~an 11%~~a 10% increase in wholesale sales prices. This resulted in an unfavorable ~~$13.4~~$17.5 million wholesale sales volume variance, offset partially ~~offset~~ by a favorable wholesale price variance of ~~$3.0~~$9.0 million. Wholesale sales volume decreased primarily as a result of an increase in outages at our generating plants during the ~~three~~nine months ended ~~June~~September 30, 2011 compared to the ~~three~~nine months ended ~~June~~September 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~~$11.2 million compared to the same period in 2010. This increase in RTO capacity and other revenues was primarily the result of a ~~$9.3~~$12.6 million increase in revenues realized from the PJM capacity auction, partially offset by a slight decrease in transmission, congestion and other revenues.

80

Table of Contents
·      Other Unrealized MTM revenues, consisting of retail sales contracts accounted for as derivatives, decreased ~~$4.0~~$6.5 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.
74

~~Table of Contents~~
·~~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.

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

·      Net fuel costs, which include coal, gas, oil and emission allowance costs, increased ~~$1.2~~$24.7 million, or 1%24%, compared to the same period in 2010, primarily due to the impact of an increase in the price of fuel, as well as an $11.8 million increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal, partially offset by a 3% decrease in the volume of generation.
·Net purchased power decreased $10.7 million, or 9%, compared to the same period in 2010 due to a decrease of $22.9 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 decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Partially offsetting the decrease in net purchased power was an $18.9 million increase associated with higher purchased power volumes partially offset by a $5.7 million decrease 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. These decreases were partially offset by a $1.0 million increase in Unrealized MTM derivative gains associated with purchased power contracts due to increases in the market prices for power.
For the nine months ended September 30, 2011:
·Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $23.8 million, or 8%, compared to the same period in 2010, primarily due to the impact of a ~~17.3%~~12% decrease in the volume of generation, ~~and a 13.3%~~which was offset by an 18% increase in the price of generation byfrom our plants ~~resulting from~~due to an increase in and the timing of unit outages during the ~~three~~nine months ended ~~June~~September 30, 2011 ~~when~~as compared to the same period in ~~2010.~~2010, as well as a $15.3 million increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal.

·      Net purchased power increased ~~$22.7~~$60.0 million, or ~~25%~~21%, compared to the same period in 2010 due to an increase of ~~$4.5~~$7.3 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 $34.5~~an $85.9 million increase associated with higher purchased power volumes partially offset by a ~~$10.1~~$26.8 million decrease 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.
~~For the six months ended June 30, 2011:~~
·~~Net fuel costs, which include coal, gas, oil and emission allowance costs, decreased $0.9~~ These increases were partially offset by a $6.4 million ~~or 0.5%, compared to the same period~~increase in ~~2010, primarily~~Unrealized MTM derivative gains associated with purchased power contracts due to ~~the impact of a 15.8% decrease~~increases in 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.market prices for power.

·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.
7581

Table of Contents

DPL — Operation and Maintenance

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

Generating facilities operating and maintenance expenses

$
8.7

$
16.2

$
(1.4
)
$
14.8

Merger related costs

5.8

12.3

Low-income payment program (1)

3.9

11.5

Maintenance of overhead transmission and distribution lines

2.2

9.5

0.9

10.3

Low-income payment program (1)

3.2

7.7

Merger related costs

5.8

6.6

Competitive retail operations

2.4

5.5

Insurance settlement, net

—

3.4

—

3.4

Group insurance / long-term disability

(4.6
)
(8.8
)
Energy efficiency programs (1)

0.3

(1.6
)

(0.9
)
(2.5
)
Group insurance / long-term disability

(4.4
)
(4.1
)
Other, net

3.5

0.4

1.7

(0.6
)
Total operation and maintenance expense

$
19.3

$
38.1

$
7.8

$
45.9

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

During the three months ended ~~June~~September 30, 2011, Operation and maintenance expense increased ~~$19.3~~$7.8 million, or ~~22%~~9%, compared to the same period in 2010. This variance was primarily the result of:
·increased costs related to the Proposed Merger with AES,
·increased assistance for low-income retail customers which is funded by the USF revenue rate rider,
·increased expenses of $2.3 million related to the maintenance of overhead transmission and distribution lines as a result of storms, partially offset by the timing of routine maintenance of such lines, and
·increased marketing, customer maintenance and labor cost associated with the competitive retail business as a result of increased sales volume and number of customers.
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 nine months ended September 30, 2011, Operation and maintenance expense increased $45.9 million, or 18%, 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 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~~costs 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,~~AES,

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

·      increased ~~cost~~expenses related to the ~~Proposed Merger~~maintenance of overhead transmission and distribution lines of which $9.1 million was a result of storms including a significant ice storm in February 2011,
·increased marketing, customer maintenance and labor costs associated with ~~AES,~~the competitive retail business as a result of increased sales volume and number of customers, and

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

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 going onto long-term disability during the current year as compared to the same period in 2010.

82

Table of Contents
DPL — Depreciation and Amortization
For the three ~~and six~~ months ended ~~June~~September 30, 2011, Depreciation and amortization expense ~~decreased $0.6~~increased $3.6 million, or 2%11%, ~~and $2.9 million, or 4%, respectively,~~ as compared to the three ~~and six~~ months ended ~~June~~September 30, 2010. The increase is primarily the result of a net increase in depreciable property.
For the nine months ended September 30, 2011, Depreciation and amortization expense increased $0.7 million, or 1%, as compared to the nine months ended September 30, 2010. The increase is primarily the result of a net increase in depreciable property partially offset by a decrease ~~primarily reflects the impact of~~due to a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010.
76

~~Table of Contents~~

DPL — General Taxes
For the three months ended ~~June~~September 30, 2011,, General taxes increased ~~$0.3~~$1.2 million, or ~~1.0%~~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~~2010.

For the ~~six~~nine months ended ~~June~~September 30, 2011,, General taxes increased ~~$6.6~~$7.8 million, or ~~10.4%~~8% 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 of $4.5 million from the Ohio gross receipts tax audit.

DPL — Investment Income
Investment income recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2011 did not fluctuate significantly from that recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2010.

DPL — Interest Expense
For the three months ended ~~June~~September 30, 2011,, Interest expense did not fluctuate significantly from that recorded during the same period in 2010. For the ~~six~~nine months ended ~~June~~September 30, 2011, Interest expense decreased ~~$0.9~~$1.7 million, or 3%, as compared to the same period in 2010 primarily due to the early redemption of the DPL Capital Trust II 8.125% capital securities discussed ~~below.~~below partially offset by additional interest expense taken as a result of de-designating a portion of our interest rate hedge contracts. See Note 9 to the Notes to Condensed Consolidated Financial Statements.

DPL — Charge for Early Redemption of Debt
The Charge for early redemption of debt reflects the ~~purchase, in~~ February 2011 purchase 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~~nine months ended ~~June~~September 30, 2011,, Income tax expense decreased ~~$13.8~~$11.8 million, or ~~46.0%~~29%, and ~~$25.4~~$37.2 million, or ~~38.0%~~35%, respectively, as compared to the same periods in 2010 primarily due to decreased pre-tax income.
83

Table of Contents

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. These segments are discussed further ~~below:~~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~~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 competitive retail electric service business which sells retail electric energy under contract to residential, commercial and industrial customers who have selected DPLER as their alternative electric supplier. The Competitive Retail segment sells electricity to approximately ~~15,000~~25,000 customers 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 serves approximately 3,000 customers in ~~northern~~Northern Illinois. 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. The electric energy used to meet its Illinois sales obligation was purchased from PJM. The Competitive Retail segment has no transmission or generation assets. The operations of DPLER are not subject to rate regulation by federal or state regulators.

77

~~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 15 of Notes to Condensed Consolidated Financial Statements for further discussion of DPL’s reportable segments.

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

Three months ended June 30,

Increase (Decrease)

Three months ended September 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

Utility

$
215.1

$
245.1

$
(30.0
)

$
247.2

$
273.2

$
(26.0
)
Competitive Retail

12.5

10.1

2.4

17.2

8.6

8.6

Other

12.6

9.6

3.0

11.2

12.9

(1.7
)
Adjustments and Eliminations

(1.0
)
(1.1
)
0.1

(1.1
)
(1.1
)
—

Total consolidated

$
239.2

$
263.7

$
(24.5
)
Total Consolidated

$
274.5

$
293.6

$
(19.1
)
84

Table of Contents

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

Six months ended June 30,

Increase (Decrease)

Nine months ended September 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

Utility

$
462.5

$
509.9

$
(47.4
)

$
709.7

$
783.1

$
(73.4
)
Competitive Retail

28.8

14.6

14.2

46.0

23.2

22.8

Other

24.0

17.9

6.1

35.2

30.8

4.4

Adjustments and Eliminations

(2.0
)
(2.2
)
0.2

(3.1
)
(3.3
)
0.2

Total consolidated

$
513.3

$
540.2

$
(26.9
)
Total Consolidated

$
787.8

$
833.8

$
(46.0
)

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.

Six months ended June 30,

Increase (Decrease)

Three months ended September 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

Revenues:

Retail

$
199.6

$
104.0

$
95.6

$
119.5

$
84.1

$
35.4

RTO and other

(3.6
)
0.6

(4.2
)

(0.9
)
0.4

(1.3
)

$
196.0

$
104.6

$
91.4

$
118.6

$
84.5

$
34.1

Cost of revenues:

Purchased power

$
167.2

$
90.0

$
77.2

$
101.4

$
75.9

$
25.5

Gross margins (a)

$
28.8

$
14.6

$
14.2

$
17.2

$
8.6

$
8.6

Operation and maintenance expense

6.1

2.8

3.3

4.5

2.0

2.5

Other expenses (income), net

1.0

0.4

0.6

0.7

0.5

0.2

Total expenses, net

$
7.1

$
3.2

$
3.9

$
5.2

$
2.5

$
2.7

Earnings (Loss) from continuing operations before income tax

21.7

11.4

10.3

Earnings (loss) from continuing operations before income tax

12.0

6.1

5.9

Income tax expense (benefit)

9.9

4.3

5.6

4.2

1.4

2.8

Net income (Loss)

$
11.8

$
7.1

$
4.7

Net income (loss)

$
7.8

$
4.7

$
3.1

Gross margin as a percentage of revenues

14.7
%
14.0
%

15
%
10
%

(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.

7985

Table of Contents

Nine months ended September 30,

Increase (Decrease)

$ in millions

2011

2010

2011 vs. 2010

Revenues:

Retail

$
319.1

$
188.1

$
131.0

RTO and other

(4.5
)
1.0

(5.5
)

$
314.6

$
189.1

$
125.5

Cost of revenues:

Purchased power

$
268.6

$
165.9

$
102.7

Gross margins (a)

$
46.0

$
23.2

$
22.8

Operation and maintenance expense

10.6

4.8

5.8

Other expenses (income), net

1.7

0.9

0.8

Total expenses, net

$
12.3

$
5.7

$
6.6

Earnings (loss) from continuing operations before income tax

33.7

17.5

16.2

Income tax expense (benefit)

14.1

5.7

8.4

Net income (loss)

$
19.6

$
11.8

$
7.8

Gross margin as a percentage of revenues

15
%
12
%

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

Competitive Retail Segment — Revenue
For the three months ended ~~June~~September 30, 2011, the segment’s retail revenues increased ~~$43.6~~$35.4 million, or 42%, 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 $13.8 million recorded during the three months ended September 30, 2011. Primarily as a result of the purchase of MC Squared and customer switching in Ohio, the Competitive Retail segment sold approximately 1,871 million kWh of power to 25,309 customers during the three months ended September 30, 2011 compared to 1,384 million kWh sold to 4,826 customers during the same period in 2010.
For the nine months ended September 30, 2011, the segment’s retail revenues increased $131.0 million, or 70%, 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 $12.2 million recorded during the three months ended June 30, 2011. Primarily as a result of the customer switching discussed above, the Competitive Retail segment sold approximately 1,420 million kWh of power to 12,033 customers in Ohio during the three months ended June 30, 2011 compared to 1,033 million kWh sold to 2,661 Ohio 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$30.1 million recorded since this purchase date. Primarily as a result of the purchase of MC Squared and customer switching ~~discussed above,~~in Ohio, the Competitive Retail segment sold approximately ~~2,764~~5,011 million kWh of power to ~~12,033~~25,309 customers ~~in Ohio~~ during the ~~six~~nine months ended ~~June~~September 30, 2011 compared to ~~1,753~~3,166 million kWh sold to ~~2,661 Ohio~~4,826 customers during the same period in 2010.

Competitive Retail Segment — Purchased Power
For the three months ended ~~June~~September 30, 2011, Purchased power for the segment increased ~~$36.8~~$25.5 million, or ~~70%~~34%, as compared to the same period in 2010 primarily due to higher purchased power volumes required to satisfy an increasing customer base as a result of customer switching and the purchase of MC Squared. This increase was partially offset by lower average prices paid for purchased power in the three months ended September 30, 2011 compared to the same period in 2010. 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.

86

Table of Contents
For the ~~six~~nine months ended ~~June~~September 30, 2011, Purchased power for the segment increased ~~$77.2~~$102.7 million, or ~~86%~~62%, as compared to the same period in 2010 primarily due to higher purchased power volumes required to satisfy an increasing customer base as a result of customer switching and the purchase of MC Squared. Also contributing to this increase is higher average prices paid for purchased power for the nine months ended September 30, 2011 compared to the same period in 2010. 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.

Competitive Retail Segment — Operation and Maintenance
For the three months ended ~~June~~September 30, 2011, the segment’s Operation and maintenance expenses which include employee-related expenses, accounting, information technology, payroll, legal and other administration expenses, increased ~~$1.5~~$2.5 million, or ~~94%~~125%, compared to the same period in 2010. The higher operation and maintenance expense in 2011 as compared to 2010 is primarily reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

For the ~~six~~nine months ended ~~June~~September 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~~$5.8 million, or ~~118%~~121%, compared to the same period in 2010. The higher operation and maintenance expense in 2011 as compared to 2010 is primarily reflective of increased marketing and customer maintenance costs associated with the increased sales volume and number of customers.

80

~~Table of Contents~~
Competitive Retail Segment — Income Tax Expense
For the three months ended ~~June~~September 30, 2011, the segment’s income tax expense increased ~~$0.2~~$2.8 million.

For the ~~six~~nine months ended ~~June~~September 30, 2011, the segment’s income tax expense increased ~~$5.6~~$8.4 million compared to the same period in 2010 primarily due to increased pre-tax income. In addition, as a result of the purchase of MC Squared we recorded a $2.0 million charge for state deferred taxes due to the Illinois Unitary Tax rules.

87

Table of Contents
RESULTS OF OPERATIONS — DP&L

Income Statement Highlights — DP&L

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011

2010

2011

2010

2011

2010

2011

2010

Revenues:

Retail

$
243.7

$
281.3

$
534.1

$
595.4

$
292.1

$
319.8

$
826.2

$
915.2

Wholesale

104.7

89.6

210.9

165.9

122.3

97.3

333.2

263.2

RTO revenues

18.1

19.0

38.5

39.2

20.7

21.6

59.2

60.8

RTO capacity revenues

42.1

34.0

88.9

61.4

31.7

48.3

120.6

109.7

Total revenues

$
408.6

$
423.9

$
872.4

$
861.9

$
466.8

$
487.0

$
1,339.2

$
1,348.9

Cost of revenues:

Fuel costs

$
90.2

$
90.0

$
190.6

$
191.0

$
116.8

$
98.4

$
303.5

$
290.4

Gains from sale of coal

(1.1
)
(1.1
)
(2.9
)
(1.3
)

(3.9
)
(1.1
)
(6.8
)
(2.4
)
Gains from sale of emission allowances

—

(0.4
)
—

(0.6
)

—

(0.1
)
—

(0.7
)
Mark-to-market (gains) / losses

11.1

0.2

15.0

(0.8
)
Net fuel

89.1

88.5

187.7

189.1

124.0

97.4

311.7

286.5

Purchased power

32.4

21.4

66.6

35.0

28.5

26.3

95.2

61.0

RTO charges

27.6

26.1

56.7

50.6

33.5

30.8

90.2

81.4

RTO capacity charges

44.4

42.8

98.9

77.3

33.6

59.7

132.5

137.0

Mark-to-market (gains) / losses

—

(0.4
)
(0.1
)
(0.1
)
Total purchased power

104.4

90.3

222.2

162.9

95.6

116.4

317.8

279.3

Total cost of revenues

$
193.5

$
178.8

$
409.9

$
352.0

$
219.6

$
213.8

$
629.5

$
565.8

Gross margins (a)

$
215.1

$
245.1

$
462.5

$
509.9

$
247.2

$
273.2

$
709.7

$
783.1

Gross margin as a percentage of revenues

52.6
%
57.8
%
53.0
%
59.2
%

53
%
56
%
53
%
58
%

Operating Income

$
55.8

$
97.0

$
145.1

$
215.4

$
100.0

$
131.9

$
245.1

$
347.3

(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: wholesale market prices, DP&L’s retail demand, retail demand elsewhere throughout the entire wholesale market area, DP&L and non-DP&L plants’ availability to sell into the wholesale market and weather conditions across the multi-state region. DP&L’s plan is to make wholesale sales when market prices allow for the economic operation of its generation facilities that are not being utilized to meet its retail demand.

8188

Table of Contents

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

Three Months Ended

Six Months Ended

Three Months Ended

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

Retail

Rate

$
(17.9
)
$
(34.1
)

$
(3.3
)
$
(37.1
)
Volume

(21.2
)
(29.7
)

(27.2
)
(57.2
)
Other miscellaneous

1.5

2.5

2.8

5.3

Total retail change

$
(37.6
)
$
(61.3
)

$
(27.7
)
$
(89.0
)

Wholesale

Rate

$
8.0

$
11.0

$
6.2

$
17.4

Volume

7.1

34.0

18.8

52.6

Total wholesale change

$
15.1

$
45.0

$
25.0

$
70.0

RTO capacity and other

RTO capacity and other revenues

$
7.2

$
26.8

$
(17.5
)
$
9.3

Total revenues change

$
(15.3
)
$
10.5

$
(20.2
)
$
(9.7
)

For the three months ended ~~June~~September 30, 2011, Revenues decreased ~~$15.3~~$20.2 million, or 4%, to ~~$408.6~~$466.8 million from ~~$423.9~~$487.0 million in the prior year. This decrease was primarily the result of lower average retail rates and lower retail sales volumes and decreased RTO capacity and other revenues, partially offset by wholesale sales volumes, higher average wholesale prices ~~as well as~~and increased ~~RTO capacity and~~ other miscellaneous revenues. The revenue components for the three months ended ~~June~~September 30, 2011 are further discussed below:

·                  Retail revenues decreased ~~$37.6~~$27.7 million primarily as a result of a 7%1% 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 an increase in the Fuel and Purchased Power Recovery Rider and an increase in the Universal Service Fund Rider. Most of the retail volume decline due to switching is reflected as a wholesale volume increase since DP&L still retains and serves most of these customers, but on a wholesale basis through its DPLER affiliate. Also contributing to the decline in revenues was ~~an 8%~~a 9% decrease in retail sales volumes largely due to ~~an unfavorable 15% decrease in cooling degree days from the prior year.~~cooler weather. The above resulted in an unfavorable ~~$17.9~~$3.3 million retail price variance and an unfavorable ~~$21.2~~$27.2 million retail sales volume variance.

·                  Wholesale revenues increased ~~$15.1~~$25.0 million primarily as a result of ~~an 8%~~a 5% increase in average wholesale prices combined with ~~an 8%~~a 19% 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 ~~$8.0~~$6.2 million wholesale price variance and a favorable wholesale sales volume variance of ~~$7.1~~$18.8 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 $7.2~~decreased $17.5 million compared to the same period in 2010. This ~~increase~~decrease in RTO capacity and other revenues was primarily the result of a ~~$7.9~~$16.5 million ~~increase~~decrease in revenues realized from the PJM capacity auction ~~offset slightly by~~including a decrease in transmission and congestion revenues.

8289

Table of Contents

For the ~~six~~nine months ended ~~June~~September 30, 2011, Revenues ~~increased $10.5~~decreased $9.7 million, or 1%, to ~~$872.4~~$1,339.2 million from ~~$861.9~~$1,348.9 million in the prior year. This ~~increase~~decrease was primarily the result of lower retail rates and lower retail sales volumes, partially offset by 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.~~revenues. The revenue components for the ~~six~~nine months ended ~~June~~September 30, 2011 are further discussed below:

·                  Retail revenues decreased ~~$61.3~~$89.0 million primarily as a result of a 6%4% 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%6% decrease in retail sales volumes largely due to an unfavorable ~~15%~~5% decrease in cooling degree days from the prior year. The above resulted in an unfavorable ~~$34.1~~$37.1 million retail price variance and an unfavorable ~~$29.7~~$57.2 million retail sales volume variance. The decrease was partially offset by $3.5 million of other miscellaneous retail revenues which includes revenues associated with the operation of a recently acquired distribution system.

·                  Wholesale revenues increased ~~$45.0~~$70.0 million primarily as a result of a 6% increase in average wholesale prices combined with a ~~21%~~20% 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~~$52.6 million wholesale sales volume variance and a favorable wholesale price variance of ~~$11.0~~$17.4 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~~$9.3 million compared to the same period in 2010. This increase in RTO capacity and other revenues was primarily the result of a ~~$27.4~~$10.9 million increase in revenues realized from the PJM capacity auction offset slightly beby a decrease in transmission and congestion revenues.

DP&L — Cost of Revenues
For the three months ended ~~June~~September 30, 2011:

·                  Net fuel costs, which include coal, gas, oil and emission allowance costs, increased ~~$0.6~~$26.6 million, or 1%27%, compared to 2010, primarily due to the impact of an increase in the price of fuel, as well as a ~~17.8%~~$10.9 million increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal, partially offset by a 3% decrease in the volume of ~~generation~~generation.
·Net purchased power decreased $20.8 million, or 18%, compared to the same period in 2010, due largely to a decrease of $23.4 million in RTO capacity and other charges which were incurred as a ~~12.7%~~member of PJM, including costs associated with DP&L’s load obligations for retail customers. This decrease included the net impact of the deferral and recovery of DP&L’s transmission, capacity and other PJM-related charges. Also contributing to the decrease in net purchased power was a $5.7 million increase associated with higher purchased power volumes partially offset by $3.5 million decrease 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.
90

Table of Contents
For the nine months ended September 30, 2011:
·Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $25.2 million, or 9%, compared to 2010, primarily due to the impact of an 18% increase in the price of generation byfrom our plants ~~resulting from~~due to an increase in, and the timing of, unit outages during the ~~three~~nine months ended ~~June~~September 30, 2011 ~~when~~as compared to the same period in ~~2010.~~2010, as well as a $15.8 million increase in Unrealized MTM losses largely related to lower relative market prices and lower contracted volumes for NYMEX quality coal, partially offset by a 12% decrease in the volume of generation.

·                  Net purchased power increased ~~$14.1~~$38.5 million, or ~~16%~~14%, compared to the same period in 2010, partially due ~~largely~~ to an increase of ~~$3.1~~$4.3 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 ~~$19.7~~$53.1 million increase associated with higher purchased power volumes partially offset by ~~$5.8~~an $18.9 million decrease 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.

~~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

Nine Months Ended

June 30,

June 30,

September 30,

September 30,

$ in millions

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

2011 vs. 2010

Generating facilities operating and maintenance expenses

$
8.7

$
16.0

$
(1.5
)
$
14.5

Low-income payment program (1)

3.9

11.5

Maintenance of overhead transmission and distribution lines

2.2

9.5

0.9

10.3

Low-income payment program (1)

3.2

7.7

Group insurance / long-term disability

(4.7
)
(8.8
)
Energy efficiency programs (1)

0.3

(1.6
)

(0.9
)
(2.5
)
Group insurance / long-term disability

(4.3
)
(4.1
)
Other, net

(0.4
)
(5.7
)

3.8

(1.7
)
Total operation and maintenance expense

$
9.7

$
21.8

$
1.5

$
23.3

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

For the three months ended ~~June~~September 30, 2011, Operation and maintenance expense increased ~~$9.7~~$1.5 million, or ~~11%~~2%, compared to the same period in 2010. This variance was primarily the result of increased assistance for low-income retail customers which is funded by the USF revenue rate rider. These increases were partially offset by 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, lower expenses related to energy efficiency programs and lower expenses for generating facilities.
For the nine months ended September 30, 2011, Operation and maintenance expense increased $23.3 million, or 10%, 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, 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~~rider, 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 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, and~~
·~~increased assistance for low-income retail customers which is funded by the USF revenue rate rider.~~2011.

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.~~2010, and
·lower expenses relating to energy efficiency programs that were put in place for our customers.
91

Table of Contents

DP&L — Depreciation and Amortization
For the three months ended ~~June~~September 30, 2011,, Depreciation and amortization expense increased ~~$0.2~~$3.4 million, or 1%11%, as compared to the three months ended ~~June~~September 30, 2010. The increase is primarily the result of a net increase in depreciable property.
For the nine months ended September 30, 2011, Depreciation and amortization expense increased $1.9 million, or 2%, as compared to the nine months ended September 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.

~~For the six months ended June 30, 2011~~, Depreciation and amortization expense decreased $1.5 million, or 2%, as compared to the six months ended June 30, 2010. 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.
84

~~Table of Contents~~
DP&L — General Taxes
For the three and ~~six~~nine months ended ~~June~~September 30, 2011,, General taxes increased ~~$1.3~~$1.0 million, or ~~4.4%~~3%, and ~~$2.6~~$3.6 million, or ~~4.2%~~4%, 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~~nine months ended ~~June~~September 30, 2011 did not fluctuate significantly from that recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2010.

DP&L — Interest Expense
Interest expense recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2011 did not fluctuate significantly from that recorded during the three and ~~six~~nine months ended ~~June~~September 30, 2010.

DP&L — Income Tax Expense
For the three and ~~six~~nine months ended ~~June~~September 30, 2011, Income tax expense decreased ~~$12.9~~$12.6 million, or ~~45%~~32%, and ~~$22.7~~$35.3 million, or ~~35%~~34%, respectively, compared to the same period in 2010, primarily due to decreased pre-tax income.
92

Table of Contents

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

For the Six Months

Nine Months Ended

Ended June 30,

September 30,

$ in millions

2011

2010

2011

2010

Net cash provided by operating activities

$
185.1

$
204.9

$
264.8

$
331.6

Net cash used for investing activities

(28.6
)
(120.2
)

(78.9
)
(160.3
)
Net cash used for financing activities

(207.7
)
(72.2
)

(242.3
)
(107.1
)

Net change

$
(51.2
)
$
12.5

$
(56.4
)
$
64.2

Cash and cash equivalents at beginning of period

124.0

74.9

124.0

74.9

Cash and cash equivalents at end of period

$
72.8

$
87.4

$
67.6

$
139.1

DP&L

For the Six Months

Nine Months Ended

Ended June 30,

September 30,

$ in millions

2011

2010

2011

2010

Net cash provided by operating activities

$
163.2

$
205.1

$
286.8

$
338.0

Net cash used for investing activities

(89.1
)
(71.6
)

(138.5
)
(110.6
)
Net cash used for financing activities

(115.4
)
(150.4
)

(180.6
)
(150.6
)

Net change

$
(41.3
)
$
(16.9
)

$
(32.3
)
$
76.8

Cash and cash equivalents at beginning of period

54.0

57.1

54.0

57.1

Cash and cash equivalents at end of period

$
12.7

$
40.2

$
21.7

$
133.9

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.

DPL — Net Cash provided by Operating Activities
DPL’s Net cash provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 can be summarized as follows:

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Net income

$
75.2

$
132.4

$
142.3

$
218.8

Depreciation and amortization

70.2

73.1

106.0

105.3

Deferred income taxes

37.5

6.4

70.5

38.7

Charge for early redemption of debt

15.3

—

Contribution to pension plan

(40.0
)
(20.0
)

(40.0
)
(40.0
)
Charge for early redemption of debt

15.3

—

Cash settlement of interest rate hedges, net of tax effect

(31.3
)
—

Other

26.9

13.0

2.0

8.8

Net cash provided by operating activities

$
185.1

$
204.9

$
264.8

$
331.6

93

Table of Contents

For the ~~six~~nine months ended ~~June~~September 30, 2011, Net cash provided by operating activities was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

·                  A ~~$37.5~~$70.5 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~~contributions, financial transaction losses and other temporary differences arising from routine changes in balance sheet accounts giving rise to ~~the defined benefit pension plan in February 2011.~~deferred taxes.

·                  A $15.3 million charge for the early redemption of DPL Capital Trust II securities.
·DP&L made discretionary contributions of $40.0 million to the defined benefit pension plan in 2011.
·DPL made a cash payment of $48.1 million ($31.3 million net of the tax effect) related to an interest rate hedge contract that settled during the period.

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

·                  The ~~$6.4~~$38.7 million increase to Deferred income taxes primarily results from a ~~$7.0~~$14.0 million temporary difference due to a pension ~~contribution~~contributions and estimate-to-actual adjustments of depreciation expense, repair expense and other temporary differences arising from routine changes in balance sheet accounts.

·                  DP&L made a discretionary ~~contribution of $20.0~~contributions totaling $40.0 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.

86

~~Table of Contents~~
DP&L — Net Cash provided by Operating Activities
DP&L’s Net cash provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 can be summarized as follows:

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Net income

$
83.5

$
131.5

$
147.4

$
214.7

Depreciation and amortization

66.5

68.0

100.3

98.4

Deferred income taxes

37.2

5.8

56.1

36.9

Contribution to pension plan

(40.0
)
(20.0
)

(40.0
)
(40.0
)
Other

16.0

19.8

23.0

28.0

Net cash provided by operating activities

$
163.2

$
205.1

$
286.8

$
338.0

For the ~~six~~nine months ended ~~June~~September 30, 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.

94

Table of Contents
DPL — Net Cash used for Investing Activities
DPL’s Net cash used for investing activities for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 can be summarized as follows:

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Environmental and renewable energy capital expenditures

$
(5.9
)
$
(7.2
)

$
(8.5
)
$
(8.2
)
Other asset acquisitions, net

(85.5
)
(67.9
)

(132.8
)
(105.5
)
Purchase of MC Squared

(8.2
)
—

(8.3
)
—

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

69.2

(47.0
)

69.2

(48.3
)
Other

1.8

1.9

1.5

1.7

Net cash used for investing activities

$
(28.6
)
$
(120.2
)

$
(78.9
)
$
(160.3
)

For the ~~six~~nine months ended ~~June~~September 30, 2011, DP&L &L’s~~continued~~ environmental expenditures were primarily related to ~~see reductions in its environmental and renewable energy capital expenditures due to the completion of the solar energy facility~~pollution control devices at ~~Yankee Station during 2010.~~our generation plants. Additionally, DPL, on behalf of DPLER, made a cash payment of approximately ~~$8.2~~$8.3 million to acquire MC Squared (see Note 15 of Notes to Condensed Consolidated Financial Statements). Also during the ~~six~~nine months ended ~~June~~September 30, 2011, DPL redeemed $70.9 million of short-term investments mostly comprised of VRDN securities as well as purchasing 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~~nine months ended ~~June~~September 30, 2010, DP&L ~~incurred~~continued to see reductions in its environmental ~~and renewable energy~~ capital expenditures due to the completion of FGD and SCR projects. The expenditures incurred during 2010 relate primarily ~~related~~ to the construction of a solar energy facility at Yankee ~~Station.~~station. DP&L also continued to make upgrades and other investments in other generation, transmission and distribution equipment. During this period, DPL also purchased VRDN securities at a net ~~$32~~total of $33.2 million ~~of VRDN securities~~ from various institutional securities brokers as well as ~~$15~~$15.1 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

~~Table of Contents~~
DP&L — Net Cash used for Investing Activities
DP&L’s Net cash used for investing activities for the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010 can be summarized as follows:

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Environmental and renewable energy capital expenditures

$
(5.8
)
$
(7.2
)

$
(8.5
)
$
(8.2
)
Other asset acquisitions, net

(85.0
)
(66.3
)

(131.4
)
(104.1
)
Other

1.7

1.9

1.4

1.7

Net cash used for investing activities

$
(89.1
)
$
(71.6
)

$
(138.5
)
$
(110.6
)

For the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, the significant components of DP&L’s Net cash used for investing activities are similar to those discussed under DPL’s Net cash provided by / used for investing activities above.

95

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

Six Months Ended

Nine Months Ended

June 30,

September 30,

$ in millions

2011

2010

2011

2010

Dividends paid on common stock

$
(76.4
)
$
(69.9
)

$
(113.8
)
$
(104.8
)
Payment of long-term debt

(297.4
)
—

Repurchase of DPL common stock

—

(3.9
)

—

(3.9
)
Early redemption of long-term debt, including premium

(134.2
)
—

(134.2
)
—

Payment of MC Squared debt

(13.5
)
—

(13.5
)
—

Issuance of long-term debt

300.0

—

Exercise of warrants

14.7

—

14.7

—

Other

1.7

1.6

1.9

1.6

Net cash used for financing activities

$
(207.7
)
$
(72.2
)

$
(242.3
)
$
(107.1
)

For the ~~six~~nine months ended ~~June~~September 30, 2011, DPL paid common stock dividends of ~~$76.4~~$113.8 million and $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 ~~DP&L~~DPL received $14.7 million from the exercise of 700,000 warrants.

For the ~~six~~nine months ended ~~June~~September 30, 2010, DPL paid common stock dividends of ~~$69.9~~$104.8 million. In addition, under a stock repurchase program approved by the Board of Directors in October 2009 (see Note 11 of Notes to Condensed Consolidated Financial Statements), DPL repurchased approximately 145,915 DPL common shares for $3.9 million.

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

Six Months Ended

June 30,

$ in millions

2011

2010

Dividends paid on common stock to parent

$
(115.0
)
$
(150.0
)
Other

(0.4
)
(0.4
)
Net cash used for financing activities

$
(115.4
)
$
(150.4
)
88

~~Table of Contents~~

Nine Months Ended

September 30,

$ in millions

2011

2010

Dividends paid on common stock to parent

$
(180.0
)
$
(150.0
)
Other

(0.6
)
(0.6
)
Net cash used for financing activities

$
(180.6
)
$
(150.6
)

For the ~~six~~nine months ended ~~June~~September 30, 2011, DP&L’s Net cash used for financing activities primarily relates to ~~$115.0~~$180.0 million in dividends paid to DPL.

For the ~~six~~nine months ended ~~June~~September 30, 2010, DP&L’s Net cash used for financing activities primarily relates to $150.0 million in dividends paid to DPL.

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, potential margin requirements for retail operations, interest and dividend payments. For 2011, and in subsequent years, we expect to satisfy these requirements with a combination of cash from operations and funds from the capital markets as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

96

Table of Contents
At the filing date of this quarterly report on Form 10-Q, DP&L has access to ~~$420~~$400 million of short-term financing under two revolving credit facilities. The first facility, established in August 2011, is for ~~$220~~$200 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 borrowing under the first facility by $50 million. The second facility, established in April 2010, is for $200 million and expires in April 2013. A total of five banks participate in this facility, with no bank having more than 35% of the total commitment.DPL established a $125 million revolving credit facility 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. In addition, DPL entered into a $425 million unsecured term loan agreement with a syndicated bank group in August 2011. This agreement is for a three year term expiring on August 24, 2014. DPL used the proceeds from a $300 million drawdown of this facility to redeem $297.4 million of 6.875% senior unsecured notes.

Amounts

Amounts

available as of

available as of

$ in millions

Type

Maturity

Commitment

June 30, 2011

Type

Maturity

Commitment

September 30, 2011

DP&L

Revolving

November 2011

$
220.0

$
220.0

Revolving

August 2015

$
200.0

$
200.0

DP&L

Revolving

April 2013

$
200.0

$
200.0

Revolving

April 2013

200.0

200.0

$
420.0

$
420.0

DPL Inc.

Revolving

August 2014

125.0

125.0

$
525.0

$
525.0

EachDP&L revolving credit facility has a $50 million ~~Letter of Credit (LOC)~~LOC sublimit. The DPL revolving credit facility has a $125 million LOC sublimit. As of ~~June~~September 30, 2011 and through the date of filing this quarterly report on Form 10-Q, there were no 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~~$67.6 million and ~~$12.7~~$21.7 million, respectively, at ~~June~~September 30, 2011.

89

~~Table of Contents~~
Debt Covenants
As mentioned above DPL has access to $125 million of short-term financing under its revolving credit facility and $425 million of financing 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 0.65 to 1.00 prior to the consummation of the Proposed Merger and 0.70 to 1.00 after the consummation of the Proposed Merger. The second financial covenant, applicable only if DPL’s credit ratings were to fall below investment grade, requires DPL’s consolidated earnings before interest, taxes, depreciation and amortization (EBITDA) to consolidated interest charges ratio to be not less than 2.50 to 1.00. As of September 30, 2011 the first covenant was met with a ratio of 0.52 to 1.00 and the second covenant, while not currently applicable, would have been met with a ratio of 8.23 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 guaranty obligations, divided by the total of DPL’s shareholders’ equity and total debt including guaranty 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 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~~September 30, 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 obligations, divided by the total of DP&L’s shareholders’ equity and total debt including guaranty obligations.

~~There~~Except as noted above, 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.
97

Table of Contents

Capital Requirements
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~~$750 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~~$130 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~~$128.5 million and ~~$62.4~~$102.5 million during the ~~six month periods~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. DPL expects to spend approximately ~~$310~~$225 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~~$127.6 million and ~~$60.8~~$100.6 million during the ~~six month periods~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. DP&L expects to spend approximately ~~$300~~$200 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 of 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

BBB+

A

Negative

April 2011
Moody’s Investors Service

Baa1

Aa3

Negative

April 2011
Standard & Poor’s Corp.

BBB+

A

Negative

April 2011

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

In connection with the closing of the Proposed Merger (see Note 16 of Notes to Condensed Consolidated Financial Statements), DPL is expected to assume upon closing of the Proposed Merger, $1.25 billion of debt that an AES ~~affiliate will issue~~subsidiary issued to finance the acquisition. As a result of this ~~proposed~~expected additional indebtedness, in April 2011 DPL and DP&L were downgraded by one of the major credit rating agencies above and all three major credit rating agencies reduced their outlook from stable 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
90

~~Table of Contents~~
Consolidated Financial Statements. This may cause the need for additional credit assurance to satisfy various creditors.

Off-Balance Sheet Arrangements

DPL — Guarantees
In the normal course of business, DPL enters into various agreements with its wholly-owned subsidiaries, DPLE and DPLER, and its indirect 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.
98

Table of Contents
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. The changes in our credit ratings in April 2011 have not triggered these provisions. ~~There~~However, there may be further changes to our credit ratings which may trigger these provisions.

At ~~June~~September 30, 2011, DPL had ~~$90.2~~$86.7 million of guarantees to third parties for future financial or performance assurance under such agreements, including ~~$73.2~~$69.7 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 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~~$0.5 million and ~~$1.0~~$1.7 million at ~~June~~September 30, 2011 and December 31, 2010, respectively.

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~~September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or ~~$61.4~~$61.0 million, of a ~~$1,252.5~~$1,244.5 million debt obligation that matures in 2026. This would only happen if this electric generation company defaulted on its debt payments. As of ~~June~~September 30, 2011, 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~~changes to ~~the federal government that is payable monthly over 50 years and bears interest at 4.2% per annum~~our debt as discussed further in Note 5 of Notes to Condensed Consolidated Financial Statements.

See Note 14 of Notes to Condensed Consolidated Financial Statements.

91

~~Table of Contents~~
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 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. 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 under contract and a significant portion of projected 2012 needs, sales requirements may change, particularly for retail load.
99

Table of Contents
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~~September 30, 2011 would not have a significant effect on Net income.
92

~~Table of Contents~~

The following table provides information regarding the volume and average market price of our NYMEX coal forward derivative contracts at ~~June~~September 30, 2011 and the effect to Net income if the market price were to increase or decrease by 10%:

Weighted

Increase /

Weighted

Increase /

Average

Decrease in

Average

Decrease in

Contract

Market

Net Income

Contract

Market

Net Income

Commodity

Volume

Units

Price / Unit

(in millions)

Volume

Units

Price / Unit

(in millions)

NYMEX Coal Forwards - Non-Hedged

2011 - Purchase

149,188

tons

$
77.89

$
0.4
(a)

59,675

tons

$
73.90

$
0.1
(a)
2012 - Purchase

1,246,200

tons

$
82.26

$
3.8
(a)

903,030

tons

$
75.07

$
2.6
(a)
2013 - Purchase

372,000

tons

$
86.72

$
2.1
(a)

465,000

tons

$
78.42

$
2.4
(a)

(a)

The Net income impact of a 10% change in the market price of NYMEX coal is partially offset by our partners’ share of the gain or loss and by the retail jurisdictional share of the DPL portion that is deferred on the balance sheet in conjunction with the fuel cost and purchased power rider.

Wholesale Revenues
Approximately ~~18%~~15% of DPL’s and ~~16%~~33% of DP&L’s electric revenues for the three months ended ~~June~~September 30, 2011 were from sales of excess energy and capacity in the wholesale market (DP&L’s electric revenues in the wholesale market are reduced for sales to DPLER). Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

Approximately 17% of DPL’s and ~~17%~~30% of DP&L’s electric revenues for the three months ended ~~June~~September 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%~~34% of DP&L’s electric revenues for the ~~six~~nine months ended ~~June~~September 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.
100

Table of Contents
Approximately 17% of DPL’s and 28% of DP&L’s electric revenues for the nine months ended September 30, 2010 were from sales of excess energy and capacity in the wholesale market. Energy in excess of the needs of existing retail customers is sold in the wholesale market when we can identify opportunities with positive margins.

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

$
7.9

$
6.9

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

93

~~Table of Contents~~
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

2011

2012

2013

2014

Computed average capacity price ($/MW-day)

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~~September 30, 2011, 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~~September 30, 2011. As of ~~June~~September 30, 2011, approximately ~~55%~~50% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

$ in millions

DPL

DP&L

Effect of a $10 change in capacity auction pricing

$
5.0

$
3.7

101

Table of Contents
$ in millions

DPL

DP&L

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

$
5.2

$
3.8

Capacity revenues and costs are also impacted by, among other factors, the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load. In determining the capacity price sensitivity above, we did not consider the impact that may arise from the variability of these other factors.

Fuel and Purchased Power Costs
DPL’s and DP&L’s fuel (including coal, gas, oil and emission allowances) and purchased power costs as a percentage of total operating costs for the three months and ~~six~~nine months ended ~~June~~September 30, 2011 were ~~35%~~42% and ~~35%~~37%, respectively. We have substantially all of the total expected coal volume needed to meet our retail and firm wholesale sales requirements for 2011 under contract and a significant portion of projected 2012 needs are also 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; 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 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 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%~~50% of DP&L’s total fuel costs. The table below provides the effect on annual net income as of ~~June~~September 30, 2011, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate ~~55%~~50%:

$ in millions

DPL

DP&L

DPL

DP&L

Effect of 10% change in fuel and purchased power

$
18.7

$
18.1

$
17.7

$
17.0

94

~~Table of Contents~~
Interest Rate Risk
As a result of our normal investing and borrowing activities, our financial results are exposed to fluctuations in interest rates, which we manage through our regular financing activities. We maintain both cash on deposit and investments in cash equivalents that may be affected by adverse interest rate fluctuations. DPL has fixed-rate long-term debt and DP&L has both fixed and variable-rate long-term debt. DP&L’s variable-rate debt is associated with tax-exempt 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 of Notes to Condensed Consolidated 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~~September 30, 2011, we have entered into interest rate hedging relationships with an aggregate notional amount of ~~$300 million and~~ $160 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 million aggregate notional amount interest rate hedging relationships is ~~4.04% and 3.80%, respectively.~~4%. 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.

102

Table of Contents
The carrying value of DPL’s debt was ~~$1,221.4~~$1,224.0 million at ~~June~~September 30, 2011, consisting of DP&L’s first mortgage bonds, DP&L’s debt associated with tax-exempt pollution control bonds, DPL’s unsecured notes and DP&L’s capital ~~lease.~~leases. The fair value of this debt was ~~$1,198.7~~$1,204.6 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 DPL’s debt obligations that are sensitive to interest rate changes:

Principal Payments 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,

For the years ending September 30,

September 30,

September 30,

$ in millions

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (a)

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (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
%
0.2
%
0.2
%

Fixed-rate debt

$
297.8

$
0.4

$
470.4

$
0.1

$
0.1

$
352.6

$
1,121.4

$
1,098.7

$
0.4

$
0.4

$
770.3

$
0.1

$
0.1

$
352.7

$
1,124.0

$
1,104.6

Average interest rate

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

4.9
%
5.0
%
3.7
%
4.2
%
4.2
%
5.0
%
4.1
%

Total

$
1,221.4

$
1,198.7

$
1,224.0

$
1,204.6

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

The carrying value of DP&L’s debt was $903.4 million at ~~June~~September 30, 2011, consisting of its first mortgage bonds, tax-exempt pollution control bonds and a capital lease. The fair value of this debt was ~~$877.3~~$884.2 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 of Contents~~
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,

For the years ending September 30,

September 30,

September 30,

$ in millions

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (a)

2012

2013

2014

2015

2016

Thereafter

2011 (a)

2011 (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
%
0.2
%
0.2
%

Fixed-rate debt

$
0.4

$
0.4

$
470.4

$
0.1

$
0.1

$
332.0

$
803.4

$
777.3

$
0.4

$
0.4

$
470.3

$
0.1

$
0.1

$
332.1

$
803.4

$
784.2

Average interest rate

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

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

Total

$
903.4

$
877.3

$
903.4

$
884.2

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

Debt maturities occurring in 2011 are discussed under FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS.

103

Table of Contents
Long-term Debt Interest Rate Risk Sensitivity Analysis
~~Our~~The following table presents our estimate of market risk exposure ~~is presented~~ for our fixed-rate and variable-rate debt at ~~June~~September 30, 2011 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~~September 30, 2011, we did not hold any market risk sensitive instruments which were entered into for trading purposes.

DPL

Carrying value at

Fair value at

One percent

Carrying value at

Fair value at

One percent

June 30,

June 30,

interest rate

September 30,

September 30,

interest rate

$ in millions

2011

2011

risk

2011

2011

risk

Long-term debt

Variable-rate debt

$
100.0

$
100.0

$
1.0

$
100.0

$
100.0

$
1.0

Fixed-rate debt

1,121.4

1,098.7

11.0

1,124.0

1,104.6

11.0

Total

$
1,221.4

$
1,198.7

$
12.0

$
1,224.0

$
1,204.6

$
12.0

DP&L

Carrying value at

Fair value at

One percent

Carrying value at

Fair value at

One percent

June 30,

June 30,

interest rate

September 30,

September 30,

interest rate

$ in millions

2011

2011

risk

2011

2011

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

803.4

784.2

8.8

Total

$
903.4

$
877.3

$
8.8

$
903.4

$
884.2

$
9.8

DPL’s debt is comprised of both fixed-rate debt and variable-rate debt. In regard to fixed-rate debt, the interest rate risk with respect to DPL’s long-term debt, excluding capital lease obligations, primarily relates to the potential impact a decrease of one percentage point in interest rates has on the fair value of DPL’s $~~1,098.7~~1,104.6 million of fixed-rate debt and not on DPL’s financial position or results of operations. On the variable-rate debt, the interest rate risk with respect to DPL’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DPL’s results of operations related to DP&L’s $100.0 million variable-rate long-term debt outstanding as of ~~June~~September 30, 2011.
96

~~Table of Contents~~

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~~$784.2 million of fixed-rate debt and not on DP&L’s financial position or DP&L’s results of operations. On the variable-rate debt, the interest rate risk with respect to DP&L’s long-term debt represents the potential impact an increase of one percentage point in the interest rate has on DP&L’s results of operations related to DP&L’s $100.0 million variable-rate long-term debt outstanding as of ~~June~~September 30, 2011.

Equity Price Risk
As of ~~June~~September 30, 2011, approximately ~~38%~~32% of the defined benefit pension plan assets were comprised of investments in equity securities and ~~62%~~68% related to investments in fixed income securities, cash and cash equivalents, and alternative investments. The equity securities are carried at their market value of approximately ~~$127.7~~$106.1 million at ~~June~~September 30, 2011. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$12.8~~$10.6 million reduction in fair value as of ~~June~~September 30, 2011.

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.
104

Table of Contents
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.

CRITICAL ACCOUNTING ESTIMATES

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

Different estimates could have a material effect on our financial results. Judgments and uncertainties affecting the application of these policies and estimates may result in materially different amounts being reported under different conditions or circumstances. Historically, however, recorded estimates have not differed materially from actual results. Significant items subject to such judgments include: the carrying value of property, plant and equipment; unbilled revenues; 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 for a complete listing of our critical accounting policies and estimates. There have been no material changes to these critical accounting policies and estimates.

97105

Table of Contents

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

June 30,

June 30,

June 30,

September 30,

September 30,

September 30,

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

Electric sales (millions of kWh)

Residential

1,144

1,114

1,144

1,114

1

—

1,432

1,515

1,432

1,515

32

—

Commercial

985

924

791

906

638

190

1,125

1,121

884

1,086

776

420

Industrial

867

977

818

972

773

666

946

939

893

930

860

717

Other retail

349

360

343

358

257

202

392

399

382

397

203

247

Total retail

3,345

3,375

3,096

3,350

1,669

1,058

3,895

3,974

3,591

3,928

1,871

1,384

Wholesale

516

786

542

783

—

—

703

625

717

578

—

—

Total

3,861

4,161

3,638

4,133

1,669

1,058

4,598

4,599

4,308

4,506

1,871

1,384

Operating revenues ($ in thousands)

Residential

$
153,998

$
146,003

$
153,917

$
145,995

$
81

$
10

$
193,684

$
194,510

$
191,255

$
194,495

$
2,430

$
16

Commercial

96,905

93,422

54,304

80,673

42,601

16,269

108,462

107,503

56,489

80,122

51,973

27,382

Industrial

65,530

72,270

18,809

34,624

46,721

35,229

71,564

66,909

19,735

24,772

51,828

42,137

Other retail

27,304

28,363

12,315

17,069

15,890

11,054

30,931

30,832

18,734

17,314

13,086

14,412

Other miscellaneous revenues

4,337

2,609

4,416

2,878

56

6

5,749

2,854

5,889

3,089

92

21

Total retail

348,074

342,667

243,761

281,239

105,349

62,568

410,390

402,608

292,102

319,792

119,409

83,968

Wholesale

28,659

39,116

104,705

89,538

739

—

40,660

31,124

122,296

97,356

—

—

RTO revenues

69,221

60,495

60,142

53,195

615

311

59,599

80,384

52,391

69,817

688

449

Other revenues

(981
)
3,195

—

—

(4,668
)
6

1,158

2,769

—

—

(1,573
)
7

Total

$
444,973

$
445,473

$
408,608

$
423,972

$
102,035

$
62,885

$
511,807

$
516,885

$
466,789

$
486,965

$
118,524

$
84,424

Electric customers at end of period

Residential

454,552

455,594

454,552

455,594

137

27

453,860

454,783

453,860

454,783

8,434

30

Commercial

52,970

50,429

50,056

50,128

12,224

1,878

53,065

50,504

50,029

50,110

13,612

3,433

Industrial

1,891

1,801

1,755

1,764

726

321

1,917

1,803

1,755

1,770

789

504

Other

6,877

6,659

6,760

6,656

2,113

776

6,916

6,686

6,795

6,683

2,474

859

Total

516,290

514,483

513,123

514,142

15,200

3,002

515,758

513,776

512,439

513,346

25,309

4,826

(a)This chart contains electric sales from DP&L’s generation and purchased power. DP&L sold ~~1,420~~1,567 million kWh and ~~1,033~~1,338 million kWh of power to DPLER (a subsidiary of DPL) during the three months ending ~~June~~September 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.

98106

Table of Contents

ELECTRIC SALES AND REVENUES

DPL

DP&L (a)

DPLER (b)

DPL

DP&L (a)

DPLER (b)

Six Months Ended

Six Months Ended

Six Months Ended

Nine Months Ended

Nine Months Ended

Nine Months Ended

June 30,

June 30,

June 30,

September 30,

September 30,

September 30,

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

2011

2010

Electric sales (millions of kWh)

Residential

2,688

2,709

2,688

2,709

1

1

4,120

4,224

4,120

4,224

33

—

Commercial

1,917

1,810

1,622

1,789

1,152

341

3,042

2,931

2,507

2,875

1,927

707

Industrial

1,696

1,778

1,625

1,772

1,489

1,046

2,642

2,717

2,517

2,702

2,350

1,800

Other retail

691

697

681

696

498

394

1,083

1,096

1,063

1,093

701

659

Total retail

6,992

6,994

6,616

6,966

3,140

1,782

10,887

10,968

10,207

10,894

5,011

3,166

Wholesale

1,122

1,545

1,196

1,534

—

—

1,825

2,170

1,913

2,110

—

—

Total

8,114

8,539

7,812

8,500

3,140

1,782

12,712

13,138

12,120

13,004

5,011

3,166

Operating revenues ($ in thousands)

Residential

$
347,138

$
326,089

$
347,043

$
326,076

$
95

$
13

$
540,821

$
520,599

$
538,297

$
520,571

$
2,525

$
29

Commercial

192,472

182,422

114,789

160,008

77,683

22,413

300,934

289,925

171,278

240,130

129,656

49,795

Industrial

129,399

129,871

38,771

71,864

90,628

58,007

200,963

196,780

58,506

96,636

142,456

100,144

Other retail

55,675

54,790

26,418

32,870

31,123

23,614

86,606

85,622

45,153

50,184

44,209

38,026

Other miscellaneous revenues

6,909

4,095

7,106

4,561

88

9

12,658

6,949

12,995

7,650

148

27

Total retail

731,593

697,267

534,127

595,379

199,617

104,056

1,141,982

1,099,875

826,229

915,171

318,994

188,021

Wholesale

61,088

79,349

210,911

165,880

—

—

101,748

110,473

333,207

263,236

—

—

RTO revenues

145,903

113,923

127,387

100,684

1,104

565

205,501

194,307

179,778

170,501

1,792

1,013

Other revenues

1,041

6,132

—

—

(4,669
)
16

2,200

8,901

—

—

(6,210
)
26

Total

$
939,625

$
896,671

$
872,425

$
861,943

$
196,052

$
104,637

$
1,451,431

$
1,413,556

$
1,039,214

$
1,348,908

$
314,576

$
189,060

Electric customers at end of period

Residential

454,552

455,594

454,552

455,594

137

27

453,860

454,783

453,860

454,783

8,434

30

Commercial

52,970

50,429

50,056

50,128

12,224

1,878

53,065

50,504

50,029

50,110

13,612

3,433

Industrial

1,891

1,801

1,755

1,764

726

321

1,917

1,803

1,755

1,770

789

504

Other

6,877

6,659

6,760

6,656

2,113

776

6,916

6,686

6,795

6,683

2,474

859

Total

516,290

514,483

513,123

514,142

15,200

3,002

515,758

513,776

512,439

513,346

25,309

4,826

(a)       This chart contains electric sales from DP&L’s generation and purchased power. DP&L sold ~~2,764~~4,330 million kWh and ~~1,753~~3,091 million kWh of power to DPLER (a subsidiary of DPL) during the ~~six~~nine months ending ~~June~~September 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.

99107

Table of Contents

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~~nine months ended ~~June~~September 30, 2011 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~~Reports on Form 10-Q for the three months ended March 31, 2011 and for the three months ended June 30, 2011, and the Notes to the Consolidated Financial Statements included therein, contain descriptions of certain legal proceedings in which we are or were involved. The information in this Item 1 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 Form 10-K for the fiscal year ended December 31, 2010 and Quarterly ~~Report~~Reports on form 10-Q for the three months ended March 31, 2011 and the three months ended June 30, 2011, and should be read in conjunction with these prior reports.

The following information is incorporated by reference into this Item: (i) information about the legal proceedings related to the Proposed Merger involving DPL and AES contained in Item 1 - Note 16 of Notes to Condensed Consolidated Financial Statements of this ~~report~~report; and (ii) information about the legal proceedings contained under the section entitled “Ohio Regulation” ~~and the first legal proceeding contained~~ under the ~~subsection~~subsections of the section entitled ~~“Litigation Involving Co-Owned Plants”~~“Environmental Matters” and under the section entitled ~~“Litigation, Notices of Violation~~“Legal and Other ~~Matters Related to Air Quality”~~Matters” in Item 1 — Note 14 of Notes to Condensed Consolidated Financial Statements of this report.

~~100~~108

Table of Contents

Item 1a — Risk Factors

A comprehensive listing of risk factors that we consider to be the most significant to your decision to invest in our stock is provided in our most recent Annual Report on Form 10-K and supplemented in our Quarterly ~~Report~~Reports on Form 10-Q for the three months ended March 31, 2011 and for the three months ended June 30, 2011. These reports may be obtained as discussed on Page 67 of this report. The information in this Item 1a of our Quarterly Report on Form 10-Q restates, and provides updates on certain of the risk factors included in these prior ~~reports and also contains an additional risk factor.~~reports. If any of these events occur, our business, financial position or results of operation could be materially affected.
Fluctuations in our sales of coal and excess emission allowances could cause a material adverse effect on our results of operations, financial condition and cash flows for any particular period.
DP&L sells coal to other parties from time to time for reasons that include maintaining an appropriate balance between projected supply and projected use and as part of a coal price optimization program where coal under contract may be resold and replaced with other coal or power available in the market with a favorable price spread, adjusted for any quality differentials. During 2010 and 2009, DP&L realized net gains from these sales. Sales of coal are impacted by a range of factors, including price volatility among the different coal basins and qualities of coal, variations in power demand and the market price of power compared to the cost to produce power. These factors could cause the amount and price of coal we sell to fluctuate, which could cause a material adverse impact on our results of operations, financial condition and cash flows for any particular period.
DP&L may sell its excess emission allowances, including NOx and SO2 emission allowances, from time to time. Sales of any excess emission allowances are impacted by a range of factors, such as general economic conditions, fluctuations in market demand, availability of excess inventory available for sale and changes to the regulatory environment, including the enactment of the USEPA’s Cross-State Air Pollution Rule (“CSAPR”). These factors could cause the amount and price of excess emission allowances DP&L sells to fluctuate, which could cause a material adverse effect on DPL’s results of operations, financial condition and cash flows for any particular period. There has been overall reduced trading activity in the annual NOx and SO2 emission allowance trading markets in recent years. This impact on the emission allowance trading market was due, in large part, to a court order calling into question the USEPA’s Clean Air Interstate Rule annual NOx and SO2 emission allowance trading programs and requiring the USEPA to issue new regulations to address the court order. The adoption of regulations that regulate emissions or establish or modify emission allowance trading programs, like the CSAPR, which was finalized on July 6, 2011, could impact the emission allowance trading markets and have a material effect on DP&L’s emission allowance sales.

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~~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.

109

Table of Contents
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 ProposedMerger, 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 reasonsincluding, among others, if the Merger Agreement is terminated under certain specified circumstances,DPLwill be required to pay The AES Corporation a termination fee of $106 million. The occurrence of either of these events individually or in combination could have a material adverse affect on DPL’sfinancial results.

We will be subject to business uncertainties and contractual restrictions while the ProposedMerger 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 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.

~~101~~

~~Table of Contents~~
We expect that matters relating 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 affect our financial results.

In addition, the Merger Agreement restricts us, without The AES Corporation’s consent, from making certain acquisitions and taking other specified actions,including limiting 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.

Lawsuits have been filed 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 certain of our shareholders challenging the Proposed Merger and seeking, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms. We could also be subject to additional litigation related to the Proposed Merger, whether or not it is consummated. If any plaintiff is successful 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~~believe that any such litigation is
without merit, these matters create additional uncertainty relating to the consummation of the proposed transaction and defending such matters is costly and distracting to management.
110

Table of Contents

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 assets and liabilities ~~may~~will be adjusted and any resulting goodwill or negative goodwill ~~may~~will be allocated and pushed down to DPL. Although we believe 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.~~
From time to time we rely on access to the credit 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 counterparties could adversely affect our results of operations, financial condition and cash flows. If 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. ~~DP&L~~ has variable rate debt that bears interest based on 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~~ ~~DP&L~~ ~~is currently rated investment grade by various rating agencies.~~ ~~DPL~~ ~~expects to assume additional significant debt upon consummation of the Proposed Merger involving The AES Corporation. In light of this expected assumption of~~
~~102~~

~~Table of Contents~~
debt, one of the major rating agencies has downgraded our debt. In addition, all three major credit rating agencies have reduced their outlook from stable to negative 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 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 certain of our contracts, and a below investment grade credit rating could require us to provide other credit assurances under these contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
Item 2 — Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 — Defaults Upon Senior Securities

None

Item 4 — Removed and Reserved

111

Table of Contents
Item 5 — Other Information

None
~~103~~

~~Table of Contents~~

Item 6 — Exhibits

DPL Inc.

DP&L

Exhibit
Number

Exhibit

Location

X

~~2(a)~~10(a)

Credit Agreement, ~~and Plan of Merger,~~ dated as of ~~April 19,~~August 24, 2011, ~~by and~~ among DPL Inc., ~~The AES Corporation~~PNC Bank, National Association, as Administrative Agent, Bank of America, N.A., Fifth Third Bank and ~~Dolphin Sub, Inc.~~U.S. Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and the other lenders party to the Credit Agreement

Exhibit ~~2.1~~10.1 to Report on Form 8-K filed ~~April 20,~~August 30, 2011 ~~(File~~
(File No. 1-9052)
X
10(b)
Credit Agreement, dated as of August 24, 2011, among DPL Inc., U.S. Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, Bank of America, N.A., Fifth Third Bank and PNC Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and the other lenders party to the Credit Agreement
Exhibit 10.2 to Report on Form 8-K filed August 30, 2011
(File No. 1-9052)

X

X

~~10(a)~~10(c)

~~Limited Consent and Waiver, dated as of May 24, 2011, to the~~ Credit Agreement, dated as of ~~April 20, 2010,~~August 24, 2011, among The Dayton Power and Light Company, Fifth Third Bank, as Administrative Agent, Swing Line Lender and an L/C Issuer, Bank of America, N.A., U.S. Bank, National Association and PNC Bank, National Association, as Co-Syndication Agents, Bank of America, N.A., as ~~Administrative~~Documentation Agent, and ~~an L/C Issuer, and~~ the ~~lender parties~~other lenders party to the Credit Agreement

Exhibit ~~10.1~~10.3 to Report on Form 8-K filed ~~May 31,~~August 30, 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)
112

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

X

31(c)

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

Filed herewith as
Exhibit 31(c)

X

31(d)

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

Filed herewith as
Exhibit 31(d)

X

32(a)

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

Filed herewith as
Exhibit 32(a)

X

32(b)

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

Filed herewith as
Exhibit 32(b)

X

32(c)

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

Filed herewith as
Exhibit 32(c)

X

32(d)

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

Filed herewith as
Exhibit 32(d)

X

X

101.INS

XBRL Instance

Furnished herewith as Exhibit 101.INS
~~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.
Pursuant to paragraph (b) (4) (v) of Item 601 of Regulation S-K, we have not filed as exhibits 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~~113

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,~~October 27, 2011
/s/ Paul M. Barbas

Paul M. Barbas

President and Chief Executive Officer

(principal executive officer)

~~July 28,~~October 27, 2011
/s/ Frederick J. Boyle

Frederick J. Boyle

Senior Vice President, and Chief Financial Officer

(principal financial officer)

~~July28,~~October 27, 2011
/s/ Joseph W. Mulpas

Joseph W. Mulpas

Vice President, Controller and Chief Accounting Officer

(principal accounting officer)

~~106~~114

Abbreviation or Acronym		Definition

AMI		Advanced Metering Infrastructure

AOCI		Accumulated Other Comprehensive Income

ARO		Asset Retirement Obligation

ASU	��	Accounting Standards Update

BTU		British Thermal Units

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, a subsidiary of AEP

CO2		Carbon Dioxide

CCEM		Customer Conservation and Energy Management

CRES		Competitive Retail Electric Service

DPL		DPL Inc., the parent company

DPLE		DPL Energy, LLC, a wholly-owned subsidiary of DPL that owns and operates peaking generation facilities from which it makes wholesale sales

DPLER		DPL Energy Resources, Inc., a wholly-owned subsidiary of DPL that sells retail electric energy and other energy services

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

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

EIR		Environmental Investment Rider

EPS		Earnings Per Share

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

ESOP		Employee Stock Ownership Plan

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

FASB		Financial Accounting Standards Board

FASC		FASB Accounting Standards Codification

FERC		Federal Energy Regulatory Commission

FGD		Flue Gas Desulfurization

GAAP		Generally Accepted Accounting Principles in the United States

GHG		Greenhouse Gas

IFRS		International Financial Reporting Standards

kWh		Kilowatt hours

Abbreviation or Acronym		Definition

LOC		Letter of Credit

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

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

Merger 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 acquire DPL for $30 per share in a cash transaction valued at approximately $3.5 billion plus the assumption of $1.2 billion of debt. Upon closing, DPL will become a wholly-owned subsidiary of AES

MRO		Market Rate Option

MTM		~~Mark to Market~~Mark-to-Market

MVIC		Miami Valley Insurance Company, a wholly-owned insurance subsidiary of DPL that provides insurance services to DPL and its subsidiaries

MWh		Megawatt hours

NERC		North American Electric Reliability Corporation

NOV		Notice of Violation

NOx		Nitrogen Oxide

NYMEX		New York Mercantile Exchange

OAQDA		Ohio Air Quality Development Authority

OCC		Office of the 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., a regional transmission organization

Proposed Merger		The proposed merger involving 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

RPM		Reliability Pricing Model

SB 221		Ohio Senate Bill 221, an Ohio electric energy bill that was signed by the Governor on May 1, 2008 and went into effect July 31, 2008. This law required all Ohio distribution utilities to file either an electric security plan or a market rate option to be in effect January 1, 2009. The law also contains, among other things, annual targets relating to advanced energy portfolio standards, renewable energy, demand reduction and energy efficiency standards

SCR		Selective Catalytic Reduction

Abbreviation or Acronym		Definition

SEC		Securities and Exchange Commission

SECA		Seams Elimination Charge Adjustment

SERP		Supplemental Executive Retirement Plan

SFAS		Statement of Financial Accounting Standards

SO2		Sulfur Dioxide

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

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

TCRR		Transmission Cost Recovery Rider

USEPA		U.S. Environmental Protection Agency

USF		Universal Service Fund

VRDN		Variable Rate Demand Note

	Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
$ in millions except per share amounts	2011			2010			2011			2010			2011			2010			2011			2010

Revenues	$	444.9		$	445.5		$	939.6		$	896.7		$	511.8		$	516.9		$	1,451.4		$	1,413.6

Cost of revenues:
Fuel	92.1			90.9			191.9			192.8			129.0			104.3			320.9			297.1
Purchased power	113.6			90.9			234.4			163.7			108.3			119.0			342.7			282.7
Total cost of revenues	205.7			181.8			426.3			356.5			237.3			223.3			663.6			579.8

Gross margin	239.2			263.7			513.3			540.2			274.5			293.6			787.8			833.8

Operating expenses:
Operation and maintenance	106.8			87.5			206.2			168.1			92.0			84.2			298.2			252.3
Depreciation and amortization	35.1			35.7			70.2			73.1			35.8			32.2			106.0			105.3
General taxes	31.5			31.2			70.3			63.7			33.8			32.6			104.1			96.3
Total operating expenses	173.4			154.4			346.7			304.9			161.6			149.0			508.3			453.9

Operating income	65.8			109.3			166.6			235.3			112.9			144.6			279.5			379.9

Other income / (expense), net:
Investment income	0.1			0.2			0.2			0.3			0.1			0.3			0.3			0.6
Interest expense	(17.6		)	(17.5		)	(34.5		)	(35.4		)	(16.8		)	(17.6		)	(51.3		)	(53.0		)
Charge for early redemption of debt	—			—			(15.3		)	—			—			—			(15.3		)	—
Other expense	(0.3		)	(0.5		)	(0.7		)	(1.3		)	(0.5		)	(0.5		)	(1.2		)	(1.8		)
Total other income / (expense), net	(17.8		)	(17.8		)	(50.3		)	(36.4		)	(17.2		)	(17.8		)	(67.5		)	(54.2		)

Earnings before income tax	48.0			91.5			116.3			198.9			95.7			126.8			212.0			325.7

Income tax expense	16.3			30.1			41.1			66.5			28.6			40.4			69.7			106.9

Net income	$	31.7		$	61.4		$	75.2		$	132.4		$	67.1		$	86.4		$	142.3		$	218.8

Average number of common shares outstanding (millions):
Basic	114.2			115.7			114.1			115.6			115.0			115.8			114.4			115.7
Diluted	114.9			116.2			114.7			116.2			115.5			116.3			115.0			116.2

Earnings per share of common stock:
Basic	$	0.28		$	0.53		$	0.66		$	1.15		$	0.58		$	0.75		$	1.24		$	1.89
Diluted	$	0.28		$	0.53		$	0.66		$	1.14		$	0.58		$	0.74		$	1.24		$	1.88

Dividends paid per share of common stock	$	0.3325		$	0.3025		$	0.6650		$	0.6050		$	0.3325		$	0.3025		$	0.9975		$	0.9075

	At			At			At			At
	June 30,			December 31,			September 30,			December 31,
$ in millions	2011			2010			2011			2010

ASSETS

Current assets:
Cash and cash equivalents	$	72.8		$	124.0		$	67.6		$	124.0
Short-term investments	—			69.3			—			69.3
Accounts receivable, net (Note 2)	201.8			215.5			203.2			215.5
Inventories (Note 2)	115.6			115.3			126.8			115.3
Taxes applicable to subsequent years	31.8			63.7			15.9			63.7
Other prepayments and current assets	69.4			40.6			68.6			40.6
Total current assets	491.4			628.4			482.1			628.4

Property, plant and equipment:
Property, plant and equipment	5,482.6			5,353.6			5,508.3			5,353.6
Less: Accumulated depreciation and amortization	(2,629.3		)	(2,555.2		)	(2,652.7		)	(2,555.2		)
	2,853.3			2,798.4			2,855.6			2,798.4

Construction work in process	112.3			119.7			118.6			119.7
Total net property, plant and equipment	2,965.6			2,918.1			2,974.2			2,918.1

Other noncurrent assets:
Regulatory assets (Note 3)	178.8			189.0			178.2			189.0
Other deferred assets	75.8			77.8			42.0			77.8
Total other noncurrent assets	254.6			266.8			220.2			266.8

Total Assets	$	3,711.6		$	3,813.3		$	3,676.5		$	3,813.3

	Three Months Ended June 30,						Three Months Ended September 30,
	2011			2010
$ in millions							2011			2010
Comprehensive income:
Net income	$	31.7		$	61.4		$	67.1		$	86.4
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
Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.2 million and income tax expense of $0.1 million, respectively							(0.3		)	0.3
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $24.9 million and $3.6 million, respectively							(46.6		)	(9.1		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax benefit of $0.1 million and income tax expense of $0.4 million, respectively							0.9			0.8
Comprehensive income	$	22.1		$	52.0		$	21.1		$	78.4

	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010
$ in millions							2011			2010
Comprehensive income:
Net income	$	75.2		$	132.4		$	142.3		$	218.8
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
Net change in unrealized gains (losses) on financial instruments, net of income tax benefit of $0.2 million and income tax expense of $0.1 million, respectively							(0.3		)	0.2
Net change in deferred gains (losses) on cash flow hedges, net of income tax benefit of $28.9 million and $6.0 million, respectively							(55.4		)	(14.7		)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense of $0.7 million and $0.3 million, respectively							2.5			3.4
Comprehensive income	$	68.0		$	129.3		$	89.1		$	207.7

			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

	DP&L Share		DP&L Investment							DP&L Share		DP&L Investment
									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	$	76	$	57	$	—	No
Conesville Unit 4	16.5	129	119		30		4		Yes	16.5	129	119		31		5		Yes
East Bend Station	31.0	186	201		132		—		Yes	31.0	186	201		132		—		Yes
Killen Station	67.0	402	617		294		2		Yes	67.0	402	617		298		2		Yes
Miami Fort Units 7 and 8	36.0	368	354		134		10		Yes	36.0	368	366		137		2		Yes
Stuart Station	35.0	808	719		274		17		Yes	35.0	808	719		275		15		Yes
Zimmer Station	28.1	365	1,060		620		15		Yes	28.1	365	1,060		624		18		Yes
Transmission (at varying percentages)		—	91		57		—				—	91		57		—
Total		2,465	$	3,236	$	1,596	$	49			2,465	$	3,249	$	1,611	$	42

Wholly-owned production unit:
Hutchings Station	100.0	390	$	124	$	113	$	1	No	100.0	390	$	124	$	114	$	1	No

(a)	Range of interest rates for the nine months ended September 30, 2011 and the twelve months ended December 31, 2010, respectively.

(b)	Range of interest rates since the loan was drawn in August 2011.

$ 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

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

	At June 30,				At December 31,				At September 30,				At December 31,
	2011				2010				2011				2010
$ 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	$	1.6	$	1.6
Equity Securities	3.5		4.2		3.8		4.4		3.9		4.0		3.8		4.4
Debt Securities	5.2		5.5		5.2		5.5		5.1		5.6		5.2		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.3		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	9.2	$	10.2	$	10.9	$	11.8	$	9.5	$	10.0	$	10.9	$	11.8

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

Total Assets	$	9.2	$	10.2	$	80.2	$	81.1	$	9.5	$	10.0	$	80.2	$	81.1

Liabilities
Debt	$	1,221.4	$	1,198.7	$	1,324.1	$	1,307.5	$	1,224.0	$	1,204.6	$	1,324.1	$	1,307.5


DP&L
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities (a)	16.9		33.7		17.5		30.2		17.3		33.5		17.5		30.2
Debt Securities	5.2		5.5		5.2		5.5		5.1		5.6		5.2		5.5
Multi-Strategy Fund	0.3		0.3		0.3		0.3		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	22.6	$	39.7	$	24.6	$	37.6	$	22.9	$	39.5	$	24.6	$	37.6

Liabilities
Debt	$	903.4	$	877.3	$	884.1	$	850.6	$	903.4	$	884.2	$	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	$	—

$ in millions	Fair Value at September 30, 2011		Fair Value at December 31, 2010		Unfunded Commitments		Redemption Frequency
Money Market Fund (a)	$	0.2	$	1.6	$	—	Immediate

Equity Securities (b)	4.0		4.4		—		Immediate

Debt Securities (c)	5.6		5.5		—		Immediate

Multi-Strategy Fund (d)	0.2		0.3		—		Immediate

Total	$	10.0	$	11.8	$	—

	Assets and Liabilities Measured at Fair Value on a Recurring Basis																Assets and Liabilities Measured at Fair Value on a Recurring Basis
				Level 1		Level 2			Level 3										Level 1		Level 2		Level 3					Fair Valueon
$ 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			Fair Value at September 30, 2011*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at September 30, 2011
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			4.0		—		4.0		—		—			4.0
Debt Securities	5.5			—		5.5			—		—			5.5			5.6		—		5.6		—		—			5.6
Multi-Strategy Fund	0.3			—		0.3			—		—			0.3			0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	10.2		$	—	$	10.2		$	—	$	—		$	10.2		$	10.0	$	—	$	10.0	$	—	$	—		$	10.0

Derivative Assets
FTRs	$	0.2		$	—	$	0.2		$	—	$	—		$	0.2		$	0.1	$	—	$	0.1	$	—	$	—		$	0.1
Heating Oil Futures	3.3			3.3		—			—		(3.3		)	—			1.7		1.7		—		—		(1.7		)	—
Interest Rate Hedge	18.6			—		18.6			—		—			18.6
Forward NYMEX Coal Contracts	24.4			—		24.4			—		(13.6		)	10.8			2.3		—		2.3		—		(1.2		)	1.1
Forward Power Contracts	12.9			—		12.9			—		(0.8		)	12.1			12.8		—		12.8		—		(2.0		)	10.8
Total Derivative Assets	$	59.4		$	3.3	$	56.1		$	—	$	(17.7	)	$	41.7		$	16.9	$	1.7	$	15.2	$	—	$	(4.9	)	$	12.0

Short-term Investments - Bonds	—			—		—			—		—			—			—		—		—		—		—			—
Total Short-term investments	$	—		$	—	$	—		$	—	$	—		$	—
Total Short-term Investments																	$	—	$	—	$	—	$	—	$	—		$	—

Total Assets	$	69.6		$	3.3	$	66.3		$	—	$	(17.7	)	$	51.9		$	26.9	$	1.7	$	25.2	$	—	$	(4.9	)	$	22.0

Liabilities
Derivative Liabilities
Interest Rate Hedge	$	(18.7	)	$	—	$	(18.7	)	$	—	$	—		$	(18.7	)
Interest Rate Hedges																	$	28.5	$	—	$	28.5	$	—	$	—		$	28.5
Forward NYMEX Coal Contracts	(0.5		)	—		(0.5		)	—		0.5			—			6.3		—		6.3		—		(6.3		)	—
Forward Power Contracts	(9.7		)	—		(9.7		)	—		3.5			(6.2		)	6.6		—		6.6		—		(2.6		)	4.0
Total Derivative Liabilities	$	(28.9	)	$	—	$	(28.9	)	$	—	$	4.0		$	(24.9	)	$	41.4	$	—	$	41.4	$	—	$	(8.9	)	$	32.5

Total Liabilities	$	(28.9	)	$	—	$	(28.9	)	$	—	$	4.0		$	(24.9	)	$	41.4	$	—	$	41.4	$	—	$	(8.9	)	$	32.5

	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	11.3	1.0		12.3
Heating Oil Futures (1)	Mark to Market	Gallons	4,578.0	—		4,578.0		Mark to Market	Gallons	3,654.0	—		3,654.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	927.2	(965.7	)	(38.5	)	Cash Flow Hedge	MWh	974.9	(746.5	)	228.4
Forward Power Contracts (1)	Mark to Market	MWh	446.9	(423.2	)	23.7		Mark to Market	MWh	587.0	(570.7	)	16.3
Forward Power Contracts (2)	Mark to Market	MWh	1,311.3	(1,338.7	)	(27.4	)	Mark to Market	MWh	1,365.2	(1,350.1	)	15.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	3,588.3	—		3,588.3		Mark to Market	Tons	2,658.3	—		2,658.3
Interest Rate Swaps (2)	Cash Flow Hedge	USD	460,000.0	—		460,000.0		Cash Flow Hedge	USD	160,000.0	—		160,000.0

								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	)

$ 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	)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	(0.3	)	$	(29.9	)
Realized gain / (loss)	1.4			0.6			0.2		(1.3		)	0.9			4.3			0.5			—			1.2			6.0
Total	$	(8.8	)	$	(0.8	)	$	0.3	$	(1.4	)	$	(10.7	)	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(5.0	)	$	—		$	—	$	—		$	(5.0	)	$	(13.8	)	$	—		$	—		$	—		$	(13.8	)
Regulatory (asset) / liability	(2.3		)	(0.9		)	—		—			(3.2		)	(4.0		)	(0.6		)	—			—			(4.6		)

Recorded in Income Statement: gain / (loss)
Retail revenue	$	—		$	—		$	—	$	(3.1	)	$	(3.1	)	$	—		$	—		$	—		$	(1.6	)	$	(1.6	)
Purchased power	—			—			0.3		1.7			2.0			—			—			(0.1		)	2.5			2.4
Fuel	(1.5		)	—			—		—			(1.5		)	(5.8		)	(0.5		)	—			—			(6.3		)
O&M	—			0.1			—		—			0.1			—			—			—			—			—
Total	$	(8.8	)	$	(0.8	)	$	0.3	$	(1.4	)	$	(10.7	)	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)

$ 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	6.1			(0.3		)	Other prepayments and current assets	5.8
Forward Power Contracts in a Liability position	(4.5		)	1.3			Other current liabilities	(3.2		)
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	$	17.0		$	(8.4	)		$	8.6

Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	6.2		$	(0.1	)	Other deferred assets	$	6.1
Forward Power Contracts in a Liability position	(2.2		)	1.1			Other deferred credits	(1.1		)
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	$	15.7		$	(6.0	)		$	9.7

Total MTM Position	$	32.7		$	(14.4	)		$	18.3

	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	—		—

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

Three Months Ended June 30, 2011
Three Months Ended September 30, 2011
Revenues from external customers	$	327.6	$	102.0	$	15.3		$	—		$	444.9	$	376.6	$	118.6	$	16.6		$	—		$	511.8
Intersegment revenues	81.0		—		1.0			(82.0		)	—		90.2		—		1.1			(91.3		)	—
Total revenues	$	408.6	$	102.0	$	16.3		$	(82.0	)	$	444.9	$	466.8	$	118.6	$	17.7		$	(91.3	)	$	511.8

Fuel	89.1		—		3.0			—			92.1		124.0		—		5.0			—			129.0
Purchased power	104.4		89.5		0.7			(81.0		)	113.6		95.6		101.4		1.5			(90.2		)	108.3

Gross margin	$	215.1	$	12.5	$	12.6		$	(1.0	)	$	239.2	$	247.2	$	17.2	$	11.2		$	(1.1	)	$	274.5

Depreciation and amortization	$	33.4	$	—	$	1.7		$	—		$	35.1	$	33.8	$	0.1	$	1.9		$	—		$	35.8
Interest expense	9.7		0.1		7.9			(0.1		)	17.6		9.3		0.1		7.6			(0.2		)	16.8
Income tax expense (benefit)	15.5		3.3		(2.5		)	—			16.3		26.8		4.2		(2.4		)	—			28.6
Net income (loss)	30.8		5.7		(3.7		)	(1.1		)	31.7		63.9		7.8		(6.2		)	1.6			67.1

Cash capital expenditures	48.4		—		—			—			48.4		49.1		—		0.8			—			49.9

Three Months Ended June 30, 2010

Three Months Ended September 30, 2010
Revenues from external customers	$	371.2	$	62.8	$	11.5		$	—		$	445.5	$	411.1	$	84.5	$	21.3		$	—		$	516.9
Intersegment revenues	52.7		—		1.1			(53.8		)	—		75.9		—		1.1			(77.0		)	—
Total revenues	$	423.9	$	62.8	$	12.6		$	(53.8	)	$	445.5	$	487.0	$	84.5	$	22.4		$	(77.0	)	$	516.9

Fuel	88.5		—		2.4			—			90.9		97.4		—		6.9			—			104.3
Purchased power	90.3		52.7		0.6			(52.7		)	90.9		116.4		75.9		2.6			(75.9		)	119.0

Gross margin	$	245.1	$	10.1	$	9.6		$	(1.1	)	$	263.7	$	273.2	$	8.6	$	12.9		$	(1.1	)	$	293.6

Depreciation and amortization	$	33.2	$	0.1	$	2.4		$	—		$	35.7	$	30.4	$	—	$	1.8		$	—		$	32.2
Interest expense	9.1		—		8.4			—			17.5		9.4		—		8.3			(0.1		)	17.6
Income tax expense (benefit)	28.4		3.1		(1.4		)	—			30.1		39.4		1.4		(0.4		)	—			40.4
Net income (loss)	59.4		5.0		(1.4		)	(1.6		)	61.4		83.2		4.7		(4.2		)	2.7			86.4

Cash capital expenditures	34.1		—		1.2			—			35.3		38.8		—		(0.2		)	—			38.6

	Nine Months Ended		Nine Months Ended
	September 30, 2011		September 30, 2010
	Electric Customers	Sales (in Millions of kWh)	Electric Customers	Sales (in Millions of kWh)

Supplied by DPLER	21,990	4,330	4,396	3,091
Supplied by non-affiliated CRES providers	19,285	566	426	75
Total supplied in our service territory	41,275	4,896	4,822	3,166

Supplied by DP&L in our service territory(a)	512,439	10,772	513,332	10,894

	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

													Three Months Ended						Nine Months Ended
	Three Months Ended June 30,						Six Months Ended June 30,						September 30,						September 30,
$ in millions	2011			2010			2011			2010			2011			2010			2011			2010

Revenues:
Retail	$	348.1		$	342.7		$	731.6		$	697.3		$	410.3		$	402.6		$	1,141.9		$	1,099.9
Wholesale	28.7			39.1			61.1			79.3			40.7			31.2			101.8			110.3
RTO revenues	19.5			20.1			40.9			41.2			22.3			23.4			63.2			64.6
RTO capacity revenues	49.7			40.4			105.0			72.7			37.3			57.0			142.3			129.7
Other revenues	2.9			3.2			5.7			6.2			2.8			2.7			8.5			8.9
Other mark to market losses	(4.0		)	—			(4.7		)	—
Other mark-to-market gains / (losses)													(1.6		)	—			(6.3		)	0.2
Total revenues	$	444.9		$	445.5		$	939.6		$	896.7		$	511.8		$	516.9		$	1,451.4		$	1,413.6

Cost of revenues:
Fuel costs	$	93.3		$	92.4		$	194.8		$	194.7		$	121.8		$	104.8		$	312.7		$	300.5
Gains from sale of coal	(1.2		)	(1.1		)	(2.9		)	(1.3		)	(3.9		)	(1.1		)	(6.8		)	(2.4		)
Gains from sale of emission allowances	—			(0.4		)	—			(0.6		)	—			(0.1		)	—			(0.7		)
Mark-to-market (gains) / losses													11.1			0.7			15.0			(0.3		)
Net fuel	92.1			90.9			191.9			192.8			129.0			104.3			320.9			297.1

Purchased power	39.5			21.3			75.5			35.0			39.7			26.5			120.3			61.2
RTO charges	27.1			26.7			56.4			51.4			34.5			33.3			90.9			84.6
RTO capacity charges	47.0			42.9			102.5			77.3			35.5			59.6			138.0			137.0
Mark-to-market (gains) / losses													(1.4		)	(0.4		)	(6.5		)	(0.1		)
Net purchased power	113.6			90.9			234.4			163.7			108.3			119.0			342.7			282.7

Total cost of revenues	$	205.7		$	181.8		$	426.3		$	356.5		$	237.3		$	223.3		$	663.6		$	579.8

Gross margins (a)	$	239.2		$	263.7		$	513.3		$	540.2		$	274.5		$	293.6		$	787.8		$	833.8

Gross margin as a percentage of revenues	53.8		%	59.2		%	54.6		%	60.2		%	54		%	57		%	54		%	59		%

Operating income	$	65.8		$	109.3		$	166.6		$	235.3		$	112.9		$	144.6		$	279.5		$	379.9

Earnings per share of common stock:
Basic EPS from operations	$	0.28		$	0.53		$	0.66		$	1.15		$	0.58		$	0.75		$	1.24		$	1.89
Diluted EPS from operations	$	0.28		$	0.53		$	0.66		$	1.14		$	0.58		$	0.74		$	1.24		$	1.88

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

Utility	$	215.1		$	245.1		$	(30.0	)	$	247.2		$	273.2		$	(26.0	)
Competitive Retail	12.5			10.1			2.4			17.2			8.6			8.6
Other	12.6			9.6			3.0			11.2			12.9			(1.7		)
Adjustments and Eliminations	(1.0		)	(1.1		)	0.1			(1.1		)	(1.1		)	—
Total consolidated	$	239.2		$	263.7		$	(24.5	)
Total Consolidated										$	274.5		$	293.6		$	(19.1	)