10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

OR

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

For the transition period from                to               

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-9052	DPL INC.	31-1163136
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-224-6000
1-2385	THE DAYTON POWER AND LIGHT COMPANY	31-0258470
	(An Ohio Corporation)
	1065 Woodman Drive Dayton, Ohio 45432
	937-224-6000

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

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

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

DPL Inc.	Yes 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 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	117,729,995
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.

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
		Electric Sales and Revenues	106
	Item 3	Quantitative and Qualitative Disclosures about Market Risk	107
	Item 4	Controls and Procedures	108

Part II Other Information
	Item 1	Legal Proceedings	108
	Item 1a	Risk Factors	109
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	111
	Item 3	Defaults Upon Senior Securities	111
	Item 4	Removed and Reserved	111
	Item 5	Other Information	112
	Item 6	Exhibits	112

Other
	Signatures	114
	Certifications	115

2

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 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

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
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, 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
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

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
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

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 noted in the section.

6

Item 1 – Financial Statements

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions except per share amounts	2011			2010			2011			2010
Revenues	$	511.8		$	516.9		$	1,451.4		$	1,413.6
Cost of revenues:
Fuel	129.0			104.3			320.9			297.1
Purchased power	108.3			119.0			342.7			282.7
Total cost of revenues	237.3			223.3			663.6			579.8
Gross margin	274.5			293.6			787.8			833.8
Operating expenses:
Operation and maintenance	92.0			84.2			298.2			252.3
Depreciation and amortization	35.8			32.2			106.0			105.3
General taxes	33.8			32.6			104.1			96.3
Total operating expenses	161.6			149.0			508.3			453.9
Operating income	112.9			144.6			279.5			379.9
Other income / (expense), net:
Investment income	0.1			0.3			0.3			0.6
Interest expense	(16.8		)	(17.6		)	(51.3		)	(53.0		)
Charge for early redemption of debt	—			—			(15.3		)	—
Other expense	(0.5		)	(0.5		)	(1.2		)	(1.8		)
Total other income / (expense), net	(17.2		)	(17.8		)	(67.5		)	(54.2		)
Earnings before income tax	95.7			126.8			212.0			325.7
Income tax expense	28.6			40.4			69.7			106.9
Net income	$	67.1		$	86.4		$	142.3		$	218.8
Average number of common shares outstanding (millions):
Basic	115.0			115.8			114.4			115.7
Diluted	115.5			116.3			115.0			116.2
Earnings per share of common stock:
Basic	$	0.58		$	0.75		$	1.24		$	1.89
Diluted	$	0.58		$	0.74		$	1.24		$	1.88
Dividends paid per share of common stock	$	0.3325		$	0.3025		$	0.9975		$	0.9075

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

7

DPL INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Cash flows from operating activities:
Net income	$	142.3		$	218.8
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	106.0			105.3
Deferred income taxes	70.5			38.7
Unamortized investment tax credit	(2.1		)	(2.1		)
Charge for early redemption of debt	15.3			—
Changes in certain assets and liabilities:
Accounts receivable	21.1			7.9
Inventories	(11.5		)	10.6
Prepaid taxes	(27.0		)	(0.9		)
Taxes applicable to subsequent years	47.7			44.2
Deferred regulatory costs, net	7.9			7.0
Accounts payable	(13.4		)	(4.7		)
Accrued taxes payable	(58.2		)	(58.1		)
Accrued interest payable	(3.1		)	(5.6		)
Pension, retiree and other benefits	(31.7		)	(54.6		)
Insurance and claims costs	4.1			(0.3		)
Other	(3.1		)	25.4
Net cash provided by operating activities	264.8			331.6
Cash flows from investing activities:
Capital expenditures	(141.3		)	(113.7		)
Purchase of MC Squared	(8.3		)	—
Purchases of short-term investments and securities	(1.7		)	(62.7		)
Sales of short-term investments and securities	70.9			14.4
Other	1.5			1.7
Net cash used for investing activities	(78.9		)	(160.3		)
Cash flows from financing activities:
Dividends paid on common stock	(113.8		)	(104.8		)
Early redemption of Capital Trust II debt	(122.0		)	—
Premium paid for early redemption of debt	(12.2		)	—
Payment of MC Squared debt	(13.5		)	—
Payment of long-term debt	(297.4		)	—
Issuance of long-term debt	300.0			—
Withdrawals from revolving credit facilities	50.0			—
Repayments of borrowings from revolving credit facilities	(50.0		)	—
Repurchase of DPL common stock	—			(3.9		)
Exercise of stock options	1.6			1.4
Exercise of warrants	14.7			—
Tax impact related to exercise of stock options	0.3			0.2
Net cash used for financing activities	(242.3		)	(107.1		)
Cash and cash equivalents:
Net change	(56.4		)	64.2
Balance at beginning of period	124.0			74.9
Cash and cash equivalents at end of period	$	67.6		$	139.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	49.4		$	59.6
Income taxes paid, net	$	25.5		$	60.8
Non-cash financing and investing activities:
Accruals for capital expenditures	$	14.8		$	14.1
Long-term liability incurred for purchase of assets	$	18.7		$	—

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

8

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	67.6		$	124.0
Short-term investments	—			69.3
Accounts receivable, net (Note 2)	203.2			215.5
Inventories (Note 2)	126.8			115.3
Taxes applicable to subsequent years	15.9			63.7
Other prepayments and current assets	68.6			40.6
Total current assets	482.1			628.4
Property, plant and equipment:
Property, plant and equipment	5,508.3			5,353.6
Less: Accumulated depreciation and amortization	(2,652.7		)	(2,555.2		)
	2,855.6			2,798.4
Construction work in process	118.6			119.7
Total net property, plant and equipment	2,974.2			2,918.1
Other noncurrent assets:
Regulatory assets (Note 3)	178.2			189.0
Other deferred assets	42.0			77.8
Total other noncurrent assets	220.2			266.8
Total Assets	$	3,676.5		$	3,813.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

9

DPL INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

			At			At
			September 30,			December 31,
$ in millions			2011			2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion - long-term debt (Note 5)			$	0.4		$	297.5
Accounts payable			82.2			98.7
Accrued taxes			72.4			68.1
Accrued interest			15.6			18.4
Customer security deposits			16.9			18.7
Other current liabilities			37.0			40.9
Total current liabilities			224.5			542.3
Noncurrent liabilities:
Long-term debt (Note 5)			1,223.6			1,026.6
Deferred taxes (Note 6)			670.0			625.4
Regulatory liabilities (Note 3)			133.1			124.0
Pension, retiree and other benefits			25.9			64.9
Unamortized investment tax credit			30.3			32.4
Insurance and claims costs			14.1			10.1
Other deferred credits			112.6			146.2
Total noncurrent liabilities			2,209.6			2,029.6
Redeemable preferred stock of subsidiary			22.9			22.9
Commitments and contingencies (Note 14)
Common shareholders’ equity:
Common stock, at par value of $0.01 per share:
	September 2011	December 2010
Shares authorized	250,000,000	250,000,000
Shares issued	163,724,211	163,724,211
Shares outstanding	117,724,111	116,924,844	1.2			1.2
Warrants			1.6			2.7
Common stock held by employee plans			(7.1		)	(12.5		)
Accumulated other comprehensive loss			(72.1		)	(18.9		)
Retained earnings			1,295.9			1,246.0
Total common shareholders’ equity			1,219.5			1,218.5
Total Liabilities and Shareholders’ Equity			$	3,676.5		$	3,813.3

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

10

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF RESULTS OF OPERATIONS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2011			2010			2011			2010
Revenues	$	466.8		$	487.0		$	1,339.2		$	1,348.9
Cost of revenues:
Fuel	124.0			97.4			311.7			286.5
Purchased power	95.6			116.4			317.8			279.3
Total cost of revenues	219.6			213.8			629.5			565.8
Gross margin	247.2			273.2			709.7			783.1
Operating expenses:
Operation and maintenance	80.2			78.7			266.7			243.4
Depreciation and amortization	33.8			30.4			100.3			98.4
General taxes	33.2			32.2			97.6			94.0
Total operating expenses	147.2			141.3			464.6			435.8
Operating income	100.0			131.9			245.1			347.3
Other income / (expense), net:
Investment income	0.4			0.4			1.5			1.3
Interest expense	(9.3		)	(9.4		)	(28.7		)	(27.9		)
Other expense	(0.4		)	(0.3		)	(1.2		)	(1.4		)
Total other income / (expense), net	(9.3		)	(9.3		)	(28.4		)	(28.0		)
Earnings before income tax	90.7			122.6			216.7			319.3
Income tax expense	26.8			39.4			69.3			104.6
Net income	63.9			83.2			147.4			214.7
Dividends on preferred stock	0.2			0.2			0.6			0.6
Earnings on common stock	$	63.7		$	83.0		$	146.8		$	214.1

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

11

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Cash flows from operating activities:
Net income	$	147.4		$	214.7
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	100.3			98.4
Deferred income taxes	56.1			36.9
Unamortized investment tax credit	(2.1		)	(2.1		)
Changes in certain assets and liabilities:
Accounts receivable	26.4			27.5
Inventories	(11.5		)	10.3
Prepaid taxes	(11.5		)	(0.9		)
Taxes applicable to subsequent years	47.1			44.0
Deferred regulatory costs, net	7.9			7.0
Accounts payable	(14.9		)	(6.1		)
Accrued taxes payable	(58.5		)	(55.6		)
Accrued interest payable	7.4			2.2
Pension, retiree and other benefits	(31.7		)	(54.6		)
Other	24.4			16.3
Net cash provided by operating activities	286.8			338.0
Cash flows from investing activities:
Capital expenditures	(139.9		)	(112.3		)
Other	1.4			1.7
Net cash used for investing activities	(138.5		)	(110.6		)
Cash flows from financing activities:
Dividends paid on common stock to parent	(180.0		)	(150.0		)
Dividends paid on preferred stock	(0.6		)	(0.6		)
Withdrawals from revolving credit facilities	50.0			—
Repayments of borrowings from revolving credit facilities	(50.0		)	—
Net cash used for financing activities	(180.6		)	(150.6		)
Cash and cash equivalents:
Net change	(32.3		)	76.8
Balance at beginning of period	54.0			57.1
Cash and cash equivalents at end of period	$	21.7		$	133.9
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	22.2		$	27.6
Income taxes paid, net	$	13.9		$	60.7
Non-cash financing and investing activities:
Accruals for capital expenditures	$	14.8		$	14.1
Long-term liability incurred for the purchase of assets	$	18.7		$	—

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

12

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	21.7		$	54.0
Accounts receivable, net (Note 2)	152.5			178.0
Inventories (Note 2)	125.6			114.2
Taxes applicable to subsequent years	15.7			62.8
Other prepayments and current assets	45.2			42.7
Total current assets	360.7			451.7
Property, plant and equipment:
Property, plant and equipment	5,243.8			5,093.7
Less: Accumulated depreciation and amortization	(2,545.2		)	(2,453.1		)
	2,698.6			2,640.6
Construction work in process	118.0			119.6
Total net property, plant and equipment	2,816.6			2,760.2
Other noncurrent assets:
Regulatory assets (Note 3)	178.2			189.0
Other deferred assets	64.2			74.5
Total other noncurrent assets	242.4			263.5
Total Assets	$	3,419.7		$	3,475.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

13

THE DAYTON POWER AND LIGHT COMPANY

CONDENSED BALANCE SHEETS

	At			At
	September 30,			December 31,
$ in millions	2011			2010
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities:
Current portion - long-term debt (Note 5)	$	0.4		$	0.1
Accounts payable	75.1			95.7
Accrued taxes	70.3			66.6
Accrued interest	15.5			7.7
Customer security deposits	16.9			18.7
Other current liabilities	33.8			33.6
Total current liabilities	212.0			222.4
Noncurrent liabilities:
Long-term debt (Note 5)	903.0			884.0
Deferred taxes (Note 6)	656.4			598.0
Regulatory liabilities (Note 3)	133.1			124.0
Pension, retiree and other benefits	25.9			64.9
Unamortized investment tax credit	30.3			32.4
Other deferred credits	84.4			147.3
Total noncurrent liabilities	1,833.1			1,850.6
Redeemable preferred stock	22.9			22.9
Commitments and contingencies (Note 14)
Common shareholder’s equity:
Common stock, at par value of $0.01 per share	0.4			0.4
Other paid-in capital	782.8			782.4
Accumulated other comprehensive loss	(15.1		)	(20.2		)
Retained earnings	583.6			616.9
Total common shareholder’s equity	1,351.7			1,379.5
Total Liabilities and Shareholder’s Equity	$	3,419.7		$	3,475.4

See Notes to Condensed Consolidated Financial Statements.

These interim statements are unaudited.

14

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 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 1,528 people as of September 30, 2011, of which 1,497 employees were employed by DP&L.  Approximately 53% of all employees are under a collective bargaining agreement which expires on 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.

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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.

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 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 September 30, 2011; our results of operations for the three and nine months ended September 30, 2011; and our cash flows for the nine months ended 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 nine months ended 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 nine months ended September 30, 2011 and 2010 was not material.

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

Depreciation Study — Change in Estimate

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life.  For DPL’s generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates.  In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions.  The results of the depreciation study concluded that many of DPL’s composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated.  DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense.  For the nine months ended September 30, 2011, the reduction was $4.8 million ($3.1 million, net of tax) and increased diluted EPS by approximately $0.03 per share.  The net reduction in depreciation expense for the twelve months ended September 30, 2011 was $7.2 million ($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’scurrent 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				Nine Months Ended
	September 30,				September 30,
$ in millions	2011		2010		2011		2010
State/Local excise taxes	$	14.3	$	14.6	$	39.9	$	40.1

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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						Nine Months Ended
	September 30,						September 30,
$ in millions	2011			2010			2011			2010
DP&L Revenues:
Sales to DPLER (a)	$	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	)	$	(2.4	)	$	(2.5	)
Expense recoveries for services provided to DPLER (c)	$	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 nine months ended 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.  It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts.  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.

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2.     Supplemental Financial Information and Comprehensive Income

DPL Inc.

	At			At
	September 30,			December 31,
$ in millions	2011			2010
Accounts receivable, net:
Unbilled revenue	$	60.0		$	84.5
Customer receivables	124.7			113.9
Amounts due from partners in jointly-owned plants	10.8			7.0
Coal sales	3.8			4.0
Other	5.2			7.0
Provision for uncollectible accounts	(1.3		)	(0.9		)
Total accounts receivable, net	$	203.2		$	215.5
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies	39.7			38.8
Other	6.7			3.3
Total inventories, at average cost	$	126.8		$	115.3

DP&L

	At			At
	September 30,			December 31,
$ in millions	2011			2010
Accounts receivable, net:
Unbilled revenue	$	38.0		$	64.3
Customer receivables	97.4			95.6
Amounts due from partners in jointly-owned plants	10.8			7.0
Coal sales	3.8			4.0
Other	3.5			7.9
Provision for uncollectible accounts	(1.0		)	(0.8		)
Total accounts receivable, net	$	152.5		$	178.0
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies	38.5			37.7
Other	6.7			3.3
Total inventories, at average cost	$	125.6		$	114.2

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Supplemental Financial Information and Comprehensive Income (continued)

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

DPL Inc.

	Three Months Ended September 30,
$ in millions	2011			2010
Comprehensive income:
Net income	$	67.1		$	86.4
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	$	21.1		$	78.4

 DP&L

	Three Months Ended September 30,
$ in millions	2011			2010
Comprehensive income:
Net income	$	63.9		$	83.2
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	$	65.8		$	85.6

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

DPL Inc.

	Nine Months Ended September 30,
$ in millions	2011			2010
Comprehensive income:
Net income	$	142.3		$	218.8
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		)	0.2
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	$	89.1		$	207.7

 DP&L

	Nine Months Ended September 30,
$ in millions	2011		2010
Comprehensive income:
Net income	$	147.4	$	214.7
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	$	152.5	$	217.1

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3.  Regulatory Matters

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

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

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.  On October 26, 2011, the PUCO approved our Economic Development 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:

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.

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

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

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.

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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 but there is some uncertainty as to the costs that will be recovered from or returned to customers.  Independent third parties conducted the fuel audit in accordance with PUCO standards.  On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the majority of the issues raised by the auditor.  On October 19, 2011, we had a hearing on this case.  Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation.  DP&L expects to record a favorable or unfavorable adjustment to earnings after the 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 September 30, 2011, we had $42 million of construction work in process at such facilities.  DP&L’s share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L’s share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

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

	DP&L Share		DP&L Investment
									SCR and FGD
									Equipment
		Summer					Construction		Installed
		Production	Gross Plant		Accumulated		Work in		and In
	Ownership	Capacity	In Service		Depreciation		Process		Service
	(%)	(MW)	($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	207	$	76	$	57	$	—	No
Conesville Unit 4	16.5	129	119		31		5		Yes
East Bend Station	31.0	186	201		132		—		Yes
Killen Station	67.0	402	617		298		2		Yes
Miami Fort Units 7 and 8	36.0	368	366		137		2		Yes
Stuart Station	35.0	808	719		275		15		Yes
Zimmer Station	28.1	365	1,060		624		18		Yes
Transmission (at varying percentages)		—	91		57		—
Total		2,465	$	3,249	$	1,611	$	42
Wholly-owned production unit:
Hutchings Station	100.0	390	$	124	$	114	$	1	No

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On July 15, 2011, Duke Energy, a co-owner at the Beckjord Unit 6 facility, filed their Long-term Forecast Report with the PUCO.  The plan indicated that Duke Energy plans to cease production at the Beckjord Station, including our jointly-owned Unit 6, in December 2014.  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.

5.   Debt Obligations

Long-term Debt

	At			At
	September 30,			December 31,
$ in millions	2011			2010
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%	35.3			35.3
Pollution control series maturing in January 2034 - 4.80%	179.1			179.1
Pollution control series maturing in September 2036 - 4.80%	100.0			100.0
Pollution control series maturing in November 2040 - variable rates: 0.06% - 0.29% and 0.16% - 0.36% (a)	100.0			100.0
U.S. Government note maturing in February 2061 - 4.20%	18.5			—
	902.9			884.4
Obligation for capital lease	0.5			0.1
Unamortized debt discount	(0.4		)	(0.5		)
Total long-term debt - DP&L	$	903.0		$	884.0
DPL
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
Total long-term debt - DPL	$	1,223.6		$	1,026.6

Current portion - Long-term Debt

	At		At
	September 30,		December 31,
$ in millions	2011		2010
DP&L
U.S. Government note maturing in February 2061 - 4.20%	$	0.1	$	—
Obligation for capital lease	0.3		0.1
Total current portion - long-term debt - DP&L	$	0.4	$	0.1
DPL
Senior notes maturing in September 2011 - 6.875%	—		297.4
Total current portion - long-term debt - DPL	$	0.4	$	297.5

(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.

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At 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	$	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 Dolphin Subsidiary II, Inc., a subsidiary of AES,  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 may reduce DPL’s ratings to below investment grade upon assumption by DPL of the additional debt 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 was terminated by DP&L 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 nine months ended 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 September 30, 2011.  Fees associated with this credit facility were not material during the three and nine months ended September 30, 2011.  The fees and interest rate associated with this facility 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 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.

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.

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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.

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6.   Income Taxes

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
DPL	29.8	%	31.9	%	32.9	%	32.8	%
DP&L	29.6	%	32.1	%	32.0	%	32.8	%

Income tax expenses for the three and nine months ended 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 33.2% and 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 September 30, 2011, 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 of $2.0 million recorded as a result of the acquisition of MC Suared.

For the three and nine months ended September 30, 2011, DP&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 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 provision adjustments related to the Section 199 Domestic Production Deduction, ESOP related deductions and flow-through related deductions.

For the nine months ended September 30, 2011, the increase in DPL’s current period effective tax rate compared to the same period in 2010 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 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 $38.8 million and $56.0 million, respectively, during the nine months ended 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, 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 September 30, 2011, DPL has incurred approximately $8.9 million in certain costs that are directly associated with the Proposed Merger, which may be deemed as non-deductible, resulting in approximately $3.1 million of additional tax expense for the period in which the transaction occurs.

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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 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.

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 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 $40.0 million to the defined benefit plan 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 September 30, 2011 and 2010 was:

Net Periodic Benefit Cost / (Income)	Pension						Postretirement
$ in millions	2011			2010			2011			2010
Service cost	$	0.8		$	1.0		$	—		$	0.1
Interest cost	4.1			4.5			0.2			0.3
Expected return on assets (a)	(6.2		)	(5.6		)	(0.1		)	—
Amortization of unrecognized:
Actuarial (gain) / loss	1.7			2.0			(0.5		)	(0.2		)
Prior service cost	0.5			0.9			0.1			—
Net periodic benefit cost / (income) before adjustments	$	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 $317 million.

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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, Net of Medicare Part D Reimbursements

$ in millions	Pension		Postretirement
2011	$	5.3	$	0.6
2012	$	23.1	$	2.4
2013	$	23.1	$	2.4
2014	$	23.6	$	2.3
2015	$	24.0	$	2.1
2016 - 2020	$	122.9	$	8.8

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8.  Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The fair value of our financial instruments represents estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at September 30, 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 September 30,				At December 31,
	2011				2010
$ in millions	Cost		Fair Value		Cost		Fair Value
DPL
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities	3.9		4.0		3.8		4.4
Debt Securities	5.1		5.6		5.2		5.5
Multi-Strategy Fund	0.3		0.2		0.3		0.3
Total Master Trust Assets	$	9.5	$	10.0	$	10.9	$	11.8
Short-term Investments - VRDNs	$	—	$	—	$	54.2	$	54.2
Short-term Investments - Bonds	—		—		15.1		15.1
Total Short-term Investments	$	—	$	—	$	69.3	$	69.3
Total Assets	$	9.5	$	10.0	$	80.2	$	81.1
Liabilities
Debt	$	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
Equity Securities (a)	17.3		33.5		17.5		30.2
Debt Securities	5.1		5.6		5.2		5.5
Multi-Strategy Fund	0.3		0.2		0.3		0.3
Total Master Trust Assets	$	22.9	$	39.5	$	24.6	$	37.6
Liabilities
Debt	$	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 at 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 as debt is presented at amortized cost in the Condensed Consolidated Financial Statements.  The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2061.

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

DPL had $0.5 million ($0.3 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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 $16.6 million ($10.8 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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’scurrent 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.

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Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 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 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 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 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 nine months ended September 30, 2011.

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The fair value of assets and liabilities at 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
			Level 1		Level 2		Level 3					Fair Valueon
$ in millions	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
Equity Securities	4.0		—		4.0		—		—			4.0
Debt Securities	5.6		—		5.6		—		—			5.6
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	10.0	$	—	$	10.0	$	—	$	—		$	10.0
Derivative Assets
FTRs	$	0.1	$	—	$	0.1	$	—	$	—		$	0.1
Heating Oil Futures	1.7		1.7		—		—		(1.7		)	—
Forward NYMEX Coal Contracts	2.3		—		2.3		—		(1.2		)	1.1
Forward Power Contracts	12.8		—		12.8		—		(2.0		)	10.8
Total Derivative Assets	$	16.9	$	1.7	$	15.2	$	—	$	(4.9	)	$	12.0
Short-term Investments - Bonds	—		—		—		—		—			—
Total Short-term Investments	$	—	$	—	$	—	$	—	$	—		$	—
Total Assets	$	26.9	$	1.7	$	25.2	$	—	$	(4.9	)	$	22.0
Liabilities
Derivative Liabilities
Interest Rate Hedges	$	28.5	$	—	$	28.5	$	—	$	—		$	28.5
Forward NYMEX Coal Contracts	6.3		—		6.3		—		(6.3		)	—
Forward Power Contracts	6.6		—		6.6		—		(2.6		)	4.0
Total Derivative Liabilities	$	41.4	$	—	$	41.4	$	—	$	(8.9	)	$	32.5
Total Liabilities	$	41.4	$	—	$	41.4	$	—	$	(8.9	)	$	32.5

*Includes credit valuation adjustments for counterparty risk.

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DPL

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2010*		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities	4.4		—		4.4		—		—			4.4
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	11.8	$	—	$	11.8	$	—	$	—		$	11.8
Derivative Assets
FTRs	$	0.3	$	—	$	0.3	$	—	$	—		$	0.3
Heating Oil Futures	1.6		1.6		—		—		(1.6		)	—
Interest Rate Hedge	20.7		—		20.7		—		—			20.7
Forward NYMEX Coal Contracts	37.5		—		37.5		—		(21.9		)	15.6
Forward Power Contracts	0.2		—		0.2		—		(0.2		)	—
Total Derivative Assets	$	60.3	$	1.6	$	58.7	$	—	$	(23.7	)	$	36.6
Short-term Investments - VRDNs	$	54.2	$	—	$	54.2	$	—	$	—		$	54.2
Short-term Investments - Bonds	15.1		—		15.1		—		—			15.1
Total Short-term Investments	$	69.3	$	—	$	69.3	$	—	$	—		$	69.3
Total Assets	$	141.4	$	1.6	$	139.8	$	—	$	(23.7	)	$	117.7
Liabilities
Derivative Liabilities
Interest Rate Hedges	$	6.6	$	—	$	6.6	$	—	$	—		$	6.6
Forward Power Contracts	3.1		—		3.1		—		(1.1		)	2.0
Total Derivative Liabilities	$	9.7	$	—	$	9.7	$	—	$	(1.1	)	$	8.6
Total Liabilities	$	9.7	$	—	$	9.7	$	—	$	(1.1	)	$	8.6

*Includes credit valuation adjustments for counterparty risk.

34

The fair value of assets and liabilities at 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
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	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
Equity Securities (a)	33.5		29.5		4.0		—		—			33.5
Debt Securities	5.6		—		5.6		—		—			5.6
Multi-Strategy Fund	0.2		—		0.2		—		—			0.2
Total Master Trust Assets	$	39.5	$	29.5	$	10.0	$	—	$	—		$	39.5
Derivative Assets
FTRs	$	0.1	$	—	$	0.1	$	—	$	—		$	0.1
Heating Oil Futures	1.7		1.7		—		—		(1.7		)	—
Forward NYMEX Coal Contracts	2.3		—		2.3		—		(1.2		)	1.1
Forward Power Contracts	3.2		—		3.2		—		(2.4		)	0.8
Total Derivative Assets	$	7.3	$	1.7	$	5.6	$	—	$	(5.3	)	$	2.0
Total Assets	$	46.8	$	31.2	$	15.6	$	—	$	(5.3	)	$	41.5
Liabilities
Derivative Liabilities
Forward NYMEX Coal Contracts	$	6.3	$	—	$	6.3	$	—	$	(6.3	)	$	—
Forward Power Contracts	2.8		—		2.8		—		(1.4		)	1.4
Total Derivative Liabilities	$	9.1	$	—	$	9.1	$	—	$	(7.7	)	$	1.4
Total Liabilities	$	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
			Level 1		Level 2		Level 3					Fair Value on
$ in millions	Fair Value at December 31, 2010		Based on Quoted Prices in Active Markets		Other Observable Inputs		Unobservable Inputs		Collateral and Counterparty Netting			Balance Sheet at December 31, 2010
Assets
Master Trust Assets
Money Market Funds	$	1.6	$	—	$	1.6	$	—	$	—		$	1.6
Equity Securities (a)	30.2		25.8		4.4		—		—			30.2
Debt Securities	5.5		—		5.5		—		—			5.5
Multi-Strategy Fund	0.3		—		0.3		—		—			0.3
Total Master Trust Assets	$	37.6	$	25.8	$	11.8	$	—	$	—		$	37.6
Derivative Assets
FTRs	$	0.3	$	—	$	0.3	$	—	$	—		$	0.3
Heating Oil Futures	1.6		1.6		—		—		(1.6		)	—
Forward NYMEX Coal Contracts	37.5		—		37.5		—		(21.9		)	15.6
Forward Power Contracts	0.2		—		0.2		—		(0.2		)	—
Total Derivative Assets	$	39.6	$	1.6	$	38.0	$	—	$	(23.7	)	$	15.9
Total Assets	$	77.2	$	27.4	$	49.8	$	—	$	(23.7	)	$	53.5
Liabilities
Derivative Liabilities
Forward Power Contracts	$	3.1	$	—	$	3.1	$	—	$	(1.1	)	$	2.0
Total Derivative Liabilities	$	3.1	$	—	$	3.1	$	—	$	(1.1	)	$	2.0
Total Liabilities	$	3.1	$	—	$	3.1	$	—	$	(1.1	)	$	2.0

*Includes credit valuation adjustments for counterparty risk.

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

35

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 98% and 87% of the inputs to the fair value of our derivative instruments are from quoted market 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 nine months ended September 30, 2011.

Cash Equivalents

DPL had no money in money market funds at September 30, 2011 and $29.9 million in money market funds at December 31, 2010 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 September 30, 2011, 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	11.3	1.0		12.3
Heating Oil Futures (1)	Mark to Market	Gallons	3,654.0	—		3,654.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	974.9	(746.5	)	228.4
Forward Power Contracts (1)	Mark to Market	MWh	587.0	(570.7	)	16.3
Forward Power Contracts (2)	Mark to Market	MWh	1,365.2	(1,350.1	)	15.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	2,658.3	—		2,658.3
Interest Rate Swaps (2)	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.

36

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 September 30, 2011, we have outstanding interest rate hedging relationships with aggregate notional amounts of $160 million related to planned future borrowing activities in calendar year 2013.  During the three months ended September 30, 2011, 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 entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL’s 6.875% debt that was due in September 2011.  The remainder 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 $3.1 million ($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 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.

37

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	12.3		$	—		$	7.7
Net gains / (losses) associated with current period hedging transactions	1.8			(49.8		)	(0.4		)	(8.9		)
Net (gains) / losses reclassified to earnings
Interest expense	—			1.4			—			(0.6		)
Revenues	0.1			—			0.8			—
Purchased power	—			—			—			—
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	—			3.1
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.

38

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

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	11.0		$	—		$	13.5
Net gains / (losses) associated with current period hedging transactions	1.8			—			(0.4		)	—
Net (gains) / losses reclassified to earnings
Interest expense	—			(0.6		)	—			(0.6		)
Revenues	0.1			—			0.8			—
Purchased power	—			—			—			—
Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the ineffective portion of the hedging transaction
Interest expense	—			—
Revenues	—			—
Portion expected to be reclassified to earnings in the next twelve months*	$	0.8		$	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			—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate

above due to market price changes.

40

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the nine months ended September 30, 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	)	$	12.3		$	(1.4	)	$	14.7
Net gains / (losses) associated with current period hedging transactions	0.8			—			3.3			—
Net (gains) / losses reclassified to earnings
Interest expense	—			(1.9		)	—			(1.8		)
Revenues	0.8			—			(1.5		)	—
Purchased power	0.6			—			—			—
Ending accumulated derivative gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the ineffective portion of the hedging transaction
Interest expense	—			—
Revenues	—			—
Portion expected to be reclassified to earnings in the next twelve months*	$	0.8		$	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			—

*The actual amounts that we reclassify from AOCI to earnings related to power can differ from the estimate

above due to market price changes.

41

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

Fair Values of Derivative Instruments Designated as Hedging Instruments

at 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	(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
$ 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	)
Interest Rate Hedges in a Liability Position	(6.6		)	—			Other current liabilities	(6.6		)
Total short-term cash flow hedges	$	(9.4	)	$	1.0			$	(8.4	)
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		)
Interest Rate Hedges in an Asset Position	20.7			—			Other deferred assets	20.7
Total long-term cash flow hedges	$	20.7		$	(0.1	)		$	20.6
Total cash flow hedges	$	11.3		$	0.9			$	12.2

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

42

The following tables show the fair value and balance sheet classification of DP&L’s derivative instruments designated as hedging instruments at September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments

at September 30, 2011

DP&L

								Fair Value on
$ in millions	Fair Value(1)			Netting(2)			Balance Sheet Location	Balance Sheet
Short-term Derivative Positions
Forward Power Contracts in an Asset Position	$	0.3		$	(0.3	)	Other prepayments and current assets	$	—
Forward Power Contracts in a Liability Position	(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	(0.1		)	0.1			Other deferred credits	—
Total long-term cash flow hedges	$	1.3		$	(0.9	)		$	0.4
Total cash flow hedges	$	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 Accounting

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

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

43

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	(0.3	)	$	(29.9	)
Realized gain / (loss)	4.3			0.5			—			1.2			6.0
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(13.8	)	$	—		$	—		$	—		$	(13.8	)
Regulatory (asset) / liability	(4.0		)	(0.6		)	—			—			(4.6		)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	—		$	—		$	—		$	(1.6	)	$	(1.6	)
Purchased power	—			—			(0.1		)	2.5			2.4
Fuel	(5.8		)	(0.5		)	—			—			(6.3		)
O&M	—			—			—			—			—
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)

For the three months ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)	0.6			(0.4		)	(0.4		)	—		(0.2		)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(1.6	)	$	—		$	—		$	—	$	(1.6	)
Regulatory (asset) / liability	(1.0		)	0.7			—			—		(0.3		)
Recorded in Income Statement: gain / (loss)
Purchased power	$	—		$	—		$	(0.5	)	$	0.5	$	—
Fuel	(0.6		)	0.2			—			—		(0.4		)
O&M	—			—			—			—		—
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

44

For the nine months ended September 30, 2011

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	—	$	(0.1	)	$	0.6		$	(41.1	)
Realized gain / (loss)	8.1			1.5		(0.6		)	(0.8		)	8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(21.2	)	$	—	$	—		$	—		$	(21.2	)
Regulatory (asset) / liability	(5.9		)	0.1		—			—			(5.8		)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	—		$	—	$	—		$	(6.3	)	$	(6.3	)
Purchased power	—			—		(0.7		)	6.1			5.4
Fuel	(6.4		)	1.3		—			—			(5.1		)
O&M	—			0.1		—			—			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)

For the nine months ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)	1.6			(1.5		)	(1.4		)	(0.1		)	(1.4		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	0.2		$	—		$	—		$	—		$	0.2
Regulatory (asset) / liability	(0.6		)	0.6			—			—			—
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	—		$	—		$	—		$	(0.1	)	$	(0.1	)
Purchased power	—			—			(1.8		)	0.7			(1.1		)
Fuel	1.0			(0.5		)	—			—			0.5
O&M	—			(0.1		)	—			—			(0.1		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	(0.6	)

45

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	0.3		$	(29.3	)
Realized gain / (loss)	4.3			0.5			—			(0.3		)	4.5
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	—		$	(24.8	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(13.8	)	$	—		$	—		$	—		$	(13.8	)
Regulatory (asset) / liability	(4.0		)	(0.6		)	—			—			(4.6		)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	—		$	—		$	—		$	(0.1	)	$	(0.1	)
Purchased power	—			—			(0.1		)	0.1			—
Fuel	(5.8		)	(0.5		)	—			—			(6.3		)
O&M	—			—			—			—			—
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	—		$	(24.8	)

For the three months ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)	0.6			(0.4		)	(0.4		)	—		(0.2		)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(1.6	)	$	—		$	—		$	—	$	(1.6	)
Regulatory (asset) / liability	(1.0		)	0.7			—			—		(0.3		)
Recorded in Income Statement: gain / (loss)
Purchased power	$	—		$	—		$	(0.5	)	$	0.5	$	—
Fuel	(0.6		)	0.2			—			—		(0.4		)
O&M	—			—			—			—		—
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

46

For the nine months ended September 30, 2011

$ in millions	NYMEX Coal			Heating Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	—	$	(0.1	)	$	—		$	(41.7	)
Realized gain / (loss)	8.1			1.5		(0.6		)	(0.8		)	8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	(21.2	)	$	—	$	—		$	—		$	(21.2	)
Regulatory (asset) / liability	(5.9		)	0.1		—			—			(5.8		)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	—		$	—	$	—		$	(0.2	)	$	(0.2	)
Purchased power	—			—		(0.7		)	(0.6		)	(1.3		)
Fuel	(6.4		)	1.3		—			—			(5.1		)
O&M	—			0.1		—			—			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)

For the nine months ended September 30, 2010

$ in millions	NYMEX Coal			Heating Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)	1.6			(1.5		)	(1.4		)	(0.1		)	(1.4		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner’s share of gain / (loss)	$	0.2		$	—		$	—		$	—		$	0.2
Regulatory (asset) / liability	(0.6		)	0.6			—			—			—
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	—		$	—		$	—		$	(0.1	)	$	(0.1	)
Purchased power	—			—			(1.8		)	0.7			(1.1		)
Fuel	1.0			(0.5		)	—			—			0.5
O&M	—			(0.1		)	—			—			(0.1		)
Total	$	0.6		$	—		$	(1.8	)	$	0.6		$	(0.6	)

47

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 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	0.7			(0.6		)	Other prepayments and current assets	0.1
Forward Power Contracts in a Liability position	(0.7		)	0.6			Other current liabilities	(0.1		)
NYMEX-Quality Coal Forwards in an Asset position	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	1.7			(1.7		)	Other prepayments and current assets	—
Total short-term derivative MTM positions	$	1.6		$	(0.8	)		$	0.8
Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.8		$	(0.5	)	Other deferred assets	$	0.3
Forward Power Contracts in a Liability position	(0.9		)	0.5			Other deferred credits	(0.4		)
NYMEX-Quality Coal Forwards in an Asset position	0.7			(0.3		)	Other deferred assets	0.4
NYMEX-Quality Coal Forwards in a Liability position	(4.5		)	4.5			Other deferred credits	—
Total long-term derivative MTM positions	$	(3.9	)	$	4.2			$	0.3
Total MTM Position	$	(2.3	)	$	3.4			$	1.1

(1) Includes credit valuation adjustment.

(2) Includes counterparty and collateral netting.

48

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 September 30, 2011 is $13.1 million.  This amount is offset by $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 $2.1 million.  If our debt were to fall below investment grade, we would have to post collateral for the remaining $4.1 million.

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

10.  Share-Based Compensation

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

49

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

	Options			RSUs			Performance Shares
	2011		2010	2011	2010		2011	2010
Outstanding at beginning of period	500		351,500	—	3,311		296,591	307,985
Granted	—		—	—	—		—	—
Dividends	—		—	—	—		—	—
Exercised	(500	)	—	—	(3,311	)	—	—
Expired	—		—	—	—		—	—
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 period	284,237		249,101		111,298		110,706
Granted	—		2,617		—		—
Dividends	—		—		—		—
Exercised	(25,585	)	(1,800	)	—		—
Expired	—		—		—		—
Forfeited	—		(7,635	)	(2,340	)	(1,494	)
Outstanding at period end	258,652		242,283		108,958		109,212
Exercisable at period end	—		—		—		—

	Director RSUs
	2011		2010
Outstanding at beginning of period	—		15,944
Granted	14,392		—
Dividends accrued	634		655
Exercised and issued	—		—
Exercised and deferred	(634	)	(471	)
Forfeited	—		—
Outstanding at period end	14,392		16,128
Exercisable at period end	—		—

50

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 117,724,111 are outstanding at September 30, 2011.

On October 27, 2010, the DPL Board of Directors approved a 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 nine months ended September 30, 2011.  At 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

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.

Pursuant to the warrant agreement, DPL has authorized common shares sufficient to provide for the exercise in full of all outstanding warrants.  At 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 nine months ended 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 September 30,
	2011					2010
$ and shares in millions except				Per					Per
per share amounts	Income		Shares	Share		Income		Shares	Share
Basic EPS	$	67.1	115.0	$	0.58	$	86.4	115.8	$	0.75
Effect of Dilutive Securities:
Warrants			0.3					0.3
Stock options, performance and restricted shares			0.2					0.2
Diluted EPS	$	67.1	115.5	$	0.58	$	86.4	116.3	$	0.74

52

	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 nine months ended 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 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 September 30, 2011, DPL had $86.7 million of guarantees to third parties for future financial or performance assurance under such agreements including $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 $0.5 million and $1.7 million at 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.

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DP&L — Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP.  As of September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or $61.0 million, of a $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 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 changes in our debt as discussed in Note 5 of Notes to Condensed Consolidated Financial Statements.

Contingencies

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

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Environmental Matters Related to Air Quality

Clean Air Act Compliance

In 1990, the federal government amended the CAA to further regulate air pollution.  Under the 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 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.

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 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 were distributed in the fourth quarter of 2011.

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We are in the process of reviewing the rule, and are currently unable to predict the ultimate financial effect. We do not believe the rule will have a material impact on our operations in 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.

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 was 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 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.

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There is a possibility that these areas will be re-designated as “attainment” for PM 2.5 within the 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.  On September 2, 2011, the USEPA decided to 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.

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 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 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 to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions.  This reporting rule will guide development of policies and programs to reduce emissions.  DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

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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 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.

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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.  More than five years have passed since the malfunction was reported and management does not believe that there will be a resolution of this matter 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 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 this issue.

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.  We submitted comments to the proposed regulations on August 17, 2011.  The final rules are expected to be in place by mid-2012.  We do not yet know the impact these proposed rules will have on our operations.

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.

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In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit.  In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA.  In September 2010, the USEPA formally objected to a revised Permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation.  In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011.  We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011.  In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA.  This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA’s objection, then the authority for issuing the permit will pass to the USEPA.  DP&L is unable to predict the timing for issuance of a final 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 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.

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On April 7, 2010, the USEPA published an Advance Notice of Proposed Rulemaking (ANPRM) announcing that it is reassessing existing regulations governing the use and distribution in commerce of polychlorinated biphenyls (PCB).  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 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 responded to the USEPA final inspection report with plans to address the recommendations.  DP&L is unable to predict whether there will be additional USEPA action relative to DP&L’s proposed plan or the effect on operations that might arise under a different plan.

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

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&L submitted 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.

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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.

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 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.  DP&L recently underwent an audit of its fuel and purchased power recovery rider but there is some uncertainty as to the costs that will be 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 majority of the issues raised by the auditor.  On October 19, 2011, we had a hearing on this case.  Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation.  DP&L expects to record a favorable or unfavorable adjustment to earnings after the 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 became 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 October 26, 2011, the PUCO approved our Economic Development Rider, as filed, which is designed to recover costs associated with this and other economic development contracts and programs.

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Legal and Other Matters

In February 2007, DP&L filed a lawsuit against a coal supplier seeking damages incurred due to the supplier’s failure to supply approximately 1.5 million tons of coal to two jointly owned plants under a coal supply agreement, of which approximately 570 thousand tons was DP&L’s share.  DP&L obtained replacement coal to meet its needs.  The supplier has denied liability, and is currently in federal bankruptcy proceedings 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 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 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.  On September 30, 2011, the FERC issued two SECA-related orders that affirmed an earlier order issued in 2010 by denying the rehearing requests that a number of different parties, including DP&L, had filed.  These orders are now final, subject to possible appellate court review.  These orders do not affect prior settlements that had been reached with other parties that owed SECA revenues to DP&L or were recipients of amounts paid by DP&L.  For other parties that had not previously settled with DP&L, the exact timing and amounts of any payments that would be made or received by DP&L under these orders is still uncertain.

Refer to Note 16 of Notes to Condensed Consolidated Financial Statements for additional information surrounding the Proposed Merger and any related legal matters.

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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 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 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 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.

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

$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL Consolidated
Three Months Ended September 30, 2011
Revenues from external customers	$	376.6	$	118.6	$	16.6		$	—		$	511.8
Intersegment revenues	90.2		—		1.1			(91.3		)	—
Total revenues	$	466.8	$	118.6	$	17.7		$	(91.3	)	$	511.8
Fuel	124.0		—		5.0			—			129.0
Purchased power	95.6		101.4		1.5			(90.2		)	108.3
Gross margin	$	247.2	$	17.2	$	11.2		$	(1.1	)	$	274.5
Depreciation and amortization	$	33.8	$	0.1	$	1.9		$	—		$	35.8
Interest expense	9.3		0.1		7.6			(0.2		)	16.8
Income tax expense (benefit)	26.8		4.2		(2.4		)	—			28.6
Net income (loss)	63.9		7.8		(6.2		)	1.6			67.1
Cash capital expenditures	49.1		—		0.8			—			49.9
Three Months Ended September 30, 2010
Revenues from external customers	$	411.1	$	84.5	$	21.3		$	—		$	516.9
Intersegment revenues	75.9		—		1.1			(77.0		)	—
Total revenues	$	487.0	$	84.5	$	22.4		$	(77.0	)	$	516.9
Fuel	97.4		—		6.9			—			104.3
Purchased power	116.4		75.9		2.6			(75.9		)	119.0
Gross margin	$	273.2	$	8.6	$	12.9		$	(1.1	)	$	293.6
Depreciation and amortization	$	30.4	$	—	$	1.8		$	—		$	32.2
Interest expense	9.4		—		8.3			(0.1		)	17.6
Income tax expense (benefit)	39.4		1.4		(0.4		)	—			40.4
Net income (loss)	83.2		4.7		(4.2		)	2.7			86.4
Cash capital expenditures	38.8		—		(0.2		)	—			38.6

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$ in millions	Utility		Competitive Retail		Other			Adjustments and Eliminations			DPL  Consolidated
Nine Months Ended September 30, 2011
Revenues from external customers	$	1,092.9	$	314.6	$	43.9		$	—		$	1,451.4
Intersegment revenues	246.3		—		3.1			(249.4		)	—
Total revenues	$	1,339.2	$	314.6	$	47.0		$	(249.4	)	$	1,451.4
Fuel	311.7		—		9.2			—			320.9
Purchased power	317.8		268.6		2.6			(246.3		)	342.7
Gross margin	$	709.7	$	46.0	$	35.2		$	(3.1	)	$	787.8
Depreciation and amortization	$	100.3	$	0.2	$	5.5		$	—		$	106.0
Interest expense	28.7		0.2		22.7			(0.3		)	51.3
Income tax expense (benefit)	69.3		14.1		(13.7		)	—			69.7
Net income (loss)	147.4		19.6		(24.7		)	—			142.3
Cash capital expenditures	139.9		—		1.4			—			141.3
Nine Months Ended September 30, 2010
Revenues from external customers	$	1,183.0	$	189.1	$	41.5		$	—		$	1,413.6
Intersegment revenues	165.9		—		3.3			(169.2		)	—
Total revenues	$	1,348.9	$	189.1	$	44.8		$	(169.2	)	$	1,413.6
Fuel	286.5		—		10.6			—			297.1
Purchased power	279.3		165.9		3.4			(165.9		)	282.7
Gross margin	$	783.1	$	23.2	$	30.8		$	(3.3	)	$	833.8
Depreciation and amortization	$	98.4	$	0.1	$	6.8		$	—		$	105.3
Interest expense	27.9		—		25.2			(0.1		)	53.0
Income tax expense (benefit)	104.6		5.7		(3.4		)	—			106.9
Net income (loss)	214.7		11.8		(7.6		)	(0.1		)	218.8
Cash capital expenditures	112.3		—		1.4			—			113.7
Total Assets
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

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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 and was approved by DPL’s shareholders on September 23, 2011.  Consummation of the transaction is subject to certain conditions, including 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.  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.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1.25 billion in long-term Senior Notes 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.

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

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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 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 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 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 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 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 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 Merger of DPL and AES.

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

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

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

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

On July 29, 2011, DPL, DPL’s directors, 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.

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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 District Court will schedule a hearing regarding, among other things, approval of the proposed settlement and any application by plaintiffs’ counsel for an 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 intends to vigorously 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 Definitive Proxy Statement filed with the SEC on August 5, 2011, as modified by a correction to the Definitive Proxy Statement filed with the SEC on August 24, 2011.

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.

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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 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.

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.

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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 $30.00 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 and was approved by DPL’s shareholders on September 23, 2011.  Consummation of the transaction is subject to certain conditions, including 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.  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.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1.25 billion in long-term Senior Notes 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.

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Additional information concerning the Proposed Merger, including a copy of the Merger Agreement, is included in DPL’s Definitive Proxy Statement filed with the SEC on August 5, 2011, as modified by a correction to the Definitive Proxy Statement filed with the SEC 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 September 30, 2011.  For the year ended December 31, 2010, it sold approximately 648 million kWh of power, generating revenues of approximately $46 million.  We believe that the purchase of MC Squared complements DPLER’s existing Ohio retail market activity and 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:

REGULATORY ENVIRONMENT

·Carbon Emissions 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.

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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 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 were distributed in the fourth quarter of 2011.  We are in the process of reviewing the rule and are currently unable to predict the ultimate financial effect. We do not believe the rule will have a material impact on our operations in 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 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/day in the capacity auction price would result in an annual impact to net income of approximately $5.2 million and $3.8 million for DPL and DP&L, respectively.  These estimates do not, however, take into consideration the other factors that may affect the impact of capacity revenues and costs on net income such as the levels of customer switching, our generation capacity, the levels of wholesale revenues and our retail customer load.  These estimates are discussed further within Commodity Pricing Risk under the Market Risk section of this Management Discussion & Analysis.

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·Ohio Competitive Considerations and Proceedings

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

Lower 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 months ended September 30, 2011 and 2010 and the nine months ended September 30, 2011 and 2010:

	Three Months Ended		Three 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	1,567	4,396	1,338
Supplied by non-affiliated CRES providers	19,285	283	426	59
Total supplied in our service territory	41,275	1,850	4,822	1,397
Supplied by DP&L in our service territory(a)	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 40% and 34% of DP&L’s total distribution volumes during the three months ended September 30, 2011 and 2010, respectively.  The reduction to gross margin during the three months ended September 30, 2011 as a result of customers switching to DPLER and other CRES providers was approximately $19.8 million and $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.

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During the second and third quarters of 2011, we have seen a significant increase in retail competition for our residential retail customers. Approximately 12% of DP&L’s annualized residential load switched to CRES providers during those quarters with DPLER acquiring 57% of the switched load.  For the calendar year 2011, based on current trends, we project customer switching will negatively impact DPL’s gross margin by approximately $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 recently underwent an audit of its fuel and purchased power recovery rider, but there is some uncertainty as to the costs that will be 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 majority of the issues raised by the auditor.  On October 19, 2011, we had a hearing on this case.  Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation.  DP&L expects to record a favorable or unfavorable adjustment to earnings after the final order is received.

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FINANCIAL OVERVIEW

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

For the three months ended September 30, 2011, Net income for DPL was $67.1 million, or $0.58 per share, compared to Net income of $86.4 million, or $0.74 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 three 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 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 experienced during 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 nine months ended 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, and

·a decrease in the volume of fuel consumed due to decreased generation by our power plants.

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RESULTS OF OPERATIONS — DPL

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

Income Statement Highlights — DPL

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2011			2010			2011			2010
Revenues:
Retail	$	410.3		$	402.6		$	1,141.9		$	1,099.9
Wholesale	40.7			31.2			101.8			110.3
RTO revenues	22.3			23.4			63.2			64.6
RTO capacity revenues	37.3			57.0			142.3			129.7
Other revenues	2.8			2.7			8.5			8.9
Other mark-to-market gains / (losses)	(1.6		)	—			(6.3		)	0.2
Total revenues	$	511.8		$	516.9		$	1,451.4		$	1,413.6
Cost of revenues:
Fuel costs	$	121.8		$	104.8		$	312.7		$	300.5
Gains from sale of coal	(3.9		)	(1.1		)	(6.8		)	(2.4		)
Gains from sale of emission allowances	—			(0.1		)	—			(0.7		)
Mark-to-market (gains) / losses	11.1			0.7			15.0			(0.3		)
Net fuel	129.0			104.3			320.9			297.1
Purchased power	39.7			26.5			120.3			61.2
RTO charges	34.5			33.3			90.9			84.6
RTO capacity charges	35.5			59.6			138.0			137.0
Mark-to-market (gains) / losses	(1.4		)	(0.4		)	(6.5		)	(0.1		)
Net purchased power	108.3			119.0			342.7			282.7
Total cost of revenues	$	237.3		$	223.3		$	663.6		$	579.8
Gross margins (a)	$	274.5		$	293.6		$	787.8		$	833.8
Gross margin as a percentage of revenues	54		%	57		%	54		%	59		%
Operating income	$	112.9		$	144.6		$	279.5		$	379.9
Earnings per share of common stock:
Basic EPS from operations	$	0.58		$	0.75		$	1.24		$	1.89
Diluted EPS from operations	$	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.

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DPL — Revenues

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Number of days	2011	2010	2011	2010
Heating degree days (a)	124	52	3,604	3,475
Cooling degree days (a)	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			Nine Months Ended
	September 30,			September 30,
$ in millions	2011 vs. 2010			2011 vs. 2010
Retail
Rate	$	12.7		$	44.3
Volume	(7.9		)	(8.0		)
Other miscellaneous	2.9			5.7
Total retail change	$	7.7		$	42.0
Wholesale
Rate	$	5.7		$	9.0
Volume	3.8			(17.5		)
Total wholesale change	$	9.5		$	(8.5	)
RTO capacity & other RTO
RTO capacity and other RTO revenues	$	(20.8	)	$	11.2
Other
Unrealized MTM	$	(1.6	)	$	(6.5	)
Other	0.1			(0.4		)
Total other revenue change	$	(1.5	)	$	(6.9	)
Total revenues change	$	(5.1	)	$	37.8

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

·Retail revenues increased $7.7 million resulting primarily from a 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 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 2% compared to the prior year period largely due to cooler weather.  The above resulted in a favorable $12.7 million retail price variance and an unfavorable $7.9 million retail sales volume variance.

·Wholesale revenues increased $9.5 million primarily as a result of a 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 a 10% increase in wholesale sales prices.  This resulted in an unfavorable $17.5 million wholesale sales volume variance, offset partially by a favorable wholesale price variance of $9.0 million.  Wholesale sales volume decreased primarily as a result of an increase in outages at our generating plants during the nine months ended September 30, 2011 compared to the nine 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, increased $11.2 million compared to the same period in 2010.  This increase in RTO capacity and other revenues was primarily the result of a $12.6 million increase in revenues realized from the PJM capacity auction, partially offset by a slight decrease in transmission, congestion and other revenues.

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·Other Unrealized MTM revenues, consisting of retail sales contracts accounted for as derivatives, decreased $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.

DPL — Cost of Revenues

For the three months ended September 30, 2011:

·Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $24.7 million, or 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 12% decrease in the volume of generation, which was offset by an 18% increase in the price of generation from our plants due to an increase in and the timing of unit outages during the nine months ended September 30, 2011 as compared to the same period in 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 $60.0 million, or 21%, compared to the same period in 2010 due to an increase of $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 an $85.9 million increase associated with higher purchased power volumes partially offset by a $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.  These increases were partially offset by a $6.4 million increase in Unrealized MTM derivative gains associated with purchased power contracts due to increases in the market prices for power.

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DPL — Operation and Maintenance

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2011 vs. 2010			2011 vs. 2010
Generating facilities operating and maintenance expenses	$	(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	0.9			10.3
Competitive retail operations	2.4			5.5
Insurance settlement, net	—			3.4
Group insurance / long-term disability	(4.6		)	(8.8		)
Energy efficiency programs (1)	(0.9		)	(2.5		)
Other, net	1.7			(0.6		)
Total operation and maintenance expense	$	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 September 30, 2011, Operation and maintenance expense increased $7.8 million, or 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 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 related to the 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 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.

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DPL — Depreciation and Amortization

For the three months ended September 30, 2011, Depreciation and amortization expense increased $3.6 million, or 11%, as compared to the three months ended 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 due to a depreciation study which resulted in lower depreciation rates on generation property which were implemented on July 1, 2010.

DPL — General Taxes

For the three months ended September 30, 2011, General taxes increased $1.2 million, or 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.

For the nine months ended September 30, 2011, General taxes increased $7.8 million, or 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 nine months ended September 30, 2011 did not fluctuate significantly from that recorded during the three and nine months ended September 30, 2010.

DPL — Interest Expense

For the three months ended September 30, 2011, Interest expense did not fluctuate significantly from that recorded during the same period in 2010.  For the nine months ended September 30, 2011, Interest expense decreased $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 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 February 2011 purchase of $122.0 million principal of the DPL Capital Trust II 8.125% 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 nine months ended September 30, 2011, Income tax expense decreased $11.8 million, or 29%, and $37.2 million, or 35%, respectively, as compared to the same periods in 2010 primarily due to decreased pre-tax income.

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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.

Utility Segment

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

Competitive Retail Segment

The Competitive Retail segment is comprised of DPLER’s 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 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 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.

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 September 30,						Increase (Decrease)
$ in millions	2011			2010			2011 vs. 2010
Utility	$	247.2		$	273.2		$	(26.0	)
Competitive Retail	17.2			8.6			8.6
Other	11.2			12.9			(1.7		)
Adjustments and Eliminations	(1.1		)	(1.1		)	—
Total Consolidated	$	274.5		$	293.6		$	(19.1	)

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

	Nine months ended September 30,						Increase (Decrease)
$ in millions	2011			2010			2011 vs. 2010
Utility	$	709.7		$	783.1		$	(73.4	)
Competitive Retail	46.0			23.2			22.8
Other	35.2			30.8			4.4
Adjustments and Eliminations	(3.1		)	(3.3		)	0.2
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.

Income Statement Highlights — Competitive Retail Segment

	Three months ended September 30,						Increase (Decrease)
$ in millions	2011			2010			2011 vs. 2010
Revenues:
Retail	$	119.5		$	84.1		$	35.4
RTO and other	(0.9		)	0.4			(1.3		)
	$	118.6		$	84.5		$	34.1
Cost of revenues:
Purchased power	$	101.4		$	75.9		$	25.5
Gross margins (a)	$	17.2		$	8.6		$	8.6
Operation and maintenance expense	4.5			2.0			2.5
Other expenses (income), net	0.7			0.5			0.2
Total expenses, net	$	5.2		$	2.5		$	2.7
Earnings (loss) from continuing operations before income tax	12.0			6.1			5.9
Income tax expense (benefit)	4.2			1.4			2.8
Net income (loss)	$	7.8		$	4.7		$	3.1
Gross margin as a percentage of revenues	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.

85

	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 September 30, 2011, the segment’s retail revenues increased $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 $30.1 million recorded since this purchase date.  Primarily as a result of the purchase of MC Squared and customer switching in Ohio, the Competitive Retail segment sold approximately 5,011 million kWh of power to 25,309 customers during the nine months ended September 30, 2011 compared to 3,166 million kWh sold to 4,826 customers during the same period in 2010.

Competitive Retail Segment — Purchased Power

For the three months ended September 30, 2011, Purchased power for the segment increased $25.5 million, or 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. The electric energy used to meet the segment’s Illinois sales obligation was purchased from PJM.

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For the nine months ended September 30, 2011, Purchased power for the segment increased $102.7 million, or 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.  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 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 $2.5 million, or 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 nine months ended 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 $5.8 million, or 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.

Competitive Retail Segment — Income Tax Expense

For the three months ended September 30, 2011, the segment’s income tax expense increased $2.8 million.

For the nine months ended September 30, 2011, the segment’s income tax expense increased $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.

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RESULTS OF OPERATIONS — DP&L

Income Statement Highlights — DP&L

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
$ in millions	2011			2010			2011			2010
Revenues:
Retail	$	292.1		$	319.8		$	826.2		$	915.2
Wholesale	122.3			97.3			333.2			263.2
RTO revenues	20.7			21.6			59.2			60.8
RTO capacity revenues	31.7			48.3			120.6			109.7
Total revenues	$	466.8		$	487.0		$	1,339.2		$	1,348.9
Cost of revenues:
Fuel costs	$	116.8		$	98.4		$	303.5		$	290.4
Gains from sale of coal	(3.9		)	(1.1		)	(6.8		)	(2.4		)
Gains from sale of emission allowances	—			(0.1		)	—			(0.7		)
Mark-to-market (gains) / losses	11.1			0.2			15.0			(0.8		)
Net fuel	124.0			97.4			311.7			286.5
Purchased power	28.5			26.3			95.2			61.0
RTO charges	33.5			30.8			90.2			81.4
RTO capacity charges	33.6			59.7			132.5			137.0
Mark-to-market (gains) / losses	—			(0.4		)	(0.1		)	(0.1		)
Total purchased power	95.6			116.4			317.8			279.3
Total cost of revenues	$	219.6		$	213.8		$	629.5		$	565.8
Gross margins (a)	$	247.2		$	273.2		$	709.7		$	783.1
Gross margin as a percentage of revenues	53		%	56		%	53		%	58		%
Operating Income	$	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.

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

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2011 vs. 2010			2011 vs. 2010
Retail
Rate	$	(3.3	)	$	(37.1	)
Volume	(27.2		)	(57.2		)
Other miscellaneous	2.8			5.3
Total retail change	$	(27.7	)	$	(89.0	)
Wholesale
Rate	$	6.2		$	17.4
Volume	18.8			52.6
Total wholesale change	$	25.0		$	70.0
RTO capacity and other
RTO capacity and other revenues	$	(17.5	)	$	9.3
Total revenues change	$	(20.2	)	$	(9.7	)

For the three months ended September 30, 2011, Revenues decreased $20.2 million, or 4%, to $466.8 million from $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 and increased other miscellaneous revenues.  The revenue components for the three months ended September 30, 2011 are further discussed below:

·Retail revenues decreased $27.7 million primarily as a result of a 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 a 9% decrease in retail sales volumes largely due to cooler weather. The above resulted in an unfavorable $3.3 million retail price variance and an unfavorable $27.2 million retail sales volume variance.

·Wholesale revenues increased $25.0 million primarily as a result of a 5% increase in average wholesale prices combined with 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 $6.2 million wholesale price variance and a favorable wholesale sales volume variance of $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, decreased $17.5 million compared to the same period in 2010.  This decrease in RTO capacity and other revenues was primarily the result of a $16.5 million decrease in revenues realized from the PJM capacity auction including a decrease in transmission and congestion revenues.

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For the nine months ended September 30, 2011, Revenues decreased $9.7 million, or 1%, to $1,339.2 million from $1,348.9 million in the prior year.  This 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.  The revenue components for the nine months ended September 30, 2011 are further discussed below:

·Retail revenues decreased $89.0 million primarily as a result of a 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 6% decrease in retail sales volumes largely due to an unfavorable 5% decrease in cooling degree days from the prior year.  The above resulted in an unfavorable $37.1 million retail price variance and an unfavorable $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 $70.0 million primarily as a result of a 6% increase in average wholesale prices combined with a 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 $52.6 million wholesale sales volume variance and a favorable wholesale price variance of $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 $9.3 million compared to the same period in 2010.  This increase in RTO capacity and other revenues was primarily the result of a $10.9 million increase in revenues realized from the PJM capacity auction offset slightly by a decrease in transmission and congestion revenues.

DP&L — Cost of Revenues

For the three months ended September 30, 2011:

·Net fuel costs, which include coal, gas, oil and emission allowance costs, increased $26.6 million, or 27%, compared to 2010, primarily due to the impact of an increase in the price of fuel, as well as a $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.

·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 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.

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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 from our plants due to an increase in, and the timing of, unit outages during the nine months ended September 30, 2011 as compared to the same period in 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 $38.5 million, or 14%, compared to the same period in 2010, partially due to an increase of $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 $53.1 million increase associated with higher purchased power volumes partially offset by 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.

DP&L — Operation and Maintenance

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
$ in millions	2011 vs. 2010			2011 vs. 2010
Generating facilities operating and maintenance expenses	$	(1.5	)	$	14.5
Low-income payment program (1)	3.9			11.5
Maintenance of overhead transmission and distribution lines	0.9			10.3
Group insurance / long-term disability	(4.7		)	(8.8		)
Energy efficiency programs (1)	(0.9		)	(2.5		)
Other, net	3.8			(1.7		)
Total operation and maintenance expense	$	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 September 30, 2011, Operation and maintenance expense increased $1.5 million, or 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 assistance for low-income retail customers which is funded by the USF revenue rate rider, and

·increased expenses related to the maintenance of overhead transmission and distribution lines largely related to a significant ice storm in February 2011.

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, and

·lower expenses relating to energy efficiency programs that were put in place for our customers.

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DP&L — Depreciation and Amortization

For the three months ended September 30, 2011, Depreciation and amortization expense increased $3.4 million, or 11%, as compared to the three months ended 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.

DP&L — General Taxes

For the three and nine months ended September 30, 2011, General taxes increased $1.0 million, or 3%, and $3.6 million, or 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 nine months ended September 30, 2011 did not fluctuate significantly from that recorded during the three and nine months ended September 30, 2010.

DP&L — Interest Expense

Interest expense recorded during the three and nine months ended September 30, 2011 did not fluctuate significantly from that recorded during the three and nine months ended September 30, 2010.

DP&L — Income Tax Expense

For the three and nine months ended September 30, 2011, Income tax expense decreased $12.6 million, or 32%, and $35.3 million, or 34%, respectively, compared to the same period in 2010, primarily due to decreased pre-tax income.

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FINANCIAL CONDITION, LIQUIDITY AND CAPITAL REQUIREMENTS

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

DPL 

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Net cash provided by operating activities	$	264.8		$	331.6
Net cash used for investing activities	(78.9		)	(160.3		)
Net cash used for financing activities	(242.3		)	(107.1		)
Net change	$	(56.4	)	$	64.2
Cash and cash equivalents at beginning of period	124.0			74.9
Cash and cash equivalents at end of period	$	67.6		$	139.1

DP&L

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Net cash provided by operating activities	$	286.8		$	338.0
Net cash used for investing activities	(138.5		)	(110.6		)
Net cash used for financing activities	(180.6		)	(150.6		)
Net change	$	(32.3	)	$	76.8
Cash and cash equivalents at beginning of period	54.0			57.1
Cash and cash equivalents at end of period	$	21.7		$	133.9

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

Net Cash Provided by Operating Activities

The revenue from our energy business continues to be the principal source of cash from operating activities while our primary uses of cash include payments for fuel, purchased power, operation and maintenance expenses, interest and taxes.

DPL — Net Cash provided by Operating Activities

DPL’s Net cash provided by operating activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Net income	$	142.3		$	218.8
Depreciation and amortization	106.0			105.3
Deferred income taxes	70.5			38.7
Charge for early redemption of debt	15.3			—
Contribution to pension plan	(40.0		)	(40.0		)
Cash settlement of interest rate hedges, net of tax effect	(31.3		)	—
Other	2.0			8.8
Net cash provided by operating activities	$	264.8		$	331.6

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For the nine months ended 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 $70.5 million increase to Deferred income taxes primarily as a result of depreciation as well as pension contributions, financial transaction losses and other temporary differences arising from routine changes in balance sheet accounts giving rise to 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 nine months ended September 30, 2010, Net cash provided by operating activities was primarily a result of earnings from continuing operations adjusted for noncash depreciation and amortization, combined with the following significant transactions:

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

·DP&L made discretionary contributions totaling $40.0 million to the defined benefit pension plan .

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

DP&L — Net Cash provided by Operating Activities

DP&L’s Net cash provided by operating activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Net income	$	147.4		$	214.7
Depreciation and amortization	100.3			98.4
Deferred income taxes	56.1			36.9
Contribution to pension plan	(40.0		)	(40.0		)
Other	23.0			28.0
Net cash provided by operating activities	$	286.8		$	338.0

For the nine months ended 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.

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DPL — Net Cash used for Investing Activities

DPL’s Net cash used for investing activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Environmental and renewable energy capital expenditures	$	(8.5	)	$	(8.2	)
Other asset acquisitions, net	(132.8		)	(105.5		)
Purchase of MC Squared	(8.3		)	—
Sales / (purchases) of short-term investments, net	69.2			(48.3		)
Other	1.5			1.7
Net cash used for investing activities	$	(78.9	)	$	(160.3	)

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

DP&L — Net Cash used for Investing Activities

DP&L’s Net cash used for investing activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Environmental and renewable energy capital expenditures	$	(8.5	)	$	(8.2	)
Other asset acquisitions, net	(131.4		)	(104.1		)
Other	1.4			1.7
Net cash used for investing activities	$	(138.5	)	$	(110.6	)

For the nine months ended 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.

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DPL — Net Cash used for Financing Activities

DPL’s Net cash used for financing activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

	Nine Months Ended
	September 30,
$ in millions	2011			2010
Dividends paid on common stock	$	(113.8	)	$	(104.8	)
Payment of long-term debt	(297.4		)	—
Repurchase of DPL common stock	—			(3.9		)
Early redemption of long-term debt, including premium	(134.2		)	—
Payment of MC Squared debt	(13.5		)	—
Issuance of long-term debt	300.0			—
Exercise of warrants	14.7			—
Other	1.9			1.6
Net cash used for financing activities	$	(242.3	)	$	(107.1	)

For the nine months ended September 30, 2011, DPL paid common stock dividends of $113.8 million and $134.2 million for the purchase of the DPL Capital Trust II capital securities, of which $122.0 million related to the capital securities and an additional $12.2 million related to the premium paid on the purchase.  DPL also paid down the debt of MC Squared which was acquired in February 2011 (see Note 15 of Notes to Condensed Consolidated Financial Statements) and DPL received $14.7 million from the exercise of 700,000 warrants.

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

DP&L — Net Cash used for Financing Activities

DP&L’s Net cash used for financing activities for the nine months ended September 30, 2011 and 2010 can be summarized as follows:

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

For the nine months ended 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.

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At the filing date of this quarterly report on Form 10-Q, DP&L has access to $400 million of short-term financing under two revolving credit facilities.  The first facility, established in August 2011, is for $200 million and expires in August 2015 and has eight participating banks, with no bank having more than 22% of the total commitment.  DP&L also has the option to increase the 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
					available as of
$ in millions	Type	Maturity	Commitment		September 30, 2011
DP&L	Revolving	August 2015	$	200.0	$	200.0
DP&L	Revolving	April 2013	200.0		200.0
DPL Inc.	Revolving	August 2014	125.0		125.0
			$	525.0	$	525.0

Each DP&L revolving credit facility has a $50 million LOC sublimit.  The DPL revolving credit facility has a $125 million LOC sublimit.  As of September 30, 2011 and through the date of filing this quarterly report on Form 10-Q, there were no outstanding LOCs on the revolving credit facilities.

Cash and cash equivalents for DPL and DP&L amounted to $67.6 million and $21.7 million, respectively, at September 30, 2011.

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 $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 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.

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.

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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 $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 $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 $128.5 million and $102.5 million during the nine months ended September 30, 2011 and 2010, respectively.  DPL expects to spend approximately $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 $127.6 million and $100.6 million during the nine months ended September 30, 2011 and 2010, respectively.  DP&L expects to spend approximately $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 subsidiary issued to finance the acquisition.  As a result of this expected additional indebtedness, in April 2011 DPL and DP&L were downgraded by one of the major credit rating agencies 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 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.

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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.  However, there may be further changes to our credit ratings which may trigger these provisions.

At September 30, 2011, DPL had $86.7 million of guarantees to third parties for future financial or performance assurance under such agreements, including $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 $0.5 million and $1.7 million at 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 September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or $61.0 million, of a $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 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 changes to 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.

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.

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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 September 30, 2011 would not have a significant effect on Net income.

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

			Weighted		Increase /
			Average		Decrease in
	Contract		Market		Net Income
Commodity	Volume	Units	Price / Unit		(in millions)
NYMEX Coal Forwards - Non-Hedged
2011 - Purchase	59,675	tons	$	73.90	$	0.1	(a)
2012 - Purchase	903,030	tons	$	75.07	$	2.6	(a)
2013 - Purchase	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 15% of DPL’s and 33% of DP&L’s electric revenues for the three months ended 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 30% of DP&L’s electric revenues for the three 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.

Approximately 17% of DPL’s and 34% of DP&L’s electric revenues for the nine months ended 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.

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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 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
Effect of 10% change in price per MWh	$	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

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

	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 September 30, 2011, of a hypothetical increase or decrease of $10/MW-day in the RPM auction price. The table shows the impact resulting from capacity revenue changes.  We did not include the impact of a change in the RPM capacity costs since these costs will either be recovered through the RPM rider for SSO retail customers or recovered through the development of our overall energy pricing for customers who do not fall under the SSO.  These estimates include the impact of the RPM rider and are based on the levels of customer switching experienced through September 30, 2011.  As of September 30, 2011, approximately 50% of DP&L’s RPM capacity revenues and costs were recoverable from SSO retail customers through the RPM rider.

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$ 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 nine months ended September 30, 2011 were 42% and 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 50% of DP&L’s total fuel costs.  The table below provides the effect on annual net income as of September 30, 2011, of a hypothetical increase or decrease of 10% in the prices of fuel and purchased power, adjusted for the approximate 50%:

$ in millions	DPL		DP&L
Effect of 10% change in fuel and purchased power	$	17.7	$	17.0

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 September 30, 2011, we have entered into interest rate hedging relationships with an aggregate notional amount of $160 million related to planned future borrowing activities in calendar year 2013.  The average interest rate associated with the $160 million aggregate notional amount interest rate hedging relationships is 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.

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The carrying value of DPL’s debt was $1,224.0 million at 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 leases.  The fair value of this debt was $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
	For the years ending September 30,																		September 30,			September 30,
$ in millions	2012			2013			2014			2015			2016			Thereafter			2011 (a)			2011 (a)
Long-term debt
Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0		$	100.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.2		%	0.2		%
Fixed-rate debt	$	0.4		$	0.4		$	770.3		$	0.1		$	0.1		$	352.7		$	1,124.0		$	1,104.6
Average interest rate	4.9		%	5.0		%	3.7		%	4.2		%	4.2		%	5.0		%	4.1		%
Total																			$	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 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 $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:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

DP&L

																			Carrying value at			Fair value at
	For the years ending September 30,																		September 30,			September 30,
$ in millions	2012			2013			2014			2015			2016			Thereafter			2011 (a)			2011 (a)
Long-term debt
Variable-rate debt	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0		$	100.0
Average interest rate	0.0		%	0.0		%	0.0		%	0.0		%	0.0		%	0.2		%	0.2		%
Fixed-rate debt	$	0.4		$	0.4		$	470.3		$	0.1		$	0.1		$	332.1		$	803.4		$	784.2
Average interest rate	4.9		%	5.0		%	5.1		%	4.2		%	4.2		%	4.8		%	5.0		%
Total																			$	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.

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Long-term Debt Interest Rate Risk Sensitivity Analysis

The following table presents our estimate of market risk exposure for our fixed-rate and variable-rate debt at 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 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
	September 30,		September 30,		interest rate
$ in millions	2011		2011		risk
Long-term debt
Variable-rate debt	$	100.0	$	100.0	$	1.0
Fixed-rate debt	1,124.0		1,104.6		11.0
Total	$	1,224.0	$	1,204.6	$	12.0

DP&L

	Carrying value at		Fair value at		One percent
	September 30,		September 30,		interest rate
$ in millions	2011		2011		risk
Long-term debt
Variable-rate debt	$	100.0	$	100.0	$	1.0
Fixed-rate debt	803.4		784.2		8.8
Total	$	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 $1,104.6 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 September 30, 2011.

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 $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 September 30, 2011.

Equity Price Risk

As of September 30, 2011, approximately 32% of the defined benefit pension plan assets were comprised of investments in equity securities and 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 $106.1 million at September 30, 2011.  A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10.6 million reduction in fair value as of 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.

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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.

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ELECTRIC SALES AND REVENUES

	DPL				DP&L (a)				DPLER (b)
	Three Months Ended				Three Months Ended				Three Months Ended
	September 30,				September 30,				September 30,
	2011		2010		2011		2010		2011			2010
Electric sales (millions of kWh)
Residential	1,432		1,515		1,432		1,515		32			—
Commercial	1,125		1,121		884		1,086		776			420
Industrial	946		939		893		930		860			717
Other retail	392		399		382		397		203			247
Total retail	3,895		3,974		3,591		3,928		1,871			1,384
Wholesale	703		625		717		578		—			—
Total	4,598		4,599		4,308		4,506		1,871			1,384
Operating revenues ($ in thousands)
Residential	$	193,684	$	194,510	$	191,255	$	194,495	$	2,430		$	16
Commercial	108,462		107,503		56,489		80,122		51,973			27,382
Industrial	71,564		66,909		19,735		24,772		51,828			42,137
Other retail	30,931		30,832		18,734		17,314		13,086			14,412
Other miscellaneous revenues	5,749		2,854		5,889		3,089		92			21
Total retail	410,390		402,608		292,102		319,792		119,409			83,968
Wholesale	40,660		31,124		122,296		97,356		—			—
RTO revenues	59,599		80,384		52,391		69,817		688			449
Other revenues	1,158		2,769		—		—		(1,573		)	7
Total	$	511,807	$	516,885	$	466,789	$	486,965	$	118,524		$	84,424
Electric customers at end of period
Residential	453,860		454,783		453,860		454,783		8,434			30
Commercial	53,065		50,504		50,029		50,110		13,612			3,433
Industrial	1,917		1,803		1,755		1,770		789			504
Other	6,916		6,686		6,795		6,683		2,474			859
Total	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 1,567 million kWh and 1,338 million kWh of power to DPLER (a subsidiary of DPL) during the three months ending 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.

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ELECTRIC SALES AND REVENUES

	DPL				DP&L (a)				DPLER (b)
	Nine Months Ended				Nine Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,
	2011		2010		2011		2010		2011			2010
Electric sales (millions of kWh)
Residential	4,120		4,224		4,120		4,224		33			—
Commercial	3,042		2,931		2,507		2,875		1,927			707
Industrial	2,642		2,717		2,517		2,702		2,350			1,800
Other retail	1,083		1,096		1,063		1,093		701			659
Total retail	10,887		10,968		10,207		10,894		5,011			3,166
Wholesale	1,825		2,170		1,913		2,110		—			—
Total	12,712		13,138		12,120		13,004		5,011			3,166
Operating revenues ($ in thousands)
Residential	$	540,821	$	520,599	$	538,297	$	520,571	$	2,525		$	29
Commercial	300,934		289,925		171,278		240,130		129,656			49,795
Industrial	200,963		196,780		58,506		96,636		142,456			100,144
Other retail	86,606		85,622		45,153		50,184		44,209			38,026
Other miscellaneous revenues	12,658		6,949		12,995		7,650		148			27
Total retail	1,141,982		1,099,875		826,229		915,171		318,994			188,021
Wholesale	101,748		110,473		333,207		263,236		—			—
RTO revenues	205,501		194,307		179,778		170,501		1,792			1,013
Other revenues	2,200		8,901		—		—		(6,210		)	26
Total	$	1,451,431	$	1,413,556	$	1,039,214	$	1,348,908	$	314,576		$	189,060
Electric customers at end of period
Residential	453,860		454,783		453,860		454,783		8,434			30
Commercial	53,065		50,504		50,029		50,110		13,612			3,433
Industrial	1,917		1,803		1,755		1,770		789			504
Other	6,916		6,686		6,795		6,683		2,474			859
Total	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 4,330 million kWh and 3,091 million kWh of power to DPLER (a subsidiary of DPL) during the nine months ending 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.

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Item 4.  Controls and Procedures

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

There was no change in our internal control over financial reporting during the nine months ended 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 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 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; and (ii) information about the legal proceedings contained under the section entitled “Ohio Regulation” under the subsections of the section entitled “Environmental Matters” and under the section entitled “Legal and Other Matters” in Item 1 — Note 14 of Notes to Condensed Consolidated Financial Statements of this report.

108

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 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 7 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.  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.  The Proposed Merger 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

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 is terminated prior to the completion of the Proposed Merger, DPL could incur significant transaction costs that could materially impact its financial performance and results.  Failure to complete the Proposed Merger could also negatively impact DPL’s stock price and its future business and financial results.

DPL will incur significant merger transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the Proposed Merger.  If the Proposed Merger is not completed for certain reasons including, among others, if the Merger Agreement is terminated under certain specified circumstances, DPL will be required to pay The AES Corporation a termination fee of $106 million.  The occurrence of either of these events individually or in combination could have a material adverse affect on DPL’s financial results.

We will be subject to business uncertainties and contractual restrictions while the Proposed Merger with The AES Corporation is pending that could adversely affect our financial results.

Uncertainty about the effect of the Proposed Merger on employees or suppliers may have an adverse effect on us.  Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain 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.

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 currently 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

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 will be adjusted and any resulting goodwill or negative goodwill 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.

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

Item 5 — Other Information

None

Item 6 — Exhibits

DPL Inc.	DP&L	Exhibit Number	Exhibit	Location
X		10(a)	Credit Agreement, dated as of August 24, 2011, among DPL Inc., PNC Bank, National Association, as Administrative Agent, Bank of America, N.A., Fifth Third Bank and 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 10.1 to Report on Form 8-K filed August 30, 2011 (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(c)	Credit Agreement, dated as of 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 Documentation Agent, and the other lenders party to the Credit Agreement	Exhibit 10.3 to Report on Form 8-K filed August 30, 2011 (File No. 1-2385)
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

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
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

113

SIGNATURES

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

		DPL Inc.
		The Dayton Power and Light Company
		(Registrants)
Date:	October 27, 2011	/s/ Paul M. Barbas
		Paul M. Barbas
		President and Chief Executive Officer
		(principal executive officer)
	October 27, 2011	/s/ Frederick J. Boyle
		Frederick J. Boyle
		Senior Vice President, and Chief Financial Officer
		(principal financial officer)
	October 27, 2011	/s/ Joseph W. Mulpas
		Joseph W. Mulpas
		Vice President, Controller and Chief Accounting Officer
		(principal accounting officer)

114

EX-31.(A)

Exhibit 31(a)

CERTIFICATIONS

I, Paul M. Barbas, certify that:

1.I have reviewed this quarterly report on Form 10-Q of DPL Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011
	/s/ Paul M. Barbas
	Paul M. Barbas
	President and Chief Executive Officer

EX-31.(B)

Exhibit 31(b)

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1.I have reviewed this quarterly report on Form 10-Q of DPL Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011
	/s/ Frederick J. Boyle
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

EX-31.(C)

Exhibit 31(c)

CERTIFICATIONS

I, Paul M. Barbas, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011
	/s/ Paul M. Barbas
	Paul M. Barbas
	President and Chief Executive Officer

EX-31.(D)

Exhibit 31(d)

CERTIFICATIONS

I, Frederick J. Boyle, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Dayton Power and Light Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2011
	/s/ Frederick J. Boyle
	Frederick J. Boyle
	Senior Vice President and Chief Financial Officer

EX-32.(A)

Exhibit 32(a)

DPL Inc.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of DPL Inc. (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended September 30, 2011, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuers as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuers and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Paul M. Barbas

Paul M. Barbas

President and Chief Executive Officer

Date: October 27, 2011

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.(B)

Exhibit 32(b)

DPL Inc.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of DPL Inc. (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended September 30, 2011, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuers as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuers and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Frederick J. Boyle

Frederick J. Boyle

Senior Vice President and Chief Financial Officer

Date: October 27, 2011

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.(C)

Exhibit 32(c)

The Dayton Power and Light Company

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of The Dayton Power and Light Company (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended September 30, 2011, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuers as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuers and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Paul M. Barbas

Paul M. Barbas

President and Chief Executive Officer

Date: October 27, 2011

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

EX-32.(D)

Exhibit 32(d)

The Dayton Power and Light Company

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned officer of The Dayton Power and Light Company (the “Issuer”) hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Issuer’s Quarterly Report on Form 10-Q for the period ended September 30, 2011, which this certificate accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Issuers as of the dates and for the periods expressed therein.

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this statement required by Section 906 of the Sarbanes-Oxley Act of 2002, has been provided to the Issuer and will be retained by the Issuers and furnished to the Securities and Exchange Commission or its staff upon request.

Signed:

/s/ Frederick J. Boyle

Frederick J. Boyle

Senior Vice President and Chief Financial Officer

Date: October 27, 2011

The foregoing certificate is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Issuer’s Annual Report or as a separate disclosure document.

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Pension and Postretirement Benefits (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2010 Management Employees [Member]	Feb. 28, 2011 DP&L [Member]	Sep. 30, 2010 DP&L [Member]
Defined benefit plan employee vested percentage	100.00%	100.00%
Defined benefit plan employee vested minimum period	5
Contribution to the defined benefit plan			$ 40.0	$ 40.0

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Condensed Consolidated Statements of Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities:
Net income	$ 142.3	$ 218.8
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	106.0	105.3
Deferred income taxes	70.5	38.7
Unamortized investment tax credit	(2.1)	(2.1)
Charge for early redemption of debt	15.3
Changes in certain assets and liabilities:
Accounts receivable	21.1	7.9
Inventories	(11.5)	10.6
Prepaid taxes	(27.0)	(0.9)
Taxes applicable to subsequent years	47.7	44.2
Deferred regulatory costs, net	7.9	7.0
Accounts payable	(13.4)	(4.7)
Accrued taxes payable	(58.2)	(58.1)
Accrued interest payable	(3.1)	(5.6)
Pension, retiree and other benefits	(31.7)	(54.6)
Insurance and claims costs	4.1	(0.3)
Other	(3.1)	25.4
Net cash provided by operating activities	264.8	331.6
Cash flows from investing activities:
Capital expenditures	(141.3)	(113.7)
Purchase of MC Squared	(8.3)
Purchases of short-term investments and securities	(1.7)	(62.7)
Sales of short-term investments and securities	70.9	14.4
Other	1.5	1.7
Net cash used for investing activities	(78.9)	(160.3)
Cash flows from financing activities:
Dividends paid on common stock	(113.8)	(104.8)
Early redemption of Capital Trust II debt	(122.0)
Premium paid for early redemption of debt	(12.2)
Payment of MC Squared debt	(13.5)
Payment of long-term debt	(297.4)	0
Issuance of long-term debt	300.0	0
Withdrawals from revolving credit facilities	50.0
Repayments of borrowings from revolving credit facilities	(50.0)
Repurchase of DPL common stock		(3.9)
Exercise of stock options	1.6	1.4
Exercise of warrants	14.7	0
Tax impact related to exercise of stock options	0.3	0.2
Net cash used for financing activities	(242.3)	(107.1)
Cash and cash equivalents:
Net change	(56.4)	64.2
Balance at beginning of period	124.0	74.9
Cash and cash equivalents at end of period	67.6	139.1
Supplemental cash flow information:
Interest paid, net of amounts capitalized	49.4	59.6
Income taxes paid, net	25.5	60.8
Non-cash financing and investing activities:
Accruals for capital expenditures	14.8	14.1
Long-term liability incurred for purchase of assets	18.7
THE DAYTON POWER AND LIGHT COMPANY [Member]
Cash flows from operating activities:
Net income	147.4	214.7
Adjustments to reconcile Net income to Net cash provided by operating activities:
Depreciation and amortization	100.3	98.4
Deferred income taxes	56.1	36.9
Unamortized investment tax credit	(2.1)	(2.1)
Changes in certain assets and liabilities:
Accounts receivable	26.4	27.5
Inventories	(11.5)	10.3
Prepaid taxes	(11.5)	(0.9)
Taxes applicable to subsequent years	47.1	44.0
Deferred regulatory costs, net	7.9	7.0
Accounts payable	(14.9)	(6.1)
Accrued taxes payable	(58.5)	(55.6)
Accrued interest payable	7.4	2.2
Pension, retiree and other benefits	(31.7)	(54.6)
Other	24.4	16.3
Net cash provided by operating activities	286.8	338.0
Cash flows from investing activities:
Capital expenditures	(139.9)	(112.3)
Other	1.4	1.7
Net cash used for investing activities	(138.5)	(110.6)
Cash flows from financing activities:
Dividends paid on common stock	(180.0)	(150.0)
Dividends paid on preferred stock	(0.6)	(0.6)
Withdrawals from revolving credit facilities	50.0
Repayments of borrowings from revolving credit facilities	(50.0)
Net cash used for financing activities	(180.6)	(150.6)
Cash and cash equivalents:
Net change	(32.3)	76.8
Balance at beginning of period	54.0	57.1
Cash and cash equivalents at end of period	21.7	133.9
Supplemental cash flow information:
Interest paid, net of amounts capitalized	22.2	27.6
Income taxes paid, net	24.6	60.7
Non-cash financing and investing activities:
Accruals for capital expenditures	14.8	14.1
Long-term liability incurred for purchase of assets	$ 18.7

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Condensed Consolidated Balance Sheets (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 67.6	$ 124.0
Short-term investments	0	69.3
Accounts receivable, net (Note 2)	203.2	215.5
Inventories (Note 2)	126.8	115.3
Taxes applicable to subsequent years	15.9	63.7
Other prepayments and current assets	68.6	40.6
Total current assets	482.1	628.4
Property, plant and equipment:
Property, plant and equipment	5,508.3	5,353.6
Less: Accumulated depreciation and amortization	(2,652.7)	(2,555.2)
Property, plant and equipment, net of depreciation	2,855.6	2,798.4
Construction work in process	118.6	119.7
Total net property, plant and equipment	2,974.2	2,918.1
Other noncurrent assets:
Regulatory assets (Note 3)	178.2	189.0
Other deferred assets	42.0	77.8
Total other noncurrent assets	220.2	266.8
Total Assets	3,676.5	3,813.3
Current liabilities:
Current portion - long-term debt (Note 5)	0.4	297.5
Accounts payable	82.2	98.7
Accrued taxes	72.4	68.1
Accrued interest	15.6	18.4
Customer security deposits	16.9	18.7
Other current liabilities	37.0	40.9
Total current liabilities	224.5	542.3
Noncurrent liabilities:
Long-term debt (Note 5)	1,223.6	1,026.6
Deferred taxes (Note 6)	670.0	625.4
Regulatory liabilities (Note 3)	133.1	124.0
Pension, retiree and other benefits	25.9	64.9
Unamortized investment tax credit	30.3	32.4
Insurance and claims costs	14.1	10.1
Other deferred credits	112.6	146.2
Total noncurrent liabilities	2,209.6	2,029.6
Redeemable preferred stock	22.9	22.9
Commitments and contingencies (Note 14)
Common shareholders' equity:
Common stock, at par value of $0.01 per share:	1.2	1.2
Warrants	1.6	2.7
Common stock held by employee plans	(7.1)	(12.5)
Accumulated other comprehensive loss	(72.1)	(18.9)
Retained earnings	1,295.9	1,246.0
Total common shareholders' equity	1,219.5	1,218.5
Total Liabilities and Shareholders' Equity	3,676.5	3,813.3
THE DAYTON POWER AND LIGHT COMPANY [Member]
Current assets:
Cash and cash equivalents	21.7	54.0
Accounts receivable, net (Note 2)	152.5	178.0
Inventories (Note 2)	125.6	114.2
Taxes applicable to subsequent years	15.7	62.8
Other prepayments and current assets	45.2	42.7
Total current assets	360.7	451.7
Property, plant and equipment:
Property, plant and equipment	5,243.8	5,093.7
Less: Accumulated depreciation and amortization	(2,545.2)	(2,453.1)
Property, plant and equipment, net of depreciation	2,698.6	2,640.6
Construction work in process	118.0	119.6
Total net property, plant and equipment	2,816.6	2,760.2
Other noncurrent assets:
Regulatory assets (Note 3)	178.2	189.0
Other deferred assets	64.2	74.5
Total other noncurrent assets	242.4	263.5
Total Assets	3,419.7	3,475.4
Current liabilities:
Current portion - long-term debt (Note 5)	0.4	0.1
Accounts payable	75.1	95.7
Accrued taxes	70.3	66.6
Accrued interest	15.5	7.7
Customer security deposits	16.9	18.7
Other current liabilities	33.8	33.6
Total current liabilities	212.0	222.4
Noncurrent liabilities:
Long-term debt (Note 5)	903.0	884.0
Deferred taxes (Note 6)	656.4	598.0
Regulatory liabilities (Note 3)	133.1	124.0
Pension, retiree and other benefits	25.9	64.9
Unamortized investment tax credit	30.3	32.4
Other deferred credits	84.4	147.3
Total noncurrent liabilities	1,833.1	1,850.6
Redeemable preferred stock	22.9	22.9
Commitments and contingencies (Note 14)
Common shareholders' equity:
Common stock, at par value of $0.01 per share:	0.4	0.4
Other paid-in capital	782.8	782.4
Accumulated other comprehensive loss	(15.1)	(20.2)
Retained earnings	583.6	616.9
Total common shareholders' equity	1,351.7	1,379.5
Total Liabilities and Shareholders' Equity	$ 3,419.7	$ 3,475.4

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Proposed Merger with the AES Corporation (Narrative) (Details) (USD $)	0 Months Ended	9 Months Ended				9 Months Ended	3 Months Ended		0 Months Ended
	Apr. 19, 2011	Sep. 30, 2011	Mar. 01, 2011	Sep. 30, 2011 Senior Notes Maturing in September 2011 - 6.875% [Member]	Dec. 31, 2010 Senior Notes Maturing in September 2011 - 6.875% [Member]	Sep. 30, 2011 DP&L [Member] U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2011 DP&L [Member]	Nov. 21, 2006 DP&L [Member]	Apr. 19, 2011 Contract Termination [Member]
Acquisition cost per share	$ 30.00
Value of divestiture of business	$ 3,500,000,000
Amount of debt and preferred stock assumed by AES at acquisition	1,200,000,000
Maximum quarterly common stock dividend per share		0.3325
Senior notes maturing in September 2011				297,400,000	297,400,000
Debt instrument interest percentage			4.20%	6.875%		4.20%
Debt instrument maturity year		2061				February 2061	2026
Additional principal amount of senior notes to be raised		1,250,000,000
Unsecured revolving credit agreement								220,000,000
Loans Payable to Bank, Noncurrent		425,000,000
Divestiture of business potential fees		$ 45,000,000							$ 106,000,000

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Debt maturities minimum period			2011
Debt maturities maximum period			2061
Unrealized gain			$ 0.5
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss) before Taxes			0.1
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax			0.1
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax					0.9
Other Comprehensive Income, Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	(0.3)	0.3	(0.3)	0.2	0.6
Unrealized gain after tax			0.3
Unrealized gains or losses are expected to be transferred to earnings in the next twelve months.					0.4
Money market funds					29.9
DP&L [Member]
Debt maturities maximum period	2026
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss) before Taxes			0.1
Available-for-sale Securities, Change in Net Unrealized Holding Gain (Loss), Net of Tax			0.1
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax			16.6		13.0
Other Comprehensive Income, Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	(0.4)	1.8	2.3	(0.9)	8.5
Unrealized gain after tax			$ 10.8
Inputs to the fair value of derivative instruments from quoted market prices			98.00%

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Overview and Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2011

Overview and Summary of Significant Accounting Policies [Abstract]

Excise Taxes Levied by State or Local Governments

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
$ in millions		2011		2010		2011		2010
State/Local excise taxes	$	14.3	$	14.6	$	39.9	$	40.1

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						Nine Months Ended
		September 30,						September 30,
$ in millions		2011			2010			2011			2010
DP&L Revenues:
Sales to DPLER (a)	$	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	)	$	(2.4	)	$	(2.5	)
Expense recoveries for services provided to DPLER (c)	$	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 nine months ended 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.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 24, 2011
Entity Registrant Name	DPL INC
Entity Central Index Key	0000787250
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
DPL [Member]
Entity Common Stock, Shares Outstanding		117,729,995
THE DAYTON POWER AND LIGHT COMPANY [Member]
Entity Registrant Name	DAYTON POWER & LIGHT CO
Entity Central Index Key	0000027430
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		41,172,173
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3

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Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010
Estimated annual effective income tax rate		33.20%	32.60%
Increase in income tax expense	$ 2.6	$ 0.7
Increase in deferred state income taxes		2.0
Increase in deferred tax liabilities		38.8
Certain costs incurred associated with the merger		8.9
Additional tax expense		3.1
DP&L [Member]
Increase in income tax expense	2.6	2.2
Increase in deferred tax liabilities		$ 56.0

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Ownership of Coal-fired Facilities (Tables)

9 Months Ended

Sep. 30, 2011

Ownership of Coal-fired Facilities [Abstract]

Ownership Interests

	DP&L Share						DP&L Investment
										SCR and FGD
										Equipment
		Summer						Construction		Installed
		Production Gross Plant Accumulated							Work in	and In
	Ownership	Capacity		In Service		Depreciation			Process	Service
	(%)	(MW)		($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	207	$	76		$	57	$	-	No
Conesville Unit 4	16.5	129			119		31		5	Yes
East Bend Station	31.0	186			201		132		-	Yes
Killen Station	67.0	402			617		298		2	Yes
Miami Fort Units 7 and 8	36.0	368			366		137		2	Yes
Stuart Station	35.0	808			719		275		15	Yes
Zimmer Station	28.1	365			1,060		624		18	Yes
Transmission (at varying percentages)		-			91		57		-
Total		2,465	$	3,249		$	1,611	$	42
Wholly-owned production unit:
Hutchings Station	100.0	390		$	124	$	114	$	1	No

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Debt Obligations (Long-term Debt Maturities) (Details) (USD $) In Millions	Sep. 30, 2011
Due within one year	$ 0.4
Due within two years	0.4
Due within three years	770.3
Due within four years	0.1
Due within five years	0.1
Thereafter	453.1
Total	1,224.4
DP&L [Member]
Due within one year	0.4
Due within two years	0.4
Due within three years	470.3
Due within four years	0.1
Due within five years	0.1
Thereafter	432.5
Total	$ 903.8

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Pension and Postretirement Benefits

9 Months Ended

Sep. 30, 2011

Pension and Postretirement Benefits

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 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.

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 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 $40.0 million to the defined benefit plan 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 September 30, 2011 and 2010 was:

Net Periodic Benefit Cost / (Income)		Pension						Postretirement
$ in millions		2011			2010			2011			2010
Service cost	$	0.8		$	1.0		$	-		$	0.1
Interest cost		4.1			4.5			0.2			0.3
Expected return on assets (a)		(6.2	)		(5.6	)		(0.1	)		-
Amortization of unrecognized:
Actuarial (gain) / loss		1.7			2.0			(0.5	)		(0.2	)
Prior service cost		0.5			0.9			0.1			-
Net periodic benefit cost / (income) before adjustments	$	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 $317 million.

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 Medicare Part D Reimbursements
$ in millions		Pension	Postretirement
2011	$	5.3	$	0.6
2012	$	23.1	$	2.4
2013	$	23.1	$	2.4
2014	$	23.6	$	2.3
2015	$	24.0	$	2.1
2016 - 2020	$	122.9	$	8.8

DP&L [Member]

Pension and Postretirement Benefits

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 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.

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 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 $40.0 million to the defined benefit plan 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 September 30, 2011 and 2010 was:

Net Periodic Benefit Cost / (Income)		Pension						Postretirement
$ in millions		2011			2010			2011			2010
Service cost	$	0.8		$	1.0		$	-		$	0.1
Interest cost		4.1			4.5			0.2			0.3
Expected return on assets (a)		(6.2	)		(5.6	)		(0.1	)		-
Amortization of unrecognized:
Actuarial (gain) / loss		1.7			2.0			(0.5	)		(0.2	)
Prior service cost		0.5			0.9			0.1			-
Net periodic benefit cost / (income) before adjustments	$	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 $317 million.

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 Medicare Part D Reimbursements
$ in millions		Pension	Postretirement
2011	$	5.3	$	0.6
2012	$	23.1	$	2.4
2013	$	23.1	$	2.4
2014	$	23.6	$	2.3
2015	$	24.0	$	2.1
2016 - 2020	$	122.9	$	8.8

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Debt Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Debt Obligations [Abstract]

Long-term Debt

Long-term Debt		At			At
		September 30,			December 31,
$ in millions		2011			2010
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%		35.3			35.3
Pollution control series maturing in January 2034 - 4.80%		179.1			179.1
Pollution control series maturing in September 2036 - 4.80%		100.0			100.0
Pollution control series maturing in November 2040 -
variable rates: 0.06% - 0.29% and 0.16% - 0.36% (a)		100.0			100.0
U.S. Government note maturing in February 2061 - 4.20%		18.5			-
		902.9			884.4
Obligation for capital lease		0.5			0.1
Unamortized debt discount		(0.4	)		(0.5	)
Total long-term debt - DP&L	$	903.0		$	884.0
DPL
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
Total long-term debt - DPL	$	1,223.6		$	1,026.6

Current Portion - Long-term Debt

Current portion - Long-term Debt		At		At
		September 30,		December 31,
$ in millions		2011		2010
DP&L
U.S. Government note maturing in February 2061 - 4.20%	$	0.1	$	-
Obligation for capital lease		0.3		0.1
Total current portion - long-term debt - DP&L	$	0.4	$	0.1
DPL
Senior notes maturing in September 2011 - 6.875%		-		297.4
Total current portion - long-term debt - DPL	$	0.4	$	297.5

(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.

Maturities of Long-term Debt Including Capital Lease Obligations

$ 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

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Ownership of Coal-fired Facilities (Ownership Interests) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011 mW
Construction Work in Process	42.0
DP&L [Member] | DP&L Share [Member]
Production Capacity (MW)	2,465
DP&L [Member] | DP&L Share [Member] | Beckjord Unit 6 [Member]
Ownership (%)	50.00%
Production Capacity (MW)	207
DP&L [Member] | DP&L Share [Member] | Conesville Unit 4 [Member]
Ownership (%)	16.50%
Production Capacity (MW)	129
DP&L [Member] | DP&L Share [Member] | East Bend Station [Member]
Ownership (%)	31.00%
Production Capacity (MW)	186
DP&L [Member] | DP&L Share [Member] | Killen Station [Member]
Ownership (%)	67.00%
Production Capacity (MW)	402
DP&L [Member] | DP&L Share [Member] | Miami Fort Units 7 and 8 [Member]
Ownership (%)	36.00%
Production Capacity (MW)	368
DP&L [Member] | DP&L Share [Member] | Stuart Station [Member]
Ownership (%)	35.00%
Production Capacity (MW)	808
DP&L [Member] | DP&L Share [Member] | Zimmer Station [Member]
Ownership (%)	28.10%
Production Capacity (MW)	365
DP&L [Member] | DP&L Share [Member] | Transmission (At Varying Percentages) [Member]
Production Capacity (MW)
DP&L [Member] | DP&L Share [Member] | Hutchings Station [Member]
Ownership (%)	100.00%
Production Capacity (MW)	390
DP&L [Member] | DP&L Investment [Member]
Gross Plant In Service	3,249
Accumulated Depreciation	1,611
Construction Work in Process	42.0
DP&L [Member] | DP&L Investment [Member] | Beckjord Unit 6 [Member]
Gross Plant In Service	76
Accumulated Depreciation	57
Construction Work in Process
SCR and FGD Equipment Installed and In Service	No
DP&L [Member] | DP&L Investment [Member] | Conesville Unit 4 [Member]
Gross Plant In Service	119
Accumulated Depreciation	31
Construction Work in Process	5.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | East Bend Station [Member]
Gross Plant In Service	201
Accumulated Depreciation	132
Construction Work in Process
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | Killen Station [Member]
Gross Plant In Service	617
Accumulated Depreciation	298
Construction Work in Process	2.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | Miami Fort Units 7 and 8 [Member]
Gross Plant In Service	366
Accumulated Depreciation	137
Construction Work in Process	2.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | Stuart Station [Member]
Gross Plant In Service	719
Accumulated Depreciation	275
Construction Work in Process	15.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | Zimmer Station [Member]
Gross Plant In Service	1,060
Accumulated Depreciation	624
Construction Work in Process	18.0
SCR and FGD Equipment Installed and In Service	Yes
DP&L [Member] | DP&L Investment [Member] | Transmission (At Varying Percentages) [Member]
Gross Plant In Service	91
Accumulated Depreciation	57
Construction Work in Process
DP&L [Member] | DP&L Investment [Member] | Hutchings Station [Member]
Gross Plant In Service	124
Accumulated Depreciation	114
Construction Work in Process	1.0
SCR and FGD Equipment Installed and In Service	No

XML

Supplemental Financial Information and Comprehensive Income (Supplemental Financial Information) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Unbilled revenue	$ 60.0	$ 84.5
Customer receivables	124.7	113.9
Amounts due from partners in jointly-owned plants	10.8	7.0
Coal sales	3.8	4.0
Other	5.2	7.0
Provision for uncollectible accounts	(1.3)	(0.9)
Total accounts receivable, net	203.2	215.5
Fuel, limestone and emission allowances	80.4	73.2
Plant materials and supplies	39.7	38.8
Other	6.7	3.3
Total inventories, at average cost	126.8	115.3
DP&L [Member]
Unbilled revenue	38.0	64.3
Customer receivables	97.4	95.6
Amounts due from partners in jointly-owned plants	10.8	7.0
Coal sales	3.8	4.0
Other	3.5	7.9
Provision for uncollectible accounts	(1.0)	(0.8)
Total accounts receivable, net	152.5	178.0
Fuel, limestone and emission allowances	80.4	73.2
Plant materials and supplies	38.5	37.7
Other	6.7	3.3
Total inventories, at average cost	$ 125.6	$ 114.2

XML

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2011

Regulatory Matters [Abstract]

Regulatory Assets and Liabilities

				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.

XML

EPS

9 Months Ended

Sep. 30, 2011

EPS

12. EPS

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

DPL's ESOP.

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

$ and shares in millions except			Three Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		Income	Shares		Share		Income	Shares		Share
Basic EPS	$	67.1	115.0	$	0.58	$	86.4	115.8	$	0.75
Effect of Dilutive
Securities:
Warrants			0.3					0.3
Stock options, performance and
restricted shares			0.2					0.2
Diluted EPS	$	67.1	115.5	$	0.58	$	86.4	116.3	$	0.74

$ and shares in millions except			Nine Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		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

DP&L [Member]

EPS

12. EPS

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

DPL's ESOP.

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

$ and shares in millions except			Three Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		Income	Shares		Share		Income	Shares		Share
Basic EPS	$	67.1	115.0	$	0.58	$	86.4	115.8	$	0.75
Effect of Dilutive
Securities:
Warrants			0.3					0.3
Stock options, performance and
restricted shares			0.2					0.2
Diluted EPS	$	67.1	115.5	$	0.58	$	86.4	116.3	$	0.74

$ and shares in millions except			Nine Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		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

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Regulatory Matters

9 Months Ended

Sep. 30, 2011

Regulatory Matters

3. Regulatory Matters

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

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

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. On October 26, 2011, the PUCO approved our Economic Development 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		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.

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

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

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.

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 but there is some uncertainty as to the costs that will be recovered from or returned to customers. Independent third parties conducted the fuel audit in accordance with PUCO standards. On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the majority of the issues raised by the auditor. On October 19, 2011, we had a hearing on this case. Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation. DP&L expects to record a favorable or unfavorable adjustment to earnings after the final order is received.

DP&L [Member]

Regulatory Matters

3. Regulatory Matters

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

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

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, the electric discount provided to this customer may be recovered from all customers through an Economic Development Rider.

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

				At	At
	Type of	Amortization		September 30,	December 31,
$ in millions	Recovery (a)	Through		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.

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

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

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.

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 but there is some uncertainty as to the costs that will be recovered from or returned to customers. Independent third parties conducted the fuel audit in accordance with PUCO standards. On October 6, 2011, DP&L and all of the active participants in this proceeding reached a Stipulation and Recommendation that resolves the majority of the issues raised by the auditor. On October 19, 2011, we had a hearing on this case. Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation. DP&L expects to record a favorable or unfavorable adjustment to earnings after the final order is received.

XML

Overview and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2011	Dec. 31, 2010
Service Area Square Miles		6,000
Service Area By County		24
Approximate number of retail customers		500,000
Number of coal fired power plants	8	8
Entity number of employees	1,528	1,528	1,528
Employees under a collective bargaining agreement which expires in October-2011		53.00%
Deferred SECA revenue	$ 14,100,000	$ 14,100,000	$ 14,100,000	$ 15,400,000
Reduction of depreciation expense net		4,800,000.00	7,200,000
Reduction in depreciation expense net of tax		$ 3,100,000.00	$ 4,700,000
Increase in diluted EPS		$ 0.03	$ 0.04
DP&L [Member]
Entity number of employees	1,497	1,497	1,497

XML

Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities

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 September 30, 2011, DPL and DP&L had the following outstanding derivative instruments:

						Net Purchases/
	Accounting		Purchases	Sales		(Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs (1)	Mark to Market	MWh	11.3	1.0		12.3
Heating Oil Futures (1)	Mark to Market	Gallons	3,654.0	-		3,654.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	974.9	(746.5	)	228.4
Forward Power Contracts (1)	Mark to Market	MWh	587.0	(570.7	)	16.3
Forward Power Contracts (2)	Mark to Market	MWh	1,365.2	(1,350.1	)	15.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	2,658.3	-		2,658.3
Interest Rate Swaps (2)	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.

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

						Net Purchases/
	Accounting		Purchases	Sales		(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 September 30, 2011, we have outstanding interest rate hedging relationships with aggregate notional amounts of $160 million related to planned future borrowing activities in calendar year 2013. During the three months ended September 30, 2011, 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 entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL's 6.875% debt that was due in September 2011. The remainder 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 $3.1 million ($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 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.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	12.3		$	-		$	7.7
Net gains / (losses) associated with current
period hedging transactions		1.8			(49.8	)		(0.4	)		(8.9	)
Net (gains) / losses reclassified to earnings
Interest expense		-			1.4			-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
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		-			3.1
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.

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

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	11.0		$	-		$	13.5
Net gains / (losses) associated with current
period hedging transactions		1.8			-			(0.4	)		-
Net (gains) / losses reclassified to earnings
Interest expense		-			(0.6	)		-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

The following table provides information for DP&L 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	)	$	12.3		$	(1.4	)	$	14.7
Net gains / (losses) associated with current
period hedging transactions		0.8			-			3.3			-
Net (gains) / losses reclassified to earnings
Interest expense		-			(1.9	)		-			(1.8	)
Revenues		0.8			-			(1.5	)		-
Purchased power		0.6			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

The following tables show the fair value and balance sheet classification of DPL's derivative instruments designated as hedging instruments at September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DPL
									Fair Value on
$ in millions	Fair Value1			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
$ in millions	Fair Value1			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	)
Interest Rate Hedges in a Liability Position		(6.6	)		-		Other current liabilities		(6.6	)
Total short-term cash flow hedges	$	(9.4	)	$	1.0			$	(8.4	)
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	)
Interest Rate Hedges in an Asset Position		20.7			-		Other deferred assets		20.7
Total long-term cash flow hedges	$	20.7		$	(0.1	)		$	20.6
Total cash flow hedges	$	11.3		$	0.9			$	12.2

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 designated as hedging instruments at September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DP&L
									Fair Value on
$ in millions	Fair Value1			Netting2			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		(0.1	)		0.1		Other deferred credits		-
Total long-term cash flow hedges	$	1.3		$	(0.9	)		$	0.4
Total cash flow hedges	$	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 Value1			Netting2			Balance Sheet Location		Balance Sheet
Short-term Derivative Positions
Forward Power Contracts in a Liability Position	$	(2.8	)	$	1.0		Other current liabilities	$	(1.8	)
Total short-term cash flow hedges	$	(2.8	)	$	1.0			$	(1.8	)
Long-term Derivative Positions
Forward Power Contracts in an Asset Position	$	0.2		$	(0.2	)	Other deferred assets	$	-
Forward Power Contracts in a Liability Position		(0.2	)		0.1		Other deferred credits		(0.1	)
Total long-term cash flow hedges	$	-		$	(0.1	)		$	(0.1	)
Total cash flow hedges	$	(2.8	)	$	0.9			$	(1.9	)

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

Mark-to-Market Accounting

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

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

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	(0.3	)	$	(29.9	)
Realized gain / (loss)		4.3			0.5			-			1.2			6.0
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail Revenue	$	-		$	-		$	-		$	(1.6	)	$	(1.6	)
Purchased power		-			-			(0.1	)		2.5			2.4
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)

For the three months ended September 30, 2010
NYMEX
$ in millions		Coal		Heating Oil				FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	0.6		$	(41.1	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(6.3	)	$	(6.3	)
Purchased power		-			-		(0.7	)		6.1			5.4
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)

For the nine months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)		1.6			(1.5	)		(1.4	)		(0.1	)		(1.4	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	0.2		$	-		$	-		$	-		$	0.2
Regulatory (asset) / liability		(0.6	)		0.6			-			-			-
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(1.8	)		0.7			(1.1	)
Fuel		1.0			(0.5	)		-			-			0.5
O&M		-			(0.1	)		-			-			(0.1	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	0.3		$	(29.3	)
Realized gain / (loss)		4.3			0.5			-			(0.3	)		4.5
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(0.1	)		0.1			-
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)

For the three months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	-		$	(41.7	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(0.2	)	$	(0.2	)
Purchased power		-			-		(0.7	)		(0.6	)		(1.3	)
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)

For the nine months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)		1.6			(1.5	)		(1.4	)		(0.1	)		(1.4	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	0.2		$	-		$	-		$	-		$	0.2
Regulatory (asset) / liability		(0.6	)		0.6			-			-			-
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(1.8	)		0.7			(1.1	)
Fuel		1.0			(0.5	)		-			-			0.5
O&M		-			(0.1	)		-			-			(0.1	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)

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
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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 September 30, 2011.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at September 30, 2011
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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		0.7			(0.6	)	Other prepayments and current assets		0.1
Forward Power Contracts in a Liability position		(0.7	)		0.6		Other current liabilities		(0.1	)
NYMEX-Quality Coal Forwards in an Asset position		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		1.7			(1.7	)	Other prepayments and current assets		-
Total short-term derivative MTM positions	$	1.6		$	(0.8	)		$	0.8
Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.8		$	(0.5	)	Other deferred assets	$	0.3
Forward Power Contracts in a Liability position		(0.9	)		0.5		Other deferred credits		(0.4	)
NYMEX-Quality Coal Forwards in an Asset position		0.7			(0.3	)	Other deferred assets		0.4
NYMEX-Quality Coal Forwards in a Liability position		(4.5	)		4.5		Other deferred credits		-
Total long-term derivative MTM positions	$	(3.9	)	$	4.2			$	0.3
Total MTM Position	$	(2.3	)	$	3.4			$	1.1

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

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
									Fair Value on
$ in millions	Fair Value1				Netting2		Balance Sheet Location		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

¹Includes credit valuation adjustment.

²Includes 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 September 30, 2011 is $13.1 million. This amount is offset by $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 $2.1 million. If our debt were to fall below investment grade, we would have to post collateral for the remaining $4.1 million.

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

DP&L [Member]

Derivative Instruments and Hedging Activities

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 September 30, 2011, DPL and DP&L had the following outstanding derivative instruments:

						Net Purchases/
	Accounting		Purchases	Sales		(Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs (1)	Mark to Market	MWh	11.3	1.0		12.3
Heating Oil Futures (1)	Mark to Market	Gallons	3,654.0	-		3,654.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	974.9	(746.5	)	228.4
Forward Power Contracts (1)	Mark to Market	MWh	587.0	(570.7	)	16.3
Forward Power Contracts (2)	Mark to Market	MWh	1,365.2	(1,350.1	)	15.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	2,658.3	-		2,658.3
Interest Rate Swaps (2)	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.

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

						Net Purchases/
	Accounting		Purchases	Sales		(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 September 30, 2011, we have outstanding interest rate hedging relationships with aggregate notional amounts of $160 million related to planned future borrowing activities in calendar year 2013. During the three months ended September 30, 2011, 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 entered into a $425.0 million unsecured term loan agreement with a syndicated bank group on August 24, 2011, in part, to pay the approximately $297.4 million principal amount of DPL's 6.875% debt that was due in September 2011. The remainder 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 $3.1 million ($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 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.

The following table provides information for DPL concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	12.3		$	-		$	7.7
Net gains / (losses) associated with current
period hedging transactions		1.8			(49.8	)		(0.4	)		(8.9	)
Net (gains) / losses reclassified to earnings
Interest expense		-			1.4			-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
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		-			3.1
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.

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

The following table provides information for DP&L concerning gains or losses recognized in AOCI for the cash flow hedges for the three months ended September 30, 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	$	(1.5	)	$	11.0		$	-		$	13.5
Net gains / (losses) associated with current
period hedging transactions		1.8			-			(0.4	)		-
Net (gains) / losses reclassified to earnings
Interest expense		-			(0.6	)		-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

The following table provides information for DP&L 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	)	$	12.3		$	(1.4	)	$	14.7
Net gains / (losses) associated with current
period hedging transactions		0.8			-			3.3			-
Net (gains) / losses reclassified to earnings
Interest expense		-			(1.9	)		-			(1.8	)
Revenues		0.8			-			(1.5	)		-
Purchased power		0.6			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

The following tables show the fair value and balance sheet classification of DPL's derivative instruments designated as hedging instruments at September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DPL
									Fair Value on
$ in millions	Fair Value1			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
$ in millions	Fair Value1			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	)
Interest Rate Hedges in a Liability Position		(6.6	)		-		Other current liabilities		(6.6	)
Total short-term cash flow hedges	$	(9.4	)	$	1.0			$	(8.4	)
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	)
Interest Rate Hedges in an Asset Position		20.7			-		Other deferred assets		20.7
Total long-term cash flow hedges	$	20.7		$	(0.1	)		$	20.6
Total cash flow hedges	$	11.3		$	0.9			$	12.2

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 designated as hedging instruments at September 30, 2011 and December 31, 2010.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DP&L
									Fair Value on
$ in millions	Fair Value1			Netting2			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		(0.1	)		0.1		Other deferred credits		-
Total long-term cash flow hedges	$	1.3		$	(0.9	)		$	0.4
Total cash flow hedges	$	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 Value1			Netting2			Balance Sheet Location		Balance Sheet
Short-term Derivative Positions
Forward Power Contracts in a Liability Position	$	(2.8	)	$	1.0		Other current liabilities	$	(1.8	)
Total short-term cash flow hedges	$	(2.8	)	$	1.0			$	(1.8	)
Long-term Derivative Positions
Forward Power Contracts in an Asset Position	$	0.2		$	(0.2	)	Other deferred assets	$	-
Forward Power Contracts in a Liability Position		(0.2	)		0.1		Other deferred credits		(0.1	)
Total long-term cash flow hedges	$	-		$	(0.1	)		$	(0.1	)
Total cash flow hedges	$	(2.8	)	$	0.9			$	(1.9	)

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

Mark-to-Market Accounting

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

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

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	(0.3	)	$	(29.9	)
Realized gain / (loss)		4.3			0.5			-			1.2			6.0
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail Revenue	$	-		$	-		$	-		$	(1.6	)	$	(1.6	)
Purchased power		-			-			(0.1	)		2.5			2.4
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)

For the three months ended September 30, 2010
NYMEX
$ in millions		Coal		Heating Oil				FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	0.6		$	(41.1	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(6.3	)	$	(6.3	)
Purchased power		-			-		(0.7	)		6.1			5.4
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)

For the nine months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)		1.6			(1.5	)		(1.4	)		(0.1	)		(1.4	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	0.2		$	-		$	-		$	-		$	0.2
Regulatory (asset) / liability		(0.6	)		0.6			-			-			-
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(1.8	)		0.7			(1.1	)
Fuel		1.0			(0.5	)		-			-			0.5
O&M		-			(0.1	)		-			-			(0.1	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)

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 nine months ended September 30, 2011 and 2010.

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	0.3		$	(29.3	)
Realized gain / (loss)		4.3			0.5			-			(0.3	)		4.5
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(0.1	)		0.1			-
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)

For the three months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	-		$	(41.7	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(0.2	)	$	(0.2	)
Purchased power		-			-		(0.7	)		(0.6	)		(1.3	)
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)

For the nine months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)		1.6			(1.5	)		(1.4	)		(0.1	)		(1.4	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	0.2		$	-		$	-		$	-		$	0.2
Regulatory (asset) / liability		(0.6	)		0.6			-			-			-
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(1.8	)		0.7			(1.1	)
Fuel		1.0			(0.5	)		-			-			0.5
O&M		-			(0.1	)		-			-			(0.1	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)

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
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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 September 30, 2011.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at September 30, 2011
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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		0.7			(0.6	)	Other prepayments and current assets		0.1
Forward Power Contracts in a Liability position		(0.7	)		0.6		Other current liabilities		(0.1	)
NYMEX-Quality Coal Forwards in an Asset position		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		1.7			(1.7	)	Other prepayments and current assets		-
Total short-term derivative MTM positions	$	1.6		$	(0.8	)		$	0.8
Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.8		$	(0.5	)	Other deferred assets	$	0.3
Forward Power Contracts in a Liability position		(0.9	)		0.5		Other deferred credits		(0.4	)
NYMEX-Quality Coal Forwards in an Asset position		0.7			(0.3	)	Other deferred assets		0.4
NYMEX-Quality Coal Forwards in a Liability position		(4.5	)		4.5		Other deferred credits		-
Total long-term derivative MTM positions	$	(3.9	)	$	4.2			$	0.3
Total MTM Position	$	(2.3	)	$	3.4			$	1.1

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

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
									Fair Value on
$ in millions	Fair Value1				Netting2		Balance Sheet Location		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

¹Includes credit valuation adjustment.

²Includes 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 September 30, 2011 is $13.1 million. This amount is offset by $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 $2.1 million. If our debt were to fall below investment grade, we would have to post collateral for the remaining $4.1 million.

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

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Contractual Obligations, Commercial Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Contractual Obligations, Commercial Commitments and Contingencies

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 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 September 30, 2011, DPL had $86.7 million of guarantees to third parties for future financial or performance assurance under such agreements including $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 $0.5 million and $1.7 million at 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.

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or $61.0 million, of a $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 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 changes in our debt as discussed in Note 5 of Notes to Condensed Consolidated Financial Statements.

Contingencies

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

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 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.

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 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 were distributed in the fourth quarter of 2011. We are in the process of reviewing the rule and are currently unable to predict the ultimate financial effect. We do not believe the rule will have a material impact on our operations in 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.

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 was 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 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. There is a possibility that these areas will be re-designated as "attainment" for PM 2.5 within the 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. On September 2, 2011, the USEPA decided to 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.

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 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 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 to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

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

Litigation Involving Co-Owned Plants

On June 20, 2011, the Supreme Court rejected federal common law nuisance claims brought initially in 2004 by eight states, the City of New York and three land trusts, who had sought injunctive relief and limitations on GHGs emitted by American Electric Power Company, Inc. (AEP), one of AEP's subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. 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 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.

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. More than five years have passed since the malfunction was reported and management does not believe that there will be a resolution of this matter 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 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 this issue.

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. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012.  We do not yet know the impact these proposed rules will have on our operations.

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. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised Permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA's objection, then the authority for issuing the permit will pass to the USEPA. DP&L is unable to predict the timing for issuance of a final 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 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.

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 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 responded to the USEPA final inspection report with plans to address the recommendations.  DP&L is unable to predict whether there will be additional USEPA action relative to DP&L's proposed plan or the effect on operations that might arise under a different plan.

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

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&L submitted 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.

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.

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 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. DP&L recently underwent an audit of its fuel and purchased power recovery rider but there is some uncertainty as to the costs that will be 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 majority of the issues raised by the auditor. On October 19, 2011, we had a hearing on this case. Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation. DP&L expects to record a favorable or unfavorable adjustment to earnings after the 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 became 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 October 26, 2011 the PUCO approved our Economic Development Rider, as filed, related to this arrangement.

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

Refer to Note 16 of Notes to Condensed Consolidated Financial Statements for additional information surrounding the Proposed Merger and any related legal matters.

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.

DP&L [Member]

Contractual Obligations, Commercial Commitments and Contingencies

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 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 September 30, 2011, DPL had $86.7 million of guarantees to third parties for future financial or performance assurance under such agreements including $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 $0.5 million and $1.7 million at 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.

DP&L – Equity Ownership Interest

DP&L owns a 4.9% equity ownership interest in an electric generation company which is recorded using the cost method of accounting under GAAP. As of September 30, 2011, DP&L could be responsible for the repayment of 4.9%, or $61.0 million, of a $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 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 changes in our debt as discussed in Note 5 of Notes to Condensed Consolidated Financial Statements.

Contingencies

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

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 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.

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 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 were distributed in the fourth quarter of 2011. We are in the process of reviewing the rule and are currently unable to predict the ultimate financial effect. We do not believe the rule will have a material impact on our operations in 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.

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 was 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 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. There is a possibility that these areas will be re-designated as "attainment" for PM 2.5 within the 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. On September 2, 2011, the USEPA decided to 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.

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 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 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 to the USEPA was submitted prior to the September 30, 2011 due date for 2010 emissions. This reporting rule will guide development of policies and programs to reduce emissions. DP&L does not anticipate that this reporting rule will result in any significant cost or other impact on current operations.

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

Litigation Involving Co-Owned Plants

On June 20, 2011, the Supreme Court rejected federal common law nuisance claims brought initially in 2004 by eight states, the City of New York and three land trusts, who had sought injunctive relief and limitations on GHGs emitted by American Electric Power Company, Inc. (AEP), one of AEP's subsidiaries, Cinergy Corp. (a subsidiary of Duke Energy Corporation (Duke Energy)) and four other electric power companies. 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 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.

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. More than five years have passed since the malfunction was reported and management does not believe that there will be a resolution of this matter 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 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 this issue.

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. We submitted comments to the proposed regulations on August 17, 2011. The final rules are expected to be in place by mid-2012. We do not yet know the impact these proposed rules will have on our operations.

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. In December 2008, the USEPA requested that the Ohio EPA provide additional information regarding the thermal discharge in the draft permit. In June 2009, DP&L provided information to the USEPA in response to their request to the Ohio EPA. In September 2010, the USEPA formally objected to a revised Permit provided by Ohio EPA due to questions regarding the basis for the alternate thermal limitation. In December 2010, DP&L requested a public hearing on the objection, which was held on March 23, 2011. We participated in and presented our position on the issue at the hearing and in written comments submitted on April 28, 2011. In a letter to the Ohio EPA dated September 28, 2011, the USEPA reaffirmed its objection to the revised permit as previously drafted by the Ohio EPA. This reaffirmation stipulated that if the Ohio EPA does not re-draft the permit to address the USEPA's objection, then the authority for issuing the permit will pass to the USEPA. DP&L is unable to predict the timing for issuance of a final 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 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.

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 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 responded to the USEPA final inspection report with plans to address the recommendations. DP&L is unable to predict whether there will be additional USEPA action relative to DP&L's proposed plan or the effect on operations that might arise under a different plan.

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

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&L submitted 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.

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.

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 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. DP&L recently underwent an audit of its fuel and purchased power recovery rider but there is some uncertainty as to the costs that will be 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 majority of the issues raised by the auditor. On October 19, 2011, we had a hearing on this case. Although the Stipulation and Recommendation was uncontested, the PUCO may approve, disapprove, or modify the stipulation. DP&L expects to record a favorable or unfavorable adjustment to earnings after the 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 became 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 October 26, 2011 the PUCO approved our Economic Development Rider, as filed, related to this arrangement.

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

Refer to Note 16 of Notes to Condensed Consolidated Financial Statements for additional information surrounding the Proposed Merger and any related legal matters.

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.

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Share-Based Compensation

9 Months Ended

Sep. 30, 2011

Share-Based Compensation

10. Share-Based Compensation

Share-based compensation expense was $1.3 million ($0.8 million net of tax) and $1.2 million ($0.8 million net of tax) for the three months ended September 30, 2011 and 2010, respectively, and $4.0 million ($2.6 million net of tax) and $3.8 million ($2.5 million net of tax) for the nine months ended 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 September 30, 2011 and 2010 was as follows:

		Options				RSUs			Performance Shares
	2011			2010	2011		2010		2011	2010
Outstanding at beginning of period		500		351,500		-	3,311		296,591	307,985
Granted		-		-		-	-		-	-
Dividends		-		-		-	-		-	-
Exercised		(500	)	-		-	(3,311	)	-	-
Expired		-		-		-	-		-	-
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 period	284,237		249,101		111,298		110,706
Granted	-		2,617		-		-
Dividends	-		-		-		-
Exercised	(25,585	)	(1,800	)	-		-
Expired	-		-		-		-
Forfeited	-		(7,635	)	(2,340	)	(1,494	)
Outstanding at period end	258,652		242,283		108,958		109,212
Exercisable at period end	-		-		-		-

	Director RSUs
	2011		2010
Outstanding at beginning of period	-		15,944
Granted	14,392		-
Dividends accrued	634		655
Exercised and issued	-		-
Exercised and deferred	(634	)	(471	)
Forfeited	-		-
Outstanding at period end	14,392		16,128
Exercisable at period end	-		-

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.

DP&L [Member]

Share-Based Compensation

10. Share-Based Compensation

Share-based compensation expense was $1.3 million ($0.8 million net of tax) and $1.2 million ($0.8 million net of tax) for the three months ended September 30, 2011 and 2010, respectively, and $4.0 million ($2.6 million net of tax) and $3.8 million ($2.5 million net of tax) for the nine months ended 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 September 30, 2011 and 2010 was as follows:

		Options				RSUs			Performance Shares
	2011			2010	2011		2010		2011	2010
Outstanding at beginning of period		500		351,500		-	3,311		296,591	307,985
Granted		-		-		-	-		-	-
Dividends		-		-		-	-		-	-
Exercised		(500	)	-		-	(3,311	)	-	-
Expired		-		-		-	-		-	-
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 period	284,237		249,101		111,298		110,706
Granted	-		2,617		-		-
Dividends	-		-		-		-
Exercised	(25,585	)	(1,800	)	-		-
Expired	-		-		-		-
Forfeited	-		(7,635	)	(2,340	)	(1,494	)
Outstanding at period end	258,652		242,283		108,958		109,212
Exercisable at period end	-		-		-		-

	Director RSUs
	2011		2010
Outstanding at beginning of period	-		15,944
Granted	14,392		-
Dividends accrued	634		655
Exercised and issued	-		-
Exercised and deferred	(634	)	(471	)
Forfeited	-		-
Outstanding at period end	14,392		16,128
Exercisable at period end	-		-

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.

XML

Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2011

Share-Based Compensation [Abstract]

Summarized Share-Based Compensation Activity

		Options				RSUs			Performance Shares
	2011			2010	2011		2010		2011	2010
Outstanding at beginning of period		500		351,500		-	3,311		296,591	307,985
Granted		-		-		-	-		-	-
Dividends		-		-		-	-		-	-
Exercised		(500	)	-		-	(3,311	)	-	-
Expired		-		-		-	-		-	-
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 period	284,237		249,101		111,298		110,706
Granted	-		2,617		-		-
Dividends	-		-		-		-
Exercised	(25,585	)	(1,800	)	-		-
Expired	-		-		-		-
Forfeited	-		(7,635	)	(2,340	)	(1,494	)
Outstanding at period end	258,652		242,283		108,958		109,212
Exercisable at period end	-		-		-		-

	Director RSUs
	2011		2010
Outstanding at beginning of period	-		15,944
Granted	14,392		-
Dividends accrued	634		655
Exercised and issued	-		-
Exercised and deferred	(634	)	(471	)
Forfeited	-		-
Outstanding at period end	14,392		16,128
Exercisable at period end	-		-

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	-		-

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The fair value of our financial instruments represents estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at September 30, 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 September 30,				At December 31,
		2011				2010
$ in millions		Cost	Fair Value			Cost	Fair Value
DPL
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities		3.9		4.0		3.8		4.4
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	9.5	$	10.0	$	10.9	$	11.8
Short-term Investments - VRDNs	$	-	$	-	$	54.2	$	54.2
Short-term Investments - Bonds		-		-		15.1		15.1
Total Short-term Investments	$	-	$	-	$	69.3	$	69.3
Total Assets	$	9.5	$	10.0	$	80.2	$	81.1
Liabilities
Debt	$	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
Equity Securities (a)		17.3		33.5		17.5		30.2
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	22.9	$	39.5	$	24.6	$	37.6
Liabilities
Debt	$	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 at 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 as debt is presented at amortized cost in the Condensed Consolidated Financial Statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2061.

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.

DPL had $0.5 million ($0.3 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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 $16.6 million ($10.8 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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.

Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 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 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
		Fair Value at		Fair Value at		Unfunded	Redemption
$ in millions		September 30, 2011	December 31, 2010			Commitments	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 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 nine months ended September 30, 2011.

The fair value of assets and liabilities at 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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at				Based on Quoted	Other				Collateral and			Balance Sheet at
	September 30,				Prices in Active	Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities			4.0		-		4.0		-		-			4.0
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		10.0	$	-	$	10.0	$	-	$	-		$	10.0
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.3		-		2.3		-		(1.2	)		1.1
Forward Power Contracts			12.8		-		12.8		-		(2.0	)		10.8
Total Derivative Assets	$		16.9	$	1.7	$	15.2	$	-	$	(4.9	)	$	12.0
Short-term Investments - Bonds			-		-		-		-		-			-
Total Short-term investments	$		-	$	-	$	-	$	-	$	-		$	-
Total Assets	$		26.9	$	1.7	$	25.2	$	-	$	(4.9	)	$	22.0
Liabilities
Derivative Liabilities
Interest Rate Hedge	$		28.5	$	-	$	28.5	$	-	$	-		$	28.5
Forward NYMEX Coal Contracts			6.3		-		6.3		-		(6.3)			-
Forward Power Contracts			6.6		-		6.6		-		(2.6)			4.0
Total Derivative Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5
Total Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5

*Includes credit valuation adjustments for counterparty risk.

DPL
				Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1		Level 2		Level 3
														Fair Value on
		Fair Value at		Based on Quoted			Other			Collateral and				Balance Sheet at
		December 31, Prices in Active				Observable Unobservable Counterparty								December 31,
$ in millions		2010	*		Markets		Inputs		Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$	1.6		$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities		4.4			-		4.4		-		-			4.4
Debt Securities		5.5			-		5.5		-		-			5.5
Multi-Strategy Fund		0.3			-		0.3		-		-			0.3
Total Master Trust Assets	$	11.8		$	-	$	11.8	$	-	$	-		$	11.8
Derivative Assets
FTRs	$	0.3		$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures		1.6			1.6		-		-		(1.6	)		-
Interest Rate Hedge		20.7			-		20.7		-		-			20.7
Forward NYMEX Coal Contracts		37.5			-		37.5		-		(21.9	)		15.6
Forward Power Contracts		0.2			-		0.2		-		(0.2	)		-
Total Derivative Assets	$	60.3		$	1.6	$	58.7	$	-	$	(23.7	)	$	36.6
Short-term Investments - VRDNs	$	54.2		$	-	$	54.2	$	-	$	-		$	54.2
Short-term Investments - Bonds		15.1			-		15.1		-		-			15.1
Total Short-term investments	$	69.3		$	-	$	69.3	$	-	$	-		$	69.3
Total Assets	$	141.4		$	1.6	$	139.8	$	-	$	(23.7	)	$	117.7
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	6.6		$	-	$	6.6	$	-	$	-		$	6.6
Forward Power Contracts		3.1			-		3.1		-		(1.1	)		2.0
Total Derivative Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6
Total Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6

*Includes credit valuation adjustments for counterparty risk.

The fair value of assets and liabilities at 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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	September 30, Prices in Active					Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities (a)			33.5		29.5		4.0		-		-			33.5
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		39.5	$	29.5	$	10.0	$	-	$	-		$	39.5
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.3		-		2.3		-		(1.2	)		1.1
Forward Power Contracts			3.2		-		3.2		-		(2.4	)		0.8
Total Derivative Assets	$		7.3	$	1.7	$	5.6	$	-	$	(5.3	)	$	2.0
Total Assets	$		46.8	$	31.2	$	15.6	$	-	$	(5.3	)	$	41.5
Liabilities
Derivative Liabilities
Forward NYMEX Coal Contracts	$		6.3	$	-	$	6.3	$	-	$	(6.3)		$	-
Forward Power Contracts			2.8		-		2.8		-		(1.4)			1.4
Total Derivative Liabilities	$		9.1	$	-	$	9.1	$	-	$	(7.7)		$	1.4
Total Liabilities	$		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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	December 31, Prices in Active					Observable Unobservable Counterparty December 31,
$ in millions	2010	*			Markets	Inputs			Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$		1.6	$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities (a)			30.2		25.8		4.4		-		-			30.2
Debt Securities			5.5		-		5.5		-		-			5.5
Multi-Strategy Fund			0.3		-		0.3		-		-			0.3
Total Master Trust Assets	$		37.6	$	25.8	$	11.8	$	-	$	-		$	37.6
Derivative Assets
FTRs	$		0.3	$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures			1.6		1.6		-		-		(1.6	)		-
Forward NYMEX Coal Contracts			37.5		-		37.5		-		(21.9	)		15.6
Forward Power Contracts			0.2		-		0.2		-		(0.2	)		-
Total Derivative Assets	$		39.6	$	1.6	$	38.0	$	-	$	(23.7	)	$	15.9
Total Assets	$		77.2	$	27.4	$	49.8	$	-	$	(23.7	)	$	53.5
Liabilities
Derivative Liabilities
Forward Power Contracts	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Derivative Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0

*Includes credit valuation adjustments for counterparty risk.

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

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 98% and 87% of the inputs to the fair value of our derivative instruments are from quoted market 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 nine months ended September 30, 2011.

Cash Equivalents

DPL had no money in money market funds at September 30, 2011 and $29.9 million in money market funds at December 31, 2010 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.

DP&L [Member]

Fair Value Measurements

8. Fair Value Measurements

The fair values of our financial instruments are based on published sources for pricing when possible. We rely on valuation models only when no other methods exist. The fair value of our financial instruments represents estimates of possible value that may not be realized in the future. The table below presents the fair value and cost of our non-derivative instruments at September 30, 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 September 30,				At December 31,
		2011				2010
$ in millions		Cost	Fair Value			Cost	Fair Value
DPL
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities		3.9		4.0		3.8		4.4
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	9.5	$	10.0	$	10.9	$	11.8
Short-term Investments - VRDNs	$	-	$	-	$	54.2	$	54.2
Short-term Investments - Bonds		-		-		15.1		15.1
Total Short-term Investments	$	-	$	-	$	69.3	$	69.3
Total Assets	$	9.5	$	10.0	$	80.2	$	81.1
Liabilities
Debt	$	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
Equity Securities (a)		17.3		33.5		17.5		30.2
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	22.9	$	39.5	$	24.6	$	37.6
Liabilities
Debt	$	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 at 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 as debt is presented at amortized cost in the Condensed Consolidated Financial Statements. The debt amounts include the current portion payable in the next twelve months and have maturities that range from 2011 to 2061.

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.

DPL had $0.5 million ($0.3 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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 $16.6 million ($10.8 million after tax) in unrealized gains and $0.1 million ($0.1 million after tax) in unrealized losses on the Master Trust assets in AOCI at 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.

Net Asset Value (NAV) per Unit

The following table discloses the fair value and redemption frequency for those assets whose fair value is estimated using the NAV per unit as of September 30, 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 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
		Fair Value at		Fair Value at		Unfunded	Redemption
$ in millions		September 30, 2011	December 31, 2010			Commitments	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 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 nine months ended September 30, 2011.

The fair value of assets and liabilities at 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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at				Based on Quoted	Other				Collateral and			Balance Sheet at
	September 30,				Prices in Active	Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities			4.0		-		4.0		-		-			4.0
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		10.0	$	-	$	10.0	$	-	$	-		$	10.0
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.3		-		2.3		-		(1.2	)		1.1
Forward Power Contracts			12.8		-		12.8		-		(2.0	)		10.8
Total Derivative Assets	$		16.9	$	1.7	$	15.2	$	-	$	(4.9	)	$	12.0
Short-term Investments - Bonds			-		-		-		-		-			-
Total Short-term investments	$		-	$	-	$	-	$	-	$	-		$	-
Total Assets	$		26.9	$	1.7	$	25.2	$	-	$	(4.9	)	$	22.0
Liabilities
Derivative Liabilities
Interest Rate Hedge	$		28.5	$	-	$	28.5	$	-	$	-		$	28.5
Forward NYMEX Coal Contracts			6.3		-		6.3		-		(6.3)			-
Forward Power Contracts			6.6		-		6.6		-		(2.6)			4.0
Total Derivative Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5
Total Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5

*Includes credit valuation adjustments for counterparty risk.

DPL
				Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1		Level 2		Level 3
														Fair Value on
		Fair Value at		Based on Quoted			Other			Collateral and				Balance Sheet at
		December 31, Prices in Active				Observable Unobservable Counterparty								December 31,
$ in millions		2010	*		Markets		Inputs		Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$	1.6		$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities		4.4			-		4.4		-		-			4.4
Debt Securities		5.5			-		5.5		-		-			5.5
Multi-Strategy Fund		0.3			-		0.3		-		-			0.3
Total Master Trust Assets	$	11.8		$	-	$	11.8	$	-	$	-		$	11.8
Derivative Assets
FTRs	$	0.3		$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures		1.6			1.6		-		-		(1.6	)		-
Interest Rate Hedge		20.7			-		20.7		-		-			20.7
Forward NYMEX Coal Contracts		37.5			-		37.5		-		(21.9	)		15.6
Forward Power Contracts		0.2			-		0.2		-		(0.2	)		-
Total Derivative Assets	$	60.3		$	1.6	$	58.7	$	-	$	(23.7	)	$	36.6
Short-term Investments - VRDNs	$	54.2		$	-	$	54.2	$	-	$	-		$	54.2
Short-term Investments - Bonds		15.1			-		15.1		-		-			15.1
Total Short-term investments	$	69.3		$	-	$	69.3	$	-	$	-		$	69.3
Total Assets	$	141.4		$	1.6	$	139.8	$	-	$	(23.7	)	$	117.7
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	6.6		$	-	$	6.6	$	-	$	-		$	6.6
Forward Power Contracts		3.1			-		3.1		-		(1.1	)		2.0
Total Derivative Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6
Total Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6

*Includes credit valuation adjustments for counterparty risk.

The fair value of assets and liabilities at 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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	September 30, Prices in Active					Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities (a)			33.5		29.5		4.0		-		-			33.5
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		39.5	$	29.5	$	10.0	$	-	$	-		$	39.5
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.3		-		2.3		-		(1.2	)		1.1
Forward Power Contracts			3.2		-		3.2		-		(2.4	)		0.8
Total Derivative Assets	$		7.3	$	1.7	$	5.6	$	-	$	(5.3	)	$	2.0
Total Assets	$		46.8	$	31.2	$	15.6	$	-	$	(5.3	)	$	41.5
Liabilities
Derivative Liabilities
Forward NYMEX Coal Contracts	$		6.3	$	-	$	6.3	$	-	$	(6.3)		$	-
Forward Power Contracts			2.8		-		2.8		-		(1.4)			1.4
Total Derivative Liabilities	$		9.1	$	-	$	9.1	$	-	$	(7.7)		$	1.4
Total Liabilities	$		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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	December 31, Prices in Active					Observable Unobservable Counterparty December 31,
$ in millions	2010	*			Markets	Inputs			Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$		1.6	$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities (a)			30.2		25.8		4.4		-		-			30.2
Debt Securities			5.5		-		5.5		-		-			5.5
Multi-Strategy Fund			0.3		-		0.3		-		-			0.3
Total Master Trust Assets	$		37.6	$	25.8	$	11.8	$	-	$	-		$	37.6
Derivative Assets
FTRs	$		0.3	$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures			1.6		1.6		-		-		(1.6	)		-
Forward NYMEX Coal Contracts			37.5		-		37.5		-		(21.9	)		15.6
Forward Power Contracts			0.2		-		0.2		-		(0.2	)		-
Total Derivative Assets	$		39.6	$	1.6	$	38.0	$	-	$	(23.7	)	$	15.9
Total Assets	$		77.2	$	27.4	$	49.8	$	-	$	(23.7	)	$	53.5
Liabilities
Derivative Liabilities
Forward Power Contracts	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Derivative Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0

*Includes credit valuation adjustments for counterparty risk.

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

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 98% and 87% of the inputs to the fair value of our derivative instruments are from quoted market 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 nine months ended September 30, 2011.

Cash Equivalents

DPL had no money in money market funds at September 30, 2011 and $29.9 million in money market funds at December 31, 2010 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.

XML

Pension and Postretirement Benefits (Estimated Future Benefit Payments) (Details) (USD $) In Millions	Sep. 30, 2011
Pension [Member]
2011	$ 5.3
2012	23.1
2013	23.1
2014	23.6
2015	24.0
2016 - 2020	122.9
Postretirement [ Member]
2011	0.6
2012	2.4
2013	2.4
2014	2.3
2015	2.1
2016 - 2020	$ 8.8

XML

Overview and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Overview and Summary of Significant Accounting Policies

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

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.

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 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 September 30, 2011; our results of operations for the three and nine months ended September 30, 2011; and our cash flows for the nine months ended 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 nine months ended 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 nine months ended September 30, 2011 and 2010 was not material.

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

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

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

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

.

Depreciation Study – Change in Estimate

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL's generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation study concluded that many of DPL's composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated. DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the nine months ended September 30, 2011, the reduction was $4.8 million ($3.1 million, net of tax) and increased diluted EPS by approximately $0.03 per share. The net reduction in depreciation expense for the twelve months ended September 30, 2011 was $7.2 million ($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				Nine Months Ended
		September 30,				September 30,
$ in millions		2011		2010		2011		2010
State/Local excise taxes	$	14.3	$	14.6	$	39.9	$	40.1

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						Nine Months Ended
		September 30,						September 30,
$ in millions		2011			2010			2011			2010
DP&L Revenues:
Sales to DPLER (a)	$	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	)	$	(2.4	)	$	(2.5	)
Expense recoveries for services provided to DPLER (c)	$	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 nine months ended 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. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts. 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.

DP&L [Member]

Overview and Summary of Significant Accounting Policies

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

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.

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 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 September 30, 2011; our results of operations for the three and nine months ended September 30, 2011; and our cash flows for the nine months ended 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 nine months ended 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 nine months ended September 30, 2011 and 2010 was not material.

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

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

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

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

.

Depreciation Study – Change in Estimate

Depreciation expense is calculated using the straight-line method, which allocates the cost of property over its estimated useful life. For DPL's generation, transmission and distribution assets, straight-line depreciation is applied monthly on an average composite basis using group rates. In July 2010, DPL completed a depreciation rate study for non-regulated generation property based on its property, plant and equipment balances at December 31, 2009, with certain adjustments for subsequent property additions. The results of the depreciation study concluded that many of DPL's composite depreciation rates should be reduced due to projected useful asset lives which are longer than those previously estimated. DPL adjusted the depreciation rates for its non-regulated generation property effective July 1, 2010, resulting in a net reduction of depreciation expense. For the nine months ended September 30, 2011, the reduction was $4.8 million ($3.1 million, net of tax) and increased diluted EPS by approximately $0.03 per share. The net reduction in depreciation expense for the twelve months ended September 30, 2011 was $7.2 million ($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				Nine Months Ended
		September 30,				September 30,
$ in millions		2011		2010		2011		2010
State/Local excise taxes	$	14.3	$	14.6	$	39.9	$	40.1

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						Nine Months Ended
		September 30,						September 30,
$ in millions		2011			2010			2011			2010
DP&L Revenues:
Sales to DPLER (a)	$	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	)	$	(2.4	)	$	(2.5	)
Expense recoveries for services provided to DPLER (c)	$	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 nine months ended 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. It also increases reporting for financial instruments disclosed at fair value but not recorded at fair value and provides clarification of blockage factors and other premiums and discounts. 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.

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Ownership of Coal-fired Facilities

9 Months Ended

Sep. 30, 2011

Ownership of Coal-fired Facilities

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 September 30, 2011, we had $42 million of construction work in process at such facilities. DP&L's share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L's share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

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

	DP&L Share						DP&L Investment
										SCR and FGD
										Equipment
		Summer						Construction		Installed
		Production Gross Plant Accumulated							Work in	and In
	Ownership	Capacity		In Service		Depreciation			Process	Service
	(%)	(MW)		($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	207	$	76		$	57	$	-	No
Conesville Unit 4	16.5	129			119		31		5	Yes
East Bend Station	31.0	186			201		132		-	Yes
Killen Station	67.0	402			617		298		2	Yes
Miami Fort Units 7 and 8	36.0	368			366		137		2	Yes
Stuart Station	35.0	808			719		275		15	Yes
Zimmer Station	28.1	365			1,060		624		18	Yes
Transmission (at varying percentages)		-			91		57		-
Total		2,465	$	3,249		$	1,611	$	42
Wholly-owned production unit:
Hutchings Station	100.0	390		$	124	$	114	$	1	No

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

DP&L [Member]

Ownership of Coal-fired Facilities

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 September 30, 2011, we had $42 million of construction work in process at such facilities. DP&L's share of the operating cost of such facilities is included within the corresponding line in the Condensed Statements of Results of Operations and DP&L's share of the investment in the facilities is included within Total net property, plant and equipment in the Condensed Balance Sheets.

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

	DP&L Share						DP&L Investment
										SCR and FGD
										Equipment
		Summer						Construction		Installed
		Production Gross Plant Accumulated							Work in	and In
	Ownership	Capacity		In Service		Depreciation			Process	Service
	(%)	(MW)		($ in millions)		($ in millions)		($ in millions)		(Yes/No)
Production Units:
Beckjord Unit 6	50.0	207	$	76		$	57	$	-	No
Conesville Unit 4	16.5	129			119		31		5	Yes
East Bend Station	31.0	186			201		132		-	Yes
Killen Station	67.0	402			617		298		2	Yes
Miami Fort Units 7 and 8	36.0	368			366		137		2	Yes
Stuart Station	35.0	808			719		275		15	Yes
Zimmer Station	28.1	365			1,060		624		18	Yes
Transmission (at varying percentages)		-			91		57		-
Total		2,465	$	3,249		$	1,611	$	42
Wholly-owned production unit:
Hutchings Station	100.0	390		$	124	$	114	$	1	No

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

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Regulatory Matters (Narrative) (Details)	3 Months Ended	9 Months Ended
	Sep. 30, 2009	Sep. 30, 2011
Duration of plan, months		42
Reconciliation period	2
Regional Transmission Organization Costs [Member]
Regulatory asset, amortization period, years		10

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2010

Sep. 30, 2011

Dec. 31, 2010

Sep. 30, 2011

DP&L [Member]

Sep. 30, 2010

DP&L [Member]

Sep. 30, 2011

DP&L [Member]

Sep. 30, 2010

DP&L [Member]

Schedule of Notional Amounts of Outstanding Derivative Positions

						Net Purchases/
	Accounting		Purchases	Sales		(Sales)
Commodity	Treatment	Unit	(in thousands)	(in thousands)		(in thousands)
FTRs (1)	Mark to Market	MWh	11.3	1.0		12.3
Heating Oil Futures (1)	Mark to Market	Gallons	3,654.0	-		3,654.0
Forward Power Contracts (1)	Cash Flow Hedge	MWh	974.9	(746.5	)	228.4
Forward Power Contracts (1)	Mark to Market	MWh	587.0	(570.7	)	16.3
Forward Power Contracts (2)	Mark to Market	MWh	1,365.2	(1,350.1	)	15.1
NYMEX-quality Coal Contracts* (1)	Mark to Market	Tons	2,658.3	-		2,658.3
Interest Rate Swaps (2)	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.

						Net Purchases/
	Accounting		Purchases	Sales		(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.

Gains or Losses Recognized in AOCI for the Cash Flow Hedges

		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	$	(1.5	)	$	12.3		$	-		$	7.7
Net gains / (losses) associated with current
period hedging transactions		1.8			(49.8	)		(0.4	)		(8.9	)
Net (gains) / losses reclassified to earnings
Interest expense		-			1.4			-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
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		-			3.1
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.

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

		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	$	(1.5	)	$	11.0		$	-		$	13.5
Net gains / (losses) associated with current
period hedging transactions		1.8			-			(0.4	)		-
Net (gains) / losses reclassified to earnings
Interest expense		-			(0.6	)		-			(0.6	)
Revenues		0.1			-			0.8			-
Purchased power		-			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

The following table provides information for DP&L 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	)	$	12.3		$	(1.4	)	$	14.7
Net gains / (losses) associated with current
period hedging transactions		0.8			-			3.3			-
Net (gains) / losses reclassified to earnings
Interest expense		-			(1.9	)		-			(1.8	)
Revenues		0.8			-			(1.5	)		-
Purchased power		0.6			-			-			-
Ending accumulated derivative
gain / (loss) in AOCI	$	0.4		$	10.4		$	0.4		$	12.9
Net (gains) / losses associated with the
ineffective portion of the hedging transaction
Interest expense		-			-
Revenues		-			-
Portion expected to be reclassified to
earnings in the next twelve months*	$	0.8		$	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			-

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

Schedule of Derivative Assets and Liabilities at Fair Value

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DPL
									Fair Value on
$ in millions	Fair Value1			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
$ in millions	Fair Value1			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	)
Interest Rate Hedges in a Liability Position		(6.6	)		-		Other current liabilities		(6.6	)
Total short-term cash flow hedges	$	(9.4	)	$	1.0			$	(8.4	)
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	)
Interest Rate Hedges in an Asset Position		20.7			-		Other deferred assets		20.7
Total long-term cash flow hedges	$	20.7		$	(0.1	)		$	20.6
Total cash flow hedges	$	11.3		$	0.9			$	12.2

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Designated as Hedging Instruments
at September 30, 2011
DP&L
									Fair Value on
$ in millions	Fair Value1			Netting2			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		(0.1	)		0.1		Other deferred credits		-
Total long-term cash flow hedges	$	1.3		$	(0.9	)		$	0.4
Total cash flow hedges	$	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 Value1			Netting2			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.

Schedule of Gains and Losses on Derivatives Not Designated as Hedging Instruments

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	(0.3	)	$	(29.9	)
Realized gain / (loss)		4.3			0.5			-			1.2			6.0
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail Revenue	$	-		$	-		$	-		$	(1.6	)	$	(1.6	)
Purchased power		-			-			(0.1	)		2.5			2.4
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	0.9		$	(23.9	)

For the three months ended September 30, 2010
NYMEX
$ in millions		Coal		Heating Oil				FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	0.6		$	(41.1	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(6.3	)	$	(6.3	)
Purchased power		-			-		(0.7	)		6.1			5.4
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.2	)	$	(32.9	)

For the three months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(27.9	)	$	(1.6	)	$	(0.1	)	$	0.3		$	(29.3	)
Realized gain / (loss)		4.3			0.5			-			(0.3	)		4.5
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(13.8	)	$	-		$	-		$	-		$	(13.8	)
Regulatory (asset) / liability		(4.0	)		(0.6	)		-			-			(4.6	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(0.1	)		0.1			-
Fuel		(5.8	)		(0.5	)		-			-			(6.3	)
O&M		-			-			-			-			-
Total	$	(23.6	)	$	(1.1	)	$	(0.1	)	$	-		$	(24.8	)

For the three months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power		Total
Change in unrealized gain / (loss)	$	(3.8	)	$	1.3		$	(0.1	)	$	0.5	$	(2.1	)
Realized gain / (loss)		0.6			(0.4	)		(0.4	)		-		(0.2	)
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(1.6	)	$	-		$	-		$	-	$	(1.6	)
Regulatory (asset) / liability		(1.0	)		0.7			-			-		(0.3	)
Recorded in Income Statement: gain / (loss)
Purchased power	$	-		$	-		$	(0.5	)	$	0.5	$	-
Fuel		(0.6	)		0.2			-			-		(0.4	)
O&M		-			-			-			-		-
Total	$	(3.2	)	$	0.9		$	(0.5	)	$	0.5	$	(2.3	)

For the nine months ended September 30, 2011
	NYMEX			Heating
$ in millions		Coal			Oil		FTRs			Power			Total
Change in unrealized gain / (loss)	$	(41.6	)	$	-	$	(0.1	)	$	-		$	(41.7	)
Realized gain / (loss)		8.1			1.5		(0.6	)		(0.8	)		8.2
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	(21.2	)	$	-	$	-		$	-		$	(21.2	)
Regulatory (asset) / liability		(5.9	)		0.1		-			-			(5.8	)
Recorded in Income Statement: gain / (loss)
Retail revenue	$	-		$	-	$	-		$	(0.2	)	$	(0.2	)
Purchased power		-			-		(0.7	)		(0.6	)		(1.3	)
Fuel		(6.4	)		1.3		-			-			(5.1	)
O&M		-			0.1		-			-			0.1
Total	$	(33.5	)	$	1.5	$	(0.7	)	$	(0.8	)	$	(33.5	)

For the nine months ended September 30, 2010
	NYMEX			Heating
$ in millions		Coal			Oil			FTRs			Power			Total
Change in unrealized gain / (loss)	$	(1.0	)	$	1.5		$	(0.4	)	$	0.7		$	0.8
Realized gain / (loss)		1.6			(1.5	)		(1.4	)		(0.1	)		(1.4	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)
Recorded on Balance Sheet:
Partner's share of gain / (loss)	$	0.2		$	-		$	-		$	-		$	0.2
Regulatory (asset) / liability		(0.6	)		0.6			-			-			-
Recorded in Income Statement: gain / (loss)
Wholesale revenue	$	-		$	-		$	-		$	(0.1	)	$	(0.1	)
Purchased power		-			-			(1.8	)		0.7			(1.1	)
Fuel		1.0			(0.5	)		-			-			0.5
O&M		-			(0.1	)		-			-			(0.1	)
Total	$	0.6		$	-		$	(1.8	)	$	0.6		$	(0.6	)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at September 30, 2011
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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		0.7			(0.6	)	Other prepayments and current assets		0.1
Forward Power Contracts in a Liability position		(0.7	)		0.6		Other current liabilities		(0.1	)
NYMEX-Quality Coal Forwards in an Asset position		1.6			(0.9	)	Other prepayments and current assets		0.7
NYMEX-Quality Coal Forwards in a Liability position		(1.7	)		1.7		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	$	1.7		$	(0.9	)		$	0.8
Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.8		$	(0.5	)	Other deferred assets	$	0.3
Forward Power Contracts in a Liability position		(0.9	)		0.5		Other deferred credits		(0.4	)
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	$	(3.9	)	$	4.3			$	0.4
Total MTM Position	$	(2.2	)	$	3.4			$	1.2

¹ Includes credit valuation adjustment.

² Includes counterparty and collateral netting.

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at December 31, 2010
										Fair Value on
$ in millions	Fair Value1				Netting2			Balance Sheet Location		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

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

Fair Values of Derivative Instruments Not Designated as Hedging Instruments
at September 30, 2011
								Fair Value on
$ in millions	Fair Value1			Netting2			Balance Sheet Location	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		0.7			(0.6	)	Other prepayments and current assets		0.1
Forward Power Contracts in a Liability position		(0.7	)		0.6		Other current liabilities		(0.1	)
NYMEX-Quality Coal Forwards in an Asset position		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		1.7			(1.7	)	Other prepayments and current assets		-
Total short-term derivative MTM positions	$	1.6		$	(0.8	)		$	0.8
Long-term Derivative Positions
Forward Power Contracts in an Asset position	$	0.8		$	(0.5	)	Other deferred assets	$	0.3
Forward Power Contracts in a Liability position		(0.9	)		0.5		Other deferred credits		(0.4	)
NYMEX-Quality Coal Forwards in an Asset position		0.7			(0.3	)	Other deferred assets		0.4
NYMEX-Quality Coal Forwards in a Liability position		(4.5	)		4.5		Other deferred credits		-
Total long-term derivative MTM positions	$	(3.9	)	$	4.2			$	0.3
Total MTM Position	$	(2.3	)	$	3.4			$	1.1

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Derivative Instruments and Hedging Activities (Outstanding Derivative Instruments) (Details) (USD $)	9 Months Ended
	Sep. 30, 2011 MWH		Dec. 31, 2010 MWH
FTRs [Member] | MTM position [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights	11,300	[1]	9,000	[2]
Sales of Units Derivative Instruments Financial Transmission Rights	1,000	[1]		[2]
Derivative, Nonmonetary Notional Amount	12,300	[1]	9,000	[2]
Heating Oil [Member] | MTM position [Member]
Purchase of Volume Units Derivative Instruments Heating Oil Futures	3,654,000	[1]	6,216,000	[2]
Sales of Volume Units Derivative Instruments Heating Oil Futures				[2]
Derivative, Nonmonetary Notional Amount	3,654,000	[1]	6,216,000	[2]
DPL [Member] | Forward Power Contracts [Member] | MTM position [Member]
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(1,350,100)	[3]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	1,365,200	[3]
Derivative, Nonmonetary Notional Amount	15,100	[3]
Forward Power Contracts [Member] | MTM position [Member]
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(570,700)	[1]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged	587,000	[1]	195,600	[2]
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged			(108,500)	[2]
Derivative, Nonmonetary Notional Amount	16,300	[1]	87,100	[2]
Forward Power Contracts [Member] | Cash Flow Hedge [Member]
Purchase of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	974,900	[1]
Sales of Units Derivative Instruments Forward Power Contracts Designated as Cash Flow Hedge	(746,500)	[1]
Purchase of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged			580,800	[2]
Sales of Units Derivative Instruments Forward Power Contracts Not Designated as Hedged			(572,900)	[2]
Derivative, Nonmonetary Notional Amount	228,400	[1]	7,900	[2]
NYMEX Coal [Member] | MTM position [Member]
Purchase of Volume Units Derivative Instruments Coal Contracts	2,658,300	[1],[2]	4,006,800	[2],[4]
Sales of Volume Units Derivative Instruments Coal Contracts				[2],[4]
Derivative, Nonmonetary Notional Amount	2,658,300	[1],[2]	4,006,800	[2],[4]
Interest Rate Swap [Member] | Cash Flow Hedge [Member]
Purchase of Derivative Instruments Interest Rate Swaps	160,000,000	[3]	360,000,000
Sales of Derivative Instruments Interest Rate Swaps
Notional Amount of Derivatives	160,000,000	[3]	360,000,000

[1] Reflected in both DPL's and DP&L's Condensed Consolidated Financial Statements.

[2] *Includes our partners' share for the jointly-owned plants that DP&L operates.

[3] Reflected in only DPL's Condensed Consolidated Financial Statements.

[4] Includes our partners' share for the jointly-owned plants that DP&L operates.

XML

Derivative Instruments and Hedging Activities (Fair Values of Derivative Instruments Designated as Hedging Instruments) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivative Liability, Fair Value	$ (13.1)
DP&L [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value	0.3	[1]
Derivative Fair Value Counterparty And Collateral Netting	0.3	[2]	1.0	[2]
Derivative Fair Value Counterparty And Collateral Netting, Liability	0.2	[2]
Derivative Liability, Fair Value	(1.1)	[1]	(2.8)	[1]
DP&L [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
DP&L [Member] | Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value, Not Offset Amount	(0.9)		(1.8)
DP&L [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value	1.4	[1]	0.2	[1]
Derivative Fair Value Counterparty And Collateral Netting	(1.0)	[2]	(0.2)	[2]
Derivative Fair Value Counterparty And Collateral Netting, Liability	0.1	[2]	0.1	[2]
Derivative Liability, Fair Value	(0.1)	[1]	(0.2)	[1]
DP&L [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value, Not Offset Amount			(0.1)
DP&L [Member] | Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0.4
Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value	0.3	[1]
Derivative Fair Value Counterparty And Collateral Netting	(0.3)	[2]	1.0	[2]
Derivative Fair Value Counterparty And Collateral Netting, Liability	0.2	[2]
Derivative Liability, Fair Value	(1.1)	[1]	(2.8)	[1]
Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
Forward Contract Power [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value, Not Offset Amount	(0.9)		(1.8)
Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value	1.4	[1]	0.2	[1]
Derivative Fair Value Counterparty And Collateral Netting	(1.0)	[2]	(0.2)	[2]
Derivative Fair Value Counterparty And Collateral Netting, Liability	0.1	[2]	0.1	[2]
Derivative Liability, Fair Value	(0.2)	[1]	(0.2)	[1]
Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value, Not Offset Amount	(0.1)		(0.1)
Forward Contract Power [Member] | Long-term Derivative Positions [Member] | Other Deferred Asset [Member]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0.4
Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting		[2]		[2]
Derivative Liability, Fair Value	(28.5)	[1]	(6.6)	[1]
Interest Rate Swap [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value, Not Offset Amount	(28.5)		(6.6)
Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value			20.7	[1]
Derivative Fair Value Counterparty And Collateral Netting				[2]
Interest Rate Swap [Member] | Long-term Derivative Positions [Member] | Other Deferred Credit [Member]
Derivative Liability, Fair Value, Not Offset Amount			(20.7)
DP&L [Member] | Cash Flow Hedge [Member] | Short-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting	(0.1)	[2]
Derivative, Fair Value, Net	(0.8)	[1]	(2.8)	[1]
Derivative, Collateral, net			1.0	[2]
Derivative, Fair Value, Offset, Net	(0.9)		(1.8)
DP&L [Member] | Cash Flow Hedge [Member] | Long-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting	(0.9)	[2]
Derivative, Fair Value, Net	1.3	[1]
Derivative, Collateral, net			(0.1)	[2]
Derivative, Fair Value, Offset, Net	0.4		(0.1)
DP&L [Member] | Cash Flow Hedge [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting	(1.0)	[2]
Derivative, Fair Value, Net	0.5	[1]	(2.8)	[1]
Derivative, Collateral, net			0.9	[2]
Derivative, Fair Value, Offset, Net	(0.5)		(1.9)
Cash Flow Hedge [Member] | Short-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting			1.0	[2]
Derivative Liability, Fair Value, Not Offset Amount			(8.4)
Derivative, Fair Value, Net	(0.8)	[1]	(9.4)	[1]
Derivative, Collateral, net	(0.1)	[2]
Derivative, Fair Value, Offset, Net	(0.9)
Cash Flow Hedge [Member] | Long-term Derivative Positions [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting			(0.1)	[2]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			20.6
Derivative, Fair Value, Net	(27.3)	[1]	20.7	[1]
Derivative, Collateral, net	(0.9)	[2]
Derivative, Fair Value, Offset, Net	(28.2)
Cash Flow Hedge [Member] | Designated as Hedging Instrument [Member]
Derivative Fair Value Counterparty And Collateral Netting			0.9	[2]
Derivative, Fair Value, Net	(28.1)	[1]	11.3	[1]
Derivative, Collateral, net	(1.0)	[2]
Derivative, Fair Value, Offset, Net	(29.1)		12.2
DP&L [Member]
Derivative Liability, Fair Value	(8.5)
Derivative, Fair Value, Offset, Net	$ 2.1

[1] 1 Includes credit valuation adjustment.

[2] 2 Includes counterparty and collateral netting.

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Pension and Postretirement Benefits (Net Periodic Benefit Cost-Income) (Details) (USD $)	9 Months Ended	12 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Pension [Member]	Sep. 30, 2010 Pension [Member]	Sep. 30, 2011 Pension [Member]	Sep. 30, 2010 Pension [Member]	Sep. 30, 2011 Postretirement [ Member]	Sep. 30, 2010 Postretirement [ Member]	Sep. 30, 2011 Postretirement [ Member]	Sep. 30, 2010 Postretirement [ Member]
Service cost			$ 800,000	$ 1,000,000	$ 3,700,000	$ 3,200,000		$ 100,000	$ 100,000	$ 100,000
Interest cost			4,100,000	4,500,000	12,700,000	13,500,000	200,000	300,000	700,000	1,000,000
Expected return on assets			(6,200,000)	(5,600,000)	(18,400,000)	(16,800,000)	(100,000)		(200,000)	(200,000)
Actuarial (gain) / loss			1,700,000	2,000,000	6,200,000	5,600,000	(500,000)	(200,000)	(900,000)	(600,000)
Prior service cost			500,000	900,000	1,600,000	2,800,000	100,000		100,000	100,000
Net periodic benefit cost / (income) before adjustments			900,000	2,800,000	5,800,000	8,300,000	(300,000)	200,000	(200,000)	400,000
Difference between market related value of assets in years	5
Difference between actual and estimated asset returns in MRVA	3
Market related value of assets		$ 317,000,000

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Share-Based Compensation (Summarized Share-Based Compensation Activity) (Details)			3 Months Ended		9 Months Ended		3 Months Ended			9 Months Ended							3 Months Ended		9 Months Ended		3 Months Ended					3 Months Ended
	Sep. 30, 2010	Jun. 30, 2010	Sep. 30, 2011 Parent Company [Member] Restricted Shares [Member]	Sep. 30, 2010 Parent Company [Member] Restricted Shares [Member]	Sep. 30, 2011 Parent Company [Member] Restricted Shares [Member]	Sep. 30, 2010 Parent Company [Member] Restricted Shares [Member]	Sep. 30, 2010 Restricted Shares [Member]	Sep. 30, 2011 Restricted Shares [Member]	Jun. 30, 2011 Restricted Shares [Member]	Sep. 30, 2010 Parent Company [Member]	Sep. 30, 2010 Parent Company [Member] Restricted Stock Units (RSUs) [Member]	Sep. 30, 2011 Parent Company [Member] Performance Shares [Member]	Sep. 30, 2010 Parent Company [Member] Performance Shares [Member]	Sep. 30, 2011 Parent Company [Member] Stock Options [Member]	Sep. 30, 2011 Parent Company [Member] Management Performance Shares [Member]	Sep. 30, 2010 Parent Company [Member] Management Performance Shares [Member]	Sep. 30, 2011 Parent Company [Member] Director RSU's [Member]	Sep. 30, 2010 Parent Company [Member] Director RSU's [Member]	Sep. 30, 2011 Parent Company [Member] Director RSU's [Member]	Sep. 30, 2010 Parent Company [Member] Director RSU's [Member]	Sep. 30, 2010 Restricted Stock Units (RSUs) [Member]	Sep. 30, 2011 Performance Shares [Member]	Jun. 30, 2011 Performance Shares [Member]	Sep. 30, 2010 Performance Shares [Member]	Jun. 30, 2010 Performance Shares [Member]	Sep. 30, 2011 Stock Options [Member]	Sep. 30, 2011 Management Performance Shares [Member]	Sep. 30, 2010 Management Performance Shares [Member]
Outstanding at beginning of year	351,500	351,500			219,391	218,197	249,101	258,652	284,237	417,500				351,500	104,124	84,241					3,311	296,591	296,591	307,985	307,985	500	111,298	110,706
Granted					67,346	42,796	2,617								49,510	37,480
Exercised			(25,585)	(1,800)	(28,085)	(10,803)				(66,000)				(75,500)	(7,911)						(3,311)					(500)
Expired														(276,000)	(31,081)
Forfeited						(7,907)	(7,635)								(5,684)	(12,509)											(2,340)	(1,494)
Outstanding at period end	351,500	351,500	258,652	242,283	258,652	242,283	242,283	258,652	284,237	351,500					108,958	109,212						296,591	296,591	307,985	307,985		108,958	109,212
Exercisable at period end	351,500									351,500
Outstanding at beginning of year											3,311	278,334	237,704					15,944	16,320	20,712
Granted												85,093	161,534				14,392		14,392	15,752
Dividends																	634	655	1,996	1,809
Exercised											3,311		(91,253)
Exercised and issued																			2,066	2,618
Exercised and deferred																	(634)	(471)	16,250	19,527
Expired												(66,836)
Outstanding at period end												296,591	307,985				14,392	16,128	14,392	16,128

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Debt Obligations

9 Months Ended

Sep. 30, 2011

Debt Obligations

5. Debt Obligations

Long-term Debt		At			At
		September 30,			December 31,
$ in millions		2011			2010
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%		35.3			35.3
Pollution control series maturing in January 2034 - 4.80%		179.1			179.1
Pollution control series maturing in September 2036 - 4.80%		100.0			100.0
Pollution control series maturing in November 2040 -
variable rates: 0.06% - 0.29% and 0.16% - 0.36% (a)		100.0			100.0
U.S. Government note maturing in February 2061 - 4.20%		18.5			-
		902.9			884.4
Obligation for capital lease		0.5			0.1
Unamortized debt discount		(0.4	)		(0.5	)
Total long-term debt - DP&L	$	903.0		$	884.0
DPL
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
Total long-term debt - DPL	$	1,223.6		$	1,026.6
Current portion - Long-term Debt		At			At
		September 30,			December 31,
$ in millions		2011			2010
DP&L
U.S. Government note maturing in February 2061 - 4.20%	$	0.1		$	-
Obligation for capital lease		0.3			0.1
Total current portion - long-term debt - DP&L	$	0.4		$	0.1
DPL
Senior notes maturing in September 2011 - 6.875%		-			297.4
Total current portion - long-term debt - DPL	$	0.4		$	297.5

(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.

At 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	$	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 Dolphin Subsidiary II, Inc., a subsidiary of AES, 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 may reduce DPL's ratings to below investment grade upon assumption by DPL of the additional debt 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 was terminated by DP&L 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 nine months ended 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 September 30, 2011. Fees associated with this credit facility were not material during the three and nine months ended September 30, 2011. The fees and interest rate associated with this facility 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 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.

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

On February 28, 2011, DPLER purchased MC Squared. As part of the purchase price, DPL acquired restricted cash for repayment of MC Squared debt. On the day of the purchase, DPL issued a guarantee to a third party for the MC Squared debt. By issuing the guarantee, all restrictions on the cash were released and DPL used the cash to redeem most of the MC Squared debt owed to a third party totaling $13.5 million.

On March 1, 2011, DP&L purchased $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.

DP&L [Member]

Debt Obligations

5. Debt Obligations

Long-term Debt		At			At
		September 30,			December 31,
$ in millions		2011			2010
DP&L
First mortgage bonds maturing in October 2013 - 5.125%	$	470.0		$	470.0
Pollution control series maturing in January 2028 - 4.70%		35.3			35.3
Pollution control series maturing in January 2034 - 4.80%		179.1			179.1
Pollution control series maturing in September 2036 - 4.80%		100.0			100.0
Pollution control series maturing in November 2040 -
variable rates: 0.06% - 0.29% and 0.16% - 0.36% (a)		100.0			100.0
U.S. Government note maturing in February 2061 - 4.20%		18.5			-
		902.9			884.4
Obligation for capital lease		0.5			0.1
Unamortized debt discount		(0.4	)		(0.5	)
Total long-term debt - DP&L	$	903.0		$	884.0
DPL
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
Total long-term debt - DPL	$	1,223.6		$	1,026.6
Current portion - Long-term Debt		At			At
		September 30,			December 31,
$ in millions		2011			2010
DP&L
U.S. Government note maturing in February 2061 - 4.20%	$	0.1		$	-
Obligation for capital lease		0.3			0.1
Total current portion - long-term debt - DP&L	$	0.4		$	0.1
DPL
Senior notes maturing in September 2011 - 6.875%		-			297.4
Total current portion - long-term debt - DPL	$	0.4		$	297.5

(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.

At 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	$	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 Dolphin Subsidiary II, Inc., a subsidiary of AES, 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 may reduce DPL's ratings to below investment grade upon assumption by DPL of the additional debt 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 was terminated by DP&L 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 nine months ended 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 September 30, 2011. Fees associated with this credit facility were not material during the three and nine months ended September 30, 2011. The fees and interest rate associated with this facility 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 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.

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

On February 28, 2011, DPLER purchased MC Squared. As part of the purchase price, DPL acquired restricted cash for repayment of MC Squared debt. On the day of the purchase, DPL issued a guarantee to a third party for the MC Squared debt. By issuing the guarantee, all restrictions on the cash were released and DPL used the cash to redeem most of the MC Squared debt owed to a third party totaling $13.5 million.

On March 1, 2011, DP&L purchased $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.

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Ownership of Coal-fired Facilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Undivided ownership interests	7
Construction Work in Process	$ 42.0
DP&L [Member] | DP&L Investment [Member]
Construction Work in Process	$ 42.0

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Effective Income Tax Rates

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
DPL	29.9	%	31.9	%	32.9	%	32.8	%
DP&L	29.6	%	32.1	%	32.0	%	32.8	%

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EPS (Schedule of Earnings Per Share, Basic and Diluted) (Details) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
EPS [Abstract]
Income - Basic	$ 67.1	$ 86.4	$ 142.3	$ 218.8
Shares - Basic	115.0	115.8	114.4	115.7
Earnings per share - Basic	$ 0.58	$ 0.75	$ 1.24	$ 1.89
Warrants	0.3	0.3	0.4	0.3
Stock options, performance and restricted shares	0.2	0.2	0.2	0.2
Income - Diluted	$ 67.1	$ 86.4	$ 142.3	$ 218.8
Shares - Diluted	115.5	116.3	115.0	116.2
Earnings per share - Diluted	$ 0.58	$ 0.74	$ 1.24	$ 1.88

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Derivative Instruments and Hedging Activities (Fair Values of Derivative Instruments Not Designated as Hedging Instruments) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivative Liability, Fair Value	$ (13.1)
DP&L [Member] | MTM position [Member]
Derivative Assets (Liabilities), at Fair Value, Net	(2.3)	[1]
Derivative Asset, Fair Value, Not Offset Amount	1.1
Derivative, Fair Value Counterparty and Collateral, Netting	(3.4)
DP&L [Member] | MTM position [Member] | Short-term Derivative Positions [Member]
Derivative Assets (Liabilities), at Fair Value, Net	1.6	[1]
Derivative Asset, Fair Value, Not Offset Amount	0.8
Derivative, Fair Value Counterparty and Collateral, Netting	(0.8)
DP&L [Member] | MTM position [Member] | Long-term Derivative Positions [Member]
Derivative Liability, Fair Value	3.9	[1]
Derivative Asset, Fair Value, Not Offset Amount	0.3
Derivative, Fair Value Counterparty and Collateral, Netting	4.2
MTM position [Member]
Derivative Assets (Liabilities), at Fair Value, Net	3.6	[1]
Derivative Asset, Fair Value, Not Offset Amount	8.6
Derivative, Fair Value Counterparty and Collateral, Netting	(5.0)
MTM position [Member] | Short-term Derivative Positions [Member]
Derivative Assets (Liabilities), at Fair Value, Net	4.2	[1]
Derivative Asset, Fair Value, Not Offset Amount	4.3
Derivative, Fair Value Counterparty and Collateral, Netting	(0.1)
MTM position [Member] | Long-term Derivative Positions [Member]
Derivative Assets (Liabilities), at Fair Value, Net	0.6	[1]
Derivative Asset, Fair Value, Not Offset Amount	4.3
Derivative, Fair Value Counterparty and Collateral, Netting	(4.9)
MTM position [Member] | Long-term Derivative Positions [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative, Fair Value, Not Offset, Net			24.6	[1]
Derivative, Fair Value Counterparty and Collateral, Netting			15.6
Derivative, Fair Value, Offset, Net			9.0
MTM position [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative, Fair Value, Not Offset, Net			39.3	[1]
Derivative, Fair Value Counterparty and Collateral, Netting			23.5
Derivative, Fair Value, Offset, Net			15.8
Futures [Member] | Short-term Derivative Positions [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative Asset, Fair Value			0.5	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting			(0.5)
Futures [Member] | Short-term Derivative Positions [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value, Not Offset Amount
DP&L [Member] | Heating Oil [Member] | Short-term Derivative Positions [Member]
Derivative Asset, Fair Value	1.7	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	1.7
DP&L [Member] | Heating Oil [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount
Heating Oil [Member] | Short-term Derivative Positions [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	1.7	[1]
Derivative Asset, Fair Value, Not Offset Amount
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	(1.7)
Heating Oil [Member] | Long-term Derivative Positions [Member] | Not Designated as Hedging Instrument [Member]
Derivative Asset, Fair Value			1.1	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting			(1.1)
Heating Oil [Member] | Long-term Derivative Positions [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount
DP&L [Member] | Short-term Derivative Positions [Member] | FTRs [Member]
Derivative Asset, Fair Value	0.1	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting
DP&L [Member] | Short-term Derivative Positions [Member] | FTRs [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount	0.1
Short-term Derivative Positions [Member] | FTRs [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative Asset, Fair Value			0.3	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting
Short-term Derivative Positions [Member] | FTRs [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	0.1	[1]
Derivative Asset, Fair Value, Not Offset Amount	0.1		0.3
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting
DP&L [Member] | Short-term Derivative Positions [Member] | Forward Power Contracts [Member]
Derivative Asset, Fair Value	0.7	[1]
Derivative Liability, Fair Value	(0.7)	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	(0.6)
Derivative, Fair Value Counterparty and Collateral, Netting	0.6
DP&L [Member] | Short-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount	0.1
DP&L [Member] | Short-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value, Not Offset Amount	(0.1)
DP&L [Member] | Long-term Derivative Positions [Member] | Forward Power Contracts [Member]
Derivative Asset, Fair Value	0.8	[1]
Derivative Liability, Fair Value	(0.9)	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	0.5
Derivative, Fair Value Counterparty and Collateral, Netting	0.5
DP&L [Member] | Long-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Deferred Credits [Member]
Derivative Liability, Fair Value, Not Offset Amount	(0.4)
DP&L [Member] | Long-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount	0.3
Short-term Derivative Positions [Member] | Forward Power Contracts [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative Liability, Fair Value			(0.1)	[1]
Derivative, Fair Value Counterparty and Collateral, Netting
Short-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	6.4	[1]
Derivative Asset, Fair Value, Not Offset Amount	6.0
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	(0.4)
Short-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	(3.8)	[1]
Derivative Liability, Fair Value, Not Offset Amount	(2.4)		(0.1)
Derivative, Fair Value Counterparty and Collateral, Netting	1.4
Long-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Deferred Credits [Member]
Derivative Liability, Fair Value	(1.5)	[1]
Derivative Liability, Fair Value, Not Offset Amount	(0.6)
Derivative, Fair Value Counterparty and Collateral, Netting	0.9
Long-term Derivative Positions [Member] | Forward Power Contracts [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value	4.7	[1]
Derivative Asset, Fair Value, Not Offset Amount	4.4
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	(0.3)
Short-term Derivative Positions [Member] | NYMEX-Quality Coal Forwards [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative Asset, Fair Value			14.0	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting			(7.4)
Short-term Derivative Positions [Member] | NYMEX-Quality Coal Forwards [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount			6.6
Long-term Derivative Positions [Member] | NYMEX-Quality Coal Forwards [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative Asset, Fair Value			23.5	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting			(14.5)
Long-term Derivative Positions [Member] | NYMEX-Quality Coal Forwards [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount			9.0
DP&L [Member] | Short-term Derivative Positions [Member] | NYMEX Coal [Member]
Derivative Asset, Fair Value	1.6	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	0.9
DP&L [Member] | Short-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount	0.7
DP&L [Member] | Long-term Derivative Positions [Member] | NYMEX Coal [Member]
Derivative Asset, Fair Value	0.7	[1]
Derivative Liability, Fair Value	(1.8)	[1]
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	0.3
Derivative, Fair Value Counterparty and Collateral, Netting	1.8
DP&L [Member] | Long-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Deferred Credits [Member]
Derivative Liability, Fair Value, Not Offset Amount
DP&L [Member] | Long-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value, Not Offset Amount	0.4
Short-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Prepayments and Current Assets [Member]
Derivative Asset, Fair Value	1.6	[1]
Derivative Asset, Fair Value, Not Offset Amount	0.6
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	(1.0)
Long-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Current Liabilities [Member]
Derivative Liability, Fair Value	(1.8)	[1]
Derivative, Fair Value Counterparty and Collateral, Netting	1.8
Long-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Deferred Credits [Member]
Derivative Liability, Fair Value, Not Offset Amount
Long-term Derivative Positions [Member] | NYMEX Coal [Member] | Other Deferred Assets [Member]
Derivative Asset, Fair Value	0.7	[1]
Derivative Asset, Fair Value, Not Offset Amount	0.5
Derivative, Fair Value of Derivative Asset Counterparty and Collateral, Netting	0.2
Short-term Derivative Positions [Member] | Derivative Instruments Not Designated as Hedging Instruments [Member]
Derivative, Fair Value, Not Offset, Net			14.7	[1]
Derivative, Fair Value Counterparty and Collateral, Netting			7.9
Derivative, Fair Value, Offset, Net			6.8
Other Deferred Credits [Member]
Derivative Liability, Fair Value	(4.5)	[1]
Derivative Liability, Fair Value, Not Offset Amount
Derivative, Fair Value Counterparty and Collateral, Netting	4.5
DP&L [Member]
Derivative Liability, Fair Value	(8.5)
Derivative, Fair Value, Offset, Net	$ 2.1

[1] 1 Includes credit valuation adjustment.

XML

EPS (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2011

EPS [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

$ and shares in millions except			Three Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		Income	Shares		Share		Income	Shares		Share
Basic EPS	$	67.1	115.0	$	0.58	$	86.4	115.8	$	0.75
Effect of Dilutive
Securities:
Warrants			0.3					0.3
Stock options, performance and
restricted shares			0.2					0.2
Diluted EPS	$	67.1	115.5	$	0.58	$	86.4	116.3	$	0.74

$ and shares in millions except			Nine Months Ended September 30,
per share amounts			2011					2010
					Per					Per
		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

XML

Regulatory Matters (Schedule of Regulatory Assets and Liabilities) (Details) (USD $) In Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Total Regulatory Assets	$ 178.2		$ 189.0
Total Regulatory Liabilities	133.1		124.0
Deferred Recoverable Income Taxes [Member]
Type of Recovery	B/C	[1]	B/C
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	26.6		29.9
Pension Benefits [Member]
Type of Recovery	C	[1]	C
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	76.6		81.1
Unamortized Loss on Reacquired Debt [Member]
Type of Recovery	C	[1]	C
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	13.3		14.3
Regional Transmission Organization Costs [Member]
Type of Recovery	D	[1]	D
Amortization Through	2014		2014
Total Regulatory Assets	4.4		5.5
TCRR, Transmission, Ancillary and Other PJM-related Costs [Member]
Type of Recovery	F	[1]	F
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	7.7		11.8
Deferred Storm Costs - 2008 [Member]
Type of Recovery	D	[1]	D
Total Regulatory Assets	17.7		16.9
Power Plant Emission Fees [Member]
Type of Recovery	C	[1]	C
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	7.1		6.6
CCEM Smart Grid and Advanced Metering Infrastructure Costs [Member]
Type of Recovery	D	[1]	D
Total Regulatory Assets	6.6		6.6
CCEM Energy Efficiency Program Costs [Member]
Type of Recovery	F	[1]	F
Amortization Through	Ongoing		Ongoing
Total Regulatory Assets	8.0		4.8
Fuel and Purchased Power Recovery Costs [Member]
Type of Recovery	C	[1]	C
Amortization Through	Ongoing		Ongoing
Total Regulatory Liabilities	16.0		10.0
Other Costs - Assets [Member]
Total Regulatory Assets	10.2		11.5
Estimated Costs of Removal - Regulated Property [Member]
Total Regulatory Liabilities	111.7		107.9
Postretirement Benefit [Member]
Total Regulatory Liabilities	$ 5.4		$ 6.1

[1] (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.

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value and Cost of Non-Derivative Instruments

		At September 30,				At December 31,
		2011				2010
$ in millions		Cost	Fair Value			Cost	Fair Value
DPL
Assets
Money Market Funds	$	0.2	$	0.2	$	1.6	$	1.6
Equity Securities		3.9		4.0		3.8		4.4
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	9.5	$	10.0	$	10.9	$	11.8
Short-term Investments - VRDNs	$	-	$	-	$	54.2	$	54.2
Short-term Investments - Bonds		-		-		15.1		15.1
Total Short-term Investments	$	-	$	-	$	69.3	$	69.3
Total Assets	$	9.5	$	10.0	$	80.2	$	81.1
Liabilities
Debt	$	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
Equity Securities (a)		17.3		33.5		17.5		30.2
Debt Securities		5.1		5.6		5.2		5.5
Multi-Strategy Fund		0.3		0.2		0.3		0.3
Total Master Trust Assets	$	22.9	$	39.5	$	24.6	$	37.6
Liabilities
Debt	$	903.4	$	884.2	$	884.1	$	850.6

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

Fair Value and Redemption Frequency

		Fair Value Estimated using Net Asset Value per Unit
		Fair Value at		Fair Value at		Unfunded	Redemption
$ in millions		September 30, 2011	December 31, 2010			Commitments	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 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 of Assets and Liabilities Measured on Recurring Basis

DPL
					Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at				Based on Quoted	Other				Collateral and			Balance Sheet at
	September 30,				Prices in Active	Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities			4.0		-		4.0		-		-			4.0
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		10.0	$	-	$	10.0	$	-	$	-		$	10.0
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.2		-		2.2		-		(1.1	)		1.1
Forward Power Contracts			13.0		-		13.0		-		(2.1	)		10.9
Total Derivative Assets	$		17.0	$	1.7	$	15.3	$	-	$	(4.9	)	$	12.1
Short-term Investments - Bonds			-		-		-		-		-			-
Total Short-term investments	$		-	$	-	$	-	$	-	$	-		$	-
Total Assets	$		27.0	$	1.7	$	25.3	$	-	$	(4.9	)	$	22.1
Liabilities
Derivative Liabilities
Interest Rate Hedge	$		28.5	$	-	$	28.5	$	-	$	-		$	28.6
Forward NYMEX Coal Contracts			6.3		-		6.3		-		(6.3)			-
Forward Power Contracts			6.6		-		6.6		-		(2.6)			4.0
Total Derivative Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5
Total Liabilities	$		41.4	$	-	$	41.4	$	-	$	(8.9)		$	32.5

*Includes credit valuation adjustments for counterparty risk.

DPL
				Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1		Level 2		Level 3
														Fair Value on
		Fair Value at		Based on Quoted			Other			Collateral and				Balance Sheet at
		December 31, Prices in Active				Observable Unobservable Counterparty								December 31,
$ in millions		2010	*		Markets		Inputs		Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$	1.6		$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities		4.4			-		4.4		-		-			4.4
Debt Securities		5.5			-		5.5		-		-			5.5
Multi-Strategy Fund		0.3			-		0.3		-		-			0.3
Total Master Trust Assets	$	11.8		$	-	$	11.8	$	-	$	-		$	11.8
Derivative Assets
FTRs	$	0.3		$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures		1.6			1.6		-		-		(1.6	)		-
Interest Rate Hedge		20.7			-		20.7		-		-			20.7
Forward NYMEX Coal Contracts		37.5			-		37.5		-		(21.9	)		15.6
Forward Power Contracts		0.2			-		0.2		-		(0.2	)		-
Total Derivative Assets	$	60.3		$	1.6	$	58.7	$	-	$	(23.7	)	$	36.6
Short-term Investments - VRDNs	$	54.2		$	-	$	54.2	$	-	$	-		$	54.2
Short-term Investments - Bonds		15.1			-		15.1		-		-			15.1
Total Short-term investments	$	69.3		$	-	$	69.3	$	-	$	-		$	69.3
Total Assets	$	141.4		$	1.6	$	139.8	$	-	$	(23.7	)	$	117.7
Liabilities
Derivative Liabilities
Interest Rate Hedge	$	6.6		$	-	$	6.6	$	-	$	-		$	6.6
Forward Power Contracts		3.1			-		3.1		-		(1.1	)		2.0
Total Derivative Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6
Total Liabilities	$	9.7		$	-	$	9.7	$	-	$	(1.1	)	$	8.6

*Includes credit valuation adjustments for counterparty risk.

DP&L [Member]

Fair Value of Assets and Liabilities Measured on Recurring Basis

DP&L
				Assets and Liabilities Measured at Fair Value on a Recurring Basis
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	September 30, Prices in Active					Observable Unobservable Counterparty September 30,
$ in millions	2011	*			Markets	Inputs			Inputs		Netting			2011
Assets
Master Trust Assets
Money Market Funds	$		0.2	$	-	$	0.2	$	-	$	-		$	0.2
Equity Securities (a)			33.5		29.5		4.0		-		-			33.5
Debt Securities			5.6		-		5.6		-		-			5.6
Multi-Strategy Fund			0.2		-		0.2		-		-			0.2
Total Master Trust Assets	$		39.5	$	29.5	$	10.0	$	-	$	-		$	39.5
Derivative Assets
FTRs	$		0.1	$	-	$	0.1	$	-	$	-		$	0.1
Heating Oil Futures			1.7		1.7		-		-		(1.7	)		-
Forward NYMEX Coal Contracts			2.2		-		2.2		-		(1.1	)		1.1
Forward Power Contracts			3.3		-		3.3		-		(2.4	)		0.9
Total Derivative Assets	$		7.3	$	1.7	$	5.6	$	-	$	(5.2	)	$	2.1
Total Assets	$		46.8	$	31.2	$	15.6	$	-	$	(5.2	)	$	41.6
Liabilities
Derivative Liabilities
Forward NYMEX Coal Contracts	$		6.3	$	-	$	6.3	$	-	$	(6.3)		$	-
Forward Power Contracts			2.8		-		2.8		-		(1.4)			1.4
Total Derivative Liabilities	$		9.1	$	-	$	9.1	$	-	$	(7.7)		$	1.4
Total Liabilities	$		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
					Level 1	Level 2			Level 3
														Fair Value on
	Fair Value at			Based on Quoted		Other				Collateral and			Balance Sheet at
	December 31, Prices in Active					Observable Unobservable Counterparty December 31,
$ in millions	2010	*			Markets	Inputs			Inputs		Netting			2010
Assets
Master Trust Assets
Money Market Funds	$		1.6	$	-	$	1.6	$	-	$	-		$	1.6
Equity Securities (a)			30.2		25.8		4.4		-		-			30.2
Debt Securities			5.5		-		5.5		-		-			5.5
Multi-Strategy Fund			0.3		-		0.3		-		-			0.3
Total Master Trust Assets	$		37.6	$	25.8	$	11.8	$	-	$	-		$	37.6
Derivative Assets
FTRs	$		0.3	$	-	$	0.3	$	-	$	-		$	0.3
Heating Oil Futures			1.6		1.6		-		-		(1.6	)		-
Forward NYMEX Coal Contracts			37.5		-		37.5		-		(21.9	)		15.6
Forward Power Contracts			0.2		-		0.2		-		(0.2	)		-
Total Derivative Assets	$		39.6	$	1.6	$	38.0	$	-	$	(23.7	)	$	15.9
Total Assets	$		77.2	$	27.4	$	49.8	$	-	$	(23.7	)	$	53.5
Liabilities
Derivative Liabilities
Forward Power Contracts	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Derivative Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0
Total Liabilities	$		3.1	$	-	$	3.1	$	-	$	(1.1	)	$	2.0

*Includes credit valuation adjustments for counterparty risk.

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

XML

Insurance Recovery

9 Months Ended

Sep. 30, 2011

Insurance Recovery

13. Insurance Recovery

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

DP&L [Member]

Insurance Recovery

13. Insurance Recovery

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

XML

Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Total Short-term Investments	$ 0		$ 69.3
Interest Rate Swap [Member] | Collateral and Counterparty Netting [Member]
Total Derivative Liabilities
Interest Rate Swap [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Liabilities	(28.5)
Interest Rate Swap [Member] | Level 1 [Member]
Total Derivative Liabilities
Interest Rate Swap [Member] | Level 2 [Member]
Total Derivative Liabilities	(28.5)
Interest Rate Swap [Member] | Level 3 [Member]
Total Derivative Liabilities
Interest Rate Swap [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Liabilities	(28.5)
DP&L [Member] | Equity Securities [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value		[1]
DP&L [Member] | Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	33.5	[1]	30.2	[1],[2]
DP&L [Member] | Equity Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	29.5	[1]	25.8	[1]
DP&L [Member] | Equity Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	4.0	[1]	4.4	[1]
DP&L [Member] | Equity Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value		[1]
DP&L [Member] | Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	33.5	[1]	30.2	[1]
Equity Securities [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	4.0		4.4	[2]
Equity Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
Equity Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	4.0		4.4
Equity Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	4.0		4.4
DP&L [Member] | Debt Securities [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5	[2]
DP&L [Member] | Debt Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Debt Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
DP&L [Member] | Debt Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Debt Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
Debt Securities [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5	[2]
Debt Securities [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
Debt Securities [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
Debt Securities [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
Debt Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
DP&L [Member] | Money Market Funds [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6	[2]
DP&L [Member] | Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Money Market Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
DP&L [Member] | Money Market Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
Money Market Funds [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6	[2]
Money Market Funds [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
Money Market Funds [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
Money Market Funds [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3	[2]
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
Multi Strategy Fund [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Multi Strategy Fund [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3	[2]
Multi Strategy Fund [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value
Multi Strategy Fund [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
Multi Strategy Fund [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
Multi Strategy Fund [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
DP&L [Member] | Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Total Derivative Assets	(5.3)		(23.7)
Total Assets	(5.3)		(23.7)
Total Derivative Liabilities	7.7		(1.1)
Total Liabilities	7.7		(1.1)
DP&L [Member] | Collateral and Counterparty Netting [Member] | FTRs [Member]
Total Derivative Assets
DP&L [Member] | Collateral and Counterparty Netting [Member] | Futures [Member]
Total Derivative Assets	(1.7)		(1.6)
DP&L [Member] | Collateral and Counterparty Netting [Member] | Forward NYMEX Coal Contracts [Member]
Total Derivative Assets	(1.2)		(21.9)
DP&L [Member] | Collateral and Counterparty Netting [Member] | Forward Contract Power [Member]
Total Derivative Assets	(2.4)		(0.2)
Total Derivative Liabilities	1.4		(1.1)
Collateral and Counterparty Netting [Member]
Total Master Trust Assets, Fair Value
Total Derivative Assets	(4.9)		(23.7)
Total Assets	(4.9)		(23.7)
Total Short-term Investments
Total Derivative Liabilities	8.9		(1.1)
Total Liabilities	8.9		(1.1)
Collateral and Counterparty Netting [Member] | Short-term Investments - Bonds [Member]
Total Short-term Investments
Collateral and Counterparty Netting [Member] | Short-term Investments - VRDNs [Member]
Total Derivative Assets
Collateral and Counterparty Netting [Member] | FTRs [Member]
Total Derivative Assets
Collateral and Counterparty Netting [Member] | Futures [Member]
Total Derivative Assets	(1.7)		(1.6)
Collateral and Counterparty Netting [Member] | Forward NYMEX Coal Contracts [Member]
Total Derivative Assets	(1.2)		(21.9)
Total Derivative Liabilities	6.3
Collateral and Counterparty Netting [Member] | Interest Rate Hedge [Member]
Total Derivative Assets
Total Derivative Liabilities
Collateral and Counterparty Netting [Member] | Forward Contract Power [Member]
Total Derivative Assets	(2.0)		(0.2)
Total Derivative Liabilities	2.6		(1.1)
DP&L [Member] | FTRs [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	0.1		0.3	[2]
DP&L [Member] | FTRs [Member] | Level 1 [Member]
Total Derivative Assets
DP&L [Member] | FTRs [Member] | Level 2 [Member]
Total Derivative Assets	0.1		0.3
DP&L [Member] | FTRs [Member] | Level 3 [Member]
Total Derivative Assets
DP&L [Member] | FTRs [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	0.1		0.3
FTRs [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	0.1		0.3	[2]
FTRs [Member] | Level 1 [Member]
Total Derivative Assets
FTRs [Member] | Level 2 [Member]
Total Derivative Assets	0.1		0.3
FTRs [Member] | Level 3 [Member]
Total Derivative Assets
FTRs [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	0.1		0.3
DP&L [Member] | Futures [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	1.7		1.6	[2]
DP&L [Member] | Futures [Member] | Level 1 [Member]
Total Derivative Assets	1.7		1.6
DP&L [Member] | Futures [Member] | Level 2 [Member]
Total Derivative Assets
DP&L [Member] | Futures [Member] | Level 3 [Member]
Total Derivative Assets
DP&L [Member] | Futures [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets
Futures [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	1.7		1.6	[2]
Futures [Member] | Level 1 [Member]
Total Derivative Assets	1.7		1.6
Futures [Member] | Level 2 [Member]
Total Derivative Assets
Futures [Member] | Level 3 [Member]
Total Derivative Assets
DP&L [Member] | Forward NYMEX Coal Contracts [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	2.3		37.5	[2]
DP&L [Member] | Forward NYMEX Coal Contracts [Member] | Level 1 [Member]
Total Derivative Assets
DP&L [Member] | Forward NYMEX Coal Contracts [Member] | Level 2 [Member]
Total Derivative Assets	2.3		37.5
DP&L [Member] | Forward NYMEX Coal Contracts [Member] | Level 3 [Member]
Total Derivative Assets
DP&L [Member] | Forward NYMEX Coal Contracts [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	1.1		15.6
Forward NYMEX Coal Contracts [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	2.3		37.5	[2]
Total Derivative Liabilities	(6.3)
Forward NYMEX Coal Contracts [Member] | Level 1 [Member]
Total Derivative Assets
Total Derivative Liabilities
Forward NYMEX Coal Contracts [Member] | Level 2 [Member]
Total Derivative Assets	2.3		37.5
Total Derivative Liabilities	(6.3)
Forward NYMEX Coal Contracts [Member] | Level 3 [Member]
Total Derivative Assets
Total Derivative Liabilities
Forward NYMEX Coal Contracts [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	1.1		15.6
Interest Rate Hedge [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets			20.7	[2]
Total Derivative Liabilities			6.6	[2]
Interest Rate Hedge [Member] | Level 1 [Member]
Total Derivative Assets
Total Derivative Liabilities
Interest Rate Hedge [Member] | Level 2 [Member]
Total Derivative Assets			20.7
Total Derivative Liabilities			6.6
Interest Rate Hedge [Member] | Level 3 [Member]
Total Derivative Assets
Total Derivative Liabilities
Interest Rate Hedge [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets			20.7
Total Derivative Liabilities			6.6
DP&L [Member] | Forward Contract Power [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	3.2		0.2	[2]
Total Derivative Liabilities	(2.8)		3.1	[2]
DP&L [Member] | Forward Contract Power [Member] | Level 1 [Member]
Total Derivative Assets
Total Derivative Liabilities
DP&L [Member] | Forward Contract Power [Member] | Level 2 [Member]
Total Derivative Assets	3.2		0.2
Total Derivative Liabilities	(2.8)		3.1
DP&L [Member] | Forward Contract Power [Member] | Level 3 [Member]
Total Derivative Assets
Total Derivative Liabilities
DP&L [Member] | Forward Contract Power [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	0.8
Total Derivative Liabilities	(1.4)		2.0
Forward Contract Power [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets	12.8		0.2	[2]
Total Derivative Liabilities	(6.6)		3.1	[2]
Forward Contract Power [Member] | Level 1 [Member]
Total Derivative Assets
Total Derivative Liabilities
Forward Contract Power [Member] | Level 2 [Member]
Total Derivative Assets	12.8		0.2
Total Derivative Liabilities	(6.6)		3.1
Forward Contract Power [Member] | Level 3 [Member]
Total Derivative Assets
Total Derivative Liabilities
Forward Contract Power [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets	10.8
Total Derivative Liabilities	(4.0)		2.0
Short-term Investments - Bonds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Short-term Investments			15.1	[2]
Short-term Investments - Bonds [Member] | Level 1 [Member]
Total Short-term Investments
Short-term Investments - Bonds [Member] | Level 2 [Member]
Total Short-term Investments			15.1
Short-term Investments - Bonds [Member] | Level 3 [Member]
Total Short-term Investments
Short-term Investments - Bonds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Short-term Investments			15.1
Short-term Investments - VRDNs [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Derivative Assets			54.2	[2]
Short-term Investments - VRDNs [Member] | Level 1 [Member]
Total Derivative Assets
Short-term Investments - VRDNs [Member] | Level 2 [Member]
Total Derivative Assets			54.2
Short-term Investments - VRDNs [Member] | Level 3 [Member]
Total Derivative Assets
Short-term Investments - VRDNs [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Derivative Assets			54.2
DP&L [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	39.5		37.6	[2]
Total Derivative Assets	7.3		39.6	[2]
Total Assets	46.8		77.2	[2]
Total Derivative Liabilities	(9.1)		3.1	[2]
Total Liabilities	(9.1)		3.1	[2]
Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	10.0		11.8	[2]
Total Derivative Assets	16.9		60.3	[2]
Total Assets	26.9		141.4	[2]
Total Short-term Investments			69.3	[2]
Total Derivative Liabilities	(41.4)		9.7	[2]
Total Liabilities	(41.4)		9.7	[2]
DP&L [Member] | Level 1 [Member]
Total Master Trust Assets, Fair Value	29.5		25.8
Total Derivative Assets	1.7		1.6
Total Assets	31.2		27.4
Total Derivative Liabilities
Total Liabilities
Level 1 [Member]
Total Master Trust Assets, Fair Value
Total Derivative Assets	1.7		1.6
Total Assets	1.7		1.6
Total Short-term Investments
Total Derivative Liabilities
Total Liabilities
DP&L [Member] | Level 2 [Member]
Total Master Trust Assets, Fair Value	10.0		11.8
Total Derivative Assets	5.6		38.0
Total Assets	15.6		49.8
Total Derivative Liabilities	(9.1)		3.1
Total Liabilities	(9.1)		3.1
Level 2 [Member]
Total Master Trust Assets, Fair Value	10.0		11.8
Total Derivative Assets	15.2		58.7
Total Assets	25.2		139.8
Total Short-term Investments			69.3
Total Derivative Liabilities	(41.4)		9.7
Total Liabilities	(41.4)		9.7
DP&L [Member] | Level 3 [Member]
Total Master Trust Assets, Fair Value
Total Derivative Assets
Total Assets
Total Derivative Liabilities
Total Liabilities
Level 3 [Member]
Total Master Trust Assets, Fair Value
Total Derivative Assets
Total Assets
Total Short-term Investments
Total Derivative Liabilities
Total Liabilities
DP&L [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	39.5		37.6
Total Derivative Assets	2.0		15.9
Total Assets	41.5		53.5
Total Derivative Liabilities	(1.4)		2.0
Total Liabilities	(1.4)		2.0
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	10.0		11.8
Total Derivative Assets	12.0		36.6
Total Assets	22.0		117.7
Total Short-term Investments			69.3
Total Derivative Liabilities	(32.5)		8.6
Total Liabilities	$ (32.5)		$ 8.6

[1] DPL stock held in the DP&L Master Trust is eliminated in consolidation.

[2] *Includes credit valuation adjustments for counterparty risk.

XML

Derivative Instruments and Hedging Activities (Classification within the Condensed Consolidated Statements of Results of Operations or Balance Sheets of the Gains and Losses) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Change in unrealized gain / (loss)	$ (29.9)	$ (2.1)	$ (41.1)	$ 0.8
Derivative, Gain (Loss) on Derivative, Net	6.0	(0.2)	8.2	(1.4)
Gain (Loss) on Derivative Instruments, Net, Pretax	(23.9)	(2.3)	(32.9)	(0.6)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(23.9)	(2.3)	(32.9)	(0.6)
DP&L [Member] | NYMEX Coal [Member]
Change in unrealized gain / (loss)	(27.9)	(3.8)	(41.6)	(1.0)
Derivative, Gain (Loss) on Derivative, Net	4.3	0.6	8.1
Gain (Loss) on Derivative Instruments, Net, Pretax	(23.6)	(3.2)	(33.5)	1.6
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(23.6)	(3.2)	(33.5)	0.6
DP&L [Member] | NYMEX Coal [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)	(13.8)	(1.6)	(21.2)	0.2
DP&L [Member] | NYMEX Coal [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(4.0)	(1.0)	(5.9)	(0.6)
DP&L [Member] | NYMEX Coal [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | NYMEX Coal [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(5.8)	(0.6)	(6.4)	1.0
DP&L [Member] | NYMEX Coal [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | NYMEX Coal [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
NYMEX Coal [Member]
Change in unrealized gain / (loss)	(27.9)	(3.8)	(41.6)	(1.0)
Derivative, Gain (Loss) on Derivative, Net	4.3	0.6	8.1	1.6
Gain (Loss) on Derivative Instruments, Net, Pretax	(23.6)	(3.2)	(33.5)	0.6
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(23.6)	(3.2)	(33.5)	0.6
NYMEX Coal [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)	(13.8)	(1.6)	(21.2)	0.2
NYMEX Coal [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(4.0)	(1.0)	(5.9)	(0.6)
NYMEX Coal [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
NYMEX Coal [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(5.8)	(0.6)	(6.4)	1.0
NYMEX Coal [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
NYMEX Coal [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | Heating Oil [Member]
Change in unrealized gain / (loss)	(1.6)	1.3		1.5
Derivative, Gain (Loss) on Derivative, Net	0.5	(0.4)	1.5
Gain (Loss) on Derivative Instruments, Net, Pretax	(1.1)	0.9	1.5	(1.5)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.1)	0.9	1.5
DP&L [Member] | Heating Oil [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
DP&L [Member] | Heating Oil [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(0.6)	0.7	0.1	0.6
DP&L [Member] | Heating Oil [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | Heating Oil [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.5)	0.2	1.3	(0.5)
DP&L [Member] | Heating Oil [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net			0.1	(0.1)
DP&L [Member] | Heating Oil [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
Heating Oil [Member]
Change in unrealized gain / (loss)	(1.6)	1.3		1.5
Derivative, Gain (Loss) on Derivative, Net	0.5	(0.4)	1.5	(1.5)
Gain (Loss) on Derivative Instruments, Net, Pretax	(1.1)	0.9	1.5
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.1)	0.9	1.5
Heating Oil [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
Heating Oil [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(0.6)	0.7	0.1	0.6
Heating Oil [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
Heating Oil [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.5)	0.2	1.3	(0.5)
Heating Oil [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net			0.1	(0.1)
Heating Oil [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | FTR's [Member]
Change in unrealized gain / (loss)	(0.1)	(0.1)	(0.1)	(0.4)
Derivative, Gain (Loss) on Derivative, Net		(0.4)	(0.6)
Gain (Loss) on Derivative Instruments, Net, Pretax	(0.1)	(0.5)	(0.7)	(1.4)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)	(0.5)	(0.7)	(1.8)
DP&L [Member] | FTR's [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
DP&L [Member] | FTR's [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability
DP&L [Member] | FTR's [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)	(0.5)	(0.7)	(1.8)
DP&L [Member] | FTR's [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | FTR's [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | FTR's [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
FTR's [Member]
Change in unrealized gain / (loss)	(0.1)	(0.1)	(0.1)	(0.4)
Derivative, Gain (Loss) on Derivative, Net		(0.4)	(0.6)	(1.4)
Gain (Loss) on Derivative Instruments, Net, Pretax	(0.1)	(0.5)	(0.7)	(1.8)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)	(0.5)	(0.7)	(1.8)
FTR's [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
FTR's [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability
FTR's [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)	(0.5)	(0.7)	(1.8)
FTR's [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
FTR's [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
FTR's [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | Forward Power Contracts [Member]
Change in unrealized gain / (loss)	0.3	0.5		0.7
Derivative, Gain (Loss) on Derivative, Net	(0.3)		(0.8)
Gain (Loss) on Derivative Instruments, Net, Pretax		0.5	(0.8)	(0.1)
Derivative Instruments, Gain (Loss) Recognized in Income, Net		0.5	(0.8)	0.6
DP&L [Member] | Forward Power Contracts [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
DP&L [Member] | Forward Power Contracts [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability
DP&L [Member] | Forward Power Contracts [Member] | Wholesale Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net				(0.1)
DP&L [Member] | Forward Power Contracts [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	0.1	0.5	(0.6)	0.7
DP&L [Member] | Forward Power Contracts [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | Forward Power Contracts [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
DP&L [Member] | Forward Power Contracts [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)		(0.2)
Forward Power Contracts [Member]
Change in unrealized gain / (loss)	(0.3)	0.5	0.6	0.7
Derivative, Gain (Loss) on Derivative, Net	1.2		(0.8)	(0.1)
Gain (Loss) on Derivative Instruments, Net, Pretax	0.9	0.5	(0.2)	0.6
Derivative Instruments, Gain (Loss) Recognized in Income, Net	0.9	0.5	(0.2)	0.6
Forward Power Contracts [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)
Forward Power Contracts [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability
Forward Power Contracts [Member] | Wholesale Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net				(0.1)
Forward Power Contracts [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	2.5	0.5	6.1	0.7
Forward Power Contracts [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
Forward Power Contracts [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net
Forward Power Contracts [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.6)		(6.3)
DP&L [Member] | Partners Share of Gain Loss [Member]
Partner's share of gain (loss)	(13.8)	(1.6)	(21.2)	0.2
Partners Share of Gain Loss [Member]
Partner's share of gain (loss)	(13.8)	(1.6)	(21.2)	0.2
DP&L [Member] | Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(4.6)	(0.3)	(5.8)
Regulatory Asset Liability [Member]
Regulatory (asset)/liability	(4.6)	(0.3)	(5.8)
DP&L [Member] | Wholesale Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net				(0.1)
Wholesale Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net				(0.1)
DP&L [Member] | Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net			(1.3)	(1.1)
Purchased Power [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	2.4		5.4	(1.1)
DP&L [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(6.3)	(0.4)	(5.1)	0.5
Fuel [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(6.3)	(0.4)	(5.1)	0.5
DP&L [Member] | O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net			0.1	(0.1)
O&M [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net			0.1	(0.1)
DP&L [Member] | Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(0.1)		(0.2)
Retail Revenue [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(1.6)		(6.3)
DP&L [Member]
Change in unrealized gain / (loss)	(29.3)	(2.1)	(41.7)	0.8
Derivative, Gain (Loss) on Derivative, Net	4.5	(0.2)	8.2
Gain (Loss) on Derivative Instruments, Net, Pretax	(24.8)	(2.3)	(33.5)	(1.4)
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (24.8)	$ (2.3)	$ (33.5)	$ (0.6)

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes

6. Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
DPL	29.9	%	31.9	%	32.9	%	32.8	%
DP&L	29.6	%	32.1	%	32.0	%	32.8	%

Income tax expenses for the three and nine months ended 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 33.2% and 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 September 30, 2011, DPL's current period effective tax 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 be 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 increased state income taxes of $2.0 million recorded as a result of the acquisition of MC Squared.

For the three and nine months ended September 30, 2011, DP&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 tax expense being reduced by $2.6 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 the estimate-to-actual income tax provision adjustment related to the Section 199 Domestic Production Deduction, ESOP related deductions and flow-through related deductions..

For the nine months ended September 30, 2011, the increase in DPL's current period effective tax rate compared to the same period in 2010 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 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 $38.8million and $56.0 million, respectively, during the nine months ended 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 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 September 30, 2011, DPL has incurred approximately $8.9 million in certain costs that are directly associated with the Proposed Merger, which may be deemed as non-deductible, resulting in approximately $3.1 million of additional tax expense for the period in which the transaction  occurs.

DP&L [Member]

Income Taxes

6. Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
DPL	29.9	%	31.9	%	32.9	%	32.8	%
DP&L	29.6	%	32.1	%	32.0	%	32.8	%

Income tax expenses for the three and nine months ended 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 33.2% and 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 September 30, 2011, DPL's current period effective tax 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 be 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 increased state income taxes of $2.0 million recorded as a result of the acquisition of MC Squared.

For the three and nine months ended September 30, 2011, DP&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 tax expense being reduced by $2.6 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 the estimate-to-actual income tax provision adjustment related to the Section 199 Domestic Production Deduction, ESOP related deductions and flow-through related deductions..

For the nine months ended September 30, 2011, the increase in DPL's current period effective tax rate compared to the same period in 2010 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 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 $38.8million and $56.0 million, respectively, during the nine months ended 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 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 September 30, 2011, DPL has incurred approximately $8.9 million in certain costs that are directly associated with the Proposed Merger, which may be deemed as non-deductible, resulting in approximately $3.1 million of additional tax expense for the period in which the transaction occurs.

XML

Proposed Merger with the AES Corporation

9 Months Ended

Sep. 30, 2011

Proposed Merger with the AES Corporation

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 and was approved by DPL's shareholders on September 23, 2011.  Consummation of the transaction is subject to certain conditions, including 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. 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.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1.25 billion in long-term Senior Notes 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.

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

On April 25, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of DPL's board of directors and AES as defendants and naming DPL as a nominal defendant. The lawsuit filed by the 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 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 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 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 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 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 Merger of DPL and AES.

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

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

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

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

On July 29, 2011, DPL, DPL's directors, 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. 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 District Court will schedule a hearing regarding, among other things, approval of the proposed settlement and any application by plaintiffs' counsel for an 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 intends to vigorously 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 Definitive Proxy Statement filed with the SEC on August 5, 2011, as modified by a correction to the Definitive Proxy Statement filed with the SEC on August 24, 2011.

DP&L [Member]

Proposed Merger with the AES Corporation

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 and was approved by DPL's shareholders on September 23, 2011. Consummation of the transaction is subject to certain conditions, including 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. 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.

Dolphin Subsidiary II, Inc., a subsidiary of AES, issued $1.25 billion in long-term Senior Notes 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.

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

On April 25, 2011, a lawsuit was filed in the Court of Common Pleas of Montgomery County, Ohio, naming each member of DPL's board of directors and AES as defendants and naming DPL as a nominal defendant. The lawsuit filed by the 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 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 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 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 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 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 Merger of DPL and AES.

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

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

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

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

On July 29, 2011, DPL, DPL's directors, 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. 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 District Court will schedule a hearing regarding, among other things, approval of the proposed settlement and any application by plaintiffs' counsel for an 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 intends to vigorously 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 Definitive Proxy Statement filed with the SEC on August 5, 2011, as modified by a correction to the Definitive Proxy Statement filed with the SEC on August 24, 2011.

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Common Shareholders' Equity (Narrative) (Details) (USD $) In Millions, except Share data	1 Months Ended		3 Months Ended			9 Months Ended		12 Months Ended
	Jun. 30, 2011	Oct. 27, 2010	Sep. 30, 2011	Dec. 31, 2010	Mar. 31, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2009
Common Shareholders' Equity [Abstract]
Common stock, shares authorized			250,000,000	250,000,000		250,000,000
Common stock, shares outstanding			117,724,111	116,924,844		117,724,111
Amount authorized to be repurchased		$ 200
Stock repurchased, shares				2,040,000	145,915	0
Shares repurchase average per share price				$ 25.75	$ 26.71
Amount available to be used to repurchase stock			147.5
Amount of stock repurchase								3.9
Warrants exercised	700,000
Proceeds from exercise of warrants	$ 14.7					$ 14.7	$ 0
Repurchase of warrants outstanding			1,000,000			1,000,000
Common shares exercise price	$ 130

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Share-Based Compensation (Narrative) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Share-Based Compensation [Abstract]
Share-based compensation expense	$ 1.3	$ 1.2	$ 4.0	$ 3.8
Share-based compensation expense, net of tax	$ 0.8	$ 0.8	$ 2.6	$ 2.5

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Supplemental Financial Information and Comprehensive Income (Comprehensive Income) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Net income	$ 67.1	$ 86.4	$ 142.3	$ 218.8
Net change in unrealized gains (losses) on financial instruments, net of income tax expense	(0.3)	0.3	(0.3)	0.2	0.6
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense	(46.6)	(9.1)	(55.4)	(14.7)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense	0.9	0.8	2.5	3.4
Comprehensive income	21.1	78.4	89.1	207.7
Income tax benefit (expense) on unrealized gains (losses) on financial instruments	0.2	0.1	(0.2)	0.1
Income tax benefit (expense) on unrealized gains (losses) on cash flow hedges	(24.9)	(3.6)	(28.8)	(6.0)
Income tax benefit (expense) on unrealized gains (losses) on pension and postretirement benefits	0.1	0.4	0.7	0.3
DP&L [Member]
Net income	63.9	83.2	147.4	214.7
Net change in unrealized gains (losses) on financial instruments, net of income tax expense	(0.4)	1.8	2.3	(0.9)	8.5
Net change in deferred gains (losses) on cash flow hedges, net of income tax expense	1.3	(0.2)	0.2	(0.1)
Net change in unrealized gains (losses) on pension and postretirement benefits, net of income tax expense	1.0	0.8	2.6	3.4
Comprehensive income	65.8	85.6	152.5	217.1
Income tax benefit (expense) on unrealized gains (losses) on financial instruments	0.1	(1.0)	1.3	(0.5)
Income tax benefit (expense) on unrealized gains (losses) on cash flow hedges	0.9	(0.2)	1.1	1.0
Income tax benefit (expense) on unrealized gains (losses) on pension and postretirement benefits	$ 0.1	$ 0.4	$ 0.7	$ 0.3

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Business Segments (Segment Financial Information) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Revenues from external customers	$ 511.8	$ 516.9	$ 1,451.4	$ 1,413.6
Intersegment revenues
Total revenues	511.8	516.9	1,451.4	1,413.6
Fuel	129.0	104.3	320.9	297.1
Purchased power	108.3	119.0	342.7	282.7
Gross margin	274.5	293.6	787.8	833.8
Depreciation and amortization	35.8	32.2	106.0	105.3
Interest expense	16.8	17.6	51.3	53.0
Income tax expense (benefit)	28.6	40.4	69.7	106.9
Net income (loss)	67.1	86.4	142.3	218.8
Cash capital expenditures	49.9	38.6	141.3	113.7
Total Assets	3,676.5		3,676.5		3,813.3
Utility [Member]
Revenues from external customers	376.6	411.1	1,092.9	1,183.0
Intersegment revenues	90.2	75.9	246.3	165.9
Total revenues	466.8	487.0	1,339.2	1,348.9
Fuel	124.0	97.4	311.7	286.5
Purchased power	95.6	116.4	317.8	279.3
Gross margin	247.2	273.2	709.7	783.1
Depreciation and amortization	33.8	30.4	100.3	98.4
Interest expense	9.3	9.4	28.7	27.9
Income tax expense (benefit)	26.8	39.4	69.3	104.6
Net income (loss)	63.9	83.2	147.4	214.7
Cash capital expenditures	49.1	38.8	139.9	112.3
Total Assets	3,419.7		3,419.7		3,475.4
Competitive Retail [Member]
Revenues from external customers	118.6	84.5	314.6	189.1
Intersegment revenues
Total revenues	118.6	84.5	314.6	189.1
Fuel
Purchased power	101.4	75.9	268.6	165.9
Gross margin	17.2	8.6	46.0	23.2
Depreciation and amortization	0.1		0.2	0.1
Interest expense	0.1		0.2
Income tax expense (benefit)	4.2	1.4	14.1	5.7
Net income (loss)	7.8	4.7	19.6	11.8
Cash capital expenditures
Total Assets	62.1		62.1		35.7
Other Reportable Business Segment [Member]
Revenues from external customers	16.6	21.3	43.9	41.5
Intersegment revenues	1.1	1.1	3.1	3.3
Total revenues	17.7	22.4	47.0	44.8
Fuel	5.0	6.9	9.2	10.6
Purchased power	1.5	2.6	2.6	3.4
Gross margin	11.2	12.9	35.2	30.8
Depreciation and amortization	1.9	1.8	5.5	6.8
Interest expense	7.6	8.3	22.7	25.2
Income tax expense (benefit)	(2.4)	(0.4)	(13.7)	(3.4)
Net income (loss)	(6.2)	(4.2)	(24.7)	(7.6)
Cash capital expenditures	0.8	(0.2)	1.4	1.4
Total Assets	1,702.2		1,702.2		1,828.8
Adjustments and Eliminations [Member]
Revenues from external customers
Intersegment revenues	(91.3)	(77.0)	(249.4)	(169.2)
Total revenues	(91.3)	(77.0)	(249.4)	(169.2)
Fuel
Purchased power	(90.2)	(75.9)	(246.3)	(165.9)
Gross margin	(1.1)	(1.1)	(3.1)	(3.3)
Depreciation and amortization
Interest expense	(0.2)	(0.1)	(0.3)	(0.1)
Income tax expense (benefit)
Net income (loss)	1.6	2.7		(0.1)
Cash capital expenditures
Total Assets	$ (1,507.5)		$ (1,507.5)		$ (1,526.6)

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Pension and Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Pension and Postretirement Benefits [Abstract]

Net Periodic Benefit Cost / (Income)

Net Periodic Benefit Cost / (Income)		Pension						Postretirement
$ in millions		2011			2010			2011			2010
Service cost	$	0.8		$	1.0		$	-		$	0.1
Interest cost		4.1			4.5			0.2			0.3
Expected return on assets (a)		(6.2	)		(5.6	)		(0.1	)		-
Amortization of unrecognized:
Actuarial (gain) / loss		1.7			2.0			(0.5	)		(0.2	)
Prior service cost		0.5			0.9			0.1			-
Net periodic benefit cost / (income) before adjustments	$	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 $317 million.

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.

Schedule of Estimated Future Benefit Payments

Estimated Future Benefit Payments and Medicare Part D Reimbursements
$ in millions		Pension	Postretirement
2011	$	5.3	$	0.6
2012	$	23.1	$	2.4
2013	$	23.1	$	2.4
2014	$	23.6	$	2.3
2015	$	24.0	$	2.1
2016 - 2020	$	122.9	$	8.8

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	163,724,211	163,724,211
Common stock, shares outstanding	117,724,111	116,924,844
THE DAYTON POWER AND LIGHT COMPANY [Member]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01

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Overview and Summary of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2011

Overview and Summary of Significant Accounting Policies [Abstract]

Description of Business

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

Property, Plant and Equipment

Property, Plant and Equipment

We record our ownership share of our undivided interest in jointly-held plants as an asset in property, plant and equipment. Property, plant and equipment are stated at cost. For regulated transmission and distribution property, cost includes direct labor and material, allocable overhead expenses and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds and equity used to finance regulated construction projects. Capitalization of AFUDC ceases at either

project completion or at the date specified by regulators. AFUDC capitalized during the three and nine months ended September 30, 2011 and 2010 was not material.

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

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

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

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

Short-Term Investments

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.

Related Party Transactions

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						Nine Months Ended
		September 30,						September 30,
$ in millions		2011			2010			2011			2010
DP&L Revenues:
Sales to DPLER (a)	$	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	)	$	(2.4	)	$	(2.5	)
Expense recoveries for services provided to DPLER (c)	$	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 nine months ended 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.

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Debt Obligations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	0 Months Ended	9 Months Ended			1 Months Ended		1 Months Ended	3 Months Ended			1 Months Ended	9 Months Ended			1 Months Ended
	Feb. 28, 2011	Feb. 23, 2011	Sep. 30, 2011	Sep. 30, 2010	Mar. 01, 2011	Mar. 01, 2011 DP&L [Member] U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2011 DP&L [Member] U.S. Government note maturing in February 2061 - 4.20% [Member]	Aug. 31, 2011 DP&L [Member] Revolving Credit Agreement with Bank Group [Member]	Apr. 20, 2010 DP&L [Member] Revolving Credit Agreement with Bank Group [Member]	Sep. 30, 2011 DP&L [Member] Revolving Credit Agreement with Bank Group [Member]	Apr. 21, 2009 DP&L [Member] Revolving Credit Agreement with Bank Group [Member]	Aug. 31, 2011 Revolving Credit Agreement with Bank Group [Member]	Sep. 30, 2011 Five Year Senior Unsecured Notes at 6.50% maturing on October 15, 2016 [Member]	Sep. 30, 2011 Ten Year Senior Unsecured Notes at 7.25% maturing at October 15, 2021 [Member]	Sep. 30, 2011 Unsecured Term Loan Agreement [Member]	Sep. 30, 2011 Senior Notes Maturing in September 2011 - 6.875% [Member]	Jun. 30, 2011 DP&L [Member]	Dec. 04, 2008 DP&L [Member]	Nov. 21, 2006 DP&L [Member]
Additional principal amount of senior notes to be raised			$ 1,250										$ 450	$ 800
Debt Instrument, Maturity Date								Aug. 24, 2015				Aug. 24, 2014	Oct. 15, 2016	Oct. 15, 2021
Unsecured revolving credit agreement								200	200		100	125			425				220
Increase additional facility								50	50
Letter of credit sublimit									50	50
Letters of credit outstanding			0							0							0
Collateralized debt																		100
Loans Payable, Noncurrent															300
Purchase of principal amount		122.0
Interest expenses		12.2
Premium percentage		10.00%
Debt issuance costs and unamortized debt discount		3.1
Repayments of Debt	13.5															297.4
Payments to Acquire Productive Assets			$ 141.3	$ 113.7		$ 18.7
Debt Instrument, Interest Rate, Stated Percentage					4.20%		4.20%						6.50%	7.25%		6.875%

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Supplemental Financial Information and Comprehensive Income (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2011

Sep. 30, 2011

Schedule of Supplemental Financial Information

DPL Inc.		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	60.0		$	84.5
Customer receivables		124.7			113.9
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		5.2			7.0
Provision for uncollectible accounts		(1.3	)		(0.9	)
Total accounts receivable, net	$	203.2		$	215.5
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		39.7			38.8
Other		6.7			3.3
Total inventories, at average cost	$	126.8		$	115.3

Comprehensive Income

DPL Inc.
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	67.1		$	86.4
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	$	21.1		$	78.4

DPL Inc.
		Nine Months Ended September 30,
$ in millions		2011			2010
Comprehensive income:
Net income	$	142.3		$	218.8
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	)		0.2
Net change in deferred gains (losses) on cash flow hedges, net of income tax
benefit of $28.8 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	$	89.1		$	207.7

DP&L [Member]

Schedule of Supplemental Financial Information

DP&L		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	38.0		$	64.3
Customer receivables		97.4			95.6
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		3.5			7.9
Provision for uncollectible accounts		(1.0	)		(0.8	)
Total accounts receivable, net	$	152.5		$	178.0
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		38.5			37.7
Other		6.7			3.3
Total inventories, at average cost	$	125.6		$	114.2

Comprehensive Income

DP&L
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	63.9		$	83.2
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	$	65.8		$	85.6

DP&L
		Nine Months Ended September 30,
$ in millions		2011		2010
Comprehensive income:
Net income	$	147.4	$	214.7
Net change in unrealized gains (losses) on financial instruments, net of income tax
expense of $1.3 million and income tax benefits 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	$	152.5	$	217.1

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Contractual Obligations, Commercial Commitments and Contingencies (Narrative) (Details) (USD $)	0 Months Ended	9 Months Ended							3 Months Ended		1 Months Ended	0 Months Ended	3 Months Ended	4 Months Ended	9 Months Ended
	Feb. 15, 2010	Sep. 30, 2011	Sep. 30, 2010 T	Sep. 22, 2009 MT	Mar. 01, 2011	Dec. 31, 2010	Sep. 30, 2011 DPLE and DPLER [Member]	Sep. 30, 2011 MC Squared [Member]	Sep. 30, 2011 DP&L [Member] Beckjord Unit 6 [Member]	Sep. 30, 2011 DP&L [Member] Hutchings Plant [Member]	Feb. 28, 2007 DP&L [Member] Coal Supply Agreements [Member] T	May 03, 2010 DP&L [Member]	Sep. 30, 2010 DP&L [Member]	May 03, 2010 DP&L [Member]	Sep. 30, 2011 DP&L [Member]	Dec. 31, 2010 DP&L [Member]
Third party guarantees		$ 86,700,000					$ 69,700,000	$ 17,000,000
Due to third parties, current		500,000				1,700,000
Equity ownership interest															4.90%
Equity ownership interest aggregate cost															61,000,000
Debt obligation		1,244,500,000
Debt instrument interest percentage					4.20%
Environmental reserves		2,200,000
Percentage of coal-fire power plant holdings									50.00%	100.00%
Percentage of energy generated by coal		99.00%
Annual CO2 emissions generation at stations, in tons			16,000,000
Number of tons of CO2 emitted per year including electric generating units				25,000
Number of Auxiliary Boilers		7
Number of diesel electric generating engines														18
Number of emergency black start engines												8
Relief and civil penalties, per day													27,500
Coal supply failure by suppliers											1,500,000
Coal supply agreement, in tons											570,000
Proceeds from legal settlements	3,400,000
Additional cost allocation pending appeal of litigation															12,000,000
Deferred liability claims															$ 14,100,000	$ 15,400,000

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Supplemental Financial Information and Comprehensive Income

9 Months Ended

Sep. 30, 2011

Supplemental Financial Information and Comprehensive Income

2.      Supplemental Financial Information and Comprehensive Income

DPL Inc.		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	60.0		$	84.5
Customer receivables		124.7			113.9
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		5.2			7.0
Provision for uncollectible accounts		(1.3	)		(0.9	)
Total accounts receivable, net	$	203.2		$	215.5
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		39.7			38.8
Other		6.7			3.3
Total inventories, at average cost	$	126.8		$	115.3

DP&L		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	38.0		$	64.3
Customer receivables		97.4			95.6
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		3.5			7.9
Provision for uncollectible accounts		(1.0	)		(0.8	)
Total accounts receivable, net	$	152.5		$	178.0
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		38.5			37.7
Other		6.7			3.3
Total inventories, at average cost	$	125.6		$	114.2

Supplemental Financial Information and Comprehensive Income (continued)

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

DPL Inc.
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	67.1		$	86.4
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	$	21.1		$	78.4

DP&L
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	63.9		$	83.2
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	$	65.8		$	85.6

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

DPL Inc.
		Nine Months Ended September 30,
$ in millions		2011			2010
Comprehensive income:
Net income	$	142.3		$	218.8
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	)		0.2
Net change in deferred gains (losses) on cash flow hedges, net of income tax
benefit of $28.8 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	$	89.1		$	207.7

DP&L
		Nine Months Ended September 30,
$ in millions		2011		2010
Comprehensive income:
Net income	$	147.4	$	214.7
Net change in unrealized gains (losses) on financial instruments, net of income tax
expense of $1.3 million and income tax benefits 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	$	152.5	$	217.1

DP&L [Member]

Supplemental Financial Information and Comprehensive Income

2.      Supplemental Financial Information and Comprehensive Income

DPL Inc.		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	60.0		$	84.5
Customer receivables		124.7			113.9
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		5.2			7.0
Provision for uncollectible accounts		(1.3	)		(0.9	)
Total accounts receivable, net	$	203.2		$	215.5
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		39.7			38.8
Other		6.7			3.3
Total inventories, at average cost	$	126.8		$	115.3

DP&L		At			At
		September 30,			December 31,
$ in millions		2011			2010
Accounts receivable, net:
Unbilled revenue	$	38.0		$	64.3
Customer receivables		97.4			95.6
Amounts due from partners in jointly-owned plants		10.8			7.0
Coal sales		3.8			4.0
Other		3.5			7.9
Provision for uncollectible accounts		(1.0	)		(0.8	)
Total accounts receivable, net	$	152.5		$	178.0
Inventories, at average cost:
Fuel, limestone and emission allowances	$	80.4		$	73.2
Plant materials and supplies		38.5			37.7
Other		6.7			3.3
Total inventories, at average cost	$	125.6		$	114.2

Supplemental Financial Information and Comprehensive Income (continued)

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

DPL Inc.
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	67.1		$	86.4
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	$	21.1		$	78.4

DP&L
	Three Months Ended September 30,
$ in millions	2011				2010
Comprehensive income:
Net income	$	63.9		$	83.2
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	$	65.8		$	85.6

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

DPL Inc.
		Nine Months Ended September 30,
$ in millions		2011			2010
Comprehensive income:
Net income	$	142.3		$	218.8
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	)		0.2
Net change in deferred gains (losses) on cash flow hedges, net of income tax
benefit of $28.8 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	$	89.1		$	207.7

DP&L
		Nine Months Ended September 30,
$ in millions		2011		2010
Comprehensive income:
Net income	$	147.4	$	214.7
Net change in unrealized gains (losses) on financial instruments, net of income tax
expense of $1.3 million and income tax benefits 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	$	152.5	$	217.1

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Common Shareholders' Equity

9 Months Ended

Sep. 30, 2011

Common Shareholders' Equity

11. Common Shareholders' Equity

DPL has 250,000,000 authorized common shares, of which 117,724,111 are outstanding at September 30, 2011.

On October 27, 2010, the DPL Board of Directors approved a 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 nine months ended September 30, 2011. At 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. 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.

Pursuant to the warrant agreement, DPL has authorized common shares sufficient to provide for the exercise in full of all outstanding warrants. At 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.

DP&L [Member]

Common Shareholders' Equity

11. Common Shareholders' Equity

DPL has 250,000,000 authorized common shares, of which 117,724,111 are outstanding at September 30, 2011.

On October 27, 2010, the DPL Board of Directors approved a 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 nine months ended September 30, 2011. At 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. 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.

Pursuant to the warrant agreement, DPL has authorized common shares sufficient to provide for the exercise in full of all outstanding warrants. At 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.

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Fair Value Measurements (Fair Value and Redemption Frequency) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Jun. 30, 2011		Dec. 31, 2010
Unfunded Commitments
Total Fair Value	10.0				11.8
Equity Securities [Member]
Unfunded Commitments
Redemption Frequency	Immediate
Total Fair Value	4.0				4.4
Debt Securities [Member]
Unfunded Commitments				[1]
Redemption Frequency	Immediate	[1]
Total Fair Value	5.6	[1]			5.5	[1]
Money Market Funds [Member]
Unfunded Commitments				[2]
Redemption Frequency	Immediate	[2]
Total Fair Value	0.2	[2]			1.6	[2]
Multi Strategy Fund [Member]
Unfunded Commitments				[3]
Redemption Frequency	Immediate	[3]
Total Fair Value	$ 0.2	[3]			$ 0.3	[3]

[1] 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.

[2] 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.

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

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Derivative Instruments and Hedging Activities (Gains or Losses Recognized in AOCI for the Cash Flow Hedges) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended			9 Months Ended			3 Months Ended				9 Months Ended				3 Months Ended			9 Months Ended			3 Months Ended				9 Months Ended
	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2011 DP&L [Member] Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2010 DP&L [Member] Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2011 DP&L [Member] Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2010 DP&L [Member] Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2011 Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2010 Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2011 Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2010 Forward Contract Power [Member] Interest Expense [Member]	Sep. 30, 2011 Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2010 Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2011 Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2010 Interest Expense [Member] Interest Rate Swap [Member]	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2011 DP&L [Member] Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2010 DP&L [Member] Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2011 DP&L [Member] Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2010 DP&L [Member] Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2011 Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2010 Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2011 Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2010 Forward Contract Power [Member] Revenues [Member]	Sep. 30, 2011 Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2010 Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2011 Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2010 Revenues [Member] Interest Rate Swap [Member]	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member]		Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2011 DP&L [Member] Forward Contract Power [Member]		Sep. 30, 2010 DP&L [Member] Forward Contract Power [Member]	Sep. 30, 2011 Forward Contract Power [Member]		Sep. 30, 2010 Forward Contract Power [Member]		Sep. 30, 2011 Forward Contract Power [Member]		Sep. 30, 2010 Forward Contract Power [Member]		Sep. 30, 2011 DP&L [Member] Interest Rate Swap [Member]		Sep. 30, 2010 DP&L [Member] Interest Rate Swap [Member]	Sep. 30, 2011 DP&L [Member] Interest Rate Swap [Member]		Dec. 31, 2009 DP&L [Member] Interest Rate Swap [Member]	Sep. 30, 2011 Interest Rate Swap [Member]		Sep. 30, 2010 Interest Rate Swap [Member]		Sep. 30, 2011 Interest Rate Swap [Member]		Sep. 30, 2010 Interest Rate Swap [Member]
Beginning accumulated derivative gain / (loss) in AOCI																																	$ (1.5)			$ (1.8)		$ (1.4)	$ (1.5)				$ (1.8)		$ (1.4)		$ 11.0		$ 13.5	$ 12.3		$ 14.7	$ 12.3		$ 7.7		$ 21.4		$ 14.7
Net gains / (losses) associated with current period hedging transactions																																	1.8		(0.4)	0.8		3.3	1.8		(0.4)		0.8		3.3								(49.8)		(8.9)		(59.0)		(14.7)
Net gains reclassified to earnings					(0.6)	(0.6)	(1.9)	(1.8)					1.4	(0.6)	1.5	(1.8)	0.1	0.8	0.8	(1.5)					0.1	0.8	0.8	(1.5)															0.6
Ending accumulated derivative gain / (loss) in AOCI																																	0.4		0.4	0.4		0.4	0.4		0.4		0.4		0.4		10.4		12.9	10.4		14.7	(36.1)		(1.8)		(36.1)		(1.8)
Net gains / (losses) associated with the ineffective portion of the hedging transaction													3.1		5.1
Portion expected to be reclassified to earnings in the next twelve months																																	$ 0.8	[1]		$ 0.8	[1]		$ 0.8	[1]		[1]	$ 0.8	[1]		[1]	$ 2.4	[1]		$ 2.4	[1]		$ 2.4	[1]		[1]	$ 2.4	[1]		[1]
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)																																	39			39			39				39				-			-			24				24

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

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Business Segments (Narrative) (Details)	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011
Service area, counties		24
Service area, square miles		6,000
Number of coal fired power plants	8	8
Approximate number of retail customers		500,000
Competitive Retail [Member]
Approximate number of retail customers	3,000	25,000

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Business Segments (Tables)

3 Months Ended

Sep. 30, 2011

Business Segments [Abstract]

Financial Reporting for Reportable Business Segments

										Adjustments
				Competitive						and				DPL
$ in millions		Utility		Retail			Other			Eliminations				Consolidated
Three Months Ended September 30, 2011
Revenues from external customers	$	376.6	$	118.6		$	16.6			$	-		$	511.8
Intersegment revenues		90.2			-		1.1			(91.3		)		-
Total revenues	$	466.8	$	118.6		$	17.7		$	(91.3		)	$	511.8
Fuel		124.0			-		5.0				-			129.0
Purchased power		95.6		101.4			1.5			(90.2		)		108.3
Gross margin	$	247.2	$	17.2		$	11.2			$	(1.1	)	$	274.5
Depreciation and amortization	$	33.8		$	0.1	$	1.9			$	-		$	35.8
Interest expense		9.3			0.1		7.6				(0.2	)		16.8
Income tax expense (benefit)		26.8			4.2		(2.4	)			-			28.6
Net income (loss)		63.9			7.8		(6.2	)			1.6			67.1
Cash capital expenditures		49.1			-		0.8				-			49.9
Three Months Ended September 30, 2010
Revenues from external customers	$	411.1	$	84.5		$	21.3			$	-		$	516.9
Intersegment revenues		75.9			-		1.1			(77.0		)		-
Total revenues	$	487.0	$	84.5		$	22.4		$	(77.0		)	$	516.9
Fuel		97.4			-		6.9				-			104.3
Purchased power		116.4		75.9			2.6			(75.9		)		119.0
Gross margin	$	273.2		$	8.6	$	12.9			$	(1.1	)	$	293.6
Depreciation and amortization	$	30.4		$	-	$	1.8			$	-		$	32.2
Interest expense		9.4			-		8.3				(0.1	)		17.6
Income tax expense (benefit)		39.4			1.4		(0.4	)			-			40.4
Net income (loss)		83.2			4.7		(4.2	)			2.7			86.4
Cash capital expenditures		38.8			-		(0.2	)			-			38.6

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Business Segments

9 Months Ended

Sep. 30, 2011

Business Segments

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 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 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 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.

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

										Adjustments
				Competitive						and				DPL
$ in millions		Utility		Retail			Other			Eliminations				Consolidated
Three Months Ended September 30, 2011
Revenues from external customers	$	376.6	$	118.6		$	16.6			$	-		$	511.8
Intersegment revenues		90.2			-		1.1			(91.3		)		-
Total revenues	$	466.8	$	118.6		$	17.7		$	(91.3		)	$	511.8
Fuel		124.0			-		5.0				-			129.0
Purchased power		95.6		101.4			1.5			(90.2		)		108.3
Gross margin	$	247.2	$	17.2		$	11.2			$	(1.1	)	$	274.5
Depreciation and amortization	$	33.8		$	0.1	$	1.9			$	-		$	35.8
Interest expense		9.3			0.1		7.6				(0.2	)		16.8
Income tax expense (benefit)		26.8			4.2		(2.4	)			-			28.6
Net income (loss)		63.9			7.8		(6.2	)			1.6			67.1
Cash capital expenditures		49.1			-		0.8				-			49.9
Three Months Ended September 30, 2010
Revenues from external customers	$	411.1	$	84.5		$	21.3			$	-		$	516.9
Intersegment revenues		75.9			-		1.1			(77.0		)		-
Total revenues	$	487.0	$	84.5		$	22.4		$	(77.0		)	$	516.9
Fuel		97.4			-		6.9				-			104.3
Purchased power		116.4		75.9			2.6			(75.9		)		119.0
Gross margin	$	273.2		$	8.6	$	12.9			$	(1.1	)	$	293.6
Depreciation and amortization	$	30.4		$	-	$	1.8			$	-		$	32.2
Interest expense		9.4			-		8.3				(0.1	)		17.6
Income tax expense (benefit)		39.4			1.4		(0.4	)			-			40.4
Net income (loss)		83.2			4.7		(4.2	)			2.7			86.4
Cash capital expenditures		38.8			-		(0.2	)			-			38.6

									Adjustments
				Competitive					and				DPL
$ in millions		Utility		Retail		Other			Eliminations				Consolidated
Nine Months Ended September 30, 2011
Revenues from external customers	$	1,092.9	$	314.6	$	43.9			$	-		$	1,451.4
Intersegment revenues		246.3		-		3.1			(249.4		)		-
Total revenues	$	1,339.2	$	314.6	$	47.0		$	(249.4		)	$	1,451.4
Fuel		311.7		-		9.2				-			320.9
Purchased power		317.8		268.6		2.6			(246.3		)		342.7
Gross margin	$	709.7	$	46.0	$	35.2			$	(3.1	)	$	787.8
Depreciation and amortization	$	100.3	$	0.2	$	5.5			$	-		$	106.0
Interest expense		28.7		0.2		22.7				(0.3	)		51.3
Income tax expense (benefit)		69.3		14.1		(13.7	)			-			69.7
Net income (loss)		147.4		19.6		(24.7	)			-			142.3
Cash capital expenditures		139.9		-		1.4				-			141.3
Nine Months Ended September 30, 2010
Revenues from external customers	$	1,183.0	$	189.1	$	41.5			$	-		$	1,413.6
Intersegment revenues		165.9		-		3.3			(169.2		)		-
Total revenues	$	1,348.9	$	189.1	$	44.8		$	(169.2		)	$	1,413.6
Fuel		286.5		-		10.6				-			297.1
Purchased power		279.3		165.9		3.4			(165.9		)		282.7
Gross margin	$	783.1	$	23.2	$	30.8			$	(3.3	)	$	833.8
Depreciation and amortization	$	98.4	$	0.1	$	6.8			$	-		$	105.3
Interest expense		27.9		-		25.2				(0.1	)		53.0
Income tax expense (benefit)		104.6		5.7		(3.4	)			-			106.9
Net income (loss)		214.7		11.8		(7.6	)			(0.1	)		218.8
Cash capital expenditures		112.3		-		1.4				-			113.7
Total Assets
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

DP&L [Member]

Business Segments

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 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 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 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.

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

										Adjustments
				Competitive						and				DPL
$ in millions		Utility		Retail			Other			Eliminations				Consolidated
Three Months Ended September 30, 2011
Revenues from external customers	$	376.6	$	118.6		$	16.6			$	-		$	511.8
Intersegment revenues		90.2			-		1.1			(91.3		)		-
Total revenues	$	466.8	$	118.6		$	17.7		$	(91.3		)	$	511.8
Fuel		124.0			-		5.0				-			129.0
Purchased power		95.6		101.4			1.5			(90.2		)		108.3
Gross margin	$	247.2	$	17.2		$	11.2			$	(1.1	)	$	274.5
Depreciation and amortization	$	33.8		$	0.1	$	1.9			$	-		$	35.8
Interest expense		9.3			0.1		7.6				(0.2	)		16.8
Income tax expense (benefit)		26.8			4.2		(2.4	)			-			28.6
Net income (loss)		63.9			7.8		(6.2	)			1.6			67.1
Cash capital expenditures		49.1			-		0.8				-			49.9
Three Months Ended September 30, 2010
Revenues from external customers	$	411.1	$	84.5		$	21.3			$	-		$	516.9
Intersegment revenues		75.9			-		1.1			(77.0		)		-
Total revenues	$	487.0	$	84.5		$	22.4		$	(77.0		)	$	516.9
Fuel		97.4			-		6.9				-			104.3
Purchased power		116.4		75.9			2.6			(75.9		)		119.0
Gross margin	$	273.2		$	8.6	$	12.9			$	(1.1	)	$	293.6
Depreciation and amortization	$	30.4		$	-	$	1.8			$	-		$	32.2
Interest expense		9.4			-		8.3				(0.1	)		17.6
Income tax expense (benefit)		39.4			1.4		(0.4	)			-			40.4
Net income (loss)		83.2			4.7		(4.2	)			2.7			86.4
Cash capital expenditures		38.8			-		(0.2	)			-			38.6

									Adjustments
				Competitive					and				DPL
$ in millions		Utility		Retail		Other			Eliminations				Consolidated
Nine Months Ended September 30, 2011
Revenues from external customers	$	1,092.9	$	314.6	$	43.9			$	-		$	1,451.4
Intersegment revenues		246.3		-		3.1			(249.4		)		-
Total revenues	$	1,339.2	$	314.6	$	47.0		$	(249.4		)	$	1,451.4
Fuel		311.7		-		9.2				-			320.9
Purchased power		317.8		268.6		2.6			(246.3		)		342.7
Gross margin	$	709.7	$	46.0	$	35.2			$	(3.1	)	$	787.8
Depreciation and amortization	$	100.3	$	0.2	$	5.5			$	-		$	106.0
Interest expense		28.7		0.2		22.7				(0.3	)		51.3
Income tax expense (benefit)		69.3		14.1		(13.7	)			-			69.7
Net income (loss)		147.4		19.6		(24.7	)			-			142.3
Cash capital expenditures		139.9		-		1.4				-			141.3
Nine Months Ended September 30, 2010
Revenues from external customers	$	1,183.0	$	189.1	$	41.5			$	-		$	1,413.6
Intersegment revenues		165.9		-		3.3			(169.2		)		-
Total revenues	$	1,348.9	$	189.1	$	44.8		$	(169.2		)	$	1,413.6
Fuel		286.5		-		10.6				-			297.1
Purchased power		279.3		165.9		3.4			(165.9		)		282.7
Gross margin	$	783.1	$	23.2	$	30.8			$	(3.3	)	$	833.8
Depreciation and amortization	$	98.4	$	0.1	$	6.8			$	-		$	105.3
Interest expense		27.9		-		25.2				(0.1	)		53.0
Income tax expense (benefit)		104.6		5.7		(3.4	)			-			106.9
Net income (loss)		214.7		11.8		(7.6	)			(0.1	)		218.8
Cash capital expenditures		112.3		-		1.4				-			113.7
Total Assets
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

XML

Condensed Consolidated Statements of Results of Operations (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues	$ 511.8	$ 516.9	$ 1,451.4	$ 1,413.6
Cost of revenues:
Fuel	129.0	104.3	320.9	297.1
Purchased power	108.3	119.0	342.7	282.7
Total cost of revenues	237.3	223.3	663.6	579.8
Gross margin	274.5	293.6	787.8	833.8
Operating expenses:
Operation and maintenance	92.0	84.2	298.2	252.3
Depreciation and amortization	35.8	32.2	106.0	105.3
General taxes	33.8	32.6	104.1	96.3
Total operating expenses	161.6	149.0	508.3	453.9
Operating income	112.9	144.6	279.5	379.9
Other income / (expense), net:
Investment income	0.1	0.3	0.3	0.6
Interest expense	(16.8)	(17.6)	(51.3)	(53.0)
Charge for early redemption of debt			(15.3)
Other expense	(0.5)	(0.5)	(1.2)	(1.8)
Total other income / (expense), net	(17.2)	(17.8)	(67.5)	(54.2)
Earnings before income tax	95.7	126.8	212.0	325.7
Income tax expense	28.6	40.4	69.7	106.9
Net income	67.1	86.4	142.3	218.8
Earnings on common stock	67.1	86.4	142.3	218.8
Average number of common shares outstanding (millions):
Basic	115.0	115.8	114.4	115.7
Diluted	115.5	116.3	115.0	116.2
Earnings per share of common stock:
Basic	$ 0.58	$ 0.75	$ 1.24	$ 1.89
Diluted	$ 0.58	$ 0.74	$ 1.24	$ 1.88
Dividends paid per share of common stock	$ 0.3325	$ 0.3025	$ 0.9975	$ 0.9075
THE DAYTON POWER AND LIGHT COMPANY [Member]
Revenues	466.8	487.0	1,339.2	1,348.9
Cost of revenues:
Fuel	124.0	97.4	311.7	286.5
Purchased power	95.6	116.4	317.8	279.3
Total cost of revenues	219.6	213.8	629.5	565.8
Gross margin	247.2	273.2	709.7	783.1
Operating expenses:
Operation and maintenance	80.2	78.7	266.7	243.4
Depreciation and amortization	33.8	30.4	100.3	98.4
General taxes	33.2	32.2	97.6	94.0
Total operating expenses	147.2	141.3	464.6	435.8
Operating income	100.0	131.9	245.1	347.3
Other income / (expense), net:
Investment income	0.4	0.4	1.5	1.3
Interest expense	(9.3)	(9.4)	(28.7)	(27.9)
Other expense	(0.4)	(0.3)	(1.2)	(1.4)
Total other income / (expense), net	(9.3)	(9.3)	(28.4)	(28.0)
Earnings before income tax	90.7	122.6	216.7	319.3
Income tax expense	26.8	39.4	69.3	104.6
Net income	63.9	83.2	147.4	214.7
Dividends on preferred stock	0.2	0.2	0.6	0.6
Earnings on common stock	$ 63.7	$ 83.0	$ 146.8	$ 214.1

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Overview and Summary of Significant Accounting Policies (Excise Taxes Levied by State or Local Governments) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Overview and Summary of Significant Accounting Policies [Abstract]
State/Local excise taxes	$ 14.3	$ 14.6	$ 39.9	$ 40.1

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Income Taxes (Effective Income Tax Rates) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Effective income tax rates	29.90%	31.90%	32.90%	32.80%
DP&L [Member]
Effective income tax rates	29.60%	32.10%	32.00%	32.80%

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Derivative Instruments and Hedging Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Mar. 01, 2011	Sep. 30, 2011 Senior Notes Maturing in September 2011 - 6.875% [Member]	Dec. 31, 2010 Senior Notes Maturing in September 2011 - 6.875% [Member]	Sep. 30, 2011 Planned Future Borrowing Activities In 2011 [Member]	Sep. 30, 2011 Planned Future Borrowing Activities In 2013 [Member]	Sep. 30, 2011 DP&L [Member]
Interest rate hedging relationships with notional amount						$ 200	$ 160
Gain (Loss) on Settlement of Derivative Instrument (Before Tax)	48.1
Gain (Loss) on Settlement of Derivative Instrument (After Tax)	31.3
Loans Payable to Bank, Noncurrent	425	425
Senior notes maturing in September 2011				297.4	297.4
Debt instrument interest percentage			4.20%	6.875%
Reclassified from accumulated OCI into income, forecasted transactions	3.1	5.1
Reclassified from accumulated OCI into income, forecasted transactions, net of tax	2.0	3.3
Fair value of commodity derivative instruments	13.1	13.1						8.5
Derivative instrument offset amount								2.1
Liability position offset by the asset position	2.1	2.1
Collateral Already Posted, Aggregate Fair Value	6.9	6.9						5.2
Debt post collateral	$ 4.1	$ 4.1						$ 1.2

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Insurance Recovery (Narrative) (Details) (USD $) In Millions	0 Months Ended
	Feb. 15, 2010
Insurance Recovery [Abstract]
Proceeds form the settlement amounted	$ 3.4

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Debt Obligations (Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		6 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended					3 Months Ended
	Sep. 30, 2011	Mar. 01, 2011	Dec. 31, 2010	Sep. 30, 2011 DP&L [Member] First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]	Dec. 31, 2010 DP&L [Member] First Mortgage Bonds Maturing in October 2013 - 5.125% [Member]	Sep. 30, 2011 DP&L [Member] Pollution Control Series Maturing in January 2028 - 4.70% [Member]	Dec. 31, 2010 DP&L [Member] Pollution Control Series Maturing in January 2028 - 4.70% [Member]	Sep. 30, 2011 DP&L [Member] Pollution Control Series Maturing in January 2034 - 4.80% [Member]	Dec. 31, 2010 DP&L [Member] Pollution Control Series Maturing in January 2034 - 4.80% [Member]	Sep. 30, 2011 DP&L [Member] Pollution Control Series Maturing in September 2036 - 4.80% [Member]	Dec. 31, 2010 DP&L [Member] Pollution Control Series Maturing in September 2036 - 4.80% [Member]	Jun. 30, 2011 DP&L [Member] Pollution control series maturing in November 2040 - variable rates: 0.23% - 0.29% and 0.16% - 0.36% [Member]	Sep. 30, 2011 DP&L [Member] Pollution control series maturing in November 2040 - variable rates: 0.23% - 0.29% and 0.16% - 0.36% [Member]	Dec. 31, 2010 DP&L [Member] Pollution control series maturing in November 2040 - variable rates: 0.23% - 0.29% and 0.16% - 0.36% [Member]	Sep. 30, 2011 DP&L [Member] U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2011 Bank Term Loan - variable rates: 1.48% - 1.49% [Member]		Sep. 30, 2011 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Dec. 31, 2010 Note to DPL Capital Trust II Maturing in September 2031 - 8.125% [Member]	Sep. 30, 2011 DP&L [Member]	Dec. 31, 2010 DP&L [Member]
Total long-term debt, gross	$ 1,223.6		$ 1,026.6	$ 470.0	$ 470.0	$ 35.3	$ 35.3	$ 179.1	$ 179.1	$ 100.0	$ 100.0		$ 100.0	$ 100.0	$ 0.1	$ 300.0	[1]	$ 20.6	$ 142.6	$ 902.9	$ 884.4
Obligation for capital lease																				0.5	0.1
Unamortized debt discount																				(0.4)	(0.5)
Total long-term debt																				$ 903.0	$ 884.0
Debt instrument maturity year	2061			October 2013		January 2028		January 2034		September 2036		November 2040 -			February 2061			September 2031		2026
Debt instrument interest percentage		4.20%		5.125%		4.70%		4.80%		4.80%					4.20%			8.125%
Debt instrument interest percentage minimum													0.06%	0.16%		1.48%
Debt instrument interest percentage maximum													0.29%	0.36%		1.49%

[1] Range of interest rates since the loan was drawn in August 2011.

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Debt Obligations (Current portion - Long-term Debt) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			9 Months Ended			3 Months Ended
	Sep. 30, 2011	Mar. 01, 2011	Dec. 31, 2010	Sep. 30, 2011 DP&L [Member] U.S. Government note maturing in February 2061 - 4.20% [Member]	Sep. 30, 2011 Senior Notes Maturing in September 2011 - 6.875% [Member]	Dec. 31, 2010 Senior Notes Maturing in September 2011 - 6.875% [Member]	Sep. 30, 2011 DP&L [Member]	Dec. 31, 2010 DP&L [Member]
Obligation for capital lease							$ 0.3	$ 0.1
Total current portion - long-term debt	0.4		297.5	18.5			0.4	0.1
Senior notes maturing in September 2011					$ 297.4	$ 297.4
Debt instrument maturity year	2061			February 2061			2026
Debt instrument interest percentage		4.20%		4.20%	6.875%

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Fair Value Measurements (Fair Value and Cost of Non-Derivative Instruments) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
DP&L [Member] | Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	$ 17.3	[1]	$ 17.5	[1]
DP&L [Member] | Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	33.5	[1]	30.2	[1]
Equity Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	3.9		3.8
Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	4.0		4.4
DP&L [Member] | Debt Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	5.1		5.2
DP&L [Member] | Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
Debt Securities [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	5.1		5.2
Debt Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	5.6		5.5
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.3		0.3
DP&L [Member] | Hedge Funds, Multi-strategy [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
Hedge Funds, Multi-strategy [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.3		0.3
Hedge Funds, Multi-strategy [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		0.3
DP&L [Member] | Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.2		1.6
DP&L [Member] | Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
Money Market Funds [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	0.2		1.6
Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	0.2		1.6
DP&L [Member] | Debt [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Debt	903.4		884.1
DP&L [Member] | Debt [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Long-term Debt, Fair Value	884.2		850.6
Debt [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Debt	1,224.0		1,324.1
Debt [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Long-term Debt, Fair Value	1,204.6		1,307.5
DP&L [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	22.9		24.6
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Total Master Trust Assets, Cost	9.5		10.9
Total Short-term Investments			69.3
Total Assets	9.5		80.2
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Short-term Investments - Bonds [Member]
Total Master Trust Assets, Cost			15.1
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Short-term Investments - VRDNs [Member]
Total Master Trust Assets, Cost			54.2
DP&L [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	39.5		37.6
Estimate of Fair Value, Fair Value Disclosure [Member]
Total Master Trust Assets, Fair Value	10.0		11.8
Total Short-term Investments			69.3
Total Assets			81.1
Estimate of Fair Value, Fair Value Disclosure [Member] | Short-term Investments - Bonds [Member]
Total Short-term Investments			15.1
Estimate of Fair Value, Fair Value Disclosure [Member] | Short-term Investments - VRDNs [Member]
Total Short-term Investments			$ 54.2

[1] DPL stock held in the DP&L Master Trust is eliminated in consolidation.

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Overview and Summary of Significant Accounting Policies (Related Party Transactions) (Details) (DP&L [Member], USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
DP&L [Member]
Sales to DPLER	$ 90.2	$ 75.9	$ 246.3	$ 165.9
Premiums paid for insurance services provided by MVIC	(0.8)	(0.8)	(2.4)	(2.5)
Expense recoveries for services provided to DPLER	$ 1.1	$ 1.6	$ 2.8	$ 4.0